OVERCURRENT PROTECTICE DEVICES (ELECTRICAL ENGINEERING).pptx

OVERCURRENT PROTECTICE DEVICES (ELECTRICAL ENGINEERING).pptx

1. OVER-CURRENT PROTECTION AND COODINATION

2. OVERVIEW AND PHILOSOPHY Protection is one of the most complex and difficult topics in power system engineering. The primary philosophy of protection is to preserve sensitivity, selectivity, minimumtime of operation, and reliability. A local protection philosophy covering about two to three buses (or nodes of allphases ) beyond any protective device, but it does not cover a wider area for defenseagainst catastrophic failures to provide higher reliability and resiliency.

3. OVERVIEW AND PHILOSOPHY Factors to considered: trade‐off to achieve proper protection with cost‐ effectiveness,safety of personnel and equipment, etc. Distribution systems need protection against overcurrent and overvoltage. In thischapter , protection will be limited to overcurrent considerations only. With the introduction of computer‐based protection devices, the existing protectionsystems are changing gradually.

4. ROLE OF PROTECTION STUDIES Reasons for conducting protection studies: To prevent damage to equipment and circuits caused by faults or abnormal conditions. To prevent hazards to the public and utility personnel. Utilities depend on protection to maintain highest service reliability, safety, and resiliency bypreventing unnecessary power interruptions. The protection system minimizes the effects of damage when an interruption occurs, andminimizes the duration of service interruptions to customers due to a fault or short circuit and thenumber of customers affected with proper coordination and operation of the protective devices. Use this box to calculate

5. ROLE OF PROTECTION STUDIES Primary objectives of performing protection studies as a part of comprehensive distributionplanning and/or design studies: Basic addition or expansion of a distribution system Manual and automatic sectionalizing of portions of a system Decision on proper phase spacing between conductors and selection of insulation Vegetation management to assure the highest level of system reliability Inspection for other potential problems such as salt deposition on conductors and dustaccumulation on insulators• Preventive equipment maintenance Use this box to calculate

6. PROTECTION OF POWER-CARRYING DEVICES Adequate protection must be provided for all types of power‐carrying equipment suchas: Lines, feeders, and laterals Distribution substation transformers and distribution transformers Capacitors Voltage regulators Segments of the system itself Conventional and distributed energy sources (DERs) Loads Use this box to calculate

7. CLASSIFICATION OF PROTECTIVE AND SWITCHING DEVICES Protective devices are intentionally created weak links to safeguard expensivepower-carrying assets such as lines (feeders and laterals) and transformers. Basic protective devices for overcurrent protection are designed to burn and opento clear overcurrent. Purpose of protective devices is to protect equipment from overloads and shortcircuits. Various devices are used to protect different parts of distribution systems. The different classification of Protective and Switching Devices. Use this box to calculate

8. CLASSIFICATION OF PROTECTIVE AND SWITCHING DEVICES 1. Single-Action Fuses Expulsion Fuses Vacuum Fuses Current-limiting Fuses Distribution Fuse Cutouts 2. Automatic Circuit Reclosers 3. Sectionalizers 4. Circuit Breakers 5. Time Overcurrent relays 6. Static or Solid-state Relays 7. Numerical Relays Use this box to calculate

9. CLASSIFICATION OF PROTECTIVE AND SWITCHING DEVICES 8. Load Break Switch 9. Circuit Interrupter 10. Disconnecting Switch 11. Sectionalizing Switch Use this box to calculate

10. SINGLE-ACTION FUSES Fuses have a circuit-opening fusible part that is severed by current passing through it. Fuses can be used for sectionalizing feeder segments to create zones. Single-action fuses handle the expected load of distribution lines (e.g., feeders,laterals). Fuses perform both sensing and fault-interrupting functions.

