UNITED STATES DEPARTMENT OF AGRICULTURE 

Rural Utilities Service 

BULLETIN 1724E-102

RD-GD-2012-68

SUBJECT: Design Guide for Sectionalizing Distribution Lines

TO: All Electric Borrowers 

EFFECTIVE DATE: Date of Approval 

OFFICE OF PRIMARY INTEREST: Distribution Branch, Electric Staff Division

INSTRUCTIONS: This bulletin replaces Bulletin 61-2 which was rescinded in 1992. 

AVAILABILITY: This bulletin can be accessed via Internet at: 

http://www.usda.gov/rus/electric/bulletins.htm 

PURPOSE: This bulletin provides guidance and assistance in sectionalizing 

distribution lines to protect them from faults. 

10/23/12 

 Date 

 Assistant Administrator 

 Electric Program 

Disclaimer: The contents of this guidance document does not have the force and effect of law and is not 

meant to bind the public in any way. This document is intended only to provide clarity to the public 

regarding existing requirements under the law or agency policies.
RUS Bulletin 1724E-102

Page 1

TABLE OF CONTENTS

1 INTRODUCTION..............................................................................................................4

2 PHILOSOPHY AND STUDY PREPARATION...............................................................4

a General ........................................................................................................................4

b System Reliability .......................................................................................................5

c Temporary and Permanent Faults ...............................................................................5

d Zones of Protection .....................................................................................................6

e Fuse Saving .................................................................................................................7

f Frequency of Studies...................................................................................................8

g Summary of Steps in Making a Sectionalizing Study.................................................8

h Data Necessary for Sectionalizing Study....................................................................9

i Location of Sectionalizing Devices.............................................................................9

j Suggested Outline for a Sectionalizing Study...........................................................10

3 DETERMINATION OF FAULT CURRENTS ...............................................................11

a General Information ..................................................................................................11

b Calculation Method for Determining Fault Currents................................................13

4 TYPES OF SECTIONALIZING DEVICES....................................................................31

a Introduction ...............................................................................................................31

b Circuit Breakers.........................................................................................................31

c Automatic Circuit Reclosers .....................................................................................31

d Automatic Line Sectionalizers..................................................................................32

e Line Switches............................................................................................................32

f Fused Cutouts............................................................................................................33

g Current-Limiting Fuses.............................................................................................33

h Power Fuses...............................................................................................................34

i Circuit Switchers.......................................................................................................35

j Underground Sectionalizing Devices........................................................................35

k Fault Indicators..........................................................................................................35

l Intelligent Electronic Devices...................................................................................36

5 APPLICATIONS OF SECTIONALIZING DEVICES....................................................36

a General Guidelines....................................................................................................36

b Guidelines for Substation Overcurrent Protection ....................................................40

c Guidelines for Overhead Line Protection..................................................................49

d Guidelines for Underground Overcurrent Protection................................................68

6 EQUIPMENT UTILIZATION AND MAINTENANCE.................................................71

a Utilization Guidelines ...............................................................................................71

b Recloser Maintenance Guidelines.............................................................................72

7 SPECIAL CONSIDERATIONS ......................................................................................76

a Grid Stability.............................................................................................................76

b Loading Considerations.............................................................................................76

c Sympathetic Tripping................................................................................................78

d Voltage Conversions.................................................................................................78

e Intelligent Devices.....................................................................................................79

f Remote Monitoring and Control ...............................................................................82

g Distribution Automation ...........................................................................................83

h Fault Location ...........................................................................................................84

i Distributed Generation ..............................................................................................86

8 SAMPLE PROBLEM: SMALL SUBSTATION............................................................86

a Problem .....................................................................................................................87
RUS Bulletin 1724E-102

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b Selecting the Transformer Primary Fuse...................................................................88

c Selecting the Substation Feeder Protection...............................................................91

9 SAMPLE PROBLEM: LARGE SUBSTATION ............................................................93

a Basic Data .................................................................................................................94

b Solution ...................................................................................................................103

Exhibits

Exhibit A — Sample Model Printout Showing Calculations of Fault Currents and Loading 

Conditions

Exhibit B — Line Recloser Maintenance Specifications

Exhibit C — Bibliography and References

INDEX:

Sectionalizing Distribution Lines

Design Guide

ABBREVIATIONS

A amperes (or amps)

AC alternating current

ANSI American National Standards Institute

BIL basic impulse level

CLF current-limiting fuse

CRN Cooperative Research Network

DC direct current

DG distributed generation

DR distributed resources

EEI Edison Electric Institute

FCI faulted circuit indicator

FERC Federal Energy Regulatory Commission

G&T generation and transmission cooperative

GIS geographic information system

GPS global positioning system

IED intelligent electronic device

IEEE Institute of Electronics and Electrical Engineers

IMT impulse margin time

MFT minimum fault time

NEMA National Electrical Manufacturers Association

NERC North American Electric Reliability Corporation

NRECA National Rural Electric Cooperative Association

OCR oil circuit recloser

P.U. per unit

PLC programmable logic control

ROT relay operating time

SCADA supervisory control and data acquisition

SF6 sulfur hexafluoride

STD substation transformer and distribution line

TCC time-current characteristic

TCP/IP Transmission Control Protocol/Internet Protocol
RUS Bulletin 1724E-102

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UPS uninterruptible power supply

VAR volt-amperes reactive

V volts

Ω ohms
RUS Bulletin 1724E-102

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1 INTRODUCTION

This bulletin is a guide for making sectionalizing and protection studies on electric 

distribution systems for rural electric cooperatives. It provides a revised and updated 

version of RUS Bulletin 61-2 which was rescinded in 1992. Specifically, the bulletin 

updates methods, examples, and tools relevant to radial distribution systems. As in the 

earlier publications, it is not intended to provide a complete and exhaustive discussion of 

the subject, but rather to present the reader with helpful information and examples that 

will typically be encountered.

Within the arena of sectionalizing, there are many aspects of the subject that are 

established, quantifiable, and part of national standards. Included in this body of 

information are specific time-current characteristics of fuses and relays, the methods of 

calculations for available short-circuit current, and the standard damage points for 

distribution transformers. There are also many aspects of sectionalizing that are more 

subjective, debatable, and influenced by experience. These include “fuse save” versus 

“fuse blow,” coordination margins, and transformer protection practices. This reflects the 

idea that system protection is partly science and partly art.

This bulletin concentrates on the “science” side of the subject and offers some wellestablished practices and conventions on the “art” side. In the end, it is the responsibility 

of a cooperative’s protection engineer to recognize the specific needs and goals of the 

cooperative and apply the principles herein to the available equipment and technology to 

accomplish the best combination of reliability and economics possible.

This bulletin is not intended to provide a detailed discussion of substation transformer 

protection. The document focuses on the distribution system beginning at the low-side 

connections of the substation transformer.

Arc Flash energy available on a distribution system will be affected by system protective 

device settings. Although it is beyond the scope of this Bulletin to address this issue, the 

protection engineer is encouraged to research and understand the relationship between 

system settings and arc flash energy.

2 PHILOSOPHY AND STUDY PREPARATION

a General. At a high level, sectionalizing is about compromises and creating the

best combination of methods and practices that suits the individual cooperative. 

Goals and issues must be considered and evaluated and then implemented. 

Questions that must be considered include the following:

Which is more of a problem, blinks or longer outages?

How high can we (or should we) set protective devices?

Are our equipment maintenance cycles adequate?

Do right-of-way cycles affect our protection plans?

What weather patterns affect our service area?
RUS Bulletin 1724E-102

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b System Reliability. The goal of all coordination philosophies is improved system

reliability.

(1) Setting Service Priorities. Inherently, the installation of any coordination

device sacrifices the electric service to the loads and customers downline

for the greater good of maintaining service to the rest of the customers. 

The device may protect major or critical loads by dropping long exposures 

to noncritical loads during fault conditions. But one must remember that 

every sectionalizing device sets a priority of service because its operation 

stops electric service, even temporarily, to the downline customers in 

favor of the rest of the circuit customers.

(2) Protective Devices. The protection engineer must face a compromise: 

Higher settings for protective devices typically will improve reliability on 

a distribution system by reducing the number of nuisance operations while 

allowing for more downline devices to be applied. On the other hand, 

lower settings for protective devices can improve the security of the 

system by clearing higher-impedance faults (at the expense of increased 

operations).

(3) Different Approaches. No single approach is right for all systems and,

many times, not even for all portions of one system. Urban and rural 

service areas have different characteristics and different approaches may 

be appropriate. This bulletin suggests an approach for determining 

settings for typical environments. It is important to understand the 

methodology and what can be achieved (as well as what cannot be 

achieved) rather than to use rote settings or values.

c Temporary and Permanent Faults. Faults can generally be categorized as

temporary or permanent.

(1) System Protection. It is easy to agree on one thing in system protection:

that permanent faults need to be disconnected or they will disconnect 

themselves through destruction of the system. Studies have shown that a

majority of faults are temporary in nature. Historically, utilities have used 

devices (circuit breakers and reclosers) to clear temporary faults and 

restore service without manual intervention. These same devices also 

clear permanent faults, but require manual intervention to restore service 

afterward.

(2) Application of Fault Devices. The application of these devices, including 

how many to use, how to use them, and how to set them depends on the 

sectionalizing goals of the cooperative. Any fault or short circuit draws 

fault current depending on the system and fault impedance. Some 

electronically controlled reclosers record the magnitude of the fault which 
RUS Bulletin 1724E-102

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occurred. Some faults are actually located by comparing the actual fault 

current level to areas that can develop a fault of that magnitude. Tolerance 

to temporary faults is discussed in Section 2E of this Design Guide, 

“Fuse Saving.”

d Zones of Protection. In developing a sectionalizing study, maximum and

minimum fault currents must be calculated.

(1) Determining Fault Current Levels. Maximum fault current levels are used 

to ensure that interrupting devices have adequate capabilities and ratings 

to handle the full amount of fault current to which they may be exposed. 

Minimum fault current levels are used to determine the zone of protection 

for a particular device. Determining the minimum fault current is a 

challenge, as fault currents can be below load levels. Certain assumptions 

are required because of the variability of faults on distribution systems. 

Utilities have used such methods to estimate minimum fault current levels 

as:

Assuming some percentage of maximum fault current,

Assuming some multiple of load current, and

Assuming some fault impedance (Zf) level.

(2) Methods. Traditionally, cooperatives have used the fault impedance

method successfully, and this method will be described in this manual. 

The question that has always been considered is “What fault impedance 

should be used?” The previous version of this bulletin suggested 30 to 40 

Ω for overhead lines and 10 to 20 Ω for underground lines. This led to 

some confusion and concern about the use of 40 Ω of ground fault 

resistance to calculate the minimum fault current available for overhead 

construction on distribution systems under the jurisdiction of the Rural 

Utilities Service.

(3) Discussion. The following discussion (through the end of this subsection)

is offered to clarify the issue and establish guidelines that can support 

sound electric system operations. Studies have shown that the actual fault 

impedance when an energized conductor is in contact with the earth can 

vary from zero to infinity.1 Therefore, it is impossible, using current 

technology, to select a minimum pickup value that will both detect 

energized conductors in contact with the ground and allow normal load 

currents to flow without interfering with normal system operation.

The 40-Ω value described in RUS bulletins and literature has always been 

 

1

“Downed Power Lines: Why They Can’t Always Be Detected,” NRECA, February 22, 1989.
RUS Bulletin 1724E-102

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a compromise and was never intended to be an absolute value.

2

 This is 

supported by the fact that Bulletin 61-2 was a guide bulletin before it was 

rescinded and by the fact that it suggested the use of 30 Ω under certain 

conditions.

From an engineering perspective, any ground fault resistance used in 

selecting minimum ground trip levels is a “design value” selected for 

calculation purposes only and should not be confused with the ground 

fault resistance that might occur. The values of 40 and 30 Ω have been 

used for many years on RUS systems. Surveys have shown that utilities 

frequently use values other than 40 Ω.3,4 The actual value used (or method 

used, for that matter) should be determined by the cooperative’s engineer 

or consultant. Such a practice of selecting a method that allows for the 

possible detection of low-level ground faults while considering system 

voltage, load current, phase unbalance, and system coordination is 

considered prudent and sound utility engineering.

e Fuse Saving. One method of system protection and sectionalizing is the proper

application of power fuses on the distribution system. This is an economical 

method to provide additional sectionalizing locations, but has one major 

drawback.

(1) Drawback. When the fuse blows, a service technician must go to the 

location, determine the cause of the fault, and re-fuse. Automatic devices, 

such as reclosers and circuit breakers, will reset themselves after operating 

a few times short of lockout, but at a considerable added cost. Fuses, by 

their nature, are a time-current device. A given current for a given time 

will melt or “blow” the undamaged fuse. Temporary faults can also melt 

the fuse.

(2) Outage Solutions. To avoid an outage and the associated service

technician’s visit, the upline recloser may have a “quick-trip curve”

enabled. This allows the upline device to quickly deenergize and 

reenergize the line with the intention to save the fuse from blowing. 

Unfortunately, this “blinks” the lights of a much larger portion of the 

system.

With today’s demand for improved power quality, including fewer blinks, 

this fuse-saving philosophy is being avoided, for at least a portion of the 

time, by some systems. By disabling the reclosers’ quick-trip operation

and allowing the fuses to blow, the smallest possible portion of the system 

 

2

“Review of Sectionalizing Fundamentals,” L.B. Crann, July 1972, REA National Field Conference.

3

“Ground Fault Impedance Values for System Protection,” NRECA CRN Project 96-05, August 1997.

4

“IEEE Guide for Protective Relay Applications to Distribution Lines,” IEEE Std 37.230-2007.
RUS Bulletin 1724E-102

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experiences the outage. But, unfortunately, when a lightning shower 

blows through, many fuses are blown that could have been saved. Some 

systems can switch from the fuse-blowing philosophy to the fuse-saving 

philosophy, and vice versa, by reenabling or disabling the quick trip 

feature with distribution automation systems.

Some systems accept the fact that blinks caused by temporary faults are 

the real world and that the power system cannot provide blink-free power 

to its customers. In such systems, it is strongly suggested that each 

customer provide its own voltage protection in the form of uninterruptible 

power supplies (UPS) to critical loads, including home personal 

computers, just as they must be protected from surges by surge 

suppressors.

f Frequency of Studies. Sectionalizing studies should be reviewed at frequent

intervals to ensure that they are adequate.

(1) The frequency of review should be driven by the rate of change of the

system itself. When load currents or system configurations experience 

significant changes, the sectionalizing study should be updated to review 

the impact on devices.

(2) Major system changes would also necessitate that a sectionalizing study be 

performed as part of the work. The following would typically determine 

the need for a new study: 

Constructing a new substation,

Increasing substation transformer capacity,

Adding new substation feeders,

Changes in available fault current due to transmission and/or 

distribution improvements,

Major reconductoring projects, whether increasing conductor size 

on existing three-phase lines or converting from single phase to 

three phase, or

Conversion to a higher operating voltage.

g Summary of Steps in Making a Sectionalizing Study. The following is a list of

individual steps involved in making a sectionalizing study. These steps provide 

an orderly overview of the process.

(1) Obtain complete data on the distribution system and determine all device 

types that are likely to be used in the study.

(2) Select preferred locations for sectionalizing devices or relocated sites for 

existing devices. Determination of locations is based on operational 

concerns, outage histories, and review of system configurations.

(3) Calculate all available fault current at each tentative sectionalizing device 
RUS Bulletin 1724E-102

Page 9

location.

(4) Select feeder protection to provide optimum coverage on the feeder and 

adequate coordination with substation transformer protection.

(5) Starting at the substation feeder protection level, make sure each device 

meets the cooperative’s goals for sectionalizing and coordination. Revise 

locations and settings as necessary.

(6) Check the selected devices for voltage rating, continuous current rating, 

interrupting current rating, and minimum pickup rating. Make sure each 

device is applied within its rating and will respond to minimum fault 

current within its zone of protection.

(7) Prepare written instructions for additions and changes to sectionalizing 

devices and update existing circuit diagrams.

h Data Necessary for Sectionalizing Study. The following data should be

assembled and updated at the beginning of the study.

(1) Distribution System Information

(a) Circuit diagrams of the distribution system prepared in accordance 

with the appropriate RUS bulletins.

(b) Locations of critical and large power loads.

(c) Maximum load currents at the time of the study for each proposed 

sectionalizing point.

(d) An understanding of historical load growth and future anticipated 

load growth for respective feeders and areas.

(e) The distribution of meters along the circuit.

(2) Substation/Source Information. This information may vary, depending on 

whether the cooperative owns just distribution lines, or distribution lines 

and substation transformers, or distribution lines and substation 

transformers and transmission lines. In each scenario, the available fault 

currents at the appropriate location must be obtained or calculated.

(3) Equipment Information. Information about the sectionalizing equipment 

being used and to be added should be collected. Specific equipment 

information, such as make, type, ratings, and characteristic curves, should 

be assembled and available for use.

i Location of Sectionalizing Devices

(1) Determine Locations. After the basic data have been accumulated, the

next step in the study is to determine tentative locations for sectionalizing 

devices. These locations may be revised after the short-circuit currents are

calculated and load currents checked. 

(2) Suggestions. Judgment and knowledge of one’s system, including terrain,

must be used for each case, but the following may be helpful:
RUS Bulletin 1724E-102

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(a) Number of Automatic Sectionalizing Devices. The number of 

automatic sectionalizing devices used in series should be kept to a 

reasonable level. There are obvious advantages and disadvantages 

to the number of devices in series. More devices can help reduce 

the number of affected customers, but more devices also can create 

greater coordination difficulties, causing misoperations. Nonautomatic devices, such as disconnect switches, can be very 

helpful in restoration when used judiciously between automatic 

devices.

(b) High-Reliability Zones. “High-reliability zones” have been 

suggested to improve system performance. In these zones, efforts 

are focused on the feeder from the source to the first set of feeder 

devices. Within this zone, all taps are provided with some form of 

sectionalizing to reduce the possibility of feeder operations. 

Outside of this zone, more judgment may be used in weighing 

protection devices versus exposure.

(c) Visibility. Main sectionalizing devices should be visible and 

accessible from roads during any season of the year.

(d) Critical Placement. Sectionalizing devices should be located 

where they will not disrupt service to critical customers. Generally,

such devices should be placed just beyond these customers.

j Suggested Outline for a Sectionalizing Study

(1) Scope of study.

(2) Tabulation of sectionalizing devices to be purchased.

(3) Sectionalizing device schedule for each substation area.

(4) Cost estimate (cost of new devices and their installation, plus changing or 

converting existing devices).

(5) Schematic diagram and coordination chart for substation protective 

devices for fault conditions.

(6) Detailed impedance fault current calculations for source and substation 

transformers up to load side bus, if appropriate.

(7) Examples of typical time current characteristic curves for devices used in 

the study.
RUS Bulletin 1724E-102

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(8) Instructions to the operations manager.

3 DETERMINATION OF FAULT CURRENTS

a General Information

(1) Assumptions. The discussion and the information in this Section of the 

Design Guide are based on the following assumptions:

(a) The frequency of the system is 60 hertz.

(b) All distribution lines have multigrounded neutral conductors.

(c) Underground lines are made up of direct-buried, single-phase

jacked cables with aluminum or copper conductors and bare

copper concentric neutrals. The voltage rating of the cable is 25 

kV or less.

(d) The substation transformers are connected delta on the supply side

and wye-grounded on the load side.

(e) The system is radial (i.e., no connected loops). If there is more

than one source of supply, they are not interconnected.

(2) Fault Current. In a sectionalizing study, it is necessary to calculate both

the maximum fault current and the minimum fault current at each 

sectionalizing point. In addition, the minimum fault current must be 

calculated for the end of each line. The method of calculating maximum 

and minimum fault currents will be given in Section 3B of this Design 

Guide.

(a) Types of Fault. There are four possible types of fault: three-phase, 

double line-to-ground, line-to-line, and single line-to-ground. 

Three-phase faults can occur only on three-phase circuits; line-toline and double line-to-ground faults can occur on three-phase or 

V-phase circuits, and line-to-ground faults can occur on any type 

circuit. As a result of the multigrounded neutral construction of 

overhead lines, the line-to-ground fault is by far the most common, 

although other types do occur. For underground cables, the only 

type of fault that is likely to occur is a line-to-ground fault. 

However, the impedance of underground cable to three-phase and 

line-to-line faults is given in this bulletin because, for combined 

underground-overhead lines, where the overhead section is farther 

from the substation than the underground cable, it is possible that a 

fault on the overhead line could cause either line-to-line or threephase fault current to pass through the cable.
RUS Bulletin 1724E-102

Page 12

(b) Maximum Fault Current for Three-Phase Lines. The three-phase 

fault current generally determines the maximum fault current level 

for three-phase lines. Near the substation, however, it is possible 

that a line-to-ground fault may produce a larger fault current. This 

is because line-to-ground faults see a lower source impedance with 

a delta/grounded-wye transformer connection, but a higher 

impedance per mile of line than three-phase faults. Thus, to 

determine the maximum fault current on a three-phase line, it is 

necessary to calculate the line-to-ground fault current as well as the 

three-phase fault current up to that point on the line where the lineto-ground current becomes equal to or less than the three-phase 

current. (See Figure 3.1.)

Figure 3.1. Fault Current on a Distribution Line Supplied by a 

Delta/Grounded-Wye Substation Transformer

 FEEDER DISTANCE FROM SUBSTATION

For V-phase and single-phase lines, line-to-line and line-to-ground 

faults, respectively, yield the maximum fault current.

Double line-to-ground faults usually yield neither a maximum nor 

a minimum value for any type of line and, thus, do not normally 

need to be calculated. See Symmetrical Components for Power 

Systems Engineering by J. Lewis Blackburn (CRC Press, 1993) for 

further information.

Table 3.1 summarizes, for each type of line, what type of fault will

yield the maximum and minimum fault current values. The table 

is applicable for overhead, underground, and combined overheadunderground lines.
RUS Bulletin 1724E-102

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Table 3.1. Fault Current Values for Various Types of Fault

Line Type

Fault Type That Yields

Maximum Fault Current Minimum Fault 

Current

Three-Phase Three-phase fault or Line-toground fault near substation.

Line-to-ground 

fault*

V- or TwoPhase LineLine-to-line fault (line-toground fault near a substation)Line-to-ground 

fault*

Single-phase Line-to-ground fault Line-to-ground 

fault*

*A value for fault resistance must be included.

A calculation method for determining fault current is presented in 

Section 3B of this Design Guide immediately below. There are 

various brands of engineering analysis software that will readily 

perform these calculations once an engineering model has been 

built and properly configured for the exact power system.

b Calculation Method for Determining Fault Currents

(1) General

(a) Since this bulletin was last updated, there have been many

changes in computational equipment and methodologies. With 

the advent and widespread usage of personal computers and 

specialized engineering software, there has been less and less 

reliance on hand calculations. However, since this bulletin is 

written for technicians and engineers of various skill and 

experience levels, some hand calculation methods will be 

discussed. Furthermore, there is an extensive bibliography 

included for the serious practitioner. Tables containing formulas 

and other useful information are included in this section of the 

Design Guide.

(b) Tables 3.2 through 3.4 in this Design Guide contain the 

information necessary to hand calculate fault currents for line-toground (Table 3.2), three-phase (Table 3.3), and line-to-line (Table 

3.4) faults. Additionally, the percent and per unit methods of 

calculating fault currents will be discussed in general.

Table 3.2. Information for Calculating Line-to-Ground Fault

Current on Load Side of Substation

1. SOURCE IMPEDANCE

(LOAD SIDE OF VOLTAGE BASE)
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Type of Fault Current or Impedance 

Value Given

Formula to Determining 

Source Impedance Zs

a. Is(L-L), line-line fault current on 

source side of substation

2

( L-L) ( L-L)

L

s

s s

E

Z

I E

b. I3s, three-phase fault current on 

source side of substation

2

3 ( L-L)

2

3

L

s

s s

E

Z

I E

c. Z1, Positive-sequence impedance 

on source side of substation

1

( L-L)

2

L

s

s

E

Z Z

E

Source impedance is available from power supplier.

2. SUBSTATION TRANSFORMER IMPEDANCE

Formula to convert substation transformer impedance Zt from 

percent to ohms:

2

 (% ) 

 ( ) 

(kV A per phase) (100,000)

t t

t

Z E

Z

Rt (resistive component of substation transfer) = 0.20Zt

(approximate)

Xt (reactive component of substation transformer) = 0.98Zt

(approximate)

3. DISTRIBUTION LINE IMPEDANCE

(SINGLE-PHASE IMPEDANCE VALUES)

Overhead Lines* Underground Lines†

ACSR 

Conduct

or Size

Ω per mile Aluminum 

Conductor Cable 

Size

Ω per mile

RL XL RL XL

336.4 

MCM

0.410 1.010 350 MCM 0.560 0.159

266.8 

MCM

0.510 1.039 250 MCM 0.759 0.211

4/0 0.640 1.220 4/0 0.890 0.261

3/0 0.759 1.270 3/0 1.089 0.340

2/0 0.940 1.369 2/0 1.319 0.439

1/0 1.120 1.450 1.0 1.559 0.570

2 1.640 1.469 1 1.839 0.670

4 2.470 1.459 2 2.159 0.880

6 3.72 1.540

4. CALCULATION OF FAULT CURRENT

Maximum line-to-ground fault current:
RUS Bulletin 1724E-102

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max 2 2

dist dist ( ) ( )

L

s t s t

E

I

R R R X X X

*Standard C1-type construction is assumed.

†To obtain total distribution line impedance Rdist and reactance Xdist to any point, 

multiply the appropriate value below by the number of miles of line. For two or more 

conductor sizes, calculate resistance and reactance values separately for each 

conductor size and total value for the sizes together.

