DP30E

DESIGN PRACTICESELECTRICAL POWER FACILITIES

SYSTEM AND EQUIPMENT PROTECTIVERELAYING

PROPRIETARY INFORMATION — For Authorized Company Use Only

SectionXXX-E

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DateEXXON

ENGINEERING

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December, 1995

EXXON RESEARCH AND ENGINEERING COMPANY — FLORHAM PARK, N.J.

CONTENTS

Section Page

SCOPE 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

REFERENCES 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

International Practices 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Other Literature 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

BACKGROUND 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

DEFINITIONS 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Burden 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Device Numbers 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fault 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

High-Resistance Neutral Grounding 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Knee Point (Knee Voltage) 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Low-Resistance Neutral Grounding 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Overload 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Overreach (Transient Overreach) 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Overtravel (Overshoot) Time 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Secondary-Selective Substation 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Selectivity /Coordination/Discrimination 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Spot-Network Substation 7. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

PROTECTIVE DEVICE TYPES AND APPLIC ATION 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Direct Acting Trips 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fuses 8. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Relays – General 10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Relays – Device Descriptions 10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Time Delay Relays (2) and (62) 10. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Distance Relays (21) 11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Volts /Hertz Relaying (24) – Overexcitation Protection 11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Synchronizing Relays (25) 11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Temperature Relays (26) 12. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Undervoltage Relays (27) 12. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Directional Power Relay (32) 13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Loss of Field Relays (40) 13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Negative-Sequence Overcurrent Relays (46) – Generator Protection 13. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Phase Balance Relays (46) – Motor Protection 14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Negative Sequence Voltage Relay (47) – Motor Protection 14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Thermal Overload Relays (49) and Locked Rotor Protection 14. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Instantaneous Overcurrent Relays (50) 16. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .




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CONTENTS (Cont)

Section Page

Inverse Time Overcurrent Relays (51) 16. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Definite Time Overcurrent Relays (51) 17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Voltage-Restrained (Voltage-Controlled) Overcurrent Relays (51v) 17. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Overvoltage Relays (59) 18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Voltage Balance Relay (60) / Pt Fuse Failure 18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Buchholz and Sudden Pressure Relays (63) 18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Directional Overcurrent and Power Relays (67 and 32) 18. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Frequency Relays (81) 19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lockout Relays (86) 19. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Differential Relays (87) 20. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Ground (Earth Fault) Relays (50N, 50G, 50GS, 51N, 51G, 51GS, 67N) 21. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

CURRENT TRANSFORMERS 21. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Core Balanced (Zero Sequence) Current Transformers 23. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

POTENTIAL TRANSFORMERS 23. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

BASIC DESIGN CONSIDERATIONS 23. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Protection Philosophy 23. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Overcurrent Device Coordination (Selectivity /Discrimination) 24. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Back-Up Protection 25. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Ground (Earth) Fault Relaying 26. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Motor Protection 26. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Generator Protection 27. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Transformer Protection 27. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Transformer Secondary Protection 28. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Busbar Protection 28. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Cable (Feeder) Protection 28. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Secondary Selective Substation Protection 28. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Spot Network Substation Protection 28. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Partial Differential Protection 29. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Restricted Earth Fault Protection 29. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Synchronizing Busbar Protection 29. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Captive Transformer Protection 30. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Calculation Procedure 30. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Documentation Required from Contractor 30. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

When Contractor Should Furnish Relay Documentation 30. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sample Relay Data and Coordination 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Relay Data Requirements 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Relay Coordination Requirements 31. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .




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Squirrel Cage Induction Motor Relay Settings 32. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

MCC Feeder Relay Settings 32. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Transformer-Secondary Relay Settings 33. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Transformer Primary Relay Settings 33. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Secondary-Selective Auto-Transfer Relay Settings 34. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Generator Relay Settings 35. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Generator Separation Relay Settings 36. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Spot Network Relay Settings 36. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Partial Differential Relay Settings 36. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Restricted Earth Fault Protection 36. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Table 1 I.E.C. Recommended Fuse Ratings for Low Voltage 37. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Table 2 Typical Current Transformer Ratios 38. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

IEEE STANDARD ELECTRICAL DEVICE FUNCTION NUMBERS 39. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Device Numbers 39. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Suffix Letters 44. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Suffix Numbers 47. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Devices Performing More than One Function 47. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FORMULAS COMMONLY USED IN RELAYING 48. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Per Unit System 48. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Definitions: 48. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Basic Formulas: 48. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Conversions and Calculations 49. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

APPENDIX 51. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

SYMBOLS 51. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FIGURES 54. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 1 Definition of Knee Point 54. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 2 Current Limiting Fuse 55. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 3 Instantaneous Relay Current vs. Time Curve with or without d.c. Filter 56. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 4 Instantaneous Relay Current vs. Time Curve Sensitive to Current Offset (d.c.) 57. . . . . . . . . . . . . . . . . . . . . . .

Figure 5 Instantaneous Relay Current vs. Time Curve with d.c. Component Filtered Out 58. . . . . . . . . . . . . . . . . . . . . .

Figure 6 Instantaneous Relay Overreach vs. System Angle (Low Overreach Relay) 58. . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 7 Instantaneous Relay Operating Time vs. Current 59. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 8 Typical Time vs. Current Curves of Relays with Inverse Time Characteristics 60. . . . . . . . . . . . . . . . . . . . . . . .

Figure 9 Inverse Time Overcurrent Relay Slopes 61. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 10 Definite Time Overcurrent Relay Time vs. Current Curve 61. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 11 Generator Cable Protection with Directional Relay (Not Recommended) 62. . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 12 Generator Cable Protection with Differential Relay (Recommended) 63. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 13 Cable Differential Protection 63. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 14 Transformer Differential Protection 64. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .




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Section Page

Figure 15 Generator or Motor Differential Protection(Lower Sketch of “Self Balancing” Scheme is Preferred for Motors) 64. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 16 Busbar Differential Protection 65. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 17 Standard Differential Protection 65. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 18 Pilot Wire Differential Protection 65. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 19 Distance (Impedance) Protection 66. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 20 Time Grading Selectivity 67. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 21 Current Grading 68. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 22 Selectivity Between Fuses 68. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 23 Instantaneous Relay Set Point 69. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 24 Instantaneous Relay Operation at Less than Half a Cycle 69. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 25 Selectivity Between an Instantaneous Relay and a Current Limiting Fuse 70. . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 26 Fuse Peak Let-Through Current Curves 71. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 27 Backup Protection 72. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 28 Motor Control Circuits 73. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 29 Transformer Protection 74. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 30 Partial Differential Protection 75. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 31 Relay Settings Record 76. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 32 Relay Coordination Graph Paper 77. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 33 Relay Coordination Sample One Line Diagram 78. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 34 Typical Relay Settings Record (13.8/2.4 kV) 79. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 35 Typical Relay Settings Record (13.8 kV/480 V) 81. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 36 Typical 2400V Phase Relaying Curves 83. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 37 Typical 2400V Ground Relaying Curves 84. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 38 Typical 2400V Motor Relaying Curves 85. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 39 Typical 480V Phase Relaying Curves 86. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 40 Typical 480V Ground Relaying Curves 87. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 41 Typical 480V Turnaround Power Center Relaying Curves 88. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 42 Stabilizing Resistor 89. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 43 Typical Fuse I2T Characteristics 90. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 44 Relative Magnitudes of Fault Currents 91. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Figure 45 Typical X/R Values 92. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Revisio n Memo

12/95 This is an overall update of DP XXX-E.




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SCOPE

This subsection outlines our approach to system and equipment protective relaying from the power source, as defined inSubsection C , to the loads.

Design details of relays and calibration procedures are not covered. For this information, reference should be made to themanufacturer’s instruction bulletins for each particular relay. Specialized protective relaying, such as for instruments and d-ccircuits, are not included.

REFERENCES

INTERNATIONAL PRACTICES

IP 16-2-1 Power System Design

IP 16-4-1 Grounding and Overvoltage Protection

IP 16-7-1 Motor Application

IP 16-9-3 Synchronous Generators

IP 16-10-1 Power Transformers

IP 16-11-1 Neutral Grounding Resistors

IP 16-12-1 Switchgear, Control Centers, and Bus Duct

IP 16-12-2 Control of Secondary Selective Substations with Automatic Transfer

IP 16-13-1 Field Installation and Testing of Electrical Equipment

OTHER LITERATURE

ANSI/IEEE C37.91-1985, IEEE Guide for Protective Relay Applications to Power Transformers

ANSI/IEEE C37.96-1988, IEEE Guide for AC Motor Protection

ANSI/IEEE C37.102-1987, IEEE Guide for AC Generator Protection

ANSI/IEEE Std 242-1986, IEEE Recommended Practice for Protection and Coordination of Industrial and CommercialPower Systems

IEC Publication 269 Low-Voltage Fuses

Protective Relaying Theory and Applications published by ABB

Protective Relays Application Guide (PRAG) Published by GEC Measurements, GEC, U.K.

Industrial Power Systems Data Book by D. Beeman, Published by McGraw-Hill

IEEE Transactions IGA March/April 1965, pp. 130 – 139, Allowing for Decrement and Fault Voltage in Industrial Relaying

BACKGROUND

Protective Relaying is essential to maintain the integrity of the electrical system during a fault or other abnormal conditions. Evena well designed and maintained system can perform poorly if the protective relaying is not properly applied.

During normal operation of an electrical system, the protective relaying is dormant and does not contribute to the reliability, hencedeficiencies, such as defective relays, disconnected wiring, design errors, or incorrect settings, can go undetected for a long time(maybe years). However, when there is a fault or other abnormal condition on the electrical system, it is essential that the faultyequipment or circuit be disconnected by the protective relaying in the shortest possible time, otherwise the whole system maycollapse.




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BACKGROUND (Cont)

Because the protective relaying is so important and because we accept that nothing can be perfect, we apply additional protectionto back-up the first line protection that will:

� Isolate the faulty equipment a short time after the primary relaying should have operated and/or

� Isolate the faulty equipment by disconnecting the supply to it at a point further from the fault than the primary protection wouldhave done.

Protective relaying should be designed to cover the worst possible scenario to fulfill its function of protecting the electrical system.This entails checking that it will operate correctly for all system configurations that are possible.

In some unusual cases it may be necessary to sacrifice coordination to achieve faster clearing times, but these cases should belimited to an absolute minimum and the reasons for it should be documented in the design notes for the project.

DEFINITIONS

BURDEN

The term used for the electrical load on the secondary of a current transformer, including the resistance of the secondary winding.The burden is either expressed in ohms (with resistance and reactance components), or in volt-amperes at a specified power factorand current (usually the rated amperes of the device or the relay tap).

DEVICE NUMBERS

The American numbering system for electrical devices is in the section entitled “IEEE STANDARD ELECTRICAL DEVICEFUNCTION NUMBERS”.

FAULT

As used herein, a fault is a short circuit that causes a very high current flow, which is generally considerably in excess of rated currentfor the equipment or circuit. Fault currents are high enough to operate a protective device to isolate the “fault” within two seconds.IP 16-2-1 defines the distinction between an overload and a fault, as follows: “Overload vs. fault protection, as used in discussingselectivity, refers to the parts of relay, device, or fuse time-current characteristics respectively above and below two seconds.”

HIGH-RESISTANCE NEUTRAL GROUNDING

A system where the ground fault current is limited to such a low value that it can flow for several hours without damage to equipment.Ground relaying is not fitted on such a system except for ground fault detection alarm. Ground fault current is normally limited to10 amperes maximum, but no more than 5 amperes is preferred. To avoid transient overvoltages, the ground fault current throughthe resistor must be equal to or slightly greater than 3 times the future maximum per-phase charging current to ground of the systemto which it is directly connected; i.e., not including parts of the system separated from the ground source by isolation transformersthat are open circuits in the zero sequence network. This makes the resistor ground fault current about equal to the capacitiveground fault current, and makes the total ground fault current about 1.414 times the resistor’s fault current. Thus the future maximumper-phase charging current to ground of the (zero sequence isolated) system can be no more than 2.35 A (preferably 1.18 A) fora high resistance grounding application. This usually limits the application of high resistance grounding to a generator with a unittransformer, or a small low-voltage system.

KNEE POINT (KNEE VOLTAGE)

The knee point is that point of a current transformer excitation curve at which a further increase of 10% of secondary e.m.f. wouldrequire an increment of exciting current of 50%. See Figure 1 . For most relaying applications, acceptable accuracy is obtained onlywhen operation is achieved below the knee point.




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DEFINITIONS (Cont)

LOW-RESISTANCE NEUTRAL GROUNDING

A system where the ground fault current is limited by a resistor connected between the system neutral and ground to reduce damageto equipment by ground faults, but where the current is high enough to operate ground protective relays reliably. Per IP 16-2-1,the neutral resistor must be sized to produce a ground fault current at least 15 times the lowest reliable operating current of theleast sensitive outgoing feeder ground relay, and at least 5 times the lowest reliable operating current of bus ground relaying. Toavoid any possibility of the ground fault current being low enough to cause transient overvoltages greater than 2.5 times the normalcrest voltage to ground, the ground fault current should be at least 6.6% of the maximum 3-phase fault current. This ground-faultmagnitude basis yields roughly the same order of magnitude ground-fault current as the 5-times rule in the previous sentence.

OVERLOAD

A current that is in excess of the rated value specified for a piece of equipment for the conditions under which it is operating, butnot a high enough current to be considered a “fault.” Examples of overloads are a pump with a higher viscosity fluid than design,and a transformer with too many loads connected.

OVERREACH (TRANSIENT OVERREACH)

Applied to instantaneous overcurrent relays and impedance relays, where for various reasons a relay operates for faults beyondthe zone it was intended to cover (reach); i.e., the relay overreaches (see faults farther away than intended by the relay setting).Overreach of an instantaneous overcurrent (50) relay relates to the relay’s sensitivity to asymmetrical amperes. A 50 relay sensitiveto d-c offset can operate even though the symmetrical value of an offset current is below the relay’s symmetrical setting. The typicalapplication of overreach in our operations is to set a 50 relay on a transformer primary so it does NOT operate for a fault on thetransformer secondary. To achieve this, the relay must be set above a multiple of the transformer-secondary symmetrical rms faultcurrent (IF) as seen by the relay. The multiple accounts for the instantaneous relay’s overreach. In practice, a 50 relay that is fullysensitive to dc offset is set at about 190% to 200% of the reflected secondary-side symmetrical fault level; while a 50 relay withlow overreach is set about 10% to 20% higher than IF times the quantity (1 + %overreach/100), where the % overreach is definedby the relay manufacturer, such as in Figure 6 .

OVERTRAVEL (OVERSHOOT) TIME

A time interval associated with time-delayed overcurrent relays related to the relay completing its operation even though the inputto the relay is removed prior to the specified operating time. For example, if for a given current, the relay operates in 0.8 seconds,but the relay operates even though the input current lasts only 0.75 seconds, the overtravel time is 50 milliseconds. The maximumovertravel time of an upstream relay must be factored into the discrimination interval between this upstream relay and a downstreamovercurrent device to ensure that the upstream device does not operate when the downstream device correctly interrupts theovercurrent. The overshoot time of a relay is provided by the relay manufacturer, and can be as low as 30 milliseconds for solidstate relays, and as high as 100 milliseconds for electromechanical relays.

SECONDARY-SELECTIVE SUBSTATION

A secondary selective substation has two busses, each supplied by a normally-closed incoming circuit breaker, and connectedtogether by a normally-open bus tie breaker. In our designs per IP 16-12-2, the loss of supply upstream of one incoming breakerresults in automatic opening of that incoming breaker, followed by closing of the tie breaker after the “dead” bus’s residual voltagehas decayed to a safe level.

SELECTIVITY/COORDINATION/DISCRIMINATION

Selectivity describes a protective system that has been designed and adjusted such that the protective device nearest to the faultoperates first to clear the fault, and its setting allows an adequate margin of safety so that a protective device farther from the faultdoes not operate for the same fault. As the relay coordination procedure commences at the load and works back to the powersource, we generally say an upstream device is selective with a downstream device.

SPOT-NETWORK SUBSTATION

A spot network substation has a main bus (with or without a normally-closed tie breaker), which is supplied by two normally-closedincoming breakers. Tripping of one incoming breaker due to an upstream fault leaves the entire substation load on the other incomerwithout the transfer of load required for secondary-selective substations. A relayed tie breaker is provided when it is important tomaintain supply to the loads on one of the busses for a bus fault or uncleared feeder fault on the other bus.




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PROTECTIVE DEVICE TYPES AND APPLIC ATION

DIRECT ACTING TRIPS

A direct-acting-trip circuit breaker uses abnormally high current flowing into the breaker to initiate a time-delayed or instantaneousresponse which causes a direct acting operating mechanism to mechanically trip the breaker, without the need for external currenttransformers and relays. The time-current characteristic of a direct-acting-trip breaker is a band, the upper boundary of whichindicates the maximum total clearing time of the breaker for a given current, while the lower boundary indicates the minimumclearing time. Direct acting trip units may be electromechanical (thermal-magnetic) or solid-state electronic. They are used inmolded-case/insulated-case circuit breakers; and they are also used in low-voltage switchgear circuit breakers in the followingapplications:

� For all outgoing feeder breakers, such as to MCCs, TAPCs, transformers, and typically to motors that would require larger thana size 4 starter. For motor feeders, the direct acting trip of a switchgear circuit breaker must be backed up with athermal-overload (49) relay in one phase.

� With Owner’s Engineer approval, for the 51 and 51N functions of secondary-selective incoming breakers. The 51N ground faultfunction is available in direct acting trips with internal current transformers. The 50 and 50N functions must be relays.

� Incoming breakers in radial and primary selective substations.

� Incoming and outgoing circuit breakers in conjunction with auto-reclose.

This last application, which we have in use in Europe, permits instantaneous tripping on both incoming and outgoing circuitbreakers. The circuit breakers have a one shot auto-reclose if immediately upstream of the load instantaneous protection, and twoshot auto-reclose if located upstream of a one shot auto-reclose circuit breaker. In this application, the circuit breakers are usuallycurrent limiting.

IP 16-12-1 states: “Selective reclosure for current limiting breakers is acceptable only if approved by the Owner’s Engineer.” If thisis employed, the relaying downstream of the circuit breaker with the instantaneous direct acting trip must be arranged for the motorsto “ride through” the disturbance or auto restart.

FUSES

Fuses are simple and reliable fault interrupters. They are less expensive than circuit breakers, but they cannot be re-used andcannot be tested. The types of fuses most often used in our installations are current limiting, which means that above a given faultlevel, the fuse will interrupt the fault current before it reaches its first peak. By limiting the magnitude and duration of fault current,current-limiting fuses minimize stress and damage to equipment, and can allow use of less expensive equipment downstream ofthe fuse. The typical use of current-limiting fuses is in motor starters, in general-purpose feeder protection, and in the protectionof transformers (usually smaller than 500 kVA in Exxon designs).

When a current-limiting fuse operates for currents in its current-limiting range, it can be characterized by its peak let-through current(see Figure 2 ), and by its minimum melting and total clearing I2t characteristics (discussed below).

When a current-limiting fuse operates for currents below its current-limiting range, it can be characterized by itstime-current-characteristic (TCC) curves, which are similar to those of other fuses.

The melting time of a fuse (sometimes referred to as pre-arcing time) is the interval from the inception of a given fault current upto the time that melting of the fuse element is sufficient for arcing to just begin.

The minimum melting curve provided by the fuse manufacturer shows the least amount of time it takes for a given current to meltan unloaded fuse in its non-current-limiting range of operation. The fuse manufacturer provides information on how to adjust theminimum-melt curve to account for preloading and other variables. The adjustment is current-based and moves the minimum-meltcurve to the left.

The minimum melting curve is used to coordinate the fuse with downstream protective devices for fault levels below the fuse’scurrent limiting threshold. The minimum melting curve is also used to avoid fuse melting during motor starting or transformerenergization. See the discussion of I2t below for current limiting operation.

The total clearing time of a fuse is the interval from the inception of the fault to the time the fault is completely interrupted.

The total clearing curve provided by the fuse manufacturer shows the maximum time it takes the fuse to completely clear anygiven constant fault current in the fuse’s non-current-limiting range of operation.




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PROTECTIVE DEVICE TYPES AND APPLIC ATION (Cont)

The fuse’s total clearing time curve is used to coordinate upstream time-delayed protective devices with the fuse for currents lessthan the fuse’s current-limiting threshold. See the discussion of I2t below for current limiting operation.

Averag e meltin g curve s are sometimes provided by a fuse manufacturer. These curves have a plus or minus tolerance of 10%on current for any given time. Thus the minimum melting curve is 10% lower in current than the average melting curve, and themaximum melting curve is 10% higher. For times greater than about 0.1 second, the maximum melting curve is essentially thesame as the total clearing curve. If coordination with an upstream time-delayed device were questionable in the time between0.1 second and 0.01 second, the estimated arcing time would have to be added to the maximum melting curve to approximatethe total clearing time.

For fault clearing times of one half cycle or less (e.g., below 0.01 second at 50 Hz), the peak let-through or I2t characteristics ofthe current-limiting fuse should be used.

Total clearing I 2t and minimum melting I 2t data can be used for coordinating fuses in their current-limiting range. Two currentlimiting fuses connected in series coordinate when the downstream fuse’s total clearing I2t is less than the upstream fuse’s minimummelting I2t. Figures 22 and 43 show I2t data versus fuse sizes.

The ratio s of fus e sizes require d fo r coordinatio n are provided in manufacturers’ literature in the form of tables showing thesize ratio of upstream to downstream fuses that will guarantee coordination. The ratio will be a constant for fuses of the sametype (e.g., 2:1), but an upstream fuse of one type may need to be anywhere from 2 times to 8 times the size of a downstreamfuse of a different type, in accordance with manufacturers’ ratio data. If closer fuse sizing (than indicated by the ratio tables) isdesired for a system coordination study, then the other fuse data discussed above should be used.

Peak let-through fuse data can be used to coordinate an upstream instantaneous relay with a downstream current limitingfuse. Coordination is achieved if the fuse’s peak let-through current times 0.707 is less than the rms pick-up setting of the upstreaminstantaneous unit. This current limitation effectively ensures that the instantaneous device does not see enough energy to operate.Figure 23 illustrates the half cycle worth of energy it takes to just cause pickup of an instantaneous relay. Figure 24 illustrates thepickup-energy portion of a current higher than the relay’s pickup current. It can be seen in Figure 25 that a current-limiting fusewill not allow the relay to see enough energy to pick up if the peak let-through of the fuse is less than the peak of the relay’s rmspickup.

Peak let-through data is presented as a function of the available symmetrical rms short-circuit current as shown in Figure 26 . Theline AB in Figure 26 represents the boundary between current limitation and non current limitation. The slope of line AB could beanything from 1.414, which is the peak of a symmetrical current, up to 2.828, which is the peak of a fully offset current. For peaklet-through determination, the slope of line AB is a function of the fault power factor, and is often drawn with a slope of about 2.6.A second line AB with a slope of 1.414 can be drawn for a short cut determination of the symmetrical rms current that has the samepeak value as the fuse’s peak let-through. For example, if for a given situation, the peak let-through current is 14,140 amperes onthe y-axis, the corresponding “equivalent” symmetrical rms value per the 1.414-sloped line is 10,000 amperes on the x-axis.

Explosive fuses are current limiting fuses that achieve fault-current interruption with the help of electronically-triggered explosivecharges. Such fuses (sometimes called smart fuses) are used where fault current limitation is required, but where the normaloperating current is too high for conventional current-limiting fuses. Explosive fuses can be used to split a system with inadequatelyrated interrupting equipment into two lower fault-level systems, or to limit the fault current from a specific source by opening its circuitor by opening a bypass around a current-limiting reactor. Such applications may be considered when a system is expanded beyondits equipment fault rating and the addition of current limiting reactors would present unacceptable operating voltage problems.

Some fuses have indicators that make it easy to detect a “blown” fuse, and striker pins that are released when the fuse “blows”.Striker pins are used to trigger a mechanism that opens a switching device to isolate all three phases, thereby preventing singlephasing.

The rating of a fuse is the current that it can carry continuously without deterioration. However, transient currents and temperaturecycling can “age” a fuse; therefore they are often replaced every five of ten years to avoid maloperation. The current at which afuse will start to melt is in the order of 120% to 150% of its rating.

A list of I.E.C. recommended fuse ratings for low voltage is given in Table 1.




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For our purposes, fuses can be divided into three main categories, as follows:

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

CATEGORY ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

TYPICAL APPLIC ATION ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

CURRENT LET-THRU


Slow Blow ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Rural Distribution Overhead Lines ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

System Peak


General Purpose ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Industry (90% of all fuses) ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Current Limiting


Ultra Rapid ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Inverter Loads/Instruments ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Current Limiting

The operation of a current limiting fuse in its current-limiting zone is shown in Figure 2 where the actual peak current that flows(let-through) is considerable less than what would have flowed if it had not been interrupted by the fuse. Fuse manufacturers providepeak let-through curves which show peak current as a function of fuse size and available fault current.

Fuses have many sophisticated features to cater for transformer inrush, motor starting, etc., so much so that in every case for thefinal design, the manufacture’s recommendations should be followed as to which type of fuse is used. Additionally, the data for theactual fuses used should be available for the relay coordination study.

In summary, always use the manufacturer’s recommendations in selecting the type of fuse, and for relay coordination use the datapertaining to the particular fuse that is used. The following data are generally required from the manufacturer:

� Pre-arcing (minimum melting) curves – to discriminate with motor starting and transformer inrush currents, and withdownstream overcurrent devices for a fault current below the fuse’s current-limiting threshold.

� Total clearing curves – to discriminate with upstream time-delayed overcurrent devices (not including current-limiting fuses).

� Peak let-through curves – to discriminate with instantaneous relays.

� Current squared time (I2t) curves for pre-arcing and total clearing, or fuse selectivity-ratio data, to discriminate between fuses.

RELAYS – GENERAL

Protective relays use inputs of current or voltage, or a combination of both, and compare these inputs to a threshold quantity whichis normally called the pickup (or the setting). Once the threshold is passed in the operating direction (e.g., high current, low voltage,low fault-impedance, etc.), the relay will either operate almost immediately (instantaneous relaying), or with a time delay. The timedelay is either fixed (definite time), or is a inverse function of the measured quantity; e.g., for an overcurrent relay, the higher thecurrent, the shorter the time delay. If the magnitude of the measured quantity returns to a non-operating level before the timing hasgone too far, the relay will reset without operating. In addition to measurement, comparison and time delay, some protective relaysdetermine and act upon the direction of the measured quantity; some perform filtering functions such as deriving sequence networkquantities; and some can retain event information and perform self-checking.

Electromechanical relays use magnetic attraction, magnetic induction, or thermal heating to achieve operation.

Solid state relays use low-power resistors, capacitors, and semi-conductor devices arranged into logic circuits to achieve operation.

Microprocessor-based relays use digital sampling and processing technology to achieve operation. They can also store eventinformation, do self-checking, and can communicate with external digital equipment.

Solid state and microprocessor-based relays have many advantages over electromechanical relays, and have become therelay-type of choice, especially for applications outside of low-voltage-motor starters.

RELAYS – DEVICE DESCRIPTIONS

Most of the relays we use in our plants are discussed below.

TIME DELAY RELAYS (2) AND (62)

We use time delay relays extensively in protective relaying and in motor reacceleration circuits. These are relatively simple relayswith some form of timing device which delays contact operation when the relay is activated. The relays must ensure that the timercan remain dormant for long periods and then operate correctly when required. Timers are either pneumatic, mechanical, orsolid state.




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DISTANCE RELAYS (21)

Relays that measure some form of impedance, often along a transmission line, are called distance relays. The terminology fordistance relays depends on how the relay uses its current and voltage inputs. Relays that effectively operate on the magnitude ofa measured impedance, but not its direction, are called impedance relays; while relays that operate on the magnitude of reactanceare called reactance relays. Both of these are normally supervised by a directional relay. Relays that measure impedancemagnitude but are inherently directional are called admittance or mho relays. How the current and voltage transformers should beconnected for various applications, and how to interpret what each relay sees for unbalanced faults is beyond the scope of thisDesign Practice. The relay instruction manual should be consulted for any given application.

When the measured impedance is less than the preset value, the relay operates. The main applications are on utility networks wherethey may be the most common relay in use. Some knowledge of their modes of operation is essential to us when we must coordinateour protective relaying with that of the local utility to which we are connected. We have the potential to use distance relaying insteadof 51V relaying for generators that are stepped up directly to a utility transmission line protected by distance relaying.

An application of distance/impedance relaying is shown in Figure 19 which shows diagramatically the operating zones and timesfor one relay on a utility transmission or distribution network. Each of the other circuit breakers shown in Figure 19 will have a similarrelay “looking” into its line (i.e., away from its local busbar) with settings on the same basis as the one shown.

The first stage of protection “looks” at 80% of its line and for a fault in that zone will operate within 0.1 seconds. The second stagelooks at 120% of its line and will operate in 0.5 seconds. The third stage (which may be non-directional) is looking at 200% of theline impedance in both directions and has an operation time of 1.5 seconds. At Busbar B there will be a directional relay on the linebetween bus A and B looking back towards bus A.

This is only a typical scheme; actual applications will vary considerably. For a fault in the middle 40% of any line, the breakers atboth ends will be tripped by the first stage of the protection to isolate the fault. For a fault in the 20% at either end of the line, thecircuit breaker nearest the fault will be tripped by the first stage of protection and the circuit breaker at the end of the line farthestfrom the fault will be tripped by the second stage of protection. If the circuit breaker nearest the fault fails to trip, its busbar will beisolated by the second stage of the feeder breakers supplying the bus. Likewise, the third stage of protection provides back-upprotection for a breaker that fails to clear a fault at the remote end of the line.

If supply to our facilities is derived from Busbar A, we know that we can see a reduced voltage for 0.5 seconds plus breaker clearingtime for distant faults cleared by the second stage of the first line protection.

When a line segment protected by a distance relay has a second source of fault current connected between the relay and a fault,the impedance relay sees a higher apparent impedance than when the second source is disconnected. A diagram and formula(Equation 12) for the higher apparent impedance is presented near the end of this Design Practice in the section entitled“CONVERSIONS AND CALCULATIONS” under the side heading “Determining Distance Relay Apparent Impedance, ZR, Due toInfeed Current”. An impedance relay that should not see beyond a given distance must be set with the second source disconnected.The relay will not protect as much of the line with the second source in, as it does when the second source is out. In effect the relayunderreaches its setting when the second fault-current source is connected.

VOLTS/HERTZ RELAYING (24) – OVEREXCITATION PROTECTION

Overexcitation (and overheating) of the magnetic core of generators and fully loaded transformers begins when the ratio of per unitvoltage to per unit frequency exceeds 1.05, and increases rapidly as the volts/hertz ratio increases. Some form of volts/hertzprotection is needed for generators – either in the form of a volts/hertz limiter in the exciter control system or volts/hertz relaying,or both. Volts/hertz relaying is needed for transformers that could be subjected to overexcitation. Where volts/hertz relaying isapplied, an alarm function should be provided with enough lead time to allow operator intervention before tripping occurs.

SYNCHRONIZING RELAYS (25)

Synchronizing relays can be divided into two main groups: system synchronizing check relays, and generator synchronizing relays.The former are used to block paralleling two parts of an electrical system that are not synchronized. They are relatively slow speedand are not used for generator synchronizing on machines above about 500 kVA.

Generator synchronizing relays are the main component of equipment packages which function to insure that the system andincoming machine-voltage magnitude, phase angle and slip frequency are within acceptable limits relative to the system voltageat the moment the generator breaker closes to synchronize the machine to the system.




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Generator synchronizing relays can be further divided into three types:

� Machine out of synchronism blocking relays

� Semi-automatic synchronizing relays

� Automatic synchronizing relays

Machine out of synchronism blocking relays will prevent closing of a generator breaker when the machine voltage vector is outsidethe preset limits, as compared to the system voltage vector. This relay is more complex than the system synchronizing check relay,since it takes into account the velocity of the machine voltage vector (phase angle and slip frequency) with respect to the systemvector as one does when synchronizing manually.

Automatic synchronizing relays are equipment packages which adjust the driver governor and generator excitation, and close thegenerator breaker when the generator voltage matches the system voltage within acceptable limits. Some automatic synchronizingrelays are also equipped to load the generator after synchronizing. Semi-automatic synchronizing relays require the operator toclose the breaker using the control switch.

We use all four types of synchronizing relays. The system synchronizing check relays are used in the automatic transfer circuit (seeIP 16-12-2) to prevent an operator from paralleling two infeeds that are out of synchronism when making a manual transfer. Also,we usually use one of the three machine synchronizing relays on our generators to facilitate proper synchronizing and avoidoperator errors, even though synchronizing a generator can be done manually using the synchroscope and voltmeters which arealways provided.

TEMPERATURE RELAYS (26)

These relays are temperature measuring devices with contacts that operate when a preset temperature is reached. We fit theseto all our power transformers (see IP 16-10-1) where the relay takes the form of a dial-type thermometer for indicating the top ofthe liquid temperature. The relay has two hands, one showing oil temperature at time of reading and the second showing maximumtemperature reached since last resetting.

For our applications, the thermometer must have hermetically-sealed, normally-closed alarm contacts set to open at the maximumself-cooled operating temperature of the transformer.

Transformers are normally supplied with temperature relays but the contacts are usually open to the atmosphere. Manufacturersgenerally meet our requirements by fitting mercury bottle switches.

The hermetically sealed contacts are required for two reasons:

� Transformers are usually located at the very edge of Division 2 areas.

� Bare contacts that will normally never operate can deteriorate in our plants.

On large main substation transformers, a more sophisticated temperature relay is used that more closely reproduces the hot-spottemperature, and switches fans and sometimes an oil circulating pump on and off.

UNDERVOLTAGE RELAYS (27)

These are either induction disc, attracted armature, or solid state devices that operate when the voltage falls below a preset level.They may be instantaneous, definite time, or time delayed with an inverse characteristic that provides the fastest clearing at zerovoltage. The symbol “27” is generally used for time delay relays and “27I” for instantaneous relays.

We use undervoltage relays for:

� Automatic transfer circuit in IP 16-12-2.

� Undervoltage protection (tripping) for motors controlled by circuit breakers, latched contactors, and d-c held contactors.

� Monitoring the voltages of the d-c control power supply for the switchgear plus the control voltage in each switchgear assembly,as per IP 16-2-1 and IP 16-12-1.

� Step reacceleration circuits.




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� Separation of in-plant generators from the utility (sometimes in combination with a second relay, such as a directionalovercurrent).

� To off-load constant torque equipment such as positive-displacement/reciprocating compressors.

� To monitor voltage on each remote bus supplying Emergency Block Valves (EBV’s) Type C and D (IP 16-2-1).

DIRECTIONAL POWER REL AY (32)

See “DIRECTIONAL OVERCURRENT AND POWER RELAYS (67 AND 32)” below.

LOSS OF FIELD REL AYS (40)

Synchronous generators and synchronous motors are fitted with this relay, which typically uses one or two distance relays, andmay include directional and undervoltage units. Loss of field can cause high currents in both the stator and rotor which can leadto dangerous overheating in a very short time. The var drain on the rest of the system can result in low system voltage and canadversely affect system stability. See Subsection B .

NEGATIVE-SEQUENCE OVERCURRENT RELAYS (46) – GENERATOR PROTECTION

Device number 46 is used both for Phase Balance relays (which respond to unbalanced phase currents) and for Negative Sequencecurrent relays (which respond to the negative sequence component of unbalanced phase currents). It is our normal practice toprovide Negative Sequence Current (46) relaying to generators, and to trip the generator breaker with this relay. The applicationof Phase Balance relaying is covered under the next subheading below.

Negative sequence currents are caused by system imbalances and asymmetries such as unbalanced faults, untransposedtransmission lines, an open-circuited phase, and unbalanced load. Negative sequence currents in a machine stator inducedouble-frequency rotor currents, which produce additional heating that can be damaging even when the total phase current is lessthan rated current. Even a small voltage unbalance can produce significant negative-sequence current because thenegative-sequence impedance is relatively low – approximately equal to the subtransient reactance for a generator (or the lockedrotor impedance for a motor). Thus a 5% negative sequence voltage applied to a generator with X2 = 12.5% can produce I2 = 40%of generator rated current, which would quickly cause an excessive temperature rise.

Generators have a short-time negative-sequence-current limit expressed as I22t = K, where K is , for example, 30 for an air-cooledcylindrical rotor machine (per MG-1). Generators have a continuous I2 capability limit which is typically 10 percent of the rated phasecurrent (per MG-1), and may be as high as 15% in some machines.

Electromechanical negative-sequence current relays have an extremely inverse I2 versus time characteristic which generallycannot be set more sensitively than to pickup at about I2 = 60% of rated full load current; therefore their primary tripping functionis to protect the generator against an uncleared phase-to-phase fault.

It is herein recommended that solid state negative-sequence current relays be used for generator protection because they providemore sensitive protection than electromechanical relays. Solid state 46 relays typically can protect generators against I2 currentsalmost as low as the generator’s continuous I2 capability. For example, if a relay has a maximum delay of 990 seconds, and K is30, the relay will correctly trip for I2 down to 17.5% of generator rated current.

It is herein recommended that consideration be given to a 46 relay with the additional feature of a sensitive alarm setting (with asmall alarm delay of about 5 seconds) which can warn the operator that a low level unbalance problem is developing. This maygive the operator sufficient time to take prescribed actions, which could include separating from the utility if the utility is identifiedas the source of the imbalance; or determining the amount of imbalance and, if practical, reducing generator output to reducemachine temperature. Any of these actions would have to be pre-planned and documented as operating procedures.

Each application of a 46 relay has to be evaluated on its own merits. In some cases it may be preferable to immediately trip thegenerator breaker at the first sign of trouble because the utility can handle the load. In another situation, the in-plant generationmay provide most of the power and it may be preferable to drop a weak utility tie – especially since it may well be the utility thatis causing the imbalance.




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PHASE BALANC E RELAYS (46) – MOTOR PROTECTION

Phase balance relays have typically only been applied to motors when this protection function is included as part of acomprehensive solid-state motor-protection relay. It is not required by Exxon’s International Practices. However, where largeunspared critical motors are involved, it is recommended to consider phase balance relaying, which can be provided by acomprehensive solid-state motor-protection relay.

NEGATIVE SEQUENCE VOLTAGE RELAY (47) – MOTOR PROTECTION

This relaying is not required by Exxon’s International Practices, and has not previously been covered in this Design Practice.However, it is recommended that negative-sequence-voltage relaying, set to alarm, be considered for the main power buses of allplants. If there is inplant generation which has tripped due to negative sequence relaying, that relaying is no longer there to indicatewhether the negative-sequence condition is persisting and potentially damaging the plant’s motors. Per ANSI C37.96-1988, a motorwith a typical 0.167 per unit locked rotor impedance, when subjected to a 5% negative sequence voltage, will experience a 30%negative sequence current and a 40 to 50% increase in temperature rise. Since this temperature rise is originating in the rotor, itwill not be sensed by overload relays and probably would not be sensed by stator RTD’s until it is too late.

A 47 relay is sensitive to imbalances in the source system upstream of the relay, but is much less sensitive to downstreamimbalances because downstream imbalances generally have a minor effect on the upstream voltage that the 47 relay is sensing.A 47 relay applied on a plant’s main power busses is likely to detect an open phase or other imbalances in the utility system, butnot an open phase in an inplant distribution feeder. Since our inplant designs make it unlikely that we will have an open phase orother persistent imbalance inside the plant, we could apply 47 relaying on our main power buses to detect and alarm for the presenceof negative sequence voltage arising from the utility company’s system.

THERMAL OVERLOAD REL AYS (49) AND LOCKED RO TOR PROTECTION

In IEEE standards, device “49” is listed as a “Thermal Relay” which functions when a winding temperature exceeds a preset value.In practice, most motor overload devices in our plants do not sense winding temperature, but instead, they use stator current tosimulate thermal conditions in the motor. In some cases, current-sensing overload relays are supplemented by winding temperaturedetectors which provide a high-temperature alarm. As used herein, the term “thermal relays” is applied both to separate relayssupplied from external current transformers and to the thermal elements (sometimes called “heaters”) in motor starters. Asdiscussed below, a 49 relay may also be used to provide motor locked-rotor protection.

With few exceptions (discussed below), our motors are tripped for specified overload conditions via solid-state or thermal-elementrelays that monitor all three of the stator phase currents. Our practices do not call for tripping of motors via winding temperaturedetectors, which activate alarms upon sensing high stator temperature.

Thermal overload relays are normally set to pick up at 110 to 115% of motor full load amperes (FLA) for 1.0 service factor motors,and at 125% of FLA for 1.15 service factor motors. These settings provide protection against moderate overloads. Higher settings– up to 140% of FLA per discussion below – might be approved on an exception basis when normal settings trip the motor on starting,or when critical process considerations make it worth subjecting a motor to moderate overload rather than tripping it.

The role of thermal overload relays in locked rotor protection will now be addressed. Thermal overload relaysprotecting medium-voltage motors have to be supplemented by a separate overcurrent (51) locked-rotor relay in one phase. SeeFigures 28 F and G.

Two things to keep in mind in the application of locked-rotor-current sensing devices are as follows:

� They may operate even though the applicable relay curve is above the trace of the starting current. This can happen becausethe relay integrates the effect of the current. Thus the relay curve either has to be set above the motor’s total starting time(assuming constant locked rotor current), or the integration effect of the relay has to be taken into account (which is somewhatcomplicated, and will not be addressed herein).

� In some cases, it may not be possible for a locked rotor relay to both start/reaccelerate a motor and provide locked rotorprotection because the motor starting time exceeds or is too close to the locked rotor damage time. In such cases one of thetwo options discussed at the end what follows has to be implemented.




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Locked rotor protection for contactor-controlled, low-voltage motors is provided solely by the contactor’s standard overloadrelays when the relay characteristic provides both locked-rotor protection and starting/reaccelerating capability. However, ifthey cannot be set to both prevent locked rotor damage and allow the motor to start (or reaccelerate), the following solutionsshould be evaluated:

� If the motor can be started/reaccelerated, but the overload relay does not provide locked rotor protection, add a separate lockedrotor relay if it can be set above the motor starting time and below the locked rotor damage point.

� If the motor cannot be started/reaccelerated because the starting time is too long for the standard (Class 10) thermalcharacteristic (cold curve for starting, hot for reaccelerating), investigate substituting an overload relay with normal pickupsetting and a longer time delay at lock rotor current (e.g., a Class 20 or 30 overload relay). If the longer delay allowsstarting/reacceleration but it does not provide locked rotor protection, add a separate locked rotor relay that permits startingand provides locked rotor protection.

� If the motor still cannot be started using longer delay characteristics per above, change to the next size thermal element orincrease the relay pickup so that the motor can start (or reaccelerate). This solution does not provide protection againstmoderate overloads. In no case shall the pickup exceed 140% of motor FLA. If pickup would have to exceed 140% of motorFLA to permit starting/reacceleration, the overload must be replaced with one that picks up below 140%. With pickup notexceeding 140% of motor FLA, and with the motor able to start/reaccelerate, the overload relay must either protect againstlocked-rotor damage, or it must be supplemented by a separate locked rotor relay.

If a motor’s starting time exceeds or is too close to the locked rotor damage time, simple locked rotor protection will not work properly.In this case, thermal overload relays provide protection against moderate overloads, and a separate locked-rotor relay must beprovided with supervision per one of the following:

� Use a “zero-speed” switch to supervise a locked rotor relay set to protect the motor against locked rotor damage. The switchdisables the relay trip signal if the motor achieves a preset low-level speed soon after the motor is energized.

� Use a distance (mho) relay to supervise a locked rotor relay set to protect against locked rotor damage. The distance relay (21)operates immediately when it sees a locked rotor impedance, and closes its contact which is in series with the contact of thelocked rotor relay. If the 21 relay continues to sense a locked rotor condition, the locked rotor relay will trip the motor when itfinishes timing out. However, if the motor impedance changes sufficiently to indicate that a successful start is underway, the21 relay drops out and disables the trip signal from the locked rotor relay. Check with the relay vendor to determine if it ispreferable to use a three phase distance relay over a single phase relay for this application.

If it is specified that a piece of driven equipment is so critical to the process that it is preferable to sustain moderate insulationaging/damage than to trip for a moderate overload, the overload relays shall be set higher, and shall be supplemented by windingtemperature detectors (or less preferably by an additional thermal-overload relay) set to alarm at or just above motor rating. Thealarm has to sound in a manned control room so that immediate attention can be paid to the situation. The normal overload relayswould be set to trip above any foreseeable overload (such as a surge condition in a compressor) but not above 140% of motor FLA.If the critical motor is a low voltage motor and is not protected against locked rotor by the “tripping” overload relays, a separate lockedrotor relay must be provided.