11. SINGLE-ACTION FUSES Drawback: Fuses need to be replaced after a single operation. While fuses are inexpensive, the labor cost of changing them is significant from anoperational perspective. Fuses are available in variety of types: Expulsion fuses Vacuum fuses Current‐limiting fuses. Distribution Fuse Cutouts Use this box to calculate

12. SINGLE-ACTION FUSES EXPULSION FUSES The principal component of a fuse linkis a fusible element, made of variousmaterials, including silver Time-current characteristic is used todetermine the fuse's operation timefor a specific fault current. The fuses are available with single or dual elements

13. EXPULSION FUSES OPERATING CHARACTERISTICS OF FUSE LINKSARE DETERMINED ARE DISTINGUISHED BY THESPEED OF OPERATION DEFINED BY THE SPEEDRATIO AS SHOWN IN THE FIGURE. SPEED RATIO OF THE FUSE LINKS OF 100 AAND BELOW IS THE RATIO OF THE CURRENT THATMELTS THE FUSE LINK IN 0.1 SECOND TO THECURRENT THAT MELTS THE FUSE IN300 SECONDS SPEED RATIO OF THE FUSE LINKS OF RATEDGREATER THAN 100A, IS DEFINED AS THERATIO OF THE CURRENT THAT MELTS THE FUSELINK IN 0.1AND 600 SECOND. SINGLE-ACTION FUSES

14. EXPULSION FUSES KLINK – “FAST TYPE” WITH SPEED RATIO OF6–8.1. THESE ARE COMMONLY USED FORURBAN SYSTEMS. N LINK – THIS IS ALSO “FAST TYPE” WITHSPEED RATIO OF 6–11. T LINK – “SLOW TYPE” WITH SPEED RATIOOF 10–13. THESE ARE SUITED FORSUBURBAN SYSTEMS. S LINK – THESE ARE “VERY SLOW” WITHSPEED RATION OF 15–20. SINGLE-ACTION FUSES

15. VACUUM FUSES VACUUM FUSES ENCLOSE THE FUSIBLE ELEMENT WITHIN A VACUUM MEDIUM INTERNAL FEATURES OF VACUUM FUSES INCLUDE ARC RUNNERS, SHIELD, AND CERAMIC INSULATION MULTIPLE CYCLES MAY BE NECESSARY FOR LOW FAULT CURRENTS TO BURN BACK THE FUSIBLE ELEMENT VACUUM FUSES CAN BE USED INDOORS AND UNDER OIL ENVIRONMENTS SINGLE-ACTION FUSES

16. CURRENT-LIMITING FUSES NON-EXPULSION FUSES LIMIT ENERGY TO THE PROTECTIVE DEVICE, REDUCING THE RISK OFCATASTROPHIC FAILURE TO THE PROTECTION DEVICE. THEIR OPERATION DEPENDS ON THE TYPE OF MEDIUM IN WHICH THEY OPERATE. HIGH-CURRENT CLEARING IS SIMILAR TO OTHER FUSES. KEY FACTORS DETERMINING THEIR OPERATION ARE LET-THROUGH CURRENT, MELT I2T, LET?THROUGH I2T, AND PEAK-ARC VOLTAGE. SINGLE-ACTION FUSES

17. CURRENT-LIMITING FUSES BASIC TYPES OF CURRENT-LIMITING FUSES: Backup or Partial-range Fuse: It must be used in conjunction with an expulsion fuse or some other device. Itis capable of properly interrupting current only above a specified level. General-purpose Current-limiting Fuse: It is designed to interrupt all fault currents from its rated interrupting currentdown to the current that causes element melting in one hour. Full-range Current-limiting Fuse: It interrupts any continuous current (up to rated interrupting current) that willcause the element to melt. SINGLE-ACTION FUSES

18. DISTRIBUTION FUSE CUTOUTS A fuse cutout is a housing forconnecting fuse link. This arrangement assists the fieldcrews to replace a burned fuse linkwith a new one. SINGLE-ACTION FUSES

19. Recloser is a multifunction protective device withfault-sensing and fault-clearing capabilities Designed to automatically reclose and reenergize theline. Reclosers are lighter than circuit breakers andmounted on poles in overhead distribution systems. AUTOMATIC CIRCUIT RECLOSERS FIG: EXAMPLES OF MODERN RECLOSER(A) NOVA NXT AND (B) INTELLIRUPTER PULSECLOSER

20. Reclosers with advanced microprocessorprotective relays are also commonly used at point of common coupling (PCC)to microgrids. Unlike fuse links, which interrupt eithertype indiscriminately, reclosers candistinguish between temporary andpermanent faults. Reclosers typically have one fast (A) andone slow (C) or two slow (B and C)characteristics. Automatic circuit reclosers trip and reclose a preset number of times to cleartemporary faults or isolate permanent faults.• AUTOMATIC CIRCUIT RECLOSERS

21. Reclosers automatically reenergize the line after tripping to test for faultclearance : After a fault is detected, reclosers trip and automatically reenergize to “ test”the line by successive “reclose” operations while giving temporary faultsrepeated chances to clear or be cleared by downstream protective devices. Should the fault not clear, the recloser recognizes it as a permanent fault andlocks open or “locks out.” A drawback of many reclosers is limited fault interruption capability. Reclosersmust be coordinated with upstream protective relay‐controlling circuit breakers ina substation. These circuit breakers are designed for interrupting fault currents. AUTOMATIC CIRCUIT RECLOSERS

22. AUTOMATIC CIRCUIT RECLOSERS

23. Recloser Classifications Reclosers are classified as single-phase for single-phase lateral applications andthree -phase for three-phase feeders. They can be hydraulically or electronically controlled.• The interrupting media for reclosers can be oil or vacuum. Modern reclosers are typically electronically controlled. Most reclosers use oil-filled chambers to interrupt fault current, but recent designsincorporate vacuum circuit interruption.21 AUTOMATIC CIRCUIT RECLOSERS

24. Sectionalizers are circuit-interrupting devices similar to reclosers but can be lessexpensive if they do not have fault-interrupting mechanisms. A sectionalizer applied in conjunction with a recloser or circuit breaker has thememory of counting the number of operations of the upstream device, but it doesnot have any fault‐interrupting capability of its own. It counts the number of operations of the backup device (recloser or circuit breaker)during fault conditions, and after a preselected number of current‐interruptingoperations (reclose attempts), the sectionalizer opens and isolates the faultedsection of line. SECTIONALIZERS

25. If the fault is temporary, both thesectionalizer and the recloser reset to thenormal state. If the fault is persistent, however, therecloser operates on its sequence, but thesectionalizer isolates the fault before therecloser starts its final reclose operation;thus, recloser lockout is avoided, and onlythat portion of the circuit beyond thesectionalizer is interrupted. SECTIONALIZERS

26. Circuit breakers are commonly employed at the substation level for overcurrentprotection of the feeders connected to them. They are mechanical switching devices capable of making, carrying, and breaking currentsunder short‐circuit or normal operating conditions. Circuit breakers are expensive and bulky protective device which can only be costjustified at the substation level. Generally, relay‐controlled circuit breakers are preferred to reclosers due to their betteraccuracy. Thus, opening and closing of substation circuit breakers are always controlledby protective relays. CIRCUIT BREAKERS

27. Circuit breakers are classified by the interrupting medium and the method of storingenergy : Oil interruption• Vacuum interruption Air‐blast interruption SF6 (gas) interruption Air‐magnetic interruption An automatic circuit breaker is equipped with a trip coil connected to a relay or othermeans , designated to open the breaker automatically under abnormal conditions, such asfault and overcurrent. CIRCUIT BREAKERS

28. These operations use: ( i ) motor‐compressed spring for one closing/opening operation with spring resetwithin 10 seconds, (ii) compressed air or other gas for two closing/opening operations, (iii) pneumatic or hydraulic breakers for higher numbers such as five closing/opening operations. CIRCUIT BREAKERS

29. Classical electromechanical protectiverelays have been in use since theearly days of electricity, dating backto the 1880s. Relays have the intelligence to detect an abnormal condition and send propersignals to circuit breakers to achieve automatic tripping and closing of the circuitbreaker contacts. For primary distribution systems, sensing function requires instrument transformersto step down both voltages and currents to standard 120 V and 5 A.• TIME OVERCURRENT RELAYS

30. For example, for a 10‐MVA, 115‐kV/12.47‐kV three‐phase substation transformer, avoltage transformer (VT) with turns ratio of 60 : 1 will be required to step down7.2 kV (L–N voltage on the low‐voltage side) to 120 V. Similarly, a currenttransformer (CT) with turns ratio of 500 : 5 will be needed to step down the full loadcurrent of 463 to a lower value suitable for relays. The time-inverse overcurrent relay is the most used relay for overcurrentprotection. This relay has plugs to select tap setting (TS), which is the minimumcurrent at which the relay starts operating. Typical TSs range from 1 to 12 A. TIME OVERCURRENT RELAYS

31. The other setting on these relays is thetime dial (TD) setting, which delays theoperation of the relay, with valuesranging from 0.5 to 11. MTS is obtained by dividing the currentflowing in the relay by selected TS. To understand the use of the figure,consider a fault current of 960 A for CTof 300 : 5 and TS of 4 A for the relay. TIME OVERCURRENT RELAYS

32. TIME OVERCURRENT RELAYS

33. TIME OVERCURRENT RELAYS

34. If we consider that a TD of 5 is selected,the operating time of the relay underthese conditions by noting the time onthe graph with TD = 5 at MTS of 4, whichis about 0.4 second. Although the present generation ofovercurrent relays use digital technologyto process the input current, these relayscontinue to mimic the time‐inverseovercurrent characteristics provided bythe classical electromechanical relays.• TIME OVERCURRENT RELAYS

35. The standard characteristics of relaysused in the United States are given by anequation in terms of TD and MTS: TIME OVERCURRENT RELAYS

36. The values of α,β, and Kdepends on the relay typesand are illustrated in thefollowing table.• The corresponding graph ofdifferent types of relay isillustrated in the figure. TIME OVERCURRENT RELAYS

37. Static relays do not have moving parts, unlike electromechanical relays. The invention of transistors enabled the development of static relays. Static relays are more accurate and have faster response times compared toelectromechanical relays. These relays require high-quality DC power supplies, which are not so practical insubstation environments. Solid-state or static relays emerged in the early 1960s but had low reliability, leadingto their short lifespan. STATIC OR SOLID-STATE RELAYS

38. Digital or numeric relays emerged in the mid-1980s with the availability of low-costmicroprocessors. They have become the preferred choice due to their multifunction capabilities andhigh accuracy. Modern digital relays are commonly used for overcurrent protection in distribution system feeders. Digital relays offer increased reliability and are now preferred for circuit protectionranging from 480 V to 765 kV. DIGITAL OR NUMERICAL RELAYS

39. Digital relays are widely used as both protective relays and microgrid controllers. They have introduced new functions such as breaker failure detection, digitalcommunications, adaptive protection, subcycle fast protection, and harmonicrestraints. These multifunction devices have significantly advanced parts, reduced costs, andsimplified maintenance in substations. Digital relays have improved data collection for continuous monitoring and eventroot cause analysis. DIGITAL OR NUMERICAL RELAYS

40. Load break switches are circuit disconnect devices used to make or break a circuit atspecified currents. They are equipped with auxiliary equipment to enhance the speed of the disconnectswitch blade. The auxiliary equipment also helps modify the arcing phenomenon to ensure safeinterruption of the circuit. Load break switches are designed to handle the switching of loads, providing areliable means of isolation and control. LOAD BREAK SWITCH

