This webinar brought to you by the Relion product family Advanced protection and control IEDs from ABB

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1 This webinar brought to you by the Relion product family Advanced protection and control IEDs from ABB Relion. Thinking beyond the box. Designed to seamlessly consolidate functions, Relion relays are smarter, more flexible and more adaptable. Easy to integrate and with an extensive function library, the Relion family of protection and control delivers advanced functionality and improved performance.

2 ABB Protective Relay School Webinar Series Disclaimer ABB is pleased to provide you with technical information regarding protective relays. The material included is not intended to be a complete presentation of all potential problems and solutions related to this topic. The content is generic and may not be applicable for circumstances or equipment at any specific facility. By participating in ABB's web-based Protective Relay School, you agree that ABB is providing this information to you on an informational basis only and makes no warranties, representations or guarantees as to the efficacy or commercial utility of the information for any specific application or purpose, and ABB is not responsible for any action taken in reliance on the information contained herein. ABB consultants and service representatives are available to study specific operations and make recommendations on improving safety, efficiency and profitability. Contact an ABB sales representative for further information.

3 Timothy Erwin North East Regional Technical Manager Basic relay school Feeder protection fundamentals June 16, 2014 Slide 3

4 Presenter Tim Erwin is a Northeast Regional Technical Manager for ABB s Distribution Automation and Protection division. Tim holds a Bachelor of Science degree in Electrical Engineering Technology from the New Jersey Institute of Technology. Prior to his six years of service at ABB, he held positions as Customer Service Supervisor, Sr. Sales Engineer for protective relays, and Sr. Development Application Engineer at RFL Inc. Tim is a member of IEEE. June 16, 2014 Slide 4

5 Why is feeder protection necessary? June 16, 2014 Slide 5

6 City lights June 16, 2014 Slide 6

7 Lightning June 16, 2014 Slide 7

8 Blackout June 16, 2014 Slide 8

9 Chaos and confusion June 16, 2014 Slide 9

10 Transmission line tower flashover June 16, 2014 Slide 10

11 Transformer Failure June 16, 2014 Slide 11

12 The electric power system: protection The improper replacement of fuses is one of the deepest rooted evils in the electric industry. V. H. Todd, Protective Relays, 1922 The electric power system did not begin to be implemented until the 1880s The need for protection evolved with the power system and experience gained from system faults Nothing service interruption was not important Intentional weak-links (thin wires) Fuses Availability Maintenance shortcuts Electromagnetic operated switches But still no fault location discrimination Application of telegraph relay technology June 16, 2014 Slide

13 Typical distribution substation feeder circuit protection devices Fuses Breakers controlled by protective relays Reclosers Sectionalizers June 16, 2014 Slide 13

14 Typical distribution substation feeder circuit Fuse B R Recloser Sectionalizer Relay Relay Transformer Primary Rural primary fuses Urban breaker or circuit switch Feeder Circuit Breaker in protective zone Breakers controlled by protective relays Reclosers Sectionalizers Lateral tapped fuses June 16, 2014 Slide 14

15 Line protection FAULT STATISTICS The probability of line faults, caused by lightning, are faults per 100 km a year. About 80% of line faults are single phase to earth 10% are two phase to earth faults 5% are isolated two phase faults 5% are three phase faults 80-85% of faults at HV lines are transient June 16, 2014 Slide 15

16 Overhead distribution feeder faults Temporary (non-persistent) 85% Lightning causing flashover Wind blowing tree branches into line(s) Permanent (persistent) 15% Broken insulator Fallen tree Automobile accident involving utility pole June 16, 2014 Slide 16

17 Distribution protection characteristics Required characteristics of protective devices are: Sensitivity responsive to fault conditions Reliability operate when required (dependability) and not operate when not required (security) Selectivity isolate minimum amount of system and interrupt service to fewest customers Speed minimize system and apparatus damage Economics June 16, 2014 Slide 17

18 Reliability DEPENDABILITY The certainty of correct operation in response to system trouble. SECURITY The ability of the system to avoid undesired operations with or without faults. June 16, 2014 Slide 18

19 Reliability DEPENDABILITY SECURITY Main 1 Main 2 Main1 Main2 The certainty of operation in response to system trouble The ability of the system to avoid misoperation with or without faults June 16, 2014 Slide 19

20 Application Protection to be applied based on exposure Higher voltage feeders tend to be longer with more exposure to faults Apply downline devices... reclosers, fuses, based typically on 3 to 5 MVA of load per segment June 16, 2014 Slide 20

21 Question # 1 Two required characteristics of a protection scheme must include A. Dependability for correct operation and sized to fit in panel B. Security to avoid false operation and proper input voltage C. Dependability to detect for correct operations and Security to guard against false operation D. Selectivity to isolate the minimum service area and programmable push buttons ABB Inc. June 16, 2014 Slide 21

22 Question # 1: answer Two required characteristics of a protection scheme must include A. Dependability for correct operation and sized to fit in panel B. Security to avoid false operation and proper input voltage C. Dependability to detect for correct operations and Security to guard against false operation D. Selectivity to isolate the minimum service area and programmable push buttons ABB Inc. June 16, 2014 Slide 22

23 Protective relays Zones of protection

24 General relaying philosophy Zone protection Generator Transformer Bus Feeder Lines Motors June 16, 2014 Slide

25 Why would I need to develop zones of protection? Zones of protection help to simplify achieving the required characteristics of protective scheme Required characteristics of protective devices are: Sensitivity responsive to fault conditions Reliability operate when required (dependability) and not operate when not required (security) Selectivity isolate minimum amount of system and interrupt service to fewest customers Speed minimize system and apparatus damage Economics June 16, 2014 Slide 25

26 Fault current levels Fault Current Vs. Distance to Fault on the Feeder Transformer Secondary End of Line Function of Substation transformer size (source impedance) Distribution voltage Fault location 10kA - majority 10-20kA - moderate number 20kA - few June 16, 2014 Slide 26

27 Zones of protection Station A Station B G G G Station C Station D M June 16, 2014 Slide

28 Zones of protection Station A Station B G G G Station C Station D M Generator Protection June 16, 2014 Slide

29 Zones of protection Station A Station B G G G Station C Station D M Transformer Protection June 16, 2014 Slide

30 Zones of protection Station A Station B G G G Notice the overlap of zones Station D M Station C Bus Protection June 16, 2014 Slide

31 Zones of protection Station A Station B G G G Station C Station D M Line Protection June 16, 2014 Slide

32 Zones of protection Station A Station B G G G Station C Station D M Motor/Feeder Protection June 16, 2014 Slide

33 Zones of protection CT for Green Zone CT for Red Zone Red Zone Green Zone Dead Tank Breaker, Two CTs June 16, 2014 Slide

34 Zones of protection CT for Green Zone CT for Red Zone Red Zone Green Zone Live Tank Breaker, Single CT June 16, 2014 Slide

35 Question # 2 Zones of protection are used to: A. Simplify achieving desired characteristics of a protection scheme, i.e. security and dependability B. Provide backup protection to down stream devices C. Allow dispatch to determine who to send out on a trouble call D. All of the above E. A&B above ABB Inc. June 16, 2014 Slide 35

36 Question # 2: answer Zones of protection are used to: A. Simplify achieving desired characteristics of a protection scheme, i.e. security and dependability B. Provide backup protection to down stream devices C. Allow dispatch to determine who to send out on a trouble call D. All of the above E. A&B above ABB Inc. June 16, 2014 Slide 36

37 Fuses ABB Inc. June 16, 2014 Slide 37

38 Fused cutouts Enclosed Fused Cutout Open Link Line terminal Porcelain Housing Silicon/Polymer Support Line terminal Line terminal Silicon/Polymer Support Mounting bracket Mounting Bracket Fuse Tube Mounted Inside Housing Door Mounting Bracket Line terminal Fuse Holder Arc Arrester Open Link Fuse Link Spring Contacts Line terminal Housing Door ABB Inc. June 16, 2014 Slide 38

