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Fundamentals of Microprocessor-based Relaying
- 1. Fundamentals of Microprocessor Based Protective Relays Suhag Patel, P.E. Industrial Electric Machinery Carson, CA IEEE Industrial & Commercial Power Systems Conference Newport Beach, CA May 5, 2011
- 2. Objective • Understand Commonly Used Protective Functions and Their ANSI Protective Device Numbers • Understand Protection is Based on Power System Component • Advantages of Grouping Protective Relay Functions in a Microprocessor Relay
- 3. ANSI Function Number • Used to Easily Convey Information on Electrical Drawings • Function Will Have a Number and Sometimes letter(s) • Examples: – 50N – 67P
- 5. Feeder Protection • The Following ANSI Device Numbers Are Used for Feeder Protection: – 50 – Instantaneous Overcurrent – 51 – Time Overcurrent – 67 – Directional Overcurrent – 79 – Reclosing Relay – 81O/U – Under/Over Frequency – 25 – Synchronism Check
- 6. Interrupting Methods • Fuse Fusible element melts to disconnect faulty zone/equipment I2T law • Recloser Single or three-phase, 15 to 38kV Line or substation • Circuit Breaker • Indoor switchgear • Outdoor breaker or switchgear • Air, Oil, SF6, Vacuum, Magnetic blast
- 8. 50 – Instantaneous OC Instantaneous Overcurrent (function 50) • The instantaneous overcurrent protective element operates with no intentional time delay when the current has exceeded the relay setting • There is a pickup setting. • 50P – phase inst. overcurrent. Pickup usually set at 25% higher than the maximum current seen by the relay for a three-phase fault at the end of the circuit. • 50N – neutral inst. overcurrent (The phasor summation of phase currents Ia, Ib, Ic equals In) • 50G – ground inst. overcurrent – low pickup setting (Uses separate or zero sequence CT)
- 10. 138 kV 52 M R 52 1 R 52 2 R 52 3 R R 52 U F-1 12.5 kV 480v • We Desire Selectivity, therefore Instantaneous Protection Alone is not Sufficient • Definite Time does not Replicate Real Equipment Damage Curves 50 – Instantaneous OC
- 12. 51 – Time Overcurrent • Where it is desired to have more time delay before the element operates for the purpose of coordinating with other protective relays or devices, the time overcurrent protective element is used. The trip time varies inversely with current magnitude. • Characteristic curves most commonly used are called “inverse,””very inverse,” and “extremely inverse.” The user must select the curve type. They are said to be a family of curves and selected by the time dial. • Curve type and time dial are separate settings. Time dial adjusts the time delay of the characteristic to achieve coordination between downstream and upstream overcurrent devices. • There is a minimum pickup setting. The pickup setting should be chosen such that the protective device will be operating on the most inverse part of its time curve over the range of current for which must operate. • 51P – phase time overcurrent • 51N – neutral time overcurrent (The phasor summation of phase currents Ia, Ib, Ic equals In) • 51G – ground time overcurrent ‐ low pickup setting (uses separate or zero sequence CT)
- 14. 51 – Time Dial
- 15. 51 – The Coordination Problem 138 kV 52 M R 52 1 R 52 2 R 52 3 R R 52 U F-1 12.5 kV 480v F1 F3 F2 F4 Fault magnitude • F4 > F3 > F2 > F1 Why? • Impedance
- 16. 51 – Coordinating Time CURRENT TIME F1 F2 F3 F4PICKUP PICKUP TIME COORDINATION INTERVAL Main Feeder Relay Feeder 3 Relay
- 17. 51 ‐ Fuses • The time verses current characteristics of a fuse has two curves. • The first curve is called the minimum melt curve • The minimum melt curve is the time between the initiation of a current large enough to cause the fusible element(s) to melt and the instant when arcing occurs. • The second curve is called the total clearing time. • The total clearing time is the total time elapsing from the beginning of an overcurrent to the final circuit interruption. • The time current characteristic curve of a fuse follows a I2T characteristic - that is to say as the current goes up, the time drops by the square of the current increase. Total clearing time curve Minimum melt Current Time
- 18. 51 – Coordinating Fuses Load Primary Secondary LoadSecondary 2I 1I 1I Time Current • The operating time of a fuse is a function of the pre-arcing (melting) and arcing time • For proper coordination, total I2T of secondary fuse shouldn’t exceed the pre-arcing (melting) of primary fuse. This is established if current ratio of primary vs. secondary fuse current rating is 2 or greater for fuses of the same type.
