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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
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.
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
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
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
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
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
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.
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
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).
= 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
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.
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.
PROTECTED OR BACKUP 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.
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.)
Vab = Va-Vb= V3 V@ Voc = Vb-Vc =
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
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,
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
=Vb 1 + Vb2 + Vb0 Vc =Vc 1 + V~ + Vc0 Vb
=a Va and Vc =aVa a =1 /120°, a2= 1 /240°
But the quantities on the right side of these equations are not all independent. For example: