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IEEE Guide For The Design of Low-Voltage Auxiliary Systems For Electric Power Substations

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IEEE Guide for the Design of Low-

Voltage Auxiliary Systems for

Electric Power Substations

IEEE Power and Energy Society

IEEE IEEE Std 1818™-2017

3 Park Avenue
New York, NY 10016-5997
USA

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IEEE Std 1818™-2017

IEEE Guide for the Design of Low-

Voltage Auxiliary Systems for
Electric Power Substations

Sponsor

Substations Committee
of the
IEEE Power and Energy Society

Approved 28 September 2017

IEEE-SA Standards Board

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Abstract: Considered in this guide are the components of both the ac and dc systems and the
provided guidelines and recommendations for designing the appropriate systems for the substation
under consideration. This guide includes the low-voltage auxiliary systems from the source(s) to the
distribution point(s). Reliability requirements and load characteristics are discussed and distribution
methods are recommended.

Keywords: ac system, auxiliary systems, battery, dc system, IEEE 1818, low voltage, station
power, station service

The Institute of Electrical and Electronics Engineers, Inc.

3 Park Avenue, New York, NY 10016-5997, USA

Copyright © 2017 by The Institute of Electrical and Electronics Engineers, Inc.

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Participants

At the time this IEEE guide was completed, the D9 Working Group had the following membership:

Hanna Abdallah, Co-Chair

Joseph Gravelle, Co-Chair
Radoslav Barac, Secretary

Gary Beane Debra Longtin James Purcell

Steven Brown Reginaldo Maniego Christian Robles
Donald Campbell James Massura Oscar Santos
Revinal Dela Rosa DJ Moreau Hamid Sharifnia
Brian Farmer Michael Nadeau Boris Shvartsberg
Charles Haahr Mike Noori Donald Wengerter
Jason Hawkins Shashikant Patel Aaron Wilson
Zachary Hoffmann Thomas Proios Linda Zhao
Bruce Largent Adam Zook

The following members of the balloting committee voted on this guide. Balloters may have voted for approval,
disapproval, or abstention.

Hanna Abdallah James Houston Bansi Patel

William Ackerman John Kay Shashikant Patel
Curtis Ashton Yuri Khersonsky Branimir Petosic
Ian Backus James Kinney Anthony Picagli
Radoslav Barac Hermann Koch Thomas Proios
Thomas Barnes Boris Kogan James Purcell
G. Bartok Jim Kulchisky Charles Rogers
W. J. (Bill) Bergman Saumen Kundu Thomas Rozek
Clarence Bradley Mikhail Lagoda Ryandi Ryandi
Matthew Braet Chung-Yiu Lam Steven Sano
Derek Brown Bruce Largent Bartien Sayogo
Kent Brown Thomas La Rose Robert Seitz
Gustavo Brunello Albert Livshitz Nikunj Shah
Kevin Buhle Jon Loeliger Devki Sharma
William Bush Debra Longtin Vinod Simha
William Byrd Reginaldo Maniego Jeremy Smith
James Cain James Massura Jerry Smith
William Cantor Larry Meisner Philip Spotts
Paul Cardinal Daleep Mohla Ryan Stargel
Randy Clelland Carl Moller Wayne Stec
Timothy Conser DJ Moreau Andrew Steffen
Gary Donner Ryan Musgrove David Tepen
Brian Farmer Michael Nadeau Eric Thibodeau
Paul Forquer Dennis Neitzel Michael Thompson
Tirthatarun Ghosh Arthur Neubauer Richard Tressler
Dastidar Michael Newman James Van De Ligt
Joseph Gravelle Joe Nims John Vergis
Randall Groves James O’Brien John Wang
Ajit Gwal T. W. Olsen Diane Watkins
Charles Haahr Lorraine Padden Donald Wengerter
Werner Hoelzl Chris Pagni Kenneth White
Gary Hoffman Jian Yu

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When the IEEE-SA Standards Board approved this guide on 28 September 2017, it had the following
membership:

Jean-Philippe Faure, Chair

Gary Hoffman, Vice Chair
John Kulick, Past Chair
Konstantinos Karachalios, Secretary

Chuck Adams Thomas Koshy Robby Robson

Masayuki Ariyoshi Joseph L. Koepfinger* Dorothy Stanley
Ted Burse Kevin Lu Adrian Stephens
Stephen Dukes Daleep Mohla Mehmet Ulema
Doug Edwards Damir Novosel Phil Wennblom
J. Travis Griffith Ronald C. Petersen Howard Wolfman
Michael Janezic Annette D. Reilly Yu Yuan

*Member Emeritus

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Introduction

This introduction is not part of IEEE Std 1818-2017, IEEE Guide for the Design of Low-Voltage Auxiliary Systems for
Electric Power Substations.

IEEE Guide 1818 was created by members of Working Group D9 and is under the sponsorship of the
Substations Committee of the IEEE Power & Energy Society. This guide provides guidance and information
to substation engineers on factors to consider in the design of ac and dc auxiliary systems for application in
electric substations. This guide references several existing standards and is not intended to replace existing
documentation, but to provide guidance for the application of ac and dc systems specifically in substation
applications.

Acknowledgment

The D9 Working Group would like to acknowledge Chuck Haahr for his fine work as technical editor.

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Contents

1. Overview�� 13
1.1 Scope�� 13
1.2 Purpose�� 13

2. Normative references�� 13

3. Definitions�� 13

4. Design of substation ac auxiliary systems�� 16

4.1 Introduction�� 16
4.2 Design criteria�� 17
4.3 Station power source requirements�� 19
4.4 Load analysis�� 21
4.5 Conductor selection�� 23
4.6 Station power transformer�� 29
4.7 Transfer switch�� 41
4.8 Bus layout and distribution circuits configuration�� 44
4.9 AC distribution panelboards for electrical substations�� 52
4.10 AC auxiliary system protection�� 54
4.11 Equipment specifications�� 55
4.12 Operation and maintenance considerations�� 56

5. Design of substation dc auxiliary system�� 58

5.1 Design criteria�� 58
5.2 Typical equipment served by the dc system�� 60
5.3 One-line diagram�� 61
5.4 DC batteries�� 62
5.5 Battery chargers�� 66
5.6 DC panels�� 70
5.7 Load transfer methods�� 70
5.8 Design considerations�� 72
5.9 Maintenance provisions�� 77

Annex A (informative) Bibliography�� 78

Annex B (informative) Conductor selection examples�� 81

Annex C (informative) Battery sizing example�� 85

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List of Figures

Figure 1—Block diagram for typical substation ac auxiliary power�� 17

Figure 2—Possible SSVT locations�� 20

Figure 3—Conductor selection process flow chart�� 26

Figure 4—Single-phase-to-ground connection�� 35

Figure 5—Single-phase transformer with phase-to-phase connections�� 36

Figure 6—Delta-delta connection�� 37

Figure 7—Delta-wye connection�� 38

Figure 8—Grounded wye–grounded wye transformer connection�� 39

Figure 9—Two leg open delta from grounded wye�� 40

Figure 10—Two leg open delta from delta�� 41

Figure 11—Simplest panelboards�� 45

Figure 12—Variation of simplest panelboard�� 45

Figure 13—Sub-panelboard�� 46

Figure 14—Reliable and flexible panelboard system�� 47

Figure 15—Panelboards with backup generator�� 47

Figure 16—Expanded radial system�� 48

Figure 17—Primary selective system�� 49

Figure 18—Secondary selective system�� 50

Figure 19—Secondary selective system with backup generator�� 51

Figure 20—Secondary selective system with backup generator and additional redundancy�� 51

Figure 21—Simplified dc system block diagram�� 58

Figure 22—Possible load case�� 63

Figure 23—Battery with breaker disconnect and charger at dc panels�� 68

Figure 24—Battery with fuse disconnect and charger at dc panels�� 68

Figure 25—Battery with no disconnect�� 69

Figure 26—Simplified parallel/transfer with two disconnects�� 71

Figure 27—Simplified parallel/transfer with one disconnect�� 71

Figure 28—DC transfer scheme�� 72

Figure 29—Rack designs�� 75

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Figure C.1—Substation one-line diagram�� 85

Figure C.2—Duty cycle tripping�� 87

Figure C.3—Completing the battery cell–sizing worksheet�� 91

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List of Tables

Table 1—Generic substation ac load study�� 24

Table 2—Typical kVA ratings for distribution transformers�� 31

Table 3—Distribution transformer short-circuit withstand capability�� 33

Table 4—Transformer BIL ratings (IEEE Std C57.12.20 [B23])�� 34

Table 5—Typical voltage ratings for ac panelboards�� 52

Table 6—Working clearances for electrical panels�� 57

Table C.1—DC load table�� 88

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IEEE Guide for the Design of Low-
Voltage Auxiliary Systems for
Electric Power Substations

1. Overview
1.1 Scope
This guide will consider the components of both the ac and dc systems and provide guidelines and
recommendations for designing the appropriate systems for the substation under consideration. This
guide covers the low-voltage auxiliary systems from the source(s) to the distribution point(s). Reliability
requirements and load characteristics are discussed, and distribution methods are recommended.

1.2 Purpose
The low-voltage ac and dc auxiliary systems comprise very important parts of the substation equipment. The
design of the ac and dc auxiliary systems facilitates the safe and reliable operation of the substation. This
guide considers various factors that affect the design of the ac and dc auxiliary systems such as reliability, load
requirements, system configurations, personnel safety, and protection of auxiliary systems equipment.

2. Normative references
The following referenced documents are indispensable for the application of this document (i.e., they must
be understood and used, so each referenced document is cited in text and its relationship to this document is
explained). For dated references, only the edition cited applies. For undated references, the latest edition of the
referenced document (including any amendments or corrigenda) applies.

IEEE Std 485™, IEEE Recommended Practice for Sizing Lead-Acid Batteries for Stationary Applications.1,2

IEEE Std 525™, IEEE Guide for the Design and Installation of Cable Systems in Substations.

3. Definitions
For the purposes of this document, the following terms and definitions apply. The IEEE Standards Dictionary
Online should be consulted for terms not defined in this clause.3

1
The IEEE standards or products referred to in this clause are trademarks of The Institute of Electrical and Electronics Engineers, Inc.
2
IEEE publications are available from The Institute of Electrical and Electronics Engineers, 445 Hoes Lane, Piscataway, NJ 08854, USA
(http://standards.ieee.org).
3
IEEE Standards Dictionary Online subscription is available at: http://www.ieee.org/portal/innovate/products/standard/
standards_dictionary.html.

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IEEE Std 1818-2017
IEEE Guide for the Design of Low-Voltage Auxiliary Systems for Electric Power Substations

authority having jurisdiction (AHJ): The organization, office, or individual that has the responsibility and
authority for approving equipment, installations, or procedures.

available short-circuit current: (at a given point in a circuit) The maximum current that the power system
can deliver through a given circuit to any negligible-impedance short circuit applied at the given point, or at
any other point that will cause the highest current to flow through the given point.

basic impulse insulation level (BIL): A reference impulse insulation strength expressed in terms of the crest
value of the withstand voltage of a standard full impulse voltage wave.

battery duty cycle: The sequence of loads a battery is expected to supply for specified time periods.

cell size: The rated capacity of a cell, or the number of positive plates in a cell.

equalizing charge: A charge, at a level higher than the normal float voltage, applied for a limited period of
time, to correct inequalities of voltage, specific gravity, or state of charge that may have developed between the
cells during service.

extra-high voltage (EHV): A maximum system voltage that is greater than 242 kV but less than 1000 kV.

ferroresonance: (A) A phenomenon usually characterized by overvoltages and very irregular wave shapes
and associated with the excitation of one or more saturable inductors through capacitance in series with the
inductor. (B) An electrical resonant condition associated with the saturation of a ferromagnetic device, such
as a transformer, through capacitance. Ferroresonance can arise when (1) due to dissimilar phase switching,
the capacitance normally in shunt with the ferromagnetic device becomes energized in series with the device,
(2) a weak source is isolated with a lightly loaded feeder containing power-factor-correction capacitors.
For example, if the resulting voltage buildup produces saturation of the feeder transformers, there will be
an interchange of energy between the system capacitance and the nonlinear magnetizing reactance of the
transformers.

float charge: A constant-voltage applied to a battery to maintain it in a fully charged condition, while
minimizing degradation or water consumption.

float service: Operation of a dc system in which the battery spends the majority of the time on float charge with
infrequent discharge. Syn: standby service.

fully rated system: Every protective device is rated to at least the available fault current at the service point.

high voltage: A class of nominal system voltages equal to or greater than 100 000 V and equal to or less than
242 000 V.

low voltage: Voltage levels that are less than or equal to 1 kV.

medium voltage: A class of nominal system voltages greater than 1000 V and less than 100 000 V.

molded-case circuit breaker (MCCB): A circuit breaker that is assembled as an integral unit in a supporting
and enclosing housing of insulating material.

nominal battery voltage: The value assigned to a battery of a given voltage class for the purpose of convenient
designation. The operating voltage of the system may vary above or below this value.

nominal system voltage: The ac system voltage by which the system is designated and to which certain
operating characteristics of the system are related.

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IEEE Std 1818-2017
IEEE Guide for the Design of Low-Voltage Auxiliary Systems for Electric Power Substations

pad-mounted transformer: An outdoor transformer utilized as part of an underground distribution system,

with enclosed compartment(s) for primary-voltage and secondary-voltage cables entering from below, and
mounted on a foundation pad.

panelboard: A single panel or group of panel units designed for assembly in the form of a single panel,
including buses and automatic overcurrent devices, and equipped with or without switches for the control
of light, heat, or power circuits; designed to be placed in a cabinet or cutout box placed in or against a wall,
partition, or other support; and accessible only from the front. (Adapted from the NEC.) See also: switchboard.

period: An interval of time in the battery duty cycle during which the current (or power) is assumed to be
constant for purposes of cell-sizing calculations.

rated capacity (lead-acid): The capacity assigned to a cell by its manufacturer for a given discharge rate, at a
specified electrolyte temperature and specific gravity, to a given end-of-discharge voltage.

remote terminal unit (RTU): A piece of equipment located at a distance from a master station to facilitate
monitoring and control the state of outlying power equipment and to communicate the information back to the
master station or host.

separately derived system: A wiring system whose power is derived from a generator, transformer, or
converter windings and has no direct electrical connection, including a solidly connected grounded circuit
conductor, to supply conductors originating in another system.

series rated system: Each protective device needs to only be rated for the available fault current at its
terminals.

station service voltage transformer (SSVT): A transformer that supplies power from a station high-voltage
bus to the station auxiliaries and also to the unit auxiliaries during unit startup and shutdown, or when the unit
auxiliaries transformer is not available, or both.

switchboard: (A) A large, single-panel, frame, or assembly of panels on which are mounted, on the face, back,
or both, switches, overcurrent and other protective devices, buses, and usually instruments. Switchboards are
generally accessible from the rear as well as from the front, and are not intended to be installed in cabinets.
(Adapted from the NEC.) (B) A metal-enclosed panel or assembly of panels that may contain molded case,
insulated case, or power circuit breakers, bolted pressure contact or fusible switches, protective devices,
and instruments. These devices may be mounted on the face or the back of the assembly. Switchboards are
generally accessible from the rear as well as from the front; however, they can be front accessible only.

switchgear: (A) A general term covering switching and interrupting devices and their combination with
associated control, instrumentation, metering, protective, and regulating devices and covering assemblies
of these devices with associated interconnections, accessories, and supporting structures used primarily
in connection with the generation, transmission, distribution, and conversion of electrical power. (B) An
assembly of equipment used to switch and control electrical power.

tertiary winding: An additional winding in a transformer that can be connected to a synchronous condenser,
a reactor, an auxiliary circuit, etc. For transformers with wye-connected primary and secondary windings, it
may also help (1) to stabilize voltages to the neutral, when delta connected (2) to reduce the magnitude of third
harmonics when delta connected (3) to control the value of the zero-sequence impedance (4) to serve load.

valve-regulated lead-acid (VRLA) cell: A lead-acid cell that is sealed with the exception of a valve that
opens to the atmosphere when the internal pressure in the cell exceeds atmospheric pressure by a preselected

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IEEE Std 1818-2017
IEEE Guide for the Design of Low-Voltage Auxiliary Systems for Electric Power Substations

amount. VRLA cells provide a means for recombination of internally generated hydrogen and oxygen to limit
water consumption.

vented battery: A battery in which the products of electrolysis and evaporation are allowed to escape to the
atmosphere as they are generated. These batteries are also commonly referred to as flooded.

4. Design of substation ac auxiliary systems

4.1 Introduction
The objective of this section is to provide the required information for the substation engineer to design an ac
auxiliary system as applicable for a substation. Figure 14 represents an ultimate station power configuration
that can be applied to any substation depending on substation size, reliability, and load requirements. One ac
source is designated as the normal or preferred source, and the second and third (if available or necessary)
sources are designated as the backup source(s). A loss of the normal source may require transferring the
load to a backup source. In substations with multiple sources, the sources are typically connected through a
transferring scheme. One or more ac panels are used to serve the substation load as required.

4
Notes in text, tables, and figures of a standard are given for information only and do not contain requirements needed to implement this
standard.

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IEEE Std 1818-2017
IEEE Guide for the Design of Low-Voltage Auxiliary Systems for Electric Power Substations

NOTE—The above letters reference different subsections covering specific components of ac auxiliary power schemes as
follows: A: see 4.2, 4.3, and 4.4; B: see 4.5; C: see 4.6; D: see 4.7; E: see 4.8; F: see 4.9.

Figure 1—Block diagram for typical substation ac auxiliary power

In the first step of the design process, the design engineer should review:

a) The design criteria for the station service.

b) The number of station service sources available. The source type could be single-phase or three-phase.
c) The load required to be served.

4.2 Design criteria

4.2.1 Introduction

In general, the design criteria of the ac auxiliary system are determined by the existing, proposed, and future
substation loads, typically measured in kVA. Diversity of the total connected load needs to be considered as
not all loads are concurrent. For example, the control enclosure cooling system should not run simultaneously
with the heating system; redundant cooling systems are not concurrent; and spring charging motors for power
circuit breakers may not run concurrently.

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Also considered with the substation loads are the equipment voltage ratings and phase requirements (single-
or three-phase) of the substation equipment to be installed. When sizing auxiliary transformers and other
station power components, the designer should consider substation expansion and short-term loads, such
as construction or maintenance loads. Timing of any proposed expansion may dictate initial installation or
deferral of station power components. Some loads may be identified as critical, which requires ac service to
be maintained continuously. Depending upon such critical loads, the substation may require two or three ac
station service sources with the ability to transfer loads between sources.

Due to the importance of the station power to the operation and reliability of the substation, the following factors
should be considered in order to determine the required station power configurations. This guide indicates
various equipment ratings (voltage, ampacity, capacity, etc.) compliant with IEEE and NEMA standards.
Equipment with other ratings conforming to standards published by other organizations is available. Design
philosophies and practices presented in this guide should be adapted appropriately based on the equipment
utilized in design and authority having jurisdiction.

4.2.2 System stability

System stability considerations are important for the reliability requirements of the station power. If the loss
of a substation results in a system disturbance to the electrical grid that could create a blackout condition in
the area, the station service system should have an independent power source. The auxiliary power system
requirements for redundant supply may also need to include the ability for the station to complete black start
operations—meaning a local generation source is required to supply the station power system and battery
chargers for the protection circuits in the event of a system collapse and subsequent repowering. See 4.3.5 and
4.7.5.

4.2.3 Customer service and loss of revenue

Some substations serve critical loads such as hospitals, manufacturing complexes, government offices,
schools, or serve large blocks of load where the substation reliability requirements are high. Some substations
are connected to power plants that obtain at least a portion of their station service from the substation. Loss
of the substation station service may result in tripping the plant and lead to a loss of revenue. These type of
stations may need multiple station power sources. Other less critical substations may only have one station
power source.

4.2.4 Equipment protection

Substation equipment protection considerations should be given to all substations regardless of the size.
High-voltage and extra-high-voltage substations contain expensive equipment such as transformers where
the cooling system is important for operation and a backup source is generally required. Similarly, protective
relays or other electronic control equipment located in high-temperature areas may require a continuous
cooling system and a second power source. Separately implemented control and protection schemes may be
implemented to mitigate the likelihood of equipment damage. The control and protection schemes are outside
the scope of this guide.

For neutral grounding, there are several different grounding philosophies. The designer should ground station
service transformer neutrals per utility practice or local jurisdictional requirements.

4.2.5 Design considerations

The designer may consider the following list when designing an ac system for substations:

a) Location of ac equipment—indoor or outdoor

b) Number of ac panels
c) Essential loads

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d) Non-essential loads
e) Conductor types and sizes
f) Voltage drop calculations
g) Jurisdictional requirements such as the National Electrical Code® (NEC®) [B34]5
h) Arc flash considerations

4.2.6 Selection of auxiliary system voltage

Several secondary voltage levels are available for ac auxiliary systems. When determining the secondary
voltage, the designer may use a standard voltage level determined by the designer’s power system or use a
voltage level based on the supplied equipment. Either way, the designer should consider the factors listed
in 4.4. Voltage ratings listed in this document are typical of North American power systems, but are not all
inclusive. Variations to these voltages discussed in this document are common in other areas of the world.

4.3 Station power source requirements

4.3.1 Introduction

Three ac sources are represented in Figure 1. One source, typically the most reliable source, is designated as
the primary, or normal, source. The second source is designated as the backup source and is used when the
normal source is unavailable. The third source is used as a second backup and is utilized only when both the
normal and secondary sources are unavailable.

There are four sources that are commonly used as substation ac auxiliary power sources:

a) Power transformer tertiary

b) Substation bus
c) Distribution line
d) Standby generators

Each source has advantages and disadvantages. Substation location, substation equipment, and bus
configurations may dictate which source is normal. The selection of redundant sources is important so an
outage would not remove both normal and alternate sources.

4.3.2 Power transformer tertiary

The tertiary of a power transformer in substations can provide a reliable source for station power applications.
When the primary and secondary windings are connected wye, a third winding connected in delta is typically
used for transformer stabilizing purposes. A tertiary winding presents a low impedance path for zero-sequence
currents and harmonics, thereby reducing the zero-sequence impedance presented to the outside world, while
avoiding the problem of tank heating. The tertiary winding typically has a volt-ampere rating between 20% to
30% of the volt-ampere rating of the primary winding. The tertiary winding typically has a medium-voltage
rating up to 34.5 kV. If there are plans to use the transformer tertiary for station auxiliary power purposes, the
tertiary winding is brought out of the transformer through bushings.

The volt-ampere rating of the tertiary winding typically exceeds the maximum volt-ampere requirement of a
substation’s ac auxiliary power load and is an adequate ac auxiliary power source.

5
The numbers in brackets correspond to those of the bibliography in Annex A.

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Consideration should be given to the available fault current at the tertiary bus. In the case that the fault current
magnitude exceeds the interrupting rating of the protective equipment, such as fuses or circuit breakers,
several options can be employed to mitigate the fault current. These options include installing current limiting
fuses, resistors, or reactors; or increasing the transformer tertiary impedance.

4.3.3 Substation bus

The substation bus is another available source for auxiliary station power. When distribution voltage is
available, distribution transformers are typically utilized for station service. Transmission voltage buses can
be used, but are not typically preferred due to their relatively high cost. A station service voltage transformer
(SSVT) is used to transform the transmission bus voltage to the ac auxiliary voltage. These transformers are
available for voltages from 34.5 kV to 345 kV. One or more SSVTs might be required, depending on required
station power load. See Figure 2 for possible connections.