EL = line-to-ground voltage on load side of substation.

Es(L-L) = line-to-line voltage on supply side of substation.

Table 3.3. Information for Calculating Three-Phase Fault Current on 

Load Side of Substation

1. SOURCE OF IMPEDANCE (LOAD SIDE VOLTAGE BASE)

Type of fault current of impedance value 

given

Formula to determine 

source impedance Zs

a. Is(L-L), line fault current on source side of 

substation

2

( L-L) ( L-L)

3

2

L

s

s s

E

Z

I E

b. I3s, three-phase fault current on source 

side of substation

2

3 ( L-L)

3

L

s

s s

E

Z

I E

c. Z1, positive-sequence impedance on 

source side of substation

2

1

( L-L)

3

L

s

s

E

Z Z

E

Source impedance is available from power supplier.

2. SUBSTATION TRANSFORMER IMPEDANCE

Formula to convert substation transformer impedance Zt from percent to 

ohms:

2

1

 (percent) 

 ( ) =

(kVA per phase) (100,000)

L

s

Z E

Z

 (resistive component of substation transformer = 0.20

 approximate

 (reactive component of substation transformer) = 0.98 

t t

t t

R Z

X Z

3. DISTRIBUTION LINE IMPEDANCE

(THREE-PHASE IMPEDANCE VALUES)

Overhead Lines* Underground Cables†

ACSR conductor 

size

Ω per mile Aluminum 

conductor 

cable size

Ω per mile

RL XL RL XL

336.4 MCM 0.278 0.632 350 MCM 0.298 0.180

266.8 MCM 0.350 0.653 250 MCM 0.410 0.256

4/0 0.441 0.712 4/0 0.606 0.271

3/0 0.557 0.727 3/0 0.741 0.293

2/0 0.702 0.742 2/0 0.941 0.311

1/0 0.885 0.756 1/0 1.363 0.349
RUS Bulletin 1724E-102

Page 16

2 1.409 0.780 1 1.363 0.349

4 2.240 0.805 2 1.844 0.385

6 3.509 0.853

4. CALCULATION OF FAULT CURRENT

Maximum three-phase fault current

max 2 2

dist dist ( ) ( )

L

s t s t

E

I

R R R X X X

* Standard CI-type construction assumed.

† See manufacturer’s technical literature for exact impedance values based on exact 

configuration, type of cable, neutral size, etc.

To obtain total distribution line impedance Rdist and reactance Xdist to any point, 

multiply the appropriate value below by the number of miles of line. For two or more 

conductor sizes, calculate resistance and reactance values separately for each 

conductor size and total value for the sizes together.

EL = line-to-ground voltage on load side of substation.

Es(L-L) = line-to-line voltage on supply side of substation.

Table 3.4. Information for Calculating Line-to-Line Fault Current on 

Load Side of Substation

1. SOURCE OF IMPEDANCE (LOAD SIDE VOLTAGE BASE)

Type of Fault Current of Impedance Value 

Given

Formula to Determine 

Source Impedance Zs

a. Is(L-L), line-line fault current on source 

side of substation

2

( L-L) ( L-L)

3

L

s

s s

E

Z

I E

b. I3s, three-phase fault current on source 

side of substation

2

3 ( L-L)

2

L

s

s s

E

Z

I E

c. Z1, positive-sequence impedance on 

source side of substation

2

1

( L-L)

2 3 L

s

s

E

Z Z

E

Source impedance is available from power supplier.

2. SUBSTATION TRANSFORMER IMPEDANCE

Formula to convert substation transformer impedance Zt from percent to 

ohms:

2

1

 (percent) 

 ( ) =

(kVA per phase) (100,000)

L

s

Z E

Z

 (resistive component of substation transformer = 0.20

 approximate

 (reactive component of substation transformer) = 0.98 

t t

t t

R Z

X Z

3. DISTRIBUTION LINE IMPEDANCE

(THREE-PHASE IMPEDANCE VALUES 

2 3

)

Overhead Lines* Underground Cables†

ACSR Conductor Ω per mile Aluminum Ω per mile
RUS Bulletin 1724E-102

Page 17

Size RL XL Conductor 

Cable Size

RL XL

336.4 MCM 0.516 1.176 350 MCM 0.552 0.335

266.8 MCM 0.650 1.213 250 MCM 0.764 0.380

4/0 0.819 1.323 4/0 0.898 0.399

3/0 1.033 1.353 3/0 1.102 0.434

2/0 1.305 1.379 2/0 1.393 0.460

1/0 1.641 1.405 1/0 1.720 0.516

2 2.623 1.450 1 2.172 0.544

4 4.167 1.498 2 2.735 0.570

6 3.509 0.853

4. CALCULATION OF FAULT CURRENT

Maximum three-phase fault current

max 2 2

dist dist ( ) ( )

L

s t s t

E

I

R R R X X X

* Standard CI-type construction assumed.

† To obtain total distribution line impedance Rdist and reactance Xdist to any point, 

multiply the appropriate value below by the number of miles of line. For two or more 

conductor sizes, calculate resistance and reactance values separately for each 

conductor size and total value for the sizes together.

EL = line-to-ground voltage on load side of substation.

Es(L-L) = line-to-line voltage on supply side of substation.

(2) Use of Fault Current Calculation Tables. Regardless of the type of fault,

there are three main components of the impedance offered to the fault: the 

impedance of the source, the impedance of the substation, and the 

impedance of the distribution line up to the location of the fault. For the 

minimum fault current, a fourth impedance, the fault resistance 

component, is added.

(a) For most cases, the calculation of a fault current consists of

determining these three impedance components (four for minimum 

fault current), finding the total impedance offered to the fault, and 

dividing the system line-to-ground voltage by this impedance. The 

steps below outline the procedure in detail and will be 

demonstrated in the sample problem in Section 8 of this Design 

Guide.

(b) If you are using an engineering analysis program, you will probably 

need to do the calculations in steps (2) and (3) below by hand and 

then insert those values into the program and let the program 

calculate the fault currents, etc., at the beginning and end of each 

line section in the database model.

(1) Refer to the appropriate table for the type of fault for which 
RUS Bulletin 1724E-102

Page 18

values are to be calculated.

(2) The source impedance can be obtained from the power

supplier. The format usually used is R + jX % on the stated 

base. Convert this to R + jX % on 100 MVA base as 

shown in the percent and per unit discussion.

(3) Determine the substation transformer size, voltage, and 

impedance in percent from the nameplate information or 

from the manufacturer. As in (2) above, the impedance 

should be resolved into its reactive and resistive 

components either by using the formulas given in the tables 

or by using a ratio based on judgment.

(4) To find the distribution line impedance to any point on the

system, multiply the appropriate value from Section 3 of

the tables by the number of miles of line from the 

substation to the point being considered. If two or more 

different-size conductors are used from the substation to the 

point, add the total resistance of the first size to the 

resistance of the next size to the point, then add the total 

reactance of the first size to the reactance of the next size, 

etc.

(5) As indicated in Section 4 of the tables, add up separately 

the resistance and reactance components determined in the

steps above. (When calculating minimum line-to-ground 

fault current, be sure to include a fault resistance value.) 

Find the total impedance and divide the system line-toground voltage by this impedance value to determine fault 

current.

(3) Minimum Fault Current. It is necessary to calculate minimum fault

currents for coordination purposes and also to define a maximum “reach” 

or “zone of protection” of an overcurrent protective device. To calculate 

minimum fault current, a value of fault resistance should be added to the 

resistance component of total system impedance up to the point of fault. 

The selection of fault resistance is discussed in Section 2D of this Design 

Guide.

(4) Distribution Substation Fault Current Calculations. Generally the power

supplier will furnish the source impedance.

(a) These values—Z1 (positive-sequence impedance), Z2 (negativesequence impedance), and Z0 (zero-sequence impedance)—are 

usually given in R + jX format as a percent or per unit (P.U.) value 

on a 100 MVA base (typically). The substation transformer size 

and impedance information is generally known and usually takes 

the form of a percent impedance on the transformer base rating. 

The source and substation transformer impedance are then usually 
RUS Bulletin 1724E-102

Page 19

converted to ohmic values.

These ohmic values are then inserted into a typical engineering 

analysis program to be used to calculate fault currents within the 

model at the end of each line section.

(b) A typical example will illustrate the procedure.

Transformer Impedance (Percent Method)

A transformer having 10% impedance on a 20 MVA rating would have 

50% impedance on a 100 MVA base (See Table 3.5 of this Design 

Guide).

100

10% 50% on a 100-M VA base

2 0

Source Impedance (Typical Format)

From the power supplier for Westland Substation (69 kV):

Transformer Conversion

Formula to convert transformer impedance Zt from percent to ohms (see 

Table 3.3 of this Design Guide):

Zt (Ω) =

2

(% )

(kV A per phase)(100, 000)

t L Z E

= 

(3,333) (100,000)

(7.09%) (7,200) 2

= 

(3,333 ) (100,000)

3,675,456

= 1.102747 Ω

Spread transformer impedance into its R and X components (Ω):

1.102495 Ω

Z1 = 7.82 + j20.8%

Z0 = 16.60 + j58.78%

on a 100-MVA base @ 69 kV
RUS Bulletin 1724E-102

Page 20

0.2 + j0.98 approximate (use manufacturer’s data)

0.2205 + j1.080445 Ω

Methodology and Formulas

1. Methodology and formulas to convert transformer impedance Zt

from percent on its own MVA base to percent on a 100 MVA base (see 

Table 3.5):

 Transformer size = 10/12/14 MVA

 Transformer impedance = 7.09%

 Transformer voltage = 69 kV HS and 7.2/12.47 kV LS

where HS = high side and LS = low side.

2. Convert transformer impedance to 100 MVA base:

100

7.09% 70.9% on 100 M VA base

1 0

3. Spread transformer impedance into its R and X components (percent

on 100 MVA):

70.9 % on 100 MVA

0.2 + j0.98

14.18 + j 69.48 % on 100 MVA

Source and Transformer Impedance (High Side)

Source Z1 = 7.82 + j20.87 % on 100 MVA

Transformer Zt = 14.18 + j69.48 % on 100 MVA

Source plus Transformer Impedance (Assume Delta/Grounded-Wye

Connection)

Total impedance at service point (percent on 100 MVA at low side):

Z1LS = Z1 + Zt = 22.0 + j90.352 % on 100 MVA

Z0 = Zt = 14.18 + j69.482 % on 100 MVA

See constants for fault calculations. Multiply by 0.0155 /%
RUS Bulletin 1724E-102

Page 21

Z1LS = 22.0 + j90.352 % on 100 MVA

0.0155 /%

0.341 1.40046 j

Convert to ohms (see Table 3.6)

Z0 = 14.18 + j69.482 % on 100 MVA

0.0155 / %

0.220 1.080 j

Convert to ohms (see Table 3.6)

Total impedance at service point at 12.47 kV:

Z1 = 0.3421 + j1.4049 Ω

Z0 = 0.220 + j1.080 Ω

Source plus Transformer Impedance

Positive-sequence impedance:

Z1 = 

2 2 (0.3421) (1.4049) j

 = 1.4459 Ω

Impedance for phase-to-neutral faults:

ZPN =

2

1 2 0 ( )

3

Z Z Z

=

2

0.3421 1.4049

0.3421 1.4049

0.220 1.080

3

j

j

j

ZPN =

2 2 0.3014 1.2966 j

Ω

= 1.3316 Ω

Fault Currents at the 7.2/12.47 kV Bus
RUS Bulletin 1724E-102

Page 22

Three-phase current = ELL (1.73)(Z1) = 

(1.73) (1.4459)

12,470

= 4985 A

Phase-to-phase current = ELL 2Z1 = 4322 A

Phase-to-neutral current = (ELL (1.73)(ZPN) = 5407 A

where ELL = line-to-line voltage in volts (not kilovolts)

Three-Phase Fault Current at the 7.2/12.47 kV Bus

Three-Phase Fault Current by the Percent Method:

Z1 = 22.0 + j90.352 % on 100 MVA

= 92.99 % on 100 MVA

Three-phase fault current =

92 .99 %

100

(4630 A) = 4979 A

Note: The difference between this value and the previous calculation is 

due to rounding off.

Line-Neutral Fault by the Percent Method

Line-neutral fault =

3

2 Z Z

2

1 0

=

2

22.0 90.352

22.0 90.352

14.18 69.42

3

j

j

j

% on 100 MVA

=

2 2 58.18 250.124

3

j

% on 100 MVA

= 19.393 + j83.3746% on 100 MVA

= 85.60038% on 100 MVA

=

85 .60038

100

(4630 A)
RUS Bulletin 1724E-102

Page 23

= 5409 A

What about the Minimum Phase-to-Ground Fault Current?

Here is where we have to insert a fault impedance such as 25, 30, or 40 

Ω or some other value determined by the application of education and 

experience, industry standards, research, etc.

Calculate Minimum Line-to-Ground Fault

Ground fault impedance = R + j0

Use engineering judgment and experience to determine R.

Zpg = ZPN + ground fault impedance

= 0.3014 + j1.2966

= 40.0 + j0 

= 40.3014 + j1.2966

Zpg =

2 2 (40.3014) (1.2966) j

= 40.322225

Phase-to-Ground Fault

Phase-to-ground fault = E (1.73)(Z pg)

=

(1.73 ) (40 .32225 )

12 .470

= 178.8 A

Minimum Phase-to-Ground Fault

If ground fault impedance = 30 Ω, then phase-to-ground fault = 237 A.

If ground fault impedance = 25 Ω, then phase-to-ground fault = 284 A.
RUS Bulletin 1724E-102

Page 24

Line-To-Ground Fault by the % Method

ZPG = ZPN + ground fault impedance

= 19.393 + j83.3746 % on 100 MVA base

+ 2,572.400 + j0 % on 100 MVA base (i.e., 40 Ω)

2,591.793 + j83.3746

= 2,593.1336 % on 100 MVA base

Line-to-ground fault current =

2593 .1336

100

(4,630 A)

= 178.54 A

Note: Use the constants for fault calculations to convert from ohms to 

percent impedance on a particular voltage base, e.g.,

40 + j0 Ω @ 12.47 kV (line-to-line)

64.31 %/Ω

2572.4 + j0 % @ 12.47 kV (line-to-line)

(5) Fault Current Calculations. While a complete discussion of per unit or 

percent quantities is beyond the scope of this bulletin, Table 3.5 gives a 

short review of the various quantities. Both the percent and per unit 

methods of calculation are simpler than using actual amperes, ohms, 

and volts.5

The discussion in Table 3.5 is based on the constants for fault current 

calculations for commonly encountered voltages in Table 3.6 of this 

Design Guide.

Table 3.5. Discussion of Per Unit and Percent Values

1. DEFINITION:

P.U. apples = actual # of apples P.U. ohms = actual ohms

base # of apples base ohms

P.U. current = actual amperes

base amperes

 

5 Power System Analysis by John Grainger, Jr., and William Stevenson, McGraw-Hill, 1994.
RUS Bulletin 1724E-102

Page 25

P.U. values 100 = % values

%V = P.U. I. %Z P.U. V = P.U. I P.U. Z

2. P.U. IMPEDANCE:

P.U. Z = actual ohms

base ohms

where

Base ohms =

rated voltage

rated current

=

LL / 3

base kV A

3 kV

V

where VLL is line-to-line voltage.

Then

Base ohms =

2

1000 (kV )

base kVA

=

2

(kV)

base M VA

P.U. Z =

2

actual ohm s

(kV )

base M V A

= 2

base M VA actual ohms

(kV)

Also

2

voltage drop across at rated 

P.U . 

rated voltage (per phase)

M V A 1000

3 kV M V A

k V k V 1000

3

Z I

Z

Z

Z

Note: %Z varies directly with the MVA base and inversely with the 

square of the voltage.

Examples:

A transformer having 10% impedance on a 20 MVA rating would have 

50% impedance on a 100 MVA base of
RUS Bulletin 1724E-102

Page 26

100

10% 50%

20

A 12.47-kV line having 1% resistance would have

%R = 1% 

13 .8

12 .47

2

= 0.816%

if the base voltage were 13.8 kV.

3. P.U. CURRENT:

P.U. I =

actual am peres

base am peres

=

L-L

load M V A 1000

3 load kV

base M V A 1000

3 base (in kV ) V

=

load M VA

base M VA

=

1

P.U. voltage

Note: P.U. I = P.U. MVA if voltage is constant.

(6) Distribution Voltage Transformation. When a line is encountered that 

incorporates an autotransformer or two-winding transformer used for 

system voltage conversion (often 7.2 kV to 14.4 kV or vice versa), there 

are several additional steps that must be taken to find the fault current 

beyond these devices.

(a) Using the procedure outlined in steps 1 through 5 in Section 

3B(2)(b) of this Design Guide, determine the resistance and 

reactance values of the total impedance (source, substation 

transformer, and distribution line) from the substation to the point 

on the line where the step-up or step-down transformer is located.

(b) Using the formula below, determine the impedance of the 

transformer in ohms. (For the purpose of this bulletin, it is 

assumed that only single-phase autotransformers or twowinding transformers will be encountered.)

Two-winding transformer or autotransformer

2 % ( )

 ( ) = 

kV A 100,000

t L

t

Z E

Z

where EL is the line-to-neutral voltage on the load side of the 
RUS Bulletin 1724E-102

Page 27

transformer, %Zt is the percent impedance of the transformer 

given at rated kVA and voltage, and kVA is the kVA rating of the 

transformer.

Resolve the impedance into its reactive and resistive components, 

either by using the formulas given below or by taking a ratio based 

on engineering judgment.

Rt = 0.2Zt Xt = 0.98Zt

(c) Reflect the source, substation transformer, and distribution line 

impedance (Z STD) determined in step a to the load side of the 

voltage transformation transformer by the appropriate method 

shown below.

(1) Step-up transformation:

Z STD load side (Ω) = (N

2

)(Z STD source side (Ω))

(2) Step-down transformation:

Z STD load side (Ω) = (1/N

2

)(Z STD source side (Ω))

where

high side line-neutral voltage

low side line-neutral voltage

N

(d) Add the distribution line resistance and reactance values from 

voltage transformation transformer location to the location of the 

fault to the R and X values obtained in steps b and c:

R total = R STD load side + R auto + R dist

X total = X STD load side + X auto + X dist

(e) Determine the fault current, using the formula below and the and R

and X values determined in step d:

line-to-ground

fault 2 2

total total

 (load side voltage)

( ) ( )

E

I

R X

To find the fault current that would appear on the source side of the

voltage transformation formula, use the appropriate formula

below:

(1) Step-down voltage transformation:
RUS Bulletin 1724E-102

Page 28

Source-side fault current = (1/N) (load-side fault current)

(2) Step-up voltage transformation:

Source-side fault current = (N) (load-side fault current)

An example of the method follows.

Sample Problem

Determine the three-phase fault current at point 1 in the diagram. The step-down autotransformer 

characteristics are 200 kVA, 14.4 to 7.2 kV, % Z = 2.63.

69 kV 24.9/14.4 kV 10.0 mi

 4/0 ACSR

 Zst Autotransformer

7.2 kV 1/0 ACSR

2.0 miles X Point 1

Zdist = (0.441 + j0.712) (10) = 4.41 + j7.12 Ω, obtained from Table 3.3.

Step a:

Zst = 0 + j3.6 given by supplier

Zdist = 4.41 + j7.12

Zstd = 4.41 + j10.72 Ω @ 14.4/24.9 kV

Step b:

Zauto load side = 

2

(% ) ( )

(kVA ) (100, 000)

L

Z E

= 

2

(2.63)(7200)

(200 kVA )(100, 000)

= 6.82 Ω

Rauto = (0.2)(Zauto) = 1.36 Ω

Xauto = (0.98)(Zauto) = 6.68 Ω

Zauto = 1.36 + j6.68 ohms

Step c:

Zstd loadside = 

2

1

N

(4.41 + j10.72) = 

2

(2)

1

(4.41 + j10.72) = 1.1 + j2.68

Where N = 

7.2

14 .4

 = 2
RUS Bulletin 1724E-102

Page 29

Step d:

Rdist = (2.0 mi) (.855 ohms/mi) = 1.77 ohms

Xdist = (2.0 mi) (.756 ohms/mi) = 1.51 ohms

Zstd = 1.10 + j2.68

Zauto = 1.36 + j6.68

Zdist = 1.77 + j1.51

Ztotal = 4.23 + j10.87

Step e:

I 3φ fault = 7200/

2 2

(4.23 ) (10 .87 )

= 

11 .664

7200

= 617.3 A

I3φ = 617.3 A

The same procedure should be followed for a step-up autotransformer or two-winding 

transformer.

(7) Fault Current on Supply Side. A fault anywhere on the load side of the

substation causes a current to flow on the supply side. To determine the 

supply side current, use the following formulas. Note that Is is not 

necessarily the same in all three phases. The formulas give the maximum 

supply currents in any one phase.

(a) For line-to-ground fault:

(L-L)

L L

s

s

E I

I

E

(b) For three-phase fault:

(L-L)

3 L L

s

s

E I

I

E

(c) For a line-to-line fault:

(L-L)

2 L L

s

s

E I

I

E

(8) Plotting the Sectionalizing Circuit Diagram. After the calculation of

short-circuit currents has been completed, the calculated values should be 

placed on the circuit diagram at each sectionalizing point and at the 

end of lines. The maximum three-phase fault current and the maximum 

line-to-ground fault current should be shown on the circuit diagram at 

every location where a sectionalizing device is installed. The minimum 

line-to-ground fault current should be shown at the end of each zone of 

protection and at the end of each single-phase and three-phase line.
RUS Bulletin 1724E-102

Page 30

Table 3.6. Constants for Fault Calculations

Voltage 

(kV), lineto-line or 

phase-to 

phase

Base amperes,

Three-phase 

amperes/100 

MVA

Percent/per Ohm Ohms/1%

500 kV 100,000 KVA

√ 3 × 500 kV

___

115.5A x √ 3 × 100%

500,000

1 Ohm

.0400 %

500 115.5 0.040 25.0

230 251 0.189 5.29

169 342 0.351 2.85

161 359 0.386 2.59

115 502 0.756 1.32

110 525 0.827 1.21

100 577 1.00 1.00

69 837 2.10 0.476

66 875 2.30 0.436

46 1255 4.73 0.212

44 1,312 5.17 0.194

38 1,519 6.92 0.144

34.5 1,673 8.4 0.11906

25 2,310 16.00 0.0625

24.9 2,319 16.13 0.06199

24 2,406 17.36 0.0576

20 2,887 25.00 0.0400

19 3,039 27.7 0.0361

18 3,208 30.87 0.0324

13.80 4,184 52.51 0.0190

12.47 4,630 64.31 0.0155

8 7,217 156.25 0.0064

7.20 8,019 192.9 0.00518

6.90 8,368 210.1 0.00476

6.60 8,748 229.6 0.00436

4.80 12,028 434.0 0.00230

4.16 13,879 577.9 0.00173

2.30 25,103 1,890 0.000529

0.600 96,228 27,778 0.0000360

0.575 100,412 30,246 0.0000331

0.480 120,285 43,403 0.0000230

0.240 240,570 173,611 0.00000576
RUS Bulletin 1724E-102

Page 31

4 TYPES OF SECTIONALIZING DEVICES

a Introduction. If the goal of sectionalizing is to economically minimize the

number and duration of outages seen by customers, then the tools of 

sectionalizing must be understood and judiciously applied. “Economically 

minimize” would suggest that there is a point of diminishing return on investment 

to combat outages. It is impossible to eliminate outages completely, so the goal 

of the protection engineer and system planner is to understand and best apply the 

resources available. The following is a brief discussion of some of the most 

common tools used on rural distribution systems and their characteristics.

b Circuit Breakers. Circuit breakers can have vacuum, oil, SF6 gas, or air as an

interrupting medium. Currently, in the distribution market, a vast majority of 

breakers sold for feeder protection are vacuum interruption circuit breakers. The 

construction and testing by manufacturers for medium-voltage circuit breakers are 

defined by a number of national and industry standards (including ANSI, IEEE, 

NEMA, and others). When used for distribution feeder protection, they are 

normally controlled by time-overcurrent relays and reclosing relays. Circuit 

breakers require an external power source for closing and tripping. Advances in 

relaying have resulted in a marked increase in the functionality and information 

that relays can offer.

c Automatic Circuit Reclosers. Automatic circuit reclosers have been used

successfully on rural circuits for many years. Reclosers are available with a wide 

range of current and voltage ratings and are suitable for use on virtually all 

distribution circuits.

(1) Series Coil Reclosers. The original concept of reclosers was to provide a

self-contained, low-cost tripping and reclosing circuit interrupter, which 

could be used economically for pole-mounted protection of distribution 

feeders.

This type of recloser is commonly referred to as a “series-coil” recloser. 

These reclosers employ a series coil that causes tripping of the recloser at 

approximately two times the continuous current rating of the coil. They 

can be either single-phase or three-phase devices. They may employ 

either a hydraulic timing mechanism for time-delayed operating curves or 

may feature a hold-closed method of operation after the fast curve 

operations. Some of the heavy-duty three-phase or single-phase models 

may use a closing solenoid connected between phases or from phase to 

neutral. Series coil reclosers are used in both substation and line 

applications.

(2) Non-Series-Coil Reclosers. Some three-phase reclosers require an

external power source for tripping and closing. This type of recloser is 
RUS Bulletin 1724E-102

Page 32

commonly referred to as “non-series-coil” recloser. Reclosers that are 

electronically controlled are more versatile and more easily modified. 

