Protection & Control COP - Ch. 1 & 2

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1.0 INTRODUCTION 1. Background First TNB Transmission Protection and Control Code of Practice (COP) focused on transmission only. It was a reference for tender specification for substation construction. This reviewed document (Second Edition) simplifies basic practices from detailed requirements. It now covers protection and control policies for generation , transmission , and distribution sections of TNB. 2. Objective Standardize policies, schemes, and practices for protection, control, and supporting equipment across TNB's generation, transmission, and distribution systems. 3. Assumption Basic electrical engineering, protection, and control knowledge is required to understand this document. 4. References COP 1st Edition - March 1995 TEPCO Study Group No. 2: Technical Recommendations Conférence Internationale des Grands Reseaux Electriques (CIGRE) International Electrotechnical Commission (IEC) Institute of Electronics and Electrical Engineering (IEEE) British Standards Factory and Machinery Act (Safety, Health and Welfare Regulations 1970) 1.1 SUBSTATION SYSTEM OVERVIEW 1. Background Substations are vital nodes in high voltage systems. Transmission networks: transport high power over large distances using high voltage. Distribution networks: cover shorter distances with lower voltage. TNB transmission voltage levels: 500kV, 275kV, 132kV. TNB distribution voltage levels: 33kV, 22kV, 11kV. A substation typically consists of: Primary equipment Secondary equipment Auxiliary equipment 2. Definitions Terms Descriptions Substation Primary All equipment in service at the nominal voltage of the electrical power system. Two types based on insulating media: Air Insulated Switchgear (AIS) & Gas Insulated Switchgear (GIS). Examples: circuit breakers, disconnectors (isolators), current transformers, voltage transformers, surge arresters, power transformers, etc. Substation Secondary All equipment for control, protection, monitoring, and measurement of the primary system. Collects and processes information from primary equipment. Examples: protection systems, control systems, etc. Substation Auxiliary Systems required to enable primary and/or secondary equipment to operate. Examples: A.C. auxiliary supplies, D.C. auxiliary supplies, generator set, etc. 2.0 PROTECTION: GENERAL REQUIREMENT 1. Philosophy Protection system functions: Detect abnormal conditions and faults. Rapidly remove and selectively isolate faults to return the power system to normal. 2. Maximum Fault Clearing Time Main protection: Max time interval between fault inception and clearance. Max fault clearing times for Main protection: Type of Fault 11kV, 22kV and 33kV 132kV 275kV 500kV Substation & Transformer faults 150ms 150ms 100ms 100ms Overhead Line and Cable faults 600ms 150ms 130ms 130ms Backup protection: Max fault clearing time shall not exceed the short-circuit rating of the primary equipment. 2.1 Zone of Protection 1. Philosophy Zone of protection shall be overlapped. Each zone shall only trip its related circuit breakers. 2. Zone of Protection Typical protection zones: Generator, Transformer, Busbar, Overhead Line/Cable. 3. Concept of Overlapping Boundaries of protection zones determined by Current Transformer (CT) locations. CT locations shall form overlapping zones of protection. 2.2 Fault Clearing System 1. Philosophy Basic tasks of Fault Clearing System (FCS): Detect all specified power system faults and abnormalities. Isolate affected equipment to restore normal power system operation. 2. Basic Criteria Criteria for FCS design: Criteria Definition Dependable Degree of certainty that FCS will operate correctly. Reliable Degree of certainty that FCS will not fail to operate in event of faults. Secure Degree of certainty that FCS will not mal-operate. Selective Ability of protection to identify faulty section/phase(s) of a power system. Sensitive Minimum operating quantities available for FCS to detect abnormal condition. Fast FCS should operate as quickly as possible to minimize system disturbance. Simple FCS should use minimal hardware components and software logics. Economical Cost of FCS should commensurate with intended function. 3. General Protection Classification FCS protection equipment divided into two relaying classes: Relaying Class Functions and Characteristics Main Priority to initiate fault clearance or action to terminate abnormal conditions. Backup Operates when system fault is not cleared, or abnormal condition not detected, in required time due to failure of other protection or circuit breaker trip. For transmission network, Backup relays shall be separated from Main relays (multifunction Backup relays acceptable). For distribution network, integrated multifunction relay for Main and Backup functions is allowed. 4. Component Features Minimal features for FCS components: FCS Component Minimum Features Current Transformer Single primary core with multi-core secondary. Voltage Transformer Single primary winding with multi-winding secondary. Telecommunication Equipment Telecommunication channels path redundancy. Protection Equipment Single or Dual Main protection with Backup protection. DC System 1 Dual charger and dual battery bank system. DC System 2 Dual or single Modular switch-mode rectifier with n+1 redundancy system. Circuit Breaker Trip Coil 500kV and 275kV: dual trip coils per pole. 132kV: dual trip coils per circuit breaker. Distribution voltage levels: one trip coil per circuit breaker. Circuit Breaker Mechanism Hydraulic, pneumatic or spring mechanism. 2.3 Protection Relays 1. Policy All protection relays must satisfy requirements in sections 2.3 and 2.4. All relays must undergo and pass acceptance testing and be listed in the TNB Accepted Relay List. 2. General Requirement Relays suitable for operation on DC system (80% to 120% of nominal 110V DC or 30V DC) without voltage dropping devices. Relays stable and unaffected by DC supply issues (decay, surges, dips, ripples, spikes, chattering). Relays shall not give trip output on DC supply loss or restoration. Relays housed in dust and moisture-proof cases (IP51 per IEC 60529). Relays suitable for tropical climate duty. Relays insensitive to capacitive effect of control cable. Relays correctly rated to CT and VT secondary ratings. 3. Facilities Reset facilities (electrical or mechanical) available without opening relay front cover. All indicators clearly visible without opening relay front cover or panel door. 4. Relay Contacts Contacts suitably rated for tripping, control, and indication. Separate and sufficient contacts for tripping, control, and alarm functions. Minimal electrolysis effect. 5. Labels Relays (mounted or not) provided with clear labels including: Function (e.g., Distance, Overcurrent) Model and Version (e.g., REL561 V1.2) Serial number Nominal input ratings (DC voltage, AC voltage, AC current, AC frequency) 6. Operating and Reset Time Maximum pickup, operating, and reset times for protection relays: Voltage Level Protection Maximum Pickup Time Maximum Operating Time Maximum Reset Time 275kV and above Main Relay, Primary Elements 30 ms 30 ms Backup Relay, Primary Elements 50 ms 1 40 ms 70 ms 2 132kV Main Relay, Primary Elements 40 ms 40 ms Backup Relay, Primary Elements 50 ms 1 50 ms 100 ms 2 33kV and below Main Relay, Primary Elements 50 ms 1 50 ms 100 ms Backup Relay, Primary Elements 50 ms 1 50 ms 100 ms 1 Only applies if the element is IDMT Overcurrent or IDMT Earth Fault or Thermal Overload protection. 2 Except for Breaker Failure protection relays, which shall have maximum permitted reset time of 20ms. 7. Operating Characteristics Operating characteristics/principles of protection relays: Relaying Method Operating Principle Current Differential Vector Differential Current Comparison Phase Comparison Distance Quadrilateral with Directional Impedance Directional Earth Fault Comparison Current Operated together with Permissive signalling Breaker Failure Definite Time - Current Operated together with Start Initiation, with phase segregated measurement Overcurrent IDMT in accordance to IEC 60255-3 Definite Time Instantaneous Earth Fault IDMT in accordance to IEC 60255-3 Definite Time Instantaneous Directional Overcurrent IDMT in accordance to IEC 60255-3 Definite Time Instantaneous Standby Earth Fault Definite Time – Current Operated Biased Differential Circulating Current with restraint element High Impedance Differential Circulating Current with stabilising element Restricted Earth Fault Circulating Current with stabilising element High Impedance Busbar Differential Circulating Current with stabilising element Low Impedance Busbar Differential Vector Differential/Circulating Current with restraint element Overexcitation Inverse time base on Volt/Hz measurement Definite Time base on Volt/Hz measurement Overload Current dependant in accordance to IEC 60255-8 Arc Protection Light Detection with Definite Time Voltage Definite Time - Voltage Operated Instantaneous - Voltage Operated Rate of change - Voltage Operated Frequency Definite Time - Voltage Operated Instantaneous - Voltage Operated Rate of change - Voltage Operated Synchronism See section 5.2.1.2 New operating principles considered subject to proven performance and Transient Network Analysis (TNA) tests. 8. Control/Protection Relay Functionality Control/protection relays in TNB system shall have the following (not limited to): Control Relay Main Functionality Additional Functionality Autoreclose Single-pole autoreclose Three-pole autoreclose Single and Three-pole autoreclose Evolving fault logic 2-breakers controller Synchronism Voltage check Synchronism check Synchronism Fail output contact 9. Relay Functionality Main protection relays in TNB system shall have the following (not limited to): Main Protection Relay Main Functionality Additional Functionality Current Differential Current Differential Intertrip CT ratio correction factor Transfer Trip Overcurrent Autoreclose 5 Synchronism 5 Current Comparison Current Comparison Intertrip CT ratio correction factor Transfer Trip Overcurrent Autoreclose 5 Synchronism 5 Distance 3 forward zones 1 reverse zone DEFC protection scheme with Current Reversal and Echo functions (Separate communication channel from Distance) PSB SOTF VTS PUTT POTT Autoreclose 5 Synchronism 5 Pilot Wire Differential Differential element Overcurrent Check Intertrip Pilot Wire Supervision Biased Differential (Transformer) Biased Differential CT ratio correction factor Vector group correction factor Inrush Restrain Overexcitation Overvoltage High Impedance Differential Differential element Through Fault Stability Restraint Restricted Earth Fault Differential element Through Fault Stability Restraint High Impedance Busbar Differential Differential element Through Fault Stability Restraint Two-out-of-two operating zones CT Supervision Low Impedance Busbar Differential Two-out-of-two operating criteria CT ratio correction factor Self monitoring Voltage Undervoltage Overvoltage Individual four-stage of under/over voltage Overexcitation Individual two-stage Volt/Hz elements Dual Timers Frequency Underfrequency Overfrequency Individual four-stage of under/over voltage Rate of change of frequency Overcurrent Three-elements IDMT in accordance to IEC 60255-3 Definite Time Instantaneous Reverse Blocking Scheme TCS 6 Earth Fault IDMT in accordance to IEC 60255-3 Definite Time Instantaneous Reverse Blocking Scheme TCS 6 5 For 275kV and above systems, the autoreclose and synchronism functions shall be separated from the Main relays. 6 Trip Circuit Supervision for distribution voltage level. 10. Backup Relay Functionality Backup protection relays in TNB system shall have the following (not limited to): Backup Protection Relay Main Functionality Additional Functionality Distance 2 forward zones 1 reverse zone PSB VTS SOTF Thermal Overload Breaker Failure Dual Current Elements Dual Timers Intertrip Overcurrent and Undervoltage Overcurrent - Definite Time Undervoltage – Definite Time Overcurrent Three-elements IDMT in accordance to IEC 60255-3 Definite Time Instantaneous TCS 6 Earth Fault IDMT in accordance to IEC 60255-3 Definite Time Instantaneous TCS 6 Directional Overcurrent IDMT in accordance to IEC 60255-3 Instantaneous VTS Automatic reversion to Non-directional Overcurrent 8 Standby Earth Fault Individual two-stage Definite Time Instantaneous Thermal Overload Individual two-stage current dependant in accordance to IEC 60255-8 7 For Bus Separation scheme 8 In case of no polarising voltage 2.3.1 Static Relays 1. General All requirements for protection relays in section 2.3 also apply. 2. Storage and Interrogation Static relays must conserve settings, registered values, and operation indications for 168 hours upon DC power failure. 3. Requirement Static relays must satisfy specified standards: Requirement Standard Test Descriptions Electromagnetic Compatibility IEC 60255-22-1, Class III High frequency IEC 60255-22-2, Class III Electrostatic discharge IEC 60255-22-4, Class IV Fast transient disturbance Electrical Insulation IEC 60255-11 IEC 60255-5 High voltage test (except DC supply input) High voltage test (DC supply input only) Impulse voltage test (all circuits, Class III) Mechanical IEC 60068-2-6 Vibration IEC 60255-21-1, Class I Vibration during transport IEC 60255-21-1, Class II IEC 60255-21-2, Class I Shock during operation and transport 4. Quality Assurance Static relays must have a proven MTBF value of more than 70 years. Static relays must have at least 10 years availability of support and parts from purchase date. 2.3.2 Numerical Relays 1. General All requirements for protection relays in section 2.3 also apply. 2. Storage and Interrogation Numerical relays must conserve logics, equations, settings, registered values, events, oscillography, and operation indications for at least 168 hours upon DC power failure. Numerical relays must continuously track internal clock (time and date) upon DC power failure. Numerical relays must be interrogable via Human Machine Interface (HMI) built on relays. Numerical relays must be interfaced to SCS and conventional control systems via IEC 60870-5-103 protocol or hardwire connection (IEC 60870-5-103 interface dedicated and independent). Numerical relays must be interrogable via relay password security from local and remote computers via TCP/IP protocol (interface dedicated and independent). 3. Requirements Numerical relays must have continuous automatic internal self-supervision functions with indications for internal errors/failures (shall not affect protection functions during normal operation). Main Protection numerical relays must have event and oscillography recording functions. Backup Protection numerical relays must have at least event recording function. Relays with combined Main and Backup Protection must have event and oscillography recording functions. Numerical relays must satisfy specified standards: Requirement Standard Test Descriptions Electromagnetic Compatibility IEC 60255-22-1, Class III High frequency IEC 60255-22-2, Class III Electrostatic discharge IEC 60255-22-3, Class III Radio frequency electromagnetic field (non-modulated) IEC 60255-22-4, Class IV Fast transient disturbance IEC 60255-6 Power frequency magnetic field Electrical Insulation IEC 60255-11 IEC 60255-5 High voltage test (except DC voltage supply input) High voltage test (DC voltage supply input only) Impulse voltage test (all circuits, Class III) Mechanical IEC 60068-2-6 Vibration during operation IEC 60255-21-1, Class I IEC 60255-21-1, Class II Vibration during transport IEC 60255-21-2, Class I Shock during operation and transport 4. Pre-processing Isolation transformers inside numerical relays must perform to an accuracy of $\pm 1\%$ of input values. Effective sampling frequency must be in the range of 800 Hz to 4000 Hz. Analog-to-digital converters must not have conversion errors over $2\%$. 5. Settings Numerical relays must be able to interchange between a minimum of 2 group settings. Changes of relay settings must be authentically verified. 6. Internal Logics Configurable internal logics of numerical relays must be standardized per TNB practice and approved by Transmission Technical Committee. 7. Input and Output Contacts Adequate number of input and output contacts must be provided and configurable. Input and output contact configurations must be standardized per TNB practice and approved by Transmission Technical Committee. 8. Data Transmission Numerical relays using teleprotection signalling (e.g., Distance, Breaker Failure relays) must have permissive and direct intertrip schemes with 110V DC interface to teleprotection equipment (no external DC/DC converter). Numerical relays using teleprotection data channels (e.g., Current Differential, Current Comparison relays) must handle transmission delays not exceeding 15ms. Numerical relays using teleprotection data channels must use 64kbit/s co-directional complying with ITUT G.703 recommendations. Optical-to-electrical interface converter allowed to handle interferences between relay and communication equipment. 9. Quality Assurance Numerical relays must have proven MTBF value of more than 70 years. Numerical relays must have at least 10 years availability of support and parts from purchase date. 2.4 Descriptions and Requirements of Protection/Control Schemes and Functions 1. Policy All protection/control relays must follow schemes and functions described in section 2.4. 2. Distance Relay Schemes Distance relay permissive schemes (Underreach and Overreach) shall be incorporated. Definitions of Distance relay permissive schemes: Permissive Scheme Variation Descriptions Underreach Permissive Underreach Transfer Trip (PUTT) Zone 1: set to underreach, initiate carrier send. Zone 2 & 3: set to overreach. Zone 2 operation with carrier receive: accelerated/instantaneous trip. Trip Logic: $CS = ZM1$; $TRIP = ZM1.T1 + ZM2.CR + ZM2.T2 + ZM3.T3 + ZM3R.T3R$ Overreach Permissive Overreach Transfer Trip 1 (POTT1) Zone 1: set to overreach, initiate carrier send. Zone 2 & 3: set to overreach. Zone 1 operation with carrier receive: accelerated/instantaneous trip. Current reversal logic: avoid unwanted tripping for parallel feeders. Trip Logic: $CS = ZM1$; $TRIP = ZM1.CR + ZM2.T2 + ZM3.T3 + ZM3R.T3R$ Permissive Overreach Transfer Trip 2 (POTT2) Zone 1: set to underreach. Zone 2 & 3: set to overreach. Zone 2: initiate carrier send. Zone 2 operation with carrier receive: accelerated/instantaneous trip. Current reversal logic: avoid unwanted tripping for parallel feeders. Trip Logic: $CS = ZM2$; $TRIP = ZM1.T1 + ZM2.CR + ZM2.T2 + ZM3.T3 + ZM3R.T3R$ Legend: $ZM$ = Zone Measuring, $T$ = Timer, $CR$ = Carrier Receive, $CS$ = Carrier Send 3. Directional Earth Fault Comparison Protection Directional Earth Fault Comparison (DEFC) protection shall be incorporated in Main protection Distance relay using Permissive Overreach Transfer Trip scheme with current reversal logic. DEFC scheme shall have a built-in, independent, and selectable timer for tripping delay after fault detection and carrier reception. DEFC scheme shall be equipped with Echo logic for remote CB open-condition. DEFC scheme preferably equipped with Weak Infeed logic for no infeed or weak infeed conditions. Carrier contacts and channels for Distance and DEFC protection shall be separated. 4. Switch On To Fault Switch On To Fault (SOTF) function shall be in all Distance relays using impedance-based measurement. SOTF coverage from relaying point to selectable Distance relay zones (preferably Zone 2 Forward and Zone 3 Reverse) with instantaneous tripping. SOTF function initiated only after CB opening, with a short time delay. SOTF function deactivated after CB closure, after a sensible period. For each feeder, only one SOTF function activated, preferably in Backup Distance protection relay. 5. Power Swing Blocking Power Swing Blocking (PSB) function shall be in Distance relay using impedance-based measurement. Distance relay blocked by PSB function from any operation when power swing condition detected. PSB function blocked during dead time of 1-pole autoreclose cycle. 6. Voltage Transformer Supervision Voltage Transformer Supervision (VTS) function shall be in Distance relay and Directional Overcurrent relay. Entire Distance relay (including DEFC function) blocked by VTS function from any operation when internal VTS triggers, except during fault conditions. Directional Overcurrent relay adaptively changes from Directional to Non-directional Overcurrent protection via VTS function when internal VTS triggers. VTS function shall not issue any tripping command. 7. Evolving Fault Logic Evolving Fault Logic (EVFL) function shall be in the autoreclose relay. Evolving fault classified as fault occurring after clearance of first-detected fault and during dead time of first-detected fault. EVFL shall initiate changes from 1-pole to 3-pole autoreclose cycle if evolving fault detected by Main protection relays, and reclose after 3-pole autoreclose dead time elapses. 8. Inrush Restrain Inrush Restrain (or Inrush Current Restrain Logic) shall be in transformer Biased Differential relay, and preferably in Current Differential and Current Comparison relays. Inrush Restrain shall have an option to block relay from tripping during inrush current conditions (e.g., during switch-on of transformer/line/cable or paralleling). 9. Transformer Restricted Earth Fault Transformer Restricted Earth Fault (REF) protection scheme shall protect at least $90\%$ of intended transformer winding. Transformer REF protection relay shall be ranked as Main protection and be independent of other relays.