39 Distribution fuses Continuous current rating Interruption rating Curve characteristics Minimum melt Total clearing June 16, 2014 Slide 39

40 Fuse characteristic 1000 Time in Seconds Minimum Melt (Response Time) Total Clearing (Interruption Time) Fuse melting time (damage) 0.1 Arc Clearing June 16, 2014 Slide Amperes

41 Distribution fuses - expulsion K link T link (slower clearing at high current) Common low current clearing time based on fuse rating 300 msec <=100 A rating 600 msec > 100 A rating June 16, 2014 Slide 41

42 Distribution fuses current limiting General purpose Rated maximum interrupting down to current that causes melting in one hour Melting at 150% to 200% of rating June 16, 2014 Slide 42

43 Distribution fuses current limiting Backup Rated maximum interrupting down to rated minimum interrupting Requires application with expulsion fuse for low current protection June 16, 2014 Slide 43

44 Fuse coordination - rule of thumb Minimum Melt (Response Time) Total Clearing (Interruption Time) Time in Seconds Downstream Upstream Maximum clearing time of downstream fuse should be less than 75% of minimum melt time of upstream fuse (device) June 16, 2014 Slide Amperes

45 Protective relays June 16, 2014 Slide 45

46 What is relaying? June 16, 2014 Slide 46

47 Relays Evolution of technology The first protective relays began to appear in the early 1900s. Electromechanical Solid-state Microprocessor June 16, 2014 Slide 47 And have evolved to the advanced substation automation systems of today.

48 Relays Definition A relay is a device that responds to a measured quantity... current, voltage, heat, pressure, vibration, etc., from one system and switches a current in another system, usually an electric circuit for the purpose of protection or control. Protective relays are devices that are used throughout the electric power system to detect abnormal and unsafe conditions and initiate corrective action. June 16, 2014 Slide 48

49 Classification of relays defined in IEEE C37.90 By function Protective - Detects intolerable conditions and defective apparatus Monitoring - Verify conditions in the protection and/or power system Reclosing - Establish closing sequences for a circuit breaker following a protective relay trip Regulating - Operates to maintain operating parameters within a defined region Auxiliary - Operates in response to other [relay] actions to provide additional functionality Synchronizing - Assures that proper conditions exist for interconnecting two sections of the power system June 16, 2014 Slide 49

50 Classification of relays By input Current Voltage Power Frequency Temperature Pressure Flow Vibration June 16, 2014 Slide 50

51 Classification of relays By performance characteristics Overcurrent Over/under voltage Distance Directional Inverse time, definite time Ground/phase High or slow speed Current differential Phase comparison Directional comparison June 16, 2014 Slide 51

52 Classification of relays By operating principle Current balance Percentage biased Multi-restraint Product Thermal Comparator Phase Magnitude June 16, 2014 Slide 52

53 Classification of relays By technology Electromechanical {CO, KAB} Solid state (Static) {MSOC} Microprocessor-based (Digital/Numerical){ Relion} June 16, 2014 Slide 53

54 The protection team Relays are just one part of a team The relay(s) The sensors PTs CTs Sudden pressure, temperature, etc. The switch or circuit breaker DC power supply (Battery) The interconnection June 16, 2014 Slide 54

55 Distribution circuit breaker/recloser Interruption medium Oil Vacuum under oil Vacuum Operating mechanism Electromechanical (spring charging) Magnetic actuator Fault sensing and control Electromechanical Solid state Microprocessor June 16, 2014 Slide 55

56 Operating mechanisms: ESV (spring charge) vs. OVR Spring charged mechanism Magnetic actuator June 16, 2014 Slide 56

57 Automatic recloser Three Phase Single Phase Improve reliability of service Pole-top mounting - eliminates need to build substation Three-phase unit can replace breaker in substation for lower current ratings June 16, 2014 Slide 57