They do require a power source for operation, which usually is an AC 

source if used on the line, or they may use DC from a battery bank if used 

in a station. This type of recloser closely resembles a circuit breaker in its 

function and operation. Three-phase reclosers with advanced controls are 

similar in functionality and information recording to electronic relays, and 

are routinely used in stations as feeder protection.

(3) Types of Electronically Controlled Units. Automatic circuit reclosers 

come in a variety of single-phase electronically controlled units, which 

offer a wide variety of coordination options and reporting functions.

Likewise, electronically operated three-phase units are now available that 

can be configured for single- or three-phase trip or lock-out operations, 

and which offer improved flexibility in sectionalizing, reliability, and 

SCADA schemes.

d Automatic Line Sectionalizers. An automatic line sectionalizer is an oil, air, or

vacuum switch that automatically opens to isolate a faulted section of line. It 

employs either a hydraulic or electronic counting mechanism, which is actuated 

by a system overcurrent and an upline circuit breaker or recloser tripping action. 

Unlike other overcurrent protection devices, a sectionalizer does not operate on a 

time-current curve. 

(1) Automatic line sectionalizers are used principally in branch circuits where:

(a) Small loads or little circuit exposure will not justify reclosers

(typically sectionalizers are less expensive than reclosers).

(b) It is desirable to establish an automatic sectionalizing point but

time-current curve coordination with other sectionalizing devices 

would be difficult or impossible.

(2) Automatic line sectionalizers are available as either three-phase or singlephase devices. They are not rated to interrupt fault current and, therefore,

must be used in conjunction with upline reclosers or circuit breakers 

capable of sensing and interrupting minimum fault currents beyond the 

sectionalizer. The recloser or circuit breaker must sense a fault and 

perform the circuit tripping and fault-clearing operation. The sectionalizer 

counts the preset number of recloser or breaker trips and senses minimum 

fault current through the sectionalizer. After both conditions are met, the 

sectionalizer automatically locks open during the open circuit time of the 

breaker or recloser. A sectionalizer may be used for switching loads 

within its load-interrupting rating.

e Line Switches. Line switches typically do not have overcurrent characteristics,
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but are extremely valuable in the operation of a distribution system, especially in 

the restoration of service. For very long or heavily loaded circuits, line switches 

can be used in conjunction with automatic circuit reclosers to help isolate 

problems and restore service to as many customers as possible.

Sectionalizing studies should consider the prevention of outages as well as 

measures to partially restore service, especially along main feeders. Line 

switches can be individually operated or gang-operated, load-breaking or nonload-breaking, and manually operated or remotely operated through SCADA 

systems. Load-break gang-operated switches are typically located at open points 

between feeders and substations to facilitate switching load between areas for 

maintenance or restoration. Non-load-break switches are economically beneficial 

in locations where main feeders go cross country or through heavily treed rightsof-way or just past a load center; they can be used to isolate the part of a circuit 

requiring repair, allowing the feeder to be reenergized to that point.

f Fused Cutouts. Fused cutouts are the most economical means of isolating

sections of faulted lines on rural distribution systems.

(1) Currently, the standard fused cutout is very popular and used for fusing 

line taps, underground take-offs, capacitor banks, and distribution 

transformers. The cutout is versatile:

(a) It can be used with one barrel for fuse applications under 100 A.

(b) With a larger fuse barrel, it can be used for applications of 100 A 

to 200 A.

(c) It accepts a solid blade that can be used as a line disconnect switch 

carrying up to 300 A of continuous current.

(2) Fused cutouts are also routinely used as a bypass mechanism for automatic 

circuit reclosers. While the cutout itself is a non-load-break device, a 

hotstick tool can be used to break load or the cutout can be purchased with 

a load-break attachment.

Typically, expulsion fuse links are used in cutouts because of their 

economy and versatility. Several types of expulsion fuses are available 

with differing curves for different applications. However, several 

manufacturers also provide a current-limiting fuse that can be used in a 

cutout for specific applications. There is available a sectionalizer (see 

functionality above) that fits in a cutout and opens after sensing a fault.

g Current-Limiting Fuses. Current-limiting fuses are relatively expensive

compared to expulsion-fused cutouts. They are also more difficult to apply since 

the engineer must consider not only their continuous current rating, but also their 
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maximum (and sometimes minimum) voltage rating and their ability to interrupt a 

current in less than one-half cycle. Industry standards define both “general 

purpose” and “backup” current-limiting fuses. In general, where current-limiting 

fuses are being considered, the backup type will usually prove more desirable 

than the general-purpose type unless the general-purpose fuses have time-current 

curves that nearly parallel those of expulsion fuses.

(1) Advantages of Backup Current-Limiting Fuses. The advantages of backup

current-limiting fuses are: 

(a) No changes in existing fusing principles or methods are required 

for coordination.

(b) The majority of faults should blow only the expulsion fuse, which 

is chosen to coordinate with the current-limiting fuse.

(2) Disadvantage of Backup Current-Limiting Fuses. A disadvantage of

backup current-limiting fuses (CLF) is that it must be used with a 

coordinated expulsion fuse. If an expulsion fuse larger than the one for 

which the CLF has been designed to coordinate is employed, the CLF may 

attempt to interrupt a current below its ability to clear, resulting in a 

burned-up fuse and a likely system fault.

(3) Justification to Use Current-Limiting Fuses. Current-limiting fuses, even

though they are expensive, can often be justified such as for:

(a) Fusing Distribution Transformers on Overhead Circuits Where 

Available Fault Current is High. Engineering judgment is required 

in this regard because the probability of disruptive transformer 

failure is related not only to the available fault current, but also to 

the rated interrupting current of a transformer internal under-oil 

expulsion fuse and/or the tank pressure withstand ability.

(b) Fusing Underground Cables and Associated Equipment. In the 

case of underground equipment, current-limiting fuses may be 

justified even where fault current is not high. Since a CLF 

operates without expulsion action, it can be placed in a confined 

space. For underground applications, either a general-purpose or a 

backup CLF with an under-oil expulsion link can be employed 

successfully.

h Power Fuses. Power fuses can be current-limiting, conventional expulsion, or

boric acid types. They have higher interrupting ratings than distribution fused 

cutouts and are, therefore, seldom applied on distribution circuits unless the 

available fault current is extremely high. Power fuses find their largest 

application as transformer bank protection or the high-side fuse for relatively 
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small distribution substation transformers. They usually have a maximum voltage 

rating of 138 kV and the fuse links are generally E rated.

i Circuit Switchers. A circuit switcher is a high-voltage load-switching and faultinterrupting device that usually—but not always—incorporates a disconnect 

switch function in the switching operation. Voltage ratings will generally cover 

all distribution power transformers.

(1) Limitations. It should be recognized that a circuit switcher is not a circuit

breaker. It has a fault-interrupting rating less than the smallest standard 

rating for circuit breakers and it does not have high-speed reclosing 

ability. A further limitation is that there are no provisions for mounting 

current transformers.

(2) Usefulness. Even though a circuit switcher has some limitations, it is

well-suited for protection of substation transformers against secondary and 

internal faults, switching transformer magnetizing current, load dropping, 

capacitor bank switching, cable switching, and switching both series and 

shunt reactors.

j Underground Sectionalizing Devices. Underground distribution systems are fed

either directly out of a substation or fed from an overhead distribution line. These 

systems have evolved into almost distinct higher-current and lower-current 

systems. Manufacturers generally rate components at 200 or 600 A. There are 

exceptions, but for the most part these are the primary conventions.

(1) 600-A Underground System. The sectionalizing devices used in 600-A

backbone underground systems are generally pad-mounted or submersible 

switches that may have fused or automatically opening tap points to 

connect to the 200-A system.

(2) 200-A Overhead System. When a 200-A system is fed directly from an

overhead system, the most common sectionalizing device protecting the 

main line is a riser pole (or pothead) fuse. Occasionally, automatic 

devices such as reclosers are used to provide protection to the overhead 

system from underground faults when greater flexibility is desired (which 

comes at a substantially higher cost).

(3) 200-A Underground System. When a 200-A system is fed (tapped) from 

an underground 600-A system, a fuse scheme or automatic opening 

scheme within a pad-mounted or submersible switch is the primary 

sectionalizing device. Operationally, the sectionalizing device commonly 

used to manually isolate problems or equipment on 200-A systems is the 

dead front load-break elbow.

k Fault Indicators. Fault indicators can be extremely valuable tools in locating
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faults and restoration efforts. Fault indicators are typically available to fit certain 

diameters of wire and can be manually or automatically reset. For automatic reset 

indicators, typically current or voltage is used to determine if the fault is cleared. 

Various factors will determine which type is selected for specific applications. 

Fault indicators are especially helpful on underground systems in locating faults 

on the underground primary and allowing service to be restored to most or all of 

the remaining system.

l Intelligent Electronic Devices. Advances in solid-state relays have provided

additional sectionalizing tools to the distribution engineer by making more 

information available to perform sectionalizing functions automatically or by 

remote control. For instance, intelligent electronic devices (IEDs) can 

approximate the location of a fault for faster response time. They have an infinite 

number of relay settings, e.g., curves, to make coordination more effective. These 

new devices also make it possible to dynamically change settings to suit a variety 

of conditions. Indirectly related to sectionalizing, they also record three-phase 

amperes, watts, and VARs; monitor power quality; and provide fault analysis 

information.

5 APPLICATIONS OF SECTIONALIZING DEVICES

a General Guidelines. In applying sectionalizing devices to electric distribution

systems, four tasks need to be accomplished to assure safe and reliable electric 

operations:

Choose appropriate locations for line devices.

Select the proper type of device to handle the available fault duty (maximums 

and minimums).

Select the proper size of device to handle the peak load currents.

Select and set the time-current characteristics (TCC) to coordinate both with 

the upline sectionalizing devices and the downline devices.

(1) Prerequisites. In order to accomplish each of these tasks, an accurate map 

and validated computer model of the electric system model must be 

developed. Applying sectionalizing and protective devices without such 

information can result in inadequate system sectionalizing and protection. 

These prerequisites include the following:

Maps showing the correct conductor sizes, lengths and phases, and 

normal open points.

Maps showing the accurate location of large critical commercial and 

industrial loads with peak load conditions.

Maps showing the current location of all sectionalizing devices and 

their sizes and types.
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Models with system fault calculations based on current source 

impedances and conductor sizes and lengths.

Models with anticipated fault calculations for the next 3 to 4 years.

Models with current loading conditions that have been validated by 

field measurements (e.g., feeder breaker or recloser ampere reading, 

line voltage regulator voltage and current readings, end-of-the-line 

voltage readings at peak conditions).

Models with projected future loading conditions based on approved 

load forecast or power requirement studies.

(2) Device Location. Before applying any sectionalizing device to a system, 

the system engineer should identify the proper and appropriate locations 

for each device. This is more of an art than a set procedure. Choosing a 

location is based on many factors and the circumstances may change as 

the system operational characteristics change. Device placement is 

selected to isolate faulted portions of the system from the rest of the 

system and to assist operating personnel in the location of the fault.

(a) Line Fuses. Line fuses are typically applied at locations that are:

(1) Short single-phase taps off main three-phase feeder lines, 

or

(2) Single-phase lines with less than 20 amperes of peak load.

(b) Line Reclosers. Line reclosers are typically applied at locations 

that are:

(1) Single-phase lines with greater than 20 amperes of peak 

load,

(2) Three-phase branches,

(3) After large industrial and commercial loads, or

(4) Locations to cover the calculated minimum down-line fault 

conditions.

(c) Line Sectionalizers. Line sectionalizers are typically applied at 

locations that are:

(1) Downline from line reclosers where minimum fault 
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conditions are met, or

(2) Downline from line reclosers where normally a line 

recloser is installed and, generally, on the ends of feeders.

(d) Uses. Typically, single-phase reclosers are used on most 

moderately loaded line applications. Three-phase devices are 

usually utilized on heavily loaded three-phase lines where ground 

fault relays are needed to cover the minimum calculated fault 

conditions. A full discussion on locating devices is included in 

Section 5C(2)(b) in this Design Guide.

(3) Maximum and Minimum Fault Currents. A distribution system 

experiences both underground and overhead fault conditions regularly. It 

is neither economical nor practical to design a system that would eliminate 

all system faults. Faults can be caused by a number of sources,

including—but not limited to—the following:

Weather (e.g., wind, lightning, ice, high temperatures),

Equipment failure,

Trees,

Public contacts with both overhead and underground lines (by digging,

in the latter case),

Animals,

Automobile accidents, and

Vandalism.

(a) Faulted Conditions. Faulted conditions can present a hazard to the 

public and utility personnel, and can cause damage to electric 

system equipment. Protective systems are applied to sense these 

faulted conditions and to limit the consequences by clearing the 

fault in a timely manner. Since most of the faulted conditions on a 

distribution system are temporary in nature, line devices are often 

applied that provide for reclosing. This results in improved system 

reliability and improved service to the ultimate consumer.

(b) Calculation of System Fault Conditions. System fault conditions 

are calculated on the basis of (1) the available source impedance 

from the power supplier (e.g., the G&T) and (2) the system 

impedance of all line devices to the point of the possible fault. The 

maximum fault conditions are calculated without any fault 

impedance and represent the highest level of current expected at a 

given line point. Such calculated levels can be used to establish 

the interrupting capability of the sectionalizing device that is to be 

applied.
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For a typical electric distribution system served by a delta/wye 

power transformer, the maximum fault at the substation bus is the 

line-to-ground fault. Moving downline on the feeder, the 

maximum three-phase and phase-to-phase-to-ground faults are 

higher and are used for sizing sectionalizing devices.

(c) Minimum Fault Resistance. Minimum faults, as stated earlier, are 

calculated by adding an estimated fault resistance to the available 

source impedance. The fault resistance is based upon the judgment 

of the system engineer or consultant and will represent the 

minimum fault current levels that are expected on the system. This 

judgment is usually based on the history of high-resistance fault 

conditions experienced on the system. The minimum levels are 

utilized to establish necessary line protective device pickup levels.

See Exhibit A for a sample model printout showing the 

calculations of fault currents and loading conditions from an 

engineering model.

(4) Maximum Load Currents. The maximum load current levels on all system 

line components are typically based on the most recent peak loading 

conditions that occurred on the system. This is often called the “base 

system.” These levels are based on peak-month consumer energy sales 

and allocated by using computer engineering model software. The 

resulting loading calculations should reflect the maximum loading 

conditions that have been experienced on the system.

(a) Planning the Sectionalizing System. In planning the sectionalizing

system, one must not only use the maximum load calculations 

from the base system, the maximum conditions should also be 

calculated for the anticipated future load conditions. Such 

conditions are determined from the current approved load forecast. 

The future system peak conditions should identify the maximum 

anticipated loads that need to be served by the future sectionalizing 

system.

(b) Peak Conditions. It is not unusual for a distribution system to 

experience two annual peak conditions. One condition could be 

for the summer and one for the winter. If such peaks are long in 

duration (longer than 2 or 3 hours per year), they both should be 

modeled and reviewed for the proper sizing of the line devices.

When line devices for maximum load conditions are sized, device 

manufacturers should be contacted for the overloading capability 

of each device. Such ratings can be considered in the sizing of the 

line devices.
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(5) Device Coordination. Device coordination means choosing characteristics 

for a line device so that it can experience a faulted condition outside its 

zone or range of protection without being tripped and still operate 

appropriately to clear the fault when it experiences a fault condition inside

its zone of protection. Effective line sectionalizing requires that line 

device time-current characteristics have proper separation and devices 

work independently when faults are in their respective zones. Section 

5C(4) in this Design Guide describes the separation requirements and how 

coordination can be achieved.

b Guidelines for Substation Overcurrent Protection. The following is information

that highlights high-side devices used to protect distribution power transformers.

(1) Power Transformer Protection

(a) High-Side Devices. High-side devices are primarily used to 

protect distribution power transformers are fuses, circuit switchers, 

and breakers. Regardless of the protective device selected, the 

primary function of the device is to protect the transformer. The 

goal is to minimize the amount of time the transformer is subjected 

to fault current. The considerations that need to be taken into 

account in selecting a protective device are the size and voltage of 

the transformer and economics.

(1) Fuses. Fuses are the least expensive option but can be 

limited in performance. They are usually used on smaller 

units of 10,000 kVA or less and voltages of 69 kV or less. 

There are some applications where fuses are used for larger 

units and voltages, but these are less common.

(2) Circuit Switchers. The next option for transformer 

protection on the economic scale is the circuit switcher. 

The circuit switcher is considered a “dumb” device in that 

it does not contain the intelligence to operate by itself. 

These devices require relays to sense fault conditions and 

provide a trip signal to the circuit switcher before it will 

operate. The circuit switcher and relay combination is usun 

for ally used in substations with transformer sizes above 

10,000 kVA and/or having high-side voltages of 69 kV or 

higher.

(3) Breakers. Breakers are the third and usually most

expensive option for transformer protection. These 

devices, like the circuit switchers, are considered to be 

dumb and require relaying to provide detection and tripping 
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intelligence. Breakers are usually used on larger 

transformers and for higher voltages.

(b) Relaying Strategies. Relaying strategies used to protect 

transformers usually consist of a high-speed differential scheme as 

the primary protection and an overcurrent scheme to provide 

backup protection. Depending on the design scheme, the 

differential relay may protect only the transformer or may 

incorporate the secondary bus of the substation. Differential relays 

are based on the principle that power in is equal to the power out. 

When the power in does not equal the power out, and the resulting 

differential exceeds a certain threshold, then the relay trips.

(1) Overcurrent Relay Schemes. The overcurrent relay 

schemes commonly used consist of phase overcurrent 

relays on the high side of the transformer and a ground 

relay on the secondary side in the neutral of the 

transformer. The relays are usually set by taking into 

account the size of the transformer, its overload capability, 

and the coordination with the substation distribution feeder 

devices. Other considerations that should be taken into 

account consist of the amount of expected imbalance on the 

secondary side and the size of the regulators being used.

(2) Phase Overcurrent Relays. The phase overcurrent relays 

are usually set by taking into consideration the size and 

overload capability of the transformer; ANSI C57-91 

provides valuable information. It should be kept in mind 

that not all transformers are the same. Substations utilizing 

autotransformers will not have as high an overload 

capability as two winding transformers. Because of their 

construction, autotransformers do not have the short-circuit 

through-fault capability of a two-winding transformer. In

coordinating the phase overcurrent with the distribution 

feeder, the shift in the time-current curves for the devices 

due to the difference in the high-side and low-side voltages 

needs to be taken into account.

(3) Ground Overcurrent Relays. The ground overcurrent relay 

must be coordinated with the distribution feeder device 

ground protection. It also should take into account the 

single winding capability of the transformer. While the 

balancing of feeders is a goal of a well-operated 

distribution system, a certain amount of imbalance can be 

expected at the substation. Any expected imbalance should 

be taken into account in determining the setting for the 
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ground overcurrent relay to prevent the relay from tripping. 

The size of the voltage regulators should be considered in 

order to protect them from overcurrents.

(4) Other Relay Devices. Other devices that can be included in 

a scheme to protect the transformer are oil-level, suddenpressure, and high-temperature relays. These relays are 

usually internal to the transformer and can be used to trip 

the high-side protective device. Settings for these relays 

are usually specified and set by the manufacturer at the 

time the transformer is specified.

(c) Low-Side Devices

(1) On the low side, bank or station breakers may be used. 

Some substation designs may utilize a secondary bus 

device. These may be fuses, reclosers, or breakers. If 

something other than a fuse is used, then the device is 

usually set up for one shot to lockout. A bus device must 

coordinate with the high-side protective device and the 

distribution feeder devices.

(2) Alternatively, low-side protection may consist of feeder

breakers or reclosers only.

(d) Protective Relays. The choices are:

(1) Differential relays,

(2) Backup overcurrent relays,

(3) Sudden-pressure relays, and

(4) Combustible gas monitoring relays.

(2) Feeder Current Protection

(a) Breaker Versus Recloser Utilization

(1) A question that is often raised by the system engineer is

what type of device should be utilized in the substation on 

the substation feeders. The options are generally either 

breakers or reclosers. The question then arises, “Which 

device is better?” The answer can be diverse when the 

various device manufacturers are asked. The real question

is not which device is better but which device can handle 

the fault and peak load duty and which device is more 

economical.
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(2) Breakers and reclosers are really two distinct device types

manufactured under different ANSI standards. Breakers 

typically have higher current interrupting ratings and also 

can support much higher continuous load currents. 

Breakers typically are built as power class equipment with 

higher basic impulse levels (BILs) and, therefore, are 

usually larger in size than a recloser. Breakers have 

limitations on number of reclosures and, according to ANSI 

Standards, should be derated under certain operating 

conditions. Refer to the applicable ANSI breaker standard 

to identify their limitations.

(3) Reclosers have traditionally been more economical and

offered more options for time-current characteristics 

(TCCs) with available electronic controls. With the 

introduction of intelligent electronic devices (IEDs), more 

TCC options are now available for breakers.

(b) Three-Phase Versus Single-Phase Reclosers

(1) Single-phase hydraulic reclosers are sometimes still being

used by rural power distributors as feeder protection. They 

are inexpensive and reliable. Such practices are 

discouraged, however, as these devices do not provide the 

flexibility in coordination with downline devices nor do 

they provide the best protection for ground and minimum 

fault conditions.

(2) One argument that is given for using single-phase devices

is that, if a fault is on one phase only, the other two phases 

can remain energized until the fault condition can be 

repaired. This improves system reliability. This is not a 

bad practice if it is limited to electric systems that have 

relatively low current levels and have no three-phase loads 

on the feeder.

Triple-single reclosers are now available with such 

flexibility and they come with ground-fault sensing and 

tripping.

(c) Coordination with the Source Device

(1) Most substation feeders utilize either single-phase reclosers

or three-phase reclosers or breakers. In either case, 

coordination with the source protective device can be 

complicated and is influenced by many variables. For the 
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most part, the feeder device is required to coordinate with a 

protective fuse on the source side of the power transformer 

or with protective relaying that may be either 

electromechanical or electronic.

(2) Coordinating with high-side fuses can be accomplished by

using a method based on time-current characteristics curves 

adjusted by multiplying factors to compensate for fuse 

preloading, ambient conditions, and the number of 

reclosures of the line protecting device. Source-side fuses 

are selected to protect the electric system from a power 

transformer fault and to protect the power transformer from 

a secondary bus fault. Once the fuse size has been 

determined, the feeder recloser or breaker curve or curves 

can be evaluated and selected.

(3) The circuit recloser or breaker must be selected to

coordinate with the source-side fuse link so that the fuse 

does not blow for any fault on the load side of the feeder 

device. The cumulative heating effect of the recloser or 

breaker operations must be less than the damage 

characteristics curve (minimum melt) of the fuse link. This 

is accomplished through the use of multiplying factors on 

the recloser or breaker TCC curves that identify the damage 

or fatigue point of the fuse link. The modified delayed 

curve must be faster than the source-side fuse’s minimummelt curve.

(4) TCC curves are used to coordinate the feeder recloser or

breaker with the source-side fuse link utilizing the 

following rule:

For the maximum available fault current at the recloser or 

breaker location, the minimum melting time of the fuse link 

on the transformer’s source-side must be greater than the 

average clearing time of the recloser/breaker’s slowest 

response curve(s), multiplied by a specific factor. The 

multiplying factors (often called “K” factors) for various 

reclosing intervals and operating sequences are published 

by fuse and recloser manufacturers. The factors range 

from 1.35 to 3.7 depending on the TCC curves of the 

recloser or breaker and the reclosing intervals selected.

(5) One other condition that needs to be considered in

coordinating source-side fuses (and relay TCC curves as 

well) is when there is an unsymmetrical transformer 
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connection (delta/wye). The ratio of primary to secondary 

fault current will be different when plotting the TCC curves 

depending on the type of secondary fault realized (threephase, phase-to-phase, and phase-to-ground). The 

following ratio factors are used to determine the amount to 

shift the fuse curve(s) to reflect the TCC response to the 

secondary of a delta/wye transformer:

Fault Type Ratio Factor

Three-phase N

Phase-to-Phase 0.87N

Phase-to-Ground 1.73N

“N” is defined as the power transformer ratio of the source 

phase-to-phase voltage to the load phase-to-phase voltage.

(6) Since the phase-to-phase fault condition will result in the

tightest coordination with the source-side fuse, it should be 

used in assuring coordination between the devices and 

protecting the fuse for a secondary fault. Another way of

saying this is that a secondary phase-to-phase fault 

produces the greater amount of source-side current for a 

given amount of secondary current. Therefore, plotting and 

reflecting the source-side fuse TCCs using the secondary 

phase-to-phase ratio factor produces a fuse TCC curve to 

the far left, resulting in the worst case condition where the 

minimum melt curve of the fuse should be protected.

(7) Similar steps are required when coordinating secondary

reclosers or breakers with substation source-side backup 

overcurrent relays. As with fuses, the TCC curves of the 

relays are selected that will provide protection to the 

electric system for a power transformer fault as well as 

protection of the transformer for a secondary substation 

fault. Once the source-side relay TCCs have been selected, 

the feeder recloser or breaker TCC curves can be reviewed 

and selected for proper coordination.

(8) When source-side relays are used, generally the system

engineer is required to coordinate the high-side overcurrent

relays as well as backup ground relays off the neutral 

bushing of the power transformer. Care should be 

exercised if source-side instantaneous pickups have been 

selected. Normally, if instantaneous pickups have been 

chosen for the high-side backup overcurrent, they should be 

set for slightly less than the maximum reflected low-side 
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available phase-to-ground fault to assure coordination with 

the low-side feeder recloser or breaker settings. Also, it is 

recommended that NO instantaneous pickup be utilized for 

the backup ground relay. If used, miscoordination is likely 

to occur with the feeder protective devices unless set so 

high that the functionality of the instantaneous setting is 

questionable.

