Cheatsheet: Protection Systems

1. Protection System Fundamentals

1.1 Basic Definitions

1.2 Protection System Requirements

• Reliability: Must operate when required and avoid false trips
• Selectivity: Isolate only faulted section, minimize outage area
• Speed: Fast operation to minimize equipment damage and maintain stability
• Sensitivity: Detect minimum fault current within zone of protection
• Dependability: Operate for all faults within protected zone
• Security: Avoid operation for faults outside protected zone

1.3 CT and PT Specifications

2. Overcurrent Protection

2.1 Overcurrent Relay Types

2.2 Inverse Time Characteristics

Where: t = operating time (s), TD = time dial setting, I = fault current, Ip = pickup current

2.3 Coordination Principles

• Coordination Time Interval (CTI): 0.2-0.4s for electromechanical, 0.1-0.3s for electronic relays
• Instantaneous vs Time Overcurrent: Set instantaneous at 150-200% of maximum through fault
• Pickup Setting: 125-150% of maximum load current for phase relays
• Ground Relay Pickup: 10-40% of phase CT rating for solidly grounded systems
• Fuse-Relay Coordination: Minimum 0.2s separation; use fuse minimum melt vs relay curve

3. Distance Protection

3.1 Distance Relay Fundamentals

3.2 Distance Relay Types

3.3 Distance Relay Settings

• Zone 1 Reach: 0.8-0.9 × ZL (line impedance)
• Zone 2 Reach: 1.2 × ZL + 0.5 × ZL2 (shortest adjacent line)
• Zone 3 Reach: 1.2 × (ZL + ZL2)
• Load Impedance Check: Zload_min = Vmin² / (√3 × Pmax); relay reach must be < 0.5="" ×="">
• Power Swing Blocking: Required when Zswing enters relay characteristic; uses rate of impedance change

3.4 Impedance Calculations

4. Differential Protection

4.1 Differential Protection Principles

4.2 Transformer Differential (87T)

4.3 Generator Differential (87G)

• CT Location: Neutral CT and terminal CT; must have identical ratios
• Minimum Pickup: 0.2-0.5 pu on generator base; lower for large units
• Slope: 10-25% for low resistance grounded; 25-40% for high resistance grounded
• Stator Ground Fault: Separate 100% stator ground (87GN) using voltage or 3rd harmonic method
• Coordination: Must be faster than backup impedance relay (21); instantaneous operation

4.4 Bus Differential (87B)

4.5 Line Differential (87L)

• Pilot Wire: Uses communication channel; fiber optic or digital communication preferred
• Phase Comparison: Compares phase angle of currents at terminals; trip if out of phase
• Current Differential: Digital comparison of current magnitudes and angles; GPS time sync
• Slope Settings: 15-50% depending on line length and CT errors; dual or triple slope
• Communication Delay: Must account for channel delay (typically <10ms for="">

5. Ground Fault Protection

5.1 Grounding System Types

5.2 Residual and Neutral Protection

5.3 Ground Fault Settings

• Solidly Grounded Pickup: 0.1-0.4 × phase CT rating; coordinate with maximum unbalance
• Low Resistance Grounded: 50-70% of resistor current rating; definite time 0.5-1.0s
• High Resistance Grounded: 10-30% of resistor current; pulsing type alerts operator
• SEL Pickup: ≥ 1.5 × maximum unbalance current, ≥ 2 × CT error
• Time Delay: 0.1-0.5s for selectivity; instantaneous if coordination permits

5.4 Restricted Earth Fault (REF/64)

6. Pilot Protection Schemes

6.1 Pilot Scheme Types

6.2 Communication Channels

6.3 Pilot Scheme Settings

• Zone 2 Reach for POTT: 120-150% protected line + 50% adjacent line (minimum)
• Zone 1 Reach: 85-90% of protected line; instantaneous with no communication delay
• Communication Delay: 8-15ms for PLC, 4-8ms for microwave, <5ms for="">
• Carrier Check: Monitors channel; blocks trip if channel fails (security)
• Echo Logic: Confirms received signal matches sent signal; added security

7. Generator Protection

7.1 Generator Protection Functions

7.2 Loss of Field Protection (40)

7.3 Negative Sequence Protection (46)

I2²t Calculation: Thermal limit based on rotor heating

• K Constant: I2²t = K where K = 5-40 for large turbine generators, K = 10-60 for hydro
• Continuous I2 Limit: 5-10% of rated current for turbine generators, 15-25% for hydro
• Alarm Setting: 50-60% of trip setting; warn before trip
• Calculation: I2 = (Ia² + Ib² + Ic² - (Ia+Ib+Ic)²/3)^0.5 / 3
• Time Curve: Inverse time characteristic; t = K/I2² seconds

7.4 Stator Ground Fault Protection

8. Transformer Protection

8.1 Transformer Protection Scheme

8.2 Transformer Differential Settings (87T)

8.3 Inrush Current Characteristics

• Peak Magnitude: 8-15× rated current for large power transformers
• Duration: Decays from seconds to minutes; primarily 2nd harmonic initially
• Harmonic Content: 2nd harmonic 30-70% of fundamental during inrush
• Sympathetic Inrush: Occurs in parallel transformers when one is energized
• Recovery Inrush: After fault clearing; may be 3-5× rated current

8.4 Thermal Protection (49)

9. Motor Protection

9.1 Motor Protection Functions

9.2 Thermal Overload Settings (49)

9.3 Starting and Locked Rotor Protection

• Starting Current: 5-7× FLA for across-the-line starting; 2-4× for reduced voltage
• Starting Time: 5-15 seconds typical; depends on load inertia
• Locked Rotor Current: 5.5-6.5× FLA at rated voltage (Code G-V)
• 51LR Pickup: 1.5-2.5× FLA; operates if motor fails to accelerate
• 51LR Time Delay: 10-30s; must exceed maximum starting time by 20-30%
• Safe Restarts: 2 starts cold, 1 start hot within 1 hour (general rule)

9.4 Motor Short Circuit Protection

10. Bus Protection

10.1 Bus Protection Schemes

10.2 High Impedance Differential

10.3 Low Impedance Differential

• Operating Current: Iop = |ΣI| (vector sum of all CT currents)
• Restraint Current: Ires = max(|I1|, |I2|, ..., |In|) or (|I1| + |I2| + ... + |In|) / n
• Minimum Pickup: 0.2-0.5A secondary; primary consideration is CT error
• Slope 1: 10-30% for normal through current range
• Slope 2: 50-80% for high through-fault CT saturation region
• Unrestrained Instantaneous: 8-10× maximum load; operates without restraint
• Operating Time: <30ms including="" breaker="" failure="">

10.4 Breaker Failure Protection (50BF)

11. Special Protection Schemes

11.1 Reclosing (79)

11.2 Sync Check Relay (25)

11.3 Underfrequency Load Shedding (81U)

• Purpose: Restore generation/load balance during frequency decay; prevent system collapse
• Typical Stages: 59.5 Hz (10% load), 59.0 Hz (10%), 58.7 Hz (15%), 58.5 Hz (15%)
• Time Delays: 0.1-1.0s per stage; prevents nuisance tripping for momentary swings
• Rate of Change: df/dt supervision optional; -0.5 to -1.0 Hz/s indicates severe deficit
• Restoration: Manual or automatic after frequency recovers to >59.8 Hz for 5 min
• Load Selection: Non-essential loads first; avoid critical infrastructure

11.4 Overvoltage/Undervoltage Protection

11.5 Frequency Relay Applications

12. Relay Coordination Principles

12.1 Coordination Time Intervals

12.2 Coordination Study Steps

• 1. One-Line Diagram: Complete with all protective devices, ratings, impedances
• 2. Fault Study: Calculate maximum and minimum fault currents at all buses
• 3. Device Selection: Choose relay types, curves, CT/PT ratios
• 4. Starting Point: Begin at load end (furthest downstream device)
• 5. Work Upstream: Each upstream device must coordinate with downstream
• 6. Check Instantaneous: Set at 150-200% of maximum through fault current
• 7. Plot Curves: Verify CTI on time-current curve (TCC) plot
• 8. Sensitivity Check: Verify operation for minimum fault current

12.3 Common Coordination Issues

12.4 Relay Setting Calculations

13. ANSI Device Numbers

13.1 Common Device Functions

13.2 Suffix Letters