58 Protective relays Basic operation principles June 16, 2014 Slide 58

59 Definite time overcurrent (50) I R Time I PU Current June 16, 2014 Slide 59

60 Inverse time overcurrent (51) I R Time I R Current June 16, 2014 Slide 60

61 Basic protection principles Over (59) and under (27) voltage ~ Z S V R Definite time overvoltage (59/59N) at or above pickup value Definite time undervoltage (27) below pickup value Time Operate Region Operate Region t V PU Voltage June 16, 2014 Slide 61

62 Basic protection principles Voltage balance (differential) OBJECT V DIFF June 16, 2014 Slide 62

63 Basic protection principles Directional relaying Reference X X Reference [Non]Operate V POL Operate Contact Opening Torque I OP Contact Closing Torque Reverse Forward Must reliably determine direction to the fault June 16, 2014 Slide 63

64 Basic protection principles Directional relaying V POL V POL-MIN I OP-MIN Reverse Boundary Forward I OP Security angle Multi-phase faults I OP = I X, X = A, B, C V POL = V YZ, YZ = BC, CA, AB Ground faults Zero sequence I OP = 3I 0 V POL = 3V 0 Zero sequence current I OP = 3I 0 I POL = I 0 (from Transformer) Negative sequence I OP = 3 I2 V POL = 3 V2 June 16, 2014 Slide 64

65 Basic protection principles Distance relaying ~ Z S V R I R Z R Distance relaying uses both voltage and current to determine if a fault is within the relay s set zone of protection Based on Kirchoff s voltage law Three phase system loops: AB, BC, CA, AG, BG, CG Phase comparator principle Phase and ground faults Positive and zero sequence transmission line impedance June 16, 2014 Slide 65

66 Basic protection principles Distance phase comparators ~ Z S V R I R Z R S1 S2 PHASE COMPARATOR Compares the phase angles of two voltages derived from system voltages and currents during a fault and relay impedance reach setting to determine operation. 1 / 0 S1 S2 S1 = I R Z R - V R S2 = V R OPERATE Apply operating torque RESTRAIN Apply opening torque June 16, 2014 Slide 66

67 Basic protection principles Typical distance characteristic No Operation Region X Z R Z H H Thevenin s equivalent impedance to sources {behind bus H Z G G Z L Operate MTA R Mho Unit Characteristic - Self Polarized June 16, 2014 Slide 67

68 Basic protection principles Differential protection I IN I OUT I IN I OUT OBJECT OBJECT R I OP = 0 OP R R I OP OP R I IN I OP = I IN - I OUT External Fault I OUT Differential protection is based on Kirchoff s current law. I IN I OP = I IN + I OUT Internal Fault Generators Motors Transformers Transmission Lines Busses Shunt Reactors I OUT June 16, 2014 Slide 68

69 Basic protection principles Types of differential measurement A B C N Bus Ground Fault on Transformer Windings June 16, 2014 Slide 69

70 Basic protection principles Types of differential measurement I 1 I 2 I 3 I 4 I d R I d = I 1 + I 2 + I 3 + I 4 Simple Overcurrent Sum all feeder currents High Impedance R = 1500 Ω Measure V June 16, 2014 Slide 70

71 Differential relay (Line) I F I F PILOT CHANNEL Local Local Remote Remote Summation Summation External Fault Internal Fault June 16, 2014 Slide 71

72 Directional comparison relay External Fault I F I F PILOT CHANNEL POTT - Sends permissive PUTT - Sends permissive Unblock - Sends unblock Blocking - Receives block POTT - Does nothing PUTT - Does nothing Unblock - Does nothing Blocking - Sends block June 16, 2014 Slide 72

73 Directional comparison relay Internal fault I F I F PILOT CHANNEL POTT - Sends and receives permissive/trips PUTT - Sends and receives permissive/trips Unblock - Sends and receives Unblock/Trips Blocking - Trips POTT - Sends and receives permissive/trips PUTT - Sends and receives permissive/trips Unblock - Sends and receives Unblock/Trips Blocking - Trips June 16, 2014 Slide 73

74 Basic protection principles Definite time-overcurrent (Fuse, EM, Micro) Inverse time-overcurrent (Fuse, EM, Micro) Directional (EM, Micro) Distance (EM, Micro) Differential (EM, Micro) Phase Comparison (EM, Micro) Directional Comparison (EM, Micro) June 16, 2014 Slide 74

75 IEEE device function numbers A device function number, with an appropriate prefix and suffix where necessary, is used to identify the function of each device all types of switchgear IEEE Standard C37.2, 1991 This standard applies to the definition and application of function numbers for devices used in electrical substations and generating plants and in installations of power utilization and conversion apparatus June 16, 2014 Slide 75

76 IEEE device function numbers and acronyms Device 11 Fill Box Method for representing multiple functions in device 11 Fill Box Method for representing multiple functions in device 11 June 16, 2014 Slide 76

77 IEEE device function numbers and acronyms Device 11 List Box Method for representing multiple functions in device 11 List Box Method for representing multiple functions in device 11 June 16, 2014 Slide 77

78 IEEE Standard (Reaffirmed 1993) Graphic symbols for electrical and electronics diagrams June 16, 2014 Slide 78

79 Question # 3 IEEE device function numbers are used to: A. Save space on schematic diagrams B. Provide a standardized way identify the function of each device all types of switchgear C. Provide security against intruders D. None of the above ABB Inc. June 16, 2014 Slide 79

80 Question # 3: answer IEEE device function numbers are used to: A. Save space on schematic diagrams B. Provide a standardized way identify the function of each device all types of switchgear C. Provide security against intruders D. None of the above ABB Inc. June 16, 2014 Slide 80

81 Coordination June 16, 2014 Slide 81

82 Distribution protection coordination Coordination of relays allow the engineer to: Minimize the number of affected customers, Prevent sympathetic tripping (overreaching) for faults outside the upstream devices zone of protection Minimize the possibility of injury and damage to system ABB Inc. June 16, 2014 Slide 82

83 Recloser or [breaker] relay characteristic Time in Seconds Response Time Breaker / Recloser Interruption Time Contact opening and arc clearing Amperes June 16, 2014 Slide 84

84 Overcurrent current device characteristics 100 ANSI Numbers 50 - Instantaneous Overcurrent (No intended delay) 10 Recloser Fast Curve Time in Seconds Inverse-time Overcurrent Recloser Slow curve PU M1 Current in Secondary Amperes June 16, 2014 Slide 85

85 Time overcurrent curves Inverse Very Inverse Extremely Inverse Time in Seconds Moderately Inverse Definite Time Current in Multiples of Pickup June 16, 2014 Slide 86

86 Time overcurrent curve time dial June 16, 2014 Slide 87

87 Recloser curves Variety of recloser curves are offered to match existing practices, fuses, conductor annealing, etc. June 16, 2014 Slide 88

88 Principles of feeder coordination Fault Current Vs. Distance to Fault on the Feeder June 16, 2014 Slide 89

89 Principles of feeder coordination Coordination Terminology SOURCE B R LOAD Upstream Source-side Protected Backup Downstream Load-side Protecting Down-line Local (where you are) June 16, 2014 Slide 90

90 Principles of feeder coordination I f2 I f1 T 1 Time T 2 June 16, 2014 Slide 91 I f1 I f2 Current 51 Inverse time-overcurrent characteristic

91 Principles of feeder coordination Breaker Recloser Fuse Relay I f3 I f2 I f1 Time Fuse Total Clearing Minimum Melt Recloser P3 CTI Relay CTI Interrupt Time CTI - Coordination Time Interval (typical sec) Response Time P1 P2 I f1 I f2 I f3 Current June 16, 2014 Slide 92

92 Coordination example T hs 2 Source (Incomer 1) I B2max I Ths-min Feeder B I B1max I B 2min B I Bn max I B 1min B N ABB Inc. June 16, 2014 Slide 93

93 Typical feeder coordination June 16, 2014 Slide 94

94 June 16, 2014 Slide 95

95 Thank you for your participation Shortly, you will receive a link to an archive of this presentation. To view a schedule of remaining webinars in this series, or for more information on ABB s protection and control solutions, visit: June 16, 2014 Slide 96