(9) One significant dilemma in coordinating with source-side

electromechanical relays is dealing with relay disk 

movement, coasting, and reset times. When a fault occurs, 

the electromechanical relay disk moves toward the closed 

position, and it will “coast” for a short time if the fault is 

interrupted or removed by the downline protecting device. 

This additional movement is typically called coasting time 

or impulse margin time (IMT). Impulse margin times are 

published for various types of electromechanical relays and 

can vary from 0.03 to 0.06 seconds. This margin time needs 

to be allowed for in the relay response to assure proper 

coordination with the downline feeder recloser or breaker.

(10) The time that should be added to the relay response is

called the “minimum fault time (MFT).” It is calculated 

using the following formula:

MFT = ROT – IMT

where ROT is relay operating time at a specific fault level 

or the maximum fault level, and IMT is impulse margin 

time. Once calculated, the MFT can be added to the source 

relay response time or the feeder device to check for proper 

clearance and coordination.

(11) Reset times of electromechanical relay disks are another

matter that needs to be considered when defining feeder 

recloser or breaker settings. Electromechanical relay disks

take an extraordinary amount of time to reset to their time 

lever or dial position. Depending on the manufacturing 

type and response speeds, the reset times vary from 25 to 

35 seconds at the mid-time dial position. This is critical 

when multi-shot protection schemes are used, which is 

what most electric systems utilize for feeder protection.

(12) When checking coordination with source-side relays,

several methods can be used, each having their own degree 

of complexity. For a single-shot (non-reclosing) feeder 

recloser or breaker condition, one method is to just add 0.3 
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seconds to the feeder device clearing time; the source relay 

time must have a greater response time than this. This is a 

conservative and more simplistic approach. A more 

accurate approach is to add minimum fault times to the 

clearing time of the feeder device and check for clearance 

and coordination. Either of these approaches allow for 

tolerances, variations due to temperature, plus any other 

variables.

(13) For coordinating multi-shot (reclosing) feeder or breaker

plans with source-side electromechanical relays, the 

method of checking coordination is much more 

complicated and important. One simple and conservative 

method is first to add all times of the sequence and 

compare the sum to the relay curves. If the added feeder 

device responses are to the left of the source-relay on the 

TCC plots, coordination exists. This method is extremely 

conservative and does not account for resetting of the relay 

disk between operations. It may not be a realistic approach 

for many applications.

(14) A more accurate method is to calculate the actual relay disk

travel for each trip and reclose operation of the feeder 

device, add recloser or breaker timing—plus impulse 

margin times—for each trip, and subtract the relay reset 

time for each reclosing interval. Calculating the total times 

as a percentage of relay travel will identify if coordination 

of the feeder recloser or breaker to the source-side relay 

will occur. If the total times are greater than 100%, the 

feeder recloser or breaker does not coordinate with the 

source-side relays and will result in the substation being 

tripped offline, causing an outage. This can be corrected by 

changing the last reclosing interval on the feeder device to 

a longer time, allowing the source electromechanical relay 

to reset more fully to attain adequate coordination between 

devices.

(15) Fortunately, with the development of static and/or

electronic relays and controls, life for the system protection 

engineer is becoming somewhat simplified. The need to 

coordinate with electromechanical relays is declining 

greatly as the new “intelligent electronic devices” (IEDs) 

are replacing the old forms. With such devices, relay and 

device responses are much easier to predict and can be 

more easily modified to assure proper coordination 

between devices.
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(16) As a rule of thumb—when not having to worry about

electromechanical complexities, and where static or 

electronic relays are present—adequate coordination 

between a feeder recloser (or feeder breaker) and the 

source-side protective device can be attained if the

minimum separation of the feeder response and the sourceprotecting device response is greater than 30 cycles (or 0.5 

seconds). Closer separation can be allowed if more precise 

TCC studies are accomplished where curve tolerances, 

device responses, reclosing intervals, and other variables 

are included for the specific application being reviewed. A 

tool that can be used to attain such coordination is the 

instantaneous pickup function, if available in the feeder 

recloser or breaker controls, applied at the proper level to 

assure the desired separation mentioned above.

(17) When feeder protection devices are equipped with both

phase and ground protection, another aspect of coordination 

of feeder devices to source-side devices is to realize the 

composite TCC response of the ground and phase trip 

settings. In other words, when checking and confirming 

coordination, it is not required to look individually at phase 

responses and ground responses. They should be viewed as 

TCC responses working together for the purposes intended. 

With a majority of line faults being phase-to-ground, the 

ground current relay is going to “see” the fault the same as 

the phase relay, and the ground relay will respond quicker. 

This means that the coordination of the phase relay by itself 

with the source-side device is not required and 

unnecessary.

(18) The system protection engineer is encouraged to refer to

system protection manuals and standard methods for details 

of the processes described above, as such are beyond the 

scope of the guide.

(d) Coordination with the Load Device(s)

(1) As stated earlier, typical electric distribution substations

utilize single-phase hydraulic reclosers or three-phase 

reclosers or breakers to protect substations from feeder 

faulted conditions. Over the last 10 years, electric systems 

have moved more and more away from the use of singlephase hydraulic reclosers. This is due to feeders having 

higher load currents and the need for ground trip protection.
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(2) For substation feeders utilizing single-phase hydraulic

reclosers, to assure proper coordination and no 

simultaneous operations, the separation between the feeder 

recloser and the downline single-phase recloser must be 

greater than 12 cycles at the maximum fault conditions at 

the downline device. From 2 to 12 cycles, possible 

simultaneous operations may occur. Less than 2 cycles 

separation means simultaneous operations will occur and 

there is not proper coordination.

(3) For feeder devices with electromechanical overcurrent

relays, the same coordination steps described in the earlier 

section must be followed. Minimum fault times, relay 

operating times, impulse margin times, and disk reset times 

must all be used to assure proper coordination.

(4) For feeder reclosers or breakers with electronic or static

relays or controls, coordination can more easily be set and 

established. Time current characteristics can be modified 

and set to adjust feeder device responses that will 

coordinate with whatever downline devices that may be in 

operation.

(5) As a rule of thumb—when not having to worry about

electromechanical complexities and where static or 

electronic relays or controls are present—adequate 

coordination between a feeder recloser or breaker and the 

downline protective devices can be attained when there is a 

minimum separation or margin of the downline feeder 

device response and the source-protecting device response 

is greater than 21 cycles or 0.35 seconds for the maximum 

fault at the downline location. Closer separation can be 

allowed if more precise TCC studies are accomplished 

where curve tolerances, device responses, reclosing 

intervals, and other variables are included for the specific 

application being reviewed.

(6) The system protection engineer is encouraged to refer to

system protection manuals and standard methods for details 

of the processes described above, as such are beyond the 

scope of this guide.

c Guidelines for Overhead Line Protection. One of the key components of a

reliable electric distribution system is the proper application of line sectionalizing 

devices. Proper application will assure reduced outage times and minimize 
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system damage due to overcurrent conditions. The following comments provide 

guidelines in the proper application of line sectionalizing devices.

(1) Line Devices. There is a wide variety of line devices available to the

system engineer for sectionalizing an electric distribution system. The 

devices are ever-changing, bringing operational and maintenance benefits 

as technology advances to fulfill the needs of the industry. Currently, the 

devices that are available are as follows:

Line reclosers (single-phase and three-phase),

Line sectionalizers (single-phase and three-phase),

Line fuses (expulsion and current-limiting), and

Line switches (single-blade and group-operated).

(a) Line Reclosers (Single-Phase and Three-Phase). Line reclosers are

a self-contained device with the necessary circuit intelligence to 

sense overcurrent conditions, to time and interrupt the overcurrent, 

and to reclose automatically to reenergize the line. If the fault is 

“permanent,” the reloser will “lock open” after a predetermined 

number of operations (usually three or four) and, thereby, isolate 

the faulted section of distribution line from the main part or source 

of the system.

(1) Most faults on overhead distribution systems are temporary

in nature and last only a few cycles or seconds. Statistical 

studies of distribution systems show that approximately 70 

to 80% of overcurrent conditions on overhead lines are 

temporary in nature. Automatic line reclosers, with their 

trip and reclose capability, eliminate prolonged outages on 

distribution lines due to temporary faults or transient 

overcurrent conditions.

(2) Automatic line or circuit reclosers are classified on the

basis of single- or three-phase, hydraulic or electronic 

controls, and oil or vacuum interrupters. Each type has its

advantages.

(3) With the high cost associated with oil maintenance, there is

a trend toward utilization of reclosers that have vacuum 

interrupters. Selecting vacuum interrupters increases the 

length of the maintenance cycle and reduces maintenance 

costs.

(4) Single-phase line reclosers are used typically for protection

of single-phase lines, such as branches or taps off threephase lines. They can also be used on three-phase circuits 
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where the load is predominantly single-phase. This allows, 

when a permanent phase-to-ground fault occurs, one phase 

to be locked out while service is maintained to the 

remaining two-thirds of the system.

(5) In the past, single-phase reclosers have been primarily

hydraulically controlled. In recent years, more and more 

single-phase reclosers have been electronically controlled. 

Such configurations offer greater flexibility in line 

applications and coordinate more precisely with upline and 

downline devices. Such devices are considerably more 

expensive and have not been utilized extensively in the 

rural electric distribution industry. As technology improves 

and the costs become more reasonable, it is expected that 

more single-phase, electronically controlled reclosers will 

be utilized.

(6) As mentioned earlier, very often on rural electric

distribution lines, three single phase reclosers are installed 

on three-phase lines. Such applications are on lines with 

relatively low peak loads, have very few large three-phase 

loads, and phase-to-ground fault levels are not very low.

(7) Three-phase line reclosers are used where lockout of all

three phases is required for any permanent fault, to prevent 

single phasing of three-phase loads such as large threephase motors. Three-phase reclosers with a ground trip 

accessory are also utilized when line load currents are high 

and minimum fault current levels are very low. In such 

cases, the three-phase reclosers are equipped with neutral 

sensing circuitry using current pickup levels much lower 

than the line phase currents. Three-phase reclosers have 

two modes of operation: single-phase trip/three-phase 

lockout and three-phase trip/three-phase lockout.

(8) Single-phase trip/three-phase lockout is obtained with three

single-phase reclosers mounted in a single tank with 

mechanical interconnection for lockout only. Each phase 

operates independently for overcurrent tripping and 

reclosing. If any phase operates to the lockout condition,

the mechanical linkage trips the other two phases open and 

locks them open. This then prevents extended single-phase 

energization of three-phase loads.

(9) Most other three-phase reclosers operate through the threephase trip/three-phase lockout mode. For any fault, all 
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contacts open simultaneously for each trip operation. The 

three phases are mechanically linked for tripping and 

reclosing, and are operated by a common mechanism.

(10) Some manufacturers are now selling three-phase reclosers

that can do single- or three-phase trip with single- or threephase lockout. These are configured to the user’s 

requirements through electronic controls.

(11) Reclosers can be purchased with hydraulic or electronic

controls. The uses of three-phase hydraulically controlled 

reclosers have declined over the years. The industry has 

deferred to the electronically controlled devices, which 

offer improved flexibility in application (added timecurrent characteristics), provide for better ground fault 

protection, and are more precise in coordination with other 

line devices.

(b) Line Sectionalizers (Single-Phase and Three-Phase). A line

sectionalizer is a protective device that automatically isolates 

faulted sections of line from a distribution system. Normally 

applied in conjunction with a backup recloser, a sectionalizer does 

not have any fault-interrupting capability of its own. Rather, it 

counts the operations of the backup device during faulted 

conditions and, after a preselected number of current-interrupting 

operations and while the source or backup device is open, the 

sectionalizer opens to isolate the faulted section of line. This 

allows the source or backup device to reclose into the remaining 

unfaulted portion of lines, thus restoring the lines to service.

If the fault is temporary, however, it will be cleared by the 

source/backup device prior to the sectionalizer count to lockout, 

and the sectionalizer will remain closed. Then the sectionalizer 

automatically resets to prepare for another complete cycle of 

operations should a new fault occur.

(1) Compared to fuse cutouts, which do, of course, have full

interrupting capability, sectionalizers provide several 

advantages that, depending on the application and the 

particular utility’s approach to overcurrent protection, can 

offset a higher initial cost. These advantages include 

application flexibility, convenience, and safety.

(2) After a permanent fault, for example, the fault-closing

capability of a sectionalizer greatly simplifies testing of a 

circuit, and if the fault is still present, interruption takes 
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place safely at the backup recloser. Since replacing fuse 

links is not required, the line can be tested and restored to 

service with far more speed and convenience. Also, the 

possibility of error in selecting the size and type of fuse is 

eliminated.

(3) In addition to providing the general advantages just cited,

sectionalizers are particularly suitable for two applications 

where time-current characteristics (which sectionalizers do 

not have) might pose coordination problems:

(a) Sectionalizers can be used between two protective 

devices with operating curves that are close 

together. This is a vital feature in locations where 

additional coordination steps are impractical or 

impossible.

(b) They can be used on close-in taps where high fault

magnitude prevents coordination with fuses or use 

of expensive high-interrupting fault reclosers.

(4) Sectionalizers are available in single- and three-phase

versions controlled by hydraulic or electronic counting 

mechanisms.

(5) Sectionalizers do have high momentary current ratings,

providing for safe closing operations on faulted lines.

(c) Line Fuses (Expulsion and Current-Limiting). Line fuses are the

most basic protective device available for line overcurrent 

protection on distribution systems. Their primary function is to 

serve as an inexpensive means to protect equipment against

overloads and short circuits.

(1) Fuses are available in a variety of types, offering a wide

variety of time-current characteristics. The basic types are

expulsion fuses and current-limiting fuses. Expulsion fuses 

are utilized more extensively in distribution systems than 

current-limiting because of cost and operational needs.

(2) Expulsion fuses serve as expendable, inexpensive “weak 

link” protective devices used on distribution lines with 

cutouts. That is, fuse links are components that are 

replaced after providing the desired protection to 

equipment and/or distribution lines. Properly coordinated 

with backup reclosers, fuses can help reduce the total cost 
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of sectionalizing equipment without reducing service 

reliability or increasing operational and maintenance 

expenses.

(3) Fuses follow basic time-current characteristics that are

described in a set of two curves. Minimum melt curves 

describe the current and time characteristics that are 

necessary for melting of a fuse to begin. Once melting has 

occurred, the fuse is considered to be damaged and,

therefore, can no longer be relied on to function in the 

manner that is expected of a new fuse. Total clear curves 

describe the current and time characteristics that are 

necessary for the fuse to fail, thus clearing a fault.

(4) Expulsion fuses can be grouped into types that have similar

time-current characteristics. These types are typically 

designated by a letter. Often these types are referred to as 

the “speed” of a fuse. Typical fuse types used in the 

electric distribution industry, from the fastest to the 

slowest, are N, QA, K, T, S, and KS. Refer to Figure 5.1

for a summary of the total clear characteristics of a 50-A

fuse for various speeds. The most popular fuse for 

coordinating with hydraulic line reclosers is the Type T.

Figure 5.1. Time Current Characteristics (50-Amp Fuse 

Comparisons)
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(5) Current-limiting fuses (CLFs) are typically utilized on

electric systems that have very high fault conditions. They 

are generally used to protect equipment such as distribution 

transformers, capacitor banks, and other devices on the 

system where available faults may result in catastrophic 

failures. With the improved design of distribution 

transformers and capacitor banks for applications at higher 

fault current locations, the use of CLFs has declined. For 

systems with loads very sensitive to voltage fluctuations, 

CLFs are used to limit fault current levels, reducing 

undesirable line voltage flicker. CLFs are generally very 

high in cost, so decisions to use them should be closely 

scrutinized.

(d) Line Switches (Single-Blade and Group-Operated). One does not

usually find line switches listed as sectionalizing devices on 

electric distribution systems, but they are important sectionalizing 

tools for aiding in power restoration. One of the key objectives of 

proper sectionalizing is to provide a means for isolating system 

faults from the rest of the system so that power can be restored. 

Related to this objective is to have line switches located on the 
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electric system where portions of the system can be clearly isolated 

(visible break) as well as to provide a means whereby loads can be 

transferred to other system sources until the faulted lines can be 

repaired. Single-phase and three-phase switches should be 

carefully placed on the system to allow for such system operations.

(2) Considerations for Sizing and Locating Devices

(a) Application Based on Valid System Model. Before considering 

the application of any line sectionalizing device, accurate 

knowledge of true system conditions must be determined and 

available to the system engineer. Without such information, 

system damage is sure to occur and service reliability will be poor.

(1) It is critical that the following system conditions are

accurately determined and/or calculated before the 

installation of any sectionalizing device:

(a) System configuration (line conductor sizes, number

phases, voltages, opens and substation boundaries, 

substation feeder numbers and service areas, etc.);

(b) Location of critical loads (e.g., large power, large

commercial and industrial plants, hospitals, schools,

nursing homes);

(c) Available fault currents; and

(d) Peak line/load currents.

(2) System configuration is demonstrated primarily from the

mapping system. The mapping system provides 

information to help determine each of the above items. If 

the system is old and not adequately maintained, steps 

should be taken to update and field verify what the current 

electric system characteristics are. Geographic information 

systems (GIS) are available to help analyze electric system 

conditions and to aid in maintenance and management. 

This tool can be invaluable in the proper operation and 

maintenance of sectionalizing devices. In addition, GIS is 

constantly improving and, with improved communication 

techniques, live or real-time system monitoring can be 

attained, providing a means for quick responses to system 

outages and line problems.

(3) The location of critical loads and consumers can be

determined generally from the service personnel in the field 

and the customer services department. These people can 

provide insight into where sectionalizing devices need to be 
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placed. In planning system protection and sectionalizing, 

knowledge of such locations is critical. Sectionalizing 

devices are placed to eliminate exposure of critical loads,

assuring minimized interruption and reliability of service. 

Such loads should be clearly indicated on system maps for 

sectionalizing system planning and outage response. No 

system can guarantee 100% reliability, but every 

reasonable effort should be put forth to maintain service to 

priority consumers.

(4) Available fault currents are calculated from the source

impedances as provided by the distributor’s power supplier. 

Calculations of system conditions are based on this 

information, and the method for calculating such values is

discussed earlier in Section 3B of this Design Guide. The 

important point here is that the information from the 

supplier should be current and validated by official means. 

“By official means” implies in written official form, and it 

is desireable that it be provided from a registered 

professional engineer. The information should include, as a 

minimum, the positive-, negative-, and zero-sequence 

impedances on, typically, a 100 MVA base at a specified 

point on the electrical system (i.e., high side of a substation, 

low side of substation, or point on a distribution meter 

point).

(5) In addition to requesting this information, inquiries should

be made to the power supplier as to any impedance changes 

that are expected over the next 2, 3, or 4 years (typically the 

period of a construction work plan). Such information will 

enable the distribution system engineer to design the 

protection system for the future worst-case scenario. 

Source impedances can change dramatically when there are 

significant changes in the transmission system (i.e.,

conductor upgrades, loop feeds, new generating plants, 

etc.), as well as changes in the substation (i.e., power 

transformer uprating, source voltage change, low-side 

voltage change). Such changes should be included in the 

planning of a sectionalizing system and incorporated in all 

system improvements.

(6) Finally, the last critical aspect of the system that needs to

be known is the line load currents. Often, such accurate 

information is the most difficult to secure. The reason is 

that the load currents vary with system conditions (i.e.,

summer, winter). Typically, the values are first calculated 
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from a system computer model built around an accurate 

mapping system, accurate consumer load data, and accurate 

substation service area boundaries for the time of the load 

data. The calculated values and model should then be 

validated from actual field-recorded peak voltages and 

currents. Such values can be recorded from installed digital 

recording voltmeters at selected key line locations (e.g.,

circuit extremities with high voltage drops, key circuit 

branch points) and from digital line voltage regulator 

controls. From the field-measured values, the system peak 

model conditions can be validated for use in the design of 

the protection system and application of sectionalizing 

devices. It is extremely important that the model accurately 

reflect the realities of the system.

(b) Location Selection

(1) After a valid system model has been developed, the 

preferred and best location of the overhead line 

sectionalizing devices can be determined. Starting from the 

substation feeder device to the end of the circuit, the 

following guidelines can be utilized in the location of line 

sectionalizing devices:

(a) Identify any zones of protection.

(b) Locate priority loads and install sectionalizing

devices downline to eliminate exposure and

improve reliability.

(c) Identify key branch points and install devices such

that service to the higher load branch or both 

branches can be maintained.

(d) Locate points on the distribution feeder where the

minimum calculated fault conditions are below

substation feeder minimum ground pickup level and

install a suitable device at that location or upline.

(e) Install devices at locations that are easily accessible

for operations.

(f) Locate taps off main lines that are either long,

through wooded areas, or inaccessible.

(2) Typically, sectionalizing devices are located on the electric 
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system for primarily two objectives:

(a) To eliminate line exposure for high loads or load 

groups (branch circuits), and

(b) To have enough devices on the system to aid in the 

location and isolation of faulted lines.

This will enable system operating and construction 

personnel to restore electric service in a timely fashion. 

Following the guidelines listed above will enable the 

system engineer to accomplish these objectives.

(3) After locating application points for reclosers, it is 

important to locate sites for the application of line switches. 

These points can be determined from the computer model 

and the mapping system. Sites where loads can be 

transferred to alternative sources should be identified and 

line switches installed to allow for easy transfer when line 

problems occur.

(4) The main purpose for the switches is to provide such 

operational flexibility, but also to provide visible breaks 

when line repairs are being made. A general guide is to 

locate these sites as follows:

(a) Adjoining substation circuit tie points,

(b) On main circuit branches,

(c) Just downline from key feeder loads, or

(d) Adjacent to feeder tie points.

(c) Selecting Equipment Type and Current Rating

(1) Once system conditions have been identified and validated

with a computer model, and after locations have been 

selected to produce the desired operational results outlined 

above, the particular sectionalizing device can be selected. 

Typically, reclosers or sectionalizers are utilized on lines 

that have the highest loads, have the most customers, and 

justify the highest expenditures for reliability. Lines with 

the lowest loads and fewest consumers will use fuses. 

Reclosers and sectionalizers are also installed to aid in fault 

location and power restoration.

(2) Line reclosers (either three-phase or single-phase) are the

most expensive sectionalizing device, with single-phase
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sectionalizers being close behind, leaving fuses as the least 

expensive device.

(3) With such devices, the following conditions have to be met

in selecting the type and size of the equipment.

(a) The device must have the insulation level suitable 

for the line voltage to which it is to be applied.

(b) The device must have the continuous current rating

to carry the projected peak load conditions and any 

anticipated load shifts. The rating should be 

selected to allow for load growth over at least the 

next 3- to 5-year period.

(c) The device must be able to interrupt the maximum

fault current calculated at the point of application.

(d) The device must respond to the minimum calculated

line-to-ground fault to the end of the line or to the 

next downline device.

(e) The device must coordinate with downline devices.

(f) The device must coordinate with upline devices.

(4) Insulation levels are usually based on rated withstand test

voltage, which is expressed as basic impulse level (BIL) in 

kilovolts. The typical ratings for distribution equipment are 

95 kV BIL for 12.5 kV systems, 125 kV BIL for 25 kV 

systems, and 150 kV for 35 kV systems. Equipment with 

higher BIL can usually operate on lower-voltage systems. 

Engineers are encouraged to coordinate such applications 

with the manufacturer before equipment installation to 

identify any limitations and operational problems.

(5) When one discusses peak load conditions, questions usually

arise as to what “peak” means. It could be the peak for 

winter, the peak for summer, the projected probable peak 

from the RUS load forecast, or even the extreme peak 

found in the RUS load forecast. It is the system engineer’s 

task to select the peak that will adequately protect the 

system in conjunction with the duration of the peak. For 

systems that routinely experience extreme summer and 

winter conditions, sectionalizing devices should be applied 

for such a peak. However, if extreme peaks are infrequent 
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and have a duration that is very short, then the normal or 

probable peak projections could and should be utilized. 

Electric systems in the extreme south generally have 

extreme winter conditions that last only a few days or even 

hours. In such cases, applying sectionalizing equipment 

based on the normal/probable or extreme summer load 

projections is economical and practical. This means that,

for short periods of time, line devices may have to be 

bypassed until the short-duration peak conditions have 

passed.

(6) Line devices also typically have overload factors identified

by the manufacturers. If such factors have been identified 

by the manufacturers, short-term operation overloads can 

be allowed without serious damage occurring to or 

improper operation of the device. The system engineer is 

encouraged to be familiar with these overload factors 

before sizing any sectionalizing device.

(7) One of the most serious mistakes in the application of

sectionalizing devices is to install them at locations where 

they do not have the interrupting rating to clear the 

maximum calculated fault. Such actions can result in 

rupture of the device, possible fire on the pole and the 

ground, and possible injury of individuals who might be 

standing below the device or in the vicinity. It is important 

that the system engineer carefully apply sectionalizing 

devices so that they have the capacity to safely interrupt the 

maximum fault calculated.

(3) Time-Current Curve Selection

(a) Protective devices are said to be coordinated when the device

closest to the fault location interrupts the line fault current without 

causing upline devices to permanently open or lock out. 

Coordination is achieved by proper selection of fuse size, trip coil 

ratings for hydraulic reclosers, or minimum trip current values in 

electronic and relay-controlled reclosers. The selection of the 

proper fuse size, trip ratings, or settings is determined by 

comparing the time-current curves (TCCs) of the upline and 

downline devices.

