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Electrical DistributionSystem Protection

A Textbook and Practical Reference on Overcurrent and Overvoltage Fundamentals, Protective Equipment and Applications

Copyright 2005 All rights reserved Printed in the United States

""'

COOPER Power Systems

I

The information in this manual, while based on generally accepted fundamentals and practices, does not claim to cover all details or variations in the requirements and problems relating to electrical distribution-system overcurrent and overvoltage phenomena, and in the methods and equipment for dealing with such phenomena. Also, the examples ctted for achieving overcurrent and overvoltage protection are typical ones presented for illustration only, and their solutions should not be applied to specific situations without full consideration of all appropriate factors.

II

A Guide to the Manual The designer of an electrical distribution system must anticipate a variety of situations that might interfere with normal operation of the system. Among the most commonly encountered abnormal conditions are line faults and their resultant overcurrents, transient overvoltages, and system overloads. Generally, atmospheric disturbances-and, to a lesser extent, human and animal interference - are the underlying causes of faults and over-voltages. Line faults can be caused by strong winds that whip phase conductors together and blow tree branches onto lines. In winter, freezing rain can produce a gradual buildup of ice on a circuit, causing one or more conductors to break and fall to the ground. Squirrels and birds will sometimes produce line or ground faults by placing themselves between energized portions of the circuit and/or ground. On underground systems, the severing of cables by earth-moving equipment is a prevalent cause of faults. Lightning strokes can fault a system by opening lines or initiating arcs between conduc-

tors as well as by causing dangerous voltage transients ondistribution circuits. The primary cause of overloads is simply unforeseen or faster-thanexpected load growth, and equipment malfunction or failure also might overtax a system. Equipment failure can be caused by the improper design, manufacture, installation, or application of the equipment itself, and by lightning, insulation deterioration, and system faults. "Distribution-system protection" is the composite of all the measures taken on a given system to minimize the effects of the abnormal conditions described above. All of the conditions cannot be prevented from occurring at all times, but they can be controlled and contained-by protecting equipment and lines from damage to the fullest extent that technology and economics permit, and by limiting any interruptions of service to the smallest practical portions of the system and numbers of customers.

In this manual, prepared for system designers, protection engineers, and students, the general subject of distribution-system protection is broken into its two principal areas: overcurrent protection and overvoltage protection. Within each of these sections are detailed discussions of fundamentals and theory, equipment characteristics, and applications. A third section then covers the special considerations that must be taken into account in protecting systems with industrial loads, with dispersed generation, and with system automation. To guide you into the manual, presented below is a general listing of the three main sections, each of which contains a detailed table of contents.

Section A (Page 1) OVERCURRENT PROTECTION 1. Fundamentals and Theory 2. Protective Equipment Characteristics and General Application Factors 3. Protective Equipment Applications and Coordination 4. Summary of Protection for a Complete Distribution System

Section B (Page 167) OVER VOLTAGE PROTECTION 1. Fundamentals and Theory 2. Insulation and Surge Arrester Characteristics and General Application Factors 3. Surge Arrester Applications and Other Protection Details 4. Summary of Protection for a Complete Distribution System

Section C (Page 245) SPECIAL SYSTEM CONSIDERATIONS 1. Effects of Industrial Loads 2. Protection of Systems with Dispersed Storage and Generation 3. Protection of Systems with Automated Distribution

III

Section A OVERCURRENT PROTECTION

Table of Contents Page 1. FUNDAMENTALS AND THEORY Introduction . .. . .... . . ..... .. . . ....... .. .. ...... 5 Principles and Objectives .. . ..... . .. . ..... . .... ... 6 Distribution System Reliability . ................ ... . . .6 Performance Indices .. ..... . ..... . ............ .. 6 Feeder Length as a Factor in Reliability .... . ... . .. .. 7 Protection Concerns and Practices ........ . ...... . .. .7 Temporary vs. Permanent Faults ................ ... 7 Protecting Feeder Segments and Taps ..............7 "Protecting" and "Protected" Devices ... . ........... .8 Momentary Service Interruptions ..... . ... . ... . ...... 8 Tools for Fault Analysis ..... . ......... . ......... .9 Method of Symmetrical Components ......... ." ...... .9 Simplifying the Approach to Complicated Problems .. . ......................9 Balanced Systems in Symmetrical Components ..... .9 Relationships Between Symmetrical Components and Phase Quantities . . . .. . ............ . ......... 10 Example of Symmetrical Components Method ....... 10 Sequence Impedances ... ............ . ......... 11 The Per-Unit Method ...... . . .... . ................ 11 Single-Phase System Calculations . ...... ... . .. ... 12 Three-Phase System Calculations ................ 13 Use of Impedances in Fault Calculations ............. 14 Types of Distribution Circuits .... .. ............... 14 Impedances of Overhead Distribution Circuits ....... 14 Impedances of Underground Distribution Cable ...... 19 Equations for Calculating Sequence Impedances of Underground Concentric Neutral Cable .. . ....20 Effect of Cable Insulation . . ...... . ... ..........25 Effect of Neutral Size ............ ... .... ......25 Effect of Earth Resistivity ... .. .. . . . .. . .. .. .. ... 25 Effect of Interphase Spacing . . .. .. . . .......... .25 Skin Effect and Proximity Effect . . .. . . .. . .... .. . .26 Impedances of Transformers ............. .. . . ... .26 Impedances of Transmission Lines . . ........ . . ... .27 Impedances of Generators ... .. .... . .. . ....... ..27 Source Impedance ................ . ...... . .. . .29 Methods for Finding Source Impedance ........ . .30 Fault Impedance .. . .. . . . ... ... . . . . .. . .. . .. . .. .31 System Faults . . .... . .. . .. . ...... . . . . . . . .... . .. 33 Types of Faults .. . ... . ... .. . . ............... . ....33 Voltages at the Terminals of a Generator . .. ... . .. . .33 Equations for a Single Line-to-Ground Fault ... . .. . .. 34 Sequence Networks ...... . ........... . . . ...... 35 Equations for Other Fault Conditions . . .. . .... . .. . .36 Thevenin's Theorem . . . . ..... . ..... . ......... .36 Equations for Fault-Current Magnitudes ... . .. .. . .36 Asymmetrical Fault Current . .. . . . .... .. .. .. . . .... . .38 Definition and Significance . . .......... . ..... . . . .38 Application of Current Asymmetry Information . ...... 39 Motor-Current Contributions ......... . ............ .42 Fault Calculation Procedures and Examples ...........43 Assumptions ............ . .......... . . . .. . .. . .43 Basic Approach . . .. . ... .. . . . .. . . . ... . ... . . .. . .43 Example of Source-Impedance Calculation ..... . ... 44 Example of Distribution-System Calculation ........ .45 Computer Calculation of Fault Currents . ........ . .47 Index of Figures and Tables . .. . . . ....... . ... . . . . .50

2

Page 2. PROTECTIVE .EQUIPMENT CHARACTERISTICS AND GENERAL APPLICATION FACTORS ... 51 Introduction . .. . . . .. . ... . .......... . .. . ... . . .. .51 Fusing Equipment . . .. .. . .. ..... ... . . ...... . .... 52 Designs and Characteristics ........ . ......... . .... 52 Fuse Links ... . .... . ............. . .... .. ...... 52 Fuse Cutouts . . ... .. .. . ..... .. .. . .. . ... . ... .. .53 Current-Limiting Fuses .. ............... . .... . .. 54 Fuse Application Factors .. . ....... . ............ . .. 59 Fuse Cutouts/Fuse Links ..... . ..... . .. . .. . .. . . . .59 Fuse-Link Selection .. ..... . .... . ... . . .. .. . ... . .60 Current-Limiting Fuse Selection ........... . ...... 61 Automatic Circuit Reclosers ... . ..... . ...... .. .. . .62 Recloser Classifications ... . .... .. ...... . .. .. .... . .62 Single-Phase Reclosers . ... ... ... . .. . .. . . . .... .62 Three-Phase Reclosers . .. ................. . .... 64 Triple/Single Reclosers ............ . .... . ....... 64 Hydraulically Controlled Reclosers .. . . . . .. . .. . .... 65 Electronically Controlled Reclosers . .. .. .. . ... . .... 65 Types of Interrupters ... . .. . .... . .. . ....... .. . . .65 Types of Insulating Mediums ...... . . . ....... . . . .. 65 Recloser Locations and Functions .. . . . . ........ . .. .66 Pad-mounted Reclosers . .. .. ... . ............. . .66 Recloser Application Factors . . ..... . .. . ....... . .. . .66 System Voltage . .. .. . .. ...... . .. .. .... . ..... . .66 Maximum Fault Current ........ . ... . ...... . . . . . .66 Maximum Load Current ....... . .... . .. .. .. . ... . .66 Minimum Fault Current . . ........ . .............. 66 Coordination with Other Protective Devices . .. . . . . . .66 Dual Timing . . . .. . . .. .......... . ......... .. .67 Ground-Fault Sensing .. . .... . ..... . . . ........ . .67 Sectionalizers .. . .. . . . .. . . . ..... . ..... .. ........ 68 Sectionalizer Classifications ... . ... . .. . .. ... . ... ... 68 Hydraulically Controlled Sectionalizers . ..... . . . .. . .68 Electronically Controlled Sectionalizers ... . .... . .... 68 Sectionalizer Features .. .. .. . . ..... . .... . .... .. ... 68 Sectionalizer Application Factors .. .. . ....... . . . ..... 68 System VoHage .. .......... .. ...... . . . .. . .. . .. 69 Maximum Load Current . . .... . ........ . ......... 69 Maximum FauH Current . .. ......... . .. ... . . . . ... 69 Coordination with Other Protective Devices ...... . .. 69 Circuit Breakers and Relays . .. . ..................70 Circuit Breaker Characteristics and Classifications ...... 70 Circuit Breaker Ratings . .... . . . .. . ......... . ...... 71 Rated Maximum Voltage .. . ..... . .. . .... . .. .. ... 71 Rated VoHage Range Factor, K . .......... .. .... . .71 Rated Withstand Test Voltage, Low Frequency . . ..... 71 Rated Withstand Test Voltage, Impulse . .... .. ..... .71 Rated Continuous Current at 60Hz .. . . . ..........71 Rated Short-Circuit Current (at Rated Maximum kV) . . . ... . . .. . .. . . .. ...... 71 Transient Recovery Voltage, Rated Time to Point P ... 71 Rated Interrupting Time ... . ..... . ...............71 Rated Permissible Tripping Delay .... . ....... .. . . .71 Rated Maximum Voltage Divided by K ... . ...... . . .72 Maximum Symmetrical Interrupting Capability ....... 72 Three-Second Short-Time Current-Carrying Capability 72 Closing-and-Latching Capability . . ..... . ....... . .. 72 Types of Relays . .. . . .. .. . . ......... . .... . .. . . ...73 Overcurrent Relay . . .......... . .... . . . ... . .... : .. 73 Time-Current Characteristics ... . ... . ..... . ....... 73 Instantaneous Trip .. . ... . ... . ....... . .. .... .. ·. .75 Reset . ..... . .. . .. . ..... . . . . ... ...... . .... . .. 78

Section A OVERCURRENT PROTECTION

Page Reclosing Relay .................................78 Microprocessor Based Relay .....................78 Index of Figures and Tables ......................79 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Introduction ...................................81 Coordination Basics ............................82 Example of System Coordination ...................82 Fuse-Fuse Coordination .........................83 TCC Coordination Method .........................83 Use of Coordination Tables ........................ 84 Rules of Thumb .................................85 Current-Limiting Fuse Coordination ...............87 Source-Side Current-Limiting Fuse and Load-Side Expulsion Fuse ...............................87 Load-Side Current-Limiting Fuse and Source-Side Expulsion Fuse ..................... 87 Coordinating Two Current-Limiting Fuses ............. 88 Backup Current-Limiting Fuse and Expulsion Fuse ..... 88 Transformer Fusing .............................90 Developing a Transformer Fusing Philosophy .......... 90 Types of Fuses for Transformer Protection ............ 90 Capacitor Fusing ...............................98 General Criteria .................................98 Withstanding Steady-State and Transient Currents ...................................98 Effectively Removing a Failed or Failing Capacitor Unit .......................................98 Summary of General Criteria ....................98 Group Capacitor Fusing ..........................98 Continuous Current ............................98 Transient Currents .............................99 Fault Current .................................99 Tank-Rupture Curve Coordination ................ 100 Voltage on Good Capacitors .................... 100 Coordination with Upline Overcurrent Devices ...... 100 Summary of Group Fusing ..................... 100 Individual Capacitor Fusing ....................... 100 Continuous Current ........................... 100 Transient Currents ............................ 100 Fault Current ................................ 100 Tank-Rupture Curve Coordination ................ 103 Voltage on Good Capacitors .................... 103 Energy Discharge into a Failed Unit .............. 104 Outrush Current .............................. 104 Coordination with Unbalance Detection Scheme .... 104 Summary of Individual Fusing ................... 104 Recloser and Fuse-Link Coordination ............. 105 Recloser Coordination Principles* ................ 105 Recloser Ratings* ............................ 105 *Pertain Also to Other Recloser Applications

Use of Time-Current Curves with Adjustments ...... 111 Coordination with Source-Side Fuse Links ......... 111 Example of Source-Side Fuse and Recloser Selections ......................... 112 Coordination with Load-Side Fuse Links ........... 112 Example of Load-Side Fuse and Recloser Selections ......................... 112 Relay-Fuse Coordination ....................... 117 Relay and Source-Side Fuse Coordination ........... 117 Total Accumulated Time Method ................. 117 Cooling-Factor Method ........................ 117 Relay and Wad-Side Fuse Coordination ............. 121 Approaches to Temporary Fault Protection ......... 121 Recloser-to-Recloser Coordination ............... 125

Page Using Time-Current Curves ....................... 125 Hydraulically Controlled Reclosers Coordination Basics ........................... 125 Smaller Reclosers (Series Coil Operated} ......... 125 Larger Recloser (High-Voltage Solenoid Closing) .... 126 Electronically Controlled Reclosers Coordination Basics ........................... 126 Example of Electronic Recloser Coordination ....... 127 Alternate Coordination Scheme ................. 128 Features and Accessories for Electronically Controlled Reclosers .......................... 128 Sequence Coordination ........................ 128 Instantaneous Trip ............................ 128 Instantaneous Lockout ......................... 131 Instantaneous Trip/Instantaneous Lockout Combination ............................... 131 Reclosing Interval .............................. 131 Hydraulically Controlled Reclosers ............... 132 Electronically Controlled Reclosers ............... 132 Examples of Reclosing Intervals ................. 132 Recloser and Relay/Circuit Breaker Coordination ... 133 Microprocessor Overcurrent Relay ................. 133 Electro-Mechanical Overcurrent Relay .............. 133 Impulse Margin Time .......................... 133 Reset Time ................................. 134 Methods for Checking Relay and Downline Recloser Coordination ....................... 135 Recloser and Relay/Circuit-Breaker Coordination Analysis ....................... 137 Calculation of Relay Travel During Recloser Operation .................... 137 Sectionalizer Applications ...................... 138 Sectionalizer Coordination Principles ............... 138 Recloser and Hydraulically Controlled Sectionalizer Coordination ...................... 138 Coil Sizes ................................... 139 Memory Time ................................ 139 Voltage Restraint ............................. 140 Recloser and Electronically Controlled Sectionalizer Coordination ...................... 141 Selection of Actuating Levels .................. 141 Sectionalizer Features ....................... 141 Count Reset .............................. 141 Voltage Restraint .......................... 141 Count Restraint ........................... 142 Current Inrush Restraint ..................... 142 Ground-Fault Sensing ...................... 142 Recloser, Sectionalizer, and Fuse-Link Coordination ... 142 Recloser, Sectionalizer, and Recloser Coordination .... 143 Circuit Breaker and Sectionalizer Coordination ........ 143 Automatic Load Transfer ........................ 144 Switched Load Transfer Schemes .................. 144 Load Transfer Schemes Utilizing Reclosers .......... 144 Load Transfer with Manual Return ................ 144 Load Transfer with Automatic Return ............. 145 Loop Sectionalizing ............................ 147 Loop Sectionalizing Scheme with Three Reclosers .... 147 Loop Sectionalizing Scheme with Five Reclosers ...... 148 Loop Sectionalizing Scheme with Three Reclosers and Two Sectionalizers ........................ 149 Index of Figures and Tables ..................... 150 4. SUMMARY OF PROTECTION FOR A COMPLETE DISTRIBUTION SYSTEM Introduction .................................. 153

3

Page

Preliminary Considerations .....................154 Review of Principles ............................ 154 System Configuration and Data .................... 154 Protective Equipment Selections and Applications .. 156 Substation Transformer Protection .................. 156 Main Circuit Protection .....................•.... 157 Recloser and Relay/Circuit Breaker Coordination .... 157 Feeder Protection ....•......................... 158 Recloser-Sectionalizer Coordination ..........•... 159 Recloser-Recloser Coordination .........•....... 159 Ground-Fault Protection .....................•....160 Branch Protection .............................. 160 Recloser-Fuse Coordination ...•................. 161 Capacitor Fusing ............................... 163 Summary .........................•...........165

* * * REFERENCES AND CREDITS

4

264

Page

Section A OVERCURRENT PROTECTION

1. FUNDAMENTALS AND THEORY An Introduction A thorough understanding of fundamentals and theory is essential for effective handling of distribution-system protection problems. In order to minimize the undesirable effects an occasionally hostile environment can have on system performance, the designer or protection engineer must know the types of faults that can occur on the system and the nature of their cause, plus, of course, the probability and effects of lightning- and system-produced voltage surges (to be covered in Section B, Overvoltage Protection). This section on fundamentals and theory begins with introductory comments about the principles and philosophy

of overcurrent protection, which will be repeated and enlarged upon, as appropriate, in subsequent sections dealing with specifics. Detailed discussions of tools the designer may use for fault analysis are followed by descriptions of the various types of faults that may be encountered, presentation of a basic method for calculating the magnitude of overcurrent for different types of disturbances, and a discussion of the use of digital computers for analyzing complex systems. All of which is intended to provide a solid foundation for understanding and use of the equipment and application information in Sections A2 and A3.

Table of Contents, Page 2 Index of Figures and Tables, Page 50

5

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY

Principles and Objectives The overall objectives of overcurrent protection are the same as for all areas of distribution-system protection: to prevent damage to equipment and circuits, to prevent hazards to the public and utility personnel, and to maintain a high level of service by preventing power interruptions when possible and minimizing their effects when they do occur. Basic system planning for radial or network service, manual or automatic sectionalizing, etc., obviously plays a major role in achieving these objectives. The use of proper phase spacing and conductor insulation also contribute, as do such practices as periodic tree trimming, inspections for other potential problems, and equipment maintenance. These areas of planning and operation are mostly outside the scope of this manual, which focuses on the kinds of abnormal conditions that can occur, the methods for recognizing and analyzing these undesirable conditions, and the selection and application of protective equipment specifically designed to respond to them. In coping with the increased currents associated with system faults and overloading, the system designer must provide adequate protection for all types of distribution apparatus (transformers, capacitors, voltage regulators, etc.) as well as for all segments of the system itself. A variety of devices can be used, ranging from single-action fuses to automatic circuit reclosers and relay-controlled circuit breakers. All must be coordinated, with protective devices in many cases serving to protect other protective devices that function as backup guardians of equipment or circuits. The final system design will be influenced by economic and environmental factors, but the starting point for an effective system must be sound technical analysis.

DISTRIBUTION SYSTEM RELIABILITY All types of electric utility customers- residential, commercial, institutional, and industrial -are heavily dependent on the availability of electric power. For the residential customer, a loss of service affects just about every function and major device in the house, both those that are fully dependent on electric power (lighting, refrigeration, microwave ovens, televisions, air conditioners, home security systems, personal computers) and those that may be only partially dependent on electricity (furnaces, water heaters). Shopping centers suffer loss of sales and may have serious problems when outages occur during busy shopping periods. Schools may cease to function. Patient care is affected at health institutions. Industrial customers experience immediate financial loss as machines and processes shut down. With all of this, the individual electric utility customer has become very aware of and sensitive to any interruption of electrical service. Customer perceptions of service reliability are affected by both the frequency and duration of outages, and efforts to improve reliability must address both of these areas. Even momentary outages lasting less than 2 seconds can be as troublesome as sustained outages for some customers. Economics will of course be a factor in each utility's approach to reliability.

6

Performance Indices For discussion of outage rates, an outage is any complete loss of electric service, even for a second or less. To measure reliability in terms of recorded outages, performance indices frequently are used as described in IEEE 1366-1998 Guide for Power Distribution Reliability Indices. Use of these "standard" indices will permit comparisons between utilities or between different divisions of a given utility. More importantly, perhaps, it will allow evaluation of changes by a direct comparison of past and future performance of a feeder or system. These indices are typically calculated for a single feeder, an operating area, or the entire utility service territory. The several types of standard indices are: 1. System Average Interruption Frequency Index (SAIFI) defines the average number of times a customer's service is interrupted during a year for longer than 2 seconds. A customer interruption is defined as one interruption to one customer. SAIFI _ Total Number of Customer lnterr Total Number of Customers S

ions

2. System Average Interruption Duration Index (SAID I) defines the average interruption duration per customer served per year. SAlOl

=Sum of Customer Interruption Durations Total Number of Customers

3. Momentary Average Interruption Frequency Index (MAIFI) defines the average number of momentary interruptions (2 seconds or less) per customer interrupted per year. MAl Fl

=Total Number of Momentary Customer Interruptions Total Number of Customers Served

4. Customer Average Interruption Duration Index (CAIDI) defines the average interruption duration for those customers interrupted during a year. CAIDI _ Sum of Customer Interruption Durations - Total Number of Customer Interruptions 5. Average Service Availability Index (ASAI) defines the ratio of the total number of customer hours that service was available during a year to the total customer hours demanded (customer hours demanded = 24 hours/day x 365 days 8760 hours).

=

ASAI

= 8760- SAID I 8760

For example, a SAlOl (see number 2, above) of 1.0 hours per year produces: ASAI

= 87608760 - 1.0 = 99.989%

A1 Feeder Length as a factor in Reliability

uany utilities

have found that service reliability deteriorated slgnifk:;antly when they converted to a higher distribution voltage ,tor example, from 4 kV to 13 kV). The higher voltage allowed bnger feeders and more customers per feeder, but each outage aftected more customers, and longer feeders required more patrol time to locate the fault and take corrective action. Even without a change to higher voltage, service reliability can deteriorate as more customers are added to a feeder, and the feeder itself may be extended. To restore service reliability in such cases, an important first step is to sectionalize each feeder into smaller segments, thereby limiting the number of customers affected by a given ootage and reducing the subsequent patrol time. Operating experience of a number of utilities that have adopted this sectionalizing practice suggests that an optimum feeder segment in terms of load is 3 to 5 MVA. As the load of a line segment approaches 8 to 10 MVA, outage rates increase to unsatisfactory levels.

PROTECTION CONCERNS AND PRACTICES Temporary Versus Permanent Faults Most faults on overhead distribution systems are temporary perhaps as high as 70 to 80 percent. Also, of those faults categorized as permanent, at least one-third had initially been temporary (that is, lasting only a few cycles to a few seconds). A temporary fault is one whose cause is transitory in nature. Examples include momentary interruptions caused by two conductors being blown together, by a tree branch faling across two conductors and then dropping clear, and by a bird or small animal that briefly causes an arc from a live terminal to ground. If the arc that results can be cleared quickly, before it burns into a permanent fault, the cause of the fault is gone, no equipment damage has occurred, and the circuit can be re-energized immediately, restoring service to the entire system. Since the "open" time between fault interruption and re-energization is so brief, this type of incident is classified as a momentary outage. A permanent fault is one in which damage has occurred, either from the cause of the fault or from the fault arc. Examples include faults caused by a broken insulator, by a broken conductor, and by an automobile knocking down a pole. When a permanent fault occurs, the line must be deenergized, and a line crew must travel to the site and repair the damage. The time to restore service may range from 30 minutes to several hours; accordingly, the incident results in a recorded sustained outage.

Maximum service reliability is achieved when the distribution system is designed and operated to minimize the effects of any fault that may occur. Given the high percentage of temporary faults, two basic rules of distribution protec,ion emerge: 1. All faults must be given a chance to be temporary by providing a reclosing operation for a fault anywhere on the system. 2.1n responding to that low percentage of faults found to be permanent after the designated number of reclosing operations has been performed, the protective devices must remove from service only the smallest possible portion of the system necessary for isolation of the faulted segment.

Protecting Feeder Segments and Taps To minimize the effects of faults on the main feeder, sectionalizing devices (reclosers or sectionalizers, or a combination of the two) can be used to divide the feeder into the desired smaller segments. All taps running off the feeder should have a protective device (fuses for small taps, a recloser or sectionalizer for large taps) where they connect to the main feeder. Even on very small taps, a fuse should be used. The justification is that this type of fuse does not only protect the tap, but rather protects the remainder of the distribution feeder from a fault on the tap. Regardless of the extent of sectionalizing for a particular feeder, a combination of a recloser and fuses (Figure OA 1) and/or sectionalizers is typically used to protect a feeder segment and its taps against both temporary and permanent faults. The fast trip curve of the recloser is used to clear all transient faults on the main feeder and taps. For permanent faults on the taps, the recloser time-delay curve allows the tap fuse to clear, resulting in an outage on the tap only. Some additional steps that can be taken to minimize the effects of transient faults on sophisticated electronic and microprocessor-controlled devices is discussed below under "Momentary Service Interruptions."

Figure OA1. Reclosers and fuses protect feeder segment and taps against temporary and transient faults.

7

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Principles and Objectives (Continued)

"Protecting" and "Protected'' Devices In order to provide safeguards against unwarranted service interruption as just described as well as in other overcurrent protection situations, there must be a pairing or series of protective devices that have been selected to function in coordinated fashion. By conventional definition, when two or more protective devices are applied to a system, the device nearest the fault on the supply side is the "protecting" device, and the next nearest (that is, the closest device upline from the "protecting" device) is the "protected" or "back-up" device. See Figure 1A1. When properly coordinated, the protecting device will function before the protected device has an opportunity to do so, thereby limiting power interruption to the area served by the former. It should be noted that a protecting device might also function as a protected device if there are additional devices downline from it. This will be discussed in detail in Section A3, Protective Equipment Applications and Coordination.

,.

SUBSTATION ~

•

jllo

•

jllo

~

PROTECTING DEVICE

A

PROTECTED OR BACKUP DEVICE

C

1

-8

PROTECTING DEVICE

Figure 1A1. Conventional definitions of protective devices based on location. Fuse links are indicated for illustration.

MOMENTARY SERVICE INTERRUPTIONS In years past, momentary service interruptions as a result of temporary faults caused little or no customer concerns or inconvenience. In fact, when a brief power loss occurred and the only result was a dimming of lights or a momentary loss of service, there was a feeling of relief because there was no long-term outage.

8

Nowadays, however, a momentary service interruption disrupts the operation of computers, digital clocks, video recorders, microwave ovens, etc., and results in customer annoyance at having to reset and reprogram the equipment. The impact is even more severe for businesses, manufacturers, and other organizations that rely heavily on computers, digital controls, and automatic systems. Following are some of the steps that can be taken by electric utilities to control the number of momentary interruptions and limit their effects. 1. The application of recloser-control coordination accessories on substation and midline reclosers can provide complete coordination of protection devices, thereby reducing the number of both momentary and longer interruptions experienced by the feeder's customers. 2. Momentary interruptions can be reduced on main feeders by midpoint sectionalizing devices. By adding a midpoint recloser and providing trip coordination with the sourceside recloser, temporary faults downline from the midpoint recloser will not affect upline customers.

3. Critical industrial or commercial loads can be protected by installing a recloser on the main feeder just downline from the critical load. This reduces the fast-trip burden of the substation device and consequently the number of momentary interruptions experienced by the critical load.

4. Reclosers can be added to longer taps off main feeders to relieve the main feeder from momentary interruptions caused by downline faults on the tap. In addition to taking whatever steps are deemed appropriate to limit the number of momentary interruptions, electric power suppliers may want to consider communicating with customers on the relative desirability of such interruptions compared to long-term outages. Customers also might be made aware that they can purchase appliances and products with battery backup, or with circuitry that overrides brief power interruptions. For industrial and commercial customers, the ideal solution may be an uninterruptible power supply.

A1 Tools for Fault Analysis The design engineer can approach the challenging task of fault analysis with tools that have proved reliable in decades of application involving systems of all types and sizes. As discussed later, computer technology has provided additional tools in the form of general and customized programs, but there can be no substitute for a thorough understanding of the basic methods and approaches that follow.

METHOD OF SYMMETRICAL COMPONENTS Under normal operating conditions, a distribution circuit is essentially a balanced three-phase system. So long as the circuit remains balanced, the single-phase equivalent circuit is a powerful tool for simplifying fault analysis, but in more cases than not, system disturbances or faults create an unbalanced circuit. The method traditionally used to solve these problems of unbalanced three-phase systems has been the analysis of symmetrical components. In this manual, only the symmetrical component equations applicable to three-phase power systems will be discussed.

Simplifying the Approach to Complicated Problems The usefulness of the method of symmetrical components is that a complicated problem can be solved by vectorially summing the solution to three balanced network problems. success .lies in the ability to establish relatively simple Interconnections between sequence networks at the point of the fault for a limited number of unbalanced conditions. At any. given point in a balanced three-phase system, the currents 1n the three-phase conductors are equal in magnitude and separated by 120 degrees in phase angle. The same holds true for the phase-to-neutral voltages and the phaseto-phase voltages. (Figure 2A 1.)

!ts

Ia =II-¢

c

A

Ic = I LI1.Q:.Q_

lb=I~

PHASE-PHASE VOLTAGES:

Vab = Va-Vb= V3 V@ Voc = Vb-Vc =

V3

V /270

Vca=Vc-Va=V3 V~

Agure 2A1. Diagram of balanced three-phase system showing conductor and phase relationships.

It is assumed that the reader is familiar with complex number notation. Figure 2A 1 uses the polar form of this notation. The magnitudes of the phase voltages and currents are V and I respectively, and the magnitude of each phase-to-phas~ voltage is the square root of 3 V.

Load impedances in the figure are assumed to include line impedances. Note the distinction between balanced voltages and currents and balanced load. Load impedances in the three phases are equal in both magnitude and angle, whereas the voltages and currents have 120-degree phase separation. The virtue of working with balanced systems is that they can be analyzed on a single-phase basis, since the current in any phase is always the phase-to-neutral voltage divided by the single-phase load impedance. Separate calculation of currents in the two remaining phases is not necessary. This characteristic of balanced three-phase systems is the basis for the use of one-line diagrams in which a three-phase circuit is pictorially represented by a single line and standard symbols for transformers, switchgear, and other system components. In a balanced circuit (Figure 2A 1), the currents and voltages are not changed if neutral points NS and NL are grounded or connected with a neutral wire, because no potential difference can exist between NS and NL. However, this lack of potential difference will not, in general, hold true if the three-wire system is unbalanced in some way. Therefore, system conditions in the unbalanced situation will be affected if points NS and NL are connected. Truly balanced three-phase systems exist only in theory. In reality, many systems are very nearly balanced and, for practical purposes, can be analyzed as if they are truly balanced systems. However, there also are situations (unbalanced loads, unsymmetrical faults, open conductors, etc.) where the degree of unbalance cannot be neglected. Many of these situations involve a single point of unbalance on an otherwise balanced system, and these are the cases in which the method of symmetrical components finds ready application. The method permits the phasors of the unbalanced threephase system to be resolved into three balanced systems of phasors. The three balanced systems can then be solved independently and the results combined in a manner that depends on the type of unbalance.

Balanced Systems In Symmetrical Components The balanced systems of phasors used in three-phase symmetrical component analysis are (Figure 3A 1): 1. Positive-sequence components (denoted by the subscript 1), consisting of three phasors of equal magnitude and 120-degree phase separation, and having the same phase sequence as the original phasors. (May be denoted by the subscript p in other literature.) 2. Negative-sequence components (denoted by the subscript 2), consisting of three phasors of equal magnitude and 120-degree phase separation, and having a phase sequence opposite to that of the original phasors. (May be denoted by the subscript n in other literature.) 3. Zero-sequence components (denoted by the subscript 0), consisting of three phasors of equal magnitude and 360- or 0-degree phase separation. (May be denoted by the subscript z in other literature.) T~e p~asors illustrated in Figure 3A 1 are given voltage des1gnat1ons, but they could just as well be called currents. The subscripts correspond to the three phases of the system and show the differences among the three systems of components. The positive-sequence components have the

9

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

normal abc phase sequence, the negative-sequence components have the opposite abc phase sequence, and the zerosequence components are in phase and have no phase sequence. Vc,

{3)

NEGATIVE SEQUENCES POSITIVE SEQUENCES ZERO SEQUENCES

Figure3A1. Balanced systems of phasors used in three-phase symmetrical component analysis.

These equations permit converting any set of three-phase voltage (or current) phasors into their equivalent symmetrical components. Equations 2 and 3 are written in terms of voltage phasors, but they also apply to currents if the V's are replaced by l's.

Example of Symmetrical Components Method Consider a three-phase, four-wire circuit supplying a wye-connected load. If an open conductor exists in one phase, what are the symmetrical components of the currents in the remaining phases?

Relationships Between Symmetrical Components and Phase Quantities To transform from symmetrical components to phase quantities, the following relationships are used {References 1, 3, 4): Va = Va 1 + Va2 + Vao

=Vb 1 + Vb2 + Vb0 Vc =Vc 1 + V~ + Vc0 Vb

18

=a Va and Vc =aVa a =1 /120°, a2= 1 /240°

Vb1 where Also,

2

1

1

lb = 1 I -60°

(1)

But the quantities on the right side of these equations are not all independent. For example:

Ic

1

Ia 1 =3 {Ia + alb + a2Ic}

!{2l..illt}

Ia2

Va=Va 1 +Va2 +Va0 Vc

=aVa

1

+

a2Va

2

+ Vao

=.667/60° =~ {Ia + a Ib + ale} 2

=! {1 {/ 60° {2)

These equations show that, once the symmetrical components of the voltage (or current) of one phase of a system are known, the phase voltages {or currents) for all three phases can be found. To transform from phase quantities to symmetrical components, the following equations are used (References

1, 3, 4):

+ (1/120° X 1 I -60°) + 0}

=! {I 60°

These relationships can be verified by an examination of Figure 3A1. Substituting into Equation 1 provides

=a2Va 1 + aVa2 + Va0

+ {1 /240° X 1/ -60°) + 0}

=! {(.5 + j.866) + (-1 + jO)}

= ~ {-.5 + j.866}

=.333/120° lao=!

{Ia + Ib + Ic}

=~ {1/60° + 1/60° + 0°}

=~

{1

ill:}

=.333ffi:

10

0

From Equation 3:

=aVa2 and Vc2 =a2Va2 Vb0 = Vao and Vc0 =Vao

Vb

.5-j.866

1

Vb 2

and

= 1 /60° =.5+j.866

A1

= .5 + j.866

Sequence Impedances In general usage, the phrase "positive-sequence impedance" does not mean the positive-sequence component of an unbalanced set of impedances ~a, ~ b, and ~c. such as might be calculated from the expression(~ a+ a~ b + a2~ c)l3. Instead, the phrase means the impedance of a symmetrical three-phase circuit measured when energized by a positivesequence voltage source. For example, if a symmetrical three-phase line has all three phases shorted at one end and is energized by a balanced three-phase positive-sequence voltage at the other end, then only positive-sequence currents will flow in the three phases of the line. The phase A line-to-ground voltage at the input to the line divided by the phase A current will then be the positive sequence of the line. Similarly, the phrases "negative-sequence impedance" and "zero-sequence impedance" are shortened expressions for "impedance to negative-sequence current" and "impedance to zero-sequence current." The symbols normally used to designate positive-, negative-, and zero-sequence impedances are used here. These are, respectively, ~ 1, ~ 2, and ~ o. This material will consider only symmetrical, or balanced, circuits. For example, fully balanced distribution lines and balanced sources of supply are assumed. These are reasonable assumptions, and results based on them are sufficiently accurate for fault calculations. Also, these assumptions help demonstrate the method of symmetrical components without getting into the many complications of the method when working with unsymmetrical systems. In unsymmetrical systems, positive-sequence currents will, in general, produce negativeand zero-sequence voltage drops as well as positivesequence voltage drop. This means that the mutual coupling between the sequence networks must be defined. These mutual sequence impedances can be calculated, but with considerable difficulty, and as a result, the method of symmetrical components loses much of its usefulness. Most applications of the method are in the analysis of unsymmetrical faults, unbalanced loads, etc., on balanced systems. Therefore, the more involved aspects of symmetrical component theory, such as the mutual impedances between sequence networks, are not discussed. However, these are given considerable attention in some of the references, especially Edith Clarke (Reference 1).

= 1 I 60°

THE PER-UNIT METHOD

Expressing these results both graphically and numerically, the positive-sequence components are:

Ia 1 = .667 I 60°

lb 1 = a 21a1 = .667 I 300° lc 1

=ala 1 =.667 I 180°

Ib1 The negative-sequence components are:

Ia2 = .333 I 120°

lb 2 = ala 2 = .333 I 240° lc 2 = a 21a2 = .333 ~

The zero-sequence components are:

Once the symmetrical components are known, phase quantities can be determined by using Equations 2 or 1:

I~ ~

/

~

1

J

1 Ia = Ia 1 + Ia 2 + Ia0 -Ia = .667 I 60° +.333 I 120° + .333 L.Q:

Iaa

= ~ (.5 + j.866} +

~

(-.5 + j.866} +

~

(1 + iO)

= .667 I 300° + .333 I 240° + .333 f.JJ':_ = ~ (.5- j.866) +

~ (-.5 -

j.866} + ~ (1 + jO)

= .5- j.866 =11300°=11-60°

= .667 I 180° + .333 1...JL + .333 1...JL =0

Note that, even though the actual current in phase C is zero, its symmetrical components are not zero.

Computations with power systems involving two or more voltage levels are greatly simplified by the per-unit method. The value of the method can best be judged by actual experience, but some of the reasons for its usefulness are: 1. When a circuit element in a system of several voltage levels, such as a transmission line, has its impedance expressed in ohms, the ohmic value will vary as the square of the ratio of voltage levels as consideration moves from one level to another. In other words, the value of the ohmic impedance will change as the point of view of the line is changed from one side of a transformer to the other. So a problem in developing an equivalent circuit of a system in actual units is to select and identify a reference voltage and express all impedance elements in ohms as viewed from the reference voltage level. When impedances are expressed in per-unit on the appropriate base, this problem is eliminated. The per-unit impedance of the line viewed from one side of the transformer is the same as that viewed from the other side. 2. The per-unit impedances of machines of the same type and widely different rating usually lie within a narrow range, whereas their ohmic values can differ significantly. 11

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

3. Manufacturers usually specify the impedance of apparatus in percent or per-unit on the base of the nameplate rating. In analyzing a system containing apparatus, it is convenient to use these per-unit impedances either directly (if the apparatus ratings are equivalent to the system voltage and kVA base) or suitably modified to conform to the system bases.

4. In studying the performance of a system, the comparative importance of the values of such factors as voltage and current is more readily judged in the per-unit system, especially when the system has a multiplicity of voltage levels. For example, the significance of a 100-ampere current may be different in one part of the system than in another. Depending on the normal full-load currents of the circuits, the 100 amperes may represent a severe overload if it exists on one line and less than normal load on another line. In the per-unit system, the base currents are frequently closely related to full-load conditions. So in the first case cited, 100 amperes might be equivalent to 1.6 perunit current (60 percent overload), and in the second case, only 0.35 per-unit current. For this purpose, the numbers 1.6 and 0.35 per-unit are more meaningful measures of the significance of the current than 100 amperes. Consider the simple voltage-current-impedance equation E=lr where the units of E, I, and are volts, amperes, and ohms, respectively. Dividing both sides of the above equation by the same number does not destroy the equality. Call this number E8 , base voltage.

and defining VAs, the base power, in volt amps as VAa

=

I-r Es

Defining a base current IB and a base impedance subject to the condition Ea = Is-rs then

_§_

Es

Therefore

VApu

=

1000 Es Ia~ kVA 8 = Esls

Epu Ipu

= is

Is

=base current in amperes

-ra

= base impedance in ohms

Epu = lpu -rpu

Taking the power-voltage-current equation

(8) (9)

kVA 8 =base power in kilo volt-amperes. Similarly, the per-unit definitions (Equations 35 and 37) become

B,

= ~s

I lpu = Is -r -rpu = -rs

(4)

kVA kVApu = kVAs

{1 0)

Equations 10 are general expressions applicable in converting the per-unit calculations. Equations 8 and 9 apply only to single-phase systems.

-rpu =is and hence

(7)

=base voltage in kilo volts

where Es

Finally, the following per-unit (pu) quantities are defined: E Es

=

Voltage, current, power, and impedance are so related (Equations 4 and 6) that selection of base values for any two determines the base values of the remaining two. Usually, base power in kVA and base voltage in kV are the quantities selected to specify the base. In this case, Equations 4 and 6 become

= _N_

Is-rs

(6)

VApu

Epu

r

.E......L

= Ea Is

Thus, the per-unit VA power is defined as

r

E Es

VA VAs

provides

Eala

(5)

Single-Phase System Calculations For single-phase systems or three-phase systems where line current, voltage line-to-neutral, and kVA per phase are used, formulas relating the various base quantities are readily obtained, as follows: and hence kVAs = base kVA per phase or single-phase base kVA

VA= El Es

= line-to-neutral base voltage or singlephase base voltage in kV

Is = kfss = base line current in amperes

-rs =

12

2

~~;s = base impedance in ohms

1

(11)

A1 Three-Phase System Calculations In three-phase circuits, data are usually given as total three-phase kVA and line-to-line kV, and the above formulas do not apply. Hence, if the line-to-line voltage and total threephase kVA are specified, the following formulas are used to find base quantities instead of Equations 11 :

If n is the transformer turns ratio, Ep and Es are the primary and secondary voltages in kV, respectively; Ip, and Is are primary and secondary currents in amperes, respectively; and ~ is the load impedance in ohms, then the following relationships can be written: Ep = nEs

kVAs = three-phase base kVA E9

1 Ip = nis

= line-to-line base voltage in kV

Is = kVAs = base line current in amperes V3Es 2

-r9 - 1000Es = base impedance in ohms kVA 9

(12)

Once the base quantities are selected, then the per-unit quantities are immediately obtained from Equations 10, so long as the units for E, I, -r, and kVA in a three-phase system calculation are line-to-line kV, amperes, ohms, and threephase kVA, respectively The per-unit impedance of a circuit element is: -r u = (actual impedance in ohms) X (base kVA) = -r kVAs P (base voltage in kV)2 X 1,ooo 1,ooo (13)

-rviewed from primary= n2 -r

and, therefore,

Now, choosing the base power kVAs the same for both sides of the transformer and the base voltage EpB and EsB so that they have the relationship

Es

EpB = nEsB then the base impedances are (from Equation 11)

where base can be either line-to-neutral voltage and singlephase kVA, or line-to-line voltage and total three-phase kVA. To change from per-unit impedance on a given base to per-unit impedance on a new base, the following formula applies:

~new= ~old pu

pu

(base kvold ) base kvnew

2

X (base kVAnew)

(15)

-rPs = 1OOOE~ 9 kVAs

(16)

and

base kVAold

(14) As noted initially, an advantage of the per-unit method is realized when the proper voltage and kVA bases are selected on the two sides of a transformer. When the kVA bases are identical and the base voltages are chosen in the same ratio as the line-to-line voltage transformation ratio (which is the same as the transformer turns ratio in delta-delta and wye-wye connections), then the per-unit value of an impedance on one side of the transformer will not change when it is viewed from the other side. This can be verified by considering a singlephase ideal (zero-impedance) transformer serving a load impedance, ~ (Figure 4A 1).

-

Is

-r

1000E§ B

=

1000(E~2

kVAs

n

kVAs

(17)

Using Equation 17, the per-unit value of load impedance viewed from the secondary is -rpu

viewed from secondary

=

1000 E~

-r =r Ss

B

and, from Equations 15 and 16, the per-unit value of ~ viewed from the primary is _,._ . . L.vtewed from pnmary -r pu viewed from primary = -r PB

=

n:1

s9 =

n2-r -rpB

= -rn 2kVAs 1000 Ep 2 B

Fagure 4A1. Diagram of single-phase transformer with zero impedance serving a load impedance.

= -r pu viewed from secondary Therefore, by properly choosing the voltage and power bases, the per-unit value of an impedance on one side of a transformer can be used directly on the other side.

13

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

USE OF IMPEDANCES IN FAULT CALCULATIONS The impedance information necessary to conduct a fauH study includes the system sequence impedances viewed from each of the fault points to be considered, and the value of fault impedance, ::Z: , associated with each type of fault. The sequence impedances of the system are independent of the type of fault. To find system impedance, first identify the individual components of the system: e.g., underground cable, overhead lines, transformers, generators, etc. Next, the sequence impedances of the individual components are determined, normally through the use of tables and formulas. Finally, the component impedances are combined to produce the equivalent sequence impedances of the system, taking into account any series-parallel connections and the various voltage levels between the point being studied and the source.

Types of Distribution Circuits The impedance of a distribution circuit is markedly affected not only by conductor material, size, and spacing, but also by such factors as the presence or absence of a neutral conductor, the nature of system grounding, and the transformer connection at the distribution substation. These factors are what distinguishes one type of distribution circuit from another. Following are diagrams of the types of distribution circuits:

1. Four-wire multigrounded-neutral system

.----------------------------------A ~---------------------------8

e---------------------------------C r-------------------------------------A

2. Four-wire unigrounded-neutral system

~----~----------------------B

)-----------------------N ._-----------------------------c 3. Three-wire unigrounded system .----------------------------------A

e--------------------------------c 4. Three-wire system served from an ungrounded, delta-connected transformer

14

5. Three-wire system served from an ungrounded, wyeconnected transformer

.----------------------------------A

e------------------~----------c

Additional classifications of circuits involving various combinations of one or two phase conductors and a neutral could be identified, but these exist in practice only as two-phase or si~gle-phase laterals tapped off of one of the above systems. So s1ngle- or two-phase laterals are not described here as separate types of distribution circuits, but rather are referred to in terms of the type of circuit from which they are supplied. For example, in studying a lateral consisting only of two phase conductors, one must know whether it is served by a grounded system (Types 1, 2, and 3) or an ungrounded system (Types 4 and 5), since both impedances and fault levels are affected. In the United States, the most common type of primary distribution circuit is the multigrounded neutral system (Type 1). This is true for both overhead and underground. .In some .areas, however, some of the other circuit types are still extenstvely used. For example, countries in the Far East including Australia, predominantly utilize a three-wir~ u.nigrounde:d system and can have distribution feeders many kilometers 1n length. These systems are characterized by low fault currents and fuses cannot be used effectively for ground-fault protection; however, single-phase tap dropping and load switching are minor considerations. . In the future, as a greater share of the distribution system 1s placed underground, dominance of the multi-grounded neutral system will increase, since most underground primary cable installations use bare neutral wire in continuous contact with the ground.

Impedances of Overhead Distribution Circuits The sequence impedances of an overhead primary circuit operating at a constant frequency are dependent on several factors. Principal factors are the size, material, and spacing or configuration of the phase and neutral conductors, and the type of distribution circuit. Lesser factors include stranding of the conductors, conductor height above ground, conductor temperature, and resistivity of the earth. The problem of identify~n~ the impedances for ~ given circuit involves, first, determ1n1ng values for these vanous factors, and then finding the corresponding impedances in published tables or by utilizing impedance equations. The use of published tables is the most common approach to this problem. Its degree of accuracy depends, of course, on how close a match there is between the values of the various factors for the circuit in question and the values of the factors used in preparing the tables. In many situations, the match is close enough for the results to be considered sufficiently accurate for fault calculations. In other situations, a close match between all of the factors i~ lacking and the amount of error introduced by the tables is either large or unknown. In these cases, impedance formulas must be used. Although the application of these formulas will not be covered in this publication, the reader should be aware of their. existence (References 1, 3, 4) and of their ready adaptation to computer programs for calculating impedances of overhead circuits.

A1 Tables 1A1, 2A1, and 3A1 present values of positive-and zero-sequence impedance of overhead distribution circuits for some typical conductor sizes and spacings of three varieties of canductors: copper, ACSR (aluminum cable, steel-reinforced), and bare all-aluminum. Negative-sequence impedances of '!li!l:anSmission and distribution lines are equivalent to positivesequence values. The tables give zero-sequence impedances of 1hree-phase, three-wire circuits, and of three-phase, four-wire ~unded-neutral circuits. Thus, the sequence impedances of iour of the five types of distribution circuits described earlier ,can be obtained from these tables, assuming the various spacing, temperature, and other factors are applicable. Of ::::ourse, it would not be necessary to know the zero-sequence mpedance of a three-wire circuit if the source is ungrounded :"""ypes 4 and 5). The only circuit type not adequately covered Of these tables is the four-wire unigrounded-neutral system ("Type 2). Even in this case, the tables are applicable in caiCUiiating three-phase and line-to-line faults, since those n.ooNe only positive-sequence impedance. Also, the tables ::an be used for calculating one class of single-phase faults on this type of circuit: that is, faults that involve a phase conductor and ground but do not involve the neutral wire. In such ::ases the return path for fault current is only through ground and we have essentially a Type 3 circuit. The zero-sequence impedance for this type of circuit is included in the tables. The data of principal importance in the tables are the ~nee and reactance components of the sequence i'npedances. The impedance magnitudes (columns labeled Z 1 Z 2 and :Z:. o) are also given, but these will rarely be of use in fault calculations. Calculating fault current at a given location on a radial system can involve addition of many irnlpedances between the location and the source. This must be done by adding resistances and reactances independently; 1lha:t is, the rectangular coordinate form (R+jX) of the complex runbers must be retained. Addition of impedance magnitudes , :Z:. values in the tables) will, in general, give incorrect results, since the angles of the polar coordinate form of the impedances ot various system components will vary widely. The impedance magnitudes are included in the tables, since they do permit a qualitative evaluation of the effect of going from one conductor size to another or going from one type of distribution circuit to another. For example, a comparison of Z O's in the tables makes it clear that the magnitude of the zero-sequence impedance of a circuit is significantly reduced when a l'1l'lllltigrounded-neutral wire is added to a three-wire unigrounded system. The positive-sequence impedance of a circuit is usually a iunction of the characteristics and configuration of the phase conductors only. The type of grounding and the existence or absence of neutral has, for most overhead circuits, a negligibie effect on positive-sequence impedance. However, the neutral conductor, the type of grounding, and the phase conductors all influence the value of zero-sequence impedance. This is implied by Tables 1A 1. 2A 1 and 3A 1, since separate positive-sequence values for the three-wire unigrounded and flour-wire multigrounded-neutral systems are not given and are not needed. This can be readily verified by the impedance equations used to develop such tables. (References 1.3,4.)

=

A few words are needed about the effect on :Z:. 1 and :Z:. 2 of the spacing of phase conductors. Tables 1A 1, 2A 1 and 3A 1 are based on geometric mean spacing of 4.69 feet among the three-phase conductors. That is, the three-phase conductors are assumed to have an average spacing of 4.69 feet, and this average is a geometric mean, not an arithmetic mean. The term "equivalent delta spacing" is sometimes used instead of geometric mean spacing. For example, if the configuration of the phase conductors of an actual circuit is as shown in Figure 5A 1, the impedance calculation is simplified (without introducing significant error) if the spacing is assumed to be at the corners of an equilateral triangle, as in Figure 6A 1. This equivalent delta spacing is found by calculating the geometric mean of the three actual spacings: Geometric Mean Spacing = (3 X 2.67 x 5.67)1/3 = 3.57 feet The tables show how the tabulated reactances (X 1 and X2) can be changed if the geometric mean spacing of the circuit under study is different from the 4.69 feet used in the calculations. For example, three 4/0 copper conductors with the spacing shown in Figure 5A 1 would have a positivesequence impedance, as

:z:. = .0574 + j (.1294-.0064) = .0574 + j.1230 ohms/1000 ft where the reactance is modified by the .0064 ohms/1 000 ft to account for the spacing change from 4.69 feet to approximately 3.5 feet.

1 '1• ""1• 2

3

• A

8

C

Figure 5A1. Actual configuration of phase conductors referred to in Figure 6A1.

c

• 8

Figure 6A1. Assumed configuration of phase conductors for simplified impedance calculation.

15

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

TABLE 1A1 Impedance of Copper Conductor in Ohms/ 1000 Feet Three-phase Geometric Mean Spacing: 4.69 feet* Line-to- Neutral Spacing: 4.00 feet Earth Resistivity: 100 meter-ohms Conductor Temperature: 50°C Phase Conductor Wire Size 500,000 CM 450,000 400,000 350,000 300,000 250,000 4/0 3/0 2/0 1/0 1 2 3 4 6 8

Positive- and NegativeSequence Impedance Components Strands R1 19 19 19 19 19 19 19 12 7 7 7 7 3 1 1 1

=R2

.0246 .0273 .0307 .0348 .0407 .0487 .0574 .0723 .0911 .1150 .1449 .1809 .2280 .2847 .4527 .7197

x,

=x 2

.1195 .1206 .1220 .1235 .1254 .1275 .1294 .1309 .1360 .1386 .1413 .1434 .1460 .1506 .1559 .1612

r,

=

Zero Sequence Phase Impedance Com&onents Conductor for Three-Wire ircults Wire Size r2 Ro Xo ro

.1216 .1252 .1258 .1284 .1318 .1364 .1415 .1494 .1640 .1799 .2027 .2301 .2708 .3220 .4792 .7405

.0788 .0814 .0848 .0892 .0949 .1028 .1116 .1265 .1453 .1691 .1991 .2350 .2822 .3388 .5068 .7739

.5606 .5617 .5631 .5646 .5665 .5686 .5705 .5720 .5771 .5795 .5824 .5845 .5871 .5917 .5970 .6023

.5663 .5682 .5691 .5701 .5739 .5777 .5795 .5862 .5947 .6023 .6155 .6307 .6496 .6818 .7831 .9820

*For geometric mean spacing of 4.0 ft. , subtract .0034 from X1 = X2 and solve for r 1 = r 4 For geometric mean spacing of 3.5 ft. , subtract .0064 from X1 = X2 and solve for r , = r2 For geometric mean spacing of 3.0 ft., subtract .0100 from X1 = X2 and solve for r 1 = r 2 For geometric mean spacing of 5.0 ft., add .0017 to X1 = X2 and solve for r, = r 2

r =v R2 + X2

The error involved in using a representative spacing (such as 4.69 feet) instead of the geometric mean spacing of the actual circuit can be considerably damped out in the final faultcurrent calculation. For example, if the actual spacing is 3 feet but 4.69 feet is assumed, an error in spacing of more than 50 percent is introduced. For the conductor sizes in Tables 1A1, 2A 1 and 3A 1 , the error in impedance magnitude produced by this assumption ranges from 0.2 to 8.8 percent. This same percentage of error would be reflected in the fault-current magnitudes if no other impedances were required in the fault calculations, but generally this is not the case. A fault calculation at a given location on a radial system must include the effect of all impedances between the location and the source. Only

16

500,000 CM 500,000 500,000 450,000 450,000 450,000 400,000 400,000 400,000 350,000 350,000 350,000 300 ,000 300,000 300,000 250,000 250,000 250,000 4/0 4/0 4/0 3/0 3/0 3/0 2/0 2/0 2/0 1/0 1/0 1/0 1 1 1 2 2 2 3 3 3 4 4 6 8

Zero-Sequence Impedance Neutral Components for Four-Wire Wire Multi-Grounded Neutral Circuits Size 2/0 1/0 1 2/0 1/0 1 2/0 1/0 1 2/0 1/0 1 2/0 1/0 1 1/0 1 2 1/0 1 2 1/0 1 2 1 2 3 2 3 4 2 3 4 2 3 4 3 4 6 4 6 6 8

Ro

Xo

ro

.1053 .1254 .1311 .1081 .1205 .1337 .1114 .1239 .1371 .1157 .1282 .1413 .1216 .1341 .1472 .1419 .1551 .1669 .1506 .1638 .1754 .1653 .1786 .1902 .1973 .2089 .2205 .2328 .2443 .2477 .2629 .2744 .2778 .2987 .3102 .3155 .3574 .3608 .3619 .4176 .4188 .5879 .8420

.3451 .3553 .3672 .3462 .3564 .3684 .3475 .3580 .3697 .3491 .3598 .3712 .3511 .3614 .3733 .3633 .3752 .3922 .3652 .3771 .3828 .3667 .3786 .3956 .3837 .4008 .4212 .4034 .4239 .4455 .4061 .4265 .4481 .4080 .4284 .4500 .4313 .4528 .4822 .4574 .5057 .5108 .5580

.3598 .3741 .3905 .3627 .3769 .3920 .3646 .3778 .3943 .3665 .3826 .3968 .3722 .3854 .4006 .3902 .4053 .4261 .3949 .4110 .4205 .4019 .4186 .4390 .4347 .4527 .4777 .4659 .4905 .5080 .4848 .5076 .5265 .5047 .5294 .5511 .5606 .5777 .6042 .6203 .6553 .7784 1.0114

a portion of the total system impedance viewed from the fault point may have the 0.2 to 8.8 percent error. The error in the fault current will be smaller than this, depending on the share of the total system impedance associated with the line section whose spacing is in error, and also depending on the zero-sequence impedance and fault impedance, if any, used in the fault calculation. Therefore, if the share of the total system impedance involved is small, there is no need to worry about allowing, for example, a fifty-percent error in conductor spacing for a small portion of an overhead distribution circuit. But when all or a large portion of the circuit is involved, then the tabulated impedances should be modified to agree with the spacing of the actual circuit.

A1 DBLE 2A1 llnpedance of ACSR Conductor in Ohms/1 000 Feet

1'1ne-phase Geometric Mean Spacing: 4.69 feet*

Ealt1 Resistivity: 100 meter-ohms

I

...... 1IWe Size

tns.ooo CM 715.000 &6..600 &36.000 lliD5_000

556..500 5DO.OOO .:rl,OOO '31JT,500 336,400 3DO,OOO 2&6,800

4oiD

:w 2)10 1A)

1

2 3 4

6

Positive- and NegativeSequence Impedance Comoonents Strands R1 = R2 = 2 ~, = ~2

x, x

26 26 54 26 26 26 30 26 26 26 26 26 6 6 6 6 6 6 6 6 6

.0244 .0273 .0303 .0307 .0326 .0352 0390 .0409 .0491 .0580 .0648 .0729 .1121 .1369 .1695 .2121 .2614 .3201 .3920 .4867 .7538

.1108 .11 19 .1133 .1133 .1138 .1148 .1150 .1167 .1188 .1206 .1220 .1233 .1453 .1528 .1566 .1595 .1612 .1612 .1604 .1600 .1627

.1138 .1153 .1170 .1172 .1188 .1203 .1214 .1239 .1284 .1341 .1379 .1430 .1833 .2055 .2311 .2655 .3078 .3570 .4233 .5133 .7689

Line-to- Neutral Spacing: 4.00 feet Conductor Temperature: sooc

Zero Sequence Impedance Com~nents for Three-Wire ircults ~0 Xo Ro

.0786 .0814 .0845 .0848 .0867 .0894 .0932 .0951 .1032 .1121 .1189 .1271 .1663 .1911 .2237 .2663 .3155 .3742 .4462 .5409 .8080

.5871 .5883 .5896 .5896 .5902 .5911 .5913 .5930 .5951 .5970 .5983 .5996 .6216 .6292 .6330 .6358 .6375 .6375 .6367 .6364 6390

.5928 .5938 .5947 .5947 .5966 .5975 .5994 .6004 .6023 .6061 .6098 .6136 .6420 .6572 .6705 .6894 .7121 .7424 .7765 .8371 1.0303

I I

I

I

! I

I I

Phase Conductor Wire Size

795,000 CM 795,000 795,000 715,000 715,000 715 ,000 666,600 666,600 666,600 636,000 636,000 636,000 605,000 605,000 605,000 556,500 556,500 556,500 500,000 500,000 500,000 477,000 477,000 477,000 397,500 397,500 397,500 336,400 336,400 336,400 300,000 300,000 300,000 266,800 266,800 266,800 4/0 4/0 4/0 3/0

310 310

I I

I I

: I I

I

, *For geometric mean spacing of 4.0 ft. , subtract .0034 from X1 = X 2 and solve for ~ 1 = ~ 4

For geometric mean spacing of 3.5 ft., subtract .0064 from X 1 = X 2 and solve for ~ 1 = ~ 2 For geometric mean spacing of 3.0 ft., subtract .01 00 from X1 = X2 and solve for ~ 1 = ~ 2 For geometric mean spacing of 5.0 ft., add .0017 to X 1 = X2 and solve for ~ 1 = ~ 2 ~ =v R2 + X2

2/0 2/0 2/0 1/0 1/0 1/0 1 1 1 2 2 2 3 3 3 4 4 6

Zero-Sequence Impedance Neutral Components for Four-Wire Wire MuHi-Grounded Neutral Circuits Size Ro ~0 Xo

4/0

310 2/0 4/0 3/0 2/0 4/0 3/0 2/0 4/0 3/0 2/0 4/0 3/0 2/0 4/0 3/0 2/0 4/0 3/0 2/0 3/0 2/0 1/0 3/0 2/0 1/0

310 2/0 1/0 2/0 1/0 1 2/0 1/0 1 1/0 1 2 1/0 1 2 1 2 3 2 3 4 2 3 4 2 3 4 3 4 6 4 6 6

.1144 .1233 .1337 .1172 .1261 .1367 .1203 .1292 .1398 .1206 .1295 .1400 .1225 .1314 .1419 .1252 .1341 .1445 .1292 .1381 .1487 .1398 .1504 .1614 .1477 .1583 .1693 .1568 .1672 .1784 .1742 .1852 .1943 .1822 .1934 .2023 .2324 .2415 .2447 .2574 .2665 .2697 .2989 .3021 .3025 .3447 .3451 .3443 .3941 .3945 .3938 .4528 .4632 .4525 .5252 .5244 .5102 .6193 .6051 .8722

.3494 .3617 .3761 .3506 .3629 .3773 .3519 .3642 .3786 .3519 .3642 .3784 .3525 .3648 .3792 .3534 .3657 .3801 .3536 .3659 .3803 .3676 .3820 .4008 .3697 .3841 .4028 .3716 .3860 .4047 .3873 .4061 .4248 .3886 .4074 .4261 .4294 .4481 .4652 .4369 .4557 .4727 .4595 .4765 .4970 .4794 .4998 .5214 .4811 .5015 .5231 .4811 .5015 .5231 .5008 .5223 .5553 .5220 .5549 .5576

.3625 .3807 .3977 .3703 .3835 .4019 .3722 .3872 4034 .3722 .3867 .4034 .3722 .3883 .4049 .3750 .3898 .4072 .3769 .3924 .4091 .3930 .3939 .4318 .3977 .4153 .4375 4025 .4195 .4428 .4244 .4470 .4661 .4545 .4492 .4706 .4879 .5085 .5246 .5076 .5275 .5445 .5483 .5610 .5814 .5909 .6117 .6241 .6222 .6383 .6534 .6610 .6629 .6932 .7254 .7008 .7500 .8068 .8210 1.0199

17

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

TABLE 3A1 Impedance of Bare All-Aluminum Conductor in Ohms/ 1000 Feet Three-phase Geometric Mean Spacing: 4.69 feet• Line-to- Neutral Spacing: 4.00 feet Conductor Temperature: sooc Earth Resistivity: 100 meter-ohms Phase Conductor Wire Size Strands 795,000 CM 37 37 750,000 37 715,000 700,000 61 37 636,000 61 600,000 37 556,500 37 500,000 37 477,000 450,000 37 37 400,000 397,500 19 37 350,000 37 336,400 37 300,000 37 266,800 37 250,000 19 4/0 19 3/0 19 210 1/0 19 7 1 7 2 7 3 4 7 7 6

18

Positive- and NegativeSequence Impedance Components

= R2 .0248 .0263 .0277 .0282 .0309 .0328 0352 .0392 .0411 .0436 .0498 .0492 .0557 .0580 .0650 .0731 .0778 .0920 .1159 .1466 .1845 .2330 .2934 .3701 .4661 .7424

R1

=X2 .11 38 .1 146 .1150 .11 52 .1163 .1169 .1180 .11 89 .1 195 .1203 .1214 .1220 .1231 .1237 .1252 .1265 .1271 .1 284 .1 311 .1347 .1377 .1413 .1 428 .1466 .1 492 .1547

x1

Zero Sequence Zero-Sequence Impedance Phase Neutral Impedance Components Conductor Components for Four-Wire Wire for Three-Wire Circuits Multi-Grounded Neutral Circuits Wire Size Size Ro ~1 = ~2 Ro ~0 ~0 Xo Xo .1165 .0792 .5549 5597 795,000 CM 4/0 .1095 .3314 .3485 .1174 .0805 .5555 5606 795,000 .3451 3/0 .1220 .3636 .1 184 .0818 .5561 .5625 795,000 210 .1237 .3604 .3807 .1 186 .0824 .5563 .5634 750,000 .3322 4/0 .1110 .3504 .1199 .0850 .5574 .5644 750,000 .1235 .3958 .3665 3/0 .1216 .0869 750,000 210 .1366 .3610 .5580 .5653 .3866 .1233 .0894 .5591 .5663 715,500 .1123 .3326 .3513 4/0 .0934 .5600 .5682 715,500 .1250 .1254 .3462 3/0 .3684 .1263 .0953 .5606 .5691 715,500 210 .1384 .3616 .3873 .1278 .0977 .5614 .5701 .1129 .3519 700,000 4/0 .3328 .1309 .1030 .5626 .5710 700,000 .1254 .3464 .3689 3/0 .1034 .5631 .1316 .5720 700,000 .1384 .3617 .3877 2/0 .1 347 .1098 .5642 .5739 636,000 4/0 .1155 .3339 .3532 .1366 .1121 .5648 .5758 636,000 .1280 .3475 .3712 3/0 .1407 .1191 .5663 .5795 636 ,000 .1411 .3629 210 .3902 .1460 .1273 .5676 .5814 600,000 .1172 410 .3345 .3542 .1489 .1320 .5682 .5833 600,000 .1299 .3722 3/0 .3481 .1580 .1462 .5706 .5890 .1430 .3634 .3911 600,000 210 .1744 .1703 .5720 .5956 556,500 .1197 .3551 4/0 .3356 .2008 556,500 .1989 .5758 .6117 .1324 .3492 .3741 3/0 .2301 .2386 .5788 .6307 556,500 .1455 2/0 .3646 3939 .2731 .2871 .5824 .6496 500,000 4/0 .1237 .3366 .3580 .3475 .3263 .5839 .6970 500,000 .1364 .3759 310 .3502 .4242 .5877 .7254 .1494 .3655 .3958 .3981 500,000 210 .4886 .5203 .5903 .7879 477,000 .1383 3/0 .3508 .3769 .7968 477,000 .1515 .3661 .3968 .7576 .5958 .9962 2/0 477,000 .1640 1/0 .3843 .4186 450,000 .1407 .3515 3/0 .3788 450,000 .1538 .3669 .3996 210 450,000 .1663 .3850 .4205 1/0 .3527 400,000 .1460 3/0 .3816 400,000 210 .1591 .3680 .4006 .1716 .4223 400,000 1/0 .3862 397,500 .1464 3/0 .3532 .3826 397,500 2/0 .1595 .4025 .3686 397,500 1/0 .1720 .3867 .4233 350,000 .3544 3/0 .1528 .3854 350,000 210 .1659 .3697 .4044 .1765 350,000 1/0 .3879 .4261 .1551 .3549 .3873 336,400 3/0 336,400 .1682 2/0 .3703 .4072 336,400 1/0 .1807 .3884 .4299 300,000 2/0 .1752 .3718 .4110 300,000 1/0 .1877 .4337 .3900 300,000 .4451 1 .1979 .4150 .1833 .3731 .4148 266,800 210 266,800 1/0 .1958 .3913 .4375 1 .2061 .4163 .4640 266,800 .1881 250,000 2/0 .3737 .4167 250,000 1/0 .2006 .3919 .4394 250,000 .4169 1 .2108 .4659 4/0 1/0 .2148 .3936 .4489 4/0 .4754 1 .2250 .4182 4/0 .2301 .4962 2 .4388 3/0 1/0 .2388 .3958 .4621 .2491 .4208 3/0 1 .4886 3/0 2 .2542 .4413 .5095 1 .4244 210 .2795 .5098 210 2 .2847 .4449 .5284 .2854 .4705 210 3 .5492 1/0 2 .3225 .4483 .5511 1/0 .4735 3 .3233 .5739 1/0 4 .3203 .4968 .5928 (Continued on Next Page)

A1 TABIL.E 3A1 (continued) ~ce of Bare All-Aluminum Conductor in Ohms/ 1000 Feet

I Phase ~ ~or

I '

Positive- and NegativeZero Sequence Neutral Phase Sequence Impedance Impedance Components Conductor Wire for Three-Wire Circuits Strands Components Size Wire Size Size R1 = R, 1 X1 = X2 1~ 1 = ~ ~n Ro I Xn I 2 •For geometric mean spacing of 4.0 ft., subtract .0034 from X1 = X2 and 1 solve for ~ 1 = ~ 2 3 1 1 4 For geometric mean spacing of 3.5 ft., subtract .0064 from X1 = X2 and 2 2 3 solve for ~ 1 = ~ 2 2 4 2 3 For geometric mean spacing of 3.0 ft., subtract .01 00 from X1 = X2 and 3 solve for ~ 1 = ~ 2 4 3 6 3 4 For geometric mean spacing of 5.0 ft., add .0017 to X1 = X2 and 4 solve for~ 1 = ~ 2 4 6 6 6 ~=v'R2+X2

1 a dances of Underground Distribution Cable

Aft measing number of primary distribution circuits involve a mixture of both overhead conductor and underground CiiiJie.. Fault calculations for such circuits require a knowledge al lhe sequence impedances of the underground as well as allhe overhead portions of the circuits. Sequence impedances of overhead lines can readily be ablained from published equations (References 1, 3, and 4) ar Tables 1A 1 through 3A 1. These references do not apply, IIIEMever, to concentric neutral cable, the type of cable most CDimlOflly used fo r underground distribution. To help fill this gap. the following material discusses the use of equations Cll!laEd specifically for calculation of the sequence impedances of concentric neutral underground cable for both three-phase ani single-phase configurations. These cable-impedance a:pllions, which are derived from equations in References 1 and 2. and an explanation of their nomenclature are presented beginning on the following page. To help define some of the ll!lms .-. the equations, Figure 7A 1 shows the cross-sectional geomeby of three identical concentric neutral cables used for a bee-phase underground distribution circuit. The spacing of the three cables in Figure 7A 1 is arbitrarily sbolm as nonsymmetrical to illustrate the generality of the ..,.afions, which are not confined to symmetrical arrangeaaenls.. In practice, the three cables are frequently laid flat in lie bottom of a trench. In applying symmetrical components ID an 011erhead system in which the three phase conductors .e nol symmetrically arranged in a delta configuration, an eqni'«alent delta spacing (Figures 5A 1 and 6A 1) is assumed iit c3culating the sequence impedances of the three-phase cilll:uil: - and the same is true for an underground circuit. ~ the actual interphase spacings (Figure 7 A 1), an equivalent delta spacing (i.e., geometric mean spacing) is a*1Wed for use in finding average mutual impedances among

Zero-Sequence Impedance Components for Four-Wire Multi-Grounded Neutral Circuits ~n Ro Xn .4513 .5824 .3710 .3718 .4771 .6051 .6231 .3688 .5004 .4324 .4530 .6250 .4786 .4331 .6458 .4301 .5000 .6591 .5085 .4824 .6989 .5057 .7131 .5057 .5403 .7273 .4886 .6017 .5083 .7841 .5430 .7992 .5847 .8614 .5485 .7814

phase conductors and the three sets of neutral conductors. While the symmetrical component concept is intended to aid in the analysis of problems of three-phase systems, it is convenient on a distribution system to extend the concept to the single-phase portions of the circuit. This means finding 2 1 and 2 o for the single-phase laterals so that they may be combined with the corresponding sequence impedances of the three-phase system which supplies the laterals. To find 2 1 and 2 o for the single-phase circuit, an arbitrary interphase geometric mean spacing, Sab, must be used in finding 2 ab-g, Equation U2. The value assumed for Sab does not matter in the end result of a line-to-ground fault calculation, for example, since 2 ab-g cancels out of the total system impedance for this type of fault. The reader can verify this by examining Equations 41, U11, and U12, assuming 21 2 2 The solution of Equations U1 through U12 for some typical sizes of copper and aluminum 15 kV distribution cable produces the sequence impedance values displayed in Tables 4A 1 through 7 A 1. Conductor resistances and most of the other cable characteristics required to solve the sequence impedance equations were obtained from Reference 9. Values of GMR (geometric mean radius) were obtained from Reference 5. An earth resistivity value of 100 meter ohms was assumed. Tables 4A 1 and 5A 1 give the impedances of three-phase cable such as might be used for underground primary mains. A 7.5-, 7.5-, 15 inch, flat cable spacing is assumed. Tables 6A 1 and 7 A 1 cover single-phase cable commonly used for primary laterals. Some of the effects that various cable parameters and other conditions have on the impedance of an underground cable are illustrated by Tables 4A 1 through 7A 1. Others are discussed in the text, which resumes on page 25.

=

19

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

EQUATIONS FOR CALCULATING SEQUENCE IMPEDANCES OF UNDERGROUND CONCENTRIC NEUTRAL CABLE The following equations* are the basic expressions needed for calculating positive- and zero-sequence impedances of both three-phase and single-phase concentric neutral cable. For a three-phase array of cables such as in Figure 7A 1, Equations U1 through U4 and U7 through U1 0 are used. For a single-phase circuit Equations, U1, U2, US, U6, U11 , and U12 are used. raa-g = [ ra + 4.788

X

10-5 X 21tf] + j 2m [4.681

X

rnn-g

X

~ + 4.788 X 10-5 X 2m] + j 2:f [4.681

=[ 4.788 X 10-5 X 2m]

+ j 21tf [4.681

10-5 1oge ( _1_ '1/ p/f) + (N-1) 4.681 GMRn

10

= [4.788 X 10-5 X 21tf]

(U1)

+ j 21tf [ 4.681 rab-g

X

10-4

..JP/f)]

GMRa

=[

10-4 + 6.096

ran-g

+ 6.096 x 10-5 1oge (_1_

10

X

X

10-4 + 6.096

X

1o- 5 1oge

(_g D

{/)lf)]

(U6)

10-4

+ 6.096 x 10-5 1oge (_1_ {0/f)]

(U2)

Sab

1 loge ---loge1 1 l +-

=

rnn-g 30

[_!n_ + 4.788 X 3N

+ 6.096 x 10-5 1oge

+ 6.096

ran-g

30

X

10-5 X 2m] + j 21tf [4.681

{Pit+

X

3

= [ 4.788 X 10-5 X 21tfl + j 21tf [4.681

+ 6.096 X 1o-5 loge

10-

_1_ 6.096 x 10-5 1oge ~b

10-5 ~ (loge _ 1 _ + (N-1) loge _ 1_)] GMRn KN~

N

4

GMRn

r an-p = j 21tf X 6.096

r (U3)

-

130 -

raa-g -rab-g

Sab

X

10-5 [ loge

- r~n-p r nn-p

(U7)

6- loge s:b l

(U8)

(U9)

(U10) X

10-4

'P,.,lf>] ..

( ~ Jri'ct' 1 "J -

'Vg. Sab 2

(U4)

(U1 2)

* The assistance of Dr. W. A. Lewis in including the effect of neutral circulating currents on positive-sequence impedance (Equations U7 through U9) is gratefully acknowledged.

20

A1 Nomenclature for Equations U1 through U12: D = diameter of the circle defined by the neutral strand centers of one concentric neutral cable (see Figure 7A 1) feet. Values of D can be derived from information published in cable manufacturer's catalogs.

f = frequency in hertz. GMRa, GMRn = geometric mean radius of the phase conductor (subscript a) and a single neutral strand (subscript n) in feet. GMRa is readily available from tables such as those in References 1, 3, and 5. GMRn can also be obtained from tables; but since each strand has a solid, circular cross-section, it is readily calculated using GMRn = .3894dn, where dn is the diameter of a single neutral strand in feet (see Figure 7A1).

i = the complex

operator, 1~oo.

KN spacing factor which, when multiplied by D/2, gives the geometric mean spacing among the N neutral strands of one concentric neutral cable. KN is obtained from the expression KN = (N)1/(N-1); see page 32 of Reference 4. N = number of neutral strands wrapped around the insulation of one concentric neutral cable (see cable manufacturers' catalogs). ra, rn = resistance of the phase conductor (subscript a) and a single neutral strand (subscript n) in ohms/1 000 feet (see cable manufacturers' catalogs). These should be a-c resistance values calculated for the expected operating temperatures of the phase and neutral conductors. They should include skin effect and proximity effect, wherever these effects can be readily determined.

p = earth resistivity in meter ohms. Representative values of ;; for various parts of the country are given in Reference 3 1pages 146 through 150), Reference 7 (pages 129 through 131 ), and Reference 8 (page 306).

Sab = geometric mean spacing of the three-phase conductors 1n feet. Referring to Figure 7A1, Sab (dabddcdca) 113 •

r aa-g, r nn-g30, r nn-g10 = self impedance of a phase conductor (subscript aa) and self impedance of a group of paralleled neutral strands (subscript nn) with earth return in ohms/1 000 feet. (See pages 376 and 397, Reference 1, and page 78, Reference 2, for the material on which Equations U1. U3, and U5 are based.)

r ab-g r an-g30, r an-g10 =mutual impedance between two conductors or two groups of conductors with earth return in ohms/1 000 feet. Subscripts a and b denote phase conductors and subscript n denotes a group of neutral conductors. In a three-phase circuit, there are actually three mutual impedances among the three-phase conductors: r ab-g, r be-g. and rca-g. However, in Equation U2, the use of a geometric mean spacing Sab instead of the actual interphase spacing means that the resulting value of r ab-g is the arithmetic mean of the three actual values. In a similar sense, r an-g30 is an average of the three actual mutual impedances that exist between each of the three-phase conductors and the entire group of neutral conductors. (See page 376, Reference 1, and page 79, Reference 2, for the material on which Equations U2, U4, and U6 are based.} r an-p = positive sequence mutual impedance between the phase conductors of the cable and their concentric neutrals in ohms/1 000 feet. • r nn-p = positive sequence self impedance of the threephase circuit formed by the concentric neutrals of the cables in ohms/1 000 feet. • r 13 r 030 = positive and zero sequence impedance, respgctively, of a three-phase concentric neutral circuit in ohms/1000 feet. • r 11 ' r 01 0 = positive and zero sequence impedance, respgctively, of a single-phase concentric neutral circuit in ohms/1 000 feet* *When positive-sequence currents flow in the phase conductors of a three-phase concentric neutral circuit, induced currents will circulate between each phase's neutral and the earth return path. The magnitude of this current depends upon neutral resistance, interphase spacing, and the diameter of the circle of centers of the concentric neutral strands. In turn, the positive sequence impedance of the circuit is modified by the magnitude of these neutral currents. r 2an-p/ r nn-p is the factor that reflects the effect of neutral circulating current on the positive-sequence impedance of three-phase concentric neutral cable (Equation U9). On an overhead openwire transmission or distribution circuit, this effect is negligible for the close spacings associated with concentric neutral cable.

21

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

-dab-

\L._f- - _ _ ; . - - - - - -

PHASE CONDUCTOR

dtx:

NEUTRAL STRAND

Figure 7A1. Cross-sectional geometry of concentric cables.

22

A1 TABLE 4A1 Impedance of 15-kV, 3-Phase, 175-mil XLP Underground Cable in Ohms/1 000 Feet Conductor temperatures- Phase: 90°C; Neutral: 70°C

Insulation: 175-mil cross-linked polyethylene Cable configuration: 3 identical single-phase concentric neutral cables with 1/3 size neutrals and with 7.5 inches, 7.5 inches, 15 inches, flat spacing (geometric mean spacing = 9.449 inches)

Frequency: 60 Hz

Earth resistivity: 100 meter-ohms

I

~1

Neutral

Phase

Concentric Strands (Copper)

Size AWG or MCM

No. of Strands

No.

1/0 210 3/0 4/0 250 350 500 750 1000

19 19 19 19 37 37 37 61 61

6 7 9 11 13 11 16 15 20

1/0 210 3/0 4/0 250 350 500 750 1000

19 19 19 19 37 37 37 61 61

9 11 14 11 13 12 17 25 33

I

u

~0

Positive- and Negative-Sequence Impedance Components

:SIZe AWG R1 = R2 x1 = x2 Aluminum Phase Conductor 14 .2182 .0955 .0926 14 .1782 14 .1433 .0893 14 .1181 .0858 14 .1038 .0827 .0761 12 .0837 12 .0680 .0674 .0581 10 .0550 10 .0493 .0495 Copper Phase Conductor 14 .1451 .0944 .0908 14 .1181 .0989 .0867 14 12 .0854 .0813 .Q785 .0770 12 10 .0657 .0685 10 .0554 .0574 .0463 .0446 10 10 .0404 .0358

I

1 1~11 = 1~21

Zero-Sequence Impedance Components Ro

I

Xo

I

1~ 0 1

.2382 .2008 .1688 .1460 .1327 .1131 .0958 .0800 .0699

.5215 .4697 .4049 .3497 .3085 .2315 .1653 .1188 .0905

.2906 .2463 .1825 .1402 .1114 .0691 .0428 .0305 .0235

.5970 .5303 .4441 .3767 .3280 .2416 .1708 .1227 .0935

.1731 .1490 .1315 .1179 .1100 .0949 .0798 .0643 .0540

.4066 .3492 .2907 .2318 .2008 .1495 .1060 .0724 .0554

.1852 .1428 .1033 .0718 .0578 .0408 .0289 .0216 .0181

.4468 .3773 .3085 .2427 .2090 .1550 .1098 .0756 .0583

TABLE 5A1 Impedance of 15-kV, 3-Phase, 220-mil XLP Underground Cable in Ohms/1 000 Feet Insulation: 220-mil cross-linked polyethylene Conductor temperatures - Phase: 90°C; Neutral: 70°C Cable configuration: 3 identical single-phase concentric neutral cables with 1/3 size neutrals and with 7.5 inches, 7..5 inches, 15 inches, flat spacing (geometric mean spacing= 9.449 inches)

Earth resistivity: 100 meter-ohms Phase

I'

Frequency: 60 Hz Neutral Concentric Strands (Copper)

Size AWG or MCM

No. of Strands

No.