41. Device designed to open and close a circuit by nonautomatic means and to open thecircuit automatically at a predetermined overcurrent value without damage to thedevice when operated within its rating. CIRCUIT INTERRUPTER

42. Device designed to open and close a circuit by nonautomatic means and to open thecircuit automatically at a predetermined overcurrent value without damage to thedevice when operated within its rating. DISCONNECTING SWITCH

43. Divides a feeder into sections Main purpose: sectionalizing only Can be a disconnecting or load break switch Not the same as sectionalizers or reclosers Sectionalizing Switch

44. Many sectionalizing switches are used Solid circle = closed sectionalizing switch on feeder Open circle = open tie switch at feeder end Example Distribution Systems

45. Smart Switching Devices New technology has created a new class of switches Still in development; more research needed (e.g., automated fuse) Some devices under development are described next New Generational Devices

46. Combines a fuse with sensors for monitoring and external control Works like a normal fuse (must be replaced after blowing) Protects substation transformers and secondary conductors Allows low-resistance grounding to reduce fault currents Guards against single phasing while keeping current-limiting function Smart Fuses

47. A smart recloser is a combination of a recloser with some form of intelligence and control incorporated to achieve automation. This Wi‐Fi‐enabled electrical equipment is a kind of “smart switch” that utilities use to more quickly detect and correct outages along their distribution systems. Smart Reclosers ( Interruptors )

48. Smart Circuit Breakers Traditional breakers are mostly electromechanical and idle New versions include wireless connectivity and computing power, like smart meters or smartphones

49. Basic Rules of Classical Distribution Protection Temporary faults → allow reclosing to restore service Permanent faults → isolate only the faulted section Goal: affect fewer customers and improve reliability Closest device to fault = Primary ; upstream devices = Backup

50. Basic Rules of Classical Distribution Protection Sectionalizing devices (reclosers, sectionalizers ) split feeders into smaller segments Taps need protection at the feeder connection Fuses → small, short single-phase taps Reclosers/ Sectionalizers → large, long taps Reclosers: Clear temporary faults with fast trip Allow fuses to clear permanent tap faults Reduce fuse operations but may cause momentary outages Midpoint sectionalizing devices minimize interruptions Critical loads can be protected with reclosers placed downstream of their connection point

51. Coordination of Protection Devices Complex process with many variables Requires careful planning (“art of protection”) Most important in radial systems with one-way power flow Benefits: fewer interruptions, less customer impact, faster restoration To conduct proper coordination, the following data are required: a) Feeder configuration diagram. b) Location of protective devices. c) Mathematical models of protective devices, including their time-current characteristics. d) Expected range of normal load currents at all locations within the system. e) Expected range of fault currents at all locations within the system.

52. General Coordination Rule Uses time-current characteristics of devices Coordinate devices sequentially from load side to source side Ensure a time gap between primary and backup devices Process repeated for all device pairs in the system Results may vary—multiple valid solutions are possible

53. Fuse – Fuse Coordination Model for Fuses Overcurrent device that melts when current is too high Higher current → faster melting Has two curves: MMC = minimum melting time TCC = total clearing time Gap between curves = arcing time

54. Fuse – Fuse Coordination A new fuse follows the standard melting and clearing curves, but repeated overloads shorten its melting time. The damaging time curve is about 75% of the MMC . The remaining 25% margin accounts for factors like ambient temperature, loading, and climate. This margin is not fixed ; it can change depending on local conditions. Example: A 10K fuse link starts melting at 20 A (≈ 2× its rating). Rule: Fuse rating ≥ (Full Load ÷ 1.5). → 10K fuse is suitable for loads < 15 A . Fuse links cannot be modeled with a single equation; instead, their characteristics are digitized for use in coordination software.

55. Rule for Fuse–Fuse Coordination For a fault, fuse B’s total clearing time curve must be below fuse A’s damaging time curve within the coordination range. The damaging curve shows current levels that cause fuse deterioration. Rule: Fuse B’s clearing time ≤ 75% of fuse A’s minimum melt time (MMT) . This ensures proper coordination and prevents fuse A from being damaged during faults.