- 19. 51 – Coordinating Fuses & Relays Current Time Minimum TCI time of 0.4s Time Over Current Curve Fuse curve • The time overcurrent relay should back up the fuse over full current range. The time overcurrent relay characteristic curve best suited for coordination with fuses is the Extremely Inverse, which is similar to the I2t fuse curves. For Extremely Inverse relay curves, primary pickup current setting should be 3-times fuse rating. For other relay curves, up to 4- times fuse rating should be considered. Ensure no cross over of fuse or time overcurrent relay curves. • To account for CT saturation and errors, electro-mechanical relay overshoot, timing errors and fuse errors a minimum TCI of 0.4s should be used.
- 20. 51 – Coordinating Relays • The following is recommended TCI to ensure proper coordination. 0 1000 2000 3000 4000 0 0.5 1 1.5 2 2.5 3 Fault current at 11 kV Timetooperate(s) 0.4 s between relay and fuse 0.3 s between digital relays
- 21. 51 – Reset Curves • Reset of Time Overcurrent Element • There are (2) different types of resets within Time Overcurrent Protection: • EM or Timed Delay Reset – this mimics the disc travel of an electromechanical relay moving back to the reset position. • If the disc has not yet completely traveled back to the reset position and the time overcurrent element picks up again, the trip time will be shorter. • If the current picks up and then dropouts many times, the disc will “ratchet” itself to the operate position. • Be careful when coordinating with upstream or downstream devices. • Instantaneous Reset – once the time overcurrent element operates, it will reset immediately
- 23. 67 – Directional Overcurrent • In Loop‐Fed Systems, it is Desirable to Have Different Trip Times for Forward and Reverse Faults • 50/51 Is Not Sufficient 1 5 2 4 3 A B E D C c e d a b L L L L Bus X Bus Y
- 24. 67 – How it Works (a) To determine the direction of current we need a reference voltage or current that will not change direction during the fault. To determine the direction of current in phase A we will use Vbc. Digital relays allow an offset from the reference voltage or current to provide better protection. (b) The protection engineer must look back into the system from the fault and determine the current fault angle (in this case a 600 lagging in current from phase Van is determined the typical fault angle).
- 25. 67 – Transmission Line Angle • Conductors (Trans. Line) mostly inductive. • Load is heavily resistive. Rload Xline Rload >> Xline
- 26. 67 – Transmission Line Angle • Normal Current lags Voltage by small amount • Fault Current lags Voltage by large amount. V I V I
- 27. 67 –V & I During 3Ø Forward Directional Fault • Prefault, Balanced Voltages and Currents • Fault, Balanced Voltages and Currents, but magnitude is much different. Va Vb Vc Ia Ic Ib
- 28. 67 –V & I During 3Ø Reverse Directional Fault • Prefault, Balanced Voltages and Currents • Fault, Balanced Voltages and Currents, but magnitude is much different. Va Vb Vc Ia Ic Ib Va Vb Vc Ia Ic Ib
- 29. 67 – Electromechanical Directional Characteristic Va Vb Vc Ia Ic Ib VabVca Vbc Va 3Ø forward fault at 60 degree line angle Vbc Restraint Region Ia Maximum Torque Line Zero Torque Line
- 31. 79 – Reclosing Relay • Not all Faults Are Permanent – Most Industrial Facilities Use Insulated Cable, Which Results in Permanent Faults – Utilities Often Use Non‐Insulated Overhead Conductors, Resulting in Many Temporary Faults: • Wind Causing Conductors to Touch • Fires Temporarily Breaking Down Air
- 32. 79 – Reclosing Relay • Automatically reclose a circuit breaker or recloser which has been tripped by protective relaying or recloser control • Multi‐shot reclosing for distribution circuits • Instantaneous shot (~0.25s) • Delayed reclosures (typically two delayed , for example 3s & 15s, or 15s & 30s) • Coordinate with branch fuses • After initial reclose block instantaneous overcurrent functions to allow fuse to blow • After successful reclose, the reclosing function will reset after some adjustable time delay (typically 60s). • If the fault is permanent, the protective device will trip and reclose several times. If unsuccessful, the protective device will go to LOCKOUT and keep the breaker open. Some devices have a separate reset time from lockout (for example 10s after the breaker is manually closed).