Figure 2—Possible SSVT locations

The SSVT is located within the line or bus zone of protection. A fault on the SSVT may be cleared by the
protective relay or by a high-side fuse. Depending on the size of the SSVT, the required fuse ampacity may not
be available for certain voltage levels. The protection engineer should be consulted for the final location when
determining the required SSVT protection. Low-side overcurrent protection of the secondary conductors
used for auxiliary station service are typically applied as close to the secondary terminals as possible. Surge
protection is typically needed on the high-side connection of the SSVT. If arresters protecting other equipment
in the station are close enough to protect the SSVT, a dedicated arrester for the SSVT may not be required.
Guidance on surge protection and separation effects can be found in IEEE Std C62.22™ [B27].

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4.3.4 Distribution feeders

A common source for substation auxiliary station power is the use of nearby distribution feeder circuits. The
feeder primary is typically connected to a step-down transformer located near the control enclosure. If the
feeder is owned by another utility, a revenue meter is installed. Since the feeder has more exposure to faults, it
is typically used as a backup to the primary source.

4.3.5 Standby generators

Generators may also be used as an ac auxiliary power source. In substations, generators are typically used
as an emergency/backup power source. There are many disadvantages in using generators as a permanent ac
auxiliary source. Choosing to use generators as a permanent ac auxiliary source requires additional design
considerations. When using generators, designers should consider fire-protection systems, fuel-storage
systems, ventilation, and the climate. Generators may also be housed in a separate building structure, which
requires the installation of a ventilation system. If the generators are located outdoors in the switchyard, there
is a reduced need for fire-protection installation, fuel-storage systems, or building ventilation.

4.4 Load analysis

4.4.1 Introduction

In order to design a reliable station service system, the ac loads for the system need to be identified and
calculated. The designer should consider the ultimate plan for the substation in order to account for future
loads anticipated at the station. After the ac loads have been identified, the demand and load factors for each
load should be applied. The resultant ac loads are used to size the station service transformer(s) and determine
associated conductor ratings. The use of demand and load factors allow for the economical selection of the
transformer size without being overly conservative.

4.4.2 Load identification

The following types of loads should be considered when identifying the overall station load:

a) Substation major equipment loads, including:

1) Transformer cooling fans
2) Transformer pumps
3) Load tap changer motor drives
4) Breaker ac charging motors
5) Equipment heaters
6) Yard loads—This load includes yard lighting and receptacle loads for equipment testing. Also
transformer oil-retention pit pumps load should be included.
b) Control enclosure loads: The control enclosure houses critical equipment used for the protection and
operation of the substation. This equipment includes substation protective relays, metering, battery
chargers, and control equipment. For optimum operation of this equipment, the cooling and heating
of the control enclosure should be operated within a specified temperature range. Other loads may
include control enclosure lights and receptacle loads.
c) Maintenance equipment load: For large substations, maintenance crews may elect to use a portable
generator as a source for the maintenance equipment. If maintenance equipment is served from the
station power transformer, the load of the maintenance equipment should be included.

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d) Ancillary structures: The substation may have additional structures for maintenance, storage, or other
purposes. Include any heating, ventilation, and air conditioning (HVAC), equipment, or structure
auxiliary load if it is sourced from the substation ac system.
e) Future build out: In order to account for the ultimate load of the substation, any future loads should be
considered and included in calculating the maximum station load. This includes loads for additional
power transformers, cooling and heating, breakers, etc.

4.4.3 Equipment rating identification

Once all planned and future loads have been identified, the ratings for each load need to be established. Ratings
may be provided by the equipment manufacturer in amperes, watts, or kVA. In order to calculate the station
load, a common basis needs to be used. Either current or kVA are typically used because both are easy and
straightforward. If current is used, the total power should be calculated based on the respective voltage class
of the equipment. Loads also should be segregated between single-phase and three-phase. For multiple-phase
systems, loads need to be balanced between phases for optimal transformer loading.

4.4.4 Demand and load factors

The demand factor is the ratio of the maximum coincident demand of a system, or part of a system, to the total
load connected to the system, or part of the system, per IEEE Std 141™ [B3]:

maximum coincident system demand

demand factor = (1)
total load connectted to the system

Demand factors can also be established for a subset of similar equipment (such as receptacles) rather than only
a single system-level demand factor.

The second consideration is the amount of time that a load runs based on a selected period of time, referred
to as load factor. Load factor is the ratio of the average load over a designated period of time to the peak load
occurring in that period per IEEE Std 141 [B3]:

average load over a designated time period

load factor = (2)
peak load occcuring in that period

The period for which the load factor is considered should be chosen based on the load capability of the
transformer(s) that is used in the design. For best practice, loads operating for three hours or more should be
considered as continuous load. High loads that operate for short periods of time also need special consideration
in relation to the entire system load.

4.4.5 Load calculations

After equipment ratings have been established, the demand and load factors are selected. Selecting the demand
and load factors often requires engineering judgment in terms of familiarity with substation operations and
understanding how the loads such as receptacles, lighting, air conditioning, transformer cooling fans, etc.,
are applied. Applying the demand and load factors provides a more realistic adjusted load (rather than simply
summing up the nameplate ratings of the equipment) for sizing of the station service transformers. In the
process of determining the ultimate loading, various conditions (generally the worst case scenario) under
which loads may be operated should be considered, such as seasonal and/or time of day. The person responsible
for the sizing of the transformer can perform the total adjusted load calculations.

For information on the process of sizing transformers, see 4.6. Be aware that the thermal time constants
(overload capability) of transformers are determined by the manufacturers and are typically different for

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dry type and liquid-immersed units. Refer to IEEE Std C57.91™ [B24] and IEEE Std C57.96™ [B25] for
additional information.

A general example of a substation load analysis is shown Table 1. The example only considers the case of loads
running during the daytime in the summer. It is not an exact or comprehensive analysis for substations, but
intended to illustrate one practical approach to the process. Load analysis varies based on substation voltage
class, capacity, climate, and any non-traditional loads.

In the example, adjusted kVA load (for transformer sizing) is determined as follows:

adjusted kVA = quantity × kVA per unit × demand factor × load factoor (3)

Justification or reasoning for the demand and load factors should be documented, such as shown in the
comments column of the example.

4.5 Conductor selection

4.5.1 Introduction

Subclause 4.5 presents general information useful in the selection of both line and load conductors. It describes
various characteristics essential to conductor selection: conductor type, insulation type, insulation voltage
rating, insulation temperature rating, conductor terminations, and conductor size. An essential document in
understanding ac and dc cables used in substation design is IEEE Std 525™.

A process flow chart has been developed to aid the designer/engineer in the conductor selection process.
However, any rules and restrictions set forth by the authority having jurisdiction (AHJ) in the area that work is
being performed supersede any documents referenced in this section.

This section covers the selection of both line and load conductors. There are six main characteristics to consider
when selecting a conductor—conductor type, insulation type, cable insulation voltage rating, cable insulation
temperature rating, the terminations being connected to (temperature rating, ampacity, etc.), and conductor
size. The engineer performing the conductor selection can use the process flow chart shown in Figure 3 and
described in 4.5 for guidance on conductor selection based on these characteristics.

For specific examples on selecting conductors (control, instrument, power, and communication), refer to the
annexes in the latest version of IEEE Std 525.

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Table 1—Generic substation ac load study
Three-
Single-
Equipment Volts Amps kW Power kVA Load Demand phase
Qty Phase phase load Comments
type (ac) (each) (each) factor (each) factor factor demand load
(kVA)
(kVA)
Outdoor Considering one in use
4 1ø 120 15.00 1.530 0.85 1.800 1.000 0.25 1.80
receptacles at any given time.
Considering two in use at any given
time, more constant loads than
Indoor outdoor (commissioning, etc.).
8 1ø 120 15.00 1.530 0.85 1.800 1.000 0.25 3.60
receptacles Load factor is a median estimate for
any connected equipment, which
could run for two hours or more.

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Outdoor
10 1ø 120 1.67 0.170 0.85 0.200 1.000 0 0.00 Lights off during day.
lighting

Copyright
Estimated load and demand
Indoor
20 1ø 208 1.20 0.213 0.85 0.250 1.000 1.000 5.00 factors are based on potential
building lights
occupancy at any given time.

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Basement lights are typically only

24
© 2017 IEEE.
turned on as needed (maintenance,
Basement
70 1ø 120 0.21 0.021 0.85 0.025 1.000 1.000 1.75 etc.), but could be on for extended
lighting

on October
periods of time, depending on the
IEEE Std 1818-2017

type of work being performed.

All rights
One running at any given time,

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Roll-up
2 3ø 208 3.27 1.000 0.85 1.176 0.000 1.000 0.00 typically not running more than 15 s
door motor
per operation (hence 0 load factor).

reserved.
Estimated four running
Exhaust fans 6 3ø 208 2.61 0.800 0.85 0.941 1.000 0.667 3.76
at any given time.
Fire alarm
2 1ø 120 4.17 0.500 1.00 0.500 1.000 1.000 1.00 Both running at all times.
panel
Load factor depends on
3 HP requirements (ambient conditions
battery room 1 3ø 208 7.31 2.238 0.85 2.633 1.000 1.000 2.63 for chargers, etc.). In this case,
IEEE Guide for the Design of Low-Voltage Auxiliary Systems for Electric Power Substations

HVAC system it is assumed that the load is

constant for three hours or more.
Table continues

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Table 1—Generic substation ac load study (continued)
Three-
Single-
Equipment Volts Amps kW Power kVA Load Demand phase
Qty Phase phase load Comments
type (ac) (each) (each) factor (each) factor factor demand load
(kVA)
(kVA)
Based on the situation of having a dc
system outage that completely drains
the batteries, requiring full restoration
Battery upon re-energization. Both chargers
2 3ø 208 53.00 17.164 0.90 19.072 1.000 1.000 38.14
charger would run at maximum output
until the batteries have recharged,
which could be over three hours,
depending on the battery system.

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9 kW control
building 1 3ø 208 29.39 9.000 0.85 10.588 1.000 1.000 10.59 Assumed worst case summer load.

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maintenance 30 1ø 120 15.00 1.530 0.85 1.800 0.500 0.133 3.60
any connected equipment, which

25
(10-receptacle

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Though there are ten receptacles,
IEEE Std 1818-2017

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typically, no more than two or three
are used at a time for smaller loads
Communication

11,2024
(laptops, test equipment, etc.).
rack power strip 1 1ø 120 15.00 1.530 0.85 1.800 0.300 0.500 0.27
Those small loads require less than

reserved.
(10 receptacle)
half the available ampacity of any
given receptacle. Rough estimate of
180 VA per receptacle used here.
420 MVA Only one transformer. Loads
transformer mostly consist of fans, pumps,
1 3ø 208 50.00 16.193 0.90 17.992 1.000 1.000 17.99
auxiliary etc., which are considered to be
power supply running for at least three hours.
IEEE Guide for the Design of Low-Voltage Auxiliary Systems for Electric Power Substations

1ø and 3ø kVA totals 17.02 73.12

Total kVA 90.14

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IEEE Std 1818-2017
IEEE Guide for the Design of Low-Voltage Auxiliary Systems for Electric Power Substations

Figure 3—Conductor selection process flow chart

4.5.2 Conductor type

The first step in conductor selection is to determine the type of conductor to be used. The conductor material
and stranding type are the most important factors to consider (i.e., aluminum versus copper and stranded
versus solid). There are advantages to using each type of conductor depending on the application. Consider
characteristics such as their weight, conductivity, and surrounding environmental conditions for the application
of the conductors. Copper has historically been used for conductors of insulated cables due to its desirable
electrical and mechanical properties. The need for mechanical flexibility usually determines whether a solid or
a stranded conductor is used, and the degree of flexibility is a function of the total number of strands. A single
insulated or bare wire is defined as a conductor, whereas an assembly of two or more insulated conductors,
with or without an overall covering, is defined as a cable. All of this information is typically available from the
cable manufacturer. For additional information on conductor material and stranding, see IEEE Std 141 [B3]
and IEEE Std 525.

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4.5.3 Cable insulation voltage rating

Cable insulation voltage rating is selected based on the operating voltage, and the expected fault-clearing
time. Further guidance on selecting the voltage rating of cables should be provided by the AHJ, or by specific
product literature provided by the manufacturer.