(b) Time-current curves of fuses and hydraulically controlled reclosers

are generally of similar shapes, which can simplify the 

coordination process. However, the limited selection of these 

curves can also make it harder to achieve the desired level of 
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coordination. Relay-controlled and electronically controlled 

reclosers have a large variety of settings and can be closely 

coordinated with other devices, but the wide range of settings can 

make the process more complicated.

(c) Several of the major protective device manufacturers publish

reference manuals that discuss device characteristics and 

coordination methods in detail. Contact your manufacturer’s 

representative to obtain copies of the texts and carefully review 

them before beginning a coordination study.

(4) Coordination

(a) Relay and Electronic Control

(1) Relay Control. Electromechanical or electronic relays are

used with three-phase breakers in substations or other 

applications that require devices capable of interrupting 

high levels of fault current. Electromechanical relays have 

several characteristics that must be considered for 

coordination with a downline device.

For time-delayed tripping, the relay contains a disk that 

begins moving toward the closed position when line current 

exceeds the relay’s minimum trip setting. When the disk 

fully rotates, it closes a set of contacts that causes the 

breaker to trip. When timing for a fault current, the relay 

disk moves toward the closed position, and it will continue 

to rotate (coast) for a short time after it is deenergized if the 

fault is interrupted by a downline device. This additional 

rotation is called the coasting time or impulse margin time. 

The downline device must clear the fault in sufficient time 

to prevent the coasting action of the disk from causing the 

relay to unnecessarily trip.

Likewise, electromechanical relays typically do not reset 

immediately after deenergization because the disk requires 

time to return to its original position. If the downline 

device is a recloser, the relay disk may not have time to 

fully reset during the reclosing interval. Under this 

condition, the disk will accumulate, or advance its rotation,

toward contact closure with each reclose action, also 

causing the relay to unnecessarily trip. Downline reclosers 

must allow a sufficient reclosing interval to allow the relay 

to reset, or allowances must be made in the relay settings to 

compensate for the accumulated disk travel.
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One commonly overlooked characteristic of relaycontrolled devices is the control response curve associated 

with the interrupting device clearing time. The clearing 

time of the interrupting device (also called the interrupting 

time) must be added to the control response time to 

determine the average clearing time. Relay trip settings can 

be adjusted using current tap and time dial settings to 

produce a variety of time-current characteristics. Refer to 

the relay manufacturer’s literature to determine the 

available settings, including the coasting and reset times, 

for the relay in question.

(2) Electronically Controlled Reclosers. Electronically

controlled reclosers are available for single- and threephase applications. They are commonly used not only in 

substations but throughout the distribution system. These 

devices can be coordinated closely with downline devices 

since there is no coasting or override in the electronic 

device. If the downline device, with its plus tolerance, 

clears faster than the response time of the electronic control 

with its negative tolerance, then the devices will coordinate.

As with relay-controlled devices, the clearing time of the 

interrupting device (also called the interrupting time) must 

be added to the control response time to determine the 

average clearing time.

For coordination with downline devices, it should be 

understood that when the control response curve of an 

electronic control is exceeded, the interrupting device has 

been committed to trip, regardless of the total clearing time. 

Thus, control response curves of both fast (instantaneous) 

and time-delay curves should be compared with downline 

sectionalizing device operating curves. As an example, the 

control response curve, including tolerance of the timedelay curve, must lie above the maximum clearing curve, 

including tolerance, of a load-side recloser or fuse if 

coordination is required.

When an electronic recloser is coordinated with an upline 

device, the clearing time of the interrupting device must be 

added to the control response time, plus tolerances, to 

check coordination with the upline device. Clearing times 

and TCC tolerances are usually listed on the manufacturer’s 

TCC sheet for the device.
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Reclosing intervals and resetting intervals may require 

coordination with other devices in applying electronic 

reclosers. When the recloser is used downline of a fuse, for 

example (in a substation application), the reclosing time 

may need to be lengthened to allow fuse cooling between 

recloser operations.

(b) Single-Phase Recloser with Single-Phase Recloser

(1) The simplest method of coordinating reclosers in series is

to choose the same make and style of recloser and then to 

select reclosers in descending coil sizes. Usually, adjacent 

coil sizes will coordinate satisfactorily if the reclosers are 

not spaced too closely. However, if load current or fault 

current at the substation is high, it may be uneconomical to 

use the higher-interrupting-rated recloser throughout the 

entire circuit. When reclosers of different make or type are 

used in series, it will be necessary to plot the time-current 

characteristic (TCC) curves of each recloser in order to 

determine coordination.

(2) Coordination by merely selecting adjacent coil sizes can

frequently be achieved with hydraulic reclosers of different 

make or type. However, this should be checked by 

comparing TCC curves. The fast curves may have different 

slopes and speeds but, in most cases, it is usually not 

possible to coordinate fast curves on hydraulic reclosers.

(3) When comparing TCC curves of adjacent reclosers, it is

important to maintain sufficient separation between the 

curves to avoid simultaneous operation of the two devices. 

Generally, separation of less than 2 cycles will result in 

simultaneous operation; separation of 2 to 12 cycles may

result in simultaneous operation; and separation of more 

than 12 cycles will assure coordination. Refer to the 

manufacturer’s recommendations to ensure that the 

coordination will be achieved for the devices in question.

(4) It is possible to coordinate series reclosers by electing

different time-delay operating curves or a different number 

of operating sequences. This generally is not 

recommended, however, except in special cases where 

coordination cannot be achieved otherwise. It is good 

practice to standardize on a particular time-delay curve and 

operating sequence for all line reclosers on a system. (This 
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does not necessarily apply to substation reclosers. The 

demanding requirement of substation protection and 

coordination can often be met by special selection of curves 

and sequences for each station or feeder.) Experience has 

indicated that a sequence of two fast curve operations 

followed by two time-delay curve operations followed by 

lockout is a good choice for line reclosers. However, some 

system operators may wish to standardize on one fast and 

either two or three time-delay curves. In high-lightningincidence areas, it may be advantageous to use three fast 

curves followed by a time-delay curve.

(c) Single-Phase Recloser with Fuses. Coordination of reclosers with 

source-side fuse links is most often encountered when the fuse is 

protecting the high-voltage side of a transformer and the recloser is 

on the low-voltage side.

(1) To coordinate the recloser with an upline fuse, the

cumulative heating effect of the recloser operations must be 

less than the minimum-melting curve (or damage curve) of 

the fuse. The time value of the recloser delayed curve is 

multiplied by a heating factor (also called the K factor) to 

account for the heating effect. The K factor will vary with 

the reclose timing and the fast-slow sequence of the 

recloser. Refer to the recloser manufacturer’s data to 

determine the K factor for the device in question.

(2) Coordination of reclosers with load-side fuse links is

usually done to permit the recloser to clear temporary faults 

beyond the fuse and to force the fuse to blow on permanent 

faults. This is commonly referred to as “fuse saving.”

Coordination is determined by plotting the time-current 

curves of both the recloser and fuse. As previously 

discussed, the reclose operations of the recloser will cause 

heating in the fuse, therefore the time value of the 

recloser’s fast curve must be shifted to account for the 

heating effect.

(3) If only one fast curve is used on the recloser, a 1.25

multiplying factor is used. If two fast curves are used, a 

1.35 multiplier is used for reclose times of 60 cycles or 

longer and a 1.8 multiplier for reclose times less than 60 

cycles. Both fuse curves, minimum melt and maximum 

clearing, should be plotted. The fuse curves should lie 

between the shifted fast curve and the time-delay curve 

over all or most of the range of available fault current. 
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Tolerance should be allowed for recloser time-delay curves. 

Because of the shape of the curves, it may not be possible 

to achieve perfect coordination over the entire fault current 

range. In general, EEI-NEMA Type T fuse links provide 

the widest range of coordination with hydraulic reclosers.

(4) It is desirable to employ recloser fuse combinations that

will allow the recloser to sense a minimum calculated fault 

at the end of the line. However, if this is not practical, the 

fuse should melt for an end-of-the-line minimum fault in 

approximately 20 seconds or less.

(d) Fuse Link to Fuse Link Coordination. Many branch lines can be 

most economically protected by fused cutouts.

(1) It is desirable that they be coordinated with and protected 

by reclosers as previously described. It is sometimes 

practical to apply, in series, two fuse links with different 

ratings protected by one recloser.

(2) At other locations, it may be more economical to provide 

only permanent fault protection by coordinating fuse links 

in series. It is best to limit the number of branch line 

sectionalizing fuses in series to two or three.

(3) It is recommended that the same make or type fuse link be 

used throughout a system. The EEI-NEMA Type K or T 

links are preferable, since they are standardized and are 

available from several suppliers.

(4) When coordinating sectionalizing line fuses in series, the 

following factors should be considered:

(a) Peak load currents at the point of application should 

be less than the fuse link rating. The fuse link must 

be large enough to withstand inrush currents to 

motors, capacitor banks, and transformer banks. In 

addition to these transients, which last only a few 

cycles, consideration should be given to cold-load 

pickup, which can last several seconds to several 

minutes. Some fuses are rated for a higher 

continuous current than the name might suggest. 

Therefore, it is important to consult the 

manufacturer’s specifications regarding fuses.

(b) The fuses should be coordinated with each other by
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applying the 75% rule. This means that the loadside fuse maximum clearing curve should not 

exceed 75% of the source-side fuse minimum 

melting curve.

(c) The fuse links should be coordinated with the burndown characteristic of the conductors in the fuse 

zone of protection.

(d) A fuse link should melt in approximately 20

seconds or faster for a minimum fault in its zone of 

protection.

(5) Identification of High-Reliability Zones

(a) Because of the widespread use of microprocessor-based devices in

homes and businesses, consumers are highly sensitive to the 

momentary outages that occur during recloser operations. These 

outages can cause clocks to reset, digital controls to malfunction, 

and computer systems to crash. Although recloser operations are a 

normal, and necessary, part of the protection scheme, many 

consumers find them objectionable and will begin to question the 

reliability of the electric system if they occur too frequently.

(b) To increase the reliability of a particular feeder, efforts must be

made to decrease the number of momentary outages affecting the 

circuit. However, as noted in Section 5C(4)(c) of this Design 

Guide, downline reclosers or fuses can cause the upline main 

feeder recloser to operate on its fast curves before the downline 

device clears the fault. These additional operations increase the 

number of momentary outages and decrease the reliability of the 

entire downline circuit. Therefore, a high-reliability zone can be 

established beginning with the substation feeder recloser and 

extending downline to the first mainline recloser.

(c) To begin establishing a high-reliability zone, the substation

protection device should utilize an electronic control with sequence 

coordination features. Sequence coordination enables the recloser 

to suppress its fast-trip operations in response to a fault beyond a 

downline recloser. All taps in this zone need to be protected by a 

fuse or recloser. The substation fast trip curves and all tap fuses 

should be coordinated to cause the fuse to blow before the recloser 

trips on its fast curve. This scheme is known as “trip-saving,” as 

opposed to the fuse-saving scheme discussed in Section 5C(4)(c)

of this Design Guide. A trip-saving scheme will cause a 

permanent outage on the tap for faults beyond the fuse, but will not 
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cause the upline recloser to operate.

(d) Another tool available for use in a high-reliability zone is the

single-phase electronic recloser. These devices are available with 

sequence coordination, and can be configured for single-phase trip 

with three-phase lockout, single-phase trip with single-phase 

lockout, or three-phase trip with three-phase lockout. Because 

these devices can operate in single-phase mode, faults affecting 

one or two phases will not cause momentary outages on the 

unaffected phases, resulting in better overall reliability.

(e) This high-reliability zone concept can be extended out on the

feeder. As noted, it will require use of electronic reclosers capable 

of sequence coordination and careful selection of recloser trip 

curves and fuse curves to achieve trip-saving coordination.

d Guidelines for Underground Overcurrent Protection

(1) All-Underground Circuits

(a) If a circuit is completely underground, it should be assumed that

there can be almost no temporary faults on that circuit. Therefore, 

there is little justification for automatic-reclosing overcurrent 

protective devices for the purpose of clearing temporary faults. 

Reclosing on an underground fault can worsen the damage to the 

faulted cable and can conceivably damage a sound adjacent cable. 

A one-shot sectionalizing plan using fuses, fault interrupters, or a 

combination of both can be considered, provided selective 

coordination of the devices in series can be attained.

(b) Fusing is the best solution for many underground sectionalizing

applications with relatively few consumers and/or lower load 

current. However, for higher loads and larger numbers of 

consumers, pad- and pole-mounted electronic fault interrupters 

offer a good alternative to fusing. As electronically controlled 

devices, these units offer a wider range of coordination than fuses. 

In addition, if ferroresonance is anticipated, or if single phasing of 

three-phase loads would be a problem, electronic three-phase fault 

interrupters can be used. A combination of fuses and fault 

interrupters is certainly a possibility for an all-underground 

sectionalizing plan.

(c) If coordination between fuses or older-style nonelectronic one-shot

devices cannot be assured because of load current or fault current 

conditions, consider the use of electronic fault interrupters or use 

electronically controlled reclosers set to one-shot operation. As 
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previously stated, these devices offer much more flexibility than do 

fuses or hydraulically controlled sectionalizers. If electronic fault 

interrupters or reclosers are not available, and coordination must be 

achieved, consider using a hydraulic recloser. In this case, the 

reclosers would not be used for the purpose of clearing temporary 

faults, but instead would be used to assure selective coordination 

of sectionalizing devices.

(d) While it is true that reclosing on an underground fault can

exacerbate the damage to a faulted cable and can conceivably 

damage a sound adjacent cable, it is felt that an overriding 

consideration is to selectively sectionalize the smallest section of 

cable, thereby rendering better service to consumers. The general 

rule of thumb is that it is not necessary to reclose on an 

underground fault. However, if in the judgment of the engineer, 

better service reliability to the most consumers can be expected by 

choosing an automatic reclosing device, it is preferable to do so. 

The number of reclosing operations should be held to a minimum. 

Usually one or at most two reclose operations will be all that will 

be required for coordination with other devices.

(2) Overhead to Underground Circuits

(a) Circuits with both overhead and underground construction present 

different sectionalizing problems than either a total underground 

circuit or a completely overhead circuit. It is not unusual for 

circuits to exit from a distribution substation with underground 

cable. The underground exit may extend for several hundred feet 

or for several miles before it reaches an overhead transition point. 

Overhead distribution circuits can also dip underground at any 

point and reemerge again to continue as an overhead line. 

Considerable engineering judgment should be exercised in 

selecting sectionalizing devices for these combination lines. If the 

majority of the line is underground with a small percentage 

overhead, the line can be considered similar to an all-underground 

circuit. The converse is also true. If the line is predominately 

overhead with a small part of it underground, it can be considered 

as a completely overhead system in choosing overcurrent 

protective devices.

(b) It is usually not possible to install fuses between reclosers,

although it may seem desirable to do so in certain overheadunderground circuits. An attempt to do this usually results in fuses 

and reclosers being larger than would ordinarily be selected. This, 

in turn, results in the entire coordination of time-current curves 

back to the substation being undesirably high.
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(c) A three-phase automatic line sectionalizer can be installed between

three-phase reclosers, provided the sectionalizer is equipped with 

the sensing required to permit it to count only the backup recloser 

operations. This is sometimes described as “voltage restraint.”

The advantage of a sectionalizer is that it does not operate on a 

time-current curve. The disadvantage of a sectionalizer is that it 

would probably be set for one count and is, therefore, a high-cost 

device compared to a fuse.

(d) If the expense of three-phase sectionalizers and three-phase

reclosers cannot be justified, the alternative is to treat the 

underground section of line as if it were an overhead line.

(e) Underground taps off main overhead lines usually present no

unusual overcurrent coordination problems. They can be 

economically fused. If coordination with fuses cannot be 

achieved, consideration should be given to electronic fault 

interrupters.

(3) Use of Fault Indicators

(a) Although underground cable faults are usually rare occurrences,

the time required to locate, switch lines, or repair the cable can 

result in an extended outage for the consumers. The proper use of 

faulted circuit indicators (FCIs) will enable quick identification of 

a faulted cable section and significantly reduce outage time. The 

FCI is easily affixed to the cable or elbow, and contains a sensor 

that causes a built-in target or indicator to operate when current 

exceeds a preset level. Operating personnel can quickly check 

each FCI on the circuit to determine the last point at which fault 

current was detected. Using this information, they can then isolate 

the faulted section and begin restoration work.

(b) FCI devices should be placed along the circuit at strategic points

that will allow operating personnel to determine the location of the 

faulted section and switch lines to restore service to the maximum 

number of consumers. The number and cost of placement of the 

FCI devices along a circuit should be weighed against the number 

of consumers and level of desired reliability.

(c) A number of manufacturers produce FCI devices in a variety of

configurations for overhead and underground use. FCIs are 

generally selected according to load current levels and reset 

methods. Devices can be reset manually, or configured for timedelay, voltage, or current reset. Most FCI manufacturers provide 
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detailed application notes for their products. Take advantage of 

this information to achieve the best results from these devices.

6 EQUIPMENT UTILIZATION AND MAINTENANCE

a Utilization Guidelines

(1) Tripping and Reclosing Practices

(a) In past years, rural electric distribution systems have typically

utilized three reclosures to lockout (or four trips to lockout). This 

has been for substation feeder circuit breakers or reclosers as well 

as line circuit reclosers. If substation feeder circuit breakers were 

used, instantaneous reclosure was utilized after the first trip. Timecurrent characteristics for recloser tripping have typically been two 

fast operations and two slow operations. Over the years, such 

practices have been evaluated and scrutinized. The results show

that changes appear to be warranted.

(b) According to a paper presented by the Power System Relaying

Committee of the IEEE Power Engineering Society, the practice of 

allowing instantaneous reclosures and four trips to lockout on 

substation circuit breakers is not a sound sectionalizing practice 

and, in fact, is detrimental to system operations.6 The study 

concluded that:

(1) With instantaneous reclosure on a circuit breaker, often the

breaker closes back into a temporary faulted line condition

before the fault clears itself, and

(2) The third reclosure is generally unsuccessful, contributing

to unnecessary through faults on substation power

transformers and should be eliminated.

(c) On the basis of the conclusions made in this study, the practice of

having instantaneous reclosures on substation distribution feeders 

is not recommended. Also, it is strongly recommended that all 

substation feeder breakers or reclosers have only two reclosures to 

lockout (or three trips to lockout). For further details, see the IEEE 

paper.

 

6

“An Analysis of VEPCO’s 34.5-kV Distribution Feeder Faults as Related to Through Fault Failures of Substation 

Transformers,” approved by the IEEE Power System Relaying Committee and presented at the 1978 IEEE Power 

Engineering Society Winter Power Meeting.
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(d) As mentioned earlier, with the use of digital clocks, microwaves,

videocassette recorders, DVD players, computers, and other 

electronic conveniences, there has been a trend to reduce feeder 

operations by eliminating the fast TCC response and allowing the 

downline fuses to clear the fault lines. This concept removes any 

fuse-saving policy, deferring to the elimination of nuisance—and 

often frequent—operations of substation feeder breakers or 

reclosers. This practice is in line with the high-reliability zone 

policy mentioned above. Such a policy is strongly recommended 

to the system engineer in the development of a sectionalizing 

system.

(2) Use of Relay and Control Targets. Whenever there is an outage on the 

line, operational personnel are anxious to get the power back on as soon as 

possible. Often valuable information is ignored or lost in the process, 

information that can be obtained by reading and recording of relay and 

control targets that are on substation relays and feeder controls. Noting 

such information can provide valuable information in the location and 

identification of faulted conditions. Timely location can result in timely 

power restoration. It is strongly recommended that the system engineer 

establish a policy that, whenever there is an outage anywhere within a 

distribution substation, all targets on relays and controls be noted and 

recorded for current and future use.

(3) Fault Locating. New circuit breakers and reclosers are being purchased 

with new intelligent electronic devices (IEDs). Such devices provide 

event information regarding the faulted condition and can aid operating 

personnel in the type and location of the fault. System engineers are 

encouraged to purchase such devices for their feeder breakers and 

reclosers and to utilize the information provided with the device.

b Recloser Maintenance Guidelines

(1) Oil Versus Vacuum Interruption. Line circuit reclosers have served 

distribution systems well for decades. Most of the reclosers used in the 

past have been reclosers that utilized oil as the interrupting medium. 

Utilizing oil for interrupting over time contaminates the oil, causing 

different TCC responses and, eventually, costly maintenance. Over the 

last 10 years, vacuum interruption technology has improved and,

currently, vacuum interrupting devices are considered to be a more 

economical means for sectionalizing. Vacuum line reclosers have greater 

duty cycles than oil interrupting devices and should hold their designed 

TCCs longer than devices that use oil interruption. When purchasing new 

line reclosers, the system engineer is encouraged to compare the life cycle 

economics of oil versus vacuum. Vacuum devices have proven 

economical because of their longer duty cycle and reduced maintenance 
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costs.

(2) Maintenance and Scheduling

(a) Substation Breakers and Reclosers with Electromechanical Relay 

and/or Electronic Controls

To maintain reliable electric service, routine testing, inspection,

and maintenance are required on all sectionalizing equipment. 

This is especially true when it comes to substation equipment and 

the protective relays and controls utilized. If these devices are not 

routinely checked and tested, major outages are sure to occur. 

Major equipment damage is also likely to occur, costing hundreds

of thousands of dollars. Power transformer failures have been 

known to occur as a result of inadequate equipment maintenance. 

It is a priority that should be established by the system engineer.

Typical circuit breakers and circuit reclosers should be tested and 

maintained about every 4 to 5 years. Generally speaking, over that 

period of time, electromechanical devices drift and require 

recalibration. Also, batteries in electronically controlled reclosers 

require testing and/or replacement. So a 4- to 5-year maintenance 

cycle is good for planning purposes on substation equipment.

Generally, there are two ways that such maintenance can occur:

(1) Method 1: Full system maintenance every duty cycle 

period. Method 1 calls for the substation equipment to be 

tested and maintained every established duty cycle (e.g., 

every 4 or 5 years). Under such a method, the maintenance 

costs can be very high for the scheduled year and may take 

a considerable time to complete, depending on the number 

of substations that the cooperative has. It normally takes 

approximately a week to test and check out two or three 

substations. Under such a method, if financial constraints 

require a delay, such maintenance is often delayed.

(2) Method 2: Partial system maintenance every year. Method 

2 calls for a percentage of the system substations to be 

tested and maintained every year. The percentage is 

determined by the established duty cycle period. For 

example, if the duty cycle has been established at 5 years, 

then 20% of the system substations are to be tested and 

maintained every year. If a system has 12 substations, then 

three substations should be scheduled each year.
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If Method 2 is selected, it is important that it be started after having 

completely testing all substations. This will assure safe and proper 

operation of the equipment for the duty cycle, which is necessary 

for reliable electric service. Method 2 also spreads the 

maintenance costs over the duty cycle period, which greatly helps 

the cooperative’s financial bottom line.

(b) Line Reclosers. One sectionalizing dilemma that has to be

addressed by the system engineer is how to maintain all the line 

reclosers on the system. Recloser manufacturers typically 

recommend that line reclosers be removed and maintained about 

every 5 to 6 years. Line recloser maintenance is typically 

accomplished under one of the following plans:

(1) Plan A: Maintain reclosers by substation service areas. 

Under Plan A, reclosers are removed and replaced from 

designated substation service areas every year. If a 

cooperative has established a 6-year duty cycle, then 

approximately 17% (1/6 = 16.7%) of the substation service 

area reclosers need to be removed and replaced every year. 

If the cooperative has 12 substations on the system, then 

two substation service area reclosers are to the replaced and 

maintained annually.

(2) Plan B: Maintain reclosers as needed according to

established duty cycles for each recloser type. Under Plan 

B, individual reclosers are monitored and maintained as 

needed. The need is established by two parameters: (1) the 

number of operations, and (2) the number of years since the 

recloser was last maintained. If a recloser has exceeded the 

established number of operations (operations duty cycle), it 

should be marked for maintenance. Also, if a recloser has 

not exceeded its established operations duty cycle but has 

not been checked in the established maintenance year cycle 

(device interval duty cycle), then it should be maintained.

Under this plan, recloser counts need to be recorded and 

reclosers need to be closely monitored when maintained in 

order that acceptable operation duty cycles can be 

established for each recloser type. It is not unusual for the 

higher-interrupting-type reclosers to have a considerably 

longer operation duty cycle than the lower-capacity 

interrupting devices. It is also characteristic that operation 

duty cycles vary between cooperatives. This is because of 

device loading and available fault currents on the system.
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(3) Plan C: Maintain reclosers when they fail to operate

properly. Plan C is considered to be an unacceptable 

method for line recloser maintenance and is not 

recommended.

Plans A and B are considered to be acceptable approaches to

maintaining line reclosers. Each plan has its own advantage and 

disadvantages. They are summarized in Table 6.1.

Table 6.1. Advantages and Disadvantages of Maintenance Plans

Advantages Disadvantages

Plan A

1. Does not require recording counts of

device operations.

2. Work order/staking sheets can be 

simplified.

1. Requires a large number of 

spare reclosers.

2. Recloser maintenance does not 

necessarily follow scheduled 

substation service areas.

3. Construction work plan needs 

as a result of growth do not 

occur by scheduled substation 

service areas.

4. Maintenance costs are higher 

because of some reclosers 

being maintained 

unnecessarily.

5. Reclosers may not operate 

properly because they are not 

actually monitored 

individually.

Plan B

1. Maintenance costs are lower because 

recloser maintenance is based on need, not 

service area.

2. Fewer spare reclosers are needed.

3. Reclosers are more likely to be working 

properly because they are monitored 

individually.

4. Maintenance fits very well with 

construction work plan system 

improvement items.