The locked-rotor function of a multi-purpose motor-protection relay can be used in place of a separate locked rotor relay if its rangeand adjustability provide proper protection. The locked rotor protection functions of some multi-purpose relays have limitedadjustability and are tied to both the hot and cold thermal curves, thus potentially creating difficulty in fitting the relay characteristicbetween the motor start time and the locked rotor damage point(s). If the locked rotor function does not have its own output contact,it could not be used with the speed switch or distance relaying schemes above.

The additions and exceptions to tripping of motors via current-sensing thermal-overload relays in all three phases are as follows:

� Thermal overload relays are disconnected for Type C and D Emergency Block Valves (per IP 16-2-1), and thermal overloadrelays are not provided in the starters for firewater pumps. The basis for omitting overload protection is that the risk to peoplewould be greater if the motor is tripped on overload than if it is not.

� When low voltage motors are controlled by switchgear circuit breakers with direct acting trips, the direct acting trips provideoverload and locked rotor protection, with backup via an overload relay in one phase.

� Motors with air filters and motors over 1500 HP are to be provided with the additional protection of a high temperature alarmfrom resistance temperature detectors imbedded in the stator winding. The alarm level should be at or just above the ratedtemperature of the winding. Overload and locked rotor protection are provided by relays per normal practice discussed above.




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INSTANTANEOUS OVERCURRENT RELAYS (50)

Instantaneous overcurrent relays (50) are electromechanical or solid-state relays with very short operating times – on the orderof one-half to one cycle at or above 5 times pickup, and about 1.5 cycles at 1.5 to 2 times pickup. Below 1.5 to 2 times pickup, relayoperating time may be 2 to 5 cycles or more. Thus instantaneous relays are not truly instantaneous. See Figure 7 .

Some instantaneous relays have low overreach (see “DEFINITIONS” section) because of dc filters, and therefore they see muchless current than may actually be flowing in an offset fault current. See Figures 3 , 4, and 5. Low overreach allows these relays tobe set lower than high overreach relays, thus providing more sensitive protection. See Figure 6 for typical overreach data on a lowoverreach 50 relay.

In summary, instantaneous overcurrent relays:

� Are calibrated in symmetrical rms amperes.

� Pick up at a current equal to the setting value.

� Have very rough rule of thumb operating times of one and a half cycles at a current equal to 1.5 times the setting, and half toone cycle at a current five times setting.

� Some are available with d-c filters to reduce transient overreach to much lower values than unfiltered relays.

� Vary in performance. Manufacturer’s data of actual relay should be used.

INVERSE TIME OVERCURRENT RELAYS (51)

These relays either have an induction disk that rotates when the current is above the setting to close a set of contacts, or areelectronic solid state devices. The role of 51 relays in motor locked-rotor protection is discussed above under “THERMALOVERLOAD RELAYS (49) AND LCOKED ROTOR PROTECTION”.

Facilities are provided to adjust both the current setting and the time of operation to give a family of curves for time vs. current. Inthe case of electromechanical relays, the current is adjusted in steps by inserting a plug into a socket that usually has a currentrange of four to one times nominal current in seven steps. The time is adjusted by a dial that varies the angular distance throughwhich the disk has to rotate to close the contacts. This “time dial” is infinitely variable over a range of settings. Typical setting rangesare 0.5 to 10, 0.1 to 1. A typical family of curves for an inverse time induction-disk overcurrent relay is shown in Figure 8 . A typicalsolid-state relay has a current range of 2.4 to 0.05 times nominal current in 47 steps. Its time characteristic can be varied from 0.05to 1.0 times the time of the base characteristic (in steps of 0.025). For the inverse time characteristic, this results in a range from0.1 second to 2.0 seconds at 31 times the current setting, in steps of 0.05 second. This is comparable to the time range of theinduction-disk relay in Figure 8 .

It will be noted in Figure 8 that the curves are not extended below a current of one and a half times the tap (current) setting. In theory,the relay should pick up at the current setting of the tap selected but, in fact, the induction disc generally starts to rotate (pick up)at a current slightly above the tap setting. Thus, the relay’s accuracy in the region of the pickup current is not reliable. Onesolid-state-relay manufacturer shows the relay curves dashed below 2 times pickup and gives accuracy data only above 2 timespickup.

At high multiples of the pickup setting, varying from 20 to 50 times pickup, depending on the relay, the Time vs. Current curves ofinverse relays tend to go asymptotic. Because of this, many inverse time relays are designated as Inverse Definite Minimum Time(IDMT), with a specified minimum time of operation at the point where the Time vs. Current curve becomes asymptotic at highcurrents. This time is useful when determining time dial settings to provide discrimination between relays.

Relays are available with varying degrees of Time vs. Current slope to suit the various applications. The normal classifications are“Extremely Inverse,” “Very Inverse,” and “Inverse,” as shown in Figure 9 .

Extremely inverse relays are useful in providing discrimination with fuses, as the shapes of the two Time vs. Current curves aresimilar. Where coordination with fuses is not a problem, an inverse-time characteristic provides a relatively short operating timeover a wide range of currents, and is the curve of choice in the majority of applications.




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Extremely inverse relays should not be used for transformer primary protection as they are not suited to the large range of currentsover which selectivity is required. Transformer primary protection (51) relays have to see through the transformer for secondaryfaults. If extremely inverse relays are used for primary protection of transformers, it is generally not possible to meet the IP 16-2-1requirement of operating in less than two seconds at 50% of minimum secondary bolted phase-to-phase fault current.

One feature of all inverse time overcurrent relays, both induction disk and solid state, is overtravel/overshoot (see “DEFINITIONS”section) which causes the relay to continue to “time out” for a short time after the current has ceased. For selectivity, it is commonto allow 0.05 (solid state) to 0.1 second (induction disk) for overshoot of upstream relays. Use actual relay overshoot data whereavailable.

DEFINITE TIME OVERCURRENT RELAYS (51)

These relays are an alternative to the inverse time overcurrent relays and are designated by the same number 51. They may beconsidered as an instantaneous relay (50) plus a timer, thus, it can be seen that their operation occurs after the setting current hasbeen maintained for the duration of the time setting. The Time vs. Current operating curve is shown in Figure 10 .

Some advantages of Definite Time Overcurrent Relays over Inverse Time Overcurrent relays are:

� They provide as good (fast) protection at low fault levels as at high levels.

� They are very easy to apply for discriminating between each other.

Disadvantages are:

� The shape of their Time vs. Current curve is undesirable for discrimination with fuses.

� The shape of their Time vs. Current curve does not follow the thermal overload characteristics of generators, motors,transformers, etc.

Ideal applications for Definite Time Overcurrent relays are for system fault protection where it is not necessary to coordinate withfuses and the thermal characteristics of equipment.

VOLTAGE-RESTRAINED (VOLTAGE-CONTROLLED) OVERCURRENT REL AYS (51V)

We use these relays for generator and generator-busbar overcurrent back-up protection (see Subsection B ).

A voltage-restrained relay uses voltage to apply restraint to an overcurrent relay. For example, a 51V relay that picks up at 200 %current when the voltage is 100%, may pick up at 50% current when the voltage is zero. The pickup, and therefore the relaycurve, varies continuously with voltage, which makes coordination analysis more complicated than with the voltage-controlled typeof relay.

A voltage-controlled relay works as follows: when voltage is above the relay’s voltage setting, operation of the overcurrent elementis blocked or a relatively high pickup characteristic is selected; but when the voltage dips below the relay’s setting, a low pickupcharacteristic is enabled. The voltage setting should be below the lowest expected voltage during motor reacceleration or otherstable voltage transient (probably set just below about 60% voltage).

We need the increased sensitivity of the 51V for generators under fault conditions because, being backup protection, the relay hasa relatively long time delay, and during this delay, the generator fault current will decay significantly from its initial value. Withoutvoltage restraint, an overcurrent characteristic set high enough to avoid tripping for non-fault conditions would take unacceptablylong to operate for a decaying fault current, if it operated at all.

We put the current transformers (CTs) for the 51V at the neutral end of the generator phase conductors. This location providesbackup protection for the generator when the generator is connected to a system that has little or no capability to backfeed faultcurrent into the generator (e.g., island operation). If the potential transformers (PTs) for the relay were on the generator side of thegenerator circuit breaker, the CTs in the generator neutral leads would provide backup to the generator differential protection whenthe generator is energized prior to connection to the system. However, we usually use the main bus PTs for the 51V to save thecost of the extra set of PTs that would be required to obtain this infrequently needed protection.

The 51V provides the ultimate backup for an uncleared fault in all parts of the electrical system into which its setting can reach.




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The 51V has an inverse characteristic, which coordinates well with the inverse characteristics of our in-plant relaying. However,if a generator is stepped up directly to a transmission system protected by distance relays, one would use distance relaying in placeof 51V relaying. In this case, attention must be paid to the configuration of the CTs and PTs relative to the winding configurationof the step-up power transformer.

Because the generator fault current is decaying with time and the relay is integrating the effect of the current, a relay with an inversetime-current characteristic will operate some time sooner than the time where the trace of the decaying current intersects the relaycurve. Thus it is not apparent when relays will operate, and what the discrimination interval between relays will be. The analysisis made more complex if the relay characteristic varies with voltage as it does with the voltage-restrained type of 51V relay. IP 16-2-1requires a relay coordination study to take account of generator decrement effects on relay operation per the method reported byArnold Kelly in IEEE Transactions on Industry and General Applications, March/April, 1965, pp. 130-139.

Generator decrement varies with loading, exciter response, and electrical distance from the fault. The 51V relay should be set withthe minimum safe discrimination interval practical for the maximum fault current through the 51V at zero voltage, and for the leastcurrent that would flow simultaneously through the downstream relay. This condition is usually obtained when the generator withthe 51V is the only source of fault current. The setting should be checked for proper operation under emergency operation conditionssuch as motor reacceleration and stable transient swings for which tripping should not occur.

If the voltage signal drops to zero, typical 51V settings will result in operation of the relay for generator load currents above about50% of generator rating. Thus a generator can be tripped off line due to nothing more than a blown PT fuse. To avoid this problem,voltage balance relaying (device 60) or other PT blown fuse protection should be considered (as discussed further below).

OVERVOLTAGE RELAYS (59)

Overvoltage protection monitoring bus voltage is not normally provided in our systems, but could find application when a generatorvendor requires such protection, or where power factor correction capacitors could cause overvoltage at light load. For generators,volts/hertz relaying (device 24) would be the preferred overvoltage protection, if overvoltage protection is to be provided. If device59 is provided for generator terminal voltage, it would typically be used to alarm, and would be supplied from the relaying PTs, andnot from the PTs for the generator’s voltage regulator. Device 59 is used to monitor voltage across the resistor of a high resistancegrounded system, and alarms or trips depending on operating philosophy.

VOLTAGE BALANC E RELAY (60) / PT FUSE FAILURE

It is recommended that voltage balance relaying (60) or other PT blown fuse protection be considered to protect against falsetripping of a generator due to a blown fuse in the PTs used for 51V relaying (or 40 or 21 relaying). Such protection is recommendedby IEEE and GE. This protection can be provided by a voltage balance relay of the type that connects between two sets of PTs whichsense the same voltage, or by the PT fuse-failure feature of a digital generator-protection system. This protection should soundan alarm and block tripping by the relays affected by the loss or reduction in voltage. The voltage balance relay should be connectedbetween the PTs for generator relaying and the PTs for the generator’s voltage regulator.

BUCHHOLZ AND SUDDEN PRESSURE REL AYS (63)

If fault pressure protection is applied for oil-filled transformers, it will be rate-of-rise type for sealed tank designs, or Buchholz typewhere conservator tanks are used. The Buchholz relay is connected in the pipe between the conservator and tank of an oil-filledtransformer. It traps bubbles of gas released in the transformer as they travel to the highest point and initiates an alarm to signifyan incipient fault. It also trips the transformer circuit breaker(s) if there is an internal fault that causes a surge of oil. There have beenreports of false operation of rate-of-rise type relays due to rapid changes in ambient air temperature and due to through faults, withthe result that many such relays have been disconnected. Hopefully, the root causes of these false trips will be found, and the relaydesign will be changed as necessary since this relaying provides for rapid disconnection of transformers under 10 MVA wheredifferential relay protection is not normally provided.

DIRECTIONAL OVERCURRENT AND POWER REL AYS (67 AND 32)

Two types of Directional Relays discussed herein are the directional overcurrent relay (67) and the directional real-power relay (32),both of which sense the magnitude and direction of the measured quantity. In order to do this, the relay requires a polarizing signal(usually voltage) in addition to the current input. Directional relays will operate correctly with a voltage as low as 1% for faults nearthe relay.




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When showing these relays on a one-line diagram, an arrow should always be added pointing in the direction that the current (orpower) must flow for operation of the relay (i.e., the direction in which the relay is “looking”).

Directional Overcurrent (67) relays are required wherever there is a closed loop, such as a spot network substation, to provideselective tripping either as the prime protection or back-up to unit protection.

Generally, directional overcurrent relays should not be used to protect a generator cable. It is very difficult to set this relay so thatit will provide cable fault protection but not operate for stable system transients which cause reactive current flow into the generator(similar to loss-of-field conditions) but which would not cause field failure relay (40) operation. The generator cable should beprotected by the generator differential relay. See Figures 11 and 12.

Where circumstances such as distance between the generator and its circuit breaker necessitate use of the directional overcurrentrelay as in Figure 11, particular attention must be devoted to selection of the operating characteristics and settings of both thedirectional overcurrent and field failure relays to minimize the possibilities for the false operation described.

The directional or reverse power relay (32) protects against power flow from the system into the generator which occurs on lossof drive motive power. This relay is required for all gas turbine generators due to the substantial power drain from the systemrequired to motor the gas turbine. It may not be required for steam turbine generators (power drain is relatively small) if the turbinehas protection and alarm provisions for the motoring condition.

Very sensitive reverse power relaying is used at the secondary of an import-only utility-tie transformer to sense the loss of theprimary-side voltage when there is a secondary-side voltage source. This is needed when the opening of a remote primary-sidecircuit breaker does not send a transfer trip signal to the transformer’s local circuit breakers.

FREQUENCY RELAYS (81)

The main applications for these relays are:

� Load shedding

� To separate in-plant generation from the utility

A more sophisticated variation of this relay measures rate of change of frequency which is often a better yardstick when decidinghow stable the system is at any one time (see Subsection B ).

LOCKOUT REL AYS (86)

Sometimes called “master tripping relay.” It is an interposing relay in the trip circuit of a circuit breaker which can be initiated by oneor several protection relays. When energized, it does three things:

1. Seals in.

2. Trips the protected circuit(s) by sending a trip signal to one or more circuit breaker(s).

3. Isolates the closing circuit of the circuit breaker(s) supplying the protected circuit to prevent either automatic or manualreclosure.

Note that the relay should isolate the circuit breaker’s closing circuit which is different from maintaining a trip signal. In the formercase, the breaker cannot be closed, in the latter, the breaker can be closed but will trip again immediately.

Reset of the relay may be electrical or by hand. We always use hand reset.

Lockout relays may be series or shunt type. The description of these is given in IP 16-12-2.

We use lockout relays with hand reset for:

� Medium voltage motors, unless the relays for fault protection have mechanical lockout incorporated in them (IP 16-12-1).

� Transformers where we specify transformer protection or transformer secondary protection (IP 16-12-2). When transformerdifferential protection is applied, the differential, Buchholz (or fault pressure relay) and transformer neutral grounding relay areall required to act through a lockout relay which in turn trips the transformer primary feeder circuit breaker and the mainsecondary breaker per IP 16-2-1.




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� Generators – operated by all the generator protective relays. We generally use two lockout relays for this duty. One for thegenerator faults, e.g., differential, and the other for external faults, e.g., 51V.

� Busbar differential protection.

DIFFERENTIAL REL AYS (87)

These relays measure the difference between the current entering a part of the network and the current leaving the same part ofthe network. If there is a discrepancy between these two measurements, there must be a fault, so the relay operates. This is a typeof “Unit Protection” or “Zone Protection” as the relay is only looking at one unit of the network (a cable, transformer, motor, generator,or busbar), and if “what comes out” does not equal “what goes in”, there is a fault in that unit, so the relay operates “instantaneously”to trip the circuit breaker(s).

Examples of differential protection are shown in Figures 13 , 14, 15, and 16.

Differential protection is more expensive than conventional overcurrent protection but has several distinct advantages:

� Selectivity is not required with other relays. This permits sensitive settings with “instantaneous” operating times.

� Location of fault is known – it must be in the zone of protection.

We usually apply differential protection to:

� Main substation power transformers, generator unit-transformers, and all transformers rated 10 MVA and larger.

� Motors rated 2501 HP (1801 kW) and above.

� Generators (except Instrument Power Supply (IPS) generators as these are small).

� Busbars and cables connected to a system that has a generator operating at the same voltage.

� Main substation busbars.

The selection of high-speed differential protection helps to maintain system stability for plants with in-plant generation.

As differential protection is required to operate only for faults within the zone of protection, it must be stable (not operate) for faultsthat are outside the zone. These “through faults” will cause large currents to flow which will be equal in the input and output circuitsof the differential relay’s zone of protection. However, the input and output currents sensed by the differential relay will not be equaldue to CT errors, therefore, the relays need to have a “percent bias” to avoid false operation. Such relays are called “percentdifferential relays”. The percent bias is achieved by introducing restraint against relay operation in such a way that there is significantrestraint against operation for external faults, and there is virtually no restraint for internal faults. This bias is normally expressedas the ratio of the “erroneous” operating current to the average restraining current. If the actual error current in the operating coil(expressed in percent of the actual restraining current) is less than the relay’s percent bias, the relay will not operate for a throughfault. The percent bias can be either fixed for all through currents, or variable, with the percent restraint increasing as thethrough-current (and therefore the current transformer error) increases. Thus if the maximum error expected between the currenttransformers is 10% for the maximum through fault, a fixed 15% or 20% bias characteristic will prevent false operation. If the errorbetween current transformers could be relatively high at high through-fault currents, the better choice is a variable percentdifferential relay which varies the operating to restraining ratio from about 5% to 10% at low currents to as high as 60% at highcurrents.

Transformer differential protection is more complex than differential protection for motors, generators, lines and buses because:

� When the ratio of the current-transformer ratios does not equal the current-ratio of the power transformer, there is an errorcurrent to the differential relay operating coil; e.g., a 13.8/4.16 KV transformer has an ampere ratio of about 1:3.3, whereas theassociated CT’s may be 200/5 and 600/5 (a 1:3 ratio). Thus a through fault gives rise to a guaranteed 10% error current in theoperating coil in this example.

� There is often a phase angle difference between the primary and secondary currents, unless the transformer vector connectionis star/star or delta/delta.

� The ratio of primary to secondary current varies with the transformer tap changer position.

� There may be large inrush currents when the transformer is energized, giving the appearance of an internal fault.




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To overcome the above problems, the transformer differential protection (usually denoted by 87T) is arranged as follows:

� If there is a ratio mismatch between the power transformer and current transformers, the differential relay should haveadjustable taps to compensate for this ratio mismatch, or auxiliary current transformers with taps need to be interposed tocorrect the mismatch.

� To compensate for phase angle difference, the CT’s on the transformer delta winding are connected in star, and the CT’s onthe transformer star winding are connected in delta.

� To compensate for the variation in the power transformer ratio due to tap changing, transformer differential relays have a largerminimum percentage bias (10 to 40%) to desensitize the relay as compared with a generator differential which has a percentagebias of 5 to 10%.

� “Harmonic restraint” is built into the relay to prevent false operation when the transformer is energized, or when inrush occursdue to transients such as fault clearing. IP 16-2-1 requires harmonic restraint on all transformer differential relays.

Where a differential zone of protection extends over long distances, say in excess of a few hundred feet, a differential pilot wire(87P) scheme is generally used. This employs a relay and three CTs at each end, and a pair of pilot wires between the relays topermit comparison, instead of extending all of the current transformer secondary circuits from one end of the zone to the other. SeeFigures 17 and 18. The outputs of the three current transformers are summed unequally such that a balanced three-phase faultproduces a net input to the relay.

In the case of conventional differential protection, four or six conductors are required to connect the CT’s to the three 87 relays.Larger conductor sizes are required as the distance between the two ends of the zone increases.

On the other hand, pilot wire protection only requires a one pair of wires between the ends of the zone that can be miles apart.Supervision of the pilot wire circuit is available.

Pilot supervision will detect and alarm a short circuit, open circuit, or earth fault on the pilot wires. It is usual for us to apply “pilotsupervision” if we use telephone cables, but not if we use a control cable laid with the power cables.

The pilot circuit can be provided by a radio link, but with the relatively short distances usually involved in our applications and thelower reliability of the radio link as compared to a hardwire circuit, to date we have not used radio links for electrical protectioncircuits.

GROUND (EARTH FAULT) RELAYS (50N, 50G, 50GS, 51N, 51G, 51GS, 67N)

See Subsection D for descriptions of ground fault relay types and applications. They can either be supplied from three CTsconnected residually (for which we usually use the symbol “N”), or from a CT in the neutral of a generator or transformer, or froma core balanced CT on a feeder cable. In the two latter cases, we usually use the symbol “G.”

Ground fault protection is sometimes provided by phase fault protective devices, such as in the case of out-going feeders onsolidly-grounded, low-voltage systems when local regulations permit it and when clearing of arcing ground faults is achieved inunder two seconds. Generator phase differential relaying may be sensitive enough to provide first line ground-fault protection forgenerators.

CURRENT TRANSFORMERS

Current transformers form a vital part in protective relaying as we depend on them to reduce the large primary currents tomanageable levels for the relays. When selecting current transformers for Design Specifications, generally the only parameterspecified is the ratio, but the following factors should also be taken into consideration:

� Number of CT’s on a circuit. We do not normally use one set of CT’s for differential relaying, overcurrent relaying, overloadrelaying, and metering, although technically it is possible. All differential circuits should have their own CT’s. Metering andovercurrent relaying are preferred to be on separate CT’s. The revenue (custody) metering will always have its own CT’s.

� Burden on the CT’s. Even after it has been determined that several sets of CT’s are required, there may be too high a burdenon one set, although this is very rare and may only present a problem with generator relaying.

� Overlapping zones. Differential circuits and directional relays should be arranged where possible with overlapping zones.




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CURRENT TRANSFORMERS (Cont)

� Space. Having given all the reasons above for adding current transformers, it must be borne in mind that the space for CT’sin equipment generally limits us to two or three sets at the most. More space is unusual.

When purchasing CT’s, other factors have to be taken into account, such as:

� Knee voltage – which must be high enough to drive the relays. Care must be taken with multi-ratio CTs because the accuracyof the CT at the knee point on the lower ratios may not be adequate.

� Accuracy required for the specific application. Accuracy is measured in terms of ratio error, which is effectively the error betweenwhat the secondary current would be based on the turns ratio and what it actually is. This error is expressed as a percent ofwhat the ideal secondary current would be without the error. For CTs for which the accuracy can be calculated (as discussedbelow), it is reasonable to use the calculated excitation current (divided by the ideal secondary current) as the measure of theerror for phase devices. The excitation current is a function of the voltage across the CT’s burden, which voltage is calculatedwhen the current through the burden is the largest current for which operation is desired. This is usually the maximumthree-phase short circuit current reflected through the CT turns ratio. Some text books indicate that when an instantaneous relay(50), set to trip, comprises part of the burden, the setting/pickup of the 50 relay can be used instead of the maximum short circuitcurrent. We recommend against this approach because at 50 pickup (and up to at least 1.5 to twice pickup), the operating timeof the 50 can be several cycles, which gives the CT time to saturate for currents higher than the 50 pickup. Thus we recommendcalculating CT error for phase devices at the maximum short circuit current.

Current transformers are available in two broad grades; namely, Metering and Protection. Metering CT’s are designed for accuracywhich is typically 0.1% error at rated current, whereas protection CT’s are typically designed for an accuracy where the error is nohigher than 10% at 20 times rated CT secondary current flowing through a standard burden.

Please note that the CT accuracy rating, discussed below, applies to the highest turns ratio of a multi-ratio CT, and for currents andburdens no higher than those upon which the accuracy rating is based. Separate accuracy ratings or other accuracy informationfor the other taps would have to be provided by the manufacturer.

In the USA, a protective-relaying CT has no more than 10% ratio error when the voltage across its burden is equal to or less thanthe secondary terminal rated voltage specified in its accuracy rating. This rated voltage is applicable when it is developedacross a standard burden at 20 times the CT’s rated secondary current. The 10% error limit applies for all currents less than 20times rated secondary current at the standard burden, or any lower standard burden used for CT accuracy rating. The voltage inthe accuracy rating is normally very close to the CT knee voltage.

The accuracy rating in the USA is comprised of a letter and the secondary terminal voltage rating discussed above; e.g., C200 orT200. The letters C or T associated with the rated voltage have the following meaning:

� The C designation means that typical excitation curve data can be used in a simple calculation of the effective (corrected) CTratio. The simple calculation of corrected CT ratio assumes that the effects of flux leakage are negligible. With this assumption,the voltage across the burden of a CT can be used directly to determine the CT’s exciting current from typical excitation curves.The “C” designation cannot be used if the corrected CT ratio determined by this simplified calculation would not be within 1%of the CT ratio determined by test for the same conditions.

� The T designation means that CT-ratio test data must be used to determine the effective CT ratio for various currents andburdens, because the simplified calculation method would not be accurate enough, as described above. The results of ratiotests for a given CT design are presented as a plot of secondary current versus primary current for various standard burdens,up to the highest standard burden which keeps the error below 50%. The currents are plotted in multiples of rated current upto 22 times the primary-side rated current.

Thus a C200 or T200 accuracy rating means the CT can develop 200 volts across the burden without exceeding 10% ratio errorfor all currents up to 20 times rated current and all standard relaying burdens up to the standard burden of 2 ohms (at 0.5 powerfactor). Twenty times current is 100 A (20 X 5 A), and the standard burden is 2 ohms in this case because 200V/100A = 2 ohms.The standard burden is the voltage rating divided by 100 for all CTs with a 5 ampere secondary. If it becomes necessary to determinethe CT accuracy for a specific set of conditions, the accuracy can be calculated for the C-rated transformer using typical excitationdata, or it can be determined from ratio test curves for T-rated transformers.




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CURRENT TRANSFORMERS (Cont)

As a first pass check of the accuracy of a CT for a specific application involving only phase devices, the CT is okay if the burdenis equal to or less than the standard burden for its voltage rating, and if the available fault current is less than or equal to 20 timesthe primary winding rating. If these criteria are not met, either the accuracy has to be checked for the specific application or ahigher-voltage-rating CT should be selected.

The accuracy rating of a CT is not meaningful in the determination of error for a residually connected ground relay, 51N.Determination of the ratio error for a 51N application is complicated by the fact that the CT in the faulted phase has to supplyexcitation current to itself and to the other CTs, which are excited by the voltage across the 51N. When high-burden electromagneticground-fault relays are involved, the total error approaches three times the excitation current of the “faulted” CT. With low-burdensolid state ground-fault relays, the total error will be much less than with electromagnetic relays, and the excitation current addedby the other CTs is likely to be considerably less than the excitation current of the “faulted” CT.

In Europe, a protection CT may be designated “100 VA 5 P 20” where the 100 VA is the burden, and accuracy is 5% or less errorat a primary current of 20 times the CT’s rated primary current. The “P” stands for protection; i.e., a CT used for protective relaying.The IEC Standard 185 covering CTs does not indicate how to deal with currents or burdens higher than those in the ratingdesignation.

Whenever a CT circuit is required at some remote location, such as in a control room for an ammeter, and the remote circuit doesnot form an essential part of the protection circuit, an interposing CT located in the substation should be connected in the protectioncircuit to isolate the remote circuit from the protection circuit. An isolating CT with a ratio of say 5/1 or 5/0.5 will have the addedadvantage of providing a higher driving voltage to the remote circuit and permit the use of a smaller cross-section cable.

CORE BALANCED (ZERO SEQUENCE) CURRENT TRANSFORMERS

See Subsection D .

A core balanced current transformer consists of an iron toroid with a winding around the iron core. When cable is passed throughthe toroid without a ground return path, and the sum of the currents in the cable is ZERO, there will be no flux in the iron core (corebalanced), whatever the magnitude of the three primary currents. However, any zero sequence (ground fault current) in thethree-phased primary cable currents will create a flux in the iron core and a current in the secondary winding on the iron coreproportional to the ground fault current in the primary circuit.

We use core balanced current transformers extensively on feeders and motor protection circuits to supply ground relays. Wherepossible, the zero sequence CT and the ground fault relay should be purchased as a unit. The ground fault relay is normallyinstantaneous and set to be very sensitive since it is not subject to the transient-offset CT imbalances of residually connected relays.

POTENTIAL TRANSFORMERS

These are generally two-winding transformers which are used to reduce system voltages to 110 V or 100 V for relays and metering.Due to the high cost of potential transformers above 15 KV, it is common to use capacitive coupling circuits, where the accuracyneed not be as high as for metering.

BASIC DESIGN CONSIDERATIONS

PROTECTION PHILOSOPHY

A good protective relaying system should have the following attributes:

� It should operate in the shortest time possible consistent with reliable and selective operation, and with the economics of design.Economics often dictate that it is not justified to use the fastest and most sensitive protection in the form of high-speed differentialrelaying.




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BASIC DESIGN CONSIDERATIONS (Cont)

� It should shut down/isolate the minimum amount of the electrical system necessary to remove the faulty part of the network;i.e., it should be selective. Every level or zone of the electrical system should have fast first-line, or primary relaying. In addition,backup relaying should be provided where practical. Backup relays for one part of a system are often the first-line protectionfor another part of the system. For example (assuming no bus-differential relaying), a fault on an outgoing feeder should becleared by the feeder protection, and not by the main-bus’s primary protection. However, if the feeder protection fails to clearthe fault, the main bus’s primary protection should operate as the backup to the feeder protection. Backup protection for partof a system is not always the primary protection for another part; e.g., stuck-breaker protection; and 51 or 51V backup of adifferentially protected bus or generator.

� It should be highly reliable in terms of repetitively operating per the setting, and in terms of operating when it is supposed toand not operating when it shouldn’t. This not only encompasses the selectivity discussed above, but includes, for example:motor locked-rotor protection operating for a locked rotor condition, but not for reacceleration current; transformerprimary-feeder 50-relaying tripping for a primary-feeder fault, but not for transformer inrush current, and not for a transformersecondary fault; a differential relay tripping for faults in its zone, but not for faults outside its zone.

With the above attributes, a well-designed protection system minimizes damage and downtime of faulty parts of the system, andminimizes the impact of electrical faults on the healthy part of the system, thereby enabling plant operations to progress withminimum interruption.

OVERCURRENT DEVICE COORDINATION (SELECTIVITY/DISCRIMINATION)

To ensure that all of the protection-system attributes discussed above are met, a protective device coordination study is required.The most common form of study covers the selection, setting and coordination of overcurrent devices; although voltage, power,and impedance relays may sometimes be involved. For overcurrent devices in series with a fault, coordination requires that theovercurrent protection closer to the fault (the downstream devices) interrupt the fault before backup protection (the upstreamdevices) can operate. Overall, the objective is to provide the fastest practical protection while ensuring that no healthy equipmentis taken out of service unnecessarily.

For the hypothetical system shown in Figure 20 , Breakers 2 and 3 do not have to coordinate with each other, nor do Breakers 4and 5, since no healthy part of the system would be affected unnecessarily by this lack of coordination. However, Breakers 1 mustcoordinate with Breakers 2 and 3, and Breakers 2 and 3 must coordinate with Breakers 4 and 5. If there were a transformer betweenBreakers 2 and 3 in Figure 20 , there could be reasons to coordinate Breakers 2 and 3; e.g., if Breaker 2 is the incomer of a secondaryselective substation.

Overcurrent-device coordination analysis is performed on log-log paper (or computer screen equivalent), with the current on theX-axis and time on the Y-axis. See Figure 32 . Where there is a transformer between overcurrent devices, the time-current curvesof both devices are referred to the same voltage level. To achieve coordination, a minimum amount of time is required between theupstream and downstream overcurrent-device curves at the maximum current that will exist simultaneously in both devices. Theminimum amount of time required to achieve coordination is called the coordination interval or coordination margin. This form ofcoordination is sometimes referred to as time grading.

Another form of coordination is current grading, where an upstream device is set above the fault level at a downstream relay’slocation. This is illustrated in Figure 21 , where an instantaneous relay (A) on the primary of a transformer is set above thesecondary-side fault level (at location B) times any overreach factor applicable to the instantaneous relay at A.

Various coordination factors that must be accounted for in the determination of the minimum required coordination interval are asfollows:

� Accuracy of the time-current curves relative to error/tolerance associated with both the upstream and downstream curves;overtravel of upstream relays; and the effect of pre-loading on minimum-melt curves of upstream fuses. Relay error is typicallya percent of the setting time, with a fixed minimum error time.

� “Downstream” current-transformer error. CT error typically contributes to the coordination margin by reducing the current seenby the relay, thus making the downstream relay slower than the curve indicates. The upstream relay would not have acompensating delay if the upstream CT is more accurate, which can happen when the upstream CT has a higher turns ratio.Unless a determination is made of the actual effect of CT error, a value of 10% of the downstream-relay time (at maximumcurrent) is typically used to account for CT error.

� “Downstream” circuit breaker operating time, which does not have to be added if the operating time is already built into thedevice curve as is the case for direct-acting-trip devices.




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� The relevant factors from above are summed and a safety factor is usually added to determine the coordination margin. Theamount of safety factor is a matter of judgement. Assuming all of the other factors covered above are separately accountedfor, the safety factor may be taken as 0.05 second for static relays and up to 0.1 second for electromechanical relays.

Where coordination is to be achieved across a delta-wye transformer, a current-shift is required for (wye) secondary-sidephase-to-phase faults. For any given time, draw a dashed curve by shifting the transformer-secondary-51-relay curve right bymultiplying the currents by 1.16. This accounts for the 1.0 per unit current in one primary phase when there is a 0.866 per unitphase-to-phase fault current in two secondary phases. Coordinate the primary-side relay with the shifted dashed curve.

Known or assumed values can be used for any or all of the above factors to determine the coordination margin.

Margins for various coordination situations are discussed in the following:

� For relay to relay coordination, the coordination margin is the sum of upstream relay error and overtravel, downstream relayerror and CT error, downstream breaker operating time, and a safety factor. The coordination margin is typically 0.3 to 0.35for static relays, and 0.4 second for electromechanical relays. Static relays have very low overtravel. They are often moreaccurate than electromechanical relays, and tend to cause less CT error due to their lower burden.

� A low-voltage switchgear breaker with time-delayed direct-acting trip (and no instantaneous unit) can coordinate withdownstream direct-acting trips and fuses if the upstream breaker’s direct-acting-trip curve is above the maximum-clearingcurve of the downstream device. Do not try to make molded case circuit breakers (MCCBs) coordinate with each other bydisabling the upstream instantaneous unit, because the instantaneous unit is necessary to the safe operation of the MCCB.

� For an upstream time-delayed relay to coordinate with a downstream fuse or direct-acting trip, the coordination interval is equalto the relay error plus relay overtravel plus a safety factor. This interval is typically 0.15 to 0.25 second, and is added abovethe maximum clearing characteristic of the fuse or direct-acting trip.

� Fuse to fuse coordination is discussed in detail earlier in this Design Practice, under the side heading “FUSES”. In summary,fuse to fuse coordination is most easily achieved using the manufacturer’s selectivity ratio guides. Otherwise, use themaximum-clearing and minimum-melting I2t data for current-limiting operation. For non-current-limiting operation, use themaximum clearing curve of the downstream fuse, and the minimum melting curve of the upstream fuse. The minimum-meltingcurves have to be adjusted for fuse pre-loading per the manufacturer’s instructions. Coordination is achieved when themaximum clearing characteristic of the downstream fuse is below (or lower than) the minimum melting characteristic of theupstream fuse (adjusted as required).

� For an upstream instantaneous relay to coordinate with a downstream current-limiting fuse, the fuse’s peak let-through currenttimes 0.7 must be less than the rms pickup of the instantaneous relay. This is discussed in more detail in the earlier sectionentitled “PROTECTIVE DEVICE TYPES AND APPLICATION”, under the side-heading “FUSES”, where peak let-through fusedata is discussed.

� Upstream fuses on the primary of a transformer must not be in their current limiting range for fully offset secondary faults. Forcoordination purposes, the upstream fuse minimum-melt characteristic must be shifted left for the pre-loading effect permanufacturers guidelines, and the downstream device curve must be shifted right by a factor of 1.16 times current values forphase-to-phase faults when the transformer is delta-wye, as discussed earlier in this section under the paragraph that beginswith “Various coordination factors ...”.

BACK-UP PROTECTION

Whenever possible, we try to provide back-up protection. This is often inherent in our time and current graded protective schemes.For example, in Figure 27 , for a fault downstream of Relay 1, Relay 2 will “see” the same current as Relay 1 and operate a shorttime after Relay 1 if Relay 1 fails to open its associated circuit breaker. Thus, Relay 2 is providing back-up protection for Relay 1.Likewise, Relay 3 will provide back-up for Relay 2. It may also provide a second stage of back-up for Relay 1 if its current settingis low enough to “see” faults downstream of Relay 1. Relay 3 will also provide back-up for Relay 4, the generator differentialprotection. Per the configuration in Figure 27 , Relay 3 is the primary protection for the generator bus.

We do not require back-up protection for ground faults in transformer main secondary connections with impedance grounding (seeIP 16-2-1), as this condition cannot be easily detected on the primary of a delta/star transformer. To provide back-up protectionwould require duplicating the relays on the transformer secondary, or restricted earth fault relaying.




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GROUND (EARTH) FAULT RELAYING

See Subsection D.

Ground relaying follows the same general rules as phase fault relaying but has the following additional points to consider:

� System neutral grounding method affects how much ground fault current is available, with low resistance grounding resultingin the ground fault current being much lower than the phase-fault current.

� Transformers with certain winding and/or grounding configurations do not pass zero-sequence current from the secondary sideto the primary side.

� Capacitive currents.

� High burden of some ground fault relays can affect current-transformation accuracy.

When sizing neutral resistors, IP 16-2-1 requires that the ground current be not less that 15 times the lowest reliable operatingcurrent of the least sensitive outgoing feeder ground relaying, and not less than five times the lowest reliable operating current ofbus ground relaying. It should be noted that for most induction disc type relays, the lowest reliable operating current may be as highas 1.5 times setting (pickup).

On solidly grounded low-voltage systems, where local codes permit, we do not provide ground-fault relays on feeder circuits whenthere is sufficient ground fault current to operate phase-fault devices. “Sufficient” current, per IP 16-4-1, means the phase protectionof a given feeder must operate in less than two seconds for a phase to ground fault at the load end of the circuit with an arc voltageof 40 volts; otherwise a ground-fault relay must be added to the circuit.

A delta/wye transformer, for all practical purposes, offers an infinite impedance to zero sequence currents, therefore, the primaryground relaying of a delta/wye transformer is instantaneous since there is no coordination problem with secondary-side relaying.For other transformer winding and grounding configurations, the zero sequence impedance of the transformer should beascertained.

When there is a solid phase to ground fault, the faulted phase potential falls to zero, and the capacitive (charging) current in thatphase to ground will be zero. In a resistance grounded medium voltage system the two healthy phases will have capacitive(charging) current of 1.73 times normal; therefore every ground fault relay at that voltage level that is part of the same neutralgrounding system will see a capacitive current equal to 3 times the capacitive (charging) current of one phase to ground of the cablesdownstream of the relay. (For a solidly grounded system, the relays would see 1 times the charging current of one phase.) The relaysmust be set above this capacitive charging current.

The output from core balanced (zero sequence) current transformers is low because:

� Often there is only half a turn on the primary.

� The fault current being measured is generally much less than phase fault current.

� The physical separation between the primary and the core is greater both because there are three conductors on the primaryand because the CT is generally slipped over the main power cable with space between the cable and the CT.

For the above reasons, it is possible that the actual primary current required to cause pickup of a relay connected to a core balancedcurrent transformer is two to ten times the relay setting. Therefore it is recommended that core balanced CT’s and their associatedrelays be purchased as a unit. Where ground relaying is employed, it should wherever possible be of the core balanced type CTin preference to residually connected phase CT’s.

MOTOR PROTECTION

Typical motor protection arrangements that comply with the International Practices are shown in Figure 28 . It should be noted thatone-line diagrams do not include the following which have been shown in Figure 28 to give the complete protection details:

� Direct acting trip device numbers, number of elements, trip signals.

� Trip signal from fuse striker pins.

Motor overload and locked-rotor protection are covered in detail earlier in this practice under “PROTECTIVE DEVICE TYPES ANDAPPLICATION”, side heading “THERMAL OVERLOAD RELAYS (49) AND LOCKED ROTOR PROTECTION”. Motor circuitground fault relaying is covered earlier under the side heading “GROUND (EARTH) FAULT RELAYING”.




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LV motors controlled by contactors are protected by three-element thermal relays for overloads, and by fuses or molded case circuitbreakers for short circuits. Molded case circuit breakers have an instantaneous trip, and in some cases, have a thermal or solidstate time-delayed trip intended for motor thermal protection. In these cases, we still use separate thermal overload relays to tripthe contactor as they follow the motor thermal capability more closely. The molded case circuit breaker thermal elements are setabove the contactor’s thermal overload relays.

Whenever a relay trips a contactor, the capability of the contactor should be checked to ensure that the relay does not require itto open for a current in excess of its rating. The fuse or circuit breaker should take over above the contactor capability limit.

Basically, we apply the same protection to LV motors controlled by switchgear circuit breakers as we do for contactors. Thedifferences being that:

� We accept the breaker direct acting trips for overload protection, but back them up with a secondary thermal element in onephase.

� We add an undervoltage relay if undervoltage protection is not otherwise provided.

� We require a ground fault relay, for solid or low-resistance grounded systems, with the relay supplied from a core-balancedcurrent transformer.

MV motor protection incorporates the following:

� Undervoltage protection if not otherwise provided.

� Hand-reset lockout for all fault protection relays.

� Overload protection in three phases.

� Locked rotor protection, in addition to overload relays, in at least one phase.

� Ground fault relay supplied from a core balanced current transformer.

� Differential protection on motors 2501 hp (1801 kW) and above, with a self-balancing scheme preferred per the lower sketchin Figure 15 .

GENERATOR PROTECTION

This is covered is Subsection B , but see also above Synchronizing Relays (25), Loss of Field Relays (40), NegativeSequence Relays (46), Voltage Restrained Relays (51V), Overvoltage Relays (59), Directional Relays (67 and 32), and DifferentialRelays (87).

Points to consider when applying generator protection are:

� Unless there is only one generator that always operates “in island”, kW and kvar can flow both to and from the generator.

� The protective relays must protect the generator and the integrity of the electrical system, but they must not inhibit the generatorfrom providing its full capability to the electrical system.

� When operating in parallel with the power utility, detailed information will be required on the utility protective relaying in the areato determine the relay setting for separation from the utility.

� If the generator is operating in parallel with other generators or the utility, fast fault clearance times will be required to maintaintransient stability, i.e., generator differential and bus differential protection.

� The Automatic Voltage Regulator (AVR) should be self-protecting, i.e., it should automatically change to manual, or a fixedsetting, if faulty. It is not practical to protect for AVR faults with protective relaying.

TRANSFORMER PROTECTION

As nearly all the power transformers we use are stepdown with a delta primary winding and wye secondary winding, the followingcomments are based on such a transformer. However, many of the comments will apply whatever the transformer vector reference(see Figure 29 ):

� Due to the relatively high impedance of the transformer, it is usually possible to apply primary-side instantaneous phaseovercurrent protection set above the current in the primary that would flow for a short circuit on the secondary terminals, i.e., therelay will not “see through” the transformer.




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� Instantaneous ground relaying is applied to the primary, preferably with a core balanced current transformer, but three currenttransformers residually connected are acceptable.

� Three overcurrent elements are used in the supply to the primary which are set to coordinate with relaying downstream of thetransformer.

� Intertripping of the secondary breaker when the primary feeder breaker opens should be implemented in the case of a spotnetwork substation.

� Tripping of transformer primary and secondary breakers is required for operation of the transformer fault pressure and51G relays; for operation of restricted-earth-fault relaying (if provided); and, in spot networks, for operation of the 67 relay, andthe 67N relay (if provided). For secondary-selective substations, the secondary breaker opens via the transfer logic for faultsupstream of the incoming breaker.

� A Buchholz or Fault Pressure relay is required on all transformers 500 kVA and above.

� A ground overcurrent relay is required in the secondary neutral of all transformers 500 kVA and above where the neutral is lowresistance or solidly grounded. For high-resistance grounding of a transformer neutral, a ground overvoltage relay is providedacross the neutral resistor, and is set to alarm. For transformers below 500 kVA, we accept that the connection from thetransformer secondary to the secondary circuit breaker is only protected by the phase overcurrent (51) relays on the transformerprimary and that they may not be set low enough to protect for arcing faults on the secondary connections.

� For relaying of transformers supplied from tapped feeders, and those with fuses on the primary, see IP 16-2-1.

� For transformers 10 MVA and larger, differential protection is provided, as discussed under “PROTECTIVE DEVICE TYPESAND APPLICATION, DIFFERENTIAL RELAYS” earlier in this Design Practice.

TRANSFORMER SECONDARY PROTECTION

Protective relaying on transformer secondary breakers is required to coordinate with downstream relaying and is selectedaccordingly.

BUSBAR PROTECTION

All busbars are included in time graded protection zones. In addition, main incoming substation busbars and generator busbarsare generally fitted with differential protection. Where there are more than two power sources, we normally provide struck-breakerprotection.

CABLE (FEEDER) PROTECTION

Protective relaying for feeders will vary depending on the load and protective relaying downstream. Transformer and motor feedersare covered in this Design Practice, and tapped feeders are dealt with in IP 16-2-1.

Distribution feeders to a bus require overcurrent protection in three phases, and an overcurrent ground relay, preferably suppliedfrom a core balanced current transformer, for low resistance or solidly grounded systems. Important feeders between buses at thesame voltage level can be fitted with differential (87) or pilot wire differential (87P) protection to eliminate one selectivity time step.

SECONDARY SELECTIVE SUBSTATION PROTECTION

This is fully covered in IP 16-12-2.

SPOT NETWORK SUBSTATION PROTECTION

Incoming circuit breakers to a spot network substation require directional phase overcurrent (67) and directional ground (67N)relays which look back towards the source, and operate selectively ahead of the incoming and bus-tie (if provided) phase andground overcurrent relaying to ensure that a fault on an incoming feeder does not trip both incomers.

For a spot network with incoming transformers, restricted earth fault relaying may be substituted for the 67N. For a spot networkwithout incoming transformers, differential or pilot-wire relaying around the source feeder is required if the source bus-tie breakeris normally closed, and is preferred if the source bus-tie is always open.




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A relayed tie breaker is provided when it is important to maintain supply to the loads on one of the busses for a bus fault or for anuncleared feeder fault on the other bus. When a relayed bus-tie breaker is provided, partial differential zones on each bus(emcompassing the incomer and tie-breaker) should be seriously considered to save a time step in the incomer (and possibly inthe source) relaying.

When partial differential protection is not provided for a spot network with incoming transformers, the incoming 51N is not neededbecause the 51G in the transformer neutral covers all the functionality of the 51N.

The following guidelines apply to relaying for a spot network substation:

� The spot-network incoming breakers should be transfer tripped by the opening of their respective source breakers.

� The spot-network source breakers should be tripped by the respective 67 and 67N or Restricted Earth Fault relays in the spotnetwork – in addition to being tripped as usual by the transformer fault-pressure and 51G relays.

� If the source bus to the spot network is always effectively a single bus, the 67 relays can be set to be fast and sensitive, butthe 67 relays must not operate for motor backfeed to a fault on the source bus or one of its feeders.

� If the source buses to the spot network are or can be electrically separated from each other while the spot network has bothincomers in operation, the 67 must coordinate with outgoing feeders from the source bus at the level of current that could passthrough the spot network; and if the spot network does not have transformers which block the flow of zero-sequence current,the 67N must likewise coordinate with the source-bus feeders.

� In the absence of partial-differential relaying, the bus-tie 51/51N relays, if provided, must coordinate with the outgoing feedersand the incomer 67 and 67N or restricted-earth-fault relays. This coordination applies up to the current from one transformer,since that is the most current the tie will see.

� In the absence of partial-differential relaying (discussed below), the incoming-line 51 phase and ground relays protecting thespot-network bus must be selective with the bus-tie relays (if provided) and with the outgoing feeders and the 67/67N relays.

PARTIAL DIFFERENTIAL PROTECTION

With a relayed bus-tie breaker in a spot network substation, a step of coordination can be saved by using partial differential phaseand ground relays which operate on the sum the phase-fault or ground-fault current into a bus from its incomer and the tie breaker.See Figure 30 . The partial-differential relays must coordinate with the outgoing feeders on the bus because the outgoing feedersare not in the differential relay circuit. This coordination must occur at twice the fault current from one incomer. When the spotnetwork has incoming transformers, the 51G in the transformer neutral must coordinate with the partial differential ground relay atthe ground-fault current from one source. Likewise, the primary side 51 relays must coordinate with the partial differential 51 relaysat the maximum phase-fault current from one source.

With a partial differential setup, if the bus-tie breaker fails to operate for a phase fault on one bus, the other bus’s partial-differentialrelaying will not operate. Therefore, the backup will be the feeder relaying at the source bus – unless breaker-failure relaying isadded to the tie breaker as backup to trip the incomers. If an incoming breaker fails to operate for a primary side phase fault (transfertrip or 67 trip signal), the only backup is the primary 51 relay looking through two transformers. If this backup is not consideredadequate or desirable, incomer breaker failure relaying should be provided to trip the spot-network bus tie – thereby saving thesupply to one bus.

RESTRICTED EARTH FAULT PROTECTION

Restricted earth fault protection is a ground-fault differential zone covering the grounded wye winding of a transformer, and itsincoming bus duct or cable. Various relay types can be used for this application, including overcurrent, overvoltage, and differential.This protection can be used in spot-network relaying in place of the 67N. The differential protection (87T) on large transformers(with an appropriately sized neutral grounding resistor) should be sensitive enough to protect more than half the winding from aground fault, without the need for restricted-earth fault protection. In any case, the transformer fault-pressure relaying provides fastand relatively sensitive protection.

SYNCHRONIZING BUSBAR PROTECTION

Future




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CAPTIVE TRANSFORMER PROTECTION

The protection of captive (or unit) transformers for generators and motors is the same as for other transformers, except for thefollowing:

� On the motor side of a step-down transformer, the wye winding may be high-resistance-grounded, with an overvoltage relay(59) sensing zero-sequence voltage across the resistor. The overvoltage relay is used to trip and/or alarm.

� On a generator step-up transformer, the generator-side winding is often wound in delta, and the generator neutral ishigh-resistance grounded, with an overvoltage relay (59) sensing zero-sequence voltage across the resistor. The overvoltagerelay is normally used to trip the generator.

The nature and protection of transformers associated with variable speed drives is beyond the scope of this Design Practice.

CALCUL ATION PROCEDURE

Design specifications should include transformer sizes, number of current transformers and their ratio, relays types (at this stage,the full details of how inverse a relay is or its range of settings are not normally included), and number of elements, potentialtransformers with their ratio, and sizes of large motors. The contractor takes over from this point. The contractor is responsible forfinal sizing of all electrical components and selecting CT ratios. IP 16-2-1, Power System Design, specifies that contractors shallfurnish relay data and relay coordination, and presents general requirements for the documentation of relay data and coordination.This design practice gives the requirements in greater detail and should be used as a guide for documentation of relay data andcoordination.

DOCUMENTATION REQUIRED FROM CONTRACTOR

Two types of relay documentation are required as specified in IP 16-2-1. These two types are:

1. Relay Data – A tabular presentation which identifies and shows the recommended settings for each adjustable relay and otherprotective device. The relay data shall also furnish calibration and check points for each device plus space to record the actualvalues for these points as measured in field tests.

2. Relay Coordination – A set of time vs. current and time vs. voltage curves which show the characteristics of the relays and otherprotective devices at their recommended settings. The primary purpose of the coordination is to show graphical proof of theselectivity between devices. The coordination also shows the operating times of the protective devices at various values of faultcurrents. This permits checking that adequate protection has been provided for the electrical system components.

WHEN CONTRACTOR SHOULD FURNISH RELAY DOCUMENTATION

IP 16-2-1 establishes when the contractor should furnish relay documentation to the Owner for approval. Relay coordination shouldbe furnished on two occasions:

1. Before current transformer ratios and relay or other protective device ranges and characteristics are specified to the supplier.This preliminary issue of the coordination needs only to be complete and accurate enough to verify selection of the proper ratios,ranges, and characteristics.

2. When relay data is presented for final approval.

Relay data shall be presented to the Owner for approval when all characteristics of the electrical system and its loads are firmlyestablished and when complete information has been received from vendors on the relays and other protective devices. The datashould be presented early enough to permit the Owner to review it and to allow the contractor to complete the final copies beforethe data is needed in the field. A minimum time of two months should be allowed for review by the Owner and preparation of thefinal data by the contractor.

The preparation of the preliminary relay coordination is important. This coordination minimizes the need for changes in relays andcurrent transformers after approval of manufacturer’s drawings or delivery of equipment. Such changes can delay delivery of theequipment and, thereby, lead to delay in project completion.




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SAMPLE REL AY DATA AND COORDINATION

A set of sample relay data and coordination for two substations of a typical refinery process unit is included herein. One-line diagram,Figure 33 , covers the power circuits and protective relaying of the substations. The contractor may be given this sample (i.e.,Figures 31 through 41 and text from “ CALCULATION PROCEDURES” through “Relay Coordination Requirements”) to use asa guide when preparing his data and coordination.

RELAY DATA REQUIREMENTS

Contractor should furnish relay data on a tabular form similar to the “Relay Settings Record” shown in Figure 31 unless otherwiseadvised by the Owner. On some projects, the Owner may request that the relay data be prepared on his standard Form. For suchcases, Project Management will advise the contractor and will furnish copies of the Owner’s Form to the contractor.

Sample relay data is shown in Figures 34 and 35. The following features should be noted:

� Data should be provided for each relay even when there are multiple relays per circuit, each having the same setting.

� Blank columns should be provided to record the actual values of current (or volts) and times used in the field to calibrate andcheck each relay.

� For overcurrent relays, the calibration point should be specified at five times pickup current and the test point at two times pickupcurrent. Different values may be used for situations where it is desirable to check a relay’s performance at a specific point onits curve.

� Relay operation times at the calibrate and test points should be given in seconds and cycles. This aids the test engineer whooften measures operating timers with a cycle counter.

� The data shall include symbols for identifying each relay with its characteristic curve shown in the coordination.

� Calibrate and test points are not required for circuit breakers having direct acting trip elements unless requested by the Owner.

� Fractional time dial settings may be used. Such settings should be limited to quarters, such as 1.25, 2.5, 3.75, unless the relaytime dial is calibrated in other fractional values.

RELAY COORDINATION REQUIREMENTS

Contractor should furnish relay coordination curves on logarithmic time-current characteristic paper similar to that shown inFigure 32 . One set of curves shall be furnished for each substation.

Curve sheets shall be provided for phase relays and other phase protective devices at each voltage level. Separate curve sheetsshall be provided for ground relays and other ground protective devices. Values of symmetrical maximum and minimum short circuitcurrents shall be shown on each curve sheet.

Sample coordination curves are shown in Figures 36 through 41. The following features should be noted:

� A time vs. voltage curve for undervoltage relay 27 used to initiate automatic transfer should be shown for each secondaryselective substation. A percent voltage scale corresponding to fault current values should be plotted in accordance with theIEEE reference listed in IP 16-2-1.

� For phase relaying, the effect of the higher current seen in one primary phase during phase-to-phase faults on the secondaryof delta-wye transformers should be shown by moving the time vs. current curve of the secondary phase overcurrent relay 16%to the right (see Figure 44 ).

� For ground relaying, check the effectiveness of primary-side phase relaying to act as backup for a ground fault on the secondaryof a solidly-grounded delta-wye transformer, by shifting the primary 51 curve to the right by a factor of 1/0.58 applied to thecurrent values. Protection of the transformer is effective if the shifted primary 51 curve is below the transformer through-faultprotection curve for a reasonable range of fault currents.

� The appropriate “through-fault protection curve” for power transformers should be shown. The appropriate curve for almost allapplications is the one for infrequent fault incidence. The only situation for which the frequent-fault-incidence curve should beused is to check that an outgoing feeder subject to frequent-faults (normally an overhead line) has an overcurrent device whichprovides through-fault protection for its supply transformer. (Note: Figures 36 and 39 show a “transformer damage point”because they have not been updated to show the “through-fault protection curve”.)




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� Relay curves for all feeders need not be shown on the coordination diagram. Generally, it is only necessary to show the curvesfor the highest set feeder relays to prove feeder selectivity with the upstream relays.

� The sample only shows the coordination curves for one 2300 volt motor (Figure 38 ). Contractor should furnish similar curveson separate sheets for each motor rated above 600 volts. The motor withstand point at operating temperature for locked rotorcurrent should be shown. Also, a plot of motor current from locked rotor to full load should be shown. In order to show this plot,motor starting time must be determined.

� Each curve should be identified with a symbol listed in the relay data.

� Although not shown in the sample, contractor shall show, where applicable, the safe insulation heating limit (short circuitwithstand) for feeder cables supplying buses and power transformers rated above 600 volts per IP 16-2-1. The heating limitcurve should be on the same curve sheet with the feeder protective device. The device setting should protect the cable forcurrents up to the maximum available short circuit current.

SQUIRREL CAGE INDUCTION MOTOR RELAY SETTINGS

27M – Undervoltage relay used to open motor control devices which do not automatically drop out when voltage drops belowabout 60 to 70%. Such devices include circuit breakers, mechanically latched contactors, and dc-controlled contactorswith low drop-out voltage. The 27M function is incorporated in automatic reacceleration control schemes to trip allnon-reaccelerating motors, and all reaccelerating motors that are tripped before they are reconnected for reacceleration.This reacceleration-control 27-relay usually operates with a definite time characteristic set to trip motors in about 0.35to 0.5 seconds for voltages below about 65%. Some motors are not tripped at the outset of an undervoltage so they canreaccelerate immediately upon the return of voltage. Such motors, and reacceleration control schemes in general, requirea 27M to abort reacceleration if the undervoltage persists so long that reacceleration is no longer feasible or safe. The27M used to abort reacceleration is normally set to operate after about 5 to 10 seconds of voltage below about 65% volts.

49A – Thermal alarm relay can be set anywhere from 100% to 110% motor full load.

49 – Thermal overload relays are normally set to pick up at 110 to 115% of motor full load amperes (FLA) for 1.0 service factormotors, and at 125% of FLA for 1.15 service factor motors. See “THERMAL OVERLOAD RELAYS AND LOCKEDROTOR PROTECTION” earlier in this practice for discussion of using 49 relays for locked rotor protection.

50 – Must be set about 10% to 20% above locked rotor current, including any asymmetry to which it is sensitive. With a relaythat is fully sensitive to d-c offset, settings are generally about 200% locked rotor current.

50GS – Supplied from a core balanced CT. Setting should be as low as practical, but above 3 times the charging current ofone phase on low-resistance-grounded systems, or above the charging current of one phase on solidly-groundedsystems. Based on the CT turns ratio, pickup settings equivalent to primary currents of 5 amperes and 10 amperes arecommon, which may result in actual relay pick-up in the range of 10 amperes to 30 amperes due to the low output of corebalanced CTs. See also Subsection D .

50N – Not used unless a core-balance CT cannot be fitted. Residually connected instantaneous relays must either have a smalltime relay added, or a stabilizing resistor fitted (see Figure 42 ) to prevent tripping during motor starting. Formedium-voltage motors, setting should be such that the Lowest Reliable Operating Current is not more than6.7% (one fifteenth) of the current passed by the neutral resistor (see IP 16-2-1 on sizing neutral grounding resistors).For low-voltage motors, setting should not be more than 40% of maximum three-phase fault level. Setting must not betoo sensitive, as the performance of each of the three CT’s will not be identical. Usual setting is in the region of 20 ampsfor medium-voltage motors.

51 – This is a locked rotor protection relay, which is discussed in detail above under “THERMAL OVERLOAD RELAYS ANDLOCKED ROTOR PROTECTION”.

MCC FEEDER RELAY SETTINGS

The supply circuit to an MCC usually does not have an automatic-tripping circuit breaker when the MCC is in the same buildingas the supply switchgear. Supply to a TAPC has a tripping breaker. When there is a tripping circuit breaker, the overcurrent devicesshould be selective with the following:

� Largest motor relaying.




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� Largest reacceleration current, with care that multiple steps in rapid succession do not cause the relay to operate.

Note that IP 16-2-1 permits non-selectivity with a large single load on the basis that the loss of the large single load would resultin a plant shutdown. See IP 16-2-1 for permissible exceptions.

TRANSFORMER-SECONDARY REL AY SETTINGS

51 – Phase relaying protects the main bus, protects the transformer against through faults, acts as backup for the outgoingfeeders, and should be set as follows:

� Coordinate with the highest set downstream relaying. The 51 relay time-current characteristic should be enoughbelow the transformer through-fault protection curve (for infrequent-faults) such that the transformer primary 51relay curve can fit selectively above the incomer 51 relay curve and sufficiently below the transformer damagecurve. See “TRANSFORMER PRIMARY RELAY SETTINGS” below.

� Set not to operate for the largest reacceleration current (including already running motors), with care that multiplesteps in rapid succession do not cause the relay to operate.

� Set not to operate for starting of largest motor with all others already running.

� Set pickup no lower than 125% of transformer forced cooled rating.

� Set pickup no higher than 250% of transformer forced cooled rating, if possible.

51N – Set to be selective with downstream ground relaying. Where there is no ground relaying downstream, 51N should beselective with phase relaying. IP 16-2-1 permits relaxation of this requirement for large single motors (see IP 16-2-1 forconditions that are acceptable). On four-wire systems with three CT’s, 51N pickup must be above the maximum neutralcurrent. On medium-voltage systems with low-resistance grounding, setting should be such that the LOWEST RELIABLEOPERATING CURRENT, which may be 1.5 times pickup for induction disc relays, is not more than 20% (one fifth) of themaximum ground fault current. On low-voltage systems setting should not be more than 40% of the maximum three phasefault level. See also Subsection D .

TRANSFORMER PRIMARY RELAY SETTINGS

50 – Relay must not “see” through the transformer. If it does, it will trip the transformer for faults on the secondary which shouldbe cleared by the secondary relaying. Basis for setting is:

� Set about 10% to 20% above the maximum fault level on the secondary, taking account of any dc offset to whichthe relay is sensitive. See “OVERREACH” in the DEFINITIONS section of this practice.

� Set above transformer magnetizing inrush current. If more than one transformer on feeder, the setting must beabove the inrush of all the transformers combined.

50GS – Use same basis as 50GS for Squirrel Cage Induction Motor Relay Settings. For a delta/star transformer, the 50GS in theprimary is the first stage of the primary ground relaying.

51 – Basis for setting is:

� When a feeder supplies two or more parallel transformers, each transformer that is not adequately protected bythe feeder relay must have its own primary protection, which is normally 51 relaying supplied from bushing CTsmounted on the transformer primary. Adequate protection is defined in IP 16-2-1 (under “TAPPED FEEDERS”)as operating in less than 2 seconds at 50% of the minimum secondary-side bolted phase-to-phase fault current.

� Minimum pickup of the 51 relay protecting a tapped feeder should not be less than 125% of the sum of the forcedcooled ratings (use self cooled rating for radial substations) of all the transformers on the feeder. Pickup settingof the relay providing “adequate protection” (defined above) for any given transformer is normally determined bycoordination requirements. Per the US National Electric Code, pickup should be less than 400% of rated currentif the rated impedance is more than 6%, up to 10%; pickup should be less than 600% for rated impedance no morethan 6%.




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� On a tapped feeder or on any secondary-selective source feeder, must be selective with the highest setincoming-breaker 51-relay on the largest downstream transformer. Obviously this selectivity is required onlyup to the maximum secondary-side fault level. In the case of delta-wye transformers, the primary-side 51 relaymust be selective with a dashed line drawn 16% higher in current (move 16% to right) than the largestdownstream relay, as one primary line will “see” 16% more current than the two secondary lines for aphase-to-phase fault (see Figur e 44).

� On an untapped radial feeder, must be selective with highest-set downstream feeder device; on an untappedspot-network feeder, must be selective with highest set feeder relay, or bus tie relay if provided, orpartial-differential relay if provided.

� If pickup is not above maximum reacceleration current seen by the relay, the time delay should allow multiple stepreacceleration taking account of any additive effect of the reacceleration steps on the relay.

� Should be below transformer through-fault protection curve (for infrequent faults) to the extent practical, andshould provide fault clearing in under 2 seconds for 50% of the minimum secondary-side bolted phase-to-phasefault current. If possible for a solidly-grounded delta-wye transformer, the primary curve shifted right by 1/0.58 (oncurrent) should be below the through-fault protection curve over a reasonable secondary fault range.

SECONDARY-SELECTIVE AUTO-TRANSFER RELAY SETTINGS

27 – Transfer initiation relay, actuated for low voltage on one of the two upstream sources. Set as follows:

� “Drop-out” should be at about 75% of system nominal voltage, and in any case below the lowest bus voltageobtained during motor reacceleration.

� For substations closest to the source, time dial should be set to be selective with overcurrent relaying upstreamto permit fault clearance and voltage recovery before initiating a transfer. Over the fault range for which theincomer 50 relay blocks transfer, coordination of the 27 with downstream overcurrent devices and incomer 51relays is not necessary. However, coordination of the 27 with the incomer 51 (for the 51 to operate first) is desirableas backup for the 50 blocking function. See IP 16-2-1 under “DOCUMENTATION/DATA” for the reference on27/51 coordination. Where the 50 blocking relay does not block the 27 over the range of practical fault currents,the 27 should coordinate with the incomer 51 relays. This usually results in a setting of one second, or slightlymore, at zero volts. In the case of series transformation (see Subsection C ) the downstream substation 27 relaysmay be set to be selective with the upstream 27 relays to permit the upstream substation to transfer and avoidtransfer on the downstream substation.

27I – Healthy volts for transfer relay. This relay blocks transfer if voltages fail from both sources. It ensures that the infeed towhich the load will be transferred is healthy. If there has been a voltage dip on the “healthy” incomer, the 27I will blockinitiation of a transfer until the volts have been restored for three seconds. The 27I is an instantaneous relay that operatestime delay relay 96. On loss of incomer volts, 27I drops out which causes time delay relay 96 to pick up instantaneouslyand block transfer of the opposite bus. When voltage is restored, 27I picks up instantaneously, but the 96 time delaycontacts are not closed for three seconds which blocks transfer for three seconds after restoration of voltage. Basis forsetting is:

� Dropout must be the same as or at higher voltage than dropout of the 27 relay.

� After setting dropout, check pick-up which must be safely below the lowest expected sustained value of recoveryvoltage.

Usual setting is dropout in the range of 80 to 90% volts.

27R – Residual voltage relay that delays closing of the tie breaker until the voltage of the “unhealthy” bus has decayed to thesetting of 27R. This is required to prevent the high electrical and mechanical surges that would occur if the voltage eitherside of the tie breaker were 180 degrees out of phase and both at a high value at the time of tie closure. By setting 27Rat 25% voltage, we attempt to limit the maximum torque imposed on the motor coupling to no more than four times thetorques at motor rated output. Usual setting for relay is 25% volts with relay calibrated for dropout.




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This relay is instantaneous and will be required to operate at reduced frequency as the motors separated from the supplyslow down. A conventional a-c instantaneous relay in this duty will have its dropout voltage decrease as the residualvoltage frequency decreases, and will also drop out as the sine wave passes through a zero when the frequency slowsdown (as also would a d-c relay powered from single-phase rectifier). To avoid this problem, we use a single element d-crelay powered from a three-phase rectifier.

50 – Transfer blocking relay. Prevents initiation of transfer when low voltage is due to fault downstream until fault is cleared.When the 50 relay picks up, it energizes time delay relay 97 which blocks transfer. When the 50 relay resets, providedthe voltage has recovered enough to pick up the 27I relay, the 97 relay permits a transfer after a one-second delay. Basisfor setting is:

� Pickup should be about 10% above maximum motor contribution of motors on its own bus, taking account of relaysensitivity to dc offset, to avoid blocking transfer for a transformer bus-duct fault.

� After setting relay, it should be tested for dropout to ensure that it will drop out at some current higher than themaximum load.

50N – Same function as 50. Operates the same 97 relay as the 50 relay. Basis for setting is:

� Pickup must be below minimum ground fault current, with the usual setting being the minimum setting that willnot falsely operate for the maximum (first half cycle) asymmetrical motor backfeed to a transformer bus-duct fault.

� Pickup should be above neutral current on four-wire systems with only three CT’s.

� Dropout must be above neutral current on four-wire systems with three CT’s.

51G – Transformer neutral ground relay. Should be set to coordinate with incomer 51N.

GENERATOR RELAY SETTINGS

See Subsection B for generator relaying. Below are listed some typical settings for the relays:

32 – Power setting depends on type of driver. Set pickup at one fifth to one tenth of the minimum power required to “motor”the driver. Steam turbines require very sensitive reverse power pickup, often less than 0.5% of turbine rating , while dieselengines require pickup about 2.5% to 5% of engine rating, and gas turbines require pickup about 5% to 10% of turbinerating. Typical time setting is 10 seconds delay.

40 – Field Failure. One protection scheme uses one or two offset Impedance type (mho) relays with circles centered onnegative reactance axis (completely below the resistance axis), where the larger circle diameter is set equal to thegenerator direct axis synchronous reactance, and the offset (of the circumference below the resistance axis) is set equalto half the generator direct axis transient reactance. Typical setting for time delay is 0.5 to 0.7 seconds. When a second,more sensitive mho relay is provided, it has the same offset, but the circle diameter is one per unit impedance, and thereis no time delay. Another relay scheme has directional and undervoltage units in addition to one or two offset mho units.Consult relay application data for recommended settings for this type of scheme.

46- Negative sequence. See “NEGATIVE-SEQUENCE OVERCURRENT RELAYS (46) FOR GENERATOR PROTECTION”under “PROTECTIVE DEVICE TYPES AND APPLICATION” above. Basically, the relay curve should be just below thegenerator I22t curve, with I2 pickup above the generator’s continuous I2 capability. Often there is an alarm set below thetripping settings.




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51V- Voltage-restrained or voltage-controlled overcurrent. See “VOLTAGE-RESTRAINED (VOLTAGE-CONTROLLED)OVERCURRENT RELAYS (51V)” under “PROTECTIVE DEVICE TYPES AND APPLICATION” above. The voltagesetting for a voltage-controlled 51V should be below the lowest expected voltage during motor reacceleration (probablyset just below about 60% voltage). Set the unrestrained (lowest pickup) curve to coordinate with the highest setdownstream relay under the worst case for coordination. The coordination should account for the effect of generatordecrement on the operating time of the downstream and 51V relays per IEE Transactions IGA March/April 1965,pp. 130-139, “Allowing for Decrement and Fault Voltage in Industrial Relaying”. The 51V relay should be set with theminimum safe discrimination interval practical for the maximum fault current through the 51V at zero voltage, and for theleast current that would flow simultaneously through the highest-set downstream relay. This condition is usually obtainedwhen the generator with the 51V is the only source of fault current. The setting should be checked for proper operationunder emergency operation conditions such as motor reacceleration and stable transient swings for which tripping shouldnot occur.

59- Overvoltage. Check insulation design withstand with manufacturer. If such a relay is fitted, we recommend that it beconnected to alarm only. Typical setting 120% with time delay of 2 seconds.

64F- Rotor Ground Fault. Connect to alarm only. Typical setting 1 milliampere.

GENERATOR SEPARATION RELAY SETTINGS

67- Directional overcurrent relay looking towards utility source. May have contacts in series with a voltage relay. Current andvoltage settings should be roughly equal to those values that would occur for 50% or lower voltage at utility substationwith the in-plant generator connected. Time setting should preferably be above the utility relaying but must be less thanthat which would cause instability of the in-plant generation. Typical settings are in the 0.3 to 1 second range.

81- Frequency. Settings should be above value that would cause problems with electrical plant, such as tripping of motorsby overload relays and inability of in-plant generation to sustain itself due to the slowing down of the auxiliaries. Typicalvalues for the latter are 5% under frequency. Setting may be above frequency relay settings for load shedding in the plantif these relays are blocked when operating in parallel with the utility. Ideally frequency setting for separation of in-plantgeneration should be below the utility company’s load shedding and network fragmentation frequency relays to give theutility an opportunity to rectify the problem. More sophisticated relaying may be applied by using rate of change offrequency relays in addition to absolute frequency relays for separation of in-plant generation. A large integrated utilitynetwork extending over a country or maybe even a continent cannot change the frequency very fast due to the enormousinertia of the sum of all the synchronous machine connected. Therefore, if the frequency changes rapidly, it is a sure signthat the utility network has become fragmented, which spells problems. If possible, obtain data from the utility to determinesettings for rate of change of frequency relays. If not, determine from past incidents actual frequency performance duringnormal operation and during system disturbances.

SPOT NETWORK RELAY SETTINGS

See the guidelines for applying relaying in spot networks earlier in this Design Practice under the sideheading “SPOT NETWORKSUBSTATION PROTECTION” in the section entitled “BASIC DESIGN CONSIDERATIONS”.

PARTIAL DIFFERENTIAL RELAY SETTINGS

51- See “PARTIAL DIFFERENTIAL PROTECTION” above in the section entitled “BASIC DESIGN CONSIDERATIONS”. Forspot networks, relay must coordinate with the downstream feeder relaying with both sources feeding the fault.

RESTRICTED EARTH FAULT PROTECTION

See “RESTRICTED EARTH FAULT PROTECTION” above in the section entitled “BASIC DESIGN CONSIDERATIONS”. Selecttype of relay to be used, and follow manufacturer’s setting recommendations.




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TABLE 1I.E.C. RECOMMENDED FUSE RATINGS FOR LOW VOLTAGE

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

AMPS ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

AMPS


2 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

100*



125



160*


8ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

200ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ


250*ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ12

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ315ÁÁÁÁÁÁÁ


16

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

400*



500*



630*


32* ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

800*



1000*ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ


1250*ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ 63*

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ


80ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ




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TABLE 2TYPICAL CURRENT TRANSFORMER RATIOS

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

SINGLE RATIO(amperes)

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

DOUBLE RATIO WITHSERIES – PARALLELPRIMARY WINDINGS

(amperes)


DOUBLE RATIO WITHTAPS IN SECONDARY

WINDING(amperes)


10/5 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

25 x 50/5 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

25/50/5




50/100/5




100/200/5




200/400/5


50/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

400 x 800/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

300/600/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ75/5

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ600 x 1200/5

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ400/800/5ÁÁÁÁÁÁÁÁ


100/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

1000 x 2000/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

600/1200/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

200/5

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

2000 x 4000/5


1000/2000/5




1500/3000/5




2000/4000/5




ÁÁÁÁÁÁÁÁ800/5






ÁÁÁÁÁÁÁÁ1500/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ



2000/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ


ÁÁÁÁÁÁÁÁ3000/5 ÁÁÁÁÁÁÁ

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ










ÁÁÁÁÁÁÁÁ12,000/5ÁÁÁÁÁÁÁÁÁÁÁÁÁÁ





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IEEE STANDARD ELECTRICAL DEVICE FUNCTION NUMBERS

DEVICE NUMBERS

These device numbers are covered in IEEE Standard C37.2.

DEVICE NUMBER DEFINITION AND FUNCTION

1 Master Element is the initiating device, such as a control switch, voltage relay, float switch, etc., whichserves either directly or through such permissive devices as protective and time-delay relays to place anequipment in or out of operation.

2 Time-Delay Starting or Closing Relay is a device which functions to give a desired amount of time delaybefore or after any point or operation in a switching sequence or protective relay system, except asspecifically provided by device functions 62 and 79 described later.

3 Checking or Interlocking Relay is a device which operates in response to the position of a number of otherdevices, or to a number of predetermined conditions in an equipment to allow an operating sequence toproceed, to stop, or to provide a check of the position of these devices or of these conditions for anypurpose.

4 Master Contactor is a device, generally controlled by Device No. 1 or equivalent, and the necessarypermissive and protective devices, which serves to make and break the necessary control circuits to placean equipment into operation under the desired conditions and to take it out of operation under other orabnormal conditions.

5 Stopping Device functions to place and hold an equipment out of operation.

6 Starting Circuit Breaker is a device whose principal function is to connect a machine to its source ofstarting voltage.

7 Anode Circuit Breaker is one used in the anode circuits of a power rectifier for the primary purpose ofinterrupting the rectifier circuit if an arc back should occur.

8 Control Power Disconnecting Device is a disconnecting device – such as a knife switch, circuit breaker orpullout fuse block – used for the purpose of connecting and disconnecting, respectively, the source of controlpower to and from the control bus or equipment.

Note: Control power is considered to include auxiliary power which supplies such apparatuses as smallmotors and heaters.

9 Reversing Device is used for the purpose of reversing a machine field or for performing any other reversingfunctions.

10 Unit Sequence Switch is used to change the sequence in which units may be placed in and out of service inmultiple-unit equipments.

11 Reserved for future application.

12 Overspeed Device is usually a direct-connected speed switch which functions on machine overspeed.

13 Synchronous-Speed Device , such as a centrifugal-speed switch, a slip-frequency relay, a voltage relay, anundercurrent relay or any type of device, operates at approximately synchronous speed of a machine.

14 Underspeed Device functions when the speed of a machine falls below a predetermined value.

15 Speed or Frequency Matching Device functions to match and hold the speed or the frequency of amachine or of a system equal to, or approximately equal to, that of another machine, source or system.

16 Reserved for future application.

17 Shunting or Discharge Switch serves to open or to close a shunting circuit around any piece of apparatus(except a resistor), such as a machine field, a machine armature, a capacitor or a reactor.

Note: This excludes devices which perform such shunting operations as may be necessary in the processof starting a machine by Devices 6 to 42, or their equivalent, and also excludes Device 73 functionwhich serves for the switching of resistors.

18 Accelerating or Decelerating Device is used to close or to cause the closing of circuits which are used toincrease or to decrease the speed of a machine.




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IEEE STANDARD ELECTRICAL DEVICE FUNCTION NUMBERS (Cont)

19 Starting-to-Running Transition Contactor is a device which operates to initiate or cause the automatic transfer ofa machine from the starting to the running power connection.

20 Electrically Operated Valve is a solenoid- or motor-operated valve which is used in a vacuum, air, gas, oil, water,similar, lines.

Note: The function of the valve may be indicated by the insertion of descriptive words, such as “Brake” or“Pressure Reducing” in the function name, such as “Electrically Operated Brake Valve.”

21 Distance Relay is a device which functions when the circuit admittance, impedance, or reactance increases ordecreases beyond predetermined limits.

22 Equalizer Circuit Breaker is a breaker which serves to control or to make and break the equalizer or thecurrent-balancing connections for a machine field, or for regulating equipment, in a multiple-unit installation.

23 Temperature Control Device functions to raise or to lower the temperature of a machine or other apparatus, or ofany medium, when its temperature falls below, or rises above, a predetermined value.

Note: An example is a thermostat which switches on a space heater in a switchgear assembly when thetemperature falls to a directed value as distinguished from a device which is used to provide automatictemperature regulation between close limits and would be designated as 90T.

24 Volts per Hertz Device operates on the ratio of voltage to frequency.

25 Synchronizing or Synchronism-Check Device operates when two a-c circuits are within the desired limits offrequency, phase angle or voltage, to permit or to cause the paralleling of these two circuits.

26 Apparatus Thermal Device functions when the temperature of the shunt field or the amortisseur winding of amachine, or that of a load limiting or load shifting resistor or of a liquid or other medium exceeds a predeterminedvalue; or if the temperature of the protected apparatus, such as a power rectifier, or of any medium decreasesbelow a predetermined value.

27 Undervoltage Relay is a device which functions on a given value of undervoltage.

28 Flame Detector monitors the presence of the pilot or main flame in such apparatus as a gas turbine or a steamboiler.

29 Isolating Contactor is used expressly for disconnecting one circuit from another for the purposes of emergencyoperation, maintenance, or test.

30 Annunciator Relay is a non-automatically reset device which gives a number of separate visual indications uponthe functioning of protective devices, and which may also be arranged to perform a lockout function.

31 Separate Excitation Device connects a circuit such as the shunt field of a synchronous converter to a source ofseparate excitation during the starting sequence; or one which energizes the excitation and ignition circuits of apower rectifier.

32 Directional Power Relay is one which functions on a desired value of power flow in a given direction, or uponreverse power resulting from arc back in the anode or cathode circuits of a power rectifier.

33 Position Switch makes or breaks contact when the main device or piece of apparatus, which has no devicefunction number, reaches a given position.

34 Motor-Operated Sequence Switch is a multi-contact switch which fixes the operating sequence of the majordevices during starting and stopping, or during other sequential switching operations.

35 Brush-Operating or Slip-Ring Short-Circuiting Device is used for raising, lowering, or shifting the brushes of amachine, or for short-circuiting its slip rings, or for engaging or disengaging the contacts of a mechanical rectifier.

36 Polarity Device operates or permits the operation of another device on a predetermined polarity only.

37 Undercurrent or Underpower Relay is a device which functions when the current or power flow decreases belowa predetermined value.

38 Bearing Protective Device is one which functions on excessive bearing temperature, or on other abnormalmechanical conditions, such as undue wear, which may eventually result in excessive bearing temperature.




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39 Mechanical Condition Monitor functions on the occurrence of an abnormal mechanical condition.

40 Field Relay is a device that functions on a given or abnormally low value or failure of machine field current, or onan excessive value of the reactive component of armature current in an a-c machine indicating abnormally low fieldexcitation.

41 Field Circuit Breaker is a device which functions to apply, or to remove, the field excitation of a machine.

42 Running Circuit Breaker is a device whose principal function is to connect a machine to its source of runningvoltage after having been brought up to the desired speed on the starting connection.

43 Manual Transfer or Selector Device transfers the control circuits so as to modify the plan of operation of theswitching equipment or of some of the devices.

44 Unit Sequence Starting Relay is a device which functions to start the next available unit in a multiple-unitequipment on the failure or on the non-availability of the normally preceding unit.

45 Atmospheric Condition Monitor functions on the occurrence of an abnormal atmospheric condition.

46 Reverse-Phase or Phase-Balance Current Relay is a device which functions when the polyphase currents are ofreverse-phase sequence, or when the polyphase currents are unbalanced or contain negative phase-sequencecomponents above a given amount.

47 Phase-Sequence Voltage Relay is a device which functions upon a predetermined value of polyphase voltage inthe desired phase sequence.

48 Incomplete Sequence Relay is a device which returns the equipment to the normal, or off, position and locks it outif the normal starting, operating or stopping sequence is not properly completed within a predetermined time.

49 Machine or Transformer Thermal Relay is a device which functions when the temperature of an a-c machinearmature, or of the armature or other load carrying winding or element of a d-c machine, or converter or powerrectifier or power transformer (including a power rectifier transformer) exceeds a predetermined value.

50 Instantaneous Overcurrent or Rate-of-Rise Relay is a device which functions instantaneously on an excessivevalue of current, or on an excessive rate of current rise, thus indicating a fault in the apparatus or circuit beingprotected.

51 A-C Time Overcurrent Relay is a device which either a definite or inverse time characteristic which functionswhen the current in an a-c circuit exceeds a predetermined value.

52 A-C Circuit Breaker is a device which is used to close and interrupt an a-c power circuit under normal conditionsor to interrupt this circuit under fault or emergency conditions.

53 Exciter or D-C Generator Relay is a device which forces the d-c machine field excitation to build up during startingor which functions when the machine voltage has built up to a given value.

54 High-Speed D-C Circuit Breaker is a circuit breaker which starts to reduce the current in the main circuit in 0.01second or less, after the occurrence of the d-c overcurrent or the excessive rate of current rise.

55 Power Factor Relay is a device which operates when the power factor in an a-c circuit becomes above or below apredetermined value.

56 Field Application Relay is a device which automatically controls the application of the field excitation to an a-cmotor at some predetermined point in the slip cycle.

57 Short-Circuiting or Grounding Device is a power or stored energy operated device which functions toshort-circuit or to ground a circuit in response to automatic or manual means.

58 Power Rectifier Misfire Relay is a device which functions if one or more of the power rectifier anodes fails to fire.

59 Overvoltage Relay is a device which functions on a given value of overvoltage.

60 Voltage Balance Relay is a device which operates on a given difference in voltage between two circuits.




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61 Current Balance Relay is a device which operates on a given difference in current input or output of two circuits.

62 Time-Delay Stopping or Opening Relay is a time-delay device which serves in conjunction with the device whichinitiates the shutdown, stopping, or opening operation in an automatic sequence.

63 Liquid or Gas Pressure, Level, or Flow Relay is a device which operates on given values of liquid or gaspressure, flow or level, or on a given rate of change of these values.

64 Ground Detector Relay is a relay that operates on failure of machine or other apparatus insulation to ground.

Note: This function is not applied to a device connected in the secondary circuit of current transformers in anormally grounded power system.

65 Governor is the equipment which controls the gate or valve opening of a prime mover.

66 Notching or Jogging Device functions to allow only a specified number of operations of a given device, orequipment, or a specified number of successive operations within a given time of each other. It also functions toenergize a circuit periodically, or which is used to permit intermittent acceleration or jogging of a machine at lowspeeds for mechanical positioning.

67 A-C Directional Overcurrent Relay is a device which functions on a desired value of a-c overcurrent flowing in apredetermined direction.

68 Blocking Relay is a device which initiates a pilot signal for blocking of tripping on external faults in a transmissionline or in other apparatus under predetermined conditions, or cooperates with other devices to block tripping or toblock reclosing on an out-of-step condition or on power swings.

69 Permissive Control Device is generally a two-position, manually operated switch which in one position permits theclosing of a circuit breaker, or the placing of an equipment into operation, and in the other position prevents thecircuit breaker or the equipment from being operated.

70 Electrically Operated Rheostat is a rheostat which is used to vary the resistance of a circuit in response to somemeans of electrical control.

71 Level Switch is a switch which operates on given values, or on a given rate of change of level.

72 D-C Circuit Breaker is used to close and interrupt a d-c power circuit under normal conditions or to interrupt thiscircuit under fault or emergency conditions.

73 Load-Resistor Contactor is used to shunt or insert a step of load limiting, shifting, or indicating resistance in apower circuit, or to switch a space heater in circuit, or to switch a light, or regenerative, load resistor of a powerrectifier or other machine in and out of circuit.

74 Alarm Relay is a device other than an annunciator, as covered under Device No. 30, which is used to operate, orto operate in connection with, a visual or audible alarm.

75 Position Changing Mechanism is the mechanism which is used for moving a removable circuit breaker unit toand from the connected, disconnected, and test positions.

76 D-C Overcurrent Relay is a device which functions when the current in a d-c circuit exceeds a given value.

77 Pulse Transmitter is used to generate and transmit pulses over a telemetering or pilot-wire circuit to the remoteindicating or receiving device.

78 Phase Angle Measuring or Out-of-Step Protective Relay is a device which functions at a predetermined phaseangle between two voltages or between two currents or between voltage and current.

79 A-C Reclosing Relay is a device which controls the automatic reclosing and locking out of an a-c circuitinterrupter.

80 Flow Switch is a switch which operates on given values, or on a given rate of change of flow.




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81 Frequency Relay is a device which functions on a predetermined value of frequency – either under or over or onnormal system frequency – or rate of change of frequency.

82 D-C Reclosing Relay is a device which controls the automatic closing and reclosing of a d-c circuit interrupter,generally in response to load circuit conditions.

83 Automatic Selective Control or Transfer Relay is a device which operates to select automatically betweencertain sources or conditions in an equipment, or performs a transfer operation automatically.

84 Operating Mechanism is the complete electrical mechanism or servo-mechanism, including the operating motor,solenoids, position switches, etc., for tap changer, induction regulator or any piece of apparatus which has nodevice function number.

85 Carrier, or Pilot-Wire, Receiver Relay is a device which is operated or restrained by a signal used in connectionwith carrier-current or d-c pilot-wire fault directional relaying.

86 Locking-Out Relay is an electrically operated hand or electrically reset device which functions to shut down andhold an equipment out of service on the occurrence of abnormal conditions.

87 Differential Protective Relay is a protective device which functions on a percentage or phase angle or otherquantitative difference of two currents or of some other electrical quantities.

88 Auxiliary Motor, or Motor Generator is one used for operating auxiliary equipment such as pumps, blowers,exciters, rotating magnetic amplifiers, etc.

89 Line Switch is used as a disconnecting or isolating switch in an a-c or d-c power circuit, when this device iselectrically operated or has electrical accessories, such as an auxiliary switch, magnetic lock, etc.

90 Regulating Device functions to regulate a quantity, or quantities, such as voltage, current, power, speed,frequency, temperature, and load, at a certain value or between certain limits for machines, tie lines or otherapparatus.

91 Voltage Directional Relay is a device which operates when the voltage across an open circuit breaker or contactorexceeds a given value in a given direction.

92 Voltage and Power Directional Relay is a device which permits or causes the connection of two circuits when thevoltage difference between them exceeds a given value in a predetermined direction and causes these two circuitsto be disconnected from each other when the power flowing between them exceeds a given value in the oppositedirection.

93 Field Changing Contactor functions to increase or decrease in one step the value of field excitation on a machine.

94 Tripping, or Trip-Free, Relay is a device which functions to trip a circuit breaker, contactor, or equipment, or topermit immediate tripping by other devices; or to prevent immediate reclosure of a circuit interrupter, in case itshould open automatically even though its closing circuit is maintained closed.

95 to 99 Used only for specific applications on individual installations where none of the assigned numbered functions from1 to 94 is suitable.

Note: The following sections entitled “Suffix Letters”, “Suffix Numbers”, and “Devices Performing More thanOne Function” have not been updated. For the most up to date coverage of this material, see IEEEStandard C37.2.




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SUFFIX LETTERS

Suffix letters are used with device function numbers for various purposes. In order to prevent possible conflict, any suffix letter usedsingly, or any combination of letters, denotes only one word or meaning in an individual equipment. All other words should use theabbreviations as contained in American Standard Z32.12-1950, or latest revision thereof, or should use some other distinctiveabbreviation, or be written out in full each time they are used. Furthermore, the meaning of each single suffix letter, orcombination of letters, should be clearly designated in the legend on the drawings or publications applying to the equipment:

The following suffix letters generally form part of the device function designation and thus are written directly behind the devicenumber, such as 23X, 90V, or 52BT.

These letters denote separate auxiliary devices, such as:

X}

Y} – Auxiliary relay*

Z}

R – Raising relay

L – Lowering relay

O – Opening relay

C – Closing relay

*Note: In the control of a circuit breaker with so-called X-Y relay control scheme, the X relay is the device whose main contactsare used to energize the closing coil and the contacts of the Y relay provide the anti-pump feature for the circuit breaker.

CS – Control switch

CL – “A” auxiliary-switch relay

OP – “B” auxiliary-switch relay

U – “Up” position-switch relay

PB – Push button

These letters indicate the condition or electrical quantity to which the device responds, or the medium in which it is located, suchas:

A – Air, or amperes

C – Current

E – Electrolyte

F – Frequency, or flow

L – Level, or liquid

P – Power, or pressure

PF – Power factor

Q – Oil

S – Speed

T – Temperature




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V – Voltage, volts, or vacuum

VAR – Reactive power

W – Water, or watts

These letters denote the location of the main device in the circuit, or the type of circuit in which the device is used or the type ofcircuit or apparatus with which it is associated, when this is necessary, such as:

A – Alarm or auxiliary power

AC – Alternating current

AN – Anode

B – Battery, or blower, or bus

BK – Bypass

BT – Bus tie

C – Capacitor, or condenser, compensator, or carrier current

CA – Cathode

DC – Direct current

E – Exciter

F – Feeder, or field, or filament

G – Generator, or ground** (see note below)

H – Heater, or housing

L – Line

M – Motor, or metering

N – Network, or neutral** (see note below)

P – Pump

R – Reactor, or rectifier

S – Synchronizing

T – Transformer, or test, or thyraton

TH – Transformer (high-voltage side)

TL – Transformer (low-voltage side)

TM – Telemeter

U – Unit

** Suffix “N” is generally used in preference to “G” for devices connected in the secondary neutral of current transformers, or in thesecondary of a current transformer whose primary winding is located in the neutral of a machine or power transformer, except inthe case of transmission line relaying, where the suffix “G” is more commonly used for those relays which operate on ground faults.




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These letters denote parts of the main device:

Many of these do not form part of the device number, and should be written directly below the device number, such as 20LS

or 43A

.

BB – Bucking bar (for high speed d-c circuit breaker)

BK – Brake

C – Coil, or condenser, or capacitor

CC – Closing coil

HC – Holding coil

IS – Inductive shunt

L – Lower operating coil

M – Operating motor

MF – Fly-ball motor

ML – Load-limit motor

MS – Speed adjusting, or synchronizing, motor

S – Solenoid

TC – Trip coil

U – Upper operating coil

V – Valve

All auxiliary contacts and limit switches for such devices and equipment as circuit breakers, contactors, valves, and rheostats.These are designated as follows:

a – Auxiliary switch, open when the main device is in the de-energized or non-operated position.

b – Auxiliary switch, closed when the main device is in the de-energized or non-operated position.

aa – Auxiliary switch, open when the operating mechanism of the main device is in the de-energized or non-operatedposition.

bb – Auxiliary switch, closed when the operating mechanism of the main device is in the de-energized or non-operatingposition.

e, f, h, etc., ab, ac, ad, etc., or ba, bc, bd, etc., are special auxiliary switches other than a, b, aa, and bb. Lower-case (small) lettersare to be used for the above auxiliary switches.

Note: If several similar auxiliary switches are present on the same device, they should be designated numerically 1, 2, 3, etc.,when necessary.

LC – Latch-checking switch, closed when the circuit breaker-mechanism linkage is relatched after an opening operationof the circuit breaker.

LS – Limit switch.




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These letters cover all other distinguishing features or characteristics or conditions, not specifically described above, which serveto describe the use of the device or its contacts in the equipment such as:

A – Accelerating, or automatic

B – Blocking, or backup

C – Close, or cold

D – Decelerating, detonate, or down

E – Emergency

F – Failure, or forward

H – Hot, or high

HR – Hand reset

HS – High speed

IT – Inverse time

L – Left, or local, or low, or lower, or leading

M – Manual

OFF – Off

ON – On

O – Open

P – Polarizing

R – Right, or raise, or reclosing, or receiving, or remote, or reverse

S – Sending, or swing

T – Test, or trip, or trailing

TDC – Time-delay closing

TDO – Time-delay opening

U – Up

SUFFIX NUMBERS

If two or more devices with the same function number and suffix letter (if used) are present in the same equipment, they may bedistinguished by numbered suffixes as for example 52X-1, 52X-2, and 52X-3, when necessary.

DEVICES PERFORMING MORE THAN ONE FUNCTION

If one device performs two relatively important functions in an equipment so that it is desirable to identify both of these functions,this may be done by using a double function number and name such as:

� 27-59 undervoltage and overvoltage relay




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FORMULAS COMMONLY USED IN RELAYING

PER UNIT SYSTEM

Definitions:

kVAB = Base kVA (three phase)

kVB = Base kV (line to line)

IB = Base Current

ZB = Base Impedance

Zpu = Per Unit Impedance

Z = Impedance in Ohms

Note: To convert the impedances in an electrical system to a consistent set of per unit impedances, select the base voltageson either side of a transformer such that their ratio is the same as the nominal voltage ratio of the transformer; and selectone base kVA for the entire system. With rare exception, the base voltage and the winding nominal voltage are the same.All impedances on a given side of a transformer must be per-unitized on the base kV on that side of the transformer, andall equipment in the system, including the transformers, must be per-unitized on the base kVA of the entire system. Inthe rare event the transformer voltage ratio and base-voltages ratio are equal but the rated voltage does not equal thebase voltage (e.g., 132 kV/13.2kV = 138kV/13.8kV, but 132kV is not the base voltage), the per unit impedance basedon rated voltages must be multiplied by the square of the ratio of rated voltage to base voltage. See formulas below forconverting per unit quantities to new kVA and kV bases.

Basic Formulas:

IB �kVAB

3� kVB

amperes (1)

ZB �1000 kVB

3� IBohms �

1000 �kVB�2

kVABohms

(2)

Zpu �Z�

ZB�

Z��kVAB

�

1000 �kVB�2

(3)

Z�

�10 �kVB

�2 x % Z

kVAB

(4)




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FORMULAS COMMONLY USED IN RELAYING (Cont)

CONVERSIONS AND CALCULATIONS

Converting per unit to percent:

%Z = 100 Zpu (5)

Converting Zpu to New Voltage Base:

�Zpu�2 � �Zpu�1�kVB1

�2

�kVB2�2

(6)

Converting Zpu to New kVA Base:

�Zpu�2 � �Zpu�1(kVA)B2(kVA)B1

(7)

Given a single-phase grounding transformer with a secondary-to-primary voltage ratio of (KV)S/(KV)P, the relationship between asecondary-side resistor, (R)S and its reflection (R)P into the primary (e.g., into the neutral of a generator) is:

�R��s� �R

��P

�kVs�2

�kVp�2

(8)

Determining Burden Impedance (Z):

Z �(VA)

I2�

(V)2

VAohms

(9)

where: VA = volt-ampere burden at specified V or I.V = voltage at which burden is specified.I = current at which burden is specified.

Determining New Short Time Relay Coil Rating

(Approximate – do not use continuous rating):

I2 � I1t1t2

� (10)

where: I2 = thermal rating for t2 timeI1 = thermal rating for t1 time




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FORMULAS COMMONLY USED IN RELAYING (Cont)

Converting kVA to Amperes (1):

I � kVA3� kV

amperes (11)

where: kVA = three-phase powerkV = rated potential, kilovolts

Determining Distance Relay Apparent Impedance, ZR, Due to Infeed Current

Z

Fault LocationRelay Location

IRIR + ID

ZD

ID

ZR � Z �IDIR

ZD relay ohms (12)

where: ZR = apparent primary impedance sensed by the distance relay, based on (VR)LN at the relay location,divided by IR, for a bolted three-phase at other end.

Z = series line-impedance from relay location to fault.ZD = portion of line impedance, Z, through which ID + IR is flowing.ID = infeed currentIR = current in relaying current transformer primary

Decay of D-C Component

it � Ioe– tT

(13)

where: it = d-c component of current at time tIo = d-c component of current at time zeroe = base of Napierian logarithms = 2.71828...t = time at which d-c component is being calculated

T = Time Constant = LR

L = inductance of circuitR = resistance of circuit




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APPENDIX

XX

XXXX

Generator

Protectiveor ControlDevice

Coil

BusDuct

IndicatingLight

Pothead

PushButton

Power Transformer

DisconnectSwitch

Protectiveor ControlDevice

Drawout

Outdoor PowerCircuit Breaker

ProtectiveDevice

CurrentTransformer

Zero SequenceCurrent Transformer

DeltaWinding

Diode

Thyristor 10/95-12702-36D

SYMBOLS

G

SYMBOLS




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APPENDIX (Cont)

SYMBOLS

Resistor

Earth

Fuse

Delta-Wyewith SecondaryNeutral ResistanceGround

Wye Connectedwith NeutralSolidly Grounded

DisconnectSwitchand Fuse

Drawout IndoorMetal-CladCircuit Breaker

CircuitBreaker

LightningArrestor

Capacitor

Battery

Fused CombinationStarter

Current LimitingCircuit BreakerCombination Starter

DrawoutMetal-CladContactor

Normally ClosedContact

Normally OpenContact

ManualSelectorSwitch

TransferSwitch

SurgeProtector

Link

10/95-12702-37D




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APPENDIX (Cont)

SYMBOLS

10/95-12702-38D

==

=

~~

~

=~

Resistor

ThermalElement

Connection

WyeWinding

Autotransformer

Circuit BreakerCombination Starter

Three WindingTransformer

PowerTransformer

PotentialTransformer

Power Transformerwith AutomaticOn-Load Tap Changer

Three WindingTransformer withAutomatic On-LoadTap Changer

D-C VoltageStabilizer

A-C VoltageStabilizer

BatteryChargeror Rectifier

FusedDisconnectSwitch

Motor

Autotransformer

Reactor

Reactor

PowerTransformer

Three WindingTransformer withAutomatic On-LoadTap Changer

Inverter

M




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FIGURE 1DEFINITION OF KNEE POINT

10/95-12702-01D

Exc

iting

Vol

tage

(V

s)

Exciting Voltage (Ie)

VKVK

+50% IeK

IeK

+10%




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FIGURE 2CURRENT LIMITING FUSE

��Cut-Off Current

(Peak Let-Through)

ProspectiveCurrent

Fau

lt In

cept

ion

Cur

rent

Pre

-Arc

ing

Tim

e

Tot

al C

lear

ing

Tim

e

One

Cyc

le

Time

10/95-12702-02D




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FIGURE 3INSTANTANEOUS RELAY CURRENT VS. TIME CURVE

WITH OR WITHOUT d.c. FILTER

��

Fault Current

I Current "Seen"by Relay (RMS)

Symmetrical Current

t

10/95-12702-03D




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SENSITIVE TO CURRENT OFFSET (d.c.)

��

��

Fault Current

ICurrent "Seen"by Relay (RMS)

Asymmetrical Current

t

10/95-12702-04D




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WITH d.c. COMPONENT FILTERED OUT

��

��

Fault Current

I

Current "Seen"by Relay (RMS Minus d.c.)

Asymmetrical Current

t

10/95-12702-05D

d.c. Component

FIGURE 6INSTANTANEOUS RELAY OVERREACH VS. SYSTEM ANGLE

(LOW OVERREACH RELAY)

12

10

8

6

4

2

084° 85° 86°

System Angle

Ove

rrea

ch %

87° 88°

10/95-12702-06D




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FIGURE 7INSTANTANEOUS RELAY OPERATING TIME VS. CURRENT

Hi Setting

Low Setting

70

60

50

40

30

20

10

0

0 1 2 3 4 5

Multiples of Setting Current 10/95-12702-07D

Ope

ratin

g T

ime

(Mill

isec

onds

)

6 7 8 9 10




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FIGURE 8TYPICAL TIME VS. CURRENT CURVES OF RELAYS WITH INVERSE TIME CHARACTERISTICS

20

109876

5

2

3

4

1.9.8.7.6

.5

.2

.3

.4

.1.09.08.07.06

.05

.02

.01.5 .6 .7 .8 .9 1 5432 6 7 8 910

.03

.04

5040302060

7080

90100

109876

5

4

3

2

1

Aw

TIM

E D

IAL

SE

TT

ING

S

TIM

E IN

SE

CO

ND

S

MULTIPLES OF RELAY TAP SETTING10/95-12702-51D




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FIGURE 9INVERSE TIME OVERCURRENT RELAY SLOPES

Tim

e

Multiples of Pickup Current

Extremely Inverse

Very Inverse

Inverse

10/95-12702-08D

FIGURE 10DEFINITE TIME OVERCURRENT RELAY

TIME VS. CURRENT CURVE

Tim

e

Current

AdjustablePickupCurrent

Adjustable Time Delay

10/95-12702-09D




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FIGURE 11GENERATOR CABLE PROTECTION WITH DIRECTIONAL RELAY

(NOT RECOMMENDED)

87

67

10/95-12702-10D




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FIGURE 12GENERATOR CABLE PROTECTION WITH DIFFERENTIAL RELAY

(RECOMMENDED)

87

10/95-12702-11D

FIGURE 13CABLE DIFFERENTIAL PROTECTION

3 3

3

87

10/95-12702-12D




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FIGURE 14TRANSFORMER DIFFERENTIAL PROTECTION

3 3

3

87T10/95-12702-13D

FIGURE 15GENERATOR OR MOTOR DIFFERENTIAL PROTECTION

(LOWER SKETCH OF “SELF BALANCING” SCHEME IS PREFERRED FOR MOTORS)

3 3

3

87

3

3

8710/95-12702-14D




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FIGURE 16BUSBAR DIFFERENTIAL PROTECTION

3

33

3

33

87

10/95-12702-15D

FIGURE 17STANDARD DIFFERENTIAL PROTECTION

3 3

387

10/95-12702-16D

4 or 6 Conductors

FIGURE 18PILOT WIRE DIFFERENTIAL PROTECTION

3 3

187P

187P

10/95-12702-17D

2 Conductors (1 Pair)




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FIGURE 19DISTANCE (IMPEDANCE) PROTECTION

21

Rel

ayin

g P

oint

To 200% 200% of Line 1.5Seconds

120% of Line 0.5S

80% of Line 0.1S

Length of Line

3

A B C

10/95-12702-18D




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FIGURE 20TIME GRADING SELECTIVITY

M M

10/95-12702-19D

M M

1 1 1 1

3

2

3

2

5

4

M

1

Bus C

Bus A

Bus D

Bus D




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FIGURE 21CURRENT GRADING

10/95-12702-20D

A

B

Power Source Bus

Load Bus

FIGURE 22SELECTIVITY BETWEEN FUSES

Am

p S

quar

ed S

econ

ds

Fuse Rating in Amps

Total

Clearin

g I2

t

Pre-A

rcing

or M

inim

um M

elt I2 t

10/95-12702-21D




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FIGURE 23 FIGURE 24INSTANTANEOUS RELAY SET POINT INSTANTANEOUS RELAY OPERATION

AT LESS THAN HALF A CYCLE

��

Cur

rent

Relay Setting

t

Area = A

��

��

��

��

Cur

rent

t

11

2>

2

Area = A

10/95-12702-22D




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FIGURE 25SELECTIVITY BETWEEN AN INSTANTANEOUS RELAY AND A CURRENT LIMITING FUSE

Relay Setting Peak and Fuse Peak Let - Through

Relay Setting Current Waveform

Relay Setting (rms) = (100/

t

I

2 ) x Peak = 70% Peak

10/95-12702-24D

Prospective Fault Current




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FIGURE 26FUSE PEAK LET-THROUGH CURRENT CURVES

Pea

k Le

t-T

hrou

gh C

urre

ntkA

Pea

kB

A

200A Fuse

100A Fuse

50A Fuse

20A Fuse

10A Fuse

rms Symmetrical

System Short Circuit Current10/95-12702-25D




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FIGURE 27BACKUP PROTECTION

87

51V

10/95-12702-26D

Gen 1

Relay 3

Relay 4

51 Relay 2

51 Relay 1




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FIGURE 28MOTOR CONTROL CIRCUITS

493

493

493

350/51 Same asA, B, or

C

50GS1 1

(B)LV Contactor

and Fuses

(A)LV Contactor

and Fuses

(C)LV Contactor

and MCB

(D)LV Contactor

With Ground Relay

3

3

1

1 1

1

1

1

1 1

1

3

3 1

11

1

1

3

27

27

HR

49

49 51

51

50GS

50GS50GS

**

*

(E)LV Circuit Breaker

(F)MV Contactor

(G)MV Circuit Breaker

86HR

86HR

* * *

49/50

10/95-12702-27D-rev02/02/96-sss

Notes:

* Not required on high resistance grounded circuits.

** May not be required if incorporated in the circuit breaker.

*** Differential protection 87 required for motors 1801kW and above.

HR Hand reset.

The following details are not normally drawn on single line diagrams but have been shown here to illustrate the protection more fully

– Direct acting trip device number, number of elements, and trip signal.

– Trip signal from striker pins.




SectionXXX-E

Page

DateEXXON

ENGINEERING

74 of 92

December, 1995


FIGURE 29TRANSFORMER PROTECTION

b

b

3 3

1 1

1

11

Note 1

Alarm

50 GS

50/51

33

1150 GS

50/51

63

≥500 kVA

<500 kVA

b

3

3

3

3

3

1 1

1

1

11

Note 1

Alarm

50 GS

50/51

63

≥500 kVA with Differential

51G

86

87T

51G

10/95-12702-28D-rev02/02/96-sss

Notes:

(1) Low resistance and solidly grounded neutrals require 51G as shown.

(2) Temperature relays (26) also provided. Refer to text.




SectionXXX-E

Page

DateEXXON

ENGINEERING

75 of 92

December, 1995


FIGURE 30PARTIAL DIFFERENTIAL PROTECTION

51

51

10/95-12702-29D Fault

Bus BBus A

Relay A

Relay B

DESIGN PRACTICESSection Page

DateDecember, 1995

EXXONENGINEERING

XXX-E 76 of 92 SYSTEM AND EQUIPMENT PROTECTIVE


ELECTRICAL POWER FACILITIES

RELAYING


FIG

UR

E 3

1R

ELA

Y S

ET

TIN

GS

RE

CO

RD

Pan

elor

Fee

der

No.

AN

SI

Sym

bol

Ser

vice

Phase

Mfg

.M

odel

No.

Tim

eC

har

Inst

ruct

Boo

k N

o.T

ime

Inst

Ran

geC

T o

r P

TR

atio

Tap

Tim

eD

ial

Inst

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

Cal

ibra

teC

alib

rate

Che

ckC

heck

Coord CurveSymbol

RE

MA

RK

S

RE

LAY

RE

LAY

DE

SC

RIP

TIO

NS

ET

TIN

GS

TE

ST

PO

INT

SF

IELD

TE

ST

S

Sub

stat

ion

Vol

tage

She

et

o

fR

evis

ion

Dat

e

B

y

10/9

5-12

702-

30D




SectionXXX-E

Page

DateEXXON

ENGINEERING

77 of 92

December, 1995


FIGURE 32RELAY COORDINATION GRAPH PAPER

1 2 3 4 5 10

.1.09.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

9876.5 .9.8.7.6 20 30 40 50 90807060

200

100

300

400

500

1000900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

1 2 3 4 5 109876.5 .9.8.7.6 20 30 40 50 90807060 200

100

300

400

500

1000

900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

TIM

E IN

SE

CO

ND

S

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

TIM

E IN

SE

CO

ND

S

10/95-12702-43D

...............................................TIME-CURRENT CHARACTERISTIC CURVESFor...................................................................Fuse Links, In.........................................................................................................................................BASIS FOR DATA Standards.........................Dated........................................................................................................1. Tests made at......................Volts a-c at....................p.f., Starting at 25C with no initial load......................................2. Curves are plotted to..........................Test points so variations should be..................................................................

No. ....................................Date...................................