- 33. 79 – Reclosing & Fuses 52 R • Two methods: • Fuse blowing • Fuse blows for any fault, including temporary fault • Fuse saving • Use automatic reclosing to try and save fuses for temporary faults
- 34. 79 – Fuse Blowing CURRENT TIME FAULT TCI > 0.4s typical Fuse Feeder Relay
- 35. 79 – Fuse Saving CURRENT TIME FAULT TCI > 0.4s typical Feeder Relay Inst active on first reclose shot only Fuse INST PICKUP Inverse time only after first reclose shot
- 36. 81U – Frequency Protection • Often Applied to Feeder for Load Shedding Purposes – If system frequency is collapsing, this indicates a load‐generation imbalance. – Some feeders are designed to trip offline after frequency decays beyond a specific level, i.e. 59.8 Hz with 2S delay and 59.5 Hz no time delay
- 37. 81O – Frequency Protection • Often Applied to Feeder for Automatic Load Restoration after Load Shed Event – Once Frequency is above nominal for some time, feeder breaker is closed, restoring service back to load • Frequency Elements typically work by measuring Zero Crossings of Voltage/Current
- 38. 25 – Synchronism Check • Synchronism check function is intended for supervising the paralleling or connection of two parts of a system which are to be joined by the closure of a circuit breaker. • Synchrocheck verifies that voltages (V1 and V2) on the two sides of the supervised circuit breaker are within set limits of magnitude, angle and frequency differences. • V1 is typically acquired using 2 or 3 potential transformers • V2 is typically a signal phase potential transformer measuring a phase‐to‐phase voltage, such as Vab or Vbc G Industrial Utility
- 39. • Phase instantaneous and time-delayed overcurrent is used. • Ground instantaneous overcurrent is used. • Optionally, ground time- delayed overcurrent is used Typical Industrial Feeder CB
- 40. Typical Utility Feeder CB • Phase and ground overcurrent protection with multi-shot reclosing relay is used. • Both instantaneous and time-delayed overcurrent are used. • Reclosing is Often Included for Overhead Lines 79
- 43. Motor Protection • The Following ANSI Device Numbers Are Used for Motor Protection: – 50 – Instantaneous Overcurrent – 87M – Machine Differential – 49 – Thermal Protection – 46 – Current Unbalance Protection – 27/59 – Under/Over Voltage – 37 – Undercurrent – 66 – Jogging
- 44. 50 – Short Circuit Protection • The short circuit element provides protection for excessively high overcurrent faults • Phase-to-phase and phase-to-ground faults are common types of short circuits • To avoid nuisance tripping during starting, set the the short circuit protection pick up to a value at least 1.7 times the maximum expected symmetrical starting current of motor. • The breaker or contactor must have an interrupting capacity equal to or greater then the maximum available fault current or let an upstream protective device interrupt fault current.
- 45. 87 – Differential Protection • If sufficient margin between starting current and short circuit value doesn’t exist, differential protection is required. • Core Balance CT Connection Is Preferred
- 47. 50G – Ground Fault Protection • Many Industrial Plants use High Resistance Ground Schemes • Need sensitivity, should use Zero Sequence CT
- 48. 50G – Ground Fault Protection • Not always possible to use Zero Sequence CT • Use Residual Connection • Acceptable for Solidly Grounded System, requires delay for HRG Scheme
- 49. 49 – Thermal Protection • Different then typical overcurrent characteristic. • Takes into account cooling characteristics of the motor. • Can also use physically measured temperatures (RTD) • Very sophisticated, primary element that makes a motor relay a motor relay
- 50. A motor can run overloaded without a fault in motor or supply A primary motor protective element of the motor protection relay is the thermal overload element and this is accomplished through motor thermal image modeling. This model must account for thermal process in the motor while motor is starting, running at normal load, running overloaded and stopped. Algorithm of the thermal model integrates both stator and rotor heating into a single model. • Main Factors and Elements Comprising the Thermal Model are: • Overload Pickup Level • Overload Curve • Running & Stopped Cooling Time Constants • Hot/Cold Stall Time Ratio • RTD & Unbalance Biasing • Motor State Machine 49 – Overload Protection
- 51. 49 - Motor Thermal Limit Curves Thermal Limit Curves: B. Hot Running Overload B A. Cold Running Overload A D. Hot Locked Rotor CurveD C C. Cold Locked Rotor Curve F. Acceleration curve @100% voltage F E. Acceleration curve @ 80% rated voltageE • Thermal Limit of the model is dictated by overload curve constructed in the motor protection device in the reference to thermal damage curves normally supplied by motor manufacturer. • Motor protection device is equipped with set of standard curves and capable to construct customized curves for any motor application.
- 52. 49 - Thermal Overload Pickup • Set to the maximum allowed by the service factor of the motor. • Set slightly above the motor service factor by 8-10% to account for measuring errors • If RTD Biasing of Thermal Model is used, thermal overload setting can be set higher • Note: motor feeder cables are normally sized at 1.25 times motor’s full load current rating, which would limit the motor overload pickup setting to a maximum of 125%. SF Thermal Overload Pickup 1.0 1.1 1.15 1.25
- 53. • Thermal Capacity Used (TCU) is a criterion selected in thermal model to evaluate thermal condition of the motor. • TCU is defined as percentage of motor thermal limit utilized during motor operation. • A running motor will have some level of thermal capacity used due to Motor Losses. • Thermal Trip when Thermal Capacity Used equals 100% 49 – Thermal Capacity Used
- 54. Overload Curve Set the overload curve below cold thermal limit and above hot thermal limit If only hot curve is provided by mfgr, then must set below hot thermal limit 49 - Overload Curve Selection
- 55. If the motor starting current begins to infringe on the thermal damage curves or if the motor is called upon to drive a high inertia load such that the acceleration time exceeds the safe stall time, custom or voltage dependent overload curve may be required. 49 - Overload Curve Selection
- 56. 49 - Overload Curve Selection A custom overload curve will allow the user to tailor the relay’s thermal damage curve to the motor such that a successful start can occur without compromising protection while at the same time utilizing the motor to its full potential during the running condition.
- 57. 49 - Current Unbalance Bias Negative sequence currents (or unbalanced phase currents) will cause additional rotor heating that will be accounted for in Thermal Model. Positive Sequence Negative Sequence • Main causes of current unbalance • Blown fuses • Loose connections • Stator turn-to-turn faults • System voltage distortion and unbalance • Faults
- 58. 49 - Current Unbalance Bias • Equivalent heating motor current is employed to bias thermal model in response to current unbalance. • Im - real motor current; K - unbalance bias factor; I1 & I2 - positive and negative sequence components of motor current. • K factor reflects the degree of extra heating caused by the negative sequence component of the motor current. • IEEE guidelines for typical and conservative estimates of K.
- 59. Thermal Model - Motor Cooling • Motor cooling is characterized by separate cooling time constants (CTC) for running and stopped motor states. Typical ratio of the stopped to running CTC is 2/1 • It takes the motor typically 5 time constants to cool. Thermal Model Cooling100% load - Running Thermal Model Cooling Motor Tripped
- 60. 46 - Unbalance Protection • Indication of unbalance negative sequence current / voltage • Unbalance causes motor stress and temperature rise • Current unbalance in a motor is result of unequal line voltages • Unbalanced supply, blown fuse, single-phasing • Current unbalance can also be present due to: • Loose or bad connections • Incorrect phase rotation connection • Stator turn-to-turn faults • For a typical three-phase induction motor: • 1% voltage unbalance (V2) relates to 6% current unbalance (I2) • For small and medium sized motors, only current transformers (CTs) are available and no voltage transformers (VTs). Measure current unbalance and protect motor. • The heating effect caused by current unbalance will be protected by enabling the unbalance input to the thermal model • For example, a setting of 10% x FLA for the current unbalance alarm with a delay of 10 seconds and a trip level setting of 25% x FLA for the current unbalance trip with a delay of 5 seconds would be appropriate. Motor Relay
- 61. 27 – Undervoltage Protection • The overall result of an undervoltage condition is an increase in current and motor heating and a reduction in overall motor performance. • The undervoltage protection element can be thought of as backup protection for the thermal overload element. In some cases, if an undervoltage condition exists it may be desirable to trip the motor faster than thermal overload element. • The undervoltage trip should be set to 90% of nameplate unless otherwise stated on the motor data sheets. • Motors that are connected to the same source/bus may experience a temporary undervoltage, when one of motors starts. To override this temporary voltage sags, a time delay setpoint should be set greater than the motor starting time.