4.5.4 Cable insulation type

For jacketed conductors, the insulation type should be selected to meet the local environmental conditions—
such as dry, wet, or both, and chemical resistance. Typically, information on the application of different
insulation types is available from the manufacturer. There may also be requirements by the AHJ. IEEE Std 141
[B3] and IEEE Std 525 provides general guidance on cable insulation selection.

4.5.5 Cable temperature rating

The temperature rating of the cable should be selected to withstand the ambient temperature of the environment
in which it is installed, in addition to any self-heating that may occur. The designer selecting the conductor
should note that the conductor installation may cross multiple environments, all of which should be considered.
Typical conductor temperature ratings are 60 °C, 75 °C, 90 °C, and 105 °C.

4.5.6 Consideration for the characteristics of termination points and connected equipment

The ampacity of a conductor with a given temperature rating may need to be reduced depending on the type
of termination points to which the conductor is connected. The conductor should not be allowed to become
hotter than the thermal rating of the interconnected equipment. Typical equipment terminals are limited by the
manufacturer to 75 °C. For an example involving cable selection based on termination ratings, see Annex B.

4.5.7 Conductor size calculations

4.5.7.1 Introduction

The following factors should be considered when selecting the conductor size:

a) Required ampacity (initial conductor size selection)

b) Temperature, burial depth, and bundling corrections
c) Voltage drop
d) Short-circuit calculations

4.5.7.2 Required ampacity (initial conductor size selection)

All conductors should be initially sized based on the ampacity of the load(s) they are supplying. The size of the
conductor may be based on requirements provided by the AHJ, or by specific product literature provided by
the manufacturer. For an example involving the initial conductor size selection, reference Annex B. Once the
initial conductor type and size selection is made, verify the conductor has been sized to avoid overheating and
excessive voltage drop. If the verifications prove the conductor size to be inadequate, then the engineer should
make an economically and practically sound decision to redesign the load-distribution scheme. The redesign
decision could involve any of the following options:

a) Resize the conductor (reduces voltage drop)

b) Reallocate loads to, or rebalance loads among, different circuits to adjust load distribution
c) Add additional circuits to accommodate new loads (may require a larger ac panel)
d) Decrease the distance of circuit run (reduces voltage drop)

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e) Consider a higher voltage distribution system and local step-down transformers

4.5.7.3 Temperature, burial depth, and bundling corrections

The ampacity rating of a cable may vary based on ambient temperature, burial depth, and proximity to other
current-carrying conductors. The manufacturer can provide ampacity ratings based on a range of ambient
temperatures. If the ambient temperature in the area of a particular cable installation is not within range of
the ambient temperature specified by the manufacturer, then the ampacity should be adjusted. Guidance for
this type of ampacity adjustment factor should be obtained from the cable manufacturer or the AHJ. For an
example involving ampacity adjustment based on ambient temperature, see B.2.

4.5.7.4 Voltage drop verifications

Losses by means of voltage drop across a conductor are directly proportional to the length and impedance of
the conductor. Per Ohm’s law, the higher the current a conductor is carrying, or the higher the resistance of a
conductor, the greater the voltage drop. Voltage drop can create under-voltage issues for substation equipment,
leading to various malfunctions, depending on the type of equipment.

Voltage drop calculation for a single-phase circuit:

2× I × L ×[ R × pf + X ×sin(arccos( pf ))]
%VD = ×100 (4)
V

Voltage drop calculation for a 3-Ø load:

I × L × 3 ×[ R × pf + X ×sin(arccos( pf ))]
%VD = ×100 (5)
V
where

VD is the line-to-neutral voltage drop of the conductor expressed in volts, for a 1Ø conductor
or the line-to-line voltage drop of the conductor expressed in volts for a 3Ø conductor
V is the nominal voltage of the circuit
R is the alternating-current resistance in ohms to neutral per unit measurement
X is the alternating-current reactance in ohms to neutral per unit measurement
I is the load in amperes at 100%
L is the length of the conductor in unit measurement being considered for the voltage drop
pf is the equivalent power factor being considered for the circuit. If this factor has been accounted for
in the load study, then a value of 1.0 should be used in the voltage drop calculation

After a conductor size is selected with an acceptable level of voltage drop, verify the terminal voltage delivered
compared to the operating voltage range of the load. It is important that adequate voltage is delivered to
critical loads (i.e., trip coils, battery chargers, etc.). It is common for the AHJ to provide standards that provide
acceptable levels of voltage drop. For an example involving voltage drop calculations, see B.2.

4.5.7.5 Short-circuit calculations

Verify the conductor size can withstand the available short-circuit current at its termination point. Sizing
of the conductor based on available fault current is a function of initial or continuous conductor operating
temperature, the final conductor temperature after a fault, the maximum possible fault-clearing time based
on protective devices, and available fault current at the circuit’s termination point. The conductor final
temperature limits should be obtained from the cable manufacturer. Suggested methods and values for sizing
a conductor based on short-circuit current can be found in IEEE Std 525 and IEEE Std 242™ [B4]. However,

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any rules and/or standards provided by the AHJ should be considered before any other methods of calculation
are applied. For an example involving sizing a conductor based on short-circuit calculations, see Annex B.

4.6 Station power transformer

4.6.1 Introduction

The objective of 4.6 is to provide items for consideration to help the substation designer select the appropriate
station service transformer for the substation. Subclause 4.6 discusses the required number of transformers,
transformer power rating (kVA), transformer connections, transformer short-circuit rating, and some other
items to consider.

4.6.2 Transformer types

The following transformer types are used in the substation:

a) Pole- or structure-mounted transformer: The primary is connected overhead to the bus and the
secondary can be brought to the main panel via conduit or trench. This transformer type is simplest
when the load is single phase and less than 100 kVA and the required secondary voltage is 120/240 V
or 240/480 V. However, three-phase installations are common as well.
b) Pad-mounted transformer: To limit the voltage drop and reduce the length of the secondary conductors,
the transformers are typically located near the control enclosure. The location should not interfere
with vehicle movement within the substation yard, and should be located near the cable entrance
for easy access to the control enclosure load center. The primary cables are connected to the bus/
transformer tertiary and brought underground to the transformer. The secondary cables are connected
to the ac system as required. This transformer type is typically used when medium voltage is available,
the connected load is predominantly three-phase, and the total load is greater than 100 kVA.
c) Station service voltage transformer (SSVT): This transformer type combines the characteristics of a
voltage transformer with convenient power capability. Used in the substation application if no low-
or medium-voltage bus is available, or no nearby distribution feeder exists, or the cost of installing
the feeder is high. One to three transformers can be installed depending the required kVA rating. The
primary is normally connected from phase to ground. Typical secondary ratings available 120/240 V,
277/480 V, 240/480 V, and 600 V (ac).

4.6.3 Number of transformers required

The number of station power transformers required for a substation can be determined based on the design
criterion discussed in 4.2.5. One transformer may be acceptable for a low-load substation. For substations
with high load or high reliability requirements, two or more station power transformers may be required. An
important factor that can affect the number of station power transformers is the available sources for station
power.

Many utilities and power producers have developed standards and guidelines that help determine the number
of station power transformers that are required for a particular substation. These guidelines are based on the
utility system conditions and reliability requirements.

4.6.4 Single-phase or three-phase transformer requirements

The amount of station load determines whether single-phase or three-phase transformers are required. In
general, single-phase transformers have been used for distribution substations when the load is single-phase
and it has a low current rating. Three-phase transformers have been used for high-voltage and extra-high-
voltage substations when the load is high and some station load requires three-phase voltage input. Using a
single-phase transformer to serve large station load may result in a high level of secondary current. This could

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result in equipment with higher current rating as well as larger conductors due to excessive voltage drop. Other
loads, such as maintenance and construction equipment, may dictate if three-phase transformers are required
for station power.

4.6.5 Station service transformer rating

4.6.5.1 Introduction

Station service transformer ratings are specified by the kVA rating, transformer primary and secondary
voltages, the short-circuit rating, and the basic impulse insulation level (BIL) rating.

4.6.5.2 Transformer kVA rating

The capacity of a transformer is determined by the amount of current it can carry continuously at rated voltage
without exceeding the design temperature. Transformer ratings are given in kilovolt-amperes (kVA) since the
capacity is limited by the load current.

Calculations of transformer KVA rating

The kVA rating of the transformer should be selected to account for the expected load which the transformer
is required to serve including anticipated future load. See 4.4 for detailed information regarding load
classification and calculations. For a more general approach, the following methods can be used to determine
the transformer kVA rating. The 20% design margin used in this guide is conceptual. The designer may use a
design margin as appropriate for the application and per the owner’s operating practice.

Small substation with light load requirements

For small substation with light load requirements, the kVA rating of the single-phase transformer is determined
by calculating the ultimate connected load and adding a margin of 20%:

transformer kVA rating = 1.2× (ultimate connected load ) (6)

Medium to large substations

For large substations with high load requirements, the loads may be differentiated as follows:

a) Continuous loads: Loads that continue to operate for three hours or more are considered as continuous
loads. In substations the following loads can be considered continuous:
1) Control building HVAC and lighting
2) Transformer fans and/or pumps
3) Battery chargers
4) Equipment heaters
5) Yard lighting
6) Illuminated signs and miscellaneous inverters and receptacle loads
b) Non-continuous loads: Loads that are momentary are considered non-continuous loads. In substations
the following loads can be considered non-continuous. For larger substations, the designer may want
to consider not adding design margin to the non-continuous load.
1) Breaker’s ac motor spring chargers running current: Since this load type is momentary and the
possibility of more than one breaker charging motor starting at the same time is remote, it is

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suggested that the load of only two motors loads are added to the transformer kVA rating
calculations.
c) Maintenance and construction loads: Depending on duration of these loads, loads could fall under
either continuous or non-continuous.
1) Maintenance loads including transformer and breaker processing equipment.
2) Construction loads including construction trailers and equipment.

Once the recommended transformer kVA rating is calculated, Table 2 can be used to select the appropriate
transformer size for the application. Normally, the next transformer rating greater than the calculated value is
selected. Sizes other than listed in Table 2 may be available from manufacturers. A list of preferred continuous
kVA ratings can be found in IEEE Std C57.12.00™ [B21].

Table 2—Typical kVA ratings for distribution transformers

Overhead type Pad-mounted type
Single-phase Three-phase Single-phase Three-phase
10 30 15 45
15 45 25 75
25 75 37.5 112.5
37.5 112.5 50 150
50 150 75 225
75 225 100 300
100 300 167 500
167 500 250 750
250 750 333 1000

4.6.5.3 Transformer voltage rating

The primary and secondary voltage of the transformer should be specified. The following factors affect both
the primary and secondary voltage:

a) Available source
b) Transformer type: single-phase or three-phase
c) Transformer connection
d) Load voltage requirements
e) Transformer impedance

For a single-phase transformer, the primary voltage can be specified phase-to-phase or phase-to-ground. For
a three-phase transformer with a delta-connected primary or for a three-wire system, a phase-phase voltage is
specified. For a four-wire source, or for a transformer with wye-connected winding(s), both phase-phase and
phase-ground voltage are specified.

The following are typical substation secondary voltages (the list is not all inclusive):

a) For single-phase systems:

1) 240/120 V, single-phase, three-wire

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This is basically a “residential” service, but applicable to small- to medium-sized substations.