1. Device operations count needs 

to be determined by field 

measurement.

2. Reclosers for maintenance are 

scattered over the entire system 

and will require more precise 

work order/staking sheets.

(3) Maintenance Specifications. A system engineer can have the best

designed sectionalizing system but if it is not adequately maintained, the 

full goal of service protection and system reliability will not be attained. It 

is estimated that approximately 75% of all electric distribution 
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cooperatives outsource their line recloser maintenance. Often, such 

maintenance has consisted of an oil change or flush and cheap paint job. 

With the high cost of labor, test equipment, parts, and supplies, recloser 

maintenance shops have found the need to cut corners and do not provide 

maintenance to the reclosers to the quality needed.

To help prevent such activities, an example program, “Line Recloser 

Maintenance Specifications,” is presented here as Exhibit B. The 

specifications are for system engineers to use as needed. Revisions are 

encouraged to fit system and financial needs. The maximum maintenance 

costs should be updated to current system conditions.

Test data are called for in the specifications. Such information can aid the 

system engineer in determining operation duty cycles as well as device 

interval duty cycles.

7 SPECIAL CONSIDERATIONS

a Grid Stability. The stability of the transmission system or grid has rarely been a

consideration in designing distribution system protection. The Northeastern U.S.

blackout of 2003 brought more recommendations and regulations, some of which 

are yet to be implemented. Regardless of the cause of the Northeast blackout, 

there have been increasing demands with minimal transmission system 

improvements, resulting in increasing load curtailments or rolling blackouts. 

National and regional reliability requirements vary greatly, but most contain some 

form of load curtailment or load shedding to prevent the collapse of the 

transmission system. In January 2007, the North American Electric Reliability 

Council and the North American Electric Reliability Corporation merged into the 

single entity, NERC Corporation (see www.nerc.com/about), which was certified 

as the “electric reliability organization” by the Federal Energy Regulatory 

Commission (FERC) in July 2006. The extent of reliability requirements imposed 

on distribution system operators are still being determined; however, it is clear 

that additional requirements for the system operators, even distributors, are very 

likely to be imposed.

Many bulk power suppliers have some method of load curtailment in place, which 

may contain a staged curtailment plan, including escalating load controls such as 

requesting voluntary load reduction, the interruption of nonfirm loads, and rolling 

blackouts coordinated by the distributors. In more extreme cases, underfrequency 

relays may be installed at selected substations to automatically shed load in the 

event of system instability. Undervoltage relaying may also be used to ensure 

automated load shedding.

b Loading Considerations

(1) Critical Loads. The load served by a distribution system often affects not
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only the mechanics of system protection but also the sectionalizing 

philosophy. Critical loads such as health care, emergency response, 

communications, and other infrastructure services require special 

consideration to minimize the chance for outages. Although it is not 

always physically or economically feasible, distribution system protection 

devices should be located downline of critical loads. Although modern 

motor controls monitor and protect for the loss of one or more phases, 

consideration should be given to using three-phase or gang-operated 

devices for critical three-phase loads to prevent damage to customers’ 

equipment.

(2) Cold Load Pickup. Cold load pickup refers to the restoration of loads that

have been unserved for some time period. Cold load pickup typically is 

divided into two types: inrush controlled and thermostatically controlled. 

Inrush currents result from a number of factors, such as distribution 

transformer energization, motor starting currents, and motor accelerating 

currents. These inrush currents can easily last several cycles and exceed 

nominal load currents by up to 10 times. Thermostatically controlled cold 

load pickup is the increase in load due to increased heating or cooling 

loads, such as air conditioning, heating, and water heating. Inrush cold 

load pickup is the primary relaying consideration.

When fast curves or operations are used in system protection schemes, 

nuisance trips are not uncommon. Generally, inrush currents will stabilize

within a few cycles, and even in the event of a fast curve trip and reclose, 

the sectionalizing device will generally reclose successfully when it 

utilizes the slow curve. Some electronic reclosers support operatorenabled cold load pickup, which simply advances the control to the slow 

time-current curve. More advanced relays may utilize harmonic analysis 

(typically second and third harmonics) to identify inrush currents and 

suppress trips due to inrush. Although this type of relay is more 

prominent in substations’ transformer protection relays, newer intelligent 

devices have the ability to perform a similar function.

Cold load pickup due to thermal recovery and loss of diversity of heating 

and cooling systems can remain from a few minutes to several hours, and 

can easily reach 3 to 5 times normal load currents. These increased load 

levels, due to the loss of diversity, often require incremental load pickup. 

Although this method extends outage times, it provides better protection 

than increasing trip settings or bypassing sectionalizing equipment.

(3) Load Imbalance. Maintaining a well-balanced load is a never-ending

challenge, particularly in rural areas served by long single-phase lines. 

Seasonal loading can also complicate maintaining good load balance. 

Although electricity is often the most practical cooling method, efficient 

and cost-effective heating may be accomplished a number of ways. In 
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climates where customers can use either gas or electricity for heating, 

loads can swing from balanced to imbalanced each season, depending on 

the distribution and location of the electric and nonelectric loads.

Frequent monitoring of load imbalances at major sectionalizing points is 

important to detect potential problems. Ground relays are one of the best 

ways to detect high-impedance phase-to-ground faults. Consequently, the 

better balanced the load, the lower the neutral current and the more 

sensitive the ground relays can be set. At the same time, consideration 

must be given to the load imbalance resulting from single-phase 

sectionalizing. Keeping single-phase loads as small as possible is ideal, 

but is simply not economically feasible or practical in all cases. Another 

consequence of load imbalances is inrush currents. In the case of a load 

imbalance that causes only 40 amperes of neutral current, an inrush 

situation may cause five times that amount for several cycles. This 

resulting 200 Amps of neutral current could easily operate a 180-Amp fast 

curve. Herein lies the “art” of system protection: finding a practical 

compromise between reliability and protection.

c Sympathetic Tripping. Sympathetic tripping may be a factor in protection

analysis, particularly on weak or higher-impedance systems. Sympathetic 

tripping typically occurs at substations where protective devices are on the same 

bus. If a high-current fault occurs on a feeder served by a high-impedance source, 

the bus voltage drops proportionally to the fault current and system impedance. 

In some cases, the load can respond to the lower voltage with higher currents, 

exceeding the trip values set in the protective relay. Newer protection analysis 

software can calculate voltages throughout the distribution system for a given 

fault type and location, which can help quantify expected voltages for given 

faults. However, the load’s response to the lower voltage depends highly on the 

type of load. A purely resistive load would have a decreasing current with a 

decreasing voltage, while motor loads would typically respond with higher 

currents as they attempt to do the work with less voltage.

d Voltage Conversions. Many utilities continue to increase system voltages,

primarily to serve increasing loads with existing conductors, with the added 

benefit of reducing losses. Voltage conversions typically double system voltages, 

such as a conversion from 12.47 kV to 24.94 kV.

Only in rare instances can an entire feeder be converted to a higher voltage. 

Therefore, step transformers are often used to convert portions of a feeder. Often, 

voltage conversions occur over several years, so step transformers are an integral 

part of the distribution system. Most often voltage conversions start at the 

substation and extend downline over time. However, some situations—such as 

very long single-phase lines with loading near the end—may be best served by a 

voltage conversion at the load end of a line rather than the source end.
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While higher operational voltages lower load currents and increase fault currents, 

the values don’t always double or halve as expected. Some utilities specify step 

transformers with higher impedances to reduce through-fault currents, thereby 

increasing system impedance and further reducing fault currents.

Analysis software becomes very important when developing protection schemes 

on mixed voltage systems. The following example shows why. A 25-kV feeder 

with a 40-Ω ground impedance would result in a minimum phase-to-ground 

current of 360 A. On the 12-kV (load) side of a step transformer, the minimum 

phase-to-ground current in the 12-kV area would be 180 A. However, if a 

protective device is located in the 25-kV area, but its protection zone extends into 

the 12-kV area, the device will only see half of the 180-A minimum fault current 

in the 12-kV area, or 90 A. Although it may be intuitive that the minimum fault 

current for a 25-kV sectionalizing device (with a 40-Ω fault impedance) is 360 A, 

if its protection zone includes, and extends beyond, a step transformer, the 

minimum fault current it needs to detect and clear is actually only 90 A. 

Similarly, where a step transformer is used to step up rather than down, the 

minimum source (12-kV) fault currents increase when the fault is in the higher 

voltage (25-kV) area.

e Intelligent Devices. As technologies continue to advance and become

commonplace, sectionalizing devices increase in functionality while costs 

decrease. This provides the opportunity to extend advanced protection, as well as 

additional functionality, further into the distribution system. Although once 

limited to transmission grade relays, programmable controls have now migrated 

down to the single-phase recloser control.

(1) Programmable Logic Control. Many programmable sectionalizing devices 

now contain some form of programmable logic control (PLC). The 

electronics can be as simple as user-selectable time-current curve (TCC) 

selection and programmable time delays, or as complex as usercustomized TCCs, thereby allowing better coordination responses. 

Beyond simple data entry of settings, many devices also support ladder 

logic or logical equations to control sectionalizing devices’ tripping 

schemes. Although somewhat more complicated than electromechanical 

devices, these devices provide many more options to protection engineers.

In the most extreme applications, the combination of PLC-type

programmability coupled with remote communications can yield a very 

dynamic and flexible protection system for increasingly complex 

distribution networks. Even in the most simple radial applications, userdefined TCCs may allow the protection engineer to move from a lockout 

coordination to a trip coordination scheme while utilizing a combination 

of older hydraulic devices and newer programmable electronic devices. 

Programmable logic can also be used to set up and configure sequence-ofevents recorders or load interval data logging.
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(2) Alternative Settings. Alternative settings are, as the name implies, an 

alternative set of tripping set points. They are most useful when a device 

may be operated in multiple scenarios. A common and simple application 

of alternative settings is in a substation feeder relay or recloser that could 

serve as a secondary source to predetermined critical load. In the event 

the primary source to the critical load is lost, the backup feeder may be 

required to serve the load.

It is likely that, in many cases, the secondary source device’s setting 

would be too low and would require an increase in trip currents to serve 

both normal and contingency loads. Using alternative settings is a method 

by which the protection engineer can “pre-engineer” settings for known 

contingency cases, while simplifying the tasks of field personnel. Another 

application of alternative settings is providing seasonal settings where load 

variations dictate. The alternative trip settings are a field-selectable 

control that relieves the protection engineer from having to reprogram 

field devices.

(3) Additional Data Collection. The data acquisition capability of newer 

sectionalizing devices provides a number of advantages to the protection 

engineer as well as other functions within the electric utility. Power 

quality, diagnostic, and design information can be obtained from the 

newer intelligent electronic devices (IEDs).

(a) Time Stamps. Time stamping of electric system events is

becoming ever more important. Although most of today’s newer 

smart devices now contain Global Positioning System (GPS) 

synchronized clock capability, it is an option, and many legacy 

electronic devices do not support high-accuracy time stamping. 

Anyone who has tried to re-create a sequence of events utilizing 

multiple devices’ event reports with unsynchronized clocks knows 

just how important time-stamping synchronization becomes. 

There have been discussions about regulatory requirements 

mandating high-accuracy time stamping of system monitoring 

equipment.

(b) Fault Data. Obviously, the magnitude of fault currents during an 

event is important to the protection engineer for a number of 

reasons. Fault magnitudes, in combination with fault location from 

operations personal, and other system configuration parameters can 

help validate the accuracy of the engineering model used to 

perform the protection study. Higher-end devices can also perform 

waveform captures, which allow an even more detailed analysis by 

defining the exact cycle level timing of a fault as well as protective 

equipment response times. The former allows analysis of the 
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symmetrical and asymmetrical contribution to the fault as well. 

Probably the most useful application of fault data is the analysis of 

duty cycles. Equipment duty cycles are the primary driver of 

performing maintenance. Many of today’s smarter devices can be 

programmed to record duty cycle information and indicate to the 

operator when a particular device is nearing time for maintenance. 

Analysis of duty cycles provides the opportunity to perform more 

cost-effective, just-in-time maintenance rather than cyclical or 

reactive maintenance of protection equipment.

(c) Load Data. Load data is another component of the sectionalizing 

and coordination equations. Load data collected by IEDs can be 

used not only for coordination studies, but also for system planning 

studies or rate studies. Load interval data collection should be 

configured at the device level to support access to this data for the 

various engineering studies. Some legacy devices may store only 

24 hours of data, while newer devices can store several months of 

data, depending on what metered values are configured.

In general, most devices can monitor and record maximum 

currents, while many now support voltage inputs in addition to the 

currents, which allows meter quality data collection of parameters,

such as power, reactive power, and power factor with a single 

device. The voltages can also be used to increase the functionality 

of the protective device by providing under- or overvoltage 

protection or even single-phasing protection of downline

equipment.

(4) Relay Failure Considerations. One of the biggest drawbacks to intelligent

electronic devices is exposure to failure, simply because of the nature of 

electronics. Where an electromechanical device may have only a handful 

of active parts, electronically controlled devices have literally thousands of 

components. As a result, the mean time before failure is much shorter for 

electronic devices then for electromechanical devices and, to some extent, 

hydraulic devices. Because of this weakness, the protection engineer must 

plan for more frequent failures of protection equipment.

The engineer must also weigh the cost versus benefit of designing some 

redundancy into the system. Although it certainly makes sense to provide 

redundant or backup protection for substation transformer protection 

relays, it is not likely cost-justified to install a secondary or backup 

controller for a single-phase recloser in a rural area. Although there are 

many philosophies related to how much redundancy or how much 

overreach is built into a protection scheme, the use of downline electronic 

devices may drive the engineer to more closely consider building in more 

overreach than has been done in the past. Each situation is different, and 
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there is no hard-and-fast set of rules than would work for every situation. 

It is the protection engineer’s duty to establish a philosophy, implementing 

it where possible, but applying it practically and accepting limitations

where the situation dictates.

(5) Breaker Failure Considerations. Another utilization of the intelligence of

today’s newer devices is in breaker failure operations. Newer devices can 

detect breaker or interrupter failures either directly or indirectly. For 

example, in the event of an SF6 leak, a “smart” circuit breaker can give a 

status indication to the relay, which will, in turn, cause an alarm and 

dictate that the relay inhibit tripping signals to the breaker to prevent 

catastrophic failure in the device. A relay may also indirectly detect 

breaker failure by evaluating the magnitude and duration of a fault versus 

the expected interruption time, even when a tripped status is given back to 

the relay. Breaker failure detection may be used to expedite the tripping 

of a backup device, thereby minimizing the fault clearing time and 

equipment damage.

f Remote Monitoring and Control. There are a number of ways to remotely

monitor and control sectionalizing equipment. Legacy SCADA systems provided 

quite a bit of real-time and sequence-of-events types of information to system 

operators; however, these systems were generally dedicated to real-time control 

and feedback, with less emphasis on data acquisition. Today, most intelligent 

devices incorporate many times more data collection and internal storage capacity 

than did traditional SCADA systems, while simultaneously supporting SCADA 

monitoring and diagnostic communications. These advanced communications 

options also open the door to better management of the electrical system.

(1) Communications. The traditional method of communication has been 

through discrete inputs and outputs (contact closures) and analog inputs 

(current transformers and potential transformers). This traditional method 

generally used a SCADA system to monitor the equipment and provide 

the information back to a central location. Today, serial data streams and 

protocol “standards” have become a quasi-standard method of 

communicating to intelligent devices. Most newer devices now come 

equipped with multiple communication ports, and can often support 

simultaneous communication to various systems.

Serial communication can be achieved through a number of media and 

communications methods. In general, IEDs contain RS-232 or RS-485 

ports that can reach transmission speeds of up to a few kilobytes per 

second. Most advances in recent years have been made in the backhaul 

systems. Media converters allow RS-232 communications to be 

encapsulated over various backhaul systems, including dial-up, fiber-optic, 

wired Ethernet, licensed radio, unlicensed radio, satellite, and wireless 

Ethernet. With the ever-increasing popularity of the Internet and TCP/IP-
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based protocols, newer devices can also utilize these systems, whether 

directly or through protocol and media converters. Unfortunately for most 

rural utilities, high-speed—or any speed—communication backhaul 

systems are still only wishful thinking, or quite expensive. This is 

especially true when communication to distributed downline devices is 

considered.

(2) SCADA. Supervisory control and data acquisition (SCADA) systems 

have been around for a long time. Early SCADA systems were often 

developed independently by utilities, resulting in hundreds of proprietary 

systems and protocols that could not communicate with one another. 

Today, there are only a handful of quasi-standard protocols such as DNP 

3.0, UCA, and MODBUS, and most equipment and SCADA vendors can 

support these protocols, although some still view proprietary protocols as 

a “good thing,” since they are generally more efficient. However, given 

today’s improved bandwidths, the increase in efficiency is not worth being 

tied to a proprietary or single-source solution.

(3) Maintenance. Most newer IEDs record and store more information than 

the average cooperative engineer has time to look at; however, that 

information is there when it is needed. Fault and operations data are often 

used to calculate duty cycles, which dictate when equipment maintenance 

should be performed. Most newer devices support simultaneous SCADA 

monitoring and diagnostic communication. Often, vendor-specific 

software can be used remotely to read and change settings, download data, 

and control the device without any SCADA system, so long as there is a 

communication system available.

The data contained in IEDs can often help monitor other maintenance

issues in addition to equipment maintenance. Upline devices can often

monitor and collect fault information for nonintelligent downline devices. 

Since the fault current flows through the IED, all duty-cycle-related 

information can be captured in the upline IED. Combining outage 

reporting or “dumb” operation counters with upline intelligent data 

collection can provide the same duty cycle information for lower-cost 

downline devices. Fault magnitudes can also be utilized to help locate 

other maintenance issues, such as burning rights-of-way, failing insulators, 

and bad lightning arrestors when combined with fault analysis software 

packages.

g Distribution Automation. With the advent of lower-cost communications,

better standardization of communication protocols, and more-intelligent 

sectionalizing devices, much more sophisticated protection schemes can be 

developed. Although distribution automation can improve the performance from 

the protection perspective, it is perhaps more important in providing the ability to 

provide automatic restoration to critical loads. Very often, distribution 
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automation can be cost-justified only in high-density or high load-factor areas. 

Availability of alternative power sources, as well as communications systems, is 

often a limiting factor as well.

(1) Transfer Trip Schemes. Transfer trip schemes are often used in

multisource environments. They are used primarily when a protective 

device needs to ensure than an alternative source or distributed resource 

has been isolated. Transfer trip schemes can also be utilized as a backup 

protection scheme under breaker failure modes of operation.

In a distribution network, the availability of communications and the 

signal latency become important design considerations. Dedicated fiber 

optics is the ideal communication medium; however, other communication 

technologies have been used successfully in recent years.

(2) Flip-Flop Schemes. Flip-flop schemes are most often used for

critical load applications. When two sources are available to a critical 

load and the primary source is lost, the primary source can be isolated, 

allowing the load to be switched to the secondary source. Very often, the 

equipment used to isolate one source and switch to the other source has to 

be located in close proximity. However, with the advent of improved 

communications and a larger installed base of fiber optic communication 

cables in municipal areas, this equipment may be installed farther apart.

(3) Sectionalizing Switches. In recent years, improved sensing

technologies and microprocessors have made it possible to develop 

intelligent, automated switches. The most common application of these 

switches is to use them in the place of traditional sectionalizers by sensing 

faults, upline operations, and subsequent switch openings via motor 

operations. More advanced operational schemes can be implemented 

when these devices are enabled with communications.

h Fault Location. There are a number of ways to perform fault location. The

traditional method has been to use mechanically activated devices installed on the 

primary conductor that trigger or trip a target when a predetermined current is 

exceeded. This method has been used on transmission and distribution systems

for years. Fault locators can often be used successfully in a system protection 

scheme, especially to minimize patrol times, particularly in challenging terrain. 

In transmission systems, lines are generally long and made of the same type 

conductor for many miles. Therefore, line impedance is very predictable as a 

function of distance from the source or protective relay. Distance relays have 

been used successfully for many years on transmission lines to locate faults. 

However, distribution networks have a multitude of taps and varying sizes of 

conductors in most areas, thereby making the line impedance—and, therefore,

fault current—the same at many locations on the same feeder. This would result 

in multiple possible targets for a fault.
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(1) Fault Locators. Today there are several varieties of both mechanical

and electronic fault locators. The biggest drawback to mechanical devices 

is the predefined “setting,” or trigger levels, which limit the application of 

the devices to certain load and fault conditions. Mechanical locators also 

occasionally give false positive and false negative indications because of 

such things as improper sizing, inrush currents, and double faults (one 

fault causing another fault). The advantages of mechanical devices are 

lower cost and virtually no maintenance.

There are a few electronic fault locators on the market. They vary from 

replacements for mechanical locators to expensive IEDs capable of load 

interval and waveform capture in addition to local and remote fault 

indications. Vendors claim that the electronic devices are more accurate 

than mechanical devices and give 10+ years of maintenance-free service.

(2) Distance Relays. Distance relays essentially work on the principle of

predictable line impedance over the distance of the line. Often line 

impedance values are programmed into the devices, allowing the relay to 

calculate the distance to the fault once a fault is detected. On transmission 

lines, these relays work well with most faults; however, in rare cases, 

higher impedance or nonbolted faults may give erroneous distance 

indications.

The same principle doesn’t work as well for a distribution network. 

Compared to transmission systems, distribution systems are short and,

thus, provide less variation in fault currents over the entire line segment. 

Resolving a fault location within 1⁄2 mile is very good on a 50-mile 

transmission system, but is not quite as good on a 5-mile distribution 

system. Also, by their nature, a distribution network has many paths that 

will provide the same fault impedance, so although distance to fault may 

work well for an express feeder, it won’t work very well in a more 

complex area.

(3) Distribution Analysis Software. Distribution fault analysis software can

calculate the fault magnitude at any point along a modeled distribution 

network. Therefore, fault information from smart reclosers and relays can 

be used in combination with the analysis software to identify areas with 

matching fault currents, yielding one or more possible fault areas. This 

method is probably best used as a diagnostic tool, although it has been 

successfully integrated into some outage management systems. It has 

been used successfully to find nuisance tripping causes with magnitudeonly fault data to within 1⁄2 mile, even without more detailed fault data,

such as waveform capture and symmetrical and asymmetrical fault 

contribution factors.
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i Distributed Generation. The popularity of distributed generation (DG), or

distributed resources (DR), is increasing because of technological advances, 

system benefits, and economic improvements in the cost of connecting such 

systems to the distribution system. Installing DG will have an impact on the 

distribution system, and special provisions should be made for it. A thorough 

analysis of DG systems and their impact on distribution systems is in IEEE 

Standard 1547, Standard for Interconnecting Distributed Resources with Electric 

Power Systems. In this bulletin, the special provisions reviewed are coordination, 

isolation, and islanding.

(1) Coordination. The addition of DG will affect the coordination of a

distribution system, depending on the DG size, configuration, and 

location, as well as the location of upline and downline protective devices. 

DG should be considered as a second source to the distribution system, 

potentially resulting in higher fault currents and two-way power flow. 

Modifying the coordination of protective devices to support the higher 

fault currents may result in overreaching devices, thereby increasing the 

outage exposure to the existing distribution system. Bidirectional power 

flow devices can be also utilized to optimize the coordination; however, 

the addition of these devices and their associated components may be costprohibitive for the utility and/or DG owner.

(2) Isolation. Depending on the DG location, size, and local protection

equipment, this second source could serve as a hazard to utility 

maintenance personnel by backfeeding the distribution system during 

planned or unplanned outages. It is recommended that a means of 

disconnecting the DG from the distribution system be required so that the 

DG can be isolated during maintenance or restoration activities by utility 

personnel.

(3) Islanding. Islanding of the DG can result when the upline protective

device operates, isolating the circuit so that the DG serves the load 

normally fed by the distribution system. Damage to equipment may result 

should the upline protective device reclose out-of-synch with the DG. To 

address these issues, provision should be made to remove the DG from the 

distribution system automatically on operation of an upline protective 

device. Many smaller DG systems such as residential photovoltaic 

systems integrate islanding protection as a part of the inverter design.

8 SAMPLE PROBLEM: SMALL SUBSTATION

This sample problem is representative of the procedures and equipment used for 

overcurrent protection of small rural electric substations and their feeders. Typically, 

these substations include either three single-phase or one three-phase power transformer 

(generally ≤10 MVA) with power fuses for primary overcurrent protection. Each 

substation feeder is protected by single-phase or three-phase reclosers. Additional 
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reclosers and fuse cutouts are used to provide protection out on the feeder and at taps.

a Problem. A 69-kV to 12.5/7.2-kV distribution substation has been experiencing

load growth due to the addition of several housing developments on the east 

feeder. Load projections indicate that the existing transformer (1-3750 kVA) will 

need to be replaced in the next 24 to 36 months. In addition to replacing the 

transformers, the cooperative intends to replace the single-phase hydraulic 

reclosers (3-70L) for this feeder with a three-phase electronic recloser. Using the 

following data, select a primary fuse for the new substation transformer, 

determine appropriate settings for the new recloser on the east feeder, and verify 

that the existing reclosers on this feeder are appropriately sized.

A circuit diagram of the east feeder and the substation are shown in Figures 8.1

and 8.2.

Figure 8.1. Circuit Diagram of East Feeder

Figure 8.2. Circuit Diagram of Substation
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The following data are applicable to the problem.