1/0 210 3/0 4/0 250 350 500 750 1000

19 19 19 19 37 37 37 61 61

6 7 9 11 13 11 16 15 20

1/0 210 3/0 4/0 250 350 500 750 1000

19 19 19 19 37 37 37 61 61

9 11 14 11 13 12 17 25 33

,I

I

~1

~0

Positive- and Negative-Sequence Impedance Components

Zero-Sequence Impedance Components

Size AWG X1 =X2 R1 =R2 Aluminum Phase Conductor 14 .0956 .21 77 14 .1777 .0927 14 .0894 .1427 14 .1174 .0860 14 .1031 .0829 12 .0828 .0765 12 .0671 .0681 10 .0542 .0589 10 .0486 .0504 Copper Phase Conductor 14 .1444 .0946 14 .1173 .0911 14 .0980 .0870 12 .0844 .0818 12 .0774 .0777 10 .0647 .0694 10 .0545 .0585 10 .0456 .0459 .0370 10 .0400

I

1~~1l=l~21

Ro

.2378 .2004 .1684 .1456 .1323 .1127 .0956 .0800 .Q700

.5205 .4688 .4043 .3493 .3082 .2314 .1653 .1188 .0905

.2927 .2484 .1846 .1423 .1134 .0709 .0444 .0319 .0247

.5972 .5306 .4445 .3772 .3284 .2420 .1711 .1230 .0938

.1726 .1485 .1310 .1175 .1097 .0948 .0800 .0647 .0545

.4060 .3488 .2904 .2316 .2007 .1494 .1059 .0724 .0554

.1876 .1451 .1055 .0738 .0597 .0425 .0304 .0229 .0193

.4472 .3777 .3090 .2431 .2094 .1554 .1102 .0759 .0587

I

Xo

I

l~ol

23

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

TABLE 6A1 Impedance of 15-kV, 3-Phase, 175-mil XLP Underground Cable in Ohms/1 000 Feet Insulation: 175-mil cross-linked polyethylene Conductor temperatures- Phase: 90°C; Neutral: 70°C Full size neutral Geometric mean interphase spacing assumed for i!- 1 and i!- 0 calculations = 1S Earth resistivity: 100 meter-ohms Frequency: 60 Hz Neutral Concentric Strands (Copper)

Phase Size AWG or MCM

No. of Strands

No.

4 2 1 1/0 210 3/0 4/0 250 300 350

7 7 19 19 19 19 19 37 37 37

6 10 13 16 13 16 20 25 20 24

4 2 1 1/0 2/0 3/0 4/0

7 7 19 19 19 19 19

10 16 13 16 20 25 32

I

i!-, Positive- and Negative-Sequence Impedance Components

I

Size AWG R1 =R2 x, = X2 lli!-11 = 11!- z1 Aluminum Phase Conductor 14 .5350 .0662 .5391 14 .3360 .3415 .0609 14 .2680 .0569 .2740 14 .2100 .0543 .2169 12 .1690 .0516 .1767 12 .1320 .0490 .1408 12 .1050 .0463 .1148 12 .0890 .0440 .0993 10 .0750 .0419 .0859 10 .0650 .0402 .0764 Copper Phase Conductor 14 .0662 .3260 .3327 14 .2050 .0609 .2139 12 .1727 .0569 .1630 12 .1260 .0543 .1372 12 .1010 .0516 .1134 12 .0810 .0490 .0947 12 .0640 .0463 .0790

i!-o Zero-Sequence Impedance Components Ro

I

Phase

24

Size AWG or MCM

No. of Strands

No.

4 2 1 1/0 2/0 3/0 4/0 250 300 350

7 7 19 19 19 19 19 37 37 37

6 10 13 16 13 16 20 25 20 24

4 2 1 1/0 2/0 310 410

7 7 19 19 19 19 19

10 16 13 16 20 25 32

I

I

11!- ol

.5888 .4375 .3443 .2709 .1728 .1209 .0779 .0461 .0307 .0170

1.0406 .8417 .7407 .6459 .5331 .4483 .3717 .3106 .2665 .2276

.7122 .5846 .5001 .4271 .3604 .2997 .2417

.4387 .2692 .1710 .1186 .0752 .0437 .0200

.8365 .6437 .5285 .4432 .3682 .3028 .2425

Frequency: 60 Hz

i!-1 PosHive- and Negative-Sequence Impedance Components

Size AWG x1 = x2 R1 = R2 Aluminum Phase Conductor 14 .5100 .0662 14 .3200 .0609 14 .0569 .2550 14 .2000 .0543 12 .1600 .0516 12 .1250 .0490 12 .1000 .0463 12 .0850 .0440 10 .0710 .0419 10 .0610 .0402 Copper Phase Conductor 14 .3100 .0662 14 .1950 .0609 12 .1550 .0569 12 .1200 .0543 12 .0970 .0516 12 .0770 .0490 12 .0610 .0463

I

.8580 .7191 .6558 .5864 .5043 .4317 .3635 .3071 .2647 .2269

TABLE 7A1 Impedance of 15-kV, 1-Phase, 220-mil Conventional Underground Cable in Ohms/1000 Feet Insulation: 220-mil conventional low density thermoplastic polyethylene Full size neutral Conductor temperatures - Phase: 75°C; Neutral: 50°C Geometric mean interphase spacing assumed for i!- 1 and i!- 0 calculations = 1.5" Earth resistivity: 100 meter-ohms Neutral Concentric Strands (Copper)

Xo

i!-o Zero-Sequence Impedance Components

I

I

lri!- 11 11!- 21

=

Ro

.5143 .3257 .2613 .2072 .1681 .1343 .1102 .0957 .0825 .0730

.8410 .7040 .6384 .5677 .4911 .4204 .3544 .2993 .2522 .2154

.5734 .4158 .3216 .2498 .1717 .1208 0785 .0486 .0306 .0180

1.0179 .8176 .7148 .6202 .5202 .4374 .3630 .3033 .2541 .2162

.3170 .2043 .1651 .1317 .1099 .0913 .0766

.6967 .5652 .4877 .4166 .3522 .2919 .2355

.4171 .2493 .1703 .1189 .0762 .0455 .0223

.8120 .6177 .5166 .4333 .3604 .2954 .2365

Xo

11!- 01

1:

A1 EFFECT OF CABLE INSULATION For the 15 kV class of concentric neutral underground cable, which is in predominant use today, the two most common types of insulation are conventional and high-molecularweight polyethylene, although the latter has been the prevailing choice in UD cable insulation for many years. Both are available in 175 and 220 mils. In general, changing the thickness of cable insulation from 175 to 220 mils has only a minor effect on cable impedances. In the impedance equations, only the value of D (diameter of the circle of neutral strand centers) is affected by a change in ~nsulation thickness, and this in turn, will change Z nn-g, Z an-g, Znn-p, Z an-p, Z 13p, Z o3 , and Zo1p (Equations U3 through U10, and U12). Numerically, the effect of changing insulation thickness is illustrated by comparing Tables 4A 1 and 5A 1, where the only difference is the thickness of cable insulation. Insulation thickness affects the values of both Z 1 and Z o, ::>ut only to a minor extent. In contrast, changing the type of insulation has a major effect on cable impedance. The reason is that the increase in maximum phase-conductor temperature made possible by 'tie use of newer insulations, such as cross-linked polyethylene, n turn creates greater impedance under full load conditions. The Insulated Power Cable Engineers Association (IPCEA) sets the maximum conductor temperature rating for continuous ~JII-Ioad operation for conventional polyethylene insulation at :so C, and the rating for cross-linked polyethylene at goo C. The effect this higher permissible operating temperature '"laS on the impedance of cable insulated with cross-linked ::lOiyethylene under full-load conditions can be seen by comoaring Tables 6A 1 and 7A 1. Table 6A 1 shows sequence mpedances of single-phase cable with 175 mil cross-linked :JOiyethylene (XLP) insulation, and Table 7 A 1 shows the smaller impedances that result from the lower operating :emperature of 220 mil conventional polyethylene cable. Tables 4A 1 and 5A 1 are both confined to cross-linked ::olyethylene insulated cable, since the higher current-carrying :apacity of this cable makes it the likely choice for three::lhase applications.

EFFECT OF NEUTRAL SIZE -'Is illustrated by Figure 7A1, the neutral conductor of this :"fpe of cable consists of equally spaced strands of wire ;~~~ped spirally around the outside of the cable insulation.

nese are generally #14, 12 or 10 AWG copper wires. The size 3l1d number of wires are selected to provide approximately ;qual conductivity to that of the central phase conductor for sa1Qie-phase applications (taking into account the increased ength of the neutral strands due to spiraling). However, for tlree-phase applications, a reduced-sized neutral is available 'or the larger phase-conductor sizes, the circular mil area of 11e group of neutral wires being approximately one-third that :i the copper equivalent of one phase conductor. Since Tables ~1 and 7 A 1 give impedances for single-phase applications, rey are based on full-size neutrals. Tables 4A 1 and 5A 1, for :tree-phase applications, are based on reduced-size neutrals. In some three-phase applications, where full-size neutral :able is used, it is helpful to know the effect on cable impedance. ~~effect is illustrated by the following impedances of 250 mcm aluminum cable with 175 mil XLP insulation. =educed-size neutral (13- #14 wires): Z 1 = .1 038 + j.0827 ohms/1 000 ft (Table 4A 1) Z 0 = .3085 + j.1114 ohms/1 000 ft (Table 4A 1)

Full-size neutral (25- #12 wires): Z 1 = .1 023 + j.0618 ohms/1 000 ft Z = .1685 + j.0320 ohms/1000 ft

o

Cable insulation, cable spacing, earth resistivity, and other parameters are the same in these two cases. The only change is in the neutral. As can be seen, the effect of going to the full-size neutral is significant for both positive-and zero-sequence impedance components. On an overhead circuit, the neutral conductor has negligible effect on Z 1. This is not true for URD concentric neutral cable. When positive-sequence currents flow in the phase conductors of this type of circuit, circulating currents are induced in the nearby concentric neutrals which modify the Z 1 of the circuit. As the neutral size is increased, the effect becomes greater. In general, this means both Z 1 and Z oshould be recalculated for situations calling for threephase cable with full-size neutrals.

EFFECT OF EARTH RESISTIVITY The value of earth resistivity used in calculating the impedances of Tables 4A 1 through 7 A 1 was 100 meter-ohms. Since there can be a wide variation in this system parameter from one geographic area to another, it is of interest to estimate its effect on impedance. Again, using 250-mcm aluminum cable with 175-mil XLP insulation as the reference, the effect is as follows: For p = 10 meter-ohms: Z 1 = .1038 + j.0827 ohms/1000 ft Z 0 .2980 + j. 1181 ohms/1 000 ft For p = 100 meter-ohms: Z 1 = .1 038 + j.0827 ohms/1 000 ft (Table 4A 1) Z 0 = .3085 + j.1114 ohms/1 000 ft (Table 4A 1) For p = 1000 meter-ohms: Z 1 .1 038 + j.0827 ohms/1 000 ft Z o = .3165 + j.1051 ohms/1000 ft Cable spacing, cable insulation, neutral size, and all other parameters except earth resistivity are the same in these three cases. A change in earth resistivity does not affect the positive sequence impedance, but does affect Z o. An increase or decrease in the value of p from 100 meter-ohms by a factor of ten produces approximate changes in Ro and Xo of three and six percent, respectively, and an approximate change of two percent in the magnitude of Z o. For the given cable, a large change in p has a relatively small effect on Z o and its components. Thus, using a value of 100 meter-ohms for earth resistivity should give impedances sufficiently accurate for most situations.

EFFECT OF INTERPHASE SPACING An examination of Equations U1 through U14 shows that the geometric mean spacing of the phase conductors, Sab, affects the values of both the positive- and zero-sequence impedances of the cable. Since three-phase cable spacing practices will vary from one utility to another, the question of how spacing affects impedance is a logical one. This effect is illustrated by the following, using the 250 mcm aluminum cable of the earlier examples.

25

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

For Sab

= 9.449 inches: ~ 1 = .1038 .3085 ~

0

+ j.0827 ohms/1000 ft (Table 4A1) + j.1114 ohms/1000 ft (Table 4A1)

For Sab = 1.5 inches: ~ = .0909 + j.0439 ohms/1 000 ft 1 ~ = .3170 + j.1047 ohms/1000 ft 0 Neutral size, earth resistivity, cable insulation, and other parameters except interphase spacing are the same in these two cases. In this one example, it is apparent there can be a sizable effect on both positive- and zero-sequence reactance when the cable spacing is changed. In view of this, whenever the cable spacing in use is significantly different from the 9.449 inches used for Tables 4A 1 and 5A 1, some calculation checks for the actual spacing are advisable to determine if the tabulated impedances should be revised. In a more precisely calculated example, the large decrease in spacing would also produce some increase in resistance as a result of increased proximity effect. In the numerical example shown, the change in proximity effect is not included.

SKIN EFFECT AND PROXIMITY EFFECT Skin effect and proximity effect are phenomena associated with the nonuniform current distribution over the cross section of a conductor. In the case of proximity effect, the nonuniform current distribution is unsymmetrical and is caused by a variation of current in one or more neighboring conductors. Detailed descriptions of both effects are given in References 2 and 11. Skin effect and proximity effect influence both the resistance and reactance of a circuit. Generally, the effect on reactance is much less than it is on resistance and the reactance effect is neglected. However, the combined effect of skin and proximity effect on resistance is not always negligible. It depends on many factors, such as frequency, conductor material and size, circuit configuration (interphase spacing and phase-neutral spacing), and the relative magnitudes and phases of currents in the various conductors. For example, for a given three-phase circuit, proximity effect is not the same with zero-sequence currents in the conductors as it is with positive-sequence currents. This means proximity effect modifies positivesequence impedance in a different way than it does zerosequence impedance. While some work has been done on the calculation of positive-sequence proximity effect, little has been done on zero-sequence proximity effect. In contrast to proximity effect, skin effect does not depend on the sequence of the currents flowing. There is need for a thorough study of proximity effects in underground concentric neutral cable. Based on the work that has been done on other types of circuits and cables, the effects of proximity upon reactance are negligible at 60 hertz. However, the effects upon resistance are probably not negligible in the larger cable sizes. In the calculation of the sequence impedances displayed in Tables 4A 1 through 7A 1, both skin and proximity effects upon reactance were assumed negligible. The resistance values include skin effect but not proximity effect. When more is known about proximity effects in this type of cable, the values of phase and neutral conductor resistances {ra and rn) can be suitably modified to account for these effects. Equations U1 through U12 are general expressions for finding the sequence impedances of concentric neutral cable of any stated size, material, and spacing. The results of solving these equations for some cable sizes and configurations in common use are presented in Tables 4A1 through 7A1.

26

The sensitivity of the results to changes in such cable parameters as insulation, neutral size, and spacing has been described, and in some specific situations the tabulated impedances will not be applicable. In those cases where the cable parameters are significantly different from those on which Tables 4A 1 through 7 A 1 are based, the impedance equations must be resorted to, and the results will be of great importance. While solving the equations by hand for a large variety of cable parameters would be a tedious task, the equations are easily solved on a computer. A McGraw-Edison Power Systems service to perform this task is available. Also available: additional work showing how the formulas may be rearranged in groups of terms that can be precalculated into "building blocks" permitting desk calculation for practical cases; and comparisons of typical results, to show the effects of spacing and other factors.

Impedances of Transformers In moving from any given point on a primary distribution system back toward the source, either overhead line impedance or underground cable impedance is the first encountered. On most systems, the next major impedance element will be the distribution substation transformer. This section briefly covers the sequence impedance representation of transformers (References 2 and 4).

PRIMARY

R~+

SECONDARY

(a.) SHUNT IMPEDANCE INCLUDED

PRIMARY

SECONDARY

(b.) SHUNT IMPEDANCE NEGLECTED

Figure8A1. Per-unit equivalent circuit for a two-winding transformer.

A per-unit equivalent circuit for a two-winding transformer is shown in Figure 8A 1, a. The terms primary and secondary here refer to the high- and low-voltage windings of the transformer, not to primary and secondary distribution. Rp and Rs are resistances, and Xp and Xs are leakage reactances in the primary and secondary windings, respectively. Rh+e is the resistance required to account for hysteresis and eddy current losses in the iron core and Xm is the mutual

A1 reactance between the two windings, also called the magnetizing reactance. The current flowing through the parallel combination of Rh+e and Xm is the transformer exciting current. That portion of the exciting current flowing through Xm is the magnetizing current. The total exciting current of a transform~r is usually small in comparison to its full load current. For th1s reason, the exciting impedance branch is usually neglected and the equivalent circuit becomes as shown in Figure 8A 1,b. Equivalent circuits similar to Figure 8A 1 could be drawn for actual units instead of using the per-unit basis. However, in this situation, the square of the transformer turns ratio would enter the picture, and two sets of equivalent circuits would have to be drawn-one showing the circuit elements as viewed from the primary, and another as viewed from the secondary. The per-unit system (described earlier) avoids these complications. The simplified per-unit equivalent circuit for a transformer (Figure 8A 1,b) is suitable for most fault-current calculations. The term ~ ps is the leakage impedance of the transformer. It is also called the transformer's short-circuit impedance, since it can be measured by applying a voltage to one winding with the other winding short circuited. Generally, for three-phase transformers rated 1500 kVA and below and for single-phase transformers rated 500 kVA and below, the resistive component of the leakage impedance is significant and should not be neglected. In larger units, however, the transformer reactance dominates and the resistance is usually negligible (Reference 4). In these cases, the per-unit leakage reactance of the transformer is assumed equal to the nameplate percent impedance divided by 100, provided the kVA base for the per-unit calculations is the transformer kVA rating on which the nameplate percent impedance is based. For fault calculations on a three-phase system involving transformers, the sequence impedances of the transformers must be included in the overall system-sequence impedances. The positive-sequence impedance of a balanced three-phase transformer or three identical single-phase transformers is 1he impedance presented to positive-sequence currents. In other words, if the transformer is short-circuited on one side and energized by a positive sequence on the other, the phase A line-to-ground voltage on the supply side of the transformer tivided by the phase A supply current will be the positivesequence impedance. If both the applied voltage and the current are expressed in per-unit on the appropriate bases, then the positive-sequence impedance will be in per-unit. Since one phase of a short-circuited three-phase transformer is being !iscussed, the positive-sequence impedance is equivalent to 1he leakage impedance of the transformer. Also, since a 1Jansformer is a passive element, its positive- and negativesequence impedances are identical. Figure 9A 1 shows the positive- and negative-sequence per-unit equivalent circuits af a transformer. The zero-sequence equivalent circuit of a three-phase 1ransformer depends on the transformer connection. Figure 10A 1 shows equivalent circuits for some of the more common ,connections. Of the transformer connections illustrated, a cad-side path for zero-sequence current exists only for conoaections 3 and 5. In connections 3 and 5, if ~ n, is zero, the zero-sequence impedance is equal to the positive-sequence impedance. In theory, this is not strictly true for all transformer designs, especially three-phase core-type units, but it is suffciently accurate for most applications. For autotransformers and transformers with three or more windings, Figure 1OA 1 is oot applicable and other sources must be referred to for zerosequence equivalent circuits (References 5 and 12).

POSITIVE SEQUENCE REFERENCE BUS

SOURCE

LOAD

-r, r2=rps

~

NEGATIVE SEQUENCE REFERENCE

SOURCE

LOAD ~2

~

r2=-r,

Figure 9A1. Positive- and negative-sequence per-unit equivalent circuits of a transformer.

Impedances of Transmission Lines The circuit parameters that influence the sequence impedances of an overhead transmission line are the same as those that influence the impedances of an overhead distribution circuit. The principal parameters are conductor size, material, and spacing, plus the type of grounding. In general, the previous remarks on the effects of these parameters on impedances of overhead distribution lines apply also to overhead transmission lines. However, the circuit parameters of transmission lines can have a different range of values than the parameters of a distribution line. Transmission-line interface spacings are much larger; therefore, positive-sequence reactance is larger than for typical distribution circuits. Zero-sequence impedances also are affected by spacing changes, but in this case differences in the type of grounding, number of ground wires, etc., can have a more significant effect. Transmission-line impedance information is usually needed in distribution-system fault studies only for determination of the equivalent source impedance of the system supplying the distribution circuit. More will be said about source impedance calculations in later sections. On many systems, transmissionline impedances are readily available, since they are needed in a variety of transmission-system studies: load flow, short circuit, transient stability, system planning, etc. If such impedance data is not available, it must be calculated from appropriate equations (References 1, 3, 4, and 5). Impedances of Generators In moving away from the distribution system, the final impedance element encountered is the generator. For most distribution circuits, several voltage levels are interposed between distribution and generation, and it is not unusual for the net generator impedance to be small compared to the line and transformer impedances on a per-unit basis. In the case of a large interconnected transmission and subtransmission system supplied by a number of generators, it is safe, for distribution fault calculations, to assume the impedance of the equivalent generator to be zero. This is frequently referred to as a "stiff" system. The concept of the Thevenin equivalent, discussed after the development of fault-current equations in the following section ("System Faults"), handles this automatically. In the stiff system, the generator portion of the equivalent series impedance will be negligible.

27

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

CONNECTION DIAGRAM SOURCE LOAD

ZERO.SEQUENCE EQUIVALENT CIRCUIT

~VIEWED

FROM LOAD SIDE i

1

2

3

4

5

6

7

8

y ~ ::y ~

ZERO-SEQUENCE REFERENCE ~oL =CO ~0

LOAD

~

0

SOURCE

i:!o L = CO i:!o ~

s 0

~~

~~ ~~~.

i:!o S~L

.~

i:!ol =j!,

i:!ol =CO

OL

~.c;:,

i:!o L = 1:! • + ~N

s 0

~~

::y ~ ~~ oi'!o ;i'!1

oi'!N

i:!o ~L

s 0

i:!oL =CO

i:!o L '=

C()

i:!o L =

C()

i:!o

s

o-f'VV"\..---

so

i:!o ----f'V'VV"'\..

OL

OL

= transformer zero-sequence impedance transformer positive-sequence impedance

=neutral impedance

equivalent zero-sequence impedance of the three-phase oi'!oL = transformer connection viewed from the load side

Figure 1OA1. Transformer connections and zero-sequence equivalent circuits.

i

A1 However, since there are systems where the generator impedance is not an insignificant portion of the overall system impedance, the sequence impedance representation of generators will be discussed briefly. POSITIVE-SEQUENCE REFERENCE BUS

e POSITIVE SEQUENCE

NEGATIVE•SEQUENCE REFERENCE BUS

NEGATIVE SEQUENCE

ZERO-SEQUENCE REFERENCE BUS

ZERO SEQUENCE

Figure 11A1. Sequence equivalents of a generator.

The positive-, negative-, and zero-sequence equivalent c:in::uits for a generator are illustrated in Figure 11 A 1. Since a generator is designed to supply a balanced three-phase voltage, lie equivalent circuits show an ideal voltage source (zero IIEmal impedance) in the positive-sequence diagram, and ., sources in the negative- and zero-sequence diagrams. Senerator resistances are usually small, so only reactances are shown in the equivalent circuits. The value used for positive-sequence reactance Xg1 depends upon which time period is being studied fault or other system disturbance. If llle sustained, steady-state fault current is being calculated, laen what is called the direct-axis synchronous reactance Xd

should be used. This value would apply for times beyond 40 to 60 cycles following the fault, or whatever time period is required for the initial transients to decay to negligible levels. A reactance value applicable for the period from three to approximately 40 cycles after the fault is called the direct-axis transient reactance X'd. A third value used for the first two or three cycles following the fault is the direct-axis subtransient reactance X"d. The time periods indicated are only approximate and can vary considerably from one generator to another. Generally, subtransient reactance is used to determine the initial rms current value following the occurrence of a fault; therefore, X"d is of most interest in fault studies. In the past, transient reactance has been used in some cases to determine currents that must be interrupted by a breaker, and in making stability studies. However, with the availability of higher speed breakers, it has become more common to use subtransient reactance or more detailed generator models in such studies. In most fault studies, the value used for Xg1 (Figure 11 A 1) will be the subtransient reactance X'd. Ranges of typical per-unit values of X"d are 0.07 to 0.14 for two pole turbine generators and 0.12 to 0.17 for four-pole turbine generators. The negative-sequence reactance Xg2 of a synchronous machine is that met by a current whose phase sequence is opposite to that of the generated voltage. For this reason, Xg2 is usually taken as the average between the direct and quadrature axis subtransient reactances, X"d and X"q. For turbine generators, X"d is nearly equal to X"q, and the ranges of values cited above for X"d may be used for Xg2 as well as for Xg1 . The zero-sequence reactance Xgo of a generator varies with the armature winding pitch and is usually from 10 to 70 percent of the direct axis subtransient reactance. For turbine generators, a range of typical values for Xgo would be from 0.01 to 0.14 per unit. It should be that these values do not include any impedance ~ N that may be deliberately inserted between the neutral of the wye-connected generator and ground. As shown in Figure 11A1, the neutral impedance is independent of the generator's zero-sequence impedance. To account for the presence of the neutral impedance, 3 ~ N must appear in the zero-sequence equivalent circuit. For most systems, there will be one or more transformers separating the distribution circuit from the generator. If there is no way the distribution circuit can be supplied except through a transformer with a delta-connected main winding, as is usually the case, then the generator's zero-sequence impedance has no effect on the zero-sequence impedance seen by a distribution system fault This can be deduced from the zero-sequence equivalent circuit of a delta-wye transformer bank (Figure 1OA 1). As a result, on most present-day systems, generator zero-sequence impedance is of no significance in the calculation of distribution system faults. References 3 and 4 provide more thorough treatment of generator impedances. Also, in a specific situation, the typical values cited for Xg1, Xg2 and Xgo may not apply. Wherever the generator impedance is not negligible in distribution-system fault studies, it is best to use specific impedance values provided by the generator manufacturer.

Source Impedance One convenient approach to distribution-system fault calculations is to begin at the low-voltage (LV) bus of the distribution substation, calculate the currents for the various possible types of fault at that point, and, moving away from

29

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

LOAD

LOAD

~

LOAD

LQAO

LOAD

}

DISTRIBUTION SUBSTATION A

}

DISTRIBUTiOt-j SUBSTATION B

}

PRIMARY DI.STR.· IBUTION CIRCUITS

P, PRIMARY DISTRIBUTION CIRCUITS {

Figure 12A1. Diagram of a distribution system.

the substation, repeat the calculation procedure at each point of interest on the circuit. To do this, one must first know the value of the source impedance at the substation low-voltage bus. This is the impedance looking back into the system supplying the distribution circuit, as illustrated in Figure 12A 1. At point P1, for example, the source impedance is the equivalent impedance of the network of transformers, transmission lines, and generators supplying the low-voltage (LV) bus in substation A. The source impedance used for other distribution circuits served by the same bus in substation A will be identical to that seen at point P1. In general, however, in moving to another substation in the system, the source impedance will change. Thus, the impedance looking back into the system at point P2 in substation 8 may be much less than it is at P1 if substation 8 is electrically closer to the system generation than is substation A.

METHODS FOR FINDING SOURCE IMPEDANCE Depending on the information available, several methods for finding source impedance may be used.

Method A In cases where the distribution system is fed through a simple radial transmission system with a generator at the other end,

30

the source impedance can be calculated by hand. Using the per-unit system, the source positive-sequence impedance is the sum of the positive-sequence impedances of all system components from the distribution substation low-voltage bus up to and including the generator. The negative-sequence source impedance is found in a similar fashion. The zerosequence source impedance is usually not the sum of the component zero-sequence impedances because of the effect of the transformer connections. An example of the calculation of source impedance using Method A is presented below under "Fault Calculation Procedures and Examples."

Method B From a short-circuit study of the transmission system, obtain the per-unit values of fault current for a three-phase fault {It30) a line-to-line fault (ltLL), and line-to-ground fault {ltLG) at the high-voltage bus of the distribution substation. Preferably, these per-unit fault currents should be complex numbers. Also, if the per-unit value of V, the voltage at the substation high-voltage bus used to calculate the fault currents, was any value other than 1 + jO, it is important to know the per-unit value used. Then the sequence-source impedances at the high-voltage bus (HV) can be found as follows:

A1 (18)

(19)

(20)

Method C In some cases, only the three-phase fault kVA available at the high-voltage bus is given. This is similar to the fault-current approach outlined in Method B, except that only three-phase fault information is provided. In this situation, a value for magnitude of -2: s1 is calculated by converting the fault kVA to a per-unit fault current magnitude. Then, use Equation 21, assuming a nominal system voltage if the actual value of V at the high-voltage (HV) bus is unknown. Or, the per-unit magnitude of -2: s1 can be found directly from the following:

-2: S1, -2: S2, and -2: so are the sequence-source impedances

I

r

81 1= k_V._'A_30-"-F-AU_l_T_Ik_V._'A_B

at the high-voltage (HV) bus of the distribution substation, and ~ 1 is the fault impedance used in the short-circuit study Jsually, only bolted faults are calculated in transmission-system short-circuit studies, and -2: 1 is zero and can be omitted from Equations 18 through 20. Also, it is common to calculate only three-phase and line-to-ground faults. If these are the only fault-current values available, then assume -2: S2 = -2: S1. In 11ost situations, Equations 18 through 20 would be replaced ':JY the following:

(21)

V2 kVA3111 FAULT-PU

where I -2: s 1 I = magnitude of positive-sequence source impedance in per-unit, V = line-to-line voltage at high-voltage (HV) bus of substation in per-unit, kVA3r;,FAULT =available three-phase fault kVA, kVAs = base kVA, and

(22)

3V

rso = - - 2rs1

(23)

IfLG

Note that Equations 18 through 20 and 21 through 23 involve ::omplex number calculations and will lead to source impedances :ontaining both resistance and reactance terms. However, if, from the short-circuit study, only the magnitudes of the fault :urrents and the magnitude of the per-unit voltage V are known, then the equations can only provide the magnitudes of the source impedances. In this event, it would be necessary either to assume the source impedances are pure reactances or to assign some reasonable resistance and reactance values that combine to give the proper magnitude. Generally, since resistances are normally omitted in transmission-system short-circuit studies, it is appropriate to assume the impedances produced by solution of Equations 21 through 23 are pure reactances. The -2: s1, -2: S2, and -2: so values obtained from the above equations are high-voltage bus values and must be appropriately combined with the per-unit sequence impedances of the substation transformer to give the desired source-sequence impedances at the low-voltage bus of the substation. Also, it -nay be necessary to calculate -2: so at the high-voltage bus Equation 20 or 23) if the substation transformer connection IS such that the zero-sequence system impedance viewed from the low-voltage side of the substation is unaffected by j'je value of -2: so. For example, of the eight transformer connections shown in Figure 1 OA 1, only in the case of connection 3 (wye-wye grounded) will -2: so be added to the :ransformer zero-sequence impedance and therefore affect 'dhe zero-sequence source impedance seen from the low-voltage bus. With each of the other seven connections, the low-voltage zero-sequence source impedance is independent of -2: so seen at the high-voltage bus.

kVA30 FAULT-PU = available three-phase fault kVA in per-unit. As in Method B, assume I -2: S2 I = I -2: 81 I if no further information is provided. If a value of -2: so is needed at the high-voltage bus, it must be estimated based on prior experience with the system under study, since it cannot ·be obtained knowing only the three-phase fault kVA. Here again, the substation transformer connection should be determined first. For many connections, -2: so at the high-voltage bus is not needed for fault calculations on the distribution system.

Method D Another possible origin of sequence-source impedance information is the bus-impedance matrix data used in some transmission-system short-circuit studies. In these studies, the following conditions prevail: each generator is represented by a constant voltage behind the machine reactance (usually transient or subtransient reactance), the shunt connections (for example, line capacitances to ground) are neglected, all the transformers are set at nominal taps, and ground is taken as a reference. In the bus-impedance matrix, the diagonal elements are the impedances seen from each bus looking back into the system. These diagonal elements are also called the driving-point impedances. If the high-voltage bus of the distribution substation is represented in the bus-impedance matrix, then the diagonal element corresponding to the highvoltage bus in the positive-sequence bus-impedance matrix is the desired value of -2:81. The similar diagonal element in the zero-sequence bus-impedance matrix is the desired value of -2: so. As in Method B, these values must then be appropriately combined with the substation transformer per-unit sequence impedances to produce the source-sequence impedances at the low-voltage bus of the substation.

Fault Impedance In the application of overcurrent protective equipment to distribution systems, it is important to have a knowledge of minimum as well as maximum fault-current levels. This

31

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY Tools for Fault Analysis (Continued)

means that a fault study should result in both maximum and minimum values of fault-current magnitude at each node of the circuit. Generally, on a radial system the conditions that produce maximum fault-current levels are: maximum voltage, source impedances for maximum generation conditions, and zero values of fault impedance. Conversely, the usual conditions for minimum fault currents are minimum voltage, source impedances during times of minimum generation, and some non-zero value of fault impedance. (In most practical situations, these conditions are valid for maximum and minimum magnitudes of current for three-phase, line-to-line, and lineto-ground faults. However, there are actual circuits where the current magnitude in one phase of a double line-to-ground fault will increase when going from a zero to a non-zero value of fault impedance. This is covered briefly under "Basic Approach" in the section titled "Fault Calculation Procedures and Examples:') In many fault studies, it is customary to use a nominal system voltage in the fault-current equations. Frequently, no distinction is made between circuit loading conditions that produce maximum and minimum voltages. Also, it is assumed that the voltage at an end of the circuit has the same magnitude as the voltage at the substation. Furthermore, in many studies, maximum and minimum generation-source impedances are assumed to be equal. The validity of these assumptions varies from one circuit to another. But if they are reasonable assumptions for a given circuit, then only fault impedance permits a distinction to be made between maximum and minimum faults. Fault impedance (~f) is simply the impedance in the fault (Figure 20A 1, Page 37). It is not positive- or zero-sequence impedance, which are system characteristics. It is not necessarily related to any ground impedance or any so-called ground effects. Earth resistivity and mutual impedance between an overhead conductor and a conducting ground plane are examples of ground effects. Both of these affect the values of ~ 1 and ~ o, but not ~ t, which is a highly variable item, depending on the cause of the fault, the type of fault, and the environment. A line-to-line fault on an overhead circuit caused by a dry or dead tree branch can be a high-impedance fault and ground is not involved at all. A fallen conductor will be a low ~ f fault if the conductor drops into a stream or ground water, but it can be a high ~ f fault if it drops onto a dry pavement where ground-contact resistance is high. Also, in any specific fault situation, ~ f is a time variable. A fault may begin as a high-impedance, low-current fault and progress to a low-impedance, high-current fault. Conversely, a fault may start out with some fault impedance that increases to infinity if the fault is self-clearing, such as a fault caused by an animal that positions itself between a phase conductor and ground.

32

By now it is probably apparent that fault impedance is a nebulous quantity. Selecting an appropriate value for ~ f is by far the weakest link in the procedure for finding minimum fault currents on a system. Therefore, some engineers elect not to calculate minimum fault currents at all. Instead, they pick a value such as the current-carrying ability of the conductor at the given point on the circuit as the minimum fault current at that point. Then, by selecting a recloser or other protective device on the source side of this point so that it will operate to clear a current of at least this magnitude in a sufficiently short time, they prevent damage to the conductor. A disadvantage to this approach is that fault currents below the thermal limit of the conductor may not be detected. Other engineers calculate minimum fault currents using some stated value of ~ t. Generally, it is assumed to be a pure resistance. If ~ f could be measured in a large variety of fault situations, the value would be found to be statistically distributed over a wide range. A study of this type was conducted in the 1930s on various 26 to 220 kV systems. An EEl and Bell System report (Reference 13) of the analysis of 1375 faults on these systems states the most frequently occurring values of apparent fault resistance ranged from 5 to 25 ohms. An IEEE Committee Report (Reference 14) states that fault impedance was used in calculations by three of the 26 companies surveyed. Two of the three companies used 20 ohms and one used 40 ohms. Of the remaining 23 companies, seven reported they used zero fault impedance and 16 gave no response. A Rural Electrification Administration Bulletin (Reference 15) recommends using 40 ohms for ~ f in minimum line-to-ground fault calculations, but does not give the basis for the recommendation. Whatever value is chosen for ~ f in a given situation, the minimum fault currents resulting from calculations should not be used indiscriminately. A 40-ohm fault at the end of a long circuit may produce a calculated current in some source-side device that appears to be less than normal load current. Conversely, if nothing other than zero is used for ~ t, then a fault midway on a feeder or close to the substation may produce a calculated minimum fault current that is too large, and the result might be selection of a source-side device setting or rating that prevents detection of fault currents smaller than those calculated. Thus, judgment is required in the use of calculated minimum fault-current values, no matter what value of fault impedance is used in the calculations. It is desirable to arrive at a minimum fault current that establishes with reasonable confidence the lower end of the fault-current range at each point of a circuit. The goal is to make the probability of occurrence of faults with currents below this range as low as possible, recognizing that there is always the possibility of high-impedance faults occurring that cannot be detected by the protection system.

A1 System Faults TYPES OF FAULTS The type of fault that can occur depends on the distribution system. Line-to-ground, line-to-line, and double line-to-ground faults are common to single-, two-, and three-phase systems. Three-phase faults are, of course, characteristic only of three-phase systems. Line-to-ground faults result when one conductor falls to grou nd or contacts the neutral wire. Possible points along a is the angle separating the voltage zero and the time at which the fault occurs (t=O). The details of the solution of Equation 44 are well covered in Reference 16 and other textbooks, so only the result is stated here. Assuming the prefault current to be zero (i.e., load current = 0) then the solution is ·Rwt i = Ae X+ 8 sin (w+ e-o) where

E

A=

sin (0-e)

,f R2 + X2 E B = r,f:;;R:;;:2:::+:::;:X;:;;:2 ()=tan · 1 ~)

R

L

~~~--~-----, I I

=E sin (wt + ¢]

SWITCH

,--L-. I LOAD I

'--r-' I

....__ _ _ _ _ _ _ _ _ _ ___. _____ .JI

Figure 21 A1. Single-phase circuit for study of current behavior immediately following a fault.

* Portions adapted from material in Reference 17.

38

and

X =wl

(45)

The first term in Equation 45 is the transient part of the solution, since it is decaying exponential whose value disappears eventually. The second term is the steady-state part of the solution. These are also the d-e and a-c components, respectively. The second term is a sinusoidal function of time whose crest value is simply the crest value of the supply voltage divided by the magnitude of the system impedance as viewed from the fault. The phase difference 0 between the supply voltage (E sin(wt+ 4>)) and the steady-state fault current depends only on the X/R ratio of the circuit impedance. The significance of the transient and steady-state components of the fault current is best illustrated by considering an actual example. Figure 22A 1 shows a specific circuit with an X/R ratio of 5. The circuit is supplied by a 60-hertz source (W=377), with the fault arbitrarily occurring (switch closes) at 20 degrees on the voltage wave. The numbers obtained from the general solution, Equation 45, are given in the figure.

A1 X= 100HMS

E= 100VOLTS R

X

w

=377 RADIANS/SECOND

¢ = 20° = .349 RADIANS

R=20HMS X=5

R SWITCH CLOSES · Att=O

~=10.20HMS

SUBSTITUTING INTO EQUATION 45

i = 9.8 sin (1.024) e'

75 41 .

{)=tan

·1 X

R

78.7o 1.373 RADIANS.

+9.8 sin (377tt1.024)

= 8.37 e' 75.41 + 9.8 sin (377t- 1.024) Figure 22A1. illustration of significance of transient and steady-state fault-current components.

Figure 23A 1, however, graphically illustrates the interaction :i the terms of the equations. The curves were plotted from ne specific example of Figure 22A1 and the time base is ;raduated for that solution. The curves themselves are abeled with the general equation symbols, so that the interaction :i curves and equations is clearly shown. The upper curve snows the voltage waveform. The fault is assumed to occur ~=0) at a point on the ascending voltage wave 20 degrees after a voltage zero. The lower graph shows the total fault current solid curve) and its transient and steady-state components jotted curves) plotted on a time scale identical to that of the ..oltage waveform. The solid current curve, which is the wave· shape that would be observed on an oscilloscope connected nto the circuit, is the sum of the two dotted curves. Although "'$ither of the two current components could be recorded in his transient period by an oscilloscope, the dotted curves are still of interest since they provide a better perspective of asymmetry. Asymmetry in an a·c power system is the phenomenon whereby the symmetrical current oscillations about the zero ine are shifted so that they oscillate around some transient -eference line that is neither straight nor zero. In Figure 23A 1, :Tie total current is oscillating around the decaying exponential :;urve, which means that the exponential curve is the new --eference "zero" line for the sine wave. This will make the total :urrent wave asymmetric with respect to the true zero line, since the positive loops of current reach different crest 'Tlagnitudes than the negative loops. Now that asymmetry has been defined, what is its significance n dealing with fault currents? The answer lies in two important aspects of the problem: first, the magnetic force exerted on carts due to the current, and, secondly, the thermal or joule content of the fault current. Both the thermal and magnetic lorce characteristics are a function of the square of the current. In Figures 22A 1 and 23A 1, the first peak of the asymmetrical Naveform has a magnitude approximately 1.5 times the crest value of the steady-state waveform. For example, at this point ::he magnetic forces on interrupting equipment are about 2.25 jmes the forces caused by the steady-state fault current. In :he same fashion, if the first loop is not only greater in ampli· :ude but is above the zero line for longer than half a cycle (as :n Figure 23A 1), then the i2t content of the current (that is, its ::hermal or heating effect) is much greater. Both of these affect the design and application of the protective equipment used on a power system.

This is where the significance of current asymmetry lies. In designing and applying devices that will be exposed to fault currents, transient as well as the steady-state fault currents must be considered, since both thermal effects and mechanical forces can be greatly magnified in the initial transient period.

Application of Current Asymmetry Information The maximum magnetic forces produced in a device occur at the instant the current is maximum. In Figure 23A1 for example, the total current has peaks at approximately 7, 15, 24, and 32 milliseconds for the time range displayed. A protective device, such as a recloser, in a circuit where this fault current is flowing will experience peak magnetic forces at the same times. From the equipment design and application viewpoint, the largest of the peaks is of interest, since it subjects equipment to the severest test with respect to magnetic forces. For certain values of the voltage phase angle ( c/>) (Equation 44), the largest peak will occur in the first current loop, as shown in Figure 23A1. However, there are other values of 4> for which the largest peak will not occur until the second loop. Figure 24A 1 shows a current waveform of this type. The larger of these peaks can be found mathematically by differentiating the current expression in Equation 45 with respect to its two independent variables t and cf>. (The other variables, E, R, X, and w, are fixed for any given circuit). When this is done, it is found that the larQer of the two "largest" peaks occurs for zero voltage angle cp. which places it in the first current loop. The current waveform thus resembles that shown in Figure 23A 1 rather than that in Figure 24A 1 This 4> = 0 condition is called the condition of maximum asymmetry. References 17, 18, and 19 provide a thorough treatment of the mathematics of analyzing current under the condition of maximum asymmetry, and the details are well worth studying for a clear understanding of the implications of asymmetry. They show that some of the effects of asymmetry are dependent only on the X/R ratio of the circuit; also, that the effects on the peak value and the energy content of the first current loop are much greater than the effect on the rms value. For the condition of maximum asymmetry, the rms value of the first current loop can be as great as 1.7492 times the rms value of its steady-state symmetrical component (References 17, 18).

39

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY System Faults (Continued)

+ 100 e (t)

100 Sin (377t + .349) VOLTAGE

5

20

-100

0

1.0

0.5

TIME {CYCLES)

I (t) = 9.8 Sin (377t- 1.024) + 8.37e'

7

+15

TOTAL CURRENT

,..""

a:

·~

1/ {

I 2

w

,

'

----r---- .' """

w w

1-

..,.,.,..........

I

'\ \

a:

754

/

ClJRRENT

'\

· - - -..

I

I

0

5

,gj

2.0

1.5

I

TIME(ms) ·

0

I

-5

I 20

I

/

I

''

-10

......

_.....,,.

/

/

-15

0

0.5

Figure 23A1. Interaction of terms of equations in Figure 22A1.

40

1.0 TIME (CYCLES)

1.5

2.0

A1

Figure 24A1. Current waveform with largest magnetic-current peak in the second loop.

However, the peak of the first current loop can be as great as two times the peak of the steady-state component, and this energy content can be six times that of the first loop of the symmetrical a-c component (Reference 17). From the viewpoint of equipment design and application, these peak current and energy comparisons are more meaningful than a comparison of rms values. The discussion here is confined, however, to rms relationships, since this is the way equipment is now rated and standards are written. The root-mean-square (rms) value of an arbitrary current is (46) where

i = a current function of time t =time T = time interval specified for the rms determ in at ion.

If i = B sin wt, where B is the crest value of a sinusoidal current, Equation 46 shows that I = B/{2 so long as T is an integral multiple of a half cycle. From a physical viewpoint, a sinusoidal current with a crest value of B will have the same effect on p loss in a conductor as a d-e current whose value is B/ or this reason, I is sometimes called the effective value of i, but this {2 relationship does not in general hold for an asymmetrical waveform. Applying Equation 46 to Equation 45 results in a detailed expression for the rms value of the asymmetrical waveform, and the time interval for the integration or averaging process definitely influences the outcome (References 17, 18). Identifying the rms value of the steady-state a-c component of current in Equation 45 as I and the rms value of the total current as 1', then a useful measure of an asymmetrical waveform is the ratio I'll. Fault-current calculations (Equations 39 through 43) produce values of I. If an appropriate value for the ratio I'll is known, it can be multiplied by the calculated I value to obtain the rms value of the asymmetrical waveform. Gross and Thapar (Reference 19) cite an expression that is a function only of X, R, and . For any given value of X/R, the value of I'll with respect to can be maximized and then plotted as a function of X/R. (For the reader who has gone into the details of asymmetry calculations, Hshould be noted that this procedure involves maximizing 1', not i. Maximizing I'

is the same as maximizing I'll, since I is constant. The condition for maximum i is a zero voltage angle , as described earlier. But for maximum I', the value of is always greater than zero. If I' is calculated for the first current loop, the maximum value of I'll is 1. 7662. It occurs at an X/R ratio of 200 and an angle of 12 degrees.) The result of plotling the maximums of I'll is shown in Figure 25A 1. While the integration time interval T for finding I, the rms value of a symmetrical waveform, is constant n, the interval for finding I' varies with X/R and 0. The T used to find I' in Figure 25A 1 is not constant, but it is always the time to the first current zero of the asymmetrical waveform. At a point of fuse application on a specific circuit - if for example, the rms symmetrical fault current for a line-to-ground fault is known (Equation 41) - the single-phase equivalent X/R ratio can be found from the total system impedance used in the fault calculation. For a line-to-ground fault with zero fault impedance, this would be (2-21 + -2 o)/3. The reactive part of this impedance divided by the real part is the singlephase equivalent X/R ratio. An I'll value can be found from Figure 25A 1 for this value of X/R. This multiplied by the calculated rms symmetrical fault current will produce the greatest rms asymmetrical value possible for that type of fault. The same procedure is used for all types of faults possible at the fuse location. Then, the largest rms symmetrical and asymmetrical values can be used for selecting the fuse cutout with the proper interrupting ratings. (Since Figure 25A 1 is based on the analysis of current in a simple R, X series circuit, the procedure described is not precisely correct for finding the RMS of the asymmetrical current in a double line-to-ground fault or in any system whose symmetrical component equivalent circuit involves parallel paths. More study of the transient behavior of fault current for various types of faults and various systems needs to be made. However, the procedure described is more precise for line-to-line and single line-to-ground faults than simply using the X1/R1 ratio, which, strictly speaking, is valid only for three-phase faults.) This, briefly, illustrates the application of current asymmetry information of the type provided by Figure 25A 1, which, as noted, is based on the first current loop. This is especially useful in the application of fuses, since many fuses interrupt at the current zero following the initial loop. It is also useful in checking the momentary ratings of switches, sectionalizers, and breakers. However, the use of Figure 25A 1 for selecting breakers or reclosers with adequate interrupting capacity can result in the selection of ratings much higher than necessary. In this instance, the rms value of the first current loop is too conservative for comparison with the interrupting ratings of breakers and reclosers, since these devices do not usually interrupt for a number of cycles after fault initiation. For many practical values of X/R ratio, this means much of the asymmetry has disappeared, and the device is interrupting essentially a symmetrical current. The procedure to follow in selecting breakers and reclosers with adequate interrupting ability for a specific circuit is given in industry standards (References 20, 21).

41

A. Overcurrent Protection 1. FUNDAMENTALS AND THEORY System Faults (Continued)

.,

•i

"'

1.8

1.7 .. ·

PLOT OF MAXIMUM VALUES OF 1'/1 VERSUS X/R WHERE 1'/IIS THE RATIO OF THE RMS OF THE FIRST LOOP OF THE ASYMMETRICAL WAVEFORM TO THE RMS OF THE FIRST LOOP OF THE SYMMETRICAL WAVEFORM.

Q 1.5

~

1-

ffi 1.4

~

··-

,_,-

~

/

1/~

0::: 0:::

:::1

1.3

/

1.2

1.1

1.0

,JJ/ '

1.6

0

,·

-

~

v

"

/~

"

I'

0.9

t,l

.

" I .. I

.2

,.

.5

2

5

I

I

10

' 20

I

50

100

SHORT CIRCUit RAtl6 X/R Figure 25A1. Result of plotting the maximums of 1'/I. MOTOR-CURRENT CONTRIBUTIONS If short-circuit current contributions from large rotating machinery are neglected in system fault studies, the increased current may cause the interrupting capacity of a device to be exceeded. To determine rotating machinery contributions, the reactance (or impedance) is calculated using the multiplies in Table 8A 1, and all three-phase motors above 50 hp are treated as sources. As an aid in understanding this complex subject, following is an excerpt from ANSI/IEEE Standard 141-1986, from which the table (number 24 in the ANSI/IEEE text) has been reproduced. The excerpt has been slightly edited to eliminate potentially confusing references to material not cited in this manual. To simplify comprehensive industrial system calculations, a single combination first-cycle network is recommended ... based on the following interpretation of ... standards. Because the initial symmetrical rms magnitude of the current contributed to a terminal short circuit might be 6 times rated for a typical induction motor, using a 4.8 times rated current first-cycle estimate for the large low-voltage induction motors (described as all others, 50 hp and above in Table 8A 1) is effectively the same as multiplying subtransient impedance by approximately 1.2. For this motor group, there is reasonable correspondence of low- and high-voltage procedures. For smaller induction motors (all smaller than

42

50 hp in Table 8A 1) a conservative estimate is the 3.6 times rated current (equivalent of 0.28 per unit impedance) first-cycle assumption of low-voltage standards, and this is effectively the same as multiplying subtransient impedance by 1.67. With this interpretation as a basis, the following induction motor treatment is recommended to obtain a single combination first-cycle short-circuit calculation for multivoltage industrial systems: (a) Include connected motors, each less than 50 hp, using a 1.67 multiplying factor for sub-transient impedances. if available, or an estimated first-cycle impedance of 0.28 based on motor rating. (b) Include larger motors using the impedance multiplying factors of Table 8A 1. Most low-voltage motors 50 hp and larger are in the 1.2 times subtransient reactance group. An appropriate estimate for this group is first-cycle impedance of 0.20 per unit based on motor rating. Short circuits can be calculated using procedures described in the following section. The multiple sources and impedances are paralleled to the point of fault (Reference 24).

A1 TABLE 8A1 Rotating- Machine Reactance (or Impedance) Multipliers First-Cycle Network

Interrupting Network

1.0 Xd" 0.75 Xd" 1.0 Xd"

1.0 Xd" 0.75 Xd" 1.5 Xd"

1.0 Xd" 1.0 Xd" 1.2 Xd" Neglect From ANSI/IEEE C37.010-1979 (2) and ANSI/IEEE C37.5-1979 (3) 1. Xd"of synchronous rotating machines is the rated-voltage (saturated) direct-axis subtransient reactance. 2. Xd"of synchronous rotating machines is the rated-voltage (saturated) direct-axis transient reactance. 3. Xd" of induction motors equals 1.00 divided by per-unit locked-rotor current at rated voltage.

1 .5 Xd" 1.5 Xd" 3.0 Xd" Neglect

Type of Rotating Machine All turbine generators; all hydrogenerators with amortisseur windings; all condensers Hydrogenerators without amortisseur windings All synchronous motors Induction motors Above 1000 hp at 1800 r/min or less Above 250 hp at 3600 r/min All others, 50 hp and above All smaller than 50 hp

FAULT CALCULATION PROCEDURES AND EXAMPLES This section outlines a procedure for finding fault currents on a distribution system and includes some numerical examples.

Assumptions lin the following fault calculation examples, the underlying assumptions are: 1. System frequency is 60 hertz. 2. Distribution feeders radiate from only one substation. There is no other source of power feeding into the distribution circuits. 3. The supply system is represented by the source impedance at the substation low-voltage bus. This is the impedance looking back into the system supplying the distribution circuit. 4. The current prior to the fault is neglected: that is, all shunt connections (loads, line charging, etc.) are neglected. Thus, the voltage at each node of the circuit will be assumed to be the nominal distribution voltage.

Basic Approach This section describes an effective and readily usable procedure for calculating fault currents in a radial distribution system. An example of its application to a simple system is pro'iided in the next section. Also, since much of the procedure IS easily programmable and many fault-current calculations today are done on a computer, results from a computer study are included. The procedure consists of the following steps: 1. Draw circuit diagram.

For each identified type of overhead and underground line, use Tables 1A 1 through 7 A 1 to find its positive- and zerosequence impedances in ohms/1 000 feet. In some situations, the tabulated impedances may not be applicable, and it will be necessary to resort to calculations using impedance equations. 4. Determine line-section sequence impedances in ohms. For each line section of the circuit diagram, multiply the section length in thousands of feet by the ~ 1 and ~ o values from Step 3 in ohms/1000 feet. 5. Select fault impedance. In general, fault-current calculations are made both with and without a fault impedance. Also, it is important to note that, in some cases, the maximum fault current corresponds to a double line-to-ground fault with impedance (see pages 37 and 38). 6. Calculate total sequence impedances at point of fault. Add the positive-sequence impedances from Step 4 of all line sections connecting the point of fault to the source, including the positive-sequence source impedance determined in Step 2. Repeat the procedure for the negative- and zero-sequence impedances, with the negative-sequence impedance of a line section being equal to its positivesequence impedance. 7. Find symmetrical fault currents. Use the formulas developed under ''Types of Faults" to calculate the following currents: A. Three-phase fault (39)

A. Label the points on diagram where fault currents are to be calculated.

B. Line-to-line fault

B. Identify the different types of overhead circuit and underground cable used. C. For each line section, write on the diagram the circuit type of the section and its length in feet. 2. Calculate sequence-source impedances. Depending on what information is available on the supply system, use one of the methods outlined previously to calculate the positive-, negative-, and zero-sequence impedances. An example illustrating the use of method A begins on the next page. 3. Determine line-section sequence impedances by type in ohms/1000 feet.

(40) C. Line-to-ground fault

I I I= I

3Vt I r 1 +r 2+r 0 + sr t

(41 )

D. Double line-to-ground fault

III=I-if3V,

ra+3rt-ar2 I r 1 r 2+ 0

2

a:

~~

J:

1-

._!.

w

...J

,.,

::!

~

....

....... .... r/ .... .......

.5

1/:

~

::!

,.....,.

-

200 !50

130 ~ :::: .... 100

::,.....-

~~

"""' ~ """' ~ ~ ....... ..... ......... ......... """' ..... k t::: .,...,.. .......

75 65 50 45 40 30&35

::::. ...... ~ ~ ~ .,.

- -- L. ~ ~ .....

5

:::>

(!l

i---""

~ ~ ;.....

1-

a:

-

20

~

!

~

'

~ ~ ¥~&20. .,...,.. ......-:: ;..... 12 ;.... ...... 10 ...-:::: .,...,.. ~ ..... ...... ....... ~ 68

.,...,..

-

...... 1""""- ~r""'

v

AMPERE RATINGS OF FUSES

.....

~

.2 .1 .1

.2

.5

2

5

10

20

50

100

AVAILABLE CURRENT (nns symmetrical kiloamperes)

Figure 9A2. Maximum Jet-through current for NX current-limiting fuses - 4.3 and 5.5 kV.

57

A. Overcurrent Protection 2. PROTECTIVE EQUIPMENT CHARACTERISTICS AND GENERAL APPLICATION FACTORS Fusing Equipment (Continued)

100 /

50

/

,.... ~-"'!~ ::;... k t;:: ::::;:. ;;; ,.... ~~~88065 ~~ /

0

~

Q)

0.

20

E

"'

~~F'

.Q

:i2 -"

10

Q)

z

w a: a:

~~ ~

1- ,.,.. ~ .... ~ f::::: 1~~

::J

0 I

2

0

~

~~

a:

I 1-

t!. w

....1

-_ /

.5

x

~--"' ""'

.2

l..,......1

...-

....

/ ..... ~~

v

-

"'

8

1-

......... ~ """" ~

...-

1-""

-

......... 1.........

~

.... ....

8

....

6

....

3:ij

-

....

1.5

AMPERE RATINGS OF FUSES

~

I-"'

"""" ...- ""'

............ 1-

.5

.2

.1

10

5

2

20

50

100

AVAILABLE CURRENT (rms symmetrical kiloamperes)

Figure 1OA2. Maximum let-through current for NX current-limiting fuses- 8.3, 15.5, and 23 kV.

120

100 38 KV FUSES 6 THRU 12 AMP

c> w

:::!!:

40

I I I I I I 8 3 KV FUSES 1.5 THRU 12 AMP

~

:::!!:

·

5.~ KV FUS~S

20

1

I

I

-~

6THRU 12 AMP

0 .1

.2

.3

.4 .5

.7

2

3

4

5

7

10

AVAILABLE CURRENT (rms symmetrical kiloamperes)

Figure 11 A2. Maximum peak-arc voltage for current-limiting fuses as related to available current.

58

20

30

40 50

70

A2 phase-to-phase fault when one fuse operates before the second has a chance to melt. For ungrounded systems, the maximum voltage rating of the cutout should equal or exceed the maximum system phaseto-phase voltage. For grounded systems on single-phase taps, the maximum voltage rating should equal or exceed the maximum phase-to-ground voltage of the system, provided the BIL rating is compatible. For three-phase applications, a cutout should be used with its maximum voltage rating equal to or greater than the maximum phase-to-phase voltage. On three-phase systems, however, faults that produce conditions for which a single cutout must interrupt against phase-to-phase voltage are relatively rare, so that slant-rated cutouts may commonly be used. Table 3A2 lists typical cutout applications.

·oo

I

90

80

/

> =-

·~

70

I

'::::

> 60 :i < 50

I

::i:

40

::i: X

PR;ECTED OR BACKUP DEVICE

C ) PROTECTING DEVICE

Figure 1A3. Conventional definition of protective devices based on location. Fuse links are indicated for illustration.

Protective devices are located at the coordinating points. Device A is at the substation, C and H are in the feeder, B is in the branch tap off the feeder, D is on the distribution transformer primary, and E, F, and G are service entrance fuses on the distribution transformer secondary. All devices must be selected to carry normal load current and respond properly to a fault, as follows: • With respect to C, the protecting device is H, which means that, for a fault at point 1 , device H must interrupt and C must not open. • With respect to A, the protecting device is C, which must interrupt permanent fault current at point 2 before A operates to lockout. • Device B also is a protecting device for A and must operate similarly to C for a fault at point 3. • Only device A functions for a fault between A and C, such as at point 4. • For a transformer fault at point 5, device D interrupts current and permits normal load current to flow in the rest of the system. • For an overload on the transformer secondary at point 6, device E interrupts that circuit only, so that power to the transformer may be continued and customers on the other secondary taps will receive service.

Such coordination of properly selected and installed devices will make possible the achievement of these basic rules of distribution protection: 1. Give all faults a chance to be temporary, for most of them are - perhaps as high as 70 to 80 percent. 2. Lock out (interrupt power) only for permanent faults. 3. Remove only the smallest possible portion of the line from service. In a typical, more complex protection scheme than that shown in Figure 1A3, some devices serve both protecting and protected roles, depending on the location of specific faults. Also, devices with automatic reclosing capability, such as circuit reclosers, are provided at appropriate points to permit momentary interruptions in response to temporary faults.

DISTRIBUTION TRANSFORMERrv~~

EXAMPLE OF SYSTEM COORDINATION Figure 2A3 diagrams overcurrent coordination for a system in which a substation receives power from a high-voltage transmission line and steps the voltage down to 7.2/12.47 kV. Power to the customer is delivered by 7200 - 120/240-volt transformers. LOAD

LOAD

Figure 2A3. Typical example of system coordination.

82

LOAD

A3 Fuse-Fuse Coordination The first step in establishing a fuse-fuse coordination philosophy is strict adherence to the just-described fundamentals for ax>rdinating series protective devices. All faults should be given a chance to be temporary, lockout should occur only for permanent faults, and when lockout does occur, only the smallest possible portion of the line should be removed. For series-coordinated devices, the trip zones of protection owertap. An accepted rule for coordinating fuse links is that !he maximum clearing time of the protecting link should not aceed 75 percent of the minimum melting time of the protected link. This assures that the protecting link will interrupt n clear the fault before the protected link is damaged in anyway, as further explained below. Three methods that may be used in coordinating fuses are 1he application of time-current curves (TCCs), the use of mordination tables, and rules of thumb. The TCC method, fhe most accurate, must be used for critical coordination areas. Tables, which are derived from TCC coordination, are ll!latively accurate and can be used in repetitive situations. ~=~des of thumb, the least accurate, will achieve satisfactory toofdination in limited applications where fuses are used all il one series, in either preferred or nonpreferred ratings.

the feeder. Even more difficult to quantify are the effects of predamage - the degree to which fuse clearing characteristics may be affected when currents approach the minimum melt of the time-current characteristic. To avoid the effects of predamage, in no case should the protected link be allowed to experience a current within 90 percent of its minimum-melt curve. Example of fuse-link coordination based on TCC comparisons: Figure 3A3 shows a typical study for part of a system with feeder fuse A and branch-line fuses B and C. Known maximum available fault current in symmetrical amperes and normal load current are shown at each coordination point. Type T tin links will be used in all protective devices.

____3~:---------~---0--+-J~'OJS_A_~_P_E_R-ES---r--~ jr sar ~L SUBSTATION

36AMPERES'

TCC COORDINATION METHOD ID most cases, the entire system coordination is based on TCCs for one particular fuse type (K, T, N, etc.) throughout !he system. If so, coordination is somewhat simplified. In applying fuse links as the protective devices in Figure 1A3, coordination should assure that the source-side protected ink (A) is not damaged when a fault occurs in the zone of eiher load-side protecting link (B or C). Factors to consider in a:complishing this are: 1. Tolerances. 2.. Ambient temperature. 1 Preloading effects. 4. Predamage effects.

In practice, rather than going through a detailed analysis of factors (they are discussed below), a derating factor of 75 percent can be used. This will achieve the desired coordi'111fion (and prevent damage to the protected link) by assuring 'hal the maximum clearing time of the protecting link is no peater than 75 percent of the minimum melting time of the praected link. As previously stated, the tolerance in time-current c:haracteristics is automatically taken into account in standard TCCs. Simply overlaying the curves and comparing maximum dearing of protecting links to minimum melt of protected links ,_. account for tolerance. Published TCCs are based on a 25° C ambient temperature. ~r temperatures will reduce the melt time and lower .-Dent temperatures will increase it, as was shown earlier · FIQUre 15A2, Section A2. While this is difficult to evaluate ill view of yearly and daily variations in temperature, a range can be developed based on maximum and minimum yearly ~lEse

~ratures .

Preloading effects -the degree to which the flow of current lwough a fuse link will raise the temperature and thereby 'li!!OJce melting time - are not taken into account in developing TCC curves. Using Figure 14A2, Section A2, the effect of p:eloading can be determined for tin and silver links. As with antlient temperature variations, this is a difficult characterisic to evaluate, since preloading can vary over the life cycle of

~~~

A

@

21 AMPERES ....,__

,....15T

Figure 3A3. Diagram for study of TCC fuse coordination method.

Figure 4A3 shows maximum clearing-time and minimum melting-time curves for possible links to be used at points A, B or C on the system. The 15T link, rated 23 amperes continuous, will meet the 21 ampere load current and provide a maximum clearing time of 0.021 second for 1550 amperes at point C. Minimum melting time is not a critical factor if no other devices need be coordinated with the last fuse link on the branch.

-\ 15T

.16

25T 30T

BOT ............... ~\

'~" 1\ \\ \

-,~,,

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1\

ll

.05 1

r-.. .03 11--

.02 11-,.016 '- ·

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08 07

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03 w

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CURRENT (AMPERES)

z

0

04hl

·, '· \ 1\ If\ \ ·" ' r\

1\1--

I

',

j\

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\.

2 15

i= 02 015

f1

Figure 4A3. TCCs for coordinating fuse links in Figure 3A3 example.

83

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Fuse-Fuse Coordination (Continued)

A link must now be found to carry 36 amperes continuous current, interrupt 1630 amperes at point B, and coordinate with the 15T link. The 20T link is unsatisfactory, because it can carry only 30 amperes continuously. The next choice, the 25T link, carries 3B amperes continuously. Minimum melting time of the 25T link at 1550 amperes is 0.016 second. Because the 25T link melts before the 15T link clears, this combination is undesirable for coordination. Minimum melting time of the 30T link at 1550 amperes is 0.031 second. The maximum clearing time/minimum melting time ratio for the 30T and 15T combination is 0.021/0.031, or 6B percent. This is satisfactory, as the ratio for desirable coordination should not exceed 75 percent. An BOT link will satisfactorily interrupt 1BOO amperes at point A, carry 105 amperes continuously, and coordinate with the 30T link at point B. The CT/MT ratio for the BOT-30T combination is 0.051/0.16, or 32 percent. The results of this study are shown in Table 1A3.

USE OF COORDINATION TABLES When, as in many situations, the choice of fuse-link coordination is a repetitive process, overlaying TCCs lends itself nicely to a tabular representation. If a suitable multiplying factor is chosen as representative of the system and the fault current can be determined over a range for which two fuse links will coordinate, tables can be developed and used. For ANSI standard links, this is relatively straightforward, since the links do not vary from one manufacturer to another. Examples of this are shown in Tables 2A3 through 6A3,

which employ the 75 percent ratio in indicating the maximum fault-current values at which various types of fuse links will coordinate. Additional coordination tables are available from your Cooper Power Systems representative. The example cited under "TCC Coordination Method" can also be solved by using coordination tables. Again, select the 15T link as the protecting device at location C in Figure 3A3, based on load-current considerations; protected links at B and A can be chosen by referring to Table 3A3. First, locate 15T in the "Protecting Fuse Link Rating" column at the left, and then follow horizontally to the right to the "Maximum Fault Current" entry that is greater than the 1550 amperes available at location C. That value, 1700 amperes, corresponds to a protected link rating of 30T at location B, and since the 30T link can carry 36 amperes continuously, it is an appropriate choice. When the procedure is repeated with 30T as a protecting link at location B, Table 3A3 indicates that a fuse-link rating of 65T at location A will coordinate with the 30T link up to a fault current of 3100 amperes and satisfy the fault-current range. However, the load current at A is 105 amperes and, since the 65T link can carry only 97 amperes continuously, it will not satisfy the continuous current rating. The next larger size link, BOT, is therefore checked and found to be appropriate. As can be seen, use of the coordination tables makes fusefuse coordination relatively easy to accomplish while satisfying the 75 percent criterion.

TABLE 1A3 Study Results, Coordination of 25T - 15T Fuse-Link Coordination Location of Protected Link*

Protected Link

Protecting Link

Maximum Current Fault

Load Current

Protected Link Maximum Clearing Time

Protecting Link Minimum Melting Time

c

15T

-

-

21

-

-

B**

25T

15T

1550

36

.021

.0165

B

30T

15T

1550

36

.021

.031

A

SOT

30T

1630

105

.051

.160

Percent CTIMT

128 (.021/.0165) 68 (.021/.031) 32 (.0511/.160)

• See F1gure 1A3 •• No Coordination for 25T-15T combination.

TABLE 2A3 EEI-NEMA Type K Fuse Links Protecting Fuse-Link RatingAmperes

6K SK 10K 12K 15K 20K 25K 30K 40K 50K 65K SOK 100K 140K

Protected Link Rating - Amperes

8K

10K

12K

190

350 210

15K

20K

25K

30K

40K

50K

65K

80K

100K

140K

200K

5800 5800 5800 5800 5800 5800 5800 5800 5800 5800 5800 4500 2400

9200 9200 9200 9200 9200 9200 9200 9200 9200 9200 9200 9200 9100 4000

Maximum Fault-Current Protection Provided by Protecting Link - Amperes

510 440 300

650 650 540 320

840 840 840 710 430

1060 1060 1060 1060 870 500

1340 1340 1340 1340 1340 1100 660

1700 1700 1700 1700 1700 1700 1350 850

2200 2200 2200 2200 2200 2200 2200 1700 1100

2800 2800 2800 2800 2800 2800 2800 2800 2200 1450

3900 3900 3900 3900 3900 3900 3900 3900 3900 3500 2400

ThiS table shows max1mum values of fault currents at which EEI-NEMA Type K fuse links w1ll coordinate w1th each other. The table IS based on max1mum clearing-time curves FL2B for protecting links and 75 percent of minimum melting-time curves FL 1 B for protected links.

B4

A3 RULES OF THUMB Simple rules of thumb have been formulated for coordinating EEI-NEMA fuse links of the same type and category - for example, using preferred T links with preferred T, or nonpreferred K links with nonpreferred K. K links can be satisfactorily coordinated between adjacent ratings in the same series up to current values of 15 times the rating of the protecting link. T links can be satisfactorily coordinated between adjacent ratings up to a current value of 24

times the rating of the protecting link. Such applications ~ vide a safety factor of 75 percent or more. Preferred T ratings are 6, 10, 15, 25, 40, 65, 100, 140, 200; nonpreferred T ratings are 8, 12, 20, 30, 50, 80. As in lhe example in the preceding section, a 15T link will coordinate with a 25T link up to 24 times 15, or 375 amperes The rules of thumb cannot be extended further, and thus are limited in application.

TABLE 3A3 EEI-NEMA Type T Fuse Links Protecting Fuse-Link RatingAmperes

Protected Link Rating - Amperes

8T

10T

12T

350

680 375

1ST

20T

2ST

30T

40T

SOT

SST

SOT

100T

200T

9700 9700 9700 9700 9700 9700 9700 9700 9700 9700 9700 7200 4000

15200 15200 15200 15200 15200 15200 15200 15200 15200 15200 15200 15200 13800 7500

Maximum Fault-Current Protection Provided by Protecting Link - Amperes

6T 8T 10T 12T 15T 20T 25T 30T 40T SOT 65T

920 800 530

1200 1200 1100 680

1500 1500 1500 1280 730

2000 2000 2000 2000 1700 990

2540 2540 2540 2540 2500 2100 1400

3200 3200 3200 3200 3200 3200 2600 1500

4100 4100 4100 4100 4100 4100 4100 3100 1700

5000 5000 5000 5000 5000 5000 5000 5000 3800 1750

BOT

6100 6100 6100 6100 6100 6100 6100 6100 6100 4400 2200

100T 140T "'S

140T

table shows max1mum values of fault currents at wh1ch EEI-NEMA Type T fuse links Will coordinate w1th each other. The table 1s based on maximum cleanng-

11ne curves FL4B for protecting links and 75 percent of minimum melting-time curves FL3B for protected links,

t ABLE 4A3 Type K Fuse Links Protecting Fuse-Link RatingAmperes

5K 8K 10K 15K 20K 25K 30K 40K 50K 60K 75K 85K 100K 150K

Protected Link Rating - Amperes

8K

10K

12K

22

150

280 175

15K

20K

25K

30K

40K

50K

6SK

80K

100K

140K

200K

8900 8900 8900 8900 8900 8900 8900 8900 8900 8900 8900 8900 6000

10000 10000 10000 10000 10000 10000 10000 10000 10000 10000 10000 10000 10000 3000

Maximum Fault-current Protection Provided by Protecting Link - Amperes

400 350 200

490 490 370 200

640 640 640 450 175

1250 1250 1250 1250 1250 900

1450 1450 1450 1450 1450 1450 1300

2000 2000 2000 2000 2000 2000 2000 1300

2650 2650 2650 2650 2650 2650 2650 2500 1700

3500 3500 3500 3500 3500 3500 3500 3500 3200 2000

4950 4950 4950 4950 4950 4950 4950 4950 4950 4950 3700

"11115 1atlle shows max1mum value of fault currents at which Type N fuse links Will coordinate with each other. The table is based on maximum clearing-time curves IR..iB br protecti ng links and on 75 percent of minimum melting-time curve FL7B for protected links.

85

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Fuse-Fuse Coordination (Continued)

TABLE 5A3 Type K Fuse Link Coordination Protecting

(D)

20 500 500 325 325

1 1.5 2 3 4 5 7 10 15 20

25 750 750 670 670

30 1000 1000 900 900 620 620 620 620 620 620

40 1300 1300 1250 1250 1050 1050 1050 1050 1050 1050

65 2200 2200 2200 2200 2100 2100 2100 2100 2100 2100

50 1700 1700 1650 1650 1500 1500 1500 1500 1500 1500

80 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO

140 6000 6000 6000 6000 6000 6000 6000 6000 6000 6000

100 4000 4000 4000 4000 4000 4000 4000 4000 4000 4000

200 9500 9500 9500 9500 9500 9500 9500 9500 9500 9500

Max1mum fault current to wh1ch protected and protecting fuse Will cooradmate

TABLE 6A3 Type T Fuse Link Coordination Protecting

(D)

1 1.5 2 3 4 5 7 10 15 20

12 5BO 5BO

15 BOO BOO 730 730

20 1150 1150 1050 1050 BOO BOO BOO BOO

25 1400 1400 1400 1400 1200 1200 1200 1200 1200 1200

30 2000 2000 1900 1900 1BOO 1BOO 1BOO 1BOO 1BOO 1BOO

40 2500 2500 2500 2500 2500 2500 2500 2500 2500 2500

65 4200 4200 4200 4200 4200 4200 4200 4200 4200 4200

50 3200 3200 3200 3200 3200 3200 3200 3200 3200 3200

80 5100 5100 5100 5100 5100 5100 5100 5100 5100 5100

100 6400 6400 6400 6400 6400 6400 6400 6400 6400 6400

140 15000 15000 15000 15000 15000 15000 15000 15000 15000 15000

200 3000 3000 3000 3000 3000 3000 3000 3000 3000 3000

Max1mum fault current to wh1ch protected and protecting fuse w111 cooradmate

TABLE 7A3 EEI-NEMA Type K Fuse Link Coordination Protecting Fuse Link Rating- A

6K BK 10K 12K 15K 20K 25K 30K 40K 50K 65K BOK 100K 140K

Protected Link rating - Amperes

8

10 190

12 350 210

15 510 440 300

20 650 650 540 320

25 840 B40 710 430

30

1060 1060 1060 1050 B70 500

40 1340 1340 1340 1340 1340 1100 660

50 1700 1700 1700 1700 1700 1700 1350 B50

65 2200 2200 2200 2200 2200 2200 2200 1700 1100

80 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO 2BOO 2200 1450

100 3900 3900 3900 3900 3900 3900 3900 3900 3900 3500 2400

140

200

5BOO 5BOO 5BOO 5BOO 5BOO 5BOO 5BOO 5BOO 5BOO 5BOO 5BOO 4500 2000

9200 9200 9200 9200 9200 9200 9200 9200 9200 9200 9200 9200 9100 4000

ThiS table shows max1mum values of fault currents at which EEI-NEMA type K fuse links Will coordinate With each other. The table IS based on max1mum-cleanng time curves FL2B for protecting links and 75 percent of minimum-melting time curves FL1B for protected links.

86

A3 Current-Limiting Fuse Coordination """"-ee are several varieties of coordination situations involving

the system will allow modification of this factor. Example of source-side current-limiting fuse and loa«Hiide expulsion fuse coordination: Figure 5A3 shows the maxinun coordination point for a 65 NX fuse and a 25K link using a 0. 75 factor. The value is 1250 amperes.

current-limiting fuses. These include coordination of a sourceSide current-limiting fuse with a load-side expulsion fuse, a lmad-side current-limiting fuse with a source-side expulsion flEe, a current-limiting fuse with another current-limiting fuse, and a backup current-limiting fuse with an expulsion fuse.

LOAD-SIDE CURRENT-LIMITING FUSE AND SOURCE-SIDE EXPULSION FUSE

SOURCE-SIDE CURRENT-LIMITING FUSE AND LOAD-SIDE EXPULSION FUSE

The coordination of a load-side current-limiting fuse with a source-side expulsion fuse can be made simply by overlaying the TCC as in expulsion-fuse coordination. Again, a factor of 75 percent should be used to assure proper coordination. The zero-forcing properties and very inverse characteristic of the current-limiting fuse maximum clearing-time curve allow coordination through any level of fault current.

As with fuse links, it is essential that the protecting fuse operate I::IEfore the protected fuse begins to melt. An expulsion fuse nenupts at a current zero. Therefore, 0.8 cycles is considered !he minimum interrupting time and the range of coordination uil be limited as a result. A factor of 75 percent can again be wsed as a nominal number to take into account the various eilects-remembering, of course, that specific knowledge of 60 50 40

I

3600 3000 2400

\

1800

30

1\

20

.. ,.

\

1200 7.2/12.47 KV

~t ""l\., 65C

10

v

~

25K

8

2

300 240 65C MINIMUM MELT

\

_\

\

1\\

rJ)

0 .8 z 0 .6 (..) w rJ) .5 ~ .4 w .3

180

25K MAXIMUM CLEAR

120 (j)

60~ 48 ID

\.

:::!; ~

.2 25K 0.1 r-M INIMUM MELT .08 r-

N

36 ~

\

30w

:I:

24 18

\ \

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w

..J (..)

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12 > (..)

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1-

3.6 3.0 2.4

.05

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.75X65C MINIMUM MELT I

I I I II

1.8

'\ ~ \1 ~

.02

.01

600 480 360

6 5 4 3

-

~

~

8 88888§

l\

§

1.2

§§§§§~

CURRENT IN AMPERES

Figure 5A3. TCC for coordinating source-side current-limiting fuse and load-side expulsion fuse. 87

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Current-Limiting Fuse Coordination (Continued)

COORDINATING TWO CURRENT-LIMITING FUSES To coordinate two current-limiting fuses, the curve should be plotted beginning at 0.01 second. For current-limiting fuses, curves extend downward from that point to fractions of a cycle. Because clearance will occur within these short times, two time references must be considered. Above 0.01 second, a current-limiting fuse in series with another can be coordinated by simply overlaying TCCs and using a 75 percent coordination factor. Below 0.01 second, coordination can be achieved through the use of minimummelt and total-clear I2t values. A bar graph incorporating the 75 percent ratio is available for this (Figure 6A3). When coordinating two current-limiting fuses in series, the maximum let-through J2t of the protecting or load-side fuse must not exceed the minimum-melt I2t of the protected or source-side fuse. That is, the load-side fuse will limit the let-through energy to a magnitude that is less than would be required to melt the source-side fuse. Example: What is the smallest source-side 8.3 kV NX fuse that will coordinate with a 25 ampere load-side NX fuse? The bar graph (Figure 6A3) shows that the maximum let-through of the 25 ampere NX fuse is 2.4 x 104J2t. The smallest source-side fuse whose minimum-melt J2t exceeds this value is the 65 ampere fuse, with a minimum-melt I2t of 2.65 x 104. Examining coordination above 0.01 second is not required because coordinating margins are built into the published numbers. Coordination is conservative and will produce a coordinated system up to any fault-current level. If the fault current available is limited, coordination can be undertaken by the use of J2t versus I curves.

BACKUP CURRENT-LIMITING FUSE AND EXPUL· SION FUSE This protection method is often used, as it permits the majority of faults (which tend to be low current) to be cleared by an inexpensive expulsion fuse. When major faults occur within the equipment being protected, the current-limiting fuse operates to limit the available energy Since it is important that the expulsion fuse clears low-current faults without damage to the current-limiting fuse, the crossover point is established at current levels higher than the minimum interrupting rating of the current limiting fuse. It also is important that the current-limiting fuse lets through enough energy after it operates to cause the expulsion fuse to blow, thus providing a visible indication of the fault and a sharing of the post-impressed fault voltage by both fuses. Overlaying the fuse characteristics will produce a point where the maximum-clearing curve of the expulsion fuse crosses the minimum-melt curve of the current-limiting fuse. Higher currents will result in simultaneous operation. Table 8A3 gives typical coordination information for Cooper Power Systems backup current-limiting fuses and fuse links. Such tables are available also from other manufacturers. TABLE 8A3 Coordination of Backup Current-Limiting Fuse and Fuse Link Coordinates with Fuse Links up Through (Amperes)

Companion* Fuse Rating (Amperes)

NEMA TypeK

12 25 40

12 25 40

NEMA TypeT 8

15 20

*Cooper Power Systems trade name.

88

Cooper TypeD

Kearney Type X

1.5 20 20

2.5 10 15

A3

2

I I I

I

I

I

I

I

I

FOR8.3-KV C-RATED NX FUSES 108 X 1 8 6

t-

4

1-1--

2

t--

105 X 1

t-

t-

I= I= t- t-

r-

6

ttt-

r-

4

ttt-

r-

t-

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I= f.= t-- t--

I=

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t-t-t--

2

104 X 1

I=

rr-

6

t-t--

I'-

4

tt-

ttt-

tttt-

t-

t-

t-

t-

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t-

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r-

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r-

I=

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8

u w en >
0 0

CD 0

8_..

88888§

w _J

1.2

§ §§§§§§

CURRENT IN AMPERES X 10'

0

c.>

0.6 ~

(11

§0 8 8

88

Figure 7A3. TCCs showing transformer inrush current and transformer damage current for a specific transformer size.

91

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Transformer Fusing (Continued)

60 50 40 l

30 20

10

\

tt11

'

\

3600 3000 2400

1800 TRANSFORMER DAMAGE CURVE

,.

\ 1\

Ill

~

m

8 6

2

0

1 .8

0

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(/)

z

0

w .5

(/)

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w .3 ::::E i= .2

0.1

600 480

360

sop

5 4

3

1200

I

'\.

TRANSFORMER,... INRUSH CURVE

"'

1\l\

~

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Ci) 48

ift

:e

30~

24

1\

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ssb:

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8T

tt

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m

18

12

\

z

6.0 ~ MIN. MELT

'

\

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8 88888§

\ §

3.6 3.0 2.4

MAX. (!LEAR

'\

.02

g

;n w ..J l20 w

4.8

1\ \

.03

1\

§§§§§~

CURRENT IN AMPERES X 101

Figure 8A3. TCCs showing characteristics of appropriate expulsion fuse for transformer protection.

92

120

60

.08 .05 .04

240.

180

1.8 1.2

A3

8 6 5 4 3

2

(/)

1

Cl

z .8

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TRANSFORMER INRUSH CURVE

w .5

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w :::E .3

i=

.2

0.1

.08 .06

.05 .04

.03 .02

.01

~

g:

~

8

~L.I-~1..1..--l...-"'--1--L...I-l..... 1\)

8

~8888§

§ ~§§§§~

0.6

~ ~~~

CURRENT IN AMPERES X 101

=-igure 9A3. "r'CCs showing characteristics of expulsion and current-limiting fuse combinations for transformer protection.

93

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Transformer Fusing {Continued)

TABLE 9A3 Suggested Primary Fusing for Distribution nansformers Fuse Ratings Based on Use of Type "N" Fuse Links and High-Surge Type "H" Links (Protection Between 200% and 300% of Rated Load) Wye-Connected Primary

Delta-Connected Primary

TWMTWm Figure A

Transformer Size (kVA) 3 5 10 15

25 37.5 50 75 100 167 250

333 500

Transformer Size (kVA) 3 5 10 15 25 37.5 50 75 100 167 250 333 500

Figure B

Figure C

2400 Delta Figures A and B FigureC Link Link Rated Rated Rating Amps Rating Amps 1.25 2.08 4.17 6.25 10.42 15.63 20.8 31.25 41.67 69.4 104.2 138.8 208.3

2H 3H 8 10 20 25 30 50 60 100 150 200

2.16 3.61 7.22 10.8 18.05 27.05 36.1 54.2 72.2 119.0 180.5 238.0 361.0

3H 5H 15 20 30 40 60 85 100 150 200

7200 Delta Figures A and B Figure C Rated Link Rated Link Amps Amps Rating Rating .416 .694 1.389 2.083 3.47 5.21 6.94 10.42 13.89 23.2 34.73 46.3 69.4

.722 1.201 2.4 3.61 5.94 9.01 12.01 18.05 24.0 40.1 59.4 80.2 120.1

1H* 1H* 2H 3H 5H 8 10 20 20 40 50 60 100

1H* 1H* 5H 5H 10 20 20 30 40 60 100 150 150

Transformer Size (kVA) 3 5 10 15 25 37.5 50 75 100 167 250 333 500

Figure E

1.25 2.08 4.17 6.25 10.42 15.63 20.8 31.25 41.67 69.4 104.2 138.8 208.3

2H 3H 8 10 20 25 30 50 60 100 150 200

Figures A and B

4800/8320Y

Rated Amps .625 1.042 2.083 3.125 5.21 7.81 10.42 15.63 20.83 34.7 52.1 69.4 104.2

Figure C Link Rated Amps Rating

Link Rating 1H* 1H 3H 5H 8 15 20 25 30 50 85 100 150

1.08 1.805 3.61 5.42 9.01 13.5 18.05 27.05 36.1 60.1 90.1 120.1 180.5

1H 3H 5H 8 20 20 30 40 60 100 150 150 200

14400 Delta Figure C Rated Amps

Link Rating

.394 .656 1.312 1.97 3.28 4.92 6.56 9.84 13.12 21.8 32.8 43.7 65.6

1H* 1H* 2H 3H 5H 8 10 20 20 30 50 60 100

Figures A and B Rated Link Amps Rating .208 1H* .347 1H* .694 1H* 1.04 1H 1.74 2H 2.61 3H 3.47 5H 5.21 8 6.94 10 11.6 20 17.4 30 23.1 40 34.7 50

Rated Amps .625 1.042 2.083 3.125 5.21 7.81 10.42 15.63 20.83 34.7 52.1 69.4 104.2

Link Rating 1H* 1H 3H 5H 8 15 20 25 30 50 85 100 150

14400124900Y

Figures C Rated Link Amps Rating .361 .594 1.20 1.80 3.0 4.52 5.94 9.01 12.01 20.1 30.1 40.0 60.0

1H* 1H* 2H 3H 5H 8 10 20 20 30 50 60 100

i

Figures D, E and F;

12000 Delta 7620113200Y 7200112470Y Figures C Figures D, E and F Figures D, E and F Figure A and B Link Rated Link Rated Link Rated Rated Link Rating Amps Rating Amps Rating Amps Amps Rating 1H* 1H* .250 1H* .432 1H* .416 .394 1H* .417 1H* .722 1H* 1H .694 .656 2H .833 2H 1.44 2H 1.389 1.312 1H* 1.97 3H 1.25 1H 2.16 2.083 3H 3H 2.083 3.61 3.47 5H 3.28 5H 3H 5H 5.21 4.92 8 3.125 5.42 8 5H 8 7.22 15 6.94 10 10 4.17 6.56 8 6.25 10 10.8 9.84 20 10.42 20 20 14.44 13.89 13.12 20 8.3 15 20 20 23.2 40 21.8 30 13.87 20 23.8 40 20.83 50 36.1 60 34.73 32.8 50 30 27.75 40 47.5 60 85 46.3 60 43.7 41.67 72.2 69.4 100 65.6 100 60 100

*Since this is the smallest link available and it does not protect lor 300% of load, secondary protection is desirable.

94

Figure F

4800 Delta

2400/4160Y Figures D, E and F Link Rated Rating Amps

13 Figures A and B Link Rated Amps Rating .227 1H* 1H* .379 .757 1H* 1H 1.14 1.89 3H 2.84 5H 3.79 8 5.68 8 15 7.57 12.62 20 18.94 30 40 25.23 37.88 60

FigureD

reD, E and F Rated Link Amps Rating .208 .374 .694 1.04 1.74 2.61 3.47 5.21 6.94 11.6 17.4 23.1 34.7

1H* 1H* 1H* 1H 2H 3H 5H 8 10 20 25 40 50

A3 TABLE 10A3 Suggested Primary Fusing for Distribution Transformers Fuse Ratings Based on Use of EEI-NEMA Type "K" or "T" Fuse Links and High-Surge Type "H" Links (Protection Between 200% and 300% of Rated Load) Delta-Connected Primary

Wye-Connected Primary

Figure A

2400 Delta

I 1

Figure C

Transformer Size (kVA) 3 5 10 15 25 37.5 50 75 100 167 250 333 500

Figures A and 8 Rated Link Amps Rating 1.25 2.08 4.17 6.25 10.42 15.63 20.8 31.25 41.67 69.4 104.2 138.8 208.3

2H 3H 6 8 12 20 25 40 50 80 140 140 200

3H 5H 10 12 25 30 50 65 80 140 200

7200 Delta

Transformer Size (kVA) 3 5 10 15 25 37.5 50 75 100 167 250

333 500

Figures A and 8 Rated Link Amps Rating .416 .694 1.389 2.083 3.47 5.21 6.94 10.42 13.89 23.2 34.73 46.3 69.4

1H* 1H* 2H 3H 5H 6 8 12 15 30 40 50 80

.722 1.201 2.4 3.61 5.94 9.01 12.01 18.05 24.0 40.1 59.4 80.2 120.1

1H* 1H* 5H 5H 8 12 15 25 30 50 80 100 140

13200 Delta

Transformer Size (kVA)

Figures A and 8 Rated Link Amps Rating

Figures D, E and F Figures A and 8 Rated Link Rated Link Amps Rating Rating Amps 1.25 2.08 4.17 6.25 10.42 15.63 20.8 31.25 41.67 69.4 104.2 138.8 208.3

2H 3H 6 8 12 20 25 40 50 80 140 140 200

.625 1.042 2.083 3.125 5.21 7.81 10.42 15.63 20.83 34.7 52.1 69.4 104.2

7200/12470Y

Figure C Rated Link Amps Rating

Figure C Rated Link Amps Rating

Figure E

1H* 1H 3H 5H 6 10 12 20 25 40 65 80 140

.227 .379 .757 1.114 1.89 2.84 3.79 5.68 7.57 12.62 18.94 25.23 37.88

4800/8320Y

Figure C Link Rated Amps Rating 1.08 1.805 3.61 5.42 9.01 13.5 18.05 27.05 36.1 60.1 90.1 120.1 180.5

1H 3H 5H 6 12 15 25 30 50 80 100 140 200

.416 .694 1.389 2.083 3.47 5.21 6.94 10.42 13.89 23.2 34.73 46.3 69.4

1H* 1H* 2H 3H 5H 6 8 12 15 30 40 50 80

.394 .656 1.312 1.97 3.28 4.92 6.56 9.84 13.12 21.8 32.8 43.7 65.6

1H* 1H* 2H 3H 5H 6 8 12 15 25 40 50 80

.250 .417 .833 1.25 2.083 3.125 4.17 6.25 8.33 13.87 20.83 27.75 41.67

1H* 1H* 1H* 1H 3H 5H 6 8 10 15 25 30 60

14400 Delta 14400/2900Y Figures D, E and F Figures D, E and F Figure A and 8 Rated Link Rated Link Rated Link Amps Rating Amps Rating Amps Rating .208 .374 .694 1.04 1.74 2.61 3.47 5.21 6.94 11.6 17.4 23.1 34.7

Figures D, E and F Link Rated Rating Amps .625 1.042 2.083 3.125 5.21 7.81 10.42 15.63 20.83 34.7 52.1 69.4 104.2

1H* 1H 3H 5H 6 10 12 20 25 40 65 80 140

12000 Delta

7620/13200Y

Figures D, E and F Figures D, E and F Figure A and 8 Rated Link Rated Link Rated Link Amps Rating Amps Rating Amps Rating

1H* 1H* 1H* 1H* .394 .208 .361 1H* 1H* 1H* 1H* .656 .347 .594 1H* 1.312 1H* 2H .694 1.20 2H 1H 1.97 3H 1.04 1H 3H 1.80 3H 3.28 SH 1.74 2H 5H 3.01 4.92 5H 8 2.61 3H 4.52 6 6.50 10 3.47 SH 5.94 8 6 5.21 6 9.01 12 6 9.84 20 8 13.12 20 6.94 12.01 15 8 15 21.8 30 11.6 12 20.1 25 17.4 25 32.8 50 20 30.1 40 333 43.7 23.1 30 30 40.1 50 60 500 65.6 100 34.7 40 50 60.0 80 -~· ~ce th1s 1s the smallest link ava1lable and 1t does not protect for 300% of load, secondary protectiOn IS des1rable. 3 5 10 15 25 37.5 50 75 100 167 250

Figure F

4800 Delta

2400/4160Y

Figure C Rated Link Amps Rating 2.16 3.61 7.22 10.8 18.05 27.05 36.1 54.2 72.2 119.0 180.5 238.0 361.0

Figure D

1H* 1H* 1H* 1H 2H 3H 5 6 8 12 20 30 40

Figures C Link Rated Rating Amps .432 .722 1.44 2.16 3.61 5.42 7.22 10.8 14.44 23.8 36.1 47.5 72.2

1H* 1H* 2H 3H 5H 6 10 12 15 30 50 65 80

20000/34000Y

Figures C Link Rated Rating Amps

.50 .75 1.25 1.875 2.50 3.75 5.00 8.35 12.5 16.65 25.00

1H* 1H* 2H 2H 3H 5H 6 10 15 20 30

95

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Transformer Fusing (Continued)

TABLE 11A3 Overload Protection of Oil-insulated, Self-Cooled, and Dry-Type Transformers@ Single-Phase Application Using Current-Limiting Fusing

~ ~

...Cll ...E .e Ul

t:

co

F

1.5 3 5 7.5 10 15 25 37.5 50 75 100 150 167 200 250 333 500 750 1000 1250 1500 1667 2000 2500 3000 1. 2. 3. 4. 5.

96

@

25

r 18 18 18 18 18 18 25 45 75

@

18

18 18 18 18 18 18 18 18 25

·(!

@

·(!

6 8 18 20 25 40

6 6 12 18 25 40 65

r 1.5 1.5 1.5 3 3 3 10 12 18 25 40 50 65 80

@

18 20 25 30

3 6 8 10 12 25 30 40 50

12 18

10 20 25 30 40

12 12 18

6 6 6 6 6 6 6 6 6 8 10 12 18 20 25 40

@

6 6 6 6 6 6 6 6 6 6 8 10

@

12 15

Recommendations are based on fuse melting characteristics at an ambient temperature of 40 C. To prevent fuse blowing on transformer inrush, DO NOT USE FUSES SMALLER THAN RECOMMENDED without specific approval of the manufacturer. Fuses allow in excess of 300% of load. Fuses allow less than 140% of load. Ratings in red area are for parallel-fuse combinations.

6 6 6 6 6 6 6 6 6 6 6 8 10 12 12

A3 TABLE 12A3 Overload Protection of Oil-insulated, Self-Cooled, and Dry-Type TransformersQ) Three-Phase Application Using Current-Limiting Fusing Nominal SlngleoPIIase Voltage Across Transformer Terminals (kVj

i~

.. ..

2A

I

G)

4,3

.4.3

I

5 .5

I

I

~c:

lll

A

15 22.5

B

200

225 300 500 750

25 35 45 50 65 75

25 45 39 45 200 50 100

100

200

2Q[JJI

1000

1500

2000

2500 :D)()

Q)

~=

I~ ,~

("

18 18 18 18 25 25 45 65 75

B

A

B

A.

18 r8 18 18 35 50 65 100 100

Q)

30 45

75 100 112.5 150

I ti1'"2114.4

I

2D8

5.5 I s.s I 15.5 I 1S.!i I 15.5 Recommended Fuse-Current Ratings (amperes) •bill Column A -140-200% of Transformer Rating Column B- 200-300% of Transformer RiJling B A B A B A B A B A

I

23

8.32

12,47

I 22.!1i'l4..9

I

3~5

I

38

Recommended Fuse Volt&Qe (M:V)

E

~

I 7.2-7.96"

4.8

4.1&

® (~

® (~

8 10 20 25 30 40 65 75

6 10 18 25 30 40 50 65

12 20 25 25 40 40

12 18 18 25 30 40 50 75

1.5 3 4.5 6 10 18 18 25 30 40 50 100

12 12 18 20 18 20 30 25 25 50 20 100 50 7.5 75 ' 30 50 80 30 150 100 150 50 00 .65 80 30 200 iao 130 40 ~SQ ,.150• 100 160 100 Ulll 65 150 1!W 200 130 200 100 16'0 , ZOO 2IXt 13o '2()() : ~ocr·

D

3500 3750

i

4000

®1.5 1.5 3 3 6 10 10 12 18 18 25 50 80 100

1.5 3 4.5 6 10 12 12 18 25

l ~:~iir

5000

~: I ~

I~~

tell MO

;Zr;)()

200

:~

®1.5 1.5 ®3 3 6 8 10 12 18 20 25 50 80 lOQ

A

21

J

B

A

®(!

0

12 12 18 30 40 65 80 ·1160

6· 6 6 8 10 10 12 20 25 18 25 40 25 30 30 4()0 50

0

eo

faD'

~~ 16tfV

A

B

Bel

00

1QP '~

l

Q)

6 8 10 10 12 25 40

&')

80

,'fOD II

18 25 30 40 .!SO e~

t ~..,

9 6 6 6 6 6 6 6 6 8 8 10 15 25 30 50 60•

00

00

ae

~00

1. Recommendations are based on fuse melting characteristics at an ambient temperature of 40 C. 2. To prevent fuse blowing on transformer inrush, DO NOT USE FUSES SMALLER THAN RECOMMENDED without specific approval of the manufacturer. 3. Fuses allow in excess of 300% of load. 4.. Fuses allow less than 140% of load. 5.. Ratings in red area are for parallel-fuse combinations.

TABLE 13A3 Comparison of Expulsion Fuses and Current-Limiting Fuses Expulsion

Rating

8.3,15,23

Fuse Type Current-Limiting

Current Ratings (ANSI): 1 through 100

8.3,15,23 12 through 65

Fault Current Clearing Capacity (kA):

Determined by cutout rating

Through 50 kA

15

50-100

\titage Ratings (kV):

Discharge Interrupting Capacity (kilojoules):

symme~ic

• A current-limiting fuse, when operating, changes the circuit X/R radically. lherefore, no asymmetric ratings are normally assigned, as the fuse will +andle any current.

97

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION

Capacitor Fusing GENERAL CRITERIA The basic objectives in selecting capacitor fuses are: 1. The fuse must be capable of withstanding steady-state and transient currents in order to avoid spurious fuse operations. 2. The fuse should effectively remove a failed or failing capacitor unit from service without causing further damage or disruption to the system. These objectives are accomplished through two different protection methods: group fusing and individual fusing. In group protection, one fuse protects more than one capacitor- usually with a single fuse on each phase protecting all the capacitors on that phase (Figure 1OA3). Group fusing is generally used for protecting pole-mounted distribution capacitor racks. In such applications, the fuse links are installed in cutouts and mounted on a crossarm above the capacitor rack.

Figure 1OA3. Diagram of group capacitor fusing.

In individual protection, each capacitor in a bank is protected by its own individual fuse (Figure 11 A3). This type of protection is commonly used in outdoor-substation capacitor banks. Fuses are the bus-mounted type.

are capacitor-bank switching and lightning surges. Switching is typically of concern only when capacitor banks are switched on the same bus: i.e., back-to-back switching. This is seldom the case for pole-mounted, group-fused capacitors. However, the fuses in such applications are subject to highfrequency transients due to lightning surges, which are more likely to damage low-current-rated links. Individually fused applications involve an additional transient consideration. When a capacitor unit fails -that is, goes to a short circuit - the remaining good capacitors will discharge into the failed capacitor. Fuses on the good capacitors should be able to withstand this high-frequency outrush current to avoid multiple fuse operations.

Effectively Removing a Failed or Failing Capacitor Unit A failed or failing capacitor unit should be removed from service without causing any further damage or disruption to the system. It is important, therefore, that the clearing fuse and the capacitor unit be able to withstand the available 60Hz current and the high-frequency energy discharge from the parallel capacitors. In addition, the fuse must clear fast enough to limit the duration of voltage on the remaining good capacitors and to coordinate with upline overcurrent devices or an unbalance detection scheme. Summary of General Criteria A summary of the key criteria in choosing the appropriate fusing for a shunt-capacitor application is given in Table 14A3. In comparing the need for slow-clearing and fast-clearing fuses, it sometimes is not reasonably possible to meet all criteria. In such cases, trade-offs must be made and some risks taken in regard to the conditions when fuses and capacitors may not operate in a desirable manner. GROUP CAPACITOR FUSING The following considerations are involved in selecting a fuse for group capacitor protection: • Continuous current. • Transient current. • Fault current. • Tank-rupture curve coordination. • Voltage on good capacitors. • Coordination with upline overcurrent devices.

Figure 11 A3. Diagram of individual. capacitor fusing.

Withstanding Steady-State and Transient Currents Continuous-current and transient-current duties determine the minimum acceptable fuse size that may be used without risking spurious fuse blowing under normal conditions. The requirements for group fusing and individual fusing are similar for continuous-current duty but different for transient duty. The fuse link is chosen to have a minimum rating of at least 125 to 135 percent of rated capacitor current. This overrating is necessary because of overvoltage conditions, capacitance tolerance, and harmonics. Fuses can be damaged by high-magnitude, high-frequency currents. If possible, therefore, it is desirable to minimize spurious fuse operations by selecting an appropriate fuse link to withstand such transient currents, whose principal sources

98

Continuous Current The fuse's continuous-current capability is chosen to be equal to or greater than 135 percent of rated capacitor current for grounded-wye connected racks, and 125 percent for ungrounded-wye racks. This overrating takes into account the effects of overvoltage (ten percent), capacitor tolerance (five to 15 percent), and harmonics (five percent for ungroundedwye and ten percent for grounded-wye configurations). The minimum-size fuse link for a grounded-wye application is calculated as follows: Iiink

= 1.35 X kvar3"'

V3 kVL-L

This calculation is based on the link's being 100 percent rated. In the case of NEMA Type T and K tin links, which are 150 percent rated, this value must be divided by 1.50.

A3 TABLE 14A3 Summary of Shunt-Capacitor Fusing Criteria Fuse Characteristic Desired

Fusing Method Key Criteria

Group Protection

Individual Protection

Slow

X

X

X

X X

X X X

Withstanding Steady State and Transient Currents: Continuous Current

Fast Clearing

External Transient Currents

X

-Lightning -Switching Outrush Current

.

Effectively Removing Failed or Failing Capacitor Unit:

X X X

Fault Current Tank Rupture Curve Coordination Voltage on Good Capacitors Energy Discharge Into Failed Unit Coordinate with Upline Overcurrent Devices Coordinate with Unbalance Detection Scheme

X X X X

.

. X X

.

X X

X X

*These cntena help to determine whether expulsion or current-limiting fuses are requ;red.

Transient Currents Fuses can be damaged by high-magnitude, high-frequency currents. If possible, it is desirable to minimize spurious fuse operations by selecting an appropriate fuse link to withstand these transient currents, whose principal sources are capacitorbank switching and lightning surges. Switching is typically of concern only when capacitor banks are switched on the same bus: i.e., back-to-back switching. This is seldom the case for pole-mounted capacitors, although the fuses in such applications are subject to high-frequency transients from ightning surges. To minimize spurious fuse operations due to lightning surges, the use ofT tin links is recommended in group fusing for low-ampere ratings through 25 amperes, and K tin links 'or above 25 amperes. The T link can withstand a higher surge current than the K link, and this general recommenda:ion has resulted in good performance for areas of significant 1ghtning activity. (Note that installing switched capacitor :::anks very close together on the same pole or on adjacent :·oles should be avoided unless precautions are taken to min-nize the high-magnitude, high-frequency inrush current.) In areas of high lightning incidence and where experience ::1tetates, T tin links may be used at higher current ratings for ;;rounded-wye and delta-connected racks. For areas where ::istribution lines are shielded by trees or buildings or where :"'.e lightning incidence is low, the user may consider the use -:f K links over the entire range of link ratings. Occurrences of spurious fuse blowing due to lightning can ~so be reduced by locating the fuse cutout between the :aoacitor and its arrester rather than placing the arrester :e.veen the capacitor and the cutout.

Fault Current As stated previously, the fuse link and capacitor must be able to handle the available fault current. When capacitors are connected grounded-wye or delta in a pole-mounted rack, a capacitor failure (terminal-to-terminal short) will cause system fault current to flow. The capacitor must be able to withstand the fault current until the fuse interrupts the circuit, and the fuse must be able to interrupt the available fault current For K and T links, the available symmetric fault current should not exceed the limits shown in Table 14A3. When the available current for a given application does exceed the values given in the table, however, possible solutions include the following: • Limit the available fault current the capacitor will see by using current-limiting fuses. • Unground the neutral and operate the bank as ungrounded wye, which generally is a more cost effective solution. In this type of connection, the available current is limited to three times the line current because of the impedance of the capacitors in adjacent phases. (If a major insulation failure or simultaneous failures in two phases should occur, then fault current could flow. These events are very rare and normally are not considered when applying fuses in an ungrounded-wye application.) • Move the capacitor rack to a location with an acceptable fault-current level.

TABLE 15A3 =autt Current Limitation (50.. to 400-kvar All-Film Capacitors)* Maximum Symmetric Fault Current (RMS amps) When XIR Is:

Cutout Rating (kV)

0

5

10

15

Up to 25 38

12,000 8,200

8,500 5,700

7,400 5,000

7,100 4,700

-.a::x:er Power Systems EX line of capacitors or equivalent.

I

Maximum Link Rating that Coordinates with Available Fault Current T-Tin K-Tin 80 100 80 ET 100 EK

I

Overcurrent Protection 3:A PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Capacitor Fusing (Continued)

Tank-Rupture Curve Coordination The maximum-clearing TCC curve for the fuse link must coordinate with the tank-rupture curve for the capacitor {Figure 12A3). This coordination is necessary to insure that the fuse will clear the circuit before tank rupture can occur. The fuse's maximum-clear TCC must fall to the left of the tank-rupture TCC at and below the level of available fault current. Jn the case of high fault currents, the tank-rupture curve should be compensated for asymmetry. In general, the largest fuse sizes that coordinate with the tank-rupture curve for modern all-film capacitors such as McGraw-Edison's EX line are 100K and SOT tin links. See Table 15A3 for details. Voltage on Good Capacitors For ungrounded-wye capacitor banks, the voltage on the good capacitor units, when o~e is ~hort~d, is equal syste~ line-to-line voltage: i.e., 1. 73 t1mes 1ts rat1ng. If the fa1led u~1! IS not cleared from the circuit quickly, this high overvoltage condition could lead to a second capacitor failure in another phase, resulting in a phase-to-phase fault. For ~hi:> ~ason, it is d~~i~able to use a fast-clearing fuse so as to mtmm1ze the poss1b1llty of a second unit failure. Note that this criterion calls for a fastclearing fuse, such as a Klink, while the criterion for transient current calls for a slow-clearing fuse, such as aT link.

!o

Coordination with Upline Overcurrent Devices When a capacitor unit fails, it is desirable that the capacitor fuse clear the capacitor without any other overcurrent devices on the feeder having operated; that is, the capacitor fuse must coordinate with the upline overcurrent devices. This criterion may dictate the maximum-size capacitor rack to be used on a given feeder or adjusting the source device setting upward. It is particularly important. to note the coordination with source ground relays when usmg grounded-wye racks. Summary of Group Fusing Group fusing recommendations for the EX line of all:film capacitors are listed in Table 16A3. These recommendatl?ns assume a typical level of lightning incidence; therefore, t1n T links are listed for line-current ratings of 25 amperes and below (see earlier discussion under "Transient ~urrents"), and tin K links for ratings above 25 amperes. Available faultcurrent levels are assumed to be within the limitations listed in Table 15A3. It is recognized that, in specific cases, utilities r:night. elect to use different link ratings or types than those g1ven m the tables because of such considerations as lightning incidence rates, fuse stocking requirements, and feeder coo~dination. For example, when fusing ungrounded-wye racks w1th a very low probability of lightning transients, Type K tin links might be considered over the entire range of ratings. Or, rather than fusing grounded-wye racks with relatively low-current-rated T links, higher-rated T links might be considered to reduce spurious fuse blowings due to lightning. With ungrounded-wye racks the user can choose between Type T and K links but usualiy cannot select a different rating. However, in making any adjustments in the recommendations it is important to take into account all of the criteria discussed above. Generally, group-fused racks are connected in wye. At tir:nes it may be advantageous to connect racks in delta, es~ec1ally on 2400-volt systems or to minimize the number of d1fferent spare units kept in stock. The group fusings reco.mme~dations in Table 16A3 can be adjusted for delta configurations, as explained by the note in the table, by making the capacitor unit voltage equal to the system voltage. Larger kvar-rated delta-connected racks are possible if the fuses are put inside 100

the delta, but in that case the system voltage must be made equal to the capacitor unit voltage in order _to follow the recommendations in the table. Recommendations for delta fusing at 2400 volts are given in Table 17A3, but for all other system voltages use Table 16A3 as directed.

INDIVIDUAL CAPACITOR FUSING The following considerations are involved in selecting a fuse for individual capacitor protection: • Continuous current. • Transient current. • Fault current. • Tank-rupture curve coordination. • Voltage on good capacitors. • Energy discharge into a failed unit. • Outrush current. • Coordination with unbalance detection scheme:

Continuous Current The fuse's continuous-current capability is chosen to be equal to or greater than 135 percent of the capacitor's rated current. This overrating takes into account the effects of overvoltage conditions (ten percent), capacitance tu (Jl

6.0 ~ 4.8 i= 3.6 3.0 2.4 1.8

' r-.

[]J

~

\

.02

en

-

CJlQ)

CD~

0 88 8 8 8 08

N

W

-1>-CJlQ)CD

08 08 80000 8 8 8 80 0

CURRENT IN AMPERES

Rgure 15A3. TCCs for application diagrammed in Figure 14A3.

ABC/31

l~~crs

©

20AMPERES

7200/12470 VOLTS ABC/27

l ~ ~

-

35AMPERES

Ftgure 16A3. Typical system requiring coordination between recloser and load-side fuse links. 113

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Recloser and Fuse-Link Coordination (Continued)

The recloser selected immediately fulfills the first three requirements for proper recloser application. Its interrupting rating of 4000 amperes at 14.4 kV is sufficient to interrupt 1660 amperes at the substation secondary. Continuous load current is 90 amperes, less than the 140 ampere rating of the recloser coil. A minimum-trip value of 280 amperes permits the recloser to sense the lowest level of fault current in the desired protected zone of 340 amperes at point ABC/31. Selection of a three-phase recloser at ABC/27 would allow use of ground-fault sensing, providing more sensitive trip values for faults involving ground. A possible ground-trip setting could be 100 amperes. If this were selected, the following fuse selection procedures would be compared against the combined ground/phase characteristics of the recloser. To insure that the reclosers at ABC/27 can clear a transient fault without damaging or fatiguing the fuse link, the fuse-link

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116

A3 Relay-Fuse Coordination Relay-fuse coordination involves two distinct applications: relay and source-side fuse, and relay and load-side fuse. In both cases the relay is serving as a circuit breaker time-and-trip control, but the coordination objectives of the two applications are entirely different. The objective of relay and source-side fuse coordination is that the relayed breaker should go through its entire operating sequence without causing fuse melting or damage, so that the smallest segment of the circuit will be sectionalized. The objective of relay and load-side fuse coordination, on the other hand, is generally accepted to be a relay curve that is slower than the fuse curve, so that fusing operation and isolation of the fault take place before the breaker completes its sequence. In the latter case, the addition of instantaneous relay elements that function faster than the load-side fuse on the first breaker operation provides a measure of transient fault protection. These two applications are discussed in detail below.

RELAY AND SOURCE-SIDE FUSE COORDINATION The principal application would be a primary fuse protecting a substation transformer, with a relayed breaker serving as the secondary protection. Coordination can be undertaken by either of two methods: total accumulated time or cooling factors. For a comparison of relay and fuse time-current characteristics to be made, both curves must be expressed on the same voltage base by shifting one of the curves, as discussed in the preceding section on recloser and fuse-link coordination, beginning with the fourth paragraph under "Coordination with Source-Side Fuse Links."

Total Accumulated Time Method The simplest and most conservative method of achieving coordination is to add up the relay fault timings that are separated by less than ten seconds, the time typically required for fuses to cool completely, and compare this total to the fuse curve. A time margin of 50 percent of the source-side fuse's minimum-melt curve is recommended to allow for iJ•reloading, ambient, predamage, and non-repeatability of relay characteristics. Some utilities use 0.3 seconds as a '1largin rather than a percentage. As a basis for discussion, an installation involving a relayed tl•reaker and source-side fuse is diagrammed in Figure 20A3 The transformer and breaker ratings are indicated. The fuse is a 125E power fuse. The overcurrent relay is a type IAC53, with a CT ratio of 1000:5. It can be set at tap 2 or 4, and has an nstantaneous tap setting of 10. The reclosing relay has a reclosing sequence of instantaneous, 15 seconds, and 45 seconds. For more details regarding relay settings, refer to 'Circuit Breakers and Relays" in Section A2. In Figure 21A3, the fuse and breaker relay curves are :ompared. The fuse minimum-melt curve has been referred :o the secondary by the voltage ratio 69/12.47 because the 7atlSformer connection is symmetrical - i.e., wye-grounded/ wye-grounded. For proper coordination up to 5 kA, it appears 1lat both relay time-lever settings (2 and 4) will coordinate for

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only one fault timing. But since the reclosing relay has an instantaneous (INST) setting, the first two fault timings of the relay must be added together and plotted for true comparison with the fuse curve. With that in mind, it is obvious lever 4 will not coordinate, since its curve crosses the fuse curve at the 5000 ampere level. Although the fuse will not necessarily function on the first operation of the breaker, it could see enough current for heat damage to occur. Let us take a closer look, then, at the total accumulated time for lever 2, with its instantaneous time as indicated (Figure 22A3}. (The total accumulated curve consists of the first two fault timings of the relay; the instantaneous element was operative on the first shot only.) As can be seen, comparing the adjusted lever 2 relay curve with the fuse curve shows a margin greater than 50 percent for any fault level up to 5000 amps. Therefore, the coordination is acceptable with lever 2 and the settings shown.

Cooling-Factor Method When coordination requirements are tighter, there is another method that will result in more precise coordination. This involves the use of cooling factors for the fuse link (explained in Table 25A3) and an evaluation of the actual reclosing intervals of the relay. The formula used is: Teff = TF(N) + CN x TF(N-1) + CN-1 x CN x TF(N-2) + ... Where Teff =

CN

the effective fault timing of the relay incorporating successive reclosing heating effects.

=the cooling factor for the fuse during the tenth reclosing (open) interval. This varies from 1.0 at very short reclosing times to 0.0 at long reclosing times.

TF(N) = Nth fault duration of the reclosing device. Use of the above formula also requires a knowledge of the reset characteristics of the reset relay The relay's reset time is 10 seconds (at 0 percent remaining load) for time-lever 2, and the fuse's cooling factors are as shown in Table 25A3. (Note that fuse-link cooling factors may not be generally available from manufacturers.)

117

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Relay-Fuse Coordination (Continued)

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TABLE 25A3

Fuse-Link Cooling Factors* Cooling Interval (Seconds) 0.5 1 2 3 4 5 6 7 8 9 10

Cooling Factor (Multiplier) 1.0 .93 .8 .68 .57 .46 .36 .26 .17 .09 .02

• Fuse-link cooling factors are used to determine the percentage of residual higher-than-normal heat in the link at the indicated elapsed times following exposure to melting current.

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The reclosing relay timing would produce the operating sequence shown in figure 23A3. The first step in the coolingfactor method is to determine if the INST reclosure caused fuse damage. This is essentially the operation performed in the previous example, since the cooling factor is 1.0 for the 30-cycle (0.5 second} reclosing interval. The curves are directly added.

15 45

Figure 23A3.

Relayed breaker operating sequence.

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Relay-Fuse Coordination (Continued)

If the first reclosing interval is one second, we would use the following relation for a fault-current magnitude of 5000 amperes: Teff= TN+ CN x TN-1 =TN+ .93 TN-1 Where TN = .40 (Nth or last fault timing occurs on T.L.2). TN-1 = .075 (next-to-last or first fault timing occurs on INST curve. We must then evaluate whether the total reclosing cycle would cause a cumulative heating effect sufficient to blow the fuse. Since the actual open time varies with the fault timing, this must be done on a point-by-point basis, as in the following examples. Example 1 {INST- 15- 45 Reclosing Sequence) At 1200 Amperes 1st fault timing = 6 seconds forT. L. 2. 1st reclosing interval .5 seconds. %reset during interval= .5 (100) = 5%.

lO 2nd fault timing = (.05) (6) = .3 second forT. L. 2. 2nd reclosing interval = 15 - .5 - .3 seconds = 14.2 seconds; 10. Total fuse cooling occurs after 2nd reclosing interval. Teff = .3 + 1.0 (6) - 6.3 seconds. At 2000 Amperes 1st fault timing = 1.5 seconds forT. L. 2. 1st reclosing interval = .5 seconds % reset during interval = 5% 2nd fault timing = (.05) (1.5) = .075 seconds forT. L. 2. 2nd reclosing interval = 15- .5 - .075 seconds = 14.425 seconds; 10. Total fuse cooling occurs after 2nd reclosing interval. Teff = .075 + 1.0 (1.5) = 1.575 seconds. At 3000 Amperes 1st fault timing = .09 seconds for I. T. setting of 10. %disk travel= .09 (100} = 12.86%. (Although reclosing 7 relay tripped on instantaneous, disk travels until reclosing occurs.) 1st reclosing interval = .5 seconds. % reset during interval = ~ (1 00) = 5%. 10 Net travel= 12.86- 5 = 7.86%. 2nd fault timing= (.7) (1- .0786} = .645 seconds forT. L. 2. 2nd reclosing interval = 15 - .645- .7 seconds = 13.655 seconds; 10. Total fuse cooling occurs after 2nd reclosing interval. Teff = .645 + 1.0 (.09) = .735 seconds. At 5000 Amperes 1st fault timing = .075 seconds for I. T. setting of 10. Disk travel= (.075) (100} = 18.75%.

-:4 1st reclosing interval = .5 seconds. % reset during interval = (.5) (1 00) = 5%.

10

120

Net travel= 18.75-5 = 13.75%. 2nd fault timing= (.4) (1 - .1375) = .345 seconds forT. L. 2. 2nd reclosing interval = 15 - .345 - .5 = 14.155 seconds: 10. Total fuse cooling occurs after 2nd reclosing interval. Teff = .345 + 1.0 (.075) = .42 seconds. As can be seen, coordination is assured up to the maximum 5000 amperes. in this case, in fact, the more precise analysis was somewhat academic. However, as shown in the following, if reclosing settings are changed from instantaneous, 15, and 45 seconds to 5, 15, and 30 seconds, the analysis takes on an entirely different meaning. Example 2 5 - 10 - 30 Reclosing Sequence At 1200 Amperes 1st fault timing = 6 seconds forT. L. 2. 1st reclosing interval = 5 seconds. % reset during interval = 5/10 = 50% 2nd fault timing = (.5) {6) = 3.0 seconds forT. L. 2. 2nd reclosing interval = 15 - 5 - 3 = 7 seconds. % reset during interval = 7/1 0 = 70%. 3rd fault timing = .7 (6) = 4.2 seconds forT. L. 2. 3rd reclosing interval = 30 - 4.2 - 7 - 3 - 5 = 10.8 seconds; 10. Total fuse cooling occurs after 3rd reclosing interval. Teff = 4.2 + .26 (3.0) + (.26) (.46) (6) = 5.7 seconds. At 2000 Amperes 1st fault timing = 1.5 seconds forT. L. 2. 1st reclosing interval = 5 seconds. % reset during interval = 50%. 2nd fault timing= (.5) (1.5) = .75 forT. L. 2. 2nd reclosing interval= 15-5- .75 = 9.25 seconds. % reset during interval = 9.25/10 = 92.5%. 3rd fault timing= .925 (1.5) = 1.3875 seconds forT. L. 2. 3rd reclosing interval= 30- 1.39-9.25- .75-5 = 13.61 seconds; 10 Total fuse cooling occurs after 3rd reclosing interval. Teff = 1.39 + .09 (.75} + (.09) (.46) (1.5) = 1.52 seconds. At 5000 Amperes 1st fault timing = .075 seconds for I. T. setting of 10. Disk travel= (.075) (100) = 18.75%. .4 1st reclosing interval = 5 seconds. % reset during interval = 100%. 2nd fault timing = .4 seconds. 2nd reclosing interval = 15 - 5 - .4 = 9.6 seconds. % reset during interval = 9.6/1 0 = 96%. 3rd fault timing = .96 (.4) = .384 seconds. 3rd reclosing interval= 30- .38-9.6- .4-5 = 14.62 seconds; 10 Total fuse cooling occurs after 3rd reclosing interval. Teff = .38 + .09 (.4) + (.09) (.46) (.075) = .42 seconds.

In general, the effects of the reset time of the electromechanical relay and the timing characteristics of the reclosing relay tend to offset each other. Therefore, the more precise cooling-factor method of coordination is not often required.

A3 RELAY AND LOAD-SIDE FUSE COORDINATION 1n, its simplest form, an overcurrent relay has a single curve, and the objective of relay and load-side fuse coordination is jO assure that the relay curve is slower than the fuse curve. 3y thus allowing the fuse to operate in the event of a fault :cwnline from it, the breaker is protected from a permanent ".autt and only the smallest portion of the line is removed from service. Figure .24A3 illustrates a typical installation for study. The ""?lay settings are the same as those in the previous example ~nder "Relay and Source-Side Fuse Coordination."