Panelboards that combine both power and lighting requirements can be used with this system,
thus reducing the required number of panelboards.
b) For three-phase systems:
1) 480/240 V, three-phase, four-wire, mid-tap, delta
When using this voltage configuration, larger equipment loads such as three-phase transformer
fans and oil pumps need to be specified at 480 V. Other system loads can be specified at either 480
V or 240 V, single-phase. This type of system is ungrounded and may require a ground-detection
system. If one phase of the system becomes grounded, an alarm is initiated to indicate a ground.
If a second phase becomes grounded, then a phase-to-phase fault condition exists and a trip is
initiated. This system has a high leg and requires that panelboards are labeled to identify that such
a condition exists. This system is very uncommon.
2) 480/277 V, grounded wye connected, three-phase, four-wire
When using this voltage configuration, larger equipment loads such as three-phase transformer
fans and oil pumps need to be specified at 480 V. One advantage of this system is that luminaires
can be equipped with 277 V ballasts allowing for a reduction in voltage drop for larger runs over
the use of the more common 120 V lights.
3) 208/120 V, grounded wye-connected, three-phase, four-wire
In this system, either 208 V single-phase and three-phase or 120 V single-phase equipment can
be used. Panelboards that combine both power and lighting requirements can be used, thus
reducing the required number of panelboards. The savings realized by using fewer panelboards
may be offset by the higher cost that is introduced by voltage drop issues in comparison to a 480
V system, as the typical solution to reducing voltage drop is to increase conductor size. In this
system, an additional transformer is not needed to provide 120 V feeds to the receptacles.
4) 240 V, three-phase, three-wire, delta
When using this voltage configuration, three-phase or single-phase transformer fans and oil
pumps are specified at 240 V. This type of system is ungrounded and requires a ground-detection
system. If one phase of the system becomes grounded, an alarm is initiated to indicate a ground.
If a second phase becomes grounded, then a phase-to-phase fault condition exists and a trip is
initiated.
5) 240/120 V, three-phase, four-wire, mid-tap, closed delta
This voltage configuration is the most common for small to mid-sized substations. With this
system, one phase of the auxiliary transformer is center tapped to obtain 120 V. Panelboards that
combine both power and lighting requirements can be used, thus reducing the required number of
panelboards. This system has a high leg and requires that panelboards are labeled to identify that
such a condition exists.
6) 240/120 V, three-phase, four-wire, mid-tap, open delta
This is essentially the same as the closed delta system with the exception that with only two
transformers the kVA rating is only 58% of the kVA capacity of when three transformers are used.
This system is more economical for a medium-sized installation or when used for a temporary
installation. This system uses single-phase transformers and the third transformer can be added in
the future to increase the overall kVA capacity. This type of system is commonly used when there
is a small three-phase load and a large single-phase 120/240 V load. This system has a high leg
and requires that panelboards are labeled to identify that such a condition exists.

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4.6.5.4 Transformer short-circuit rating

The short-circuit ratings for distribution transformers are set by IEEE Std C57.12.00 [B21]. The maximum
magnitude required for units with secondary voltages rated less than 600 V is given in the table below:

Table 3—Distribution transformer short-circuit withstand capability

Single-phase KVA Three-phase KVA Rating (times normal)
5 to 25 15 to 75 40
37.5 to 100 112.5 to 300 35
167 to 500 500 25
750 to 2500 1/ZT

Two winding distribution transformers with secondary voltages rated above 600 V are required to withstand
short-circuits limited only by the transformer’s impedance.

The duration of the short-circuit current is determined by the following formulas:

For transformer rated 500 kVA or below (Category I):

1250
t= (7)
I2

t=I (8)

where

t is the duration in seconds

I is the symmetrical short-circuit current in multiples of normal base current (per unit)

For transformer rated 501 kVA to 5000 kVA (Category II):

t = 2s (9)

t=I (10)

where

t is the duration in seconds

I is the symmetrical short-circuit current in multiples of normal base current (per unit)

Transformers are required to withstand faults corresponding to the above criteria.

Determination of short-circuit capacity:

The infinite bus short-circuit capability of a transformer can be calculated as:

IS
I SC = (11)
Zt

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where

I S is the rated secondary current at base kVA

Z t is the transformer impedance in percent

For example, a 50 kVA single-phase transformer with a 120/240 V (ac) secondary and a 3.5% impedance will
have a short-circuit capability of:

50 000
0.035 = 5952.4 A (12)
240

Equipment connected to this transformer shall have the ability to withstand this current for the duration
indicated above, and be capable of interrupting that current if the equipment is a protective device such as a
circuit breaker or fuse.

4.6.5.5 Transformer impedance

The station service transformer impedance should be considered when evaluating the ac system equipment
rating. The ac equipment should withstand the maximum fault current and the circuit breakers should be
capable of interrupting the fault. The transformer impedance has a direct effect on system fault current. The
impedance determines the maximum short-circuit current.

The percentage impedance can be specified as low as 2% for small distribution transformers, and as high as
20% for large power transformers. Impedance values outside this range are generally specified for special
applications.

4.6.5.6 Transformer BIL rating

The BIL rating of overhead distribution transformers 500 kVA and smaller is its ability to withstand overvoltage
conditions resulting due to fault conditions, lightning surges, or any over-voltage due to switching surges.
Table 4 meets IEEE Std C57.12.20™ [B23] and can be used to specify the BIL rating of the transformer.

Table 4—Transformer BIL ratings (IEEE Std C57.12.20 [B23])

Voltage range volts Insulation class kV BIL
480 to 600 1.2 30
2160 to 2400 5.0 60
4160 to 4800 8.7 75
7200 to 12 470 15 95
13 200 to 14 400 18 125
19 920 to 22 900 25 150
34 400 34.5 200

4.6.6 Transformer connections

4.6.6.1 Introduction

Single-phase or three-phase transformers may be installed for station power applications.

4.6.6.2 Single-phase transformer application

Single-phase distribution transformers are manufactured with one or two primary bushings. The single-
primary-bushing transformers can be used only on grounded wye systems. For this connection, the H1 bushing

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is connected to an available phase. If a two-bushing transformer is used, the H1 is connected the same, and the
H2 bushing is connected to ground as shown in Figure 4.

Figure 4—Single-phase-to-ground connection

When a primary delta system is available, a phase-to-phase voltage is applied between the two bushings H1
and H2 as shown in Figure 5.

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Figure 5—Single-phase transformer with phase-to-phase connections

The secondary voltage can also be 480/240 V if required.

4.6.6.3 Three-phase transformer connections

Three-phase transformer connection can be achieved by using two or three single-phase transformers and
connected as required. When a three-phase transformer is required, a pad-mounted three-phase transformer
is normally used for the station power applications. A pad-mounted three-phase transformer is applicable to
below-grade connection from both the primary and the secondary’s sides. The following are some examples of
transformer connections that have been used for substation station service applications:

Delta-delta connection

The delta-delta connection shown in Figure 6 is suitable for both ungrounded and effectively grounded
sources. Phase-to-phase voltage is applied to H1, H2, and H3 terminals of the transformer. For substation
applications when the required voltage is 240 or 480, a three-wire connection is used. When the required
voltage is 240/120 V or 480/240 V, a four-wire service can be used. The delta-delta four-wire service is
accomplished by grounding the midtap of one of the transformer windings. However, if single-phase load is to
be connected, the three-phase capability of the transformer is derated.

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Figure 6—Delta-delta connection

The advantages of the delta-delta connection are as follows:

a) System voltages are more stable in relation to unbalanced load.

b) When three single-phase transformers are used to form the phase bank, if one transformer fails, the
remaining two transformers can be used at 58% of the total kVA rating. Single-phase loads are lost if
the B phase tap is lost.
c) The delta connection provides a closed path for circulation of the third harmonic component of current.
The flux remains sinusoidal which results in sinusoidal voltages.

The disadvantages of the delta-delta connection include the absence of a neutral terminal on either side.
Another drawback is that the electrical insulation is stressed to the line voltage. Therefore, a delta connection
requires increased insulation to accommodate the higher voltage across the line-line compared to the wye-
connection with line-neutral voltage for the same power. The delta connection is susceptible to ferroresonance.

Delta-wye connection

The delta-wye connection shown in Figure 7 is suitable for both ungrounded and effectively grounded sources.
The transformer primary is connected delta, and therefore phase-to-phase voltages are connected to H1, H2,
and H3 transformer terminals. The secondary is suitable for three-wire service or, if neutral is grounded,
four-wire grounded service. In substation applications four-wire service is normally used. Typical substation
secondary voltages for this transformer connection are 480/277 V or 208/120 V.

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When the neutral is grounded the transformer acts as ground source for the secondary system. Fundamental
and harmonic frequency zero-sequence currents in the secondary lines supplied by the transformer do not
flow in the primary lines. Instead, these zero-sequence currents circulate in the closed delta primary windings.
When supplied from an effectively grounded primary system, a ground relay for primary system does not see
load unbalances and ground faults in the secondary system.

Figure 7—Delta-wye connection

When used in 25 kV and 34.5 kV three-phase four-wire primary systems, ferroresonance can occur when
energizing or de-energizing the bank using single-pole switches located at the primary terminals. With smaller
kVA transformers in the bank, the probability of ferroresonance is higher.

Wye-wye connection

The wye-wye connection shown in Figure 8 is best applied at the four-wire primary and secondary where both
the primary and secondary neutrals are grounded. The high-voltage terminals H1, H2, and H3 are connected to
the three-phases, and the H0 neutral is connected to ground. In a grounded wye-wye 240/120 V or 480/240 V
cannot be supplied, only 208/120 V or 480/277 V can be supplied by this connection.

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Figure 8—Grounded wye–grounded wye transformer connection

The following operating conditions should be considered when this transformer connection is selected:

a) Excessive tank heating can result depending on the transformer construction. For three-legged core
construction, excessive tank heating is probable. For five-legged transformers, tank heating is possible
if the load unbalance is high. Tank heating can be limited if the transformer bank is made from three
single-phase transformers.
b) Zero-sequence currents and harmonics transfer to the primary. The secondary can act as high
impedance ground source.
c) A ferroresonance condition is unlikely if the transformer bank is made from three single-phase
transformers, but is possible for a four- or five-legged constructed transformer.
d) Coordination between the source ground protective device and the secondary ground protective
device is required because the secondary current can pass to the primary.

Two leg open delta–open delta connection from grounded-wye primary

The open delta–open delta connection as shown in Figure 9 shows connection to a grounded wye-connected
source such as a distribution bus. Phase-to-ground voltage is applied across the two transformer primary
windings. This connection provides a 240/120 V secondary. The A-C and A-B voltages are 240 V where A-n
and C-n are 120 V. The B phase in this connection is the high leg 208 V B-n.

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Figure 9—Two leg open delta from grounded wye

Two leg open delta–open delta connection from a delta primary

The open delta–open delta connection as shown in Figure 10 shows connection to a delta-connected
source such as a three-phase transformer tertiary winding. Phase-to-phase voltage is applied across the two
transformer primary windings. This connection provides a 240/120 V secondary. The A-C and A-B voltages
are 240 V where A-n and C-n are 120 V. The B phase in this connection is a high leg.

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Figure 10—Two leg open delta from delta

One benefit for the above two applications is when there is a large amount of single-phase loads 240/120 V
and a small amount of three-phase 240 V load. This can economically provide that with a larger single-phase
transformer connected to C-phase primary (with secondary grounded neutral tap) and a smaller transformer
connected to A-phase. Typical substation ac station auxiliary loads tend to be single-phase with a small amount
of three-phase loads (typically cooling pumps or larger three-phase battery chargers).

Another benefit is that the open delta connection avoids the ferroresonance issues of the closed delta
transformer connections.

The connection is good for substations with a lot of single-phase load and a small amount of three-phase loads.
This is inefficient for applications with substantial amounts of three-phase loads as you only get 58% of the
capacity with only two transformers instead of three equally sized transformers.

4.7 Transfer switch

4.7.1 General

The need for an auxiliary power system transfer switch is related to the criticality of the substation. If only one
station service power source is available, a transfer switch is not required. If there are no critical ac system
requirements, the dc battery system may be sufficient to operate the critical dc systems until the ac station
service power is restored.

Most substations are provided with two sources of station service ac power. The two sources of station service
power are generally designated as the normal source and the alternate (or backup or secondary) source.

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To simplify the operation of the transfer between sources, a “break before make” operation is suggested.
“Break before make” operations keep sources from operating in parallel. In the case of manual operation of
the transfer switch, it may be desirable to disable or lock out one source while the other source is being used.
In either case, sufficient training should be provided so operators do not parallel sources. Most substation ac
loads do not require continuous service to function as designed. The station service should be reviewed for
sensitive loads that may require continuous ac service to function.