System Impedance (High Side of Transformer):

Z1 = 1.32 + j6.47 Ω

Z0 = 2.76 + j13.42 Ω

If (3-phase) = 6036 A

New Transformer Data:

67 kV to 13.090Y/7560 kV

5000/7000 kVA 

Z = 7.5%

b Selecting the Transformer Primary Fuse

(1) In selecting a fuse for the new transformer, the following factors must be

considered:

System voltage,
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Available fault current,

Expected transformer loading (including peak and emergency loads),

Inrush currents (including transformer magnetizing inrush and hot and 

cold load pickup),

Transformer protection from damaging overcurrents,

Coordination with other overcurrent protective devices, and

Protection of other equipment (conductors, regulators, bus work, etc.).

(2) In the substation for this example, the nominal system voltage is 69 kV. 

The fuse selected for this application should have a voltage rating that

meets or exceeds the maximum phase-to-phase operating voltage of the

system.

(3) The available symmetrical fault current at the fuse location is just over

6,000 A. The fuse selected for this application should have an interrupting 

rating that meets or exceeds the maximum available fault current. It is a 

good practice to include sufficient margin in the interrupting rating to 

allow for future system growth and improvements.

(4) The fuse ampere rating and speed characteristic should be selected to

accommodate the expected normal and emergency load current. It is

common practice to use the transformer rating as a basis for the normal 

load current. This allows for future system growth up to the transformer

capacity without having to replace the fuses. The primary full load current 

based on the rated capacity of the transformer in this example is calculated 

as follows:

It is important to note that the continuous loading capability of an E-rated 

fuse is greater than its ampere rating. As seen in Table 8.1 below, any 

fuse larger than 40E has a continuous capability that meets or exceeds the 

rated load current of the transformer.

Table 8.1. Primary Fuse Current-Carrying Capability

Rating, A ↓ Peak-Load Capability, A

Continuous

Daily Emergency

Time, Hours 

→

1⁄2 1 2 4 8 1⁄2 1 2 4 8

5E 7.5 7.7 7.6 7.5 7.5 7.5 8.0 7.8 7.7 7.7 7.7

7E 10.5 10.8 10.8 10.6 10.5 10.5 11.2 11.0 10.8 10.8 10.8

10E 15.0 15.5 15.2 15.0 15.0 15.0 16.0 16.7 16.5 16.5 16.5

13E 19.5 20.1 19.7 19.5 19.5 19.5 20.6 20.4 20.1 20.1 20.1

15E 22.6 23.2 22.8 22.5 22.5 22.5 24.0 23.5 23.2 23.2 23.2

Ifl

kVA rating

 kV rating

7,000

67

60A
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20E 30.0 31.0 30.4 30.0 30.0 30.0 32.0 31.4 31.0 31.0 31.0

25E 37.5 38.8 38.0 37.5 37.5 37.5 40.0 39.2 38.8 38.8 38.8

30E 45.0 46.5 45.6 45.0 45.0 45.0 48.8 47.0 46.5 46.5 46.5

40E 60 62 61 60 60 60 64 63 62 62 62

50E 75 78 76 75 75 75 80 79 78 78 78

65E 87 98 95 92 91 89 104 101 99 98 95

80E 96 108 104 101 99 98 116 112 109 107 105

100E 115 126 121 119 118 117 135 131 129 128 127

125E 137 150 145 143 141 140 162 157 155 153 152

150E 157 172 166 163 162 160 187 181 178 177 175

175E 192 210 204 199 197 196 245 238 231 226 224

200E 200 224 216 208 206 204 260 250 244 238 236

(5) In addition to daily and peak loads, the selected fuse must also

accommodate emergency loading conditions, transformer magnetizing 

inrush, hot load pickup, and cold load pickup. (For a detailed discussion 

which these factors reference, see “Selection Guide for Transformer 

Primary Fuses in Medium- and High-Voltage Utility and Industrial 

Substations,” S&C Data Bulletin 210-110, October 10, 2005.)

For this application, we have selected an SMD-1A, 50E, slow-speed fuse. 

The transformer damage curve and the characteristic curves for this fuse 

are shown in the Figure 8.3.

We also note that this fuse will protect the conductors and bus and voltage 

regulators on the secondary side of the power transformer. A quick look 

at the damage curves for the conductor jumpers and bus reveals that there 

is adequate protection (not displayed in this example but available from 

various sources). Reviewing ANSI C57.15, we see that the damage point 

for voltage regulators is 40 times the base current for 15 cycles and that 

this fuse is adequate protection for that point.

Figure 8.3. Transformer Damage Curve with Primary Fuse
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c Selecting the Substation Feeder Protection

(1) We have decided to install an electronically controlled three-phase

recloser on this feeder. We will select a recloser that meets the following

criteria:

Has the correct voltage rating for the application,

Can handle the expected load current (plus some for growth), and

Has an adequate interrupting rating (plus some for inevitable 

increases).

(2) The electronically controlled recloser will have a phase overcurrent setting

and a ground overcurrent setting. As discussed in Section 5 of this Design 

Guide, the following considerations determine these settings:
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(a) The most important constraint is the first upline protective device, 

which is the substation transformer 69-kV fuse. By converting this 

fuse to a 12-kV base, we can compare different curves available 

for use with our recloser control.

(b) The peak load on this feeder is expected to be about 100 A per 

phase. We need to select phase trip settings high enough to 

accommodate the expected load and inrush. A commonly used 

convention is to set the phase trip at 1.5 to 2.5 times the expected 

peak load current to handle inrush.

(c) We need to check to make sure that the phase setting protects the 

main feeder conductor from damage. The phase setting should be 

below the time-current damage curve for the smallest conductor 

protected by the station feeder device. (Note that this setting may 

be above the continuous current rating of the feeder conductor. 

Typically, the phase setting is not used to keep the conductor from 

becoming overloaded; rather, metering is used to monitor 

overload.)

(d) A ground setting should be selected that is sensitive enough to 

respond to high-impedance faults at the end of the line, open point, 

or the next protective device on the feeder, but will allow normal 

system operation of downline devices without false trips. The 

minimum fault at the end of the three-phase line (section 1279) is 

162 A. In this example, we are fusing all single-phase laterals off 

the three-phase line.

(e) Phase and ground settings should be high enough to accommodate 

needed or expected feeder devices, such as fuses and reclosers.

(3) To select a phase setting, we start by looking at the load current times 1.5

to 2.5, or 150 to 250 A. We will lean toward the middle of this range in 

this example. Because this is an electronic control, we have a wide variety 

of current settings and curves available. Using a standard, extremely 

inverse curve available in the recloser control library, we will tentatively 

select 200 A, which fits well with the high-side fuse. Next, a comparison 

of the time current damage curve for 1/0 ACSR shows that this setting will 

be adequate for conductor protection. Figure 8.2 shows the high-side fuse 

curve, the conductor damage curve, and the feeder recloser phase curve.

(4) To select a ground setting, we start by looking at the calculated minimum

fault currents in Table 8.2. Selecting 40 Ω as our fault impedance for the 

calculation, we see that the end of section 1270 will have a minimum fault 

value of 162 A. So the ground setting must be below 162 for coverage of 

this value. Looking ahead, we also find that there is a problem with the oil 
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circuit recloser at the source of section 1275. The expected load is 47 A 

on a 35H recloser, so we elect to increase the recloser rating to 50H. This 

constrains our ground setting to be above the curve of a 50H and below 

162 A. We pick a point between the two values of 120 A, using a 

standard, extremely inverse curve, which gives us the recommended 

separation discussed in Section 5 of this Design Guide.

Table 8.2. Circuit Load and Available Fault Currents

Location Through

Current, A

Maximum

Fault Current, A

Minimum

Fault Current, A

East Feeder 96 3070 196

1201 96 2430 191

1205 11 2030 188

1210 85 1974 188

1211 82 1921 187

1215 64 1822 186

1220 64 1440 180

1225 9 1237 177

1230 2 583 156

1232 0 1156 175

1235 10 955 176

1238 47 1185 175

1240 35 1044 171

1245 32 901 166

1250 18 591 154

1255 14 447 146

1260 21 842 164

1265 14 455 149

1270 18 791 162

1275 47 506 155

1278 0 409 145

1280 0 480 151

1283 2 900 166

1370 30 454 145

9 SAMPLE PROBLEM: LARGE SUBSTATION

This sample problem illustrates a method to sectionalize the system when the substation 

transformer is larger than 10,000 kVA and the available fault current is high. It is 

assumed that the substation is under construction and a complete sectionalizing study is 

needed. For simplicity, only a major feeder will be sectionalized to simplify the results. 

The configuration developed in this example is not the only way the system can be 

sectionalized; the particular method will depend on the preferences and experiences of 

the engineer, circuit configuration, and the historical preferences of the utility.
RUS Bulletin 1724E-102

Page 94

To get the greatest long-term benefit out of the sectionalizing study, the load current 

calculations for each feeder are based on the projected peak load of the substation. The 

system and estimated loads are shown in Figure 9.1 in this Design Guide.

There are numerous software programs capable of calculating maximum and minimum 

fault currents once the data is either entered into an engineering analysis program or 

imported from a GIS system. The various devices can be coordinated by using a software 

program, or the coordination can be done manually from the manufacturers’ time-current 

curves; however, drawing the TCC curves manually is almost a thing of the past.

In general, the high-side protection at a large substation will be either a circuit switcher or 

a circuit breaker, since either of these devices will protect the transformer better than 

fuses. With the larger transformer, a differential relay scheme will be utilized, along with 

a backup overcurrent relay scheme. The differential scheme can protect just the 

transformer through the use of high- and low-side bushing current transformers, or it can 

also protect the low-side bus if current transformers are available on the low-side bus. 

This scheme is designed to minimize the transformer damage if an internal fault occurs. 

The backup overcurrent scheme is based on the upper rating of the transformer and is set 

to protect the transformer from overload situations. The differential relays’ calculations 

and settings are complex and are best left to an engineer who specializes in transformer 

protection settings and/or substation protection.

a Basic Data

(1) Source Information. The power supplier to the substation provided the 

following information about the source:

Z(+) = Z(–) = 0.14 + j4.39% on 100 MVA base

Z(0) = 3.44 + j14.65% on 100 MVA base

Three-phase fault: 2253.1 MVA = 13,008 A @ 100 kV

Single-phase fault: 1255.0 MVA = 7,246 A @ 100 kV

(2) Transformer Information. The transformer manufacturer should

supply a damage curve for the transformer. If one is unavailable, use

ANSI standard curves. The transformer information is as follows:

Transformer impedance 7.45%

Transformer rating 15,000 kVA

Transformer turns ratios 100 kV—13.2/7.62 kV

(3) Nameplate Information. The following information is supplied by the 

manufacturer or is obtained from the transformer’s nameplate:

Three phase, 15 MVA

High side 100 kV
RUS Bulletin 1724E-102

Page 95

Low side 13.2/7.62 kV

Impedance 7.45%

(4) Transformer Impedance. To determine the transformer impedance 

(ohmic) to a three-phase fault referred to the low-side base, see Table 3.3

in Section 3 of this Design Guide. To find the impedance of the 

transformer to a line-to-line fault, see Table 3.4 in Section 3 of this Design 

Guide. To find the impedance of the transformer to a line-to-ground fault, 

see Table 3.2 in Section 3 of this Design Guide.

(5) Circuit Breaker/Recloser Information. The manufacturers of the circuit 

breakers/reclosers should supply the following information:

High-side breaker rating;

Low-side breaker or recloser ratings;

Time-current curves for the high- and low-side relays;

Ratings and time-current curves for the distribution recloser; and

Ratings and time-current curves of the distribution fuses.

(6) Three-Phase Transformer Impedance. From the co-op’s records, obtain a 

circuit diagram of the substation and circuits showing proposed 

sectionalizing points, conductor sizes, length of conductors between 

protection devices, and full-load currents.

(a) Calculation of Three-Phase Transformer Impedance

Using the % or per unit method:

7.45 % 49 .667 % on 100 MVA base

15 MVA

100 MVA

On larger transformers, the assumption is made to spread the 

transformer into its resistance and reactance components by using 

the approximation 0.1 + j1.0.

Thus the transformer impedance becomes:

 (49.667%)(0.1 + j1.0) = 4.9667 + j49.667% on 100 MVA base

The 3 transformer impedance can be converted to an ohmic 

value by the following calculation (See Table 9.1 below, the 

Constants for Fault Calculations Data Sheet).

(49.667% on 100 MVA Base)(0.01742 Ohms/1%) = 0.8652 Ω @ 

13.2 kV
RUS Bulletin 1724E-102

Page 96

(b) Calculation of Three-Phase Transformer Impedance (Ohmic 

Method)

2

2

( )% ( )

(kV A per phase) 100,000 ( )

7.45 7620

5000 100, 000

0.8652 

Z t E L Z t
RUS Bulletin 1724E-102

Page 97

Table 9.1. Constants for Fault Calculations Data Sheet
RUS Bulletin 1724E-102

Page 98

(c) Calculation of Fault Currents. Maximum fault current is calculated 

at each proposed sectionalizing location. Minimum fault currents 

are calculated for each device at the end of the section of line the 

device is designed to protect, i.e., device’s zone of protection.

(1) 3 Low-Side Fault Calculations

Source Impedance Z(+) = 0.14 + j 4.39% on 100 MVA

(High Side)

Transformer Impedance ZT = 4.9667 + j 49.667% on 100 MVA

Low Side Source Impedance (Z1)= 5.1067 + j 54.057 % on 100 MVA

= 54.2976% on 100 MVA

3 Low-Side Fault =

4374 Amps 8056 Amps

54 .2976

100

[See Table 9.1 above, the Constants for Fault Calculations Data 

Sheet, for the derivation of the 4,374 Amps, i.e., Base Amps or 3 

phase Amps/100 MVA = 4,374 Amps at 13.2 kV (line to line)]

(2) Single-Phase Low-Side Fault

Calculations:

Single-Phase Fault Impedance = (2Z* + Z0)/3

Low-Side Source Impedance Z(1) = 5.0167 + j 54.057 on 100 MVA

Source Impedance Z(1) = 5.1067 + j 54.057 on 100 MVA

Transformer Impedance Z0 = 4.9667 + j 49.667 on 100 MVA

Total Low-Side Impedance = (15.1801 + 157.781)/3 % on 100 

MVA

= 5.060 + j 52.5937 % on 100 MVA

= 52.8366 % on 100 MVA Base

Single-Phase Maximum Low-Side Fault =

4374 Amps 8,278 Amps

52 .8366

100

(d) Distribution Line Impedance

(1) The last impedance to be calculated is the distribution line 

impedance. To determine the impedances for three-phase 

faults, refer to Table 3.3 in Section 3 of this Design Guide; 

for line-to-line faults, refer to Table 3.4 in Section 3 of this 
RUS Bulletin 1724E-102

Page 99

Design Guide; for line-to-ground faults, refer to Table 3.2

in Section 3 of this Design Guide.

(2) Multiply each of the values obtained from the appropriate 

table by the number of feet or miles of each conductor size 

from the substation to the protection device or the end of 

the circuit as shown in the example below (Figure 9.1).

(3) The line impedance calculation is generally performed by 

the engineering analysis model. Since the way the 

impedance model is calculated, there can be differences 

from the traditional line impedance calculations shown in 

the various RUS (REA), other references, and more modern 

impedance models that take into account the inductive and 

capacitive coupling using various matrix manipulation 

methods. The example shown in Figure 9.1 of this Design 

Guide was developed using a commercially available 

engineering analysis program and, thus, the fault current 

results are not easily exactly duplicated by hand 

calculations.

(4) The same procedure is used for each line section for threephase, line-to-line, and line-to-ground faults. The results 

are recorded on the spreadsheet or they can be read from 

the engineering analysis package software.

(e) Computation of Fault Currents. Calculating the fault current If is a 

simple matter of summing up the respective impedances 

vectorially from the fault location back to the source using the 

following equation:

2 2 1 / 2

dist dist

( )

(fault)

[( ) ( ) ] s t f s t

E L

I

R R R R X X X

When calculating the maximum fault current, assume Rf = 0.

When calculating the minimum fault current, use the assumed 

value for fault current resistance, Rf. It has been assumed that the 

Rf for large substations is 30 Ω and 40 Ω for small substations. 

The selection of these values of fault current resistance has been 

extensively discussed in earlier sections of this bulletin.

Generally, on three-phase lines, only the three-phase and single 

phase fault currents need to be calculated, since a line-to-line fault 

usually will result in neither a maximum or minimum value. 

However, on V-phase lines, the line-to-line fault will yield the 
RUS Bulletin 1724E-102

Page 100

maximum value at some distance away from the substation and 

should be calculated.

(f) Selection of Sectionalizing Devices

(1) The transformer damage curve should be obtained from the

manufacturer and plotted. Then, the high-side breaker 

relay settings should be chosen to protect the transformer 

from damage but be set high enough to carry expected load 

current along with cold load pickup ability. This curve 

should be plotted.

(2) To coordinate the high-side protection with the substation 

transformer damage curve, the high-side time-current 

curves are referenced to the distribution voltage level for 

line-to-line and line-to-ground faults. The following 

factors can be used:

Line-to-line faults:

(L-L)

2

s

L

E

E

Line-to-ground faults:

s L L ( )

L

E

E

(3) The next step is to determine the substation breaker or 

recloser relay settings. From the previous steps, the 

maximum available fault current on the low side is 8,056

Amps. The peak load current will have to be determined 

and the minimum fault current to the next set of protection 

devices will have to be calculated.

(4) The relays or electronic reclosers will have to be set to 

carry the full-load current, any load transfers that might 

occur during emergencies, and cold load pickup. The lowside protection will also have to coordinate with the highside protection scheme. Reclosers and fuses on the 

distribution circuits will then have to coordinate with the 

low-side breaker. The low-side ground protective devices 

will have to be set to take care of the minimum available 

fault current. Care must be taken to ensure that the load 

current of the largest single-phase device is not greater than 

the minimum ground trip setting.

(5) The engineer will also have to decide whether to utilize a 

fuse-saving scheme or to minimize the momentary 
RUS Bulletin 1724E-102

Page 101

interruptions and sacrifice fuses. Single-phase reclosers 

can be coordinated as long as the same sequence of either 

two fast and two slow operations or one fast and three slow 

operations is selected. To obtain the best coordination 

between reclosers, the engineer should skip a size, using, 

for example three 70-Amp, oil circuit reclosers (OCRs) on 

a three-phase line and then a 35-Amp OCR on a singlephase tap. This is not always possible because of the length 

of line on some distribution circuits. If you skip a size, you 

can generally achieve trip coordination, but if you are not 

always able to skip a size, you can still generally achieve 

lockout coordination.

(6) The maximum and minimum fault currents will need to be

calculated at each protection device to ensure that the 

device will clear the maximum available fault current, carry 

the expected load current, and interrupt the minimum fault 

current at the end of the section the device is designed to 

protect.

(7) On large substations with feeders of 3 , 336 ACSR and 

larger conductor, it is not uncommon to have a 560-Amp

continuous-rated microprocessor-controlled recloser, an 

800-Amp continuous-rated microprocessor-controlled 

recloser, or even a 1,200-Amp continuous-rated breaker 

with an electronic relay or other microprocessor control on 

each of the substation feeders.

(8) Since single-phase devices are typically rated no more than 

4,000 Amps interrupting ability, they will have to be used 

downline. Fuses, single-phase electronic sectionalizers, or 

3 electronic sectionalizers will have to be used on all taps 

in the high-fault current areas.

(9) Additionally, downline 3 electronic reclosers can be used 

in the mainline to adequately sectionalize the circuit while 

observing all of the fault current, load current, and 

minimum fault current issues discussed in this bulletin. 

The TCC curves in Figure 9.2 and Figure 9.3 show both the 

phase coordination for a 560-Amp phase trip recloser at the 

substation and a 300-Amp phase trip electronic recloser 

downline. Also shown are the ground trip settings for each 

device with the station recloser set on 140 Amps and the 

downline device set on 100 Amps.

(10) Using engineering judgment and minimum fault current
RUS Bulletin 1724E-102

Page 102

calculations, you can set the substation feeder recloser 

ground trip to a higher value than 140 Amps if the 

calculations show that the substation device will “see” to 

the downline recloser for a line-to-ground fault.

(11) The setting of the downline recloser’s ground trip to a value 

less than 100 Amps is generally not recommended since 

during fault conditions there may be enough imbalance 

caused by a single-phase-to-ground fault to trip the 

downline electronic recloser out. This will create a larger 

outage that is more difficult to troubleshoot.

Figure 9.1. Diagram of the Substation and Circuits
RUS Bulletin 1724E-102

Page 103

b Solution

In this sample problem for large substations, the fault currents have been 

calculated and the load currents have been calculated and both of these values 

have been put on the circuit diagram (Figure 9.1) in their respective places. 

Voltage drops are not placed upon the sectionalizing circuit diagram since they 

should have already been considered, evaluated, and corrected, if necessary, so 

they are not needed in the sectionalizing analysis. As can be seen, the station had 

maximum fault current exceeding 8,100 Amps. The peak load current for the 

circuit shown is 300 Amps per phase. The zone of protection for the 

recloser/breaker at the substation is Section #1. The minimum fault current at the 

end of Section #1 using a 30 ohms fault resistance is 235 Amps L to G minimum. 

A suggested setting for the feeder recloser/ breaker is, thus, 560 Amps phase trip 

and 200 Amps (approximately) for the ground trip setting.

Using engineering judgment as a good rule of thumb for the phase trip setting is 

150% to 200% of the projected peak loading. Again, using engineering judgment, 

we could set the ground trip anywhere from 100 Amps to 235 Amps. To provide 

selective coordination, generally we want to set the ground trip of the feeder 

recloser/breaker high enough and with the correct TCC so that the downline

devices will clear the fault long before the feeder recloser/breaker has to operate.

However, for faults in Section #1 in Figure 9.1, we want the phase—and 

especially the ground trip—set sensitively enough that the device will operate but 

not trip out on nuisance problems.

For Recloser #1 in Figure 9.1, we have a three-phase tap serving a large 

subdivision at the end of the line. A suggested setting for that device could be 

200 to 250 Amps on the phase trip and 140 Amps on the ground trip. With a 

judicious and experienced selection of TCC curves, this Recloser #1 would 

provide selective coordination with the upline feeder recloser/breaker. Selective 

coordination is defined, generally, as the condition in which Recloser #1 trips for 

a fault downline from its location WITHOUT the feeder recloser tripping out or 

blinking whatsoever.

For Recloser #2 in Figure 9.1, which is on the main line, the distribution engineer 

could choose to eliminate this recloser and let the feeder recloser/breaker “see” to 

the end of Section #3 depending upon the exposure of the circuit, i.e., ROW 

condition, topography, accessibility, etc. If the distribution engineer chooses to 

put in Recloser #2, the suggested setting for that phase trip could be 300 to 400 

Amps and, for the ground trip, a range of 140 Amps to 200 Amps could be used. 

Again, with careful selection of TCC curves and trip settings, selective 

coordination could be achieved between the feeder recloser/breaker and the 

downline Recloser #3. From the load end of Section #3 to the end of the circuit, 

standard sectionalizing techniques could be used.
RUS Bulletin 1724E-102

Page 104

Figure 9.2. Time Current Characteristic Curves—Phase Trip
RUS Bulletin 1724E-102

Page 105

Figure 9.3. Time Current Characteristic Curves—Ground Trip
RUS Bulletin 1724E-102

Page 106

Coordination margins between curves are as discussed earlier in the bulletin and 

reference material, combined with engineering judgment and field experience. 

All electronic devices should be equipped with sequence coordination capability 

to enhance the probability of selective coordination.

Additional tricks of the trade to achieve selective coordination are to use similarly 

shaped but different curves on electronic reclosers in service, change the 

operations sequence, modifying both the phase and the ground trip curves by 

using a constant time adder, a curve multiplier, or for the ambitious engineer, 

simply digitizing a custom curve into the microprocessor recloser/relay. All of 

these techniques are contained in the references but most require extensive study 

and experience to implement.
RUS Bulletin 1724E-102

Exhibit A

Page 1

EXHIBIT A

SAMPLE MODEL PRINTOUT SHOWING CALCULATIONS OF FAULT CURRENTS 

AND LOADING CONDITIONS

Case: Example Primary Analysis

LINE PRIOR MILES PHS WIRE MX 3P MX LLG MX LG MN LG TOTAL EQUIV % LINE TOTAL LINE

SECT SECT CONS CONSTR-N FAULT FAULT FAULT FAULT KW AMPS CAP DROP DROP LOSS

SUB 4, CKT 1

4-01 SUB (4) 0.00 240 3- BKR-560-VWVE 3595 3910 3962 178 2431 115 21 0.00 0.00 0

42765 4-01 0.05 240 3- #ACSR336 3528 3786 3830 178 2431 115 22 0.05 0.05 126

SW370-B 42765 0.05 240 3- Closed 3528 3786 3830 178 2430 115 0 0.00 0.05 0

SW370-A SW370-B 0.05 240 3- Closed 3528 3786 3830 178 2430 115 0 0.00 0.05 0

43384 SW370-A 0.74 240 3- #ACSR336 2855 2808 2703 176 2430 115 22 0.67 0.72 1557

44590 43384 0.74 0 3- #ACSR336 2855 2807 2703 176 0 0 0 0.00 0.72 0

SW362-B 44590 0.74 0 3- Open 2855 2807 2703 176 0 0 0 0.00 0.72 0

43385 43384 0.78 238 3- #ACSR336 2823 2768 2656 176 2389 113 21 0.04 0.76 93

42763 43385 0.80 238 3- #ACSR1/0 2798 2740 2624 176 2389 113 49 0.05 0.81 161

SW369-B 42763 0.80 238 3- Closed 2798 2740 2624 176 2388 113 0 0.00 0.81 0

SW369-A SW369-B 0.80 238 3- Closed 2798 2740 2624 176 2388 113 0 0.00 0.81 0

43162 SW369-A 1.05 238 3- #ACSR1/0 2507 2425 2268 174 2388 113 49 0.64 1.45 2049

42761 43162 1.11 135 3- #ACSR1/0 2445 2361 2196 174 1316 60 26 0.08 1.53 141

SW368-B 42761 1.11 135 3- Closed 2445 2361 2196 174 1315 60 0 0.00 1.53 0

SW368-A SW368-B 1.11 135 3- Closed 2445 2361 2196 174 1315 60 0 0.00 1.53 0

42759 SW368-A 1.93 135 3- #ACSR1/0 1803 1725 1513 169 1315 60 26 1.09 2.62 1952

SW367-B 42759 1.93 135 3- Closed 1803 1725 1513 169 1305 60 0 0.00 2.62 0

SW367-A SW367-B 1.93 135 3- Closed 1803 1725 1513 169 1305 60 0 0.00 2.62 0

42757 SW367-A 2.49 134 3- #ACSR1/0 1517 1452 1241 166 1302 60 26 0.74 3.35 1195

SW366-B 42757 2.49 132 3- Closed 1517 1452 1241 166 1257 58 0 0.00 3.35 0

SW366-A SW366-B 2.49 132 3- Closed 1517 1452 1241 166 1257 58 0 0.00 3.35 0

43337 SW366-A 3.36 132 3- #ACSR1/0 1218 1167 972 161 1256 58 26 1.09 4.44 1744

42755 43337 3.36 130 3- #HD6 1216 1166 971 161 1222 57 48 0.01 4.45 18

SW365-B 42755 3.36 130 3- Closed 1216 1166 971 161 1222 57 0 0.00 4.45 0

SW365-A SW365-B 3.36 130 3- Closed 1216 1166 971 161 1222 57 0 0.00 4.45 0

43321 SW365-A 4.34 123 3- #HD6 885 865 710 152 1156 55 46 2.29 6.74 731

42753 43321 4.35 123 3- #ACSR4/0 885 864 709 152 1152 55 16 0.00 6.74 4

SW364-B 42753 4.35 123 3- Closed 885 864 709 152 1152 55 0 0.00 6.74 0

SW364-A SW364-B 4.35 123 3- Closed 885 864 709 152 1152 55 0 0.00 6.74 0

42754 SW364-A 4.38 123 3- #ACSR4/0 882 861 706 152 1152 55 16 0.02 6.76 30

C166 42754 4.38 0 3- 100 KVAR 882 861 706 152 0 -13 0 0.00 6.76 0

42951 42754 4.42 123 3- #ACSR4/0 878 857 702 151 1152 59 18 0.04 6.80 51

42988 42951 4.52 119 3- #ACSR4/0 867 846 692 151 1119 58 17 0.09 6.88 115

43025 42988 6.06 109 3- #ACSR4/0 736 712 567 146 1035 54 16 1.24 8.12 711

D1796 43025 6.06 108 3- REC-50-H 736 712 567 146 1018 53 107 0.00 8.12 0

42751 D1796 6.17 99 3- #ACSR4/0 728 704 560 146 931 48 14 0.08 8.20 42

SW363-B 42751 6.17 99 3- Closed 728 704 560 146 931 48 0 0.00 8.20 0

SW363-A SW363-B 6.17 99 3- Closed 728 704 560 146 931 48 0 0.00 8.20 0

43031 SW363-A 6.50 99 3- #ACSR4/0 705 681 539 145 931 48 14 0.24 8.44 268

C165 43031 6.50 0 3- 100 KVAR 705 681 539 145 0 0 0 0.00 8.44 0

43064 43031 7.47 84 3- #ACSR4/0 646 621 486 142 786 41 12 0.64 9.08 116

43066 43064 7.63 64 3- #ACSR4/0 637 613 479 142 642 33 10 0.07 9.15 56

43223 43066 9.98 5 3- #ACSR4/0 530 507 388 135 82 4 1 0.31 9.46 0

43127 43223 10.35 2 3- #ACSR4/0 517 493 377 134 6 0 0 0.00 9.46 0

SW331-B 43127 10.35 0 3- Open 517 493 377 134 0 0 0 0.00 9.46 0

43120 43223 10.16 1 1- #ACSR4 0 0 378 133 5 0 1 0.00 9.46 0

43067 43066 7.70 36 1- #HD6 0 0 473 141 352 55 47 0.19 9.34 107

D1794 43067 7.70 35 1- REC-35-H 0 0 473 141 341 54 155 0.00 9.34 0

NODE42 D1794 8.49 5 1- #HD6 0 0 413 135 37 5 5 0.59 9.93 3

43129 43064 7.65 16 1- #HD6 0 0 471 141 111 17 15 0.13 9.20 20

NODE43 43129 8.02 6 1- #ACSR4 0 0 439 138 41 6 5 0.07 9.28 3

43000 42988 5.24 3 3- #HD6 720 709 578 145 6 0 0 0.02 6.90 0

43001 43000 5.31 2 1- #HD6 0 0 567 144 5 0 1 0.00 6.91 0

NODE55 43001 5.43 1 1- #ACSR4 0 0 553 143 1 0 0 0.00 6.91 0

42954 42951 4.53 4 3- #ACSR1/0 861 840 688 151 32 1 1 0.00 6.80 0

D1797 42954 4.53 4 3- REC-50-L 861 840 688 151 32 1 3 0.00 6.80 0

43317 D1797 4.65 4 3- #ACSR1/0 844 824 673 150 32 1 1 0.00 6.81 0

43429 43317 4.95 2 3- #ACSR4 776 761 621 148 0 0 0 0.01 6.82 0

42971 43429 4.98 2 3- #HD6 769 754 615 147 0 0 0 0.00 6.82 0

43177 42971 5.57 0 3- #ACSR4 663 655 534 142 0 0 0 0.00 6.82 0

(continued)

Substation Power Factor: 0.95 Load Factor: 0.50 Loss Factor: 0.29 Cost: 0.0750 per kWh

Run Date:
RUS Bulletin 1724E-102

Exhibit A

Page 2

Exhibit A, continued

LINE PRIOR MILES PHS WIRE MX 3P MX LLG MX LG MN LG TOTAL EQUIV % LINE TOTAL LINE

SECT SECT CONS CONSTR-N FAULT FAULT FAULT FAULT KW AMPS CAP DROP DROP LOSS

NODE54 43177 5.79 0 3- #ACSR4 630 624 509 140 0 0 0 0.00 6.82 0

42985 43177 5.86 0 3- #ACSR4 620 614 501 140 0 0 0 0.00 6.82 0

42749 43317 5.64 0 3- #ACSR1/0 726 708 573 146 0 0 0 0.00 6.81 0

SW361-A 42749 5.64 0 3- Open 726 708 573 146 0 0 0 0.00 6.81 0

43163 43162 1.08 102 3- #ACSR1/0 2468 2385 2222 174 1046 52 23 0.04 1.49 65

D1795 43163 1.08 102 1- REC-50-L 0 0 2222 174 1046 156 314 0.00 1.49 0

42875 D1795 1.52 94 1- #HD6 0 0 1662 169 941 144 120 3.23 4.72 1179

43375 42875 2.09 93 1- #ACSR4 0 0 1199 163 926 142 102 4.35 9.07 6262

42770 43375 2.57 87 1- #HD6 0 0 976 158 830 135 113 3.29 12.36 1461

43413 42770 3.11 85 1- #ACSR4 0 0 799 153 814 133 96 3.79 16.15 5130

43405 43413 4.32 63 1- #ACSR1/0 0 0 637 147 598 104 46 4.45 20.60 548

NODE69 43405 6.36 3 1- #HD6 0 0 416 131 24 4 4 5.00 25.60 0

CKT 1 total losses: $25,938

SUB4, CKT 2

4-02 SUB (4) 0.00 18 3- BKR-560-VWVE 3595 3910 3962 178 182 8 2 0.00 0.00 0

43500 4-02 0.06 18 3- #ACSR336 3527 3784 3828 178 182 8 2 0.00 0.00 0

SW371-B 43500 0.06 18 3- Closed 3527 3784 3828 178 182 8 0 0.00 0.00 0

SW371-A SW371-B 0.06 18 3- Closed 3527 3784 3828 178 182 8 0 0.00 0.00 0

43449 SW371-A 0.74 18 3- #ACSR336 2855 2807 2702 176 182 8 2 0.06 0.06 10

44589 43449 0.74 0 3- #ACSR336 2854 2806 2702 176 0 0 0 0.00 0.06 0

SW362-A 44589 0.74 0 3- Open 2854 2806 2702 176 0 0 0 0.00 0.06 0

43451 43449 0.85 18 3- #ACSR336 2767 2701 2576 176 182 8 2 0.01 0.07 0

43499 43451 2.20 15 3- #ACSR1/0 1672 1598 1383 168 125 6 3 0.23 0.30 17

43474 43499 2.25 15 1- #ACSR4 0 0 1344 167 125 18 13 0.05 0.36 10

D1802 43474 2.25 14 1- REC-35-L 0 0 1344 167 124 18 52 0.00 0.36 0

43482 D1802 2.73 1 1- #ACSR4 0 0 1076 162 14 2 1 0.26 0.62 0

43505 43482 2.74 0 1- #UG25KV1/0 0 0 1072 362 0 0 0 0.00 0.62 0

NODE68 43505 2.79 0 1- #ACSR4 0 0 1047 161 0 0 0 0.00 0.62 0

CKT 2 total losses: $37

SUB4, CKT 3

4-03 SUB (4) 0.00 2 3- BKR-560-VWVE 3595 3910 3962 178 20 14 3 0.00 0.00 0

44538 4-03 0.01 2 3- #ACSR336 3581 3883 3933 178 20 14 3 0.00 0.00 0

SW375-B 44538 0.01 2 3- Closed 3581 3883 3933 178 20 14 0 0.00 0.00 0

SW375-A SW375-B 0.01 2 3- Closed 3581 3883 3933 178 20 14 0 0.00 0.00 0

43727 SW375-A 0.12 2 3- #ACSR336 3455 3660 3693 177 20 14 3 -0.02 -0.02 4

44588 43727 0.12 0 3- #ACSR336 3455 3660 3692 177 0 0 0 0.00 -0.02 0

SW372-B 44588 0.12 0 3- Open 3455 3660 3692 177 0 0 0 0.00 -0.02 0

44540 43727 0.45 2 3- #ACSR336 3101 3125 3080 177 20 14 3 -0.05 -0.07 0

SW376-B 44540 0.45 2 3- Closed 3101 3125 3080 177 20 14 0 0.00 -0.07 0

SW376-A SW376-B 0.45 2 3- Closed 3101 3125 3080 177 20 14 0 0.00 -0.07 0

44284 44581 9.19 0 3- #ACSR336 844 769 578 156 0 0 0 0.00 -1.25 0

44318 44284 10.02 0 3- #ACSR336 789 719 537 154 0 0 0 0.00 -1.25 0

C168 44318 10.02 0 3- 200 KVAR 789 719 537 154 0 0 0 0.00 -1.25 0

44323 44318 10.38 0 3- #ACSR336 768 699 521 153 0 0 0 0.00 -1.25 0

44345 44323 10.94 0 3- #HD6 693 640 475 148 0 0 0 0.00 -1.25 0

44377 44345 12.15 0 3- #ACSR4 554 524 391 137 0 0 0 0.00 -1.25 0

44382 44377 12.33 0 3- #HD6 537 510 381 136 0 0 0 0.00 -1.25 0

SW383-A 44382 12.33 0 3- Open 537 510 381 136 0 0 0 0.00 -1.25 0

NODE65 44284 9.87 0 3- #ACSR1/0 768 705 528 152 0 0 0 0.00 -1.25 0

44122 44120 8.19 0 1- #HD6 0 0 635 158 0 0 0 0.00 -1.24 0

D1835 44122 8.19 0 1- REC-25-H 0 0 635 158 0 0 0 0.00 -1.24 0

44034 D1835 8.69 0 1- #HD6 0 0 573 153 0 0 0 0.00 -1.24 0

44047 44034 9.07 0 1- #ACSR4 0 0 531 149 0 0 0 0.00 -1.24 0

44205 44047 9.24 0 1- #HD6 0 0 514 148 0 0 0 0.00 -1.24 0

44209 44205 9.32 0 1- #ACSR4 0 0 506 147 0 0 0 0.00 -1.24 0

NODE60 44205 9.28 0 1- #HD6 0 0 511 147 0 0 0 0.00 -1.24 0

43828 44547 4.44 1 3- #ACSR336 1397 1285 1036 167 18 0 0 0.00 -0.65 0

C169 43828 4.44 0 3- 100 KVAR 1397 1285 1036 167 0 0 0 0.00 -0.65 0

43840 43828 4.55 1 3- #ACSR336 1376 1266 1017 167 18 0 0 0.00 -0.65 0

D1843 43840 4.55 1 3- REC-50-H 1376 1266 1017 167 18 0 2 0.00 -0.65 0

43850 D1843 4.84 1 3- #ACSR336 1325 1217 972 166 18 0 0 0.00 -0.64 0

44414 43850 4.99 0 3- #ACSR1/0 1282 1179 938 166 0 0 0 0.00 -0.64 0

NODE53 44414 5.78 0 3- #ACSR4 998 945 740 157 0 0 0 0.00 -0.64 0

44464 43850 5.78 1 3- #ACSR336 1180 1081 848 164 18 0 0 0.01 -0.64 0

43859 44464 5.80 1 1- #ACSR4 0 0 841 164 18 2 2 0.00 -0.63 0

(continued)

Substation Power Factor: 0.95 Load Factor: 0.50 Loss Factor: 0.29 Cost: 0.0750 per kWh

Run Date:
RUS Bulletin 1724E-102

Exhibit A

Page 3

Exhibit A, continued

LINE PRIOR MILES PHS WIRE MX 3P MX LLG MX LG MN LG TOTAL EQUIV % LINE TOTAL LINE

SECT SECT CONS CONSTR-N FAULT FAULT FAULT FAULT KW AMPS CAP DROP DROP LOSS

D1838 43859 5.80 1 1- REC-25-H 0 0 841 164 18 2 11 0.00 -0.63 0

43864 D1838 6.15 1 1- #ACSR4 0 0 764 160 18 2 2 0.05 -0.58 0

43868 43864 6.46 1 1- #HD6 0 0 706 157 18 2 2 0.04 -0.54 0

NODE52 43868 6.70 1 1- #ACSR4 0 0 664 154 18 2 2 0.02 -0.52 0

44443 44464 6.52 0 3- #ACSR336 1086 993 770 162 0 0 0 0.00 -0.64 0

43916 44443 6.58 0 1- #ACSR4 0 0 759 162 0 0 0 0.00 -0.64 0

D1836 43916 6.58 0 1- REC-25-99 0 0 759 162 0 0 0 0.00 -0.64 0

44439 D1836 6.96 0 1- #ACSR4 0 0 688 158 0 0 0 0.00 -0.64 0

43970 44439 8.45 0 1- #HD6 0 0 501 144 0 0 0 0.00 -0.64 0

NODE45 43970 8.96 0 1- #ACSR4 0 0 455 140 0 0 0 0.00 -0.64 0

43816 43814 3.84 0 1- #ACSR4 0 0 1144 168 0 0 0 0.00 -0.56 0

D1839 43816 3.84 0 1- REC-35-H 0 0 1144 168 0 0 0 0.00 -0.56 0

NODE58 D1839 4.30 0 1- #ACSR4 0 0 965 163 0 0 0 0.00 -0.56 0

43752 43741 1.83 0 3- #ACSR4 1851 1790 1565 169 0 0 0 0.00 -0.20 0

42750 43752 1.83 0 3- #ACSR1/0 1848 1787 1562 169 0 0 0 0.00 -0.20 0

SW361-B 42750 1.83 0 3- Open 1848 1787 1562 169 0 0 0 0.00 -0.20 0

CKT 3 total losses: $79

SUB4, CKT 4

4-04 SUB (4) 0.00 76 3- BKR-560-VWVE 3595 3910 3962 178 726 35 6 0.00 0.00 0

43717 4-04 0.01 76 3- #ACSR336 3584 3889 3940 178 726 35 7 0.00 0.00 2

SW373-B 43717 0.01 76 3- Closed 3584 3889 3940 178 726 35 0 0.00 0.00 0

SW373-A SW373-B 0.01 76 3- Closed 3584 3889 3940 178 726 35 0 0.00 0.00 0

43508 SW373-A 0.12 76 3- #ACSR336 3453 3656 3688 177 726 35 7 0.04 0.04 24

43520 43508 0.45 67 3- #ACSR336 3100 3124 3079 177 564 27 5 0.10 0.14 14

43719 43520 0.46 6 3- #HD6 3093 3115 3068 177 71 3 3 0.00 0.14 0

SW374-B 43719 0.46 6 3- Closed 3093 3115 3068 177 71 3 0 0.00 0.14 0

SW374-A SW374-B 0.46 6 3- Closed 3093 3115 3068 177 71 3 0 0.00 0.14 0

43612 SW374-A 0.99 6 3- #HD6 2164 2129 1958 171 71 3 3 0.08 0.22 9

NODE66 43612 1.96 2 3- #ACSR4 1270 1266 1100 160 47 2 2 0.08 0.30 0

43521 43520 0.51 57 1- #HD6 0 0 2929 176 466 68 57 0.19 0.33 129

D1807 43521 0.51 9 1- REC-35-L 0 0 2929 176 65 9 27 0.00 0.33 0

43533 D1807 0.88 9 1- #HD6 0 0 2124 172 65 9 8 0.11 0.44 8

NODE67 43533 2.73 0 1- #ACSR4 0 0 803 152 0 0 0 0.13 0.57 0

43524 43521 0.57 47 1- #ACSR1/0 0 0 2807 176 397 58 26 0.11 0.44 55

D1806 43524 0.57 47 1- REC-50-L 0 0 2807 176 397 58 118 0.00 0.44 0

43662 D1806 2.15 47 1- #ACSR1/0 0 0 1324 166 392 58 26 2.78 3.22 588

43576 43662 2.35 41 1- #ACSR4 0 0 1199 164 355 53 38 0.58 3.80 109

43606 43576 3.67 7 1- #HD6 0 0 740 151 53 8 7 1.71 5.52 6

43710 43606 3.94 5 1- #ACSR4 0 0 682 149 44 6 5 0.08 5.60 5

NODE64 43710 4.73 0 1- #HD6 0 0 559 142 0 0 0 0.06 5.66 0

43640 43508 0.12 0 3- #ACSR336 3452 3656 3688 177 0 0 0 0.00 0.04 0

SW372-A 43640 0.12 0 3- Open 3452 3656 3688 177 0 0 0 0.00 0.04 0

CKT 4 total losses: $949

SUB 4 total losses: $27,003

Substation Power Factor: 0.95 Load Factor: 0.50 Loss Factor: 0.29 Cost: 0.0750 per kWh

Run Date:
RUS Bulletin 1724E-102

Exhibit B

Page 1

EXHIBIT B

LINE RECLOSER MAINTENANCE SPECIFICATIONS

August 1, 2005

(Revision 1 – August 5, 2006)

PURPOSE: To detail the minimum requirements for refurbishment of single-phase line 

sectionalizing reclosers regardless of type, size, or manufacturer.

LIMITED SCOPE:

1. The requirements set forth herein are in no way intended to limit those steps necessary to 

bring a used recloser up to proper operating status.

2. No warranty is written or implied by the compliance of the requirements included herein. 

The user is to refer to the warranty provided by the organization or contractor actually 

performing the recloser maintenance.

REQUIREMENTS:

1. Prior to any recloser maintenance, a full operational and functional test shall be 

accomplished. Any dysfunctional aspect of the recloser operation shall be documented. 

The test is to determine also the actual pickup current level and time-current 

characteristics of the device. The pickup values and counter reading, as found, shall be 

included in the recloser final test report.

NOTE: All testing required by this specification shall be accomplished by using 

alternating current (AC) operating equipment only. Direct current (DC) or battery 

operational tests are not acceptable.

2. All internal parts of the recloser shall be disassembled, inspected, and thoroughly 

washed. All gaskets and tank liners are to be replaced if there are significant signs of 

deterioration. Other mechanism parts are to be replaced at the discretion of the 

maintenance contractor.

3. All operation counters are to be checked for proper operation. Counters with “smallsized numbers” are to be replaced with the “larger-sized numbers” as manufactured by 

__________________________.

4. Reclosers having an estimated maintenance cost of more than 50% of a new purchase 

price are to be scrapped. The maintenance contractor can give credit for parts where 

appropriate. The maximum maintenance cost for each type of recloser is as follows:

Type H or equivalent = $____

Type L or equivalent = $____
RUS Bulletin 1724E-102

Exhibit B

Page 2

Type E or equivalent = $____

Type 4H or equivalent = $____

5. After the preceding steps are accomplished, each recloser is to be tested for proper 

operation in accordance with published specifications of the manufacturer. The 

minimum tests to be performed are as follows:

Insulation resistance or hipot,

Minimum pickup current level,

Functional tests of operating handle, nonreclosing switch, and lockout indicator, and

Calibration of time-current characteristics.

NOTE: A minimum of two test points per operating curve, not including the pickup 

current point, are to be used to determine that the recloser is properly operating. 

Suggested test points are 400% and 600% of rated pickup current (or 800% and 1200% of 

rated load current). Points other than these are to be approved by the owner. Any test 

results that are not within 10% of the manufacturer’s published data should be noted and 

reviewed with the owner for possible scrapping of the unit.

6. After testing, each unit is to be thoroughly sandblasted or cleaned and painted with a 

good quality ANSI No. 70 gray paint.

7. Each unit shall also be externally labeled in the manner prescribed by the owner. The 

labeling shall be on the tank side, opposite the mounting bracket. The lettering shall be a 

minimum 3 inches high, shall include both the recloser type and size, and is to be done 

using a paint that will not deteriorate in sunlight.

8. Refurbished units are to be safely shipped back to the owner on containers that 

adequately support and protect the devices during shipment. The vendor has 

responsibility for units during shipment.

9. A report shall also be provided on each refurbished recloser unit. The report may be 

supplied electronically and by email. The report, at a minimum, shall include the 

following:

Manufacturer, type, size, kilovolt basic impulse level (BIL), and serial number;

Coil size found at start and coil size left;

Counter reading found at start and reading left;

Operations sequence as found and sequence left;

Timing test results as found and as calibrated;

Old oil batch number traceable to depository;

New oil batch number traceable to source for non-PCB verification;

Itemized list of parts installed, including invoice costs;

Date of repair and individuals performing the repairs and tests; and

Vendor comments on the timeliness of maintenance.
RUS Bulletin 1724E-102

Exhibit B

Page 3

10. Prior to shipment, the maintenance contractor is to notify the owner that refurbishment 

has been completed and that the units are available for inspection. The owner then has 

the option of going to the contractor’s facilities to inspect the refurbished units. At that 

time, the owner can request a sample of 10% of total units shipped for retesting 

observation. A price per unit for retesting is to be provided to the owner when annual 

unit price estimates are offered. If no such price is offered, it is assumed that the 

retesting will be accomplished by the contractor at no cost. It is further understood that 

all retested units found to be in nonconformance with the test reports will not be charged 

to the owner.

11. Shipped units may be retested by the owner after receipt. If a shipped unit is found to be 

not in conformance with contractor’s test report, the unit will be returned to the 

contractor at contractor’s expense for correction.

NOTE: The method of the owner’s test is to be compatible with the contractor’s.

COMMENTS AND QUESTIONS:

Comments and questions regarding these specifications are encouraged and should be addressed 

to the cooperative system engineer or his designated consultant. The system engineer is 

______________________, whose contact information is as follows:

Office phone: XXX-XXX-XXXX

FAX: YYY-YYY-YYYY

Email: sysengineer@coopabc.com
RUS Bulletin 1724E-102

Exhibit C

Page 1

EXHIBIT C

BIBLIOGRAPHY AND REFERENCES

1. “Procedure for Making a Sectionalizing Study on Rural Electric Systems.” Technical 

Standards Bulletin #4A (December 1945), Rural Electrification Administration.

2. “Guide for Making a Sectionalizing Study on Rural Electric Systems.” REA Bulletin 61-

2, March 1958.

3. “Review of Sectionalizing Fundamentals,” L.B. Crann. REA Field Conference Denver, 

Colorado, October 20, 1972.

4. “Guide for Making a Sectionalizing Study on Rural Electric Systems.” REA Bulletin 61-

2, March 1978 (Reprinted January 1982).

5. “Downed Power Lines: Why They Can’t Always Be Detected.” IEEE Power 

Engineering Society, February 22, 1989.

6. “Ground Fault Impedance Valves for System Protection.” Project 96-05. Final Report,

August 1997. Published by Cooperative Research Network (CRN) and National Rural 

Electric Cooperative Association.

7. “Electric Utility Engineering Reference Book for Distribution Systems.” Westinghouse 

Electric Corporation, 1959, 1965.

8. “Distribution System Protection Manual.” McGraw-Edison Company Power Systems 

Division Bulletin No. 71022, 1970.

9. “Symmetrical Components,” Wagner and Evans. McGraw-Hill Book Company, 1933.

10. “Elements of Power System Analysis,” Stevenson. McGraw-Hill Book Company, 1955.

11. “Electrical Distribution—System Protection,” Third Edition. Cooper Power Systems, 

1990.

12. “Applied Protective Relaying.” Westinghouse Electric Corporation, 1976.

13. “Draft Guideline for Protective Relay Applications to Distribution Lines.” IEEE 

PC37.230/D3.0, September 6, 2005.

14. “Symmetrical Components for Power Systems Engineering,” J. Lewis Blackburn. CRC 

Press, 1993.