56. Rule for Fuse–Fuse Coordination System shows max fault, min fault, and full load currents at fuse points A and B. Step 1: Select fuse links by full load Location B: 40÷1.5=26.7 𝐴40÷1.5=26.7A → choose 30T fuse Location A: 70÷1.5=46.7 𝐴70÷1.5=46.7A → choose 50T fuse These ratings protect against overloads and faults. Next step: verify coordination to ensure Fuse B clears first without damaging Fuse A.

57. Rule for Fuse–Fuse Coordination Critical current = 1794 A (max fault seen by both fuses) At this current: 30T fuse (B): Clearing time = 0.037 s 50T fuse (A): Minimum melt time = 0.05 s Ratio = 0.037/0.05=0.740.037 / 0.05 = 0.740.037/0.05=0.74 Acceptable, since ratio < 0.75

58. Recloser – Fuse Coordination Recloser curve (Fig. a): shows fast trip (A) and time delay (C) Fuse curve (Fig. b): lies between recloser curves Intersections a and b = min and max fault currents for coordination Rule: For permanent downstream faults , the fuse must clear the fault (not the recloser)

59. Recloser – Fuse Coordination Upstream Permanent Faults Recloser clears the fault Operates twice on the slow curve Then locks out to isolate the fault Upstream permanent fault → Recloser opens Temporary fault → Neither device remains open Downstream fault : Recloser trips fast, recloses, then trips fast again If fault continues → fast trip disabled Recloser uses slow curve for 2 more trips → gives fuse time to clear permanent downstream fault

60. Recloser – Fuse Coordination Points a and b = min & max fault currents for fuse–recloser coordination Adjustments needed for tolerance and temperature rise in fuse link Recloser curves adjusted with a K-factor Typical value: 1.35 for fast curve (with 2 fast + 2 slow operations) With 1 fast + 3 slow operations , K-factor = 1.2 (less temperature rise) Value of b : where the fuse damaging curve (75% of MMT) intersects the scaled fast-trip curve of the recloser Value of a : where the fuse maximum clearing curve intersects the recloser curve

61. Recloser – Fuse Coordination K-factor = 1.2 for 1 fast + 3 slow operations (less temperature rise) Point b : Intersection of fuse damaging curve (75% MMT) with scaled fast-trip curve of recloser Point a : Intersection of fuse maximum clearing curve with recloser slow curve

62. Recloser – Fuse Coordination If a fuse is upstream of the recloser → recloser’s slow curve must be scaled with a K-factor Rule: At max fault current, Fuse MMT > (Recloser average clearing time × K) K-factor range: 1.7 – 3.5 (depends on recloser type, reclosing time, curves, and sequence) Tables provide recommended K-factor values for proper coordination

63. Recloser – Fuse Coordination

64. Recloser – Fuse Coordination The above table provide Recloser K‐factors for coordination with load‐side fuse links.

65. Recloser – Fuse Coordination Consider the system shown in the figure. The objective is to select recloser settings, fuses F1 and F2, and the fuse upstream of the transformer for the given system. The maximum and the minimum fault currents at distinct locations are shown in circles drawn to the locations. The maximum load currents at distinct locations are shown next to the arrows.

66. Recloser – Fuse Coordination Recloser Selection Since the maximum load current at Bus 1 is 270 A, it is necessary to choose a set of reclosers with a maximum continuous current rating higher than 270 A. This is achieved by employing three single‐phase reclosers type L with a trip coil rating of 280 A, which have a minimum trip rating of 280 A and interrupting capability of 4000 A. The interrupting capability is higher than the maximum fault current of 3000 A at Bus 1. Note that this selection limits the ability to increase the maximum load currents in the future without upgrading the reclosers.