Since the auxiliary power sources can be supplied at different voltages than the utilization voltage in the
substation, the transfer switch or scheme can be applied at either the primary or secondary voltage. The higher
voltage application results in lower current rated equipment. 13.8 kV, 12.47 kV, 4.16 kV, 480 V, and 240/120 V
are common auxiliary power voltages and the transfer switch/scheme can be applied at any of these voltages.
The auxiliary power source can be either three-phase or single-phase, depending on the station service
requirements. Transfer switches typically can be purchased with two, three, or four poles. A four pole switch
has the ability to switch the neutral and is necessary on a system that has separately derived neutrals. Using
a transfer scheme at medium-voltage levels requires auxiliary voltage transformers and either programming
protective relays or incorporating a programmable controller for transfer and return to normal functions.

Smaller rated transfer switches can be wall mounted. Floor-mounted switches are common. Transfer switches
can be purchased for indoor or outdoor mounting.

The transfer switch may be as simple as two input sources with switching devices and one output to the load.
The transfer system may be as elaborate as a unit switchgear consisting of two input switching devices, two
transformers, two main circuit breakers, one tie circuit breaker, and multiple branch circuit breakers.

Another consideration when designing the transfer system is the reliability of the transfer switch. It may
be prudent to make provisions to bypass the switch in the event of the switch’s failure, maintenance, or
replacement. This may be accomplished by having a third source routed to the substation ac load center that
is left normally open and locked out until it is needed. It may be more cost effective to route another set of
conductors from either or both the normal and alternate source to the substation ac load center. Similar to the
transfer operation, training and procedures should be provided to the operator so that the operator is less likely
to parallel sources during a bypass operation.

When installing an auto-transfer switch to an ac system, an important consideration is to include switching of

the neutral conductor in addition to the phase conductors. This is especially important on applications with one
source provided from a separately derived ac system outside the substation with a different ground connection.
This is important for both automatic and manual transfer switches. The switching of the neutral conductor
provides isolation of a normal source from an alternate source which is important with separately derived
sources.

Another important consideration when installing a transfer switch is to specify a switch with break before
make operation. This allows for a transfer of normal and alternate sources that may be out of phase or
connected to different phases on single-phase systems. For example, a normal three-phase source connected to
a distribution bus may be 30 degrees out of phase with an alternate source connected to the tertiary windings of
a power transformer. A break before make operation allows a transfer between these two sources that are out of
phase. It is important to maintain proper phase rotation between different power sources.

4.7.2 Manual transfer switch

For less critical substations, a manual transfer switch provides the capability of transferring from the primary
to the alternate source. The manual transfer switch is a much simpler and lower cost switch than an automatic
transfer switch. However, the use of the manual transfer switch requires station alarms to alert operations
personnel of the loss of the normal ac source and dispatching personnel to the substation to operate the manual
transfer switch.

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Due to the loss of the normal ac source, many station devices will lose power. The battery charger cannot
supply the charging source for the dc battery system. In this situation, the dc battery system is the source for
station critical systems, such as system protection functions and control and breaker tripping, until operation
personnel responds and manually operates the ac transfer switch. Other systems, such as control enclosure
cooling/heating, may also be unavailable until operations responds. The designer should consider the effects of
temperature on control enclosure components and response time when considering a manual transfer switch.

If the substation has only one source of ac power, a manual transfer switch may still be desirable as a connection
point for a temporary ac alternate source, such as a portable generator.

The manual transfer switch can consist of two manually operated switching devices (usually such as circuit
breakers) capable of interrupting the load current of the transfer switch or a manually operated switch similar
to a disconnect switch that has on–off–on capability to select between the two sources. The two switching
devices are typically mechanically interlocked so both ac sources are not connected in parallel. Fault current
interruption capability is not required in the transfer switch, but a withstand rating should be specified.
Indication of source status (hot or dead) is not typically provided. Some type of alarm is necessary to detect the
loss of the primary (and perhaps secondary) ac source.

4.7.3 Automatic transfer switch

Critical substations, or substations with critical ac loads, may require an automatic transfer switch between the
normal and alternate sources. The transfer should occur only after a time delay to avoid inadvertent transfer
and only when the alternate source is available.

Automatic return to the normal source should occur only after the normal source has been restored for a
specified time to confirm it is not an unstable source.

The low-voltage (< 1 kV) automatic transfer switch consists of essentially a form C power relay capable
of interrupting the load current of the transfer switch. Higher voltage transfer switches can be composed
of two electrically operated switching devices (usually circuit breakers). The two switching devices can be
electrically and/or mechanically interlocked to keep the ac sources from being connected in parallel. Fault
current interruption capability is not required in the transfer switch, but a withstand rating should be specified.
Detection and indication of source status (hot or dead) is required. Time delays and control sequencing is
necessary to reduce the chance of transferring to a de-energized or unstable source. Indicating lights and relays
are usually provided. Alarm indication of transfer should be provided. Close and latch capability should also
be considered in equipment rating.

4.7.4 Alternate methods

Transfer switches can be cascaded to allow multiple sources to provide power to the station service system.
Depending on the criticality of the substation, two ac sources (bus derived and distribution derived) can be
normal primary and alternate, and that resultant connection can be further supported from an onsite generator
to support essential ac loads such as battery chargers, control enclosure HVAC, and communication systems
as required.

Another alternate would be for both sources to be designated as normal sources. The ac load can be divided
between the two sources with the transfer switch system consisting of the two normally closed circuit breakers
and a normally open transfer circuit breaker.

4.7.5 Alternate sources

In some instances, depending on the criticality of the station, the transfer switch alternate source may be a local
backup generator. The transfer switch controller typically provides both the ac transfer function and the ability
to exercise the generator following a pre-determined maintenance schedule. A number of alarms are available

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(engine temperature, fail to start, engine running, oil pressure, etc.) and provisions need to be made to transmit
these to the operations center.

4.8 Bus layout and distribution circuits configuration

4.8.1 Introduction

The designer responsible for designing the bus layout and distribution circuit configuration of an auxiliary ac
system should take the following parameters into consideration, at a minimum:

a) Essential versus non-essential load

b) Load ampacity and overcurrent protection requirements (see 4.4 and 4.5)
c) Voltage drop (see 4.5)
d) Construction and maintainability
e) Cost

4.8.2 Essential load

These loads are related to equipment operation and are necessary to the proper function of the substation.

a) Power transformer loads (cooling systems, fans, oil pumps, load tap changers, etc.)
b) DC battery chargers
c) Power circuit breaker loads (control, compressors, charging motors, etc.)
d) Power equipment heating circuits
e) Protective relaying, supervisory, alarm, communications, and control equipment
f) AC/DC converters for uninterruptable power supplies
g) Control enclosure HVAC systems
h) Fire alarm and fire suppression circuits
i) Security lighting

4.8.3 Non-essential load

These loads are not essential for functioning and reliability of the substation.

a) Outdoor lighting not essential for station security

b) Outdoor receptacles
c) Indoor lighting and receptacles
d) Maintenance loads (SF6 gas carts, oil refining, receptacles, etc.)
e) Construction loads (construction trailer, welding, drills, etc.)

4.8.4 Simple radial system

In this system, a single normal service and station power transformer supply all auxiliary ac load. There is no
duplication of equipment. System cost is the lowest of all the circuit arrangements.

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The simplest version of this system is shown in Figure 11. It has panelboards supplied directly from station
power transformer. Secondary breakers may not be required on the transformer as shown in Figure 11, Figure
12, and Figure 13. One of the panelboards (“A”) is used to connect a feed to another panelboard (“B”).

Figure 11—Simplest panelboards

A variation of this system is shown in Figure 12 where a power block is used to split a power supply coming
from transformer breaker into cables feeding both panelboards “A” and “B.”

Figure 12—Variation of simplest panelboard

Another version of a simple radial system is shown in Figure 13, where a main panelboard is connected directly
to a station power transformer. Breakers are used to supply sub-panelboards.

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Figure 13—Sub-panelboard

The main deficiency of the systems shown in Figure 11, Figure 12, and Figure 13 is that the panelboards do
not have independent feeds from the main system and are connected to a station power transformer breaker
through a single common cable susceptible to failure. In the case of the cable fault or a failure of one of the
panelboards ahead of the internal main breaker, the whole auxiliary ac power system becomes de-energized.

To make a simple radial system more reliable and flexible, the auxiliary bus with feeder breakers (switchboard
or switchgear), shown in Figure 14 may be used. In this system, the auxiliary bus is connected directly to the
transformer breaker through a bus, or cable run, and panelboards are connected to the bus via feeder breakers
and separate individual cables. A failure of any panelboard or a cable feeding it should result in a tripping of
the corresponding feeder breaker, leaving the rest of the ac system intact.

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Figure 14—Reliable and flexible panelboard system

Further improvement of redundancy of a simple radial system may be achieved through installation of a
backup generator, which starts upon loss of the station power transformer’s feed to the auxiliary bus, tripping
the transformer breaker and closing the generator breaker as shown in Figure 15.

Figure 15—Panelboards with backup generator

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The main advantages of a simple radial system are low cost and operational simplicity. However, it has
less reliability compared to more robust systems. A loss of the normal supply, main cable, or station power
transformer results in the interruption of auxiliary ac service for the entire substation. Another drawback of
a simple radial system is the necessity to de-energize it to perform routine maintenance of its main elements
(transformer, transformer breaker, auxiliary bus, etc.).

4.8.5 Expanded radial systems

If a simple radial ac system is applied to a larger substation, its expanded version with two station power
transformers may be used. See Figure 16.

The advantages and disadvantages of expanded radial systems are the same as those described for the simple
ones. However, by having two transformers, a better redundancy of power supply is achieved. The panelboards
can be fed through automatic or manual transfer switches, which can also provide added flexibility in the
continuity of power supply to the load if one of the transformers or buses is out of service.

Figure 16—Expanded radial system

4.8.6 Primary selective system

Protection against loss of a primary power supply can be gained through the use of a primary selective system
shown in Figure 17. Each station power transformer is connected to two separate primary feeders through
switching equipment to provide normal and alternate sources of power supply. Upon failure of the normal
source, the transformer is switched to the alternate source. Switching can be either manual or automatic.

Each panelboard can be fed through an automatic or manual transfer switch, which provides the continuity of
power supply to the load if one of the transformers or buses is out of service.

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Figure 17—Primary selective system

4.8.7 Secondary selective systems

If a pair of station power transformers is connected through a secondary tie circuit breaker or automatic
transfer switch, the end result is a secondary selective system shown in Figure 18. If any of the primary feeders
or transformers fails, power supply from the remaining source is maintained through the corresponding
transformer’s secondary breaker and a tie breaker. Tie breaker may be normally open. If this is the case, after
failure of one of the sources and opening of affected transformer’s secondary breaker, a tie breaker should be
closed either manually or automatically to provide a power supply for the bus section normally connected to
the failed source. When a power supply from this source is restored, a manual opening of the tie breaker and
closing of the returning to service transformer’s breaker are recommended.

Each panelboard can be fed through an automatic or manual transfer switch, which provides the continuity of
power supply to the load if one of the transformers or buses is out of service.

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NOTE—EO is electrically operated, NO is normally open, and NC is normally closed.

Figure 18—Secondary selective system

4.8.8 Secondary selective system with backup generator

If the level of redundancy provided by a secondary selective system shown in Figure 18 is not sufficient, a
backup generator with a circuit breaker may be added to it as shown in Figure 19. Normally, the generator’s
breaker is open, and for a loss of a single primary feeder or transformer, this scheme works exactly like the
one shown in Figure 18. But upon the loss of both transformer feeds (both transformer secondary breakers are
open) the backup generator starts automatically and its breaker closes, restoring power to both buses. Manual
closing of the transformer breaker is recommended upon restoration of any primary feed after stopping the
backup generator.

Each panelboard can be fed through an automatic or manual transfer switch, which can allow the continuity of
power to the load if one of the transformers or buses is out of service.

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Figure 19—Secondary selective system with backup generator

If even more redundancy is needed, Figure 19 may be developed into a system with two tie breakers and
possibly three transformers and a backup generator as shown in Figure 20. For applications with process-
critical equipment, additional provisions may be required for smooth transition during restoration of power.
The operational logic for this scheme is consistent with the one described for the schemes shown in Figure 17
and Figure 18.

Figure 20—Secondary selective system with backup generator and additional redundancy

The size of cable feeding any load or panelboard is required to be selected in accordance with requirements of
the AHJ or any applicable code, and to be protected by an upstream breaker or protective device.

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4.9 AC distribution panelboards for electrical substations

4.9.1 Introduction

AC distribution panelboards are utilized for termination of service and feeder cable circuits and for origination
of feeder and branch cable circuits for distribution of auxiliary ac electrical power to loads in electrical
substations.

An ac distribution panelboard is an assembly of bus bars, switching overcurrent protection devices, and
connections housed in an enclosure with purpose to control and distribute auxiliary ac power to substations
loads. AC distribution panelboards have a main bus bar for each phase, main lug only (MLO), or a main
device such as a switch, fuses or molded-case circuit breaker (MCCB), and neutral and/or ground buses, if
appropriate. Depending on voltage rating, ac distribution panelboards can be specified with a switch and/or
overcurrent devices, such as plug or cartridge fuses or MCCBs, to serve as branch circuit devices. Most ac
distribution panelboards utilized in modern industrial applications, such as electrical power substations, use
MCCBs for main, feeder, and branch circuit overcurrent devices.

4.9.2 AC distribution panelboard application

Bus bars in ac distribution panelboards are current density rated and meet temperature rise limitations
established in UL 67 [B38] (UL Standards are typical in the United States—other jurisdictions may have
similar standards boards). Standard bus bar current densities are 750 amperes per square inch for aluminum
bus bars and 1000 amperes per square inch for copper bus bars. Some ac distribution panelboard manufacturers
offer reduced current densities of 600 amperes per square inch for aluminum bus bars and 800 amperes per
square inch for copper bus bars.

AC distribution panelboards used in electrical substation applications should be designed with consideration
for the size of the conductors being terminated within the panelboard. The specified panelboards should
accommodate the bending radius of conductors routed within them and should have adequate gutter spacing.
The terminals of molded-case circuit breakers and other protective devices should be suitable for the wire
size of the circuits on which the protective devices are applied. To be conservative, the designer designing the
panelboard should account for the possibility of increases in wire sizing. The designer should also consider
the space necessary for the electricians to perform terminations in the available space within the panelboard.

For any application of ac panelboards, all panelboard manufacturers’ catalog and technical data should be
considered carefully.

4.9.3 AC distribution panelboard ratings

Panelboards can be single-phase or three-phase as required for the application.

Typical voltage ratings for ac panelboards for different ac systems are given in Table 5.

Table 5—Typical voltage ratings for ac panelboards

Voltage ratings of ac panelboards
Number of phases Number of wires AC voltage ratings—volts
1 2 120, 240, 277
1 3 120/240
3a 3 208Y/120, 480Y/277
Table continues

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Table 5—Typical voltage ratings for ac panelboards (continued)

Voltage ratings of ac panelboards
3 3 120, 240, 480, 600
3 Four-wire with neutral 208Y/120, 400Y/230, 480Y/277, 600Y/347
3 Four-wire delta with 240/120
neutral connected at
midpoint of one phase

Derived from three-phase, four-wire system

Although more ratings are available, typical nominal continuous rms current ratings of ac distribution
panelboard main buses, main terminal lugs, main fuse and holder, and MCCB utilized in applications in
electrical substations range between 100 A and 800 A. The maximum main current rating in ac panelboards is
usually less than 1600 A. The current rating of an ac distribution panelboard should not be less than the feeder
and branch circuit capacity required for the load.

Typical nominal continuous rms current ratings of feeder and branch circuits range between 20 A and 400 A.
The maximum feeder and branch circuit current rating in ac distribution panelboards is usually 1200 A.

Unless marked to indicate otherwise, the provisions for cable terminations provided in ac distribution
panelboards are based on the use of 60 °C temperature rise for wire sizes 14 AWG to 1 AWG and 75 °C
temperature rise for wire sizes 1/0 AWG and larger.

Unless rated for 100 percent continuous load at its rated current, the total load on any overcurrent device
utilized in an ac distribution panelboard should not exceed 80 percent of its nominal current rating.

4.9.4 AC distribution panelboard short-circuit rating

The rms symmetrical and asymmetrical short-circuit current at an ac distribution panelboard location should
be determined in accordance with methods provided in IEEE Std 141™ [B3], unless otherwise directed by
the AHJ. The rated rms symmetrical and asymmetrical interrupting current of an ac distribution panelboard
should exceed the available short-circuit current at the location in the electrical system. Consideration should
be given to possible future increases in available short-circuit current. Most ac distribution panelboards are
selected to have a fully integrated short-circuit interrupting rating where the ac distribution panelboard and all
overcurrent devices enclosed in the ac distribution panelboard have a short-circuit current rating greater than
the available short-circuit current at the location in the electrical system, but series ratings may be utilized.
Selectivity between overcurrent devices should be considered, if possible.

4.9.5 AC distribution panelboard standards

AC distribution panelboards are typically designed and manufactured in accordance with NEMA PB1 [B31]
and UL 67 [B38] or similar standards, and are usually supplied in suitable cabinets or enclosures which are
manufactured in accordance with standards such as NEMA 250 [B29] or UL 50 [B37] and designed to be
mounted in or on a wall or other support structure and accessible only from the front. In general, ac distribution
panelboards should be specified and applied in accordance with national or local standards, including all
provisions for grounding. However, ultimate guidance for design, manufacturing, and installation/application
of ac distribution panelboards should come from the AHJ.

Usual service conditions for ac distribution panelboards are ambient temperature of −5° C to 40 °C for ac
distribution panelboards utilizing molded-case circuit breakers, and −30 °C to 40 °C for ac distribution
panelboards utilizing enclosed switches. Usual altitude is not greater than 2000 m (6600 ft). AC distribution
panelboards for outdoor application can have a greater rated ambient temperature range and should be
provided with enclosures with a suitable weatherproof rating. For suggested applications of enclosures based
on location, see NEMA 250 [B29].

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AC distribution panelboards tested and certified to meet requirements of International Building Code (IBC)
[B28] Zone 3 or Zone 4 or other similar standards should be considered in seismically active areas. Ultimately,
any guidance for panelboard design based on seismic conditions should originate from the AHJ.

An ac distribution panelboard utilized for service equipment to provide main control and means of cutoff of
the supply conductors near the point of entrance of supply conductors of a building, structure, or other area or
premises should meet all requirements for service equipment required in UL 67 [B38] and UL 869A [B41],
unless otherwise dictated by the AHJ.

Guidance for the specification of MCCBs is given in NEMA AB-1 [B30] and UL 489 [B40]. Guidance for
specifying fusible switches is given in UL 98 [B39].

4.10 AC auxiliary system protection

4.10.1 Introduction

Several studies may be performed for auxiliary system protection. These studies include a short-circuit current
study for selection of equipment and cable sizing, a coordination study to evaluate and select the equipment
rating and protective device rating of auxiliary systems, and an arc flash study.

4.10.2 Panelboard or switchboard protection

The upstream feeder protective device (fused safety switch, fuses, MCCBs, etc.) of the panelboard or
switchboard should be sized to protect the panelboard or switchboard and the feeder cable(s).

Panelboard and switchboard may have a main incoming protective device. For a panelboard or switchboard
with a main incoming protective device (breaker or fuses, breaker), the main incoming protective device
should be sized to protect the panel bus bars. There is no limit to the number of circuits (fuses, MCCBs) in the
panelboard or switchboard. At one time, this was a 42 circuit limit, and that limit may still be in force in certain
jurisdictions.

4.10.3 Panelboard or switchboard circuit

Panelboard and switchboard circuit protection (sizing) should be determined based on the terminal and load
ampacity. Typically this is based on 100% of the non-continuous and 125% of the continuous load current with
some design margin of the circuit load. Typical design margin is 10% to 20%.

4.10.4 Circuit breaker selection

In order to properly protect the equipment and coordinate the fault clearing, circuit breakers should be properly
selected. There are three important aspects to proper selection of circuit breakers. They are the rated maximum
voltage, rated continuous current, and the short-circuit current rating.

The voltage rating of the circuit breaker should be not less than the maximum operating voltage of the ac
system. Typical low-voltage ac circuit breaker voltage ratings are 120, 120/240, 208Y/120, 240, 277, 347,
480Y/277, 480, 600Y/347, and 600 volts.

The short-circuit current rating is the maximum short-circuit current that a circuit breaker can successfully
interrupt. The circuit breakers for an ac system should have a current interrupting rating equal to or higher than
the actual ac system maximum fault current. Typical low-voltage ac circuit breaker current interrupting ratings
are 7.5 kA, 10 kA, 14 kA, 18 kA, 20 kA, 22 kA, 25 kA, 35 kA, 42 kA, 50 kA, 65 kA, 85 kA, 100 kA, 125 kA,
150 kA, and 200 kA.

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The circuit breaker current rating should not be less than 125% of the calculated maximum load. 100% rated
breakers are available if required, or may provide benefit to accommodate preferences with frame size. It may
be appropriate to include a 10% design margin.

In some cases, thermal trip units or electronic trip units should be selected based on equipment protection
requirements or the arc flash energy limitation requirements. The trip unit setting should be clearly identified
in the circuit breaker order and design document.

For more information on the selection and application of molded-case breakers, see IEEE Std 1458™ [B17].

4.10.5 Selection of circuit fuses

Appropriate fuse selection is important for the protection and fault-clearing coordination of the ac auxiliary
power system. The important ratings to consider when properly selecting fuses for ac auxiliary power system
protection are voltage rating and current rating.

The ac voltage rating of the fuse should not be less than the operating voltage of the ac auxiliary power system.
Typical ac fuse voltage ratings are 125 V, 250 V, and 600 V; 300 V and 480 V ratings are also available.

The ac current rating of a fuse is the maximum ac continuous current that can flow through a fuse without
interrupting. When the rating is exceeded, the fuse blows, opening the circuit. The maximum ac continuous
current required to supply an ac load should be considered when selecting the ac fuse rating. Typical ac
continuous current fuse ratings range from 1 A to 600 A.

4.11 Equipment specifications

4.11.1 Introduction

Documents for specifying equipment include the necessary information for manufactures or suppliers to
prepare and submit a firm proposal to furnish the requested equipment. The equipment specification usually
comprises both commercial and technical requirements.

The commercial requirements are typically a set of terms and conditions that address how, when, and to whom
the proposals are to be returned. Other information included may be legal considerations, such as taxes or
liabilities. Commercial requirements are not discussed in further detail.

The technical requirements include the description of the necessary performance requirements for the
equipment. The information in the description should include, as needed, the operational criteria of the
equipment related to its design, construction, testing, and shipment.

Subjects that need to be addressed when specifying auxillary power equipment include voltage/current
levels, service conditions, code requirements/restrictions, delivery dates, delivery/transportation to site, and
temporary storage of equipment.

Designers should be aware that the standard equipment offered by suppliers may not meet the robust
requirements needed for some substations. For instance, the size and layout of the substation may warrant
larger cables be used between equipment. These larger cable sizes require larger cable bending space and
termination sizes, and hence bigger enclosure sizes.

Numerous standards have been written to specify requirements of equipment to be used in ac auxiliary power
systems. These standards cover transformers, surge arresters, transfer switches, panelboards, medium- and
low-voltage fuses, medium- and low-voltage circuit breakers, etc.