- 62. 59 – Overvoltage Protection • The overall result of an overvoltage condition is a decrease in load current and poor power factor. • Although old motors had robust design, new motors are designed close to saturation point for better utilization of core materials and increasing the V/Hz ratio cause saturation of air gap flux leading to motor heating. • The overvoltage element should be set to 110% of the motors nameplate unless otherwise started in the data sheets.
- 63. 37 – Undercurrent • Many times, it is desirable to protect the equipment driven by a motor • In the case of a pump, for example, a sudden loss of load indicates a problem with the pump • This condition won’t damage the motor but is catastrophic to the pump
- 64. 66 – Jogging Protection • Starting a motor multiple times in rapid succession is bad for the motor • Starts/Hour limits can be applied • Time Between Starts can also be applied
- 67. Transformer Protection • The Following ANSI Device Numbers Are Used for Transformer Protection: – 50 – Instantaneous Overcurrent – 51 – Time Overcurrent – 87T – Main Transformer Differential – 87RGF – Ground Differential – 63 – Sudden Pressure – 59/81 – Volts Per Hertz
- 68. Size Matters • Small 500 to 10,000 kVA • Medium 10,000 kVA to 100 MVA • Large 100 MVA and above • Less than 500kVA not considered a power transformer • Our Discussion is mainly applicable to Medium and Large Power Transformers
- 70. 50/51 Protection • Characteristics Similar to What Was Discussed for Feeder Protection • Instantaneous Protection Applied on the High Side for Internal Fault Backup Protection • Time Overcurrent Protection Applied on the High Side for Overload Protection • Low Side TOC Protection Applied for Bus/Feeder Backup Protection
- 71. 87T – Transformer Differential • Similar to Machine Differential, but Special Considerations • Need to Compensate for Phase & Magnitude Shifts As Well as CT Ratio Differences • Need to Include Inrush Restraint Algorithm • Microprocessor Much Less Complicated then EM Relays
- 73. Transformer Phase Shifts • H1 (A) leads X1 (a) by 30 • Currents on “H” bushings are line-to-line quantities • Subtract from reference phase vector the connected non-polarity vector HV LV H1 H2 H3 X1 X3 X2 A B C a b c a b c A B C Assume 1:1 transformer
- 74. 87 – EM Relays
- 75. 87T – Microprocessor Relay * * * * D/Y30 WYE connectionWYE connection T60 Compensation Performed Internally By Relay
- 76. • Pick up set to 0.05 to 0.1 pu (based on phase CT primary) • Slope 1 for “normal” errors: 10% • Break 1 at IEEE calculated worse case remnance point (assume 80% flux) • Break 2 at 5X times Break 1 (assume no DC offset) • Slope 2 for large errors: 50‐80% ID = I1 + I2 IR = Max [I1 or I2 ] 87T ‐ Differential Characteristic
- 77. 87T ‐ Through Current: Perfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 BA A IR = Max [I1 or I2 ] ID = I1 + I2 B TRIP RESTRAIN
- 78. 87T ‐ Through Current: Imperfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 C A A IR = Max [I1 or I2 ] ID = I1 + I2 B B (2, -4) (0,0) (1, -3) C TRIP RESTRAIN
- 79. 87T ‐ Internal Fault: Perfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 BA A IR = Max [I1 or I2 ] ID = I1 + I2 B TRIP RESTRAIN 4 pu
- 80. 87T ‐ Internal Fault: Imperfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 A B A IR = Max [I1 or I2 ] ID = I1 + I2 B TRIP RESTRAIN 4 pu (4, 1.5)
- 81. 87T ‐ Inrush Detection • Inrush Detection and Restraint – 2nd harmonic restraint has been employed for years – “Gap” detection has also been employed – As transformers are designed to closer tolerances, the incidence of both 2nd harmonic and low current gaps in waveform have decreased – If 2nd harmonic restraint level is set too low, differential element may be blocked for internal fault due to generated harmonics
- 82. • When a transformer is energized, inrush current can be as high as 10 x FLC of the transformer • Inrush lasts for only a few cycles but can cause the differential element to operate because it has the appearance of an internal fault (current flows into but not out of the unloaded transformer • Predominantly 2nd harmonic • 2nd harmonic restraint is used to prevent misoperation of differential element during inrush. Transformer Magnetizing Inrush Current
- 83. Traditional 2nd Harmonic > Responds to the RATIO of magnitudes of 2nd Harmonic and Fundamental Frequency Components > Typical setting is 15-20% (dependent on transformer construction) Adaptive 2nd Harmonic > Responds to both Magnitudes and Phase Angles of 2nd Harmonic and Fundamental Frequency Component > Use on transformers experiencing lower than normal 2nd harmonic levels during magnetizing inrush conditions (say 5- 10%) 87T – Harmonic Restraint
- 86. Igd, pu I= max( IR1, IR2,IR0 ), pu Min. PKP S lope Fast detection of winding ground faults Very secure performance on external ground faults Configurable pickup, slope, and time delay 87TG - Restricted Ground Fault Protection
- 88. 63 – Pressure Devices • Two Main Types: – Sudden Pressure Relay – Applied to transformers without a Conservator Tank, uses pressure Rate of Rise – Bucholtz Relays – Applied to Transformers with a Conservator Tank, uses accumulated gas pressure • When an Arc occurs in oil, a release of various gasses occurs. • Sudden Pressure Increase is Detected by Relay
- 91. SUDDEN PRESSURE RELAY CHANGE PRESSURE RELIEF DEVICE 63 - Sudden Pressure Relay (SPR) •The SPR detects excessive rates of pressure rise within the tank as result of internal arcing causing oil breakdown and subsequent gas evolution •They can operate on a change in oil or gas pressure •Using a bellows and orifice to respond to rapid differential pressure changes, they are an inverse-time characteristic •The SPR should be an input on the digital transformer relay for targeting, SOE and waveform capture
- 92. 63 - Buchholtz Relay •Used on conservator type oil preservation systems as a protective device that senses gas accumulation •If a low level fault results in arcing, the small amount of gas that is produced will accumulate in this relay resulting in an alarm •The SPR should be an input on the digital transformer relay for targeting, SOE and waveform capture
- 93. 59/81 – Volts/Hertz Protection –Protects against overfluxing • Excessive v/Hz –Constant operational limits • ANSI C37.106 & C57.12 –1.05 loaded, 1.10 unloaded • Inverse curves typically available for values over the constant allowable maximum
- 94. 59/81 – Overexcitation Causes • Transmission Systems that Supply Distribution Substations – High voltage from Generating Plants – Voltage and Reactive Support Control Failures • Runaway LTCs • Capacitor banks in when they should be out • Shunt reactors out when they should be in • Near‐end breaker failures resulting in voltage rise on line (Ferranti effect)
- 95. 59/81 – Example of Overexcitation 60 MVAR 30 MVAR 30 MVAR Caps ON When They Should Be Off
- 96. Medium Power Transformer 87 T 50 51 51 G High Side Low Side ANSI / IEEEC37.91 “Guide for Protective Relay Applications for Power Transformers”
- 98. One Line Examples M M ST1 Other Loads S1 SB1 MM M S2 SB2 ST2 Tie Breaker
- 99. Microprocessor Benefits – Redundancy/Reduction In Device Count One Relay, 6 different independent CT input ratios CB1 CB5CB4CB3CB2 CB6 800:5 600:5 1000:5 1200:5 400:5 3000:5