67. Recloser – Fuse Coordination Source-Side Fuse & Recloser Coordination Rule: Source-side fuse must not melt for any faults on the load side. For max recloser fault = 3000 A , fuse MMT > recloser delayed clearing time . Transformer Turns Ratio (N = 3.7, Δ–Y connection): Fault currents on LV side are scaled on HV side: 3ϕ fault: × 3.7 Phase–phase fault: × 3.2 (0.87 × N) Phase–ground fault: × 6.4 (1.73 × N) Key Point: Phase–phase fault (× 3.2) gives the lowest multiplying factor , → most restrictive case → used as limiting factor for fuse & recloser coordination.

68. Recloser – Fuse Coordination Continuous Load Current and Fuse Selection Load scaling through the transformer On the low side , the transformer carries a maximum continuous load of 270 A . With the transformer turns ratio, this corresponds to only 73 A on the high side , where the fuse is located. Fuse thermal characteristics A fuse’s rating (e.g., 65 A for a 65E fuse ) is not a hard ceiling—it can usually carry more: No operation near its rating under continuous current. Can typically handle up to ~1.5 × rating continuously (≈ 97.5 A for a 65 A fuse). Will start melting if exposed to ≥ 2 × rating for a long time. Verification The 73 A continuous load seen by the fuse is well below the 97.5 A continuous capability of the 65E fuse. Therefore, the fuse won’t overheat or blow during normal operation. Final choice A 46-kV 65E slow fuse link is chosen because: It comfortably carries the normal load current. It provides proper coordination with the recloser’s delayed operation (as discussed in your earlier section).

69. Recloser – Fuse Coordination Recloser K‐factor The K‐factor value for the recloser is found according to the type of the recloser sequence and the reclosing intervals. For the recloser sequence of two fast operations followed by two delay operations, a K‐factor of 1.7 is used to scale the recloser's slow characteristics. 66

70. Recloser – Fuse Coordination Minimum Melt Time (MMT) Fuses must have an MMT higher than the recloser’s fast curve (A × 1.35) between 680–2380 A. At 2380 A , F1 and F2 should have MMT > 0.05 s → only 80T and 100T fuses qualify (65T fails). At 680–690 A , MMT should be > 0.1 s → all three fuses (65T, 80T, 100T) qualify.

71. Recloser – Fuse Coordination Maximum Clearing Time (MCT) MCT of fuses must be lower than the recloser’s delayed curve (C) . At 2380 A → MCT < 0.37 s → all fuses (65T, 80T, 100T) qualify. At 680–690 A → MCT < 1.8 s → only 65T and 80T qualify (100T fails).

72. Recloser – Fuse Coordination Selection The analysis indicates that the only fuse that satisfies all the requirements is the 80T fuse. Although the desired fuse for F1 was 65T, it needs to be increased to 80T to ensure adequate protection. Similarly, the desired fuse for F2 was 100T, but it needs to be reduced to 80T for proper coordination with the recloser. It's important to note that the 80T fuse will coordinate with the recloser, but it may melt under maximum loading conditions.

73. Recloser – Sectionalizer Coordination Sectionalizer Settings Sectionalizer operates at one less count than the recloser. Example: Recloser = 4 operations → Sectionalizer = 3. Both devices must have the same continuous current rating . Sectionalizer actuating current = 80% of recloser’s minimum trip rating .

74. Circuit Breaker – Recloser Coordination Models for Relay – Controlled Circuit Breakers The overcurrent relay‐controlled circuit breakers have a time delay unit with characteristics similar to that shown in Figure, and an instantaneous unit. The relay characteristics, its pickup value, and TD are selected based on the given load and fault currents. The relay type CO‐8 is used often.

75. Circuit Breaker – Recloser Coordination Rules for Coordination Relay curve must be set above the primary device’s curve. Pickup & time-dial settings → provide margin with recloser/device characteristics. Instantaneous relay → margin above recloser’s fast curve. Time-delay relay → allow recloser’s slow curve to act first. Static relays : easier to coordinate (no overtravel/coasting). Mechanical relays : need extra margins for reliable operation.