3-CYCLE BREAKER

Q

KLINK

\51

Figure 24A3. Diagram of installation with overcurrent relay and loadside fuse.

For coordination up to 5 kA, what is the maximum K fuse that 'Hill assure a maximum fuse clearing time that does not exceed the relay time? A margin of 0.2 to 0.3 seconds between the fuse's maximum-clear curve and the relay's time-lever curve should generally be observed to allow for CT error, setting errors, tolerances, overtravel, etc. For currents below three tim~s pickup, a 10-percent time margin has proved workable. Typically, the complete family of K-fuse maximum-clear curves would be overlayed on the relay curve, and the fuse whose curve is closest to the relay curve while satisfying appropriate time margins is the maximum-size fuse that can be used. With these considerations in mind it can be seen in Figure 25A3 that a 200K link is the largest' that can be used in this application.

Approaches to Temporary Fault Protection Of course, the single relay curve, as stated above, allows only one of the objectives of distribution-system protection to be achieved: removal from service of the smallest portion of the system in the event of a fault. It also may be desirable to have tem~orary fault protection, which, in the case of reclosers, is obtamed as a result of a dual timing characteristic {discussed in Section A2). In the relay-fuse installation under consideration here, however, it may be necessary to attempt to achieve coordination for temporary protection within the range of the minimum fault current the recloser can sense up to the maximum fault current available at the fuse location. For example, protection against temporary faults will be ~btained by adding an instantaneous element with a tap settmg of 8 to the relay in the study case. The minimum pick-up of the instantaneous element is, therefore, 1600 amperes (8x(1000/5)), which is roughly twice the pick-up of the time curve. Figure 26A3 shows that temporary fault protection is achieved from 1600 to 2700 amperes, but the 75 percent rule observed for the fuse link produces a maximum of 2250 amperes. (Remember that the fuse minimum-melt curve is shifted by 75 percent to account for ambient temperature difference, load current, and predamage.) In general, this range of protection can be expanded by lowering the instantaneous setting. The lower limit, however, is often dictated by inrush and downline device coordination, and the upper limit is fixed by the speed of the breaker. Three-cycle interruption (0.05 seconds) is generally accepted as the fastest fault clearing obtainable with a circuit breaker. The range can also be expanded by the use of a ground overcurrent relay with an instantaneous element. This addition permits the instantaneous element to be set at lower levels. The upper limit, however, is fixed by the relay and breaker operating times. If temporary fault protection (and the resultant fuse saving) i~ desired in protection applications involving relays and loadSide fusing, the process is maximized by using the largest fuses practical on lateral taps and setting the instantaneous element as low as possible. Maximum fuse size is governed by conductor burndown and coordination with the relay time curve.

121

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Relay-Fuse Coordination (Continued)

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123

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Relay-Fuse Coordination (Continued)

Figure 27A3 shows a Southeastern utility's approach to relay and load-side fuse coordination. The scheme allows temporary fault protection by using low-set ground and a low-set instantaneous element. These are both locked out by the reclosing relay after the first shot, leaving only the phase time delay for an interval of 10 to 15 seconds, after which all relays are reestablished.

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124

8 8 88

A3 Recloser-to-Recloser Coordination 'USING TIME-CURRENT CURVES llecloser-to-recloser coordination is achieved primarily by the selection of different series trip-coil ratings in hydraulic oedosers, or different minimum-trip current values in electronic "edosers. The proper selections are determined after a study of the reclosers' time-current characteristics. Tme-current curves of different hydraulic reclosers generally are of similar inverse shapes. If the reclosers involved have smilar timing mechanisms, their time-current characteristics =-e not only similar, but also essentially parallel. This tends to snplify coordination. Microprocessor controlled reclosers, on the other hand, offer a variety of time-current curves. With the number of timeanent curves and minimum trip values available, the characEristics of a microprocessor controlled recloser generally can be tailored to fit any coordination requirement. Tme-current curves can be selected to make best use of dual tnling- a feature on all reclosers that can be programmed so lhat the first operation(s) in the recloser sequence are on a fast time-current curve and are followed by delayed-curve operations. Figure 28A3 illustrates a typical set of time-current curves for a hydraulic recloser, with A being the fast curve, B delayed, and C extra delayed. Some hydraulic reclosers offer ttvee or four delayed curves in addition to the one fast curve. While there are curves for microprocessor controlled 20

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HYDRAULICALLY CONTROLLED RECLOSERS: COORDINATION BASICS Smaller Reclosers (Series Coil Operated) When coordinating hydraulically controlled reclosers in series, the minimum time required between time-current curves differs depending on the recloser types involved. On smaller singleand three-phase reclosers, movement of the series trip-coil plunger (when accelerated by overcurrent flowing through the series coil) opens the recloser contacts and loads the closing springs. Cooper Power Systems reclosers of this construction are Types H, 3H, 4H, V4H , L, V4L, 6H , V6H, E, 4E and V4E. When two such reclosers are in series, time-current curve separation of less than two cycles will always result in simultaneous operation, and separation of two to twelve cycles may do so. When curves are more than twelve cycles apart, however, simultaneous operation will not occur. (Table 26A3.)

TABLE 26A3 Time-Current Curve-Separation Guidelines for Series Operation of Hydraulically Controlled Reclosers Reclosers* (Cooper Types)

360 300 240

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reclosers that are similar to the shape of hydraulic recloser curves, many other fast and delayed curve shapes are available to fit various coordination requirements. An important consideration when coordinating reclosers with reclosers is the time (cycles) between the curves of the two reclosers. Different recloser types require different minimum times between curves to prevent simultaneous operation , as described in the following sections.

0.6

CURRENT (AMPERES)

Rgure 28A3. Yypical ABC time-current curves for 50 ampere, singlephase hydraulic recloser.

Definite Possible Never SlmulSlmulSimultaneous tan eo us taneous Operation Operation Operation

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2 to 12 Cycles

More Than 12 Cycles

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More than 8 cycles

•source-s1de recloser diCtates the necessary curve separat1on.

An example of the application of such reclosers to be coordinated in series by selecting coil ratings is shown in Figure 29A3. Three reclosers with adjacent coil sizes are programmed for a 2A2C operating sequence. Branch lines tap off at intermediate points between reclosers. The time-current characteristics of these reclosers, Figure 30A3, indicate that, at a fault current of 1000 amperes, the fast characteristics (A curves) are closer than two cycles, which means that this fault current on the load side of the 50 ampere recloser can cause simultaneous fast operations by all reclosers. Also, simultaneous operations may occur at this current even on delayed timing, since the separation between delayed curves at 1000 amperes is approximately three cycles for the 50 and 70 ampere units and eight cycles for the 70 and 100 ampere units. At 500 amperes, separation between the delayed curves of the 50 and 70 ampere units is 13.7 cycles, and between the 70 and 100 ampere units. 28.8 cycles. At this level of fault current, coordination would exist between the reclosers even though limited simultaneous operation would result, based on characteristics of the fast curves. For a 500 ampere fault on the load side of the 50 ampere recloser, all three units may

125

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Recloser-to-Recloser Coordination (Continued)

perform their two fast operations simultaneously, but during the delayed operation only the 50 ampere recloser would clear the fault by opening before the 70 and 100 ampere units. The 50 ampere unit would lock out for a permanent fault on its load side, and the other two units would reset. On special occasions where hydraulically controlled reclosers in series must have the same series-coil rating, coordination can be achieved by setting the reclosers to operate on different sequences and different delayed timecurrent curves. However, the requirement on time between curves at the fault-current levels involved still applies and should be confirmed. Figure 31A3 shows an example in which all reclosers have 100 ampere coils, but ACRE1 is set for a 1A3C sequence while ACRE2 and ACRE3 are set for 2A2B sequence. Should a fault occur at point F, ACRE1 and ACRE2 will simultaneously perform one fast operation. This response is expected because both reclosers are operating on the same time-current curve. The ACRE2 on the

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Figure 29A3. Diagram of reclosers coordinated in series by selection of coil ratings.

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Microprocessor controlled reclosers offer a wide range of operating characteristics to closely meet individual system requirements. For all reclosers to be coordinated, consideration must be given to minimum trip levels for ground faults and phase faults, choice of time-current curves, operating sequence, reclosing intervals, and application of accessories. Adjacent electronically controlled reclosers can be coordinated closely together since there is no override or follow-through of electronic circuits. If the load-side recloser clears faster than the response time of the sourceside recloser, coordination is assured. Load-side clearing time with its plus tolerance must be less than the sourceside control response time with its negative tolerance.

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CURRENT (AMPERES)

Figure 30A3. Time-current curves demonstrating recloser coordination by means of adjacent coil selection. 126

Larger Reclosers (High-Voltage Solenoid Closing) On larger single- and three-phase hydraulically controlled reclosers (such as Cooper Types D, DV, W, VW, WV and VWV), movement of the series trip-coil plunger merely releases the preloaded opening springs. A separate closing solenoid loads the opening springs and closes the contacts. Consequently, as shown in Table 26A3, the minimum time allowable between time-current curves without incurring simultaneous operation is different than for the smaller reclosers discussed earlier. When the larger of two reclosers in series is of this type (separate closing solenoid), time-current curve separation of less than two cycles will result in simultaneous operation, but when the curves are separated by more than eight cycles, the possibility of simultaneous operation is remote. Except for this difference in curve separation required to avoid simultaneous operation, coordination of the larger hydraulically controlled reclosers is the same as for smaller units. MICROPROCESSOR CONTROLLED RECLOSERS: COORDINATION BASICS

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Figure 31 A3. Diagram of reclosers coordinated in series by means of operating sequence selection.

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2A2B sequence then completes its second fast operation before ACRE1 can operate on its delayed C curve. If the fault is permanent, ACRE2 operates to lockout because ACRE2 operates on the B curve faster than ACRE1 operates on the C curve. This assumes sufficient time between the B and C curve to prevent simultaneous operation at the fault-current level involved. With this method, the branch-line fault causes one brief interruption of loads along the primary feeder. For a permanent fault at F, only ACRE2 will lock out. ACRE1 will lock out only for a permanent fault on the primary feeder such as K.

50-AMPERE

\

100 AMPERE 2A2B

A3 A general guideline for coordinating electronically controlled oeclosers - after voltage ratings, interrupting capacities, and continuous current capacities for the reclosers to be used in 1he system have been established - is to do so by means of mW'Iimum trip levels and time-current curves. With microprocessor controlled reclosers, the minimum trip level chosen does not alter the maximum continuous CUTent capacity of the recloser - unlike hydraulically controlled &:losers, in which the minimum trip and continuous current l3lings are related in that both are properties of the series coi. In microprocessor controlled reclosers, the minimum trip CUTent programmed in the control circuits is independent of lhe recloser's maximum continuous current rating. However, lhe minimum trip current chosen should account for anticipated peak system-load current. Also, it should be chosen so that 1he recloser operates for any fault current in its protection zone. Because protection against temporary faults is needed for lhe line between the substation recloser and load-side lledoser, the substation recloser should have at least one fast aperation. The load-side recloser will coordinate with the souce-side recloser if it has the same or greater number of fast operations. Delayed curves should be chosen so that the 'Dad-side recloser can operate to lockout on a permanent tot without the backup unit tripping after it performs its fast aperations. Simultaneous trippings can be eliminated by the selection of proper curves and use of the Cooper sequence coordination accessory, which is discussed later in this sec1i1Jn under "Features and Accessories for Microprocessor Controlled Reclosers:·

bample of Microprocessor Recloser Coordination Mhough coordination of microprocessor controlled reclosers is done via time-current curve studies, the coordination of curves to each other is different than it is with hydraulically cmlrolled reclosers. Please refer to Figure 32A3 and the followllg example. The maximum substation three-phase fault current is ~.(X)()() ampers and maximum load current is 450 amperes. At a sectionalizing point down the line, maximum three-phase f;;Ut current is 3600 amperes where maximum load current is "60 amperes. With these ratings factored into the recloser aiiJI)ication criteria discussed earlier, the Cooper Type WE I'IE!doser would fit both the substation application and the line a~~JP~ication. Unquestionably, other recloser types have a range Dl ratings that would satisfy these requirements, and the WE lii'E are used here merely as typical. User selection depends illllso upon operating experience, system construction, and ax:epted practices. Selection of the specific minimum trip currents must include

consideration of anticipated peak load currents on the system and the lowest fault-current level in each recloser's zone of protection. For the Type WE, ratings from which the trip current can be selected range from 50 to 1120 amperes. Minimum trip values of 1120 amperes for the substation recloser (ACRE1) and 400 amperes for the line recloser (ACRE2) were selected to facilitate cold-load pickup after an outage and to allow for future load growth. The time-current curves shown in Figure 33A3 are typical and are used for clarity of illustration. On an actual system, many influences not apparent from this isolated example may necessitate consideration of different curve shapes. Since the purpose of this example is to show the relationship of one recloser to the other, time-current curves A (fast) and B (delayed) will be reviewed first. For clarity, tolerances have been ignored here but should be considered in actual practice. Faults down line of ACRE2 should be cleared by the line recloser before the ACRE1 control responds. On fast operations, the curves show that, at fault-current levels of 1900 amperes and higher, the two reclosers will operate simultaneously. On delayed operations, since the 117 response curve for ACRE1 is slower throughout than 117 clearing for ACRE2, the line recloser (ACRE2) will clear without the substation recloser opening on its delayed curve. Assuming a 2101 , 2-117 sequence on both reclosers, a 3000 ampere permanent fault downline of ACRE2 would cause two simultaneous fast trips of both reclosers, followed by two delayed trips to lockout of ACRE2, after which ACRE1 would reset. The entire feeder would have experienced two short fast interruptions. By setting the substation recloser (ACRE1) to 1-101, 3-117, one of the unnecessary feeder interruptions can be avoided. 10 8 117 CLEAR .

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Figure 33A3. TCCs for application diagrammed in Figure 32A3.

controlled three-phase controllers. 127

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Recloser-to-Recloser Coordination (Continued)

Alternate Coordination Scheme Improved coordination would be achieved by employing a slower fast curve on the substation recloser, such as illustrated in Figure 34A3. With ACRE1 programmed for 2-104, 2117 simultaneous tripping is avoided for fault currents below 3700 amperes, which is above the level expected in ACRE2s zone of protection. This method is advantageous where faults are predominantly temporary in nature and clear after one or two fast-trip operations, but it has disadvantages when a permanent fault is encountered. In response to a permanent fault, ACRE2 operates twice on its fast curve and sequences to its delayed curve, but since ACRE1 is still on its 104 response curve, it operates twice by beating ACRE2's 117 curve. Again, there are two unnecessary feeder interruptions. The ideal is to have ACRE1 avoid those unnecessary interruptions yet still maintain its dual-timing capability for proper protection in its own zone. This is easily accomplished by activating the sequence coordination feature in the substation recloser control. This feature and others are described in the next section. 10

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FEATURES AND ACCESSORIES FOR MICROPROCESSOR CONTROLLED RECLOSERS Improved flexibility and coordination are made possible by the use of various features and accessories available with microprocessor controlled reclosers. Coordination studies may be more complicated, of course, but the accessories can provide many benefits in the form of improved system performance.

128

Sequence Coordination The sequence coordination feature is used to improve service continuity on lines protected by reclosers in series. It prevents unnecessary fast-trip operations of the back-up recloser on faults that can be cleared by the down line unit. The two typical recloser operations without sequence coordination in Figure 35A3 are similar to the examples in the preceding section. In example A, two reclosers with similar fast curves are in series. A permanent fault beyond the downline recloser is sensed by both reclosers, which then trip simultaneously on their fast curves. Even if the two reclosers had not tripped simultaneously, because the fast curve of ACRE2 is faster than ACRE1 (illustrated in example B, Figure 35A3), the backup ACRE1 will trip twice on its fast curve when the downline ACRE2 sequences to its delayed curve. In either case, service to the area between reclosers has experienced two short, but unnecessary interruptions. Both of these situations are discussed in the preceding example of microprocessor recloser coordination and the alternate coordination scheme. In sequence-coordinated operation, diagrammed in the Figure 36A3, the backup recloser merely counts the fast operations of the down line reclosers but does not trip. Its program sequence is advanced twice toward its delayed operations, but no trip signal is issued. Therefore, while the fault is sensed by the backup recloser, no operation occurs, and when the downline recloser reaches its time-delay operations, it alone trips because of the difference in time-current characteristics. Consequently, the needless service interruptions to the area between reclosers are prevented. Sequence coordination functions on fast operations only, so the number of operations that will be coordinated is determined by the number of fast operations programmed for the source-side recloser. The fast TCC for the source-side recloser must have a response curve slower than the clearing TCC for the load-side fast curve. When ground tripping is employed on reclosers that use sequence coordination, the same requirements must be met by the ground-trip TCCs as described above for phase trip. Figure 37 A3 shows typical ground-trip curves for source-side (ACRE1) and load-side (ACRE2) reclosers. As in the comparison of TCC's in the phase TCC analysis, the response curve for ACRE1 must be slower than the clearing curve for ACRE2. Of course, the requirements specified under "Electronically Controlled Reclosers: Coordination Basics" also must be met. Instantaneous Trip At higher fault-current levels, the instantaneous trip feature extends the range of recloser coordination with source-side devices. Above a predetermined level of fault current, it allows the control to bypass the programmed time-current characteristic and immediately trip the recloser without intentional time delay. Instantaneous tripping can be programmed to occur when fault current exceeds a selected multiple of minimum trip current. A range of multiples is provided to allow operation of this feature at the desired level for the particular application, and the accessory can be set to operate on any one or more trip operations in the sequence. The multiple for ground trip need not be the same as the multiple for phase. For fault currents below the selected minimum trip multiple, the control will time and trip according to its normally programmed characteristics.

A3

OPEN

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117 CLOSED -

117

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FAULT START OPERATION WITH SIMULTANEOUS TRIPPING

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TIMESEQUENCE-COORDINATED OPERATION

'9ft36A3. lllgrams of microprocessor recloser operation with sequence coordination on backup recloser.

129

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Recloser-to-Recloser Coordination (Continued)

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Figure 37 A3. . . . . Typical ground-tnp curves show1ng safe coordmat1on zone when sequence coordination accessory is used.

To keep pace with changing system requirements, the minimum trip multiple can easily be changed to any other value within the range or to different operations of the sequence. Coordination of a recloser with the instantaneous trip feature active with a source-side primary fuse is illustrated in Figure 38A3. The recloser has a minimum trip setting of 400 amperes and, with the delayed time-current curve shown but without instantaneous trip, coordination with the primary fuse would be lost with fault currents of approximately 1600 amperes and higher. With an instantaneous trip multiple of four, however, the recloser will trip instantaneously at any fault current level above 1600 amperes, so that, in this case, coordination with the primary fuse is extended to about 7000 amperes. Adequate margin must be provided between the recloser TCC and the fuse minimum melting curve to prevent fuse damage or fatigue. Instantaneous tripping allows coordination to be tailored to the requirements of the system. For example, again using a multiple of four, a fault at F1 in the system diagrammed in Figure 39A3 would initiate instantaneous tripping for any fault greater that 1600 amperes. The fault would be isolated by the sectionalizer (83), which requires only momentary current durations to activate its counting mechanism. A fault at F2, however, would not activate instantaneous tripping because of the lower fault-current level. The recloser will operate on its normal 2-1 04, 2-133 sequence, and the delayed 133 curve will allow the fuse to clear the fault.

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Figure 38A3. TCCs illustrating coordination of recloser, equipped with instantaneous trip feature, and source-side primary fuse.

Figure 39A3. Diagram of coordination scheme utilizing reclosers with instantaneous trip feature active.

Instantaneous Lockout Additional flexibility is provided by the instantaneous lockout feature, which permits the control automatically to shorten its sequence when fault current above a preset level is encountered. This feature is valuable for minimizing the effect of high-magnitude, close-in faults where there is a high probability the fault is permanent and coordination with downline devices is not required. By reducing the shots to lockout on faults above a preset level, the likelihood of equipment or conductor damage is considerably reduced.

A3 The instantaneous lockout operates in the same manner as instantaneous trip. Minimum-trip multiples are specified from a range of values. The feature can be set to lock out the control after the first, second, or third operation.

Instantaneous Trip/Instantaneous Lockout 'C ombination Combining instantaneous trip and instantaneous lockout

giYes the control yet another step of application flexibility: 1t1e ability to provide three "zones" of protection. For example, equipping the recloser applied in Figure 39A3 with instanta'1eOUS lockout as well as instantaneous trip enables use of a zoned protection scheme as illustrated In Figure 40A3. Control operation on faults in Zone 3 would be the programmed 2-1 04, 2-133 sequence, providing normal 'ledoser fuse coordination for a fault at F2. With the instantaneous trip set at a minimum-trip multiple of tour, faults in Zone 2, which would exceed the 1600 ampere level, could cause four instantaneous trip operations. t-lowever, for faults beyond the sectionalizers, coordination with !he sectionalizers (covered in a later section) would limit them m three, as the fault at F1 would be cleared by the sectionalizer on the third operation. For close-in faults (Zone 1), where high-magnitude fault anent could cause conductor burndown or possible substation ecJ.ipment damage, the instantaneous lockout can automatically shorten the control sequence. Setting the feature at a miniftJfll trip multiple of 16 would activate it at 6400 amperes. Above that fault level, the instantaneous lockout, set for one operation to lockout, minimizes the number of high fault curBlls seen, thereby reducing the possibility of line and eq~ip­ '!Delll: damage. Where the probability is high that trans1ent BJts might occur in Zone 1, the instantaneous lockout could be set to allow two Zone 1 operations.

RECLOSING INTERVAL The time between a recloser's overcurrent opening operation and the next closing operation (lockout not considered) is known as the reclosing interval. Recloser contacts are open during the reclosing interval, which may range from 0.~ seconds for instantaneous reclosing to 1000 seconds, depending on the type of recloser and the application. Somet.hin~ in be.tween these two extremes will be used for most apphcat1ons, w1th two seconds being the most common. Of course, microprocessor controlled reclosers offer the greatest flexibility.

Hydraulically Controlled Reclosers Reclosing intervals for Cooper hydraulically controlled reclosers are shown in Table 27 A3. On all single-phase and the smaller three-phase units (Types 6H and V6H), the indicated reclosing interval is fixed, with no adjustment or selection available. On the larger threephase hydraulically controlled reclosers (Type W series), the standard reclosing interval is two seconds, but an accessory can be included to provide a 30 cycle reclosing interval on the first reclosing operation. This would enable a 30 cycle, two-second sequence of reclosing intervals to be employed on a four-shot recloser program.

TABLE 27A3 Reclosing Interval Hydraulically Controlled Reclosers

'

L,V4L,D, D~E,4E,V4E

Reclosing Interval (seconds) 1.0 1.5 1.5 2.0

W, WV27, WV38X, R, RX, RV, VW, VWV27, VWV38X,

2.0*

Cooper Recloser Type H, 3H, 4H , 6H V4H , V6H

• Accessory available for 30-cycle reclos1ng on first operation.

4DO-AMPERE

2-104 2-133

~-----ZONE1------~----------ZONE2----------~----------ZONE3-----------

figure 40A3. k b" t" llilgram of zoned protection possible with instantaneous trip/instantaneous loc out com 1na Jon. 131

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Recloser-to-Recloser Coordination (Continued)

Microprocessor Controlled Reclosers A wide range of reclosing intervals can be programmed on microprocessor controlled reclosers: from the shortest possible time, called instantaneous (0.3 seconds) reclosing, to intervals as long as 1000 seconds. The choice of reclosing interval is influenced by a number of factors. Instantaneous reclosing, being the shortest contact-open time, provides the best chance of maintaining motor loads such as industrial supply, irrigation systems, or other loads that drop oH with an extended open period. Instantaneous reclosing is frequently desirable for the first reclosing in the sequence. There are, however, disadvantages. Instantaneous reclosing may not allow sufficient time to clear transient faults, such as a tree limb in contact with a line, or lines blown together in the wind. Also, ionized gases from the fault arc may not have dissipated. The two-second reclosing interval is quite common. It provides more time for transient faults to clear and ionized gases to dissipate, but an interval longer than two seconds further increases the possibility of motor loads dropping off. When used between fast trip operations, a two-second reclosing interval allows more cooling time for load-side fuses. A five-second reclosing interval often is used between the delayed trip operations of a substation recloser to allow more cooling of the high-side fuse. This permits the recloser timing to be closer to fuse minimum-melt timing. Longer reclosing intervals (1 0, 15 seconds, etc.) generally are used if the back-up protection is a mechanical relay-controlled breaker. This allows the timing disk on the overcurrent relay more time to fully reset. Examples of Reclosing Intervals Typical sequence on a line recloser where back-up protection is another recloser: INST, 2-sec, 2-sec or 2-sec, 2-sec, 2-sec Typical sequence on a station recloser with a high-side fuse involved (recloser trip sequence set for two fast, two delayed operations): INST, 2-sec, 5-sec or 2-sec, 2-sec, 5-sec Typical sequence on a recloser where back-up protection is a relayed breaker (recloser trip sequence set for two fast, two delayed operations): INST, 2-sec, 15-sec or 2-sec, 2-sec, 15-sec Reclosing intervals of longer than two seconds generally are used only after delayed trip operations. Instantaneous or twosecond intervals generally are used after fast trip operations.

TCC EDITOR™ Many microprocessor recloser controls have the capability of modifying time current curves by various methods. As an example, Cooper Power Systems has developed two methods for modifying TCC's. The first method is through setting modifiers 132

such as Multipliers, Minimum Response Time Adders, High Current Trip, etc through a series of dialog boxes within the configuration software. While this is effective, the actual time current curve is not displayed in the software. The second method offered by Cooper Power Systems is a graphical TCC Editor that is a separate application integrated with the configuration software. The TCC Editor allows visual indication of all the base TCC and all the modifiers to immediately verify that the TCC is correct per the desired system coordination. The TCC Editor's capabilities also include creating a completely unique TCC by entering time/current data coordinates which the Editor software converts to a data set in the format required by the control into which it is to be loaded. The Cooper Power Systems controls use an Import and Export feature to share the TCC between both applications. The graphical TCC Editor also includes the ability to create curves based on both ANSI and IEC standard formulas. TABLE 28A3 TCC Curve Cross Reference F6 Curve Name Kyle 101 Kyle 102 Kyle 103 Kyle 104 Kyle 105 Kyle 106 Kyle 107 Kyle 111 Kyle 112 Kyle 113 Kyle 114 Kyle 115 Kyle 116 Kyle 117 Kyle 118 Kyle 119 Kyle 120 Kyle 121 Kyle 122 Kyle 131 Kyle 132 Kyle 133 Kyle 134 Kyle 135 Kyle 136 Kyle 137 Kyle 138 Kyle 139 Kyle 140 Kyle 141 Kyle 142 Kyle 151 Kyle 152 Kyle 161 Kyle 162 Kyle 163 Kyle 164 Kyle 165 IEC lnv IEC VI IEC El Constant ANSIInv ANSI VI ANSI El USER1 USER2 USER3 USER4 USERS

F3 Cross Reference A 1 17 N R 4 L 8*, 8+ 15 8 5 p D B M 14 y G H 9 E

c

z 2 6

v w 16 3 11 13 18 7 T

K-Phase

F J K-G round n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a n/a

Index 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49

A3 Recloser and Relay/Circuit Breaker Coordination ELECTRO-MECHANICAL OVERCURRENT RELAY

To achieve proper coordination of a downline device with a relay-controlled breaker or recloser, the characteristics of the overcurrent relay must be understood. As discussed in Section A2, the two types of overcurrent relays involved are microprocessor and electro-mechanical. Each is described below as it relates to recloser coordination.

Unlike microprocessor relays, electro-mechanical relays (e. g., Westinghouse Type CO and General Electric Type lAC) have several characteristics that must be considered for coordination with a downline device.

Impulse Margin Time When timing on a fault current, the relay disk moves toward the closed position, and it will "coasf' for a short time after being deenergized when the fault is interrupted by a down line device. This additional movement is called coasting time or impulse margin time. The times involved are as follows for a CO relay:

MICROPROCESSOR OVERCURRENT RELAY

The typical microprocessor relay has fast reset of timing. Thus, coordination is relatively simple, since there is essentially no ·overshoot" or "coasting" of the timing function to be considered. The response or relay time may be used without adjustment to determine if tripping will occur, with the goal of assuring that the down line clearing time is faster than the minimum retay time. Because of the microprocessor relay's fast reset, ::umulative timing of a downline recloser is not a factor. 60 50

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133

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Recloser and Relay/Circuit Breaker Coordination (Continued)

Relay Type C0-2 C0-6 C0-7 CO-B C0-9 C0-11

TIM: Impulse Margin Time-Seconds

0.05 0.06 0.05 0.03 0.03 0.03

Thus, when operating with a downline recloser, the relay time tends to accumulate. Reset times of typical electro-mechanical overcurrent relays are shown in Figure 42A3.

The formula for determining impulse margin time is TIM =TOP-TI in which TIM is impulse margin time, TOP is relay operating time, and Tl is minimum fault time (impulse time), during which sufficient inertia is supplied to the disk to cause it to coast closed following deenergization. Figure 41 A3 shows the effect of impulse margin time for an application involving a C0-8 relay with the time lever set at 1 112. "A" and "C" are the fast and delayed recloser curves. At 1600 amps: TOP = 3.0 seconds, TIM = 0.03 seconds, and Tl = 2.97 seconds. At 10,000 amps: TOP= 0.3 seconds, TIM= 0.03 seconds, and Tl = 0.27 seconds. Impulse margin time (TIM) is significant at the higher currents and lower time-dial settings.

Reset Time The typical electro-mechanical relay does not reset immediately after deenergization, but rather requires significant time for the disk to return to its original position.

134

2

4 6 8 TIME DIAL POSITION

10

Figure 42A3. Reset times of typical electro-mechanical relays.

A3 Methods for Checking Relay and Downline Recloser Coordination 1. For a single-shot (nonreclosing) downline device, compare the curves and add 0.3 seconds to the downline device's clearing time. This conservative approach is illustrated in Figure 43A3.

A more accurate approach is to add impulse margin time to the clearing time of the downline device. The relay time must be greater than this. Either allow for tolerances, or use actual timing data and allow for variations due to temperature plus any other variations.

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§§§§§~ ~

CURRENT IN AMPERES

Figln43A3. llllllly-recloser coordination check with 0.3 seconds added to recloser clearing time.

135

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Recloser and Relay/Circuit Breaker Coordination (Continued}

2. For a reclosing sequence of a downline recloser, add all

A more accurate approach is to calculate actual relay disk travel for each trip operation of the downline recloser, add recloser timing plus relay impulse time for each trip, and subtract the relay reset time for each reclosing interval. Following is a demonstration of this method.

times of the sequence and compare to the relay curve, as in Figure 44A3. This does not account for resetting of the relay disk between operations. It is an extremely conservative method and may not be realistic for many applications.

3600

60 50 40

2400

30

1800

3000

1\

1200

20

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300

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600 480

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CURRENT IN AMPERES

Figure 44A3. Comparison of total reclosing sequence time with relay curve.

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136

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A3 RECLOSER AND RELAY/CIRCUIT BREAKER COORDINATION ANALYSIS

Relay reset during 2 sec. reclosing interval . . .- 6.7 percent Net relay travel ... . . . ...... .. . . . ... .... .4.1 percent

Let us examine the coordination possibilities for a recloser that has a 2A/2C sequence with two-second reclosing intervals, and an inverse relay curve set for 300 amperes minimum pickup and no. 5 time lever. (See Figure 45A3.) The relay requires approximately 0.6 seconds to close contacts on 1000 amperes, and 30 seconds to reset fully. It has an impulse margin time of .03 seconds.

Relay travel during second A operation ...... + 5.8 percent Relay impulse travel .... . .. .. ... . . . ......~ percent Net relay travel . . ..... . ... . ....... . .... 14.9 percent Relay reset during 2 sec. reclosing interval ... - 6.7 percent Net relay travel .... . .... . . . .... . .... . ... 8.2 percent

Recloser clearing time on A curve at 1000 amperes . ...... . .... . .... . ........ . .0.035 second

Relay travel during first C operation (.3/.6 x 100) ............. . ......... .+ 50.0 percent Relay impulse travel .... ... ......... . ....±...M percent Net relay travel . . ........... . ... . .... . .63.2 percent

Recloser clearing time on C curve at 1000 amperes . ... .. ...... . .... . ......... .0.030 second

Relay reset during 2 sec. reclosing interval . .. - 6. 7 percent Net relay travel . ... .. . .... . .... . . . .. .. .56.5 percent

Relay reset during 2-second open time of recloser (2/30 X 100) ................... . ....... 6. 7 percent

Relay travel during second C operation .....±.QQ,.Q percent Total relay travel ... . .. . . .. ... . ... .. ... 106.5 percent

Impulse margin time (.03/.60) .. . ... .. . . ..... 5.0 percent

Since the total calculated relay travel is greater than 100 percent, the circuit breaker will trip during the last "C" curve timing operation of the recloser. This can be corrected by changing the last reclosing time of the recloser sequence to a longer time - for example, to 10 seconds. This adjustment is used as the basis for the following recalculation, starting at the time before the first C operation in the preceding analysis.

50 40 30

20 10 1-- RECLOSER CURVES 8 c 6 5

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3

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w

.4 .3

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CURVE

Relay travel during first C operation (.3/.6 X 100) . . . . ...... . ....... . ..... + 50.0 percent Relay impulse travel . . .... . .. . ......... . .±..Q..Q percent Net relay travel . . ... . ... . .. ... ... .... . .63.2 percent

\

1

~

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Relay reset during 10 sec. reclosing interval (10/30X 100) .. . ... .. .... . . . . . . . ... . .- 33.3 percent Net relay travel ...... . .... .. ..... . .....29.9 percent

........

1

.08 .06 .05 .04 .03

Relay Travel

Net relay travel . . .... ..... . . . .... .. ..... . .8.2 percent

I\ OCBRELAY

I~

2

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Operation

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4

Relay travel during second C operation . . . . .+ 50.0 percent Relay impulse travel ... . . . .. . . . ....... . .. + 5.0 percent Total relay travel .......................84.9 percent

r--.

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o

ogoooo

~ ~ .. §~~~

CURRENT (AMPERES)

Agure45A3. Tine-current curves for recloser and relay/circuit breaker coordination.

c.lculation of Relay Travel During Recloser Operation Operation

Relay Travel

Relay travel during first A operation (.035/0.60 X 100) .. . ....... . ..... . ...... 5.8 percent

Relay impulse travel ........ .. .... . ......±...M percent Initial total relay travel .... . ... . ... . .. . .. 10.8 percent

Since the total relay travel is less than 100 percent, the breaker does not trip and coordination is therefore attained. The current at which this analysis is performed should be selected at the point where the recloser and relay curves have minimum separation. If the calculated coordination is "tight," a second point should be used to verify coordination throughout the entire current range. The entire process is repeated for the second point.

A Overcurrent Protection 3." PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION

Sectionalizer Applications A review of the basic sectionalizer application factors covered in Section A2 may be desirable before considering the coordination principles and specific applications discussed here.

FIRST SECTIONALIZER COUNT rTHIRD COUNT SECTIONALIZER OPENS I-SECOND COUNT

I

SECTIONALIZER COORDINATION PRINCIPLES The following basic coordination principles should be observed in the application of sectionalizers. 1. The minimum actuating current of a sectionalizer should be 80 percent of the minimum trip of the source-side device (recloser or breaker). For electronically controlled sectionalizers, the actuating current is set directly. For hydraulically controlled sectionalizers, the minimum actuating current is 160 percent of the series coil rating. When coordinating a hydraulically controlled sectionalizer with a backup recloser that is series coil operated, the sectionalizer coil should have the same current rating as the backup recloser. The 160 percent factor for actuating current will assure positive coordination with the recloser's 200 percent factor of minimum trip to coil size.

2. Sectionalizers not equipped with ground-fault sensing should have their phase actuating current selected to coordinate with the ground minimum-trip setting of the backup device. This will assure that the sectionalizer will sense and count all load-side faults cleared by the backup device. With this more sensitive setting, however, the possibility of erroneous counts due to inrush currents must be considered. For electronically controlled sectionalizers, several restraint features are available to prevent false counts. For hydraulically controlled sectionalizers, the actuating current level should be at least ten times the peak load current at the sectionalizer location. A more sensitive actuating current setting may result in false counts and lockout because of inrush currents produced by backup-device trip operations in other parts of the circuit. 3. The sectionalizer should be set to lock out in one less operation than the backup device. This general rule need not apply in the case of several sectionalizers in series, where successive units may be set for one, two, or three operations less than the backup recloser. 4. The opening and reclosing times of the backup device must be coordinated with the sectionalizer's count memory time. The combined tripping (except for the first trip) and reclosing times of the backup must be shorter than the sectionalizer's memory time, as shown in Figure 46A3. If the backup operating time is longer than the sectionalizer's memory time, the sectionalizer will partially ''forget" the number of backup tripping operations. This may require an extra backup trip operation and result in the backup locking out for a fault beyond the sectionalizer, in which case both the backup device and the sectionalizer would be locked out. 5. Three-phase sectionalizers are limited to coordination with three-phase simultaneous-opening backup devices. Nonsimultaneous phase tripping of backup devices could result in an attempted fault interruption by the sectionalizer, which is not designed for such operation.

138

FAULT

SECTIONALIZER MEMORY TIME 1 - - - - - BACKUP TIME 3

'I

R2

URRENT

-

TIME

R1 & R 2 =1ST AND 2ND RECLOSING TIMES

Figure 46A3. Sectionalizer memory time, three counts to lockout.

RECLOSER AND HYDRAULICALLY CONTROLLED SECTIONALIZER COORDINATION Because sectionalizers do not have time-current curves as do fuse links, their coordination does not require a study of curves. In the typical application shown in Figure 47A3, th~ backup recloser is set for four shots to lockout. These operations may be any combination of fast followed by delayed timing. The sectionalizer must be set for fewer counts than the backup recloser, and in this case, three counts are selected. If a permanent fault occurs beyond the sectionaliz~r, t~e sectionalizer opens and isolates the fault after the th1rd tnp operation of the recloser. The recloser then re-energizes the unfaulted sections to restore them to service.

SUBSTATION

50-AMPERE COIL 100-AMPERE MINIMUM TRIP

50-AMPERE COIL SO-AMPERE ACTUATING

Figure 47A3. . . . . Basic sectionallzer-recloser coordmat1on, w1th recloser set four shots to lockout.

If additional sectionalizers are added in series, they can be set for fewer counts to lockout, as shown in Figure 48A3. A fault beyond the last sectionalizer actuates the ~ecloser, ~nd all three sectionalizers count the current mterrupt1on. Sectionalizer C, however, locks out to isolate the faulted branch. The recloser restores the unfaulted lines to service, and sectionalizers A and 8 then reset. Note that there is no protection for temporary faults beyond sectionalizer C. Also, setting hydraulically controlled sectionalizers for fewer than three counts prevents the use of fuses down line from the sectionalizers.

A3 OIL TEMPERATURE (F)

1 COUNT

-.f.---{ c l - - SECTIONALIZERS 50-AMPERE COIL SO-AMPERE ACTUATING

·22

~

·4

14

32

50

68

86

104 122 140 158

200

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0

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ACR 50-AMPERE COIL 100-AMPERE MINIMUM TRIP

Figure 48A3. Sectionalizers added to branch lines; recloser set four shots to lockout.

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COORDINATION IN THIS AREA.

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Coil Sizes Hydraulically controlled sectionalizers are rated similarly to hydraulically controlled reclosers, since both have coils that establish the continuous-current and minimum actuating-current ratings. For hydraulically controlled sectionalizers, matching the series coil with the series coil of the backup will assure coordination. For example, a recloser rated 50 amperes continuous will coordinate with a sectionalizer rated 50 amperes continuous. The sectionalizer can carry the same load current as the recloser, but to provide positive coordination, its minimum actuating current is 80 amperes compared to the recloser's minimum trip current of 100 amperes (that is, the SO-percent relationship discussed above). llemory Time Hydraulically controlled sectionalizers were originally designed br use with hydraulically controlled reclosers. Since hydraulically controlled reclosers generally have a maximum two-second rectosing time, hydraulically controlled sectionalizers have a memory time that is fixed (there is no choice), but which will M>rk with any hydraulically controlled recloser. The memory lime depends on the resetting of the sectionalizer's hydraulic counting circuit; thus, the memory time is a function of the viscosity of the oil in the hydraulic mechanism, which in turn is dependent upon the temperature of the oil. Figures 49A3 and 50A3, and Table 28A3 provide information b accurately determining whether or not the hydraulically controlled sectionalizer will coordinate with a backup device. Figure 49A3 shows the memory time of hydraulically c:ontrolled sectionalizers as a function of maximum oil left1lerature and the operating sequence of the backup device. Maximum oil temperature is the ambient temperature pbs the temperature rise of the oil due to current flow through lie sectionalizer. Table 26A3 indicates the approximate oil temperature rise llill occurs in a hydraulically controlled sectionalizer at various ~rrent levels. Assuming a period of load-current flow l[llliol'to sectionalizer operation, the temperature rise is added -.e sectionalizer ambient temperature to determine an lfiiP'OXimate maximum oil temperature. f9,1re 50A3 indicates the portions of the backup operating ...,.ence that must be considered to determine

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-30 - 20 ·10

0

10

20

r--...... . 3()

40

.... ~ 50

60

70

OIL TEMPERATURE (C)

Figure 49A3. Coordination curve for hydraulically controlled sectionalizers.

TABLE 29A3 Oil Temperature Rise Load Current (% of coil rating)

25 50 75

Approximate Temperature Rise ("C) ("F) 2 4

7 15

13 27

proper coordination. These appropriate fault times and reclosing times during which the sectionalizer must retain the proper count constitute what is called "total accumulated time": the total time in seconds from the instant of interruption on the first fault operation to the instant of interruption on the last fault operation the sectionalizer counts before locking out. When a hydraulically controlled sectionalizer is set to lock out after counting three fault currents, the total accumulated time (TAT) of the backup device is the sum R1 + F2 + R2 + F3 in seconds. If the sectionalizer is set to lock out after two counts, the TAT is R1 + F2 . Should the sectionalizer be set for one count to lockout, there is no need to be concerned about memory time. Two requirements involving memory time must be met to assure that a hydraulically controlled sectionalizer will coordinate with backup devices: 1. Accumulated fault current on time cannot exceed 70 percent of the allowable TAT. In a two-count sequence, F2 cannot exceed 70 percent of TAT = R 1 + F2. In a three-count sequence, F2 + F3 cannot exceed 70 percent of R 1 + F2 + R2 + F3. 2. At the established oil temperature (ambient plus rise), the total accumulated time must not exceed the value indicated by the sectionalizer coordination curve, Figure 49A3. Following are two coordination examples for which FIIQiftS 49A3 and 51A3 will serve as references.

A. Overcurrent Protection 3. PROTECTIVE EQUIPMENT APPLICATIONS AND COORDINATION Sectionalizer Applications (Continued)

TOTAL ACCUMULATED TIME OPERATION OF BACK-UP DEVICE

L =LOAD CURRENT F, = 1STTRIPTIME R, = 1ST RECLOSING TIME F2 =2NDTRIPTIME R2 =2ND RECLOSING TIME F, =3RDTRIPTIME R, = 3RD RECLOSING TIME

STARTI-+------TOTALACCUMULATEDTIME-------+1 SECTIONALIZER OPENS

MAX. POSITION - - - - - - - - - - - - - - - - - - - - - - - -

2ND POSITION

START SECTIONALIZER TRIP PISTON POSITIONS - - - - ACTUAL COUNT RETENTION I I / ;' I THEORETICAL WITH NO RESETIING

Figure 50A3. Sectionalizer count retention as related to backup operating sequence. Example 1 Conditions: Maximum ambient temperature .................. a5o F Sectionalizer coil size .................... 100 amperes Normal load current ...................... 50 amperes Backup OCR .........set for 1 fast, 3 delayed operations Sectionalizer ..................set for 3 counts to open Maximum oil temperature ........... a5o + 13° = gao F

Example2 Conditions: Maximum ambient temperature .................. a5o F Sectionalizer coil size .................... 100 amperes Normal load current ...................... 50 amperes Backup OCR ......... set for 1 fast, 3 delayed operations Sectionalizer ..................set for 2 counts to open Maximum oil temperature ........... a5o + 13° = gao F

From the coordination curve in Figure 4gA3, allowable TAT at gao F is 2a seconds. Figure 51A3 illustrates this example, and explanation follows: To meet memory-time requirement no. 2, the maximum current on-time (F2 + F3 ) for a TAT of 2a seconds is 2a x 0.70 = 1g.6 seconds (round off to 20 seconds). Therefore, F2 plus F3 cannot exceed 20 seconds. To meet memory-time requirement no. 1, the TAT must not exceed 2a seconds. With F2 and F3 each at ten seconds, a maximum limit can be calculated for R1 and R2 as shown below:

The allowable TAT is again 2a seconds; with the sectionalizer set for two counts to open, there is only one fault current on-time (F 2) and only one reclosing time (R 1). Therefore, the fault current on-time (F 2) cannot exceed 20 seconds, and the reclosing time (R 1) must be a seconds or less.

TAT = (R1 + R2) + (F2 + F3) R1 + R2 =TAT - (F2 + F3) = 2a- (1 0 + 10) =a seconds Therefore, the sum of the two reclosing times cannot exceed, but can be less than, eight seconds. 140

Voltage Restraint This feature, which enables the sectionalizer to discriminate between source-side and load-side interrupting devices, is available on three-phase hydraulically controlled units. It is discussed in the following section, under"Sectionalizer Features."

A3

R, - - M - - F, = 10

~~~------~-12_._47-k_v_--r-----

1

1

SMALL FIXED

BANK

Figure 1281. Circuit that may cause magnification of capacitor switching overvoltages.

B. Overvoltage Protection 1. FUNDAMENTALS AND THEORY Overvoltages of System Origin (Continued)

Ls

E

C

Lr

_{ Ct

Figure 1381. Equivalent circuit of diagram in Figure 1281. The reason for concern with regard to this problem is that capacitor switching is often a daily event. Repetitive surges may eventually damage equipment, and the duty on the arresters is relatively severe. Voltage magnification is often evidenced by failed equipment and arresters at remote locations during capacitor switching. The following steps will usually remedy the problem: • Detune the circuit by changing bank sizes or moving banks. • Use preinsertion resistors on breakers to limit voltage surge magnitudes. • Unground the remote bank. • Switch large banks in more than one section. Figure 1481 illustrates representative waveforms of this occurrence for system parameters, with reference to Figure 1281 and 1381, summarized as follows: Ls = 14.3 mh C1 = 10 uf LT = 350 mh C2= .41 uf

Successful interruption depends on whether the interrupter can build up sufficient dielectric strength to withstand the rate-of-rise of the recovery voltage. Figure 1581 shows that, one-half cycle after interruption, two times system voltage appears across the interrupter contacts. If restrike occurs at this point, the capacitor attempts to recover to crest voltage of the opposite polarity, and in doing so overshoots by the amount of the attempted correction. The inrush current is oscillatory at high frequency, and if this current is interrupted at a high-frequency current zero, as much as 3 per-unit voltage may be trapped on the capacitor, and the restriking process may continue with the subsequent buildup of even higher voltages. Ungrounded-wye banks subject the capacitor switching device to even higher recovery voltages than the 2.0 per-unit observed for grounded-wye banks. The transient recovery voltages can attain values of 2.5 per-unit on the first phase to open when the other two phases open on the next current zero, 3.0 per-unit on the first phase to open when the other two phases open on the second current zero, and 6.4 per-unit if the first phase to clear restrikes at 2.5 per-unit (compared to 4.0 per-unit for a grounded-wye bank). Restriking capacitor-bank switching devices can result in high system-voltage surges, which may cause equipment damage if not protected adequately. Therefore, it is desirable to choose a switching device that will minimize the possibility of restrike. Opening resistors are sometimes used to ease the duty on the interrupters. At high system-voltage levels, ungrounded-wye banks are not practical, because switching devices with the required recovery-voltage duty are often not available.

.. ...·.... ...·.. .: ·... ....

•' •• BUS VOLTAGE

:-···

\ CURRENT

'••,

......:'

..: ::.. :: ·.·

MAX 4 Ec ACROSS SWITCH CONTACTS Y. CYCLE AFTER RESTRIKE

4.69pu-

Figure 1481. Waveforms of overvoltages on 2-mvar, 34.5 kV capacitor bank after energizatlon of nearby 50 mvar, 115 kV bank. RESTRIKE DURING CAPACITOR-BANK INTERRUPTION When deenergizing a capacitor bank, a capacitor switching device clears the current at a current zero. Since the current is strictly capacitive, the voltage at the time of interruption is at a peak. But since the current magnitude is quite low compared to fault currents, the current may be interrupted when the contacts have parted only a small amount. When this occurs, peak voltage is trapped in the capacitor on the load side of the switch.

182

CAPACITOR VOLTAGE

Figure 1581. Oscillographic representation of recovery voltage across interrupter contacts after capacitor-bank deenergization.

81 PRESTRIKE DURING CAPACITOR ENERGIZATION When a capacitor bank is energized, an arc is established within the interrupter contacts before they physically make contact: a phenomenon known as prestrike. Since the current flowing is of high frequency, it may go through several zeros before metallic contact is finally attained. Interrupters have been improved so that they can clear at current zero, regardless of whether it is a result of high-frequency or power-frequency current. If current is interrupted at one of the current zeros after prestrike occurs, voltage can be trapped on the switched capacitor. When the interrupter again strikes the arc or metallic contact is made, switching surges are produced similar to those discussed earlier. Multiple re-ignitions have been known to occur with vacuum interrupters. Figure 1681 shows an example of prestrike. The peak transient voltage increased from 1.80 to 3.65 per-unit, which should result in an arrester operation. In addition, the capacitor inrush current is proportionately higher, which may be damaging to the capacitor fuses. Some of the corrective measures that may be taken: • Use a switch that does not cause prestrikes with subsequent clearing. • Use preinsertion resistors. • Insert current-limiting reactors to limit the overvoltage. • Use arresters to clamp overvoltages.

BUS VOLTAGE

-3.65pu CAPACITOR VOLTAGE

1.89pu-

Inductive Current Chopping Some circuit breakers are capable of interrupting low levels of currents prior to a current zero. This action, which is known as current chopping, can give rise to abnormal overvoltages because of the magnetic energy associated with the current being trapped in the circuit. Such overvoltages usually are observed when the interrupter on an unloaded transformer chops the magnetizing current in the process of an unloaded transformer deenergization. When this happens, energy is trapped in the transformer magnetizing inductance, which is subsequently interchanged with circuit capacitance, producing a voltage surge. The magnitude of the voltage surge is conservatively:

v~~cfi where Lc Lm C

=chopped current level =transformer magnetizing inductance =capacitance on the transformer side of the switch

As can be seen in the above formula, the voltage surge produced is independent of the voltage level; therefore, this phenomenon is most troublesome on low-voltage, low-BIL systems. The level of energy discharged is of medium range and may damage low-thermal-capacity arresters. For example, a 1000 kVA transformer's surge impedance is 5 x 1Q4 ohms. If an interrupter's current-chopping level is two amperes peak, a voltage surge of 100 kV peak might be produced. Actually, the voltage surge produced is less than 60 percent of this value due to energy loss in the transformer core. One of the corrective measures taken to solve this problem is the use of fuii-BIL transformers rated 95 kV and above, even on lower-voltage systems. Another solution is to add surge capacitors to reduce the surge impedance of the transformer, although a significant length of cable between the breaker and the transformer may be used for the same purpose.

-3.65pu CAPACITOR CURRENT

PRESTRIK~ \ ARC EXTINCTION

Figure 1681. Oscillographic example of prestrike during capacitor energization.

183

B. Overvoltage Protection 1. FUNDAMENTALS AND THEORY Overvoltages of System Origin (Continued)

Current-Limiting-Fuse Arc Voltage Current-limiting fuses force the fault current to an early current zero by developing a high arc voltage that opposes current flow. The rapid change of current through the circuit inductance can result in an arc voltage that is much higher than normal operating voltage. The voltage is given by the relationship:

E

100 34.5 kV/

90

80

di =e + (-L-} dt

~ w

where E = arc voltage e normal system voltage L = total system inductance

/

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40

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l7 L

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The magnitude of the arc voltage depends on the fuseelement construction. For current-limiting fuses that have elements of uniform cross-sectional area (wire-element fuses rated 12 amperes or less), the voHage has a definite relationship to available fault current. Figure 1781 shows the maximum arc voltage that could be generated as a function of available fault current. The maximum possible arc voHage in a wire-element fuse also depends on the point in the voltage cycle during which the fault current is initiated. For current-limiting fuses that have nonuniform (ribbontype) elements, the maximum arc voltage that can be produced is constant regardless of available fault current. It is dependent only on the recovery voltage across the fuse. Figure 1881 shows the maximum arc voltage for a nonuniform-element current-limiting fuse as a function of the circuit voltage.

~4 .4kV

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8.3kV

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7.2 kV 4.8kV

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20 15 10 25 CIRCUIT VOLTAGE (kV)

100

38 KV FUSES-6 THRU 12 AMP

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.1

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.3

.4 .5

.7

2

3

4

5

7

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AVAILABLE CURRENT (rms symmetrical kiloamperes)

Figure 1781. Maximum arc voltage that can be produced by a wire-element current-limiting fuse.

184

30

35

Figure 1881. Maximum arc voltage that can be produced by a ribbonelement current-limiting fuse.

120

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25kV

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(.)

~! = change in fault current

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30 40 50

70

81 Arc-voltage magnitudes generally are not high enough to damage equipment, but may cause arrester sparkover with possible damage to low-thermal-capacity arresters. The switching surge duty on a surge arrester can be more severe than the discharge of a short-duration lightning stroke. This is so because the arrester must discharge all or part of the energy that has been stored in the system inductance ahead of the fuse. Also, additional energy supplied from the power source will be absorbed by the arrester. Tests have shown that arresters will withstand the thermal duty, provided the arrester has an energy dissipation value of one kjoule/kV of rating. Arc voltage is a low-frequency switching surge phenomenon. Therefore, the waveform is comparable to the minimum 60 Hz sparkover level of the arrester (peak voltage). Current-limiting fuses with nonuniform elements cause arrester sparkover at approximately ten percent above the minimum 60 Hz sparkover level. C-L fuses with uniform elements, however, produce surges that will cause arrester sparkover at approximately 20 percent above the minimum 60 Hz value. An example will illustrate how to determine if an arrester will sparkover due to current-limiting-fuse arc voltage. A 15.5 kV, 40° C current-limiting fuse is applied on a 12.47/7.2 kV grounded-wye system with 9 kV arresters. The maximum arc voltage is 18 kV, according to Figure 1881, since C-L fuses rated above 12 amperes have nonuniform elements. For 9 kV distribution-class arresters, the power-frequency sparkover level is 15 kV, which has a peak value of 21.2 kV. Since the maximum arc voltage is less than 21.2 kV, sparkover is not probable.

FERRORESONANT OVERVOLTAGES The term ferroresonance is often used to describe all phenomena associated with the operation of a capacitor in series Wlitlh a nonlinear or saturable inductor. During series resonance, a very high voltage can occur across the elements of a se~ LC circuit. Figure 1981 shows a series LC circuit being excited at or near its natural frequency by a voltage source E. From this figure it is obvious that the voltages Ec and EL add up to the applied voltage E. But as shown in Figure 20~1, the pha.sor diagram for this circuit, the voltage across the mductor leads the current by 90 degrees, and the voltage across the capacitor lags the current by the same amount. Therefore, the magnitudes of Ec and EL can exceed the magnitude of E. The most common occurrences of ferroresonance are on grounded systems having lightly loaded transformers with ungrounded-wye or delta-connected primaries, where singlepole switching leaves phase-to-phase or phase-to-ground capacitance connected to the load side of the switch. +Ec-

+ E

Summary of Switching Surges Table 281 summarizes the causes and effects of the distributionsystem switching surges discussed in the preceding pages.

TABLE 281 Summary of Switching Surges on Distribution System Cause and Effect Cause

i

Circuit or System Conditions: Switching Capacitance and Unloaded Transformer as a Unit Capacitor Switching Voltage Magnification Inherent Switch or Interrupter Action: Restrikes During Capacitor Switching Prestrikes During Capacitor Energization Inductive Current Chopping Current-LimitingFuse Arc Voltage (non-uniform element) Current-LimitingFuse Arc Voltage (uniform element)

Maximum Expected Voltage (pu)

Energy of Discharge

Duration of Follow Current

2pu

Medium

Prolonged

3pu Spu

High High

Prolonged Prolonged

3-6pu

High

Prolonged

6pu

Low

-

Independent of System Voltage 2pu

Medium

Prolonged

Medium

-

Independent of System Voltage

Medium

-

Figure 1981. LC circuit for illustration of ferroresonant overvoltages.

Ec

E

Figure 2081. Phasor diagram for circuit in Figure 1981. A simple example will help to illustrate this phenom~non. Figure 2181 shows single-pole switches used to energiZe a delta-connected transformer. The interconnections are by cable, as is usually the case with pad-mounted transformers.. If one of the switches is closed and the other two are open, as in the drawing, a current path is provided as ~ ~n Figure 2281. If the inductance and capacitance values 1n this circuit are such that they can be resonant at power freq~Jei11C"J'. excessive voltages can appear across the transformer wi"lciinQs and at the cables on the unenergized phases.

185

B. Overvoltage Protection 1. FUNDAMENTALS AND THEORY Overvoltages of System Origin (Continued)

Figure 21 81. Switch used to energize a delta-connected transformer..

------------, .::r:: -

.,/

''

,------/

I

I

I I I I I

,-- -

I

I

-- - - - - -)

Figure 2281. Path of current produced by closing one phase of switch in Figure 2181.

Although this example illustrates a transformer supplied through a cable, ferroresonance can also occur on lightly loaded rural systems with long overhead feeders. It may also occur with four- and five-legged core transformers with grounded-wye-connected primaries fed by a concentric neutral cable. In this case, resonance may occur with the phaseto-ground capacitance and magnetic coupling between energized and deenergized primary wind ings. Some of the control procedures used to avoid ferroresonance are: • Three-phase switching. • Use of grounded-wye primary transformer connections. • Use of resistive secondary loads. • Grounding the neutral of wye-connected primaries. • Limiting the lateral length between single-pole devices and the transformer bank. The high voltages involved in ferroresonance have been known to cause failure of connected equipment such as surge arresters, transformers, and reclosers. The high current often causes sectionalizing or equipment fuses to blow.

HARMONICS Overvoltages due to harmonic distortion of the voltage waveform are generally not sufficiently high to cause arrester sparkover or immediate insulation failure. However, when the harmonic levels are increased by resonance, accelerated degradation of insulation may occur, particularly in the capacitor banks involved in the resonance. Following is a brief summary of the harmonics problem and methods of dealing with resonance. For a more detailed discussion, refer to Electric Power Systems Harmonics Design Guide, Cooper Power Systems Bulletin No.87011. 186

Sources and Characteristics A distribution system has many potential sources of harmonics, which, in general, are produced by devices with nonlinear operating characteristics such as transformers, rotating machinery, arc furnaces and arc welding equipment, and power electronic devices. Transformer saturation characteristics result in a non-sinusoidal exciting current when a sinusoidal voltage is applied. The harmonics of consequence are the third, fifth, and seventh. Also, transformer inrush-current results in saturation on either the positive or negative half of the fundamental voltage wave, so some even harmonics, mainly the second and fourth, are generated. Harmonics produced by rotating machinery are related principally to variation in magnetic reluctance caused by slots in the machine stator and rotor. Second harmonic currents can be produced due to saturation, mainly in the teeth. Arc furnaces and arc welding equipment generate harmonics because of the nonlinear voltage-current characteristic of power arcs. The harmonics of concern are usually the fifth, which may reach 20 percent of the fundamental voltage, and the seventh, which may be five-eighths percent of the fundamental. Power electronic devices, because of their increasing use, constitute the most important category of harmonic-generating equipment. Line-commutated devices such as DC traction power system, DC supplies for batteries, and solar cells generate harmonic currents whose harmonic numbers are given by: h = pn ± 1 where h = harmonic number p = pulse number of device n =positive integer (1 ,2,3, ... ) The theoretical magnitudes of the currents are given by: lh = !.1

h where Ih = harmonic current magnitude I 1 = fundamental current magnitude The actual magnitudes are somewhat lower due to noninstantaneous commutation and delay angle if phase control is used.

Effects and Concems Harmonics are of concern because of their effect on power equipment, control, protection, and metering, and because they are a source of telephone interference. Harmonics can cause additional losses and heating on capacitor banks. Also, unfavorable phase relationship between harmonic voltages and supply voltage may cause peak voltages with amplitudes considerably above the nominal ten percent overvoltage rating of capacitors. This is important because corona starting-and-extinction levels are a function of peak-to-peak voltage, and capacitor life is directly related to these levels. In the case of induction motors, reduced efficiency and heating, especially as a result of induced rotor currents, are the most significant concerns. Also, the interaction between harmonic currents and the fundamental frequency causes an oscillating torque, which may result in mechanical oscillations.

81 In transformers, harmonics can increase both iron and current losses. The result is increased heating, but it is not usually SV"Iiftcant. Inductive coupling between AC distribution lines and lelephone lines induces harmonic voltages on the telephone system that may cause interference with message transmittal. lbis may occur when the same poles are shared by telephone and distribution circuits. Factors affecting the severity Gl interference are length of exposure, harmonic frequencies, capacitor-bank sizes and locations, and system grounding. Noise from harmonics on carrier control systems can cause erroneous operations if the harmonics generated are !'leaf a carrier frequency. Protective relays may also be affected, depending on the type of relay and design features. Relaying nefligence operating on sampled data or zero crossing of SV~als is especially susceptible to error from harmonic dstortion. Although changes in operating characteristics are Elatively small, relays have a tendency to operate slower and/or at higher pickup values. Harmonics may cause both positive and negative errors in electric metering, with the significance of errors varying greatly with different types of meters. Induction watt meters tale been found to have error magnitudes within acceptable llevels of accuracy for realistic levels of harmonics.

l

POWER-FACTOR-CORRECTION CAPACITORS Harmonic-current magnification can occur when the system is resonant at one or more of the harmonic currents flowing through it - a problem that is present when power-factorcorrection capacitors are used on a distribution feeder. A paralel resonant circuit and its impedance characteristic are shown in Figures 2381 and 2481. The impedance irtcreases, theoretically to infinity, at the resonant frequency, fo. Injecting a current through the circuit at this frequency will cause an extremely high voltage.

SYSTEM IMPEDANCE

STEP DOWN TRANSFORMER

DC DRIVE

I

ZL

~t

>-

IL

I Zc

::~lie

l Z =ZLI /Zc

Figure 2381. A parallel resonant circuit.

POWER FACTOR CORRECTION CAPACITOR

Figure 2581. System with power-factor-correction capacitors located at a source of harmonics.

An example will help illustrate the effect of power-factorcorrection capacitors located at a source of harmonics. Figure 2581 shows a system on which compensation is applied at the same bus where a DC motor drive is connected. Figure 2681 shows a simplified circuit of the same system, but with the DC motor drive replaced by a harmonic source. Xc is the capacitor-bank reactive and Xs is the system reactive up to the low-voltage bus. The resonant frequency for this circuit is given by:

-/X Xs

fr=...!.-1-= f1 21t "lsC 'J where

fr = resonant frequency fundamental frequency fr

=

w

u z

i§ w

0..

~

HARMONIC SOURCE fo

Agure 2481. Impedance characteristic of a parallel resonant circuit. Figure 2681. Simplified circuit of system in Agure 2581 .

187

B. Overvoltage Protection 1. FUNDAMENTALS AND THEORY Overvoltages of System Origin (Continued)

If the resonant frequency is close to the frequency of one of the harmonic currents generated by the DC drive, harmonic magnification may occur, and high currents may circulate between capacitor bank and system, causing fuses to blow. Also, parallel resonance is a high impedance to harmonic currents at the resonant frequency. Therefore, high harmonic voltages may result, causing damage to capacitors and other equipment. Voltage distortion has been used as one criterion to determine acceptable system performance when harmonics are present. It frequently is expressed in terms of total harmonic distortion (THO), which is the ratio of the effective (rms) value of all harmonic voltages to the effective value of the fundamental. Thus, the voltage distortion, VD, may be written: %VD = [ XVh 2 V 12

]

11

2

Tuned filters, Figure 2781, provide a shunt path for current of one particular frequency, the tuned frequency being:

f

=

1

27till

At the resonant frequency, the impedance of the filter is reduced theoretically to zero (as plotted in Figure 2881 ), drawing that particular harmonic current out of the system. High-pass damped filters, Figure 2981, provide a shuntpath for all harmonics above the tuned frequency, which is the same as that indicated above.

X 100%

According to IEEE guidelines, the voltage distortion should not be greater than those listed in Table 381.

w

TABLE 381 Voltage Distortion Limits System Voltage 460 Volts 2.4 to 69 kV 115 kV and Above

(.)

z

< Dedicated System*

General System

10% 8% 1.5%

5% 5% 1.5%

~~ II

*A dedicated system is one servicing only converters or loads not affected by voltage distortion.

Note that this measure does not reflect the true peak voltage to which insulation structures are subjected. The peak voltage must be estimated by arithmetic sum of the components. For capacitor banks, the peak should be less than 120 percent of rated peak voltage.

Corrective Measures Corrective measures that may be taken for harmonic resonance problems include increasing the short-circuit capacity at the point of connection of a harmonic source, or selecting a capacitor-bank size to avoid resonance. Both of these measures will shift the resonant frequency of the circuit to frequencies other than the ones generated by the harmonic source. Another corrective measure is the use of filters to provide a shunt path for harmonic currents, thereby reducing the level of harmonic currents and voltages in the system. One of the advantages of filters is that they provide part or all of the reactive power required by the converter. Two kinds of shunt filters can be used: tuned or high-pass.

1

fo

Figure 2881. Effect of tuned filter on harmonic current.

I L

c

R

c Figure 2981. Diagram of high-pass damped filter application. L

R

Figure 2781.

L----==------' Diagram of tuned filter application. 188

One of the problems when applying filters is that they not only absorb the harmonic current from the nearby source but also from other parts of the distribution system. They therefore should be carefully tailored to the particular installation. Parallel resonant frequencies between filters and system should be investigated; a resonance near the third or fourth harmonics may cause additional problems.

81 Traveling Waves CAUSES AND CHARACTERISTICS Traveling waves frequently occur in power transmission and distribution systems, and may be caused by short circuits, conductor breaks, lightning strokes, or switching of components. The sudden change in voltage or current caused by one of these events is not transferred instantaneously to all points on an overhead line or cable. Instead, some finite interval is required for the surge (traveling wave) to propagate down the line. R

L

R

L

R

+ e

////lll//llllll

L

e

;,1"/~$-4@

e= +zi

+i-

FORWARD WAVES

Figure 3081. Physical representation of a distributed parameter line.

Figure 3181. Relationship of propagating voltage (e) and current (i) waveforms.

The characteristics of traveling waves on particular lines or cables are due to the distributed nature of the resistance (R), inductance (L), and capacitance (C) of the lines. Figure 3081 is a physical representation of a distributed parameter line, which is broken into many small R, L, and C components. If a sharply rising voltage wave is applied to one end of the line during a lightning stroke or a system switching event, the first capacitor becomes charged very quickly, but the first series inductance prevents the second capacitor from charging simultaneously with the first one. The surge progresses down the line in a fashion analogous to what happens when the end of a long rope is whipped and the loop travels to the other end.

FORMULAS FOR DETERMINING SURGE IMPEDANCE AND VELOCITY OF PROPAGATION

Two Waves: Voltage and Current Although a traveling wave is initiated by a sharp increase in voltage, a wave of current accompanies the voltage surge. It is of the same shape and is related to the voltage wave by the surge impedance (Zs).

I

=_y_ z~ fi

z2=

·fc

= =

where L inductance per-unit length C capacitance per-unit length The velocity (v) of the wave propagation is described by the equation:

v = 1/-YIC Figure 3181 shows the relationship of the propagating voltage {e) and current (i) waveforms. Waves are reflected at line or cable discontinuities and terminations, and the behavior of the reflected wave depends on the characteristic of the junction -that is, is it an open circuit or short circuit- and the surge impedance. A traveling wave will reflect differently if it encounters a transformer as opposed to a lightning arrester. Wave behavior at junctions will be discussed in more detail later.

Surge impedance and velocity of propagation are based on the distributed inductance and capacitance of the distribution line. The following formulas can be used to determine the impedance values of different kinds of conductors. Note that the discussion has been simplified to consider only the balanced line mode of propagation for multiphase lines.

Inductance

L = .7411 log10 {

~~~)

mh/mi (3-phase line)

L = .7411 log 10 {

G~R)

mhlmi (1-phase line)

L

= .7411 log 10

~

mh/mi (single-conductor cable)

where GMD = Geometric Mean Distance between conductors

=~ DabDbcDca

= =

=

GMR Self GMD Geometric Mean Radius of conductor h conductor height r = line conductor radius r1 = cable conductor radius r2 = inner radius of sheath Dab

=distance between phase a and phase b conductors

All parameters must be expressed in the same units.

189

B. Overvoltage Protection 1. FUNDAMENTALS AND THEORY Traveling Waves (Continued)

Capacitance C = .0388/log 10 {

~~~)

.74111og 10 ( 2~)=.74111og 10 2x3g;12

L= uf/mi (3-phase line)

= 2.636 mh/mi C = .0388/log10

{G~R)

C = .0388KIIog10

~

uf/mi (1-phase line)

=

C

uf/mi (single-conductor cable) Z8

.0388 = .0388 = .011 uflmi log 10 (2h/r) log 10 (2 x 30 x 12/.2)

= 1381og10 {

2 : ) = 1381og10 (2 x 30 x 12/.2)

where K = permittivity = 490 ohms

Surge Impedance Recall that surge impedance is expressed as Zs = VDC. If the equations for L and C above are substituted for the surge impedance, the following approximations for surge impedance are valid:

or

z8 =

'-' UC

3 ·636 x 10. ] =[ 2.011 X 1Q·6

1/2= 490 ohms

2

Zs = 1381og10 { rh ) ohms (overhead line) =

~ log10 { ~ )

v-

_1_ - - - - - ' - - - - -

- --J

UC ((2.636 X 10·3)(.011

X

10·6)] 1/2

ohms (cable) = 1.86 x 1os mi/sec = Speed of Light

Typical values for the surge impedance of overhead lines and cables are: Overhead lines, Zs = 500 ohms (typically 400 - 600 ohms) Cables, Zs =50 ohms (typically 20-60 ohms)

Velocity of Propagation As stated before, the velocity of wave propagation is: V= 1/'-1 LC

WAVE BEHAVIOR AT .JUNCTIONS Previously, it has been shown that a traveling wave of voltage has an associated traveling wave of current related to it by the surge impedance Zs. At junctions of distribution lines and at terminations with R, L, and C components, as well as at short or open circuits, this relationship must still hold valid. Wave behavior as related to these various line components and conditions are discussed below.

For open-wire lines, the resulting electromagnetic wave is propagating through air, and therefore travels close to the speed of light. Velocity in this case is independent of circuit configuration and can be approximated as: V = 3 x 1os m/sec = 1000 ft/J!Sec. The line merely serves as a wave guide. For cables, the electromagnetic wave is confined to travel through the dielectric medium, or insulation. The velocity therefore is dependent upon the L and C of the cable and can be approximated as: V = _1_ = 3 x 1os rn/sec = 1000 ftl!lsec. ~ ~ '-'LC

Application of Formulas Consider an overhead single-phase line located 30 feet above the ground; conductors are 2/0 copper with a radius of 0.2 in. Let us determine the surge impedance and the velocity of propagation.

A

Figure 3281. Wave behavior

at a junction of dissimilar lines.

At a .Junction of Dissimilar Lines To illustrate wave behavior at a junction of dissimilar lines. Figure 3281 shows an incident source wave of voltage traveling on a distribution line of surge impedance Z1, approaching a junction with a distribution line of surge impedance Z2. The reflected wave produced when the incident wave (V1) reaches point A is: V2= Z2-Z1 xV1 =aV1

h = conductor height = 30 ft = 12 x 30 in. r = conductor radius = 0.2 in.

z2 + z1

The refracted (continuing) wave is: Substituting into the formulas for L and C yields

190

81 v,

I.

At a Short Circuit

I

Using the previously mentioned formulas for reflection and refraction, waveform behavior at a short circuit, shown in Figure 3481, is:

I

•

z,

I

z1 = 0 for short circuit

Z2= %Z1

I v,

I

- r-~

v2

V3 (refracted)=~= 0 Z2+ z1

v3

+

v1

I

I

I

-tv2

I

...

I

SHORT CIRCUIT

I

7');

V3

I I

I

I

I Figure 3381. Pn:qession of voltage waveforms: incident (V1), reflected (V2), and refracted (V3).

... V2

Rgure 3381 shows the progression of voltage waveforms: n:ident (V1), reflected (Y2), and refracted (V3), when Z2 112 Z1. The following calculations relate to the figure:

LK

=

v2

=( z2- z1 )

v1

=( 1/2 z1- z1 )

Z2 + Z 1

Y1 -- ( --1/2 -z 1 ) 3/2

z1

112 Z 1 + Z 1

~

v1--1- v1 3

I

Figure 3481. Wave behavior at a short circuit.

In this case, a voltage wave of two-thirds the incident value continues on the distribution line with lower impedance, while ooe-third of the wave is reflected back toward the source, cancelling a like portion of the incident wave. The current waveforms at junctions of dissimilar lines have 1he same relationships:

It is impossible to develop a voltage across the short circuit. Therefore, when a traveling wave of voltage reaches the short circuit, the voltage reflects in a negative direction, cancelling the incident voltage wave. The reflected current wave augments the incident current wave, doubling the cu rrent in the line.

11 = V 1 (incident) z1 12 = - V2 (reflected) z1 13 = Vs (refracted) z2

191

B. Overvoltage Protection 1. FUNDAMENTALS AND THEORY Traveling Waves (Continued)

At an Open Circuit The current must be zero at all times at an open end of a distribution line. For determining wave behavior at an open circuit, use the previous formula, with Z2 ==.Thus, V2 = V1 and V3 = 2V1. A current of the same magnitude but opposite polarity is initiated to cancel the incident current wave. Figure 3581 shows the behavior of a square wave at an open circuit. In this case, the voltage wave "doubles" at the open point. A more realistic picture of the behavior of traveling waves at an open point is illustrated in Figure 3681. The incident wave is shown as a series of blocks approximating the voltage waves encountered on distribution systems.

I

.............

~

~

v,

~

TIME

-

I

t=O

Vr._

c-

I Uv,

r

Vz-.

-..--

Vr-

j

t=

2~t

_.--

I OPEN CIRCUIT v,

I

..

I I

' I I

~

v,

I

Vz~

V, : INCIDENT WAVE

2:

V REFLECTED WAVE

,._ r-

Vr

Vr:TOTALOF REFLECTED AND INCIDENTWAVES ~t:

_____.__,!_:__

t= 3~1 -

__....

r

:--

I

-v,

FINITE TIME INTERVAL

~.a

I

LJ

JV2 .--

~.J

I=

4~t

t=

7~1

I I

1"""--

J

-- --Vr~

Vz....,

v1 ____,..,

Vz-

-· ~.J

r--• ~.J

v,_

~

-

~---- r--Vr--

I

v,_ ~

t=9~t

Figure 3581. Behavior of a square wave at an open circuit. ~

~

-~

..... - Vz

~

~

t=

11 ~ t

Figure 3681. "More realistic" picture of traveling waves at an open point.

192

81 At Capacitive and Inductive Terminations figure 3781 shows the behavior of the first reflection on the R:ident wave at a capacitive termination. Because the voltage across the capacitor cannot be changed instantaneously, the dage is initially zero and then builds exponentially to twice lie incident wave. The reflected wave, V2, is shown in a dashed line, and the resultant voltage in a solid line. Thus, the capacitor initially appears to be a short circuit and then appears as an open circuit when fully charged. Sometimes the reflected wave will reflect back from another capacitor and, being reversed in a positive wave, will produce an additional "blip" in the voltage waveform, producing a peak woltage that actually exceeds twice the incident wave.,

I I - - - H..~v,

I

As might be expected, an inductive tennination acts ~ sitely to a capacitive termination. It first appears as an open circuit (zero current) to the incident wave and then changes in an exponential fashion to appear shorted. FI!Jlre 3881 illustrates the effect, with the reflected wave in550 kV) 15 kA (550 kV) 20 kA (800 kV) Transmission-Line Discharge Test Required

16.1 kA 400-600 A

40-65 kA 400-600 A

H.D. = Heavy Duty

207

B. Overvoltage Protection 2. INSULATION AND SURGE ARRESTER CHARACTERISTICS AND GENERAL APPLICATION FACTORS Surge Arresters (Continued)

Figure 1282. Distribution-class surge arresters.

Figure 1482. Station-class surge arresters.

GENERAL ARRESTER APPLICATION FACTORS As previously stated, a surge arrester must be able to withstand the continuous power-frequency voltage, discharge any transient energy that occurs, and operate in the same environment as the protected equipment. Some of the factors involved in satisfying these requirements are discussed below.

Figure 1382. Intermediate-class surge arresters.

208

Selection of Voltage Rating When applying an arrester, the voltage rating is compared to the maximum expected phase-to-ground voltage against which the arrester will be required to operate. In most cases, this is considered to be a single line-to-ground fault condition where the arrester on an unfaulted phase may have to operate at an elevated voltage. Depending on the type of system connection, the voltage on an unfaulted phase can vary, as explained in Section B3, which covers arrester application in more detail. Once this number is available, the arrester rating for the particular application can be selected. ANSI Application Guide C62-11 states that the voltage rating of an arrester should always be equal to or greater than the maximum expected power-frequency voltage on a given system. Commonly used ratings of arresters for various system conditions are summarized in Table 1B3 in Section B3.

82 MAXIMUM CONTINUOUS OPERATING VOLTAGE MCOV MOV arresters are given a maximum continuous operating ~Hage (MCOV) rating indicating the voltage at which they can be energized continuously over their lifetime. Once the 'lOrmal system line-to-ground voltage has been calculated, lhe MCOV of a metal-oxide arrester can be selected as being equal to or greater than this voltage. This is the continuous line-to-ground voltage plus any overI!Oitage factor and can be calculated as follows:

1.8 1.7

r--,. 1.ja

l l'f. r--.1 .69

1.6

II II

~.68

.60

......

1.59

N..J 1.50

1.51

li-

II

NCll'iMAL DUTY rl. NSI AND HEAVY DUTY (UHS)

'i-ll

~If

~~":~ Vmax = VLL {3

X

I

I

1~

1.34

i"

~~·

1.05

1.

1.2

Where VLL =nominal system voltage, line-line 1.05 == typical maximum continuous operating voltage factor TABLE 782 Protective Characteristics - VariSTAR Heavy Duty Riser Pole (URS)

l

II 1.42

Arrester Rating (kV rms)

3 6 9 10 12 15 18 21 24 27 30

33 36

MCOV (kV rms)

2.55 5.10 7. 65 8.40 10.2 12.7 15.3 17.0 19.5 22.0 24.4 27.0 29.0

TEMPORARY OVER VOLTAGE The next consideration in selecting an MOV arrester is the possible duration of a temporary overvoltage, such as a fault condition. There is concern about the continuous heating of lhe MOV arrester, which may in time affect its efficiency. There are, therefore, temporary overvoltage curves published br MOV arresters (Figure 1582). These curves show the maxinurn overvoltage and the length of time it can be withstood b" an MOV arrester. Provided the overvoltage condition is cleared within the limits of the curve, the MOV arrester is applied properly.

1.1

001

0.1

10

100

1000

1000~

0

Time Dura1ion in Seconds

Figure 1582. Temporary overvoltage curve. No prior duty- 60° C ambient.

A metal-oxide surge arrester will operate successfully and maintain its protective characteristics provided it is not required to dissipate more energy than it can tolerate. Thus, an MOV arrester can operate at voltages above its conduction level for durations dictated by the energy it must dissipate. When the overvoltage is reduced to the arrester's maximum MCOV rating before its energy dissipation capability is reached, the arrester will maintain its protective characteristics and will not fail. MARGINS OF PROTECTION After it has been determined that an arrester can survive on the system, its ability to protect a given piece of equipment can be examined. This is done by comparing the protective characteristics of the arrester to the insulation level (Btl) of a given piece of equipment. The procedure for establishing margins of protection is discussed in more detail in Section 83, under "Insulation Coordination."

209

210

82 Shield Wires As stated in Section 81, the overhead shield wires normally employed on transmission and subtransmission lines can be effective in reducing outages due to lightning. Although shield wires are not very common on distribution systems, the higher lle system voltage, the greater the possibility that they will be used. Even with shield wires, however, it is still necessary to nstall surge arresters to protect equipment on a distribution system, as the ability of the shield wire to reduce the number of direct strokes to the phase conductors does not prevent wltages greater than the equipment BIL from appearing on lhe circuit.

When a shield wire is applied on a distribution circuit, the usual practice is to install the common neutral in the shield wire position , above the phase conductors. An alternative to use of a shield wire on urban-type circuits is to raise the middle phase conductor to provide shielding to the other phases, and increase the number of arresters on the middle phase to help compensate for its increased susceptibility to lightning strokes (Reference 7).

211

B. Overvoltage Protection

2. INSULATION AND SURGE ARRESTER CHARACTERISTICS AND GENERAL APPLICATION FACTORS

Index of Figures and Tables FIGURE

Page Overhead Distribution Line Insulation

182 282 382 482 582 682 782 882 982

Volt-time curve for determining impulse-voltage withstand levels .......................................198 Standard 1.2 x 50-microsecond test wave .........................................................199 Negative impulse flashover of wet wooden crossarms ...............................................200 Diagram of insulation with wood in series with porcelain ..............................................200 Impulse withstand values of wood-porcelain combination for different lengths of wood ......................200 Pole-top structure with two post-type insulators on wood .............................................200 Diagram of pole-top structure for use in example of insulation withstand calculation ........................201 Calculated probability of lightning flashover with power arc ............................................202 Minimum lengths of wood required to prevent follow current ...........................................202

1082 1182 1282 1382 1482 1582

Cutaway illustration of UltraSIL Housed VariSTAR Distribution Arrester ..................................206 Cutaway illustration of UltraSIL Housed VariGAP Distribution Arrester ...................................207 Distribution-class surge arrester .................................................................208 Intermediate-class surge arresters ...............................................................208 Station-class surge arresters ...................................................................208 Temporary overvoltage curve. No prior duty- 60° C ambient. .........................................209

Surge Arresters

TABLE Overhead Distribution Line Insulation 182 282 382

Typical critical impulse flashover levels (CFO) for pin-type insulators ....................................199 Typical critical impulse flashover levels (CFO) for post-type insulators ................................... 199 Negative impulse sparkover levels for air gaps between conductors and for rod gaps ....................... 199

482 582

Distribution transformer withstand levels ..........................................................204 Recloser withstand levels ......................................................................204

682 782

Comparison of standard requirements for surge arrester classifications ..................................208 Protective characteristics- VariSTAR heavy duty riser pole (URS) ......................................209

Distribution Equipment Insulation

Surge Arresters

212

Section B OVERVOLTAGE PROTECTION

3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS An Introduction Whereas the equivalent section on overcurrent protection deals with a variety of tools, the following discussion of overvoltage protection applications focuses primarily on one type of device: surge arresters. The "other protection details" mentioned in the title include the use of shield wires under some circumstances. System conditions conducive to surges that might require corrective measures other than arresters also are listed, but these are discussed in more detail in Section 81. Presented first are factors involved in the selection of arresters based on system conditions, followed by discussions of the location of arresters in relation to the equipment they protect, and of the proper connections for optimum protection. Attention then turns to determining margins of protection,

which is accomplished by coordinating arrester protective characterisics with the insulating capabilities (BIL) of equipment. The final application details covered relate to specific areas of distribution-system overvoltage protection: overhead lines, underground circuits, distribution apparatus, and substations. These areas are not necessarily mutually exclusive in overvoltage protection schemes, but each involves special considerations in the application of arresters. Historically, the emphasis in overvoltage protection has been on protecting equipment from surges, with line protection receiving only incidental attention. Growing concerns about reliability in recent years, however, have prompted many utilities to broaden their approach to overvoltage protection.

Table of Contents, Page 169 Index of Figures and Tables, Page 235

213

B. Overvoltage Protection 3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS

Arrester Function and Selection As discussed previously, surge arresters are applied to distribution systems to limit high transient overvoltages to safe values. The vast majority are applied directly to distribution feeders, with a much smaller percentage being applied in substations. In limiting the transient overvoltages on distribution systems, arresters perform two major functions: protecting equipment from failure and minimizing system power interruptions. These two functions relate, respectively, to the characteristics and principal applications of nonselfrestoring and self-restoring insulation, which are discussed in detail in Section B2. Briefly, nonself-restoring insulation, which includes kraft paper and oil and constitutes most of the insulation used in transformers, reclosers, capacitors, and other distribution equipment, exhibits permanent damage and must be repaired or replaced if a dielectric breakdown occurs within the equipment. In contrast, the insulating properties of self-restoring insulation, which includes air plus porcelain and other materials used primarily in line insulators and equipment bushings, are completely restored if the disruptive discharge (flashover) is extinguished quickly enough. Such flashovers therefore usually result in a temporary power interruption rather than an equipment failure. It should be noted, however, that flashovers can lead to permanent damage if they persist for too long a period. The proper use of arresters based on system conditions and coordinated with equipment insulation levels can help to minimize equipment failures and system interruptions due to transient overvoltage conditions. Arrester selection, the first step in accomplishing this goal, will be discussed immediately below, followed by recommendations for arrester location and connection, and the specifics of particular applications. There are three considerations involved in arrester selection: arrester voltage rating, insulation coordination. and arrester class.

ARRESTER VOLTAGE RATING The voltage rating of surge arresters is defined as the highest power-frequency voltage at which the arrester is designed to operate. (ANSI standards define an operating duty-cycle test at this voltage for each class of arrester.) The rating is based not only on the system operating voltage but also must take into account possible 60 Hz overvoltage conditions, especially those due to system faults, and the characteristics of the particular distribution system (new or established, urban or rural, etc.). System Operating Voltages Preferred nominal system voltage classifications have been defined in ANSI Standard Voltage Ratings for Electric Power Systems and Equipment (60 Hz), C84.1. The standard recognizes that no system can operate at its nominal voltage at all times over its entire length, as system regulation will cause the voltage to vary above and below the nominal value. Figure 1B3 illustrates the distribution characteristics of system voltage into which the total range of corresponding operating voltages of the industry may be divided. This figure takes into account the natural variation between different systems for any specific nominal voltage.

214

~

I re.

(/')

~~

I.

VOLTAGE RANGE B IIOLTAGE RANGE A

~

I

I

g.... I. '

~ I 0..

•

VOLTAGE

Figure 183. Distribution characteristics of system voltage. All equipment on a power system can operate over a narrow range of voltages (voltage range A) and still give excellent performance. Most electrical equipment can operate continuously at voltages either above or below nominal (voltage range B), but the performance of equipment at the high and low extremes of the voltage range may not be optimum. Since maximum voltages are of primary concern in arrester application, the maximum voltage on a system should be known to achieve precise selection of arrester ratings. If no information is available on the maximum system operating voltage, then the maximum range B voltage given in ANSI standards must be assumed. Care must be taken to avoid possible arrester misapplication when maximum system voltages listed in ANSI standards are assumed for certain distribution systems. In some voltage classes, transformers are equipped with taps above rated voltage that permit operation of the system at voltages above range B maximums. On such systems, higher-rated arresters than those normally used may be desirable.

System Faults and Other Unusual Operating Conditions In most cases, consideration of only those overvoltages resulting from system faults is sufficient when applying arresters, and only the effects of system faults will be dealt with in detail here. However, high overvoltages can occur on some systems as a result of the following unusual operating conditions: 1. Generator overspeed following load rejection. 2. Changes in system grounding conditions due to switching. 3. Coupling from high-voltage parallel lines. 4. Contact with high-voltage circuits. 5. Ferroresonance and other single phasing effects.

83 Corrective action {not involving arresters) obviously must be taken if any of the conditions described occur or seem likely to occur. Note that ferroresonance is discussed in Section 81 under "Overvoltages of System Origin." System faults, which must be considered when applying arresters, can cause temporary 60 Hz overvoltages until the fault is cleared. The arrester must be able to withstand these overvoltages, which are a function of the system grounding method. EFFECT OF SYSTEM GROUNDING DURING LINE-TOGROUND FAULTS A theoretical circuit with zero ground impedance, shown in Figure 283, illustrates neutral shift on wye-connected systems. A fault on phase A causes the voltage to collapse completely {Figure 283[C]). Since there is no impedance between the fault and the transformer neutral, phase A and the neutral remain at ground potential. The voltages from phase-toground of phase 8 and C remain unchanged from the normal operating condition. The practical system shown in Figure 383 illustrates neutral shift on wye-connected systems with ground impedance. Since resistance will always be in the ground between the fault and the transformer, this example more accurately

depicts actual situations. The neutral impedance may be Otjy the resistance of ground, or an intentional resistance or reactance placed into the transformer neutral to limit fau QJirenL As shown in Figure 383{C), a line-to-ground fault on phase A causes the neutral of the transformer bank to shift ~ from ground because of the voltage drop in the neutral resistance. Note that the voltages from phase 8 and C to ground are now higher than during normal system operation. The condition of neutral shift in ungrounded systems is illustrated in Figure 483. An assumption is made that the capacitance between lines and from line to ground is balanced, which makes the neutral coincide with ground {F~gure 4B3{BD. In addition to the line-to-ground faults illustrated, other fault conditions affect the selection of arrester ratings. For exaJ11)1e, double line-to-ground faults can result in high voltages from the unfaulted phase to ground. Phase-to-phase and threephase faults generally do not cause the highest overvoHages from phase-to-ground. When the system sequence impedances are known, these overvoltages can be calculated.

FAULT

A

c

B

B

B

C

~ A . N& G

SUBSTATION

A

G

(A) SYSTEM

(B) NORMAL VOLTAGES

(C) FAULT VOLTAGES

Figure 283. Line-to-ground voltages on theoretical wye system with no ground resistance.

FAULT

A

c

B

B

B

C

~ A&G

SUBSTATION

A

G

(A) SYSTEM

(B) NORMAL VOLTAGES

(C) FAUIJ ~I..TAGES

Figure 383. Line-to-ground voltages on wye system with ground resistance.

215

B. Overvoltage Protection 3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS Arrester Function and Selection (Continued)

FAULT

A

c

B

B

SUBSTATION A

A&G

(B) NORMAL VOLTAGES

(C) FAULT VOLTAGES

c (A) SYSTEM

Figure 483. Line-to-ground voltages on ungrounded system.

COEFFICIENT OF GROUNDING AND PERCENT ARRESTER Coefficient of grounding and percent arrester are two terms used to define the arrester ratings required for fault conditions. Coefficient of grounding can be defined as the ratio of the maximum line-to-ground voltage at the arrester location, during faults anywhere on the system, to the phase-to-phase voltage without a fault. The coefficient of grounding of a system, multiplied by the phase-to-phase voltage, equals the minimum surge-arrester rating suitable for that system. Percent arrester is the ratio of an arrester rating to the system phaseto-phase voltage expressed as a percentage.

Distribution Circuit Considerations Over years of application, the vast majority of distribution arresters have been selected on the basis of experience a method that has been entirely satisfactory for well-established circuit voltages and grounding conditions. The selection of arresters for new types of systems, however, must be based on extrapolation from existing experience and the calculation of overvoltages during fault conditions. Urban distribution circuits have a large number of low-resistance grounds on the system neutral, which results in the best possible neutral stability during faults. Therefore, urban-applied arrester ratings in percent-of-system voltages are the lowest of any circuit. Rural distribution circuits, when compared to urban circuits, have a smaller number of grounds, with resulting higher neutralto-ground resistance. Rural circuits therefore are subject to a greater neutral shift during faults and require higher percentage arresters. Also, high-voltage distribution circuits generally are employed in sparsely populated rural areas, and these circuits tend to have even fewer grounds, and thus greater neutral shift, than the lower-voltage circuits used in more densely populated rural areas.

216

CONDITIONS REQUIRING ARRESTER SELECTION BY CALCULATION The use of neutral impedances on four-wire, multigroundedneutral circuits is becoming more common. A few utilities have resorted to neutral impedances on their distribution circuits in order to confine fault currents within the rating of available fuses and reclosers. However, neutral impedances introduce numerous problems in the selection of arrester ratings, and the application of arresters on such systems on the basis of experience is extremely hazardous because of the wide range of neutral impedances that could be used. The only satisfactory method of arrester selection in these circumstances is by calculating line-to-ground voltages under fault conditions. Only the selection of arrester ratings as affected by system line-to-ground voltages during faults has been discussed. Equally important is the probability of faults occurring on the circuit. If no arrester operations occur during faults, then the phase-to-ground voltages during faults need not be consid· ered. The following factors affect fault probability: 1. Phase spacing, pole-top clearances, and line insulation level. 2. Tree trimming. 3. Shielding of the line by surrounding objects. 4. Frequency and intensity of lightning storms. 5. Line maintenance. 6. Atmospheric contamination. Calculations of arrester rating for distribution circuits differ from calculations used when dealing with transmission circuits. Experience indicates that when arrester ratings are based on Ro1X1 and Xo1X1 ratios for distribution circuits (NEMA UB LA-1), they are higher than needed. Investigation reveals that line resistance tends to limit overvoltages, and the positivesequence resistance, R1, must also be included in the determination of the overvoltages.

83 Arrester Voltage Rating Recommendations Table 183 provides a general application guide for the selection of the proper arrester rating for a given system voltage. These recommendations, are determined as follows: • .1.25 x nominal line-to-ground voltage for four-wire, multigrounded-neutral systems. • .0.80 x nominal line-to-line voltage for three-wire, solidly grounded neutral systems. • Nominal line-to-line voltage for delta and ungrounded-wye systems. Although these recommendations are generally applicable, calculations should be made to insure that the parameters of a particular system under consideration are taken into account. This is especially true when substation transformers are grounded through an impedance or when spacer cable construction is used.

INSULATION COORDINATION Insulation coordination is the process of comparing the impulse withstand strength of insulation with the voltag'e that can occur across the arrester. This of course is an important step in determining the adequacy of insulation, the extent of additional overvoltage protection that may be required, and ultimately the margin of protection. As stated previously, self-restoring insulation, related primari'ly to line components and equipment bushings, will flash over at critical voltages and be restored to its full insulating capability if the discharge has not persisted, whereas the nonsetfrestoring insulation used in distribution equipment can be permanently damaged by excessive voltages, necessitating repair or replacement. Arrester application for the purpose of limiting line flashovers is largely a matter of matching arresters with system characteristics, as discussed above, and the individual utility's approach to overhead protection. The following discussion on insulation coordination, therefore, focuses on the establishment of overvoltage protection margins for distribution equipment.

TABLE 183 Commonly Applied Surge Arrester Ratings Recommended Arrester Rating per IEEE C62.22 (kV rms)

System Voltage (kV rms) Nominal

Maximum

2.4 4.16Y/2.4 4.16 4.8 6.9 8.32Y/4.8 12.0Y/6.93 12.47Y/7.2 13.2Y/7.62 13.8Y/7.97 13.8 20.78Y/12.0 22.86Y/13.2 23 24.94Y/14.4 27.6Y/15.93 34.5Y/19.92 46Y/26.6

2.54 4.4Y/2.54 4.4 5.08 7.26 8.8Y/5.08 12.7Y/7.33 13.2Y/7.62 13.97Y/8.07 14.52Y/8.38 14.52 22Y/12.7 24.2Y/13.87 24.34 26.4Y/15.24 29.3Y/16.89 36.5Y/21.08 48.3Y/28

Four-Wire Wye Multi-Grounded Neutral -

Three-Wire Wye Solidly Grounded Neutral

Delta and Ungrounded Wye 3 6 6 6 9

-

6

3 -

-

-

-

-

-

6 9 9 10 10

9 12 15 15 15

-

15 18 18 21 27 36

-

-

-

18

21 24

-

-

30

27 30 36

-

-

-

217

B. Overvoltage Protection 3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS Arrester Function and Selection (Continued)

Equipment Withstand Recalling Section 82, in which insulation characteristics, impulse withstand tests, etc., are covered in detail, note that the 1.2 x 50 impulse voltages that insulation must withstand are classified into discrete values called Basic Impulse Insulation Levels, abbreviated BIL. One or more BIL levels may be used at a given circuit voltage. As also discussed previously, two additional impulse withstand tests that are sometimes applied are the chopped-wave and front-of-wave tests. These tests simulate the conditions that can occur when a line is flashed over by a lightning stroke. There also are standards for switching-impulse tests, which may be applied to substation equipment but are not generally applicable to distribution systems. Most distribution equipment

does, however, undergo low-frequency tests to confirm its ability to withstand 60 Hz voltages greater than the maximum rated operating voltage. For a summary of typical BIL values and related low-frequency withstand voltages for distribution transformers and reclosers, refer to Tables 482 and 582 in Section 82. In Rgure 583, the complete volt-time withstand characteristics of a transformer are plotted and compared with the discharge voltage characteristics of an arrester. The recommended margin of protection - discussed in more detail below - is indicated at three points: {MP1) the chopped-wave test level, {MP2) the BIL range, and {MP3) the switching-surge range.

CHOPPED WAVE WITHSTAND (CWW)

I

BIL RANGE (BILl \ BIL FRONT OF WAVE PROTECTIVE LEVEL (FOW)

SWITCHING SURGE RANGE (BSL) _I (TRANSF.)

--'-++1-MP2=-LPL -1

BSL MP3= SPL -1

---+--11:...----+-T- (ARRESTER)

I

SWITCHING IMPULSE PROTECTIVE LEVEL

I

(SPL)

LIGHTNING IMPULSE CLASSIFYING CURRENT (LPL)

Figure 583. Insulation coordination: equipment withstand voltage compared with surge arrester protective characteristics.

218

83 COMPARISON OF OIL-FILLED AND DRY-TYPE EQUIPMENT All apparatus that does not have an insulating liquid as part of the insulating structure can be considered dry-type equipment. Transformers of the lower voltage ratings, all rotating machines, and metalclad switchgear are examples. The insulation strength of dry-type equipment, unlike that of oil-filled equipment, does not increase significantly as the duration of the applied impulse voltage decreases. For the purpose of insulation coordination, therefore, the insulation strength of the equipment is considered to be equal to the 81L for all impulse voltage waves. The arrester discharge voltage is compared directly to the 81L of the equipment. It is generally not practical to build dry-type equipment to have the same 81L as oil-filled equipment for the same system operating voltage. Thus, the problem of insulation coordination for dry-type equipment is more difficult than for oil-filled equipment. Special arresters are available for protecting such equipment from overvoltages. It also often is desirable to shield circuits to which dry-type equipment is connected from direct lightning strokes.

Margin of Protection The difference between arrester discharge characteristics and equipment withstand level at any given instant of time is termed the margin of protection, represented by the expression: MP =

Withstand Voltage Arrester Discharge Voltage

_1

The margins of protection are calculated as per Table 283. In performing such calculations for exercise purposes, the summary of typical 81L values for transformers and reclosers listed in Tables 482 and 582 may be used. (81L and choppedwave withstand values for specific equipment are available from manufacturers.) The arrester protective characteristics called for in the calculations are listed in Table 383.

TABLE 2B3 Bases for Calculating Protection Margins Provided by MOV Arresters

MP3=

Metal-Oxide-Varistor Arresters Chopped Wave Withstand Equivalent Front-of-Wave Protection Level Equipment BIL Arrester Discharge Voltage .83 x Transformer BIL Equivalent Switching Protection Level

-1 -1 -1

219

B. Overvol 3.SURGE

Protection ESTER APPLICATIONS AND OTHER PROTECTION DETAILS

Arrester Function and Selection (Continued)

TABLE 383

........,,.,... ~

Protective Characteristics of Metal-Oxide-Varistor Arresterst Arrester Rating (kV rms) 3 6 9

10 12 15 18 21 24 27 30 33 36

MCOV (kV rms) 2.55 5.10 7.65 8.40 10.2 12.7 15.3 17.0 19.5 22.0 24.4 27.0 29.0

Protective Level* (kV crest) 11.5 23.0 33.1 34.4 43.3 54.1 64.9 68.9 80.3 90.9 101 113 121

8.60 17.2 24.8 25.8 32.4 40.4 48.5 51.5 60.1 68.0 75.8 84.2 90.8

Maximum Discharge Vol~e (kV crest) 8/20 IJS Current ave 3 kA

5kA

10 kA

20 k

40kA

9.10 18.2 26.3 27.4 34.4 43.0 51.6 54.7 63.9 72.3 80.5 89.5 96.5

9.50 19.1 27.5 28.6 35.9 44.9 53.9 57.2 66.7 75.5 84.1 93.5 101

10.4 20.8 30.0 31.2 39.2 49.0 58.8 62.4 72.8 82.4 91.8 102 110

11.5 23.0 33.2 34.5 43.3 54.2 65.0 69.0 80.5 91.1 101 113 122

13.0 25.9 37.4 38.9 48.8 61.0 73.2 77.7 90.7 103 114 127 137

I

*Based on 10 kA current impulse that results in a discharge voltage cresting in 0.5 IJS.

Minimum margins of protection recommended by ANSI Application Guide C62.22-1981 are: MP1 (Chopped-Waved Test Level): 20% MP2 (BIL Range): 20% MPs (Switching Surge Range): 15% These minimum margins include a safety factor to account for various unknowns such as errors in estimating maximum surge current, separation of transformer and equipment, and voltage withstand reduction caused by deterioration of old equipment. Within the indicated parameters, the specific margin of protection is not of significant concern when comparing protection offered by two arresters with adjacent ratings produced by the same manufacturer, for the lower rating will always yield the greater margin of protection. The specific margin of protection is of significant concern, however, when

220

comparing arresters of the same rating produced by different manufacturers or when comparing different types of arresters.

ARRESTER CLASS The majority of arresters applied on distribution systems are distribution class. This is particularly true at 15 kV and below, since the protection levels are more than adequate. However, in cases where arresters are to be located at riser poles to protect cable-connected equipment or in substations to protect larger equipment, intermediate- or even station-class arresters are used to provide even better protective characteristics. Applications requiring pressure-relief capability also will often necessitate the use of intermediate or station arresters, depending on the available fault current.

83 Arrester Location and Connection Location is a critical application factor because excessive lead length to the feeder line and to ground, and too much separation between the arrester and protected equipment, can reduce arrester effectiveness. Une, ground, and feeder leads offer high impedance paths to lightning surge current. During lightning surge discharge, these paths can develop voltages that place an additional stress on the insulation of protected equipment. Voltage developed across the leads will add to the arrester discharge voltage, so that the effect of voltage across long leads can be to nullify completely the protective characteristics of the arrester. Short leads are recommended for all arrester applications.

EFFECT OF ARRESTER LEAD LENGTHS As stated previously, short leads are recommended for all arrester applications. Figures 683 and 783 illustrate the pon that considerable distance between an arrester and protecled equipment can nullify the protection offered by the arrester. Figure 683 shows an arrester connected to the line at a distance S from the transformer it is supposed to protect.

..

r---s--~

ESTIMATING LEAD·WIRE VOLTAGE The total discharge voltage entering protected equipment will be the sum of the arrester discharge voltage and the voltage drop that occurs in the lead wires connecting the arrester between line and ground i.e., arrester IR + the lead-wire L di/dt drop, which is referred to as the IX drop. 2000 V/ft is commonly assumed for estimating purposes for lead-wire voltages. This is a good rule-of-thumb value for lightning currents below 20 kA, but recent studies have shown that voltages as high as 10 kV1ft is not uncommon. Futther analysis is provided in the Cooper Power Systems Optimizer software program. Lead-wire voltage is a nonlinear function of these parameters because of the different phase relationship between time of arrester discharge and voltage crest, and time of lead-wire IX voltage crest. Of real significance is the lead-wire voltage produced by highmagnitude, rapidly rising lightning currents. Although currents of this magnitude (65 kA) have a low probability of occurrence, they do occur. More realistically, lightning current of 10 kA to 20 kA have been shown to occur with rates of rise much less than four microseconds.

ARRESTER

TRANSFORMER

Figure 683. Surge arrester separated from transformer by length of conductor.

MICROSECONDS

Figure 783. Voltages occurrin~ on circuit ·Of Figure 683 as result of lightning-stroke discharge by arrester.

221

B. Overvoltage Protection 3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS Arrester Location and Connection (Continued)

As a lightning-generated surge propagating on the line encounters the surge arrester, the voltage is clamped. However, the voltage wave prior to clamping continues on to the transformer, where it can be reflected positively if the transformer is at line voltage, resulting in a higher voltage at the transformer. In practice, voltage waveforms such as shown in Figure 783 are typical. The overshoot of the transformer voltage, Et, is understandable in terms of inductances and capacitances, as follows. The lightning-stroke current is discharged through the arrester, yielding a discharge voltage, Ea, which is impre~ on the line separating the arrester and transformer. The hne exhibits an inductance to surges of approximately 0.4 microhenries per foot. Initially, the transformer appears capacitive and the voltage builds at a slower rate than the arrester discharge. The current charging the transformer capacitance is limited bythe line inductance. Finally, as the voltage across the transformer approaches the peak value of the arrester voltage, substantial surge current is flowing in the line inductance. It continues to flow for a short time after the transformer voltage has surpassed the arrester voltage until all the energy stored in the line inductance is transferred to the winding capacitance of the transformer or is dissipated to losses. This causes the voltage overshoot depicted in Figure 783. The amount of overshoot depends on the rate of rise of the arrester discharge voltage, the length of conductor, and the transformer construction . The higher the rate of rise and the

222

longer the conductor, the greater will be the overshoot. If we consider that the arrester discharge voltage may also be increased by the length of the arresters lead to ground, then the importance of keeping the distance between the arrester and the protected equipment as short as possible becomes even clearer.

OTHER LOCATION/CONNECTION CONSIDERATIONS The arrester and the protected equipment should also have a common interconnecting ground. That is, the ground lead of the arrester should be bonded to the ground lead of the equipment at a common point close to both devices. This eliminates extra voltage stress that might be impressed by the drop across ground impedance. Other arrester location issues are addressed in the following sections. Of particular interest are the location of arresters on underground distribution circuits and the location of arresters with respect to transformer fuses. It should be noted that most distribution-class arresters are equipped with isolators at their bottom terminals. The isolator helps to remove the arrester from the circuit should the arrester fail. (A backup overcurrent device, a fuse or recloser, actually clears the fault current.) It is important to make the ground connection such that the isolator can operate and move an adequate distance away from the failed arrester.

83 Overhead Line Protection Historically, the equipment on distribution lines was protected from high transient voltages by surge arresters, while the !lnes themselves were allowed to flash over. If a fault developed, reclosing operations of the recloser or circuit breaker restored service after a momentary outage. However, reliability has become a very important factor as more and more loads- such as computers, video equipment, and other electronic devices -are highly sensitive to momentary interruptions. And so it is more important than ever to take steps to minimize the number of line flashovers and thus the number of momentary interruptions. The protection of overhead lines from lightning-initiated overvoltages can be achieved by the use of overhead shield wires, or by placing arresters at selected intervals on the top

phase only or on all three phases. Although the primary purpose is to minimize the number of line interruptions that result from lightning strokes, the arresters will also protect, of course, against other possible disturbances. It has been shown that the most effective method is to apply arresters on all three phases. This is especially effective for spacings of approximately every 1200 feet. A review of the characteristics of distribution line insulation discussed in Section 82 will be helpful; included are tables summarizing the critical flashover levels of insulators and the sparkover levels of air and rod gaps. Also, References 811 and 812 for overvoltage protection {listing at end of manual) contain more details on overhead line protection.

223

B. Overvoltage Protection 3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS

Underground Circuit Protection The major problem associated with the protection of underground distribution (UD) circuits is the practical difficulty involved in locating surge arresters as close as desired to the equipment being protected. In underground applications, the equipment typically is located in small enclosed spaces with dead-front connections, and so there are far fewer convenient places to connect arresters than there are for pole-top or substation equipment. Feed-thru loadbreak inserts are available to acommodate dead-front arrester installation at the end-points and mid-points of an existing UD circuit. The equipment involved is the same as in overhead applications - e.g., transformers, switchgear, and capacitors - but also includes the cable itself. The cable has developed into more of an issue in recent years as it has become apparent that cable life in many applications is not what it was expected to be. Insulation degradation as a result of treeing (limb-like cracks) in the insulating jacket, coupled with high system transient voltages, is believed to have contributed to shorter cable life.

RECOMMENDED PROTECTION METHODS A typical underground system is illustrated in Figure 883. At a riser pole, the overhead line descends into a cable that goes underground to serve the customers on the UD circuit. The major consideration is to protect equipment on the UD circuit from transient overvoltages initiated on the overhead circuit, especially those due to lightning. There are five generally accepted ways to accomplish this:

1. The most basic method (Figure 983) is to place an arrester at the riser pole to limit the magnitude of the surge entering the cable system. This is the primary arrester required for UD circuit protection. If protection dollars are limited, the installation of an appropriate arrester at this location may provide adequate protective margins for 15 kV or lower-voltage systems. 2. The highest transient voltages will tend to be at the openended points on the cable. This occurs because of the phenomenon of voltage doubling of a traveling wave at an open point (see "Traveling Waves" in Section 81).1n cases where the margin of protection may not be adequate, the next step is to place arresters at these open-ended points (Figure 1083). The voltage at the open end can reach two times the protective level of the riser pole arrester for a lightning surge on the overhead line, but that value will be reduced if there are cable taps in between. The voltage at the open end is compared with the 81L or chopped-wave withstand of the equipment to determine if the protection is adequate. As the operating voltage increases above 15 kV, equipment insulation levels do not increase at the same rate. For 25 kV systems with 125 kV 81L using 18 kV arresters, and for 35 kV systems with 150 or 125 kV 81L using 27 kV arresters, it generally is necessary to provide more than riser pole protection, such as by adding arresters at the open-ended points.

OVERHEAD LINE

/\-

m.·--

UNDERGROUND CABLE

-

-~ ~--- ~ ~

T

T

Figure 883. Underground distribution cable system. OVERHEAD LINE

/\-

T Figure 983. UD circuit protection with arrester at riser pole. 224

T

---- -_-_-_-I-_-_-_-_-_-_-_-1~

T

T

83 OVERHEAD LINE

/\-

T

T

Figure 1083. UD circuit protection with arresters at riser pole and open end. OVERHEAD LINE

/\-

T

T

Figure 11 83. UD circuit with scout protection scheme.

3. One alternative to placing arresters at the open-ended points when more than riser pole protection is required is to parallel two arresters at the riser pole. In this case the arresters share the surge current and consequently reduce the magnitude of the voltage entering the cable. It is, of course, important that the arresters have nearly matched characteristics so that they will share the current appropriately.

4. Another alternative is the use of the "scout scheme", which involves the use of one arrester on either side of the riser pole arrester a span away on the overhead line (Figure 11 83).

The arrester remote from the riser pole intercepts the propagating traveling voltage wave, operates, and drains most of the surge current to ground. If the discharge voltage is high enough, the riser pole arrester will also operate, thus draining off more of the surge current. A remote possibility exists that a stroke may terminate on the span between the arresters, thereby causing the riser pole arester to share a high-magnitude surge with the scout arrester. To eliminate this possibility, a shield wire is recommended between the riser pole and scout arresters, and even a span beyond.

225

B. Overvoltage Protection 3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS Underground Circuit Protection (Continued)

5. The ultimate in overvoltage protection on a UD circuit is to provide arresters at convenient points all along the cable, in addition to the riser pole arrester. This is generally done at points of discontinuity, such as where transformers are tapped from the cable (Figure 1283). Because of their ground-level location, these arresters usually have to be dead-front or under-oil arresters, which are difficult to add to existing installations. Feed-thru loadbreak inserts are available to accommodate dead-front arrester installation at the end-points and mid-points of an existing UD circuit. This particular method of protection is gaining in popularity primarily because of increasing cable failure problems, although it helps to protect the transformers as well. The cable treeing problem may reduce the cable withstand to substantially below thewithstand capability at time of installation, and providing more overvoltage protection may help to prolong the cable life. If it is not physically or financially possible to add arresters at each point of

OVERHEAD LINE

/1-

T

T

Figure 1283. UD circuit protection with arrester at each transformer.

226

discontinuity, margin of protection can usually be sign~ cantly improved by adding mid-point arresters at one prt of discontinuity. The most effective location for mid-poirt arresters is usually the first point of discontinuity in the UD circuit. TYPE OF ARRESTER The method of selecting an arrester voltage rating for UD applications is the same as for overhead applications, but the margins of protection are much smaller and, therefore, more critical. The result is that normal distribution class arresters may not be adequate. Where analysis indicates that this is the case, special riser pole arresters or intermediate-class arresters may be used. Margin of protection can also be improved by utilizing Copper Power Systems VariGap® stv'e surge arresters in some or all locations.

83 Distribution Apparatus Protection Most of the equipment on distribution systems is located on poles or in enclosures, and each piece of equipment has its own overvoltage protection, generally provided by one or more surge arresters. Transformers make up the bulk of this equipment and the other distribution devices that are individually protected include voltage regulators, reclosers, sectionalizers, switches, and capacitors. As indicated in the above discussion, "Arrester Leads and Connections," the best protection is obtained by minimizing the arrester lead length and placing the arrester as close as possible electrically to the protected equipment. Some of the other details of arrester protection are discussed below for each type of equipment. Note that, if the equipment to be protected is dry-type rather than oil-filled, a higher margin of protection will be necessary, as explained previously under "Equipment Withstand."

DISTRIBUTION TRANSFORMERS Grounding To provide reliable surge protection for the transformer, it is essential that the arrester ground terminal be interconnected with the transformer tank and secondary neutral (Figures 1383 and 1483).

SURGE ARRESTER - - -

use of gaps is illustrated in Figure 1583. With either solid or gap interconnection, surge current is routed through several parallel ground impedances, and danger to insulation damage is minimized, even under conditions of high surge current and high ground impedance. As shown in Figure 1683, on a grounded-wye system, one arrester is necessary across each line to ground for either a three-phase or a single-phase transformer. With the delta system of Figure 1783, the arresters on the ungrounded lines are subjected to full line-to-line voltage if one conductor is accidentally grounded. A single-phase transformer tapped off this system requires two arresters: one connected to ground on each side of the primary.

----~------------~~-------N ----+-----'-1---~--------¢

SURGE ARRESTER

Figure 1483. Transformer protection with solid arrester interconnection on source side of primary fuse link. SECONDARY NEUTRAL

SECONDARY LEAD IMPEDANCE

Figure 1383. Transformer protection without arrester interconnection. If interconnection is not used (Figure 1383), a surge current flowing to ground through an impedance causes a drop that impresses a high voltage on the primary winding of the transformer. Because the secondary winding and the tank are essentially at ground potential, a potential stress exists between the two windings, and between the primary winding and the tank. Connection to a common ground point at the secondary neutral (Figure 1483) reduces the stress to the small impedances drop inherent in the arrester, thus eliminating the stress produced by the drop across ground impedance. If solid interconnection between the tank and the common ground point is not permitted by local code, gaps can be used between the tank and the common ground point, and between the ground point and the secondary neutral. The

----~------~----~~-------N ----+-----~.----+--------¢

SURGE ARRESTER

Figure 1583. Transformer protection with arrester interconnection through gaps.

227

B. Overvoltage Protection 3. SURGE ARRESTER APPLICATIONS AND OTHER PROTECTION DETAILS Distribution Apparatus Protection (Continued)

SUBSTATION

t

\

LINE-TO-LINE VOLTAGE

+

LINE-TO-NEUTRAL VOLTAGE

+ t

-=~

1 ~:,r +

SINGLEPHASE BRANCH LINE

" ... T

~LJ~

nnn

_.......

SINGLE-PHASE TRANSFORMER BANKS

-----

THREE-PHASE TRANSFORMER BANK

~ >-

~ ..~..._t-+--4 _._

Figure 1683. Arrester application on grounded-wye system.

SUBSTATION

LINE-TO-LINE VOLTAGE

SINGLEPHASE BRANCH LINE SINGLE-PHASE TRANSFORMER BANK

nnn THREE-PHASE TRANSFORMER BANK

Figure 1783. Arrester application on delta system.

228

/ SURGE ARRESTER..__~~__.

83 Fuse Location Another consideration in the application of arresters to distribution transformers is the proper location of the transformer fuse with respect to the arrester. The arrester can be connected on the load side of the primary fuse as shown in Figure 1883. This connection may reduce the length of the lead connecting the arrester between line and transformer ground, but it permits lightning surge current to flow through the link. If the link is small or the surge of long duration, the link will be unnecessarily blown or damaged, removing a transformer from service. This can be a major source of customer outages during severe storms and, consequently, may be intolerable in some instances. ----~----~------.-------N

----+-----~~--~------¢ 1------f- PRIMARY FUSE SURGE ARRESTER

Figure 1883. Arrester connection on load side of primary fuse link. In addition to shorter leads, an advantage of placing the fuse first is that the fuse can be used to clear a failed arrester as well as a failed transformer. This usually leads to much faster clearing times, especially if current-limiting fuses are used, and it minimizes the possibility of violent arrester failures, especially in high fault-current applications. Connection of the arrester on the source side of the primary fuse link is illustrated in Figure 1483. In this arrangement, the lightning surge current is drained to ground through the arrester and does not flow through the primary fuse link, thus minimizing the possibility of unnecessary fuse blowings. The advantages and disadvantages of both configurations -loadside and source-side connections - are summarized in Table 683. Both schemes are widely used, and the final choice will depend on the needs and experience of a given area.

Single Phasing As mentioned under "Ferroresonant Overvoltages" in Section 81, single-pole switching, or the operation of a fuse or other overcurrent device on one phase of a three-phase circuit can lead under some circumstances to overvoltages on the open

phase as a result of ferroresonance. It can also lead to sustained 60 Hz overvoltages appoaching 2.65 per-unit on the open phase when ungrounded wye-delta transformers are serving a large single-phase load. Although these overvoltages can be excessive for all equipment involved, they are especially troublesome for arresters, which often are the components that fail under these circumstances. The problem can be eliminated by placing arresters ahead of the transformer fuses, but if the transformer is on a fused tap as shown in Figure 1983, there is also a concern for fuse blowing at the tap point. (Again, the arrester is on the open phase and is subject to the high overvoltage conditions.) Regardless of arrester location, the problem can be minimized by selecting arresters which provide increased TOV (Temporary Overvoltage) and enhanced margin of protection such as the Cooper Power Systems VariGap® style surge arrester. Of course the entire problem can be eliminated by not using three-phase transformer connections in applications where single-phase overcurrent devices are used.

TABLE 683 Advantages and Disadvantages of Connecting Arrester on Source-Side and Load-Side of Transformer Fuse Arrester on Load Side Arrester on Source Side Advantages Disadvantages Advantages Disadvantages Surges Fuse cannot If arrester Fuse subjected ·diverted limit energy to fails, to surge by arrester. failed arrester. fuse may transients. prevent porcelain rupture. No Surge arrester Limits nuisance failure could area of system fuse cause loss of blowing . large part of outage. system. CurrentCurrentlimitinglimitin~-fuse arc vo tage fuse arc voltage may cause arrester to does not operate. appear across arrester May require longer arrester leads, reducing insulation protection margin.

s

u B

s

T A T I

0 N

.,_---------r:c-SOURCE

A typical protection scheme for a medium-size generator (between 11 and 99 kW) is shown in Figure 3C2. Note that some schemes may include a utility breaker, indicated by broken lines, for duplication of protection and to provide a means for disconnection. The monitored conditions are negativesequence voltage (47), generatorovercurrent (50/51), undervoltage (27), overvoltage (59), and frequency (81). Table 2C2 shows the potential abnormalities and the characteristics being monitored for their detection. If the generator is synchronous, a synchronizing relay (25) will be used together with a second set of PTs on the generator side of breaker 2. With medium generators, some utilities allow the use of molded-case breakers for overcurrent protection, as in the small-generator example (Figure 2C2}, instead of circuit breakers with CT's and relays. For large generators (usually between 100 kW and 1 MW) the protection requirements may be extensive like the ones shown in Figure 4C2. This scheme not only provides generator protection but also protects the system. Protection redundancy assures removal of the generator under various abnormal conditions. For example, a fault on the utility side of the dedicated transformer may be detected by the time-overcurrent devices (51 /51 N), the undervoltage relay (27), and the reverse-power relay (32). UTI LilY

~~~--------_-1~_--um__

Lt_lY_________

I

I BREAKER

~ GENERATOR

Figure 2C2. Minimum protection scheme for a distribution system with DSG.

TABLE 3C2 Standard Device or Relay Identifications* Number

25 27 32 40 46 47 50 51 59 60 67 81 87

..

I

LOAD

Function or Monitored Condition Synchronism Check Undervoltage Directional Power Field Failure Reverse Phase Current Phase Sequence Voltage Instantaneous Overcurrent Time-Delay Overcurrent Overvoltage Current Balance Directional Overcurrent Frequency Differential Protective

GENERATOR

Figure 3C2. Typical DSG protection scheme for a medium-size generator.

* Part1al hst1ng from ANSI-IEEE C37.2-1979

255

C. Special System Considerations 2. PROTECTION OF SYSTEM WITH DISPERSED STORAGE AND GENERATION (Continued)

DEDICATED TRANSFORMER

I

PT

LOADS

*

REQUIRED BY UTILITY

Figure 4C2. Typical DSG protection requirements for a large generation facility.

256

C2 SPECIFIC PROTECTION PROBLEMS As stated previously, the addition of dispersed electric power sources to a distribution system affects utility operation during both normal and abnormal conditions. Following are discussions of some of the specific and most common problems and recommended solutions to those problems.

Nuisance Fuse Blowing Because most distribution systems are radial, their protection schemes take advantage of the fact that current flows only in one direction, from the source (substation) towards the fault (Figure 5C2[A]). The protective devices are time-current coordinated so that the device closest to the fault is the one called upon to operate first and isolate the fault. With faultsupporting DSG connected to the system, however, faults will have additional short-circuit current contributions from the substation that may affect the coordination (Figure 52C[B]).

In Figure 6C2, plots of J2t vs. time for a 12.47 kV feeder with three different sizes of dispersed synchronous genernlofs (100, 1000, and 2000 kW), and a 100 T fuse iink. are compared with the plot for a 12.47 kV feeder without