{"id":3685,"date":"2026-04-13T05:30:45","date_gmt":"2026-04-13T05:30:45","guid":{"rendered":"https:\/\/xbrele.com\/?p=3685"},"modified":"2026-04-13T05:35:09","modified_gmt":"2026-04-13T05:35:09","slug":"relay-trip-logic-map-for-mv-panels-50-51-50n-51n-27-59-86-how-they-inter","status":"publish","type":"post","link":"https:\/\/xbrele.com\/de\/relay-trip-logic-map-for-mv-panels-50-51-50n-51n-27-59-86-how-they-inter\/","title":{"rendered":"Relaisausl\u00f6selogik f\u00fcr MV-Panels: 50\/51\/50N\/51N\/27\/59\/86 - Wie sie verriegeln"},"content":{"rendered":"

A Comprehensive Technical Guide to Protective Relay Coordination and Interlocking Schemes<\/h2>\n
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Introduction<\/h2>\n

In medium voltage (MV) electrical distribution systems, protective relays serve as the critical first line of defense against electrical faults, equipment damage, and personnel hazards. Understanding how these relays interlock and communicate through trip logic maps is fundamental to designing, commissioning, and maintaining reliable power systems.<\/p>\n

Over my 18 years of experience commissioning MV switchgear across petrochemical plants, data centers, and utility substations, I’ve witnessed firsthand how poorly coordinated relay schemes can cascade into catastrophic failures. Conversely, properly designed trip logic maps have saved millions of dollars in equipment and, more importantly, prevented injuries.<\/p>\n

This article provides an in-depth examination of the most common protective relay functions\u2014ANSI device numbers 50, 51, 50N, 51N, 27, 59, and 86\u2014and explains how they interlock within MV panel architectures. Whether you’re a protection engineer designing new systems or a field technician troubleshooting existing installations, this guide will serve as a practical reference for understanding relay trip logic coordination.<\/p>\n

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Section 1: Understanding ANSI Device Numbers and Their Functions<\/h2>\n

Before diving into interlock schemes, we must establish a clear understanding of each relay function. The ANSI\/IEEE C37.2 standard defines device numbers that have become the universal language of protection engineering.<\/p>\n

Overcurrent Protection (50\/51)<\/h3>\n

Device 50 (Instantaneous Overcurrent)<\/strong> operates without intentional time delay when current exceeds a predetermined threshold. Typical pickup settings range from 6 to 10 times the full-load current for transformer protection and 1.5 to 2 times for motor applications. The instantaneous element provides high-speed fault clearing for close-in faults where damage potential is greatest.<\/p>\n

Device 51 (Time Overcurrent)<\/strong> introduces an inverse time-current characteristic, allowing downstream devices to clear faults before upstream relays operate. This coordination is achieved through standardized curves (IEC extremely inverse, very inverse, standard inverse, or IEEE moderately inverse, very inverse, extremely inverse).<\/p>\n

Ground Fault Protection (50N\/51N)<\/h3>\n

Device 50N (Instantaneous Ground Overcurrent)<\/strong> detects ground faults through residual current measurement. In solidly grounded systems, pickup settings typically range from 10-20% of phase CT rating. For resistance-grounded systems, settings must coordinate with the maximum let-through current of the neutral grounding resistor.<\/p>\n

Device 51N (Time Overcurrent Ground)<\/strong> provides time-coordinated ground fault protection, essential in systems where selective coordination between multiple ground fault devices is required.<\/p>\n

Voltage Protection (27\/59)<\/h3>\n

Device 27 (Undervoltage)<\/strong> protects against voltage sags and loss of supply, typically set between 80-90% of nominal voltage with time delays of 1-10 seconds depending on application. This function is critical for motor protection and preventing automatic restart under degraded conditions.<\/p>\n

Device 59 (Overvoltage)<\/strong> guards against sustained overvoltage conditions that can damage insulation and connected equipment. Settings typically range from 110-120% of nominal voltage.<\/p>\n

Lockout Relay (86)<\/h3>\n

Device 86 (Lockout Relay)<\/strong> is an electrically operated, hand-reset device that maintains circuit breakers in their tripped position until an operator manually acknowledges the fault condition. This function is fundamental to ensuring faults are investigated before re-energization.<\/p>\n

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Section 2: Trip Logic Architecture in MV Panels<\/h2>\n

The trip logic map defines how protective relay outputs connect to circuit breaker trip coils, lockout relays, and auxiliary systems. Modern MV panels employ three primary trip architectures:<\/p>\n

Direct Trip Configuration<\/h3>\n

In simple applications, individual relay trip contacts wire directly to the circuit breaker trip coil. While economical, this approach lacks the benefits of consolidated fault indication and requires separate auxiliary contacts for each relay to block automatic reclosing.<\/p>\n

Lockout Relay Mediated Trip<\/h3>\n

More sophisticated schemes route all protective relay outputs through an 86 lockout relay. This configuration offers several advantages:<\/p>\n

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  • Single point of trip coil supervision<\/li>\n
  • Consolidated flag indication<\/li>\n
  • Inherent block of automatic reclosing<\/li>\n
  • Clear operator interface for fault acknowledgment<\/li>\n<\/ul>\n

    Multi-Function Relay Internal Logic<\/h3>\n

    Modern numerical relays implement trip logic internally through programmable logic gates. The relay’s output contacts can be configured to represent individual protection elements or combined trip functions.<\/p>\n

    [Figure 1: Trip Logic Block Diagram showing interconnection between 50\/51, 50N\/51N, 27, 59 elements feeding into 86 lockout relay with parallel paths to breaker trip coil, status indication, and SCADA\/DCS interfaces]<\/strong><\/p>\n

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    Section 3: Interlock Schemes Between Protection Functions<\/h2>\n

    The interaction between protective functions follows established principles that ensure both dependability (operating when required) and security (not operating falsely).<\/p>\n

    Overcurrent and Ground Fault Coordination<\/h3>\n

    The 50\/51 and 50N\/51N functions must coordinate in time and magnitude. Consider a typical configuration:<\/p>\n

    For a 2000A MV feeder with 2000:5 CTs:
    \n– 51 pickup: 1.2 \u00d7 FLA = 2400A (6A secondary)
    \n– 51 time dial: 0.5 on very inverse curve
    \n– 50 pickup: 8 \u00d7 FLA = 16,000A (40A secondary)
    \n– 51N pickup: 0.5A secondary (200A primary, 10% CT rating)
    \n– 51N time dial: 0.3 on very inverse curve
    \n– 50N pickup: 2A secondary (800A primary)<\/p>\n

    The ground fault elements are set more sensitively because ground faults typically involve lower magnitudes than phase faults, yet they’re equally dangerous.<\/p>\n

    Voltage and Overcurrent Interlock Logic<\/h3>\n

    Undervoltage (27) and overvoltage (59) protection often interlock with overcurrent functions to enhance scheme security:<\/p>\n

    Voltage Restraint Overcurrent (51V)<\/strong> reduces pickup threshold as voltage decreases, improving sensitivity to remote faults where voltage depression is significant but current increase is modest.<\/p>\n

    Voltage-Controlled Overcurrent<\/strong> enables the overcurrent element only when voltage drops below a threshold, providing backup protection for generator applications.<\/p>\n

    Lockout Relay Integration<\/h3>\n

    The 86 device receives inputs from all protection functions and provides outputs to:
    \n– Primary trip coil (52a path)
    \n– Backup trip coil (if equipped)
    \n– Close circuit blocking contact (52Y)
    \n– SCADA\/DCS alarm
    \n– Local annunciation<\/p>\n

    [Figure 2: Detailed 86 Lockout Relay Wiring Diagram showing multiple input contacts (50, 51, 50N, 51N, 27, 59), output contacts to trip coil, close blocking, and indication circuits, with target flag mechanism]<\/strong><\/p>\n

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    Section 4: Time Coordination and Selectivity Principles<\/h2>\n

    Achieving selective coordination requires systematic analysis of time-current characteristics across the protection system.<\/p>\n