76. Circuit Breaker – Recloser Coordination Figure shows an example of a distribution feeder protected by a recloser and a circuit breaker along with the minimum and maximum faults. Find settings of the relay for the CB to coordinate with the recloser.

77. Circuit Breaker – Recloser Coordination Solution: The first step is to select a recloser. Since the full load current is 110 A, a recloser with 140 A trip coil setting is appropriate. Figureshows the recloser curves. We select a CO‐8 relay for the circuit breaker. For a load current of 185 A, 200:5 CT will work. Further, we select 5 A as the TS for the CO‐8 relay. This will allow some margin for overload on the feeder.

78. Circuit Breaker – Recloser Coordination Solution: Now, we have to select the TD setting for the relay to coordinate with the recloser. At 1832 A, which is the largest fault current seen by both the recloser and the circuit breaker, the recloser takes 0.24 seconds to operate on the slow curve (curve C). We want the relay to take higher time than that at the same current. We compute the MTS for this current, which is:

79. Circuit Breaker – Recloser Coordination Solution: CO‐8 relay with TD of 8 takes 0.3 seconds to operate, which provides sufficient margin between the operating time of the recloser and the circuit breaker.

80. New Digital Sensing and Measuring Devices Phasor Measurement Units (PMUs) Synchrophasors : Time-synchronized values showing magnitude & phase angle of AC signals. PMUs (Phasor Measurement Units) : Devices that capture synchrophasors with high accuracy. Speed : PMUs operate ~100× faster than SCADA. Benefits : Real-time grid monitoring Better detection of instability & stress Higher reliability & efficiency Lower operating costs Applications : Used for both real-time operations and offline analysis to optimize grid performance.

81. New Digital Sensing and Measuring Devices Phasor Measurement Units (PMUs)

82. New Digital Sensing and Measuring Devices Microphasor Measurement Units PMUs vs. μ PMUs PMUs: Installed mainly on transmission systems & substations. μ PMUs: Provide synchrophasor data at consumer-level voltages. Advantages of μ PMUs More affordable than traditional PMUs → easier large-scale deployment. Enable high-resolution monitoring of the distribution grid. Support new applications: Post-event analysis Disturbance identification Near real-time monitoring Accurate fault location in distribution systems & microgrids

83. New Digital Sensing and Measuring Devices Micro-phasor Measurement Units

84. New Digital Sensing and Measuring Devices Optical Line Current Sensors Mounted on overhead lines to measure current digitally (using the Faraday effect ). Require 3 sensors for a 3-phase system. Work on lines from 120 V to 34.5 kV . Can also provide power quality (PQ) measurements with a PQ meter. Future potential for underground system use .

85. New Digital Sensing and Measuring Devices Optical Voltage Sensors Use the Pockels effect to measure voltage. Need 3 sensors for 3-phase systems. Currently applied on overhead lines . Future use: underground distribution systems .

86. New Digital Sensing and Measuring Devices Digital Pressure & Temperature Sensors Currently under research and development . Developed by utilities and equipment manufacturers . Not yet widely used in the industry. Expected to become common in the near future .

87. New Digital Sensing and Measuring Devices Evolving Digital Sensors Emerging sensors: high-frequency point-on-wave, dynamic high-range, optical PMU, MagSense . Future potential : Nanosensors for electrical & non-electrical measurements. Genetic/bacterial nanobionic sensors for faster, more precise, and accurate monitoring. Adoption expected as technology matures .

88. Emerging Protection System Design and Coordination Conventional protection may become obsolete due to system changes. DER deployment and inverter-based resources (IBRs) change system topology and complicate fault detection. Current-limiting inverters make fault detection harder; bidirectional current flow adds complexity. Future protection may rely on: Advanced methodologies Communication between system components Local & global coordination via computer systems Applicable to grids and microgrids for both planning and automation .