Note: Use full size graph paper (11” x 17”)


DateDecember, 1995

EXXONENGINEERING




RELAYING


FIG

UR

E 3

3R

ELA

Y C

OO

RD

INAT

ION

SA

MP

LE O

NE

LIN

E D

IAG

RA

M

Feeder No. 1

Feeder No. 2

5051

5051

5051

5051

50N 51N

50N 51N

5051

51G

51G

51G

400/

540

0/5

400/

540

0/5

100/

510

0/5

33

3

350

5150

513

33

33

3

3750

kV

A13

-2/2

-4kV

3750

kV

A13

-2/2

-4kV

1

11

1

11

51G

1

1

11

1

22

127

I27

I27

27R

49 50G

27R

27R

27R

27

5051

5051

50N 51N

50N 51N

11

1 1 11

12

2

127

I27

I27

27

2400

/120

V

2400

/12k

V

2400

/12

kV

2400

/120

V

Sub

stat

ion

23S

/S 2

3A

600A

Res

isto

r60

0AR

esis

tor

1200

/512

00/5

1200

/5312

00/5

300/

530

0/5

2400

VM

otor

Con

trol

Cen

ter

No.

1

2400

VM

otor

Con

trol

Cen

ter

No.

2

75/5

75/5

300/

530

0/5

300/

5

5051

1

49 50G

75/5

300/

5

5051

1

11

11

11

49 50G

5051

1

49 50G

400/

540

0/5

300/

5

5051

1

49 50G

75/5

300/

5

22

22

5051

1

49 50G

22

210

235

PM

302

CC

M 3

02P

M 3

01A

PM

301

BP

M 3

01C

PM

302

B

1250

1250

1250

235

966k

VA

1320

0/48

0V

966k

VA

1320

0/48

0V

Bus

1B

us 2

Bus

1B

us 2

600A

F22

5A60

0AF

225A

480/

120V

480V

TP

C

480V

MC

C N

o. 1

M

100A

F10

0A

Larg

est 3

3HP

480V

MC

C N

o. 2

M

100A

F10

0A

Larg

est 3

3HP

Welding Outlets

Lighting Panel D

10/9

5-12

702-

31D


DateDecember, 1995

EXXONENGINEERING

XXX-E 79 of 92SYSTEM AND EQUIPMENT PROTECTIVE



RELAYING


FIG

UR

E 3

4T

YP

ICA

L R

ELA

Y S

ET

TIN

GS

RE

CO

RD

(13

.8/2

.4 k

V)

(PA

RT

1 O

F 2

)

Pan

elor

Fee

der

No.

AN

SI

Sym

bol

Ser

vice

Phase

Mfg

.M

odel

No.

Tim

eC

har

Inst

ruct

Boo

k N

o.T

ime

Inst

Ran

geC

T o

r P

TR

atio

Tap

Tim

eD

ial

Inst

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

Cal

ibra

teC

alib

rate

Che

ckC

heck

Coord CurveSymbol

RE

MA

RK

S

RE

LAY

RE

LAY

DE

SC

RIP

TIO

NS

ET

TIN

GS

TE

ST

PO

INT

SF

IELD

TE

ST

S

Sub

stat

ion

Vol

tage

She

et

o

fR

evis

ion

Dat

e

B

y

10/9

5-12

702-

32D

2313

800-

2400

21

01/

5/71

CW

L

1 1 1 1 1 1 1

50P

-151

P-1 "

" " " "

""

""

" " ""

"""

" " " " "

""

""

" ""

""

""

"

""

"""

""

" ""

"" " "

" " " "

" "" " " " " " "

""

"" " "

"""

""

""

""

" ""

""

""

""

""

"" " "

"

""

""

""

"

""

""

"

""

"

" """" "

3750

KV

A T

rans

form

erP

rimar

y -

Bus

1

3750

KV

A T

rans

form

erS

econ

dary

- B

us 1

3750

KV

A T

rans

form

erP

rimar

y -

Bus

2

3750

KV

A T

rans

form

erN

eutr

al -

Bus

1

Bus

1 In

com

ing

Line

Bus

1

A B C A C G N AB

ABAA B C C G N

50-1

51-1

50N

-151

N-1

51G

-1

27-1

27I-

1

27R

-1

96-1

97-1

50P

-251

P-2

50-2

51-2" " "

""

""""""

""

""

"

"

"" "

27I-

2

27-2

51G

-2

50N

-251

N-2

Bus

2 -

Inco

min

gLi

ne

3750

KV

A T

rans

form

erN

eutr

al -

Bus

2

3750

KV

A T

rans

form

erS

econ

dary

- B

us 2

IAC

51B

22A

IAC

51A

2A

IAV

54E

1A

NG

V13

B30

A

GE

IAC

51B

104A

1AC

53B

101A

" " "

AB

AB

AB C - -

IAC

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51A

2A

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54E

IA

NG

V13

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RA

V11

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PB

GE

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51B

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101A

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yIn

vers

e

Inve

rse

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rse

Inst

.

Inst

.

GE

H-1

753

GE

H-1

753

GE

H-1

768

GE

I-90

805

GE

I-44

220

SR

-15-

X

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753

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TD

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yIn

vers

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GE

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9080

5

4-16

A

4-16

A

20-8

0A

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0A

0.5-

2A

1.5-

6A

55-1

40V

- -

0.2-

5se

c

2-8A - -

80-1

20V

18-3

6V

-- -

-

4-16

A20

-80A

4-16

A

0.5-

2A

1.5-

6A

55-1

40V

-80

-120

V

2400

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V

2-8A

10-4

0A

300/

5A

1200

/5A

-

932.5

0.58

100

100

d.o.

1.521

--2

400/

5A

1200

/5A

300/

5A

2400

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V

400/

5A

-82

5140

0.73

43.8

161.

4888

.8

82.

533

400.

6740

.216

3.4

204

0.5

12

2.5

0.39

23.4

10.

75 45

2.5

2-

12.5

0.73

43.8

51.

4888

.8

931.

5-

01.

060

752.

816

8

--

100

100

d.o.

110

max

.p.

u.

max

.p.

u.

--

3030

d.o.

78

-3 se

c-

d.o.

d.o.

3 180

--

-1 se

c-

1 60-

-

82

5140

0.73

43.8

161.

4888

.8

2.5

3340

0.67

40.2

163.

420

4

2.5

0.39

23.4

10.

75 45

12.5

0.73

43.8

51.

4888

.8

01.

060

752.

816

8

110

max

p.u.

R5

R4R3

R2

R1 ------

d.o.

= d

rop-

out

p.u.

= p

ick-

up

R5R1

R2

R3

R4

22333333322222


DateDecember, 1995

EXXONENGINEERING




RELAYING


FIG

UR

E 3

4 (C

ont)

TY

PIC

AL

RE

LAY

SE

TT

ING

S R

EC

OR

D (

13.8

/2.4

kV

)(P

AR

T 2

OF

2)

Pan

elor

Fee

der

No.

AN

SI

Sym

bol

Ser

vice

Phase

Mfg

.M

odel

No.

Tim

eC

har

Inst

ruct

Boo

k N

o.T

ime

Inst

Ran

geC

T o

r P

TR

atio

Tap

Tim

eD

ial

Inst

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

Cal

ibra

teC

alib

rate

Che

ckC

heck

Coord CurveSymbol

RE

MA

RK

S

RE

LAY

RE

LAY

DE

SC

RIP

TIO

NS

ET

TIN

GS

TE

ST

PO

INT

SF

IELD

TE

ST

S

Sub

stat

ion

Vol

tage

She

et

o

fR

evis

ion

Dat

e

B

y

10/9

5-12

702-

33D

2313

800-

2400

22

01/

5/71

CW

L

2 2 2

MC

C1

MC

C2

" " "

27R

-2

96-2

97-2

50 51

" " " "

"

" "

- -

3 180 1 60

"

""

" " " " " " " "

""

" """"

""

"" ""

Bus

2

PM

302-

C

PM

-301

B

PM

-301

C

PM

-302

B

CM

-302

PM

-301

A

AC B G AC B G AC

AC

AB C - - B G AC

49 50G

49 50 51 50G 49 50 51 50G

49 49 4950G

50G

50G50 51 50 51 50 51

""

""""""

"" " "

IC28

20A

102

CR

124A

2

IAC

66K

19A

IC28

20A

102

GE GE

RA

V11

B2A

CR

124A

2

2422

PB

2422

PB

IAC

66 K

19A

"" "" " " " " " " " " "

"

B G AC B G

IC28

20A

102

CR

124A

2

TA

C66

K19

A

IC28

20A

102

CR

124A

2

TA

C66

K19

A

CR

124A

2

IAC

66K

19A

IIC28

20A

102

IAC

66K

19A

IC28

20A

102

CR

124A

2

Inve

rse

Inve

rse

Inve

rse

Long

Inve

rse

Long

Inve

rse

Long

Inve

rse

Long

Inve

rse

Long

Inve

rse

Long

Inve

rse

Inst

.

Inst

.

Inst

.

GE

I442

20

SR

-15-

X

GE

H-3

071

GE

I-44

233

GE

H-3

071

GE

S-5

000A

GE

I-44

233

GE

H-3

071

GE

I-44

233

GE

H-3

071

GE

I-44

233

GE

S-5

000A

GE

S-5

000A

GE

S-5

000A

GE

I-44

233

GE

S-5

000A

Inve

rse

GE

S-5

000A

GE

H-3

071

Inve

rse

Inve

rse

GE

I-44

233

Inst

.

Inst

.

Inst

.

Inst

.

GE

H-3

071

-

85-1

15%

85-1

15%

18-3

6V

-

4-8A

4-12

A20

-80A

4-8A

4-8A

4-8A

4-8A

4-8A

4-12

A20

-80A

4-12

A20

-80A

4-12

A20

-80A

4-12

A20

-80A

4-12

A20

-80A

- - - - - - - -

-- - -

300/

5A

75/5

A

300/

5A

400/

5A

300/

5A

300/

5A

91%

2--

2400

-120

V

75/5

A

75/5

A

300/

5

300/

5A

400/

5A

400/

5A

--

3030

78m

ax.

p.u.

91%

-8.

538 se

c

6.7

402

5.3 9

120

sec

17 1020

4.5

22.5

94%

-8.

040 se

c5.

011

5se

c

4.5

4.5

4.5

4.5

4.5

222

.56.

740

29

17 1020

d.o.

d.o.

d.o.

125

sec

125

sec

- - --

8.5

8.5

38 sec

38 sec

5.1

5.1

1.5

1.5

1.5

22.5

22.5

4.8

288

4.8

288

9 9

12 720

12 720

125

sec

8.5

38 sec

5.1

22.5

4.8

288

912 72

0

120

sec

8.5

38 sec

5.3

22.5

6.7

402

917 10

20

R8

R7

R6R6

R7

R7

R8

R8 -- ---

--

--

- - - - - - -

"""

Rel

ay D

ata

and

Coo

rdin

atio

n G

uide

Par

t ! -

Doc

umen

tatio

nE

SS

O E

ngin

eerin

g

Aga

Def

TD

0.2-

5S

EC

- - -

-- -

85-1

15%

85-1

15%

85-1

15%

85-1

15%

- -

Fac

tory

Set

Fac

tory

Set

Fac

tory

Set

Fac

tory

Set

Fac

tory

Set

Fac

tory

Set

97%

97%

97%

3S

EC

1S

EC 2

- - - 8.8 - - 8.2 -

8.5 - 8.5 - 8.5 -- -

See

Rem

arks

See

Rem

arks

See

Rem

arks

See

Rem

arks

See

Rem

arks

See

Rem

arks

8.8 -

B G

Che

ck p

u. S

houl

d pu

on 1

5-am

p in

CT

pri

Set

Hig

h d.

o. 5

0 U

nit

Nor

mal

d.o

. Uni

t Not

Use

d

Hea

ter

No.

CR

123C

3.79

AE

1-2

Fus

e 4R

Hea

ter

No.

CR

123C

3.79

AE

1-2

Fus

e 4R

Ditt

o P

M30

2-C

Ditt

o P

M30

2-C

Ditt

o P

M30

1-A

Ditt

o P

M30

1-A

Ditt

o P

M30

2-C

Ditt

o P

M30

2-C

Ditt

o P

M30

2-C

Hea

ter

No.

CR

123C

4.19

AE

1-2

Fus

e 4R

R6


DateDecember, 1995

EXXONENGINEERING




RELAYING


FIG

UR

E 3

5T

YP

ICA

L R

ELA

Y S

ET

TIN

GS

RE

CO

RD

(13

.8 k

V/4

80 V

)(P

AR

T 1

OF

2)

Pan

elor

Fee

der

No.

AN

SI

Sym

bol

Ser

vice

Phase

Mfg

.M

odel

No.

Tim

eC

har

Inst

ruct

Boo

k N

o.T

ime

Inst

Ran

geC

T o

r P

TR

atio

Tap

Tim

eD

ial

Inst

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

Am

psor

Vol

ts

Tim

eS

ecC

yc

Tim

eS

ecC

yc

Am

psor

Vol

ts

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= p

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33333333322222

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DateDecember, 1995

EXXONENGINEERING




RELAYING


FIG

UR

E 3

5 (C

ont)

TY

PIC

AL

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LAY

SE

TT

ING

S R

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No.

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No.

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SectionXXX-E

Page

DateEXXON

ENGINEERING

83 of 92

December, 1995


FIGURE 36TYPICAL 2400V PHASE RELAYING CURVES

1 2 3 4 5 10

.1.09.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

9876.5 .9.8.7.6 20 30 40 50 90807060

200

100

300

400

500

1000900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

100 x CURRENT IN AMPERES AT 2400 VOLTS

1 2 3 4 5 109876.5 .9.8.7.6 20 30 40 50 90807060 200

100

300

400

500

1000

900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

TIM

E IN

SE

CO

ND

S

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

TIM

E IN

SE

CO

ND

S

...........................................................TIME-CURRENT CHARACTERISTIC CURVESFor........................................................................................................ Fuse Links, In.............................................................................................................BASIS FOR DATA Standards.........................................................Dated.........................................................................1. Tests made at................................Volts a-c at..............................p.f., Starting at 25C with no initial load..................2. Curves are plotted to....................................Test points so variations should be.........................................................

No. ..............................................Date.............................................

10/95-12702-44D

PHASE RELAYING2400 V Switchgear Substation #23

1 FL-

FA

1218

A

1 30

Max

1377

7A

1 0-0

Min

1105

1A

1 Rea

ccel

2310

A77

.5%

R1(50P)65

%60

%50

%40

%25

%

0%

Transformer Damage Limit

R2(50)

R1(51P)

R5(27)

R2(51)

R7(51)

116% ∆-Y

Fuse

R7(50)

R6(49)

% Volts





SectionXXX-E

Page

DateEXXON

ENGINEERING

84 of 92

December, 1995


FIGURE 37TYPICAL 2400V GROUND RELAYING CURVES

1 2 3 4 5 10

.1.09.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

9876.5 .9.8.7.6 20 30 40 50 90807060

200

100

300

400

500

1000900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000


1 2 3 4 5 109876.5 .9.8.7.6 20 30 40 50 90807060 200

100

300

400

500

1000

900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

TIM

E IN

SE

CO

ND

S

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

TIM

E IN

SE

CO

ND

S

10/95-12702-45D


No. ..............................................Date.............................................

2400 V Switch gear Substation #23

R8(50G)

R3(50N)

1 0G

Max

600A

R3(51N)

R4(51G)





SectionXXX-E

Page

DateEXXON

ENGINEERING

85 of 92

December, 1995


FIGURE 38TYPICAL 2400V MOTOR RELAYING CURVES

1 2 3 4 5 10

.1.09.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

9876.5 .9.8.7.6 20 30 40 50 90807060

200

100

300

400

500

1000900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000


1 2 3 4 5 109876.5 .9.8.7.6 20 30 40 50 90807060 200

100

300

400

500

1000

900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

TIM

E IN

SE

CO

ND

S

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

TIM

E IN

SE

CO

ND

S

10/95-12702-46D


No. ..............................................Date.............................................

Motor #PM-301A, B & C Substation #23

1620A LockedRotor Current

MotorStartingCurve

R7(51)

R7(50)

MotorRunningCurve

R6(49)

Type EJ-2 Fuse 24RMax. Total Clearing Time

Type EJ-2 Fuse 24RMin. Total Clearing Time

Motor Heating

Motor Withstand LockedRotor (Cold)

270 FLA

Motor Withstand LockedRotor (Warm)





SectionXXX-E

Page

DateEXXON

ENGINEERING

86 of 92

December, 1995


FIGURE 39TYPICAL 480V PHASE RELAYING CURVES

1 2 3 4 5 10

.1.09.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

9876.5 .9.8.7.6 20 30 40 50 90807060

200

100

300

400

500

1000900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000


1 2 3 4 5 109876.5 .9.8.7.6 20 30 40 50 90807060 200

100

300

400

500

1000

900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

TIM

E IN

SE

CO

ND

S

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

TIM

E IN

SE

CO

ND

S


No. ..............................................Date.............................................

10/95-12702-47D

PHASE RELAYING480 V Switchgear Substation #23A

1 0 -

G29

99A

(AR

cing

)

77.5

%

R1(50P)

65%

60%

50%

40%

25%

0%

Transformer Damage Limit

R2(51)

R2(50)

R1(51P)

R5(27)

116% ∆-Y

R9

% Volts

R6

1 FL-

FA

1164

A

1 Rea

ccel

2310

A

1 30

Max

1525

4A

1 0-0

Min

1298

A





SectionXXX-E

Page

DateEXXON

ENGINEERING

87 of 92

December, 1995


FIGURE 40TYPICAL 480V GROUND RELAYING CURVES

1 2 3 4 5 10

.1.09.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

9876.5 .9.8.7.6 20 30 40 50 90807060

200

100

300

400

500

1000900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000


1 2 3 4 5 109876.5 .9.8.7.6 20 30 40 50 90807060 200

100

300

400

500

1000

900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

TIM

E IN

SE

CO

ND

S

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

TIM

E IN

SE

CO

ND

S


No. ..............................................Date.............................................

10/95-12702-48D

GROUND RELAYING480 V Switchgear Substation #23A

R4(51G)

R9

R6

R3(50N)

R3(51N)

1 0-G

2999

A(A

rcin

g)

1 0-G

Max

1539

6A





SectionXXX-E

Page

DateEXXON

ENGINEERING

88 of 92

December, 1995


FIGURE 41TYPICAL 480V TURNAROUND POWER CENTER

RELAYING CURVES

1 2 3 4 5 10

.1.09.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

9876.5 .9.8.7.6 20 30 40 50 90807060

200

100

300

400

500

1000900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000


1 2 3 4 5 109876.5 .9.8.7.6 20 30 40 50 90807060 200

100

300

400

500

1000

900

800

700

600

2000

3000

4000

5000

1000

090

0080

0070

00

6000

CURRENT IN AMPERES

TIM

E IN

SE

CO

ND

S

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

1.9.8

.7

.6

.5

.4

.3

.2

1098

7

6

5

4

3

2

1009080

70

60

50

40

30

20

1000900800

700

600

500

400

300

200

TIM

E IN

SE

CO

ND

S


No. ..............................................Date.............................................

10/95-12702-49D

Circuit BreakersTurnaround Power Center Substation #23A

1 FL

120A

R6

R7

R8

1 0-G

2999

A(A

rcin

g)

1 30

Max

1525

4A





SectionXXX-E

Page

DateEXXON

ENGINEERING

89 of 92

December, 1995


FIGURE 42STABILIZING RESISTOR

50N

Stabilizing Resistor

10/95-12702-39D




SectionXXX-E

Page

DateEXXON

ENGINEERING

90 of 92

December, 1995


FIGURE 43TYPICAL FUSE I2T CHARACTERISTICS

30,000,000

10,000,000

1,000,000

100,000

10,000

1,000

100

1,20

0

800

500

400

300

200

100603010 10/95-12702-50D-rev02/06/96-sss

FUSE RATING – AMPERES

AM

PE

RE

S2

SE

CO

ND

S

TOTAL OPERATING I2t

PRE-ARCING I2t

This graph shows the ampere2 seconds (l2t) let throughunder short-circuit conditions corresponding tomaximum arc energy within the fuses at rated voltage.It may be used for the purpose of determining faultenergy limitation and discrimination.

Discrimination is achieved when the total l2t of theminor fuse does not exceed the pre-arcing l2t of the major fuse.


DateDecember, 1995

EXXONENGINEERING




RELAYING


FIG

UR

E 4

4R

ELA

TIV

E M

AG

NIT

UD

ES

OF

FA

ULT

CU

RR

EN

TS

Tra

nsfo

rmer

Sec

onda

ryT

rans

form

er P

rimar

y

1.0

1.0

1.0

.58

.58

.58

.58

.58

.58

1.0

1.0

1.0

1.0

1.0

1.0

.87

.87

(A)

Thr

ee P

hase

Fau

lt

(B)

Pha

se to

Pha

se F

ault

(C)

Pha

se to

Gro

und

Fau

lt

In E

xam

ple

(B)

the

Sec

onda

ry C

urre

nt is

Rea

lly 0

.866

'

1 -

0.86

66' =

0.1

333

0.13

33

0.86

66 x

100

= 1

5.38

i

.e. A

ppro

x. 1

6%

0

0 .50

.50

.50

.50

The

refo

re th

e C

urre

nt in

One

Prim

ary

Pha

se is

16%

Gre

ater

Tha

n th

e F

ault

Cur

rent

in th

e S

econ

dary

Val

ues

are

Per

Uni

t Cur

rent

of T

hree

-Pha

se F

ault

on th

e S

econ

dary

with

Tra

nsfo

rmer

Rat

io o

f 1:1

10/9

5-12

602-

41D




SectionXXX-E

Page

DateEXXON

ENGINEERING

92 of 92

December, 1995


FIGURE 45TYPICAL X/R VALUES

��

��

��

��

��

��

��

�

��

��

��

��

�� 70

60

50

40

30

20

10

01000 2500 5000

Nameplate KVA

10000 15000

500 10001005010

3-Phase, FOA-Power Transformer MVA(Standard Impedance Limits)

(For OA and FA Ratings Apply the Proper Factor)Before Using Curve

521

2500020000

Typ

ical

X/R

ac

60

50

40

30

20

10

0

Typ

ical

X/R

ac

High

(A)

X/R Range for Small Generators and Sychronous Motors(Solid Rotor and Salient Pole)

Medium

Low

High

Medium

Low

Nameplate H P

100 250 500 1000 2500 5000 10,00050

50

40

30

20

10

0

Typ

ical

X/R

ac

HighMedium

Low

(B)

X/R Range for Power Transformers

(C)X/R Range for Three-Phase Induction Motors

10/95-12702-42D

Documents

DP30E