    Coordination Time Intervals<\/h3>\n

    The minimum coordination time interval (CTI) between upstream and downstream devices must account for:
    \n– Breaker clearing time (typically 3-5 cycles for MV breakers)
    \n– Relay overtravel (2-4 cycles for electromechanical, negligible for numerical)
    \n– Safety margin (5-10 cycles)<\/p>\n

    Industry practice establishes CTI of 0.2-0.4 seconds between successive devices. The formula is:<\/p>\n

    CTI = Breaker Time + Relay Overtravel + Safety Margin<\/strong><\/p>\n

    For modern numerical relay and vacuum breaker combinations:
    \nCTI = 0.08s + 0.00s + 0.12s = 0.20s minimum<\/p>\n

    Instantaneous Overcurrent Coordination<\/h3>\n

    The 50 function presents coordination challenges because it operates without intentional time delay. Two approaches ensure selectivity:<\/p>\n

    Zone Selective Interlocking (ZSI):<\/strong> Downstream relays send blocking signals to upstream devices when they detect faults in their zone. The upstream relay delays operation for a short interval (typically 50-100ms) unless it receives no blocking signal, indicating a bus fault.<\/p>\n

    Instantaneous Pickup Coordination:<\/strong> Set the upstream 50 element above the maximum let-through current of the downstream device, ensuring only downstream faults cause upstream 50 operation.<\/p>\n

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    Section 5: Field Application Examples<\/h2>\n

    Example 1: Industrial Plant 13.8kV Feeder<\/h3>\n

    A manufacturing facility’s 13.8kV feeder supplies a 3000kVA transformer. The protection scheme includes:<\/p>\n

    Primary Protection:<\/strong>
    \n– 51: Pickup 125A, Very Inverse, TD 3.0
    \n– 50: Pickup 4000A (2\u00d7 transformer inrush)
    \n– 51N: Pickup 15A, Very Inverse, TD 2.0
    \n– 50N: Pickup 200A<\/p>\n

    Interlocking:<\/strong>
    \nAll elements trip through 86T (transformer lockout), which trips the 13.8kV feeder breaker and blocks the 480V secondary main. The 27 element (set at 85%, 2.0s delay) trips the 480V secondary main independently to prevent motor stalling during voltage sags.<\/p>\n

    Example 2: Utility Substation Bus Tie<\/h3>\n

    A 34.5kV bus tie breaker protects against bus faults and provides backup protection:<\/p>\n

    Zone Selective Interlock Implementation:<\/strong>
    \n– Feeder relays send ZSI blocking signals to bus tie relay
    \n– Bus tie 51: Pickup 2000A, Very Inverse, TD 5.0
    \n– Bus tie 50: Pickup 8000A, delayed 100ms without ZSI block
    \n– Bus tie 50N: Pickup 400A, delayed 100ms without ZSI block<\/p>\n

    When a feeder fault occurs, the feeder relay sends a blocking signal while operating to clear the fault. If no blocking signal exists (bus fault), the bus tie trips instantaneously.<\/p>\n

    [Figure 3: Zone Selective Interlocking Scheme showing communication paths between feeder relays and bus tie relay, with timing diagrams illustrating coordinated operation for both feeder and bus faults]<\/strong><\/p>\n

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    Section 6: Testing and Commissioning Procedures<\/h2>\n

    Proper commissioning validates that the trip logic map functions as designed.<\/p>\n

    Functional Testing Protocol<\/h3>\n
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    1. Individual Element Verification:<\/strong> Inject test currents\/voltages to verify each element operates at designed pickup and time.<\/li>\n
    2. Trip Path Verification:<\/strong> Trace each relay output through the logic to the breaker trip coil, verifying continuity and correct operation.<\/li>\n
    3. Interlock Testing:<\/strong> Simulate fault conditions to verify ZSI blocking, voltage restraint functions, and lockout relay operation.<\/li>\n
    4. Target Reset Verification:<\/strong> Confirm 86 device requires manual reset and properly blocks breaker closing.<\/li>\n<\/ol>\n

      Common Commissioning Issues<\/h3>\n

      From field experience, the most frequent problems include:<\/p>\n