Some of these standards are:

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IEEE Std C57.12.00, IEEE Standard for General Requirements for Liquid-Immersed Distribution,
Power, and Regulating Transformers [B21]
IEEE Std C62.22, IEEE Guide for the Application of Metal-Oxide Arresters for Alternating-Current
Systems [B27]
NEMA PB 2, Deadfront Distribution Switchboards
UL 489 (NEMA AB 1), Molded-Case Circuit Breakers, Molded-Case Switches, and Circuit-Breaker
Enclosures [B30]
UL 891, Switchboards [B42]
UL 991, Tests for Safety-Related Controls Employing Solid-State Devices [B43]
UL 1008, Transfer Switch Equipment [B44]

4.11.2 NEMA standard for indoor/outdoor operation

NEMA (National Electrical Manufacturers Association) creates ratings for equipment based on expected
performance. NEMA does not require independent testing to verify that the manufacturer is compliant to the
standard. Compliance to the standard is up to the manufacturer.

NEMA 250 [B29] describes types of enclosures for electrical equipment up to 1000 V maximum. NEMA
publishes descriptions of their enclosure types for both non-hazardous and hazardous locations. They also
define which enclosure types may be used for indoor/outdoor use and which enclosure types may be used for
indoor use only.

The designer should choose the type of enclosure specific to environmental, atmospheric, and site conditions.
For example, a NEMA Type 1 enclosure provides a minimum degree of protection for indoor use in a non-
hazardous location, while a NEMA Type 3R enclosure provides a minimum degree of protection for outdoor
use in a non-hazardous location. The degree of protection offered by these types of enclosures may be sufficient
for a particular substation environment.

4.12 Operation and maintenance considerations

4.12.1 Operational and maintenance provisions

There are several features that should be considered to enhance the operation and maintenance of the ac station
service system.

a) Provide disconnect switches that can be visibly verified and used for electrical clearance points on the
high side of the station service transformer, and between the transformer and the service panel.
b) Provide transfer switches to allow transferring load to an alternate source when the normal source
(primary bank, bus, station service bank, or line) needs to be cleared. Transfer switches are typically
break before make and need a mechanical interlocking means to avoid paralleling the sources.
c) Indoor and outdoor panels need to have adequate working space. Recommended depth, width, and
head room clear distances are shown in Table 6 and accompanying notes.
d) Panels should be dead-front design, and outdoor panels should be lockable.
e) Clearly mark phases at the transformer bank and in the distribution panels to facilitate future trouble
shooting.

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Table 6—Working clearances for electrical panels

Minimum clearance for depth
Nominal voltage No live or grounded parts Grounded parts Unguarded live
to ground opposite (see Note 1) opposite (see Note 2) parts opposite
0 V to 150 V 900 mm (3 ft) 900 mm (3 ft) 900 mm (3 ft)
151 V to 600 V 900 mm (3 ft) 1070 mm (3.5 ft) 1200 mm (4 ft)
NOTE 1—Also applicable if exposed live parts on both sides are effectively guarded by wood or other insulating
materials. Insulated wire or insulated bus bars operating at 300 V or less are not considered live parts.
NOTE 2—Concrete, brick, and wall tiles are considered as grounded.
NOTE 3—The width of the working space in front of the equipment should be the width of the equipment or 30 inches,
whichever is greater. The headroom should be the greater of 1.98 meters (6.5 ft) or the height of the equipment.
NOTE 4—This information is based on NFPA 70, Article 110-26, and NESC [B1], Section 125.A.

4.12.2 Low-maintenance design

For optimal performance and to reduce maintenance, consider the following features for outdoor distribution
panels:

a) Utilize rain-tight construction: Minimum NEMA 3R or equivalent. Include a drip shield to reduce the
likelihood of water entering the panel.
b) Steel cabinets should have a minimum of 4 mils paint by wet process or powder-coat type. Epoxy or
two coat epoxy/polyester are common for good durability. Aluminum, or in highly corrosive areas
stainless steel, cabinets may also be used.
c) Do not use piano-type (continuous) hinges on doors. Use a multi-point latching system.
d) Cover all vents with small mesh screen to reduce insect or rodent infestation. Secure in place. Use
material such as brass that does not corrode over time.

4.12.3 Standby backup ac system

The purpose of the standby ac system would be to provide continued ac power to essential systems for a set
period of time after all sources to the auxiliary power system are unavailable. The essential systems may
be defined as the dc power systems that provide the power required for relaying, control, telemetry, and
communications, and any ac power needed for breaker operation.

Factors that may determine the need for a standby backup ac system are the criticality of the substation, the
battery life for the essential systems, and the reliability of the ac sources for the auxiliary system. If there is a
possibility that an event can occur where the minimum time period to provide dc power is exceeded, a standby
backup ac system may be considered.

The standby backup ac system should be a stand-alone unit that provides power without the support of the
overall electric power system. An automatic start for the system may be desirable, considering that telemetry
and communications functions may be disabled. Control of the generator would be through an auto-transfer
switch. Manual control may also be available. Isolation of the sources to the auxiliary power system is
necessary before connecting the standby backup ac system. The designer should avoid ac system paralleling.

The standby backup ac system used in substation normally consists of a generator. The fuel source for the
standby generator should be selected based on regional conditions, such as temperature and availability of
fuels. The generator is normally used in the substation for one of the following reasons:

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a) Used as backup to the normal source when only one source is available, and the substation requires
two redundant ac sources.
b) Used as the third source when two sources are available, and the substation requires three ac sources.
c) Under emergency condition when all the normal ac sources are not available, the backup generator is
used to restore the system.

When the generator is used as a backup to one or more normal ac system(s), the station load can be transferred
to the generator automatically by the use of an automatic-transfer switch or by manual transfer, as required.

5. Design of substation dc auxiliary system

5.1 Design criteria
5.1.1 Introduction

Prior to the start of the dc system design, the designer should consider several factors that are crucial to
successful implementation. Typically in substation applications, the primary purpose of dc auxiliary systems
is to provide a reliable power source for the power system protection. DC systems provide power to operate
protective relays, monitoring equipment, and control circuits that operate power circuit breakers or other
fault-isolating equipment. The dc systems are designed to provide power for these protection systems during
outages and when the power systems are intact. Several key factors are listed below. Figure 21 is a simplified
dc block diagram.

Figure 21—Simplified dc system block diagram

5.1.2 Reliability

The reliability requirements of the power system are typically defined by the system protection design.
For example, the design requirements for transmission equipment is likely different than the requirements
for distribution equipment. These designs determine the robustness requirements for the systems. System
reliability standards should be reviewed to determine if back-up equipment or automatic switching is required
in the event of one piece of equipment failing.

5.1.3 Redundancy

The redundancy requirements of dc systems are typically related to the power system protection requirements.
For example, a transmission substation may be designed with redundant components of the protection system.
Redundant components may include ac voltage sources, protective relays, breaker trip coils, and duplicate

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components of the dc systems. Failure of one or more components of a non-redundant dc system may prevent
operation of the protection and control systems, which could lead to system outages or stability problems.
Providing redundant dc system components, such as batteries, chargers, and panelboards, may improve the
integrity of the power system in the event of power system faults, dc system maintenance, or other utility
operation.

A distribution system may not have similar design requirements or concerns related to system stability. A
designer could consider that the criticality of a certain distribution substation, such as the nature or location
of the load or customers served by that substation, may justify the addition of redundancy in the dc system.
Consideration for system back-up methods for failed equipment such as mobile substations or field ties to an
alternate source, could provide a more economical or acceptable solution to dc system redundancy.

There may be regulatory requirements requiring redundancy.

5.1.4 Environment

The environment that dc systems are exposed to impact the reliability of battery performance including the
capacity and life of the battery. Key environmental components include: temperature, vibration, cleanliness,
and ventilation. Some applications may be susceptible to seismic considerations.

5.1.5 Design considerations

The dc system design should be based on capacity and performance. Applicable criteria should be reviewed to
confirm a reliable and cost-effective system has been selected for the life of the installation.

Some factors to consider:

a) Load on the dc system when the maximum output of the battery charger is exceeded.
b) Demand on the battery when the output of the charger is interrupted.
c) Demand during the duty cycle.
d) Battery re-charging time.
e) DC system redundancy requirements.
f) The battery standby duration (e.g., 2 h, 4 h, 8 h, 12 h), when auxiliary ac power is lost.
g) Battery life—What is the projected minimum life of the dc system? Are battery life cycle costs factored
into cost of operation?
h) Battery type
i) Cost/reliability—What was the cost and quality of the battery initially selected? Does operational
history align with published life/costs?
j) Available fault current of the dc system.
k) Arc flash hazards—Reference NFPA 70E [B36].
l) Operating temperatures—Is the battery to be subjected to temperature extremes? When air
conditioning is lost, what is the expected minimum or maximum temperature the battery can be
expected to reach? What are the expected times to reach these temperatures?
m) Maintenance intervals—The overall reliability of the battery depends on proper maintenance.
n) Location—Is the battery located where required maintenance can be completed? Is the battery
properly ventilated? Is any associated equipment susceptible to damage from electrolyte?

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o) Vibration/shock—Is the battery located near rotating equipment? Lead-acid batteries easily shed their
active materials from the surface of the plates, affecting battery life.
p) Weight/size—Physical size and weight can play a significant role in determining the type of battery to
be selected. Is there enough room for the battery and rack in the proposed location? Can the location
of the battery accept the floor loading? Can the battery cells be replaced with all adjacent equipment
installed, or are lifting measures required (e.g., a multi-cell jar can easily weigh over 50 kg)? Is
adequate space allocated to get either a permanent or portable lifting device installed? Parallel strings
could be considered to reduce weight and size.
q) Design process—Does the design process account for verification of the dc system loads for all
additions or changes?
r) Changed state loads—Does the design need to account for loads that may change state? Examples
are breaker spring charging motors that run on dc on loss of ac, or a supervisory control and data
acquisition (SCADA) computer monitor that is fed from an inverter source that fails to dc on loss of its
normal ac service.
s) Is emergency lighting required? If so, can an alternate source be provided?
t) Does the dc system have alternatives in the substation emergency power system?
u) Safety components in the dc design include mitigating arc flash, electric shock, and short circuits.

The design considerations need to accommodate both the owner’s requirements and those of any regulatory
agency, AHJ, or quasi-regulatory agency. Other considerations may include those of any insurer or transmission
operator (e.g., black start plans). For example, a black start, or system restoration plan, may require more than
one attempt to close a transmission path and re-establish a secure source of the station ac service. During these
attempts, breaker spring motors may have to charge on the station battery, which may be overlooked in an
existing load case and may need to be accounted for in a new design.

5.2 Typical equipment served by the dc system

The dc system in a substation serves many critical and non-critical functions and equipment. Some typical
equipment served may include:

a) Circuit breakers
b) Circuit switchers
c) Motor operators
d) Protective relay systems
e) SCADA
f) Fire protection/detection
g) Emergency lighting
h) Security systems

While most of the equipment is required to be operational at all times, some may be defined as non-critical and
may be segregated to reduce loads in the event where the battery of the dc system is required to carry substation
loads without the battery charger available. Consideration should be given to limit the amount of non-critical
loads connected to the battery to provide reliability to the system protection and to limit the size of the battery.

The equipment may require dc voltages at different values such as 125 V (dc) for circuit breaker controls and
12 V (dc) or 24 V (dc) for a radio communication system. The designer needs to determine the best method

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to supply the various voltages. It is not recommended to tap a larger voltage battery for lower voltages (i.e.,
24 V tap on a 125 V [dc] battery). If alternate voltages are required to be supplied from a single battery, dc–
dc converters are typically utilized for smaller non-critical loads at a lower voltage or a second dc system
dedicated to the communications equipment could be installed. It is not recommended to install many dc–dc
converters to provide different voltages. Vendors should be consulted to determine if alternate power supplies
can be used.

5.3 One-line diagram

5.3.1 Introduction

To start the design process, it is recommended that the designer create a one-line diagram showing the battery
(or batteries), charger (or chargers), dc panels, and all connected loads. Consideration should also be given
for future load growth. A review of the overall substation one-line may aid in determining future possible
additions.

The one-line diagram is very important. The following should be considered during the design of the one-line
diagram:

a) System redundancy (number of chargers and battery banks)

b) Fault currents and arcing currents
c) Distribution panel connections (number of panels and how they are connected)
d) Cross tie breakers (if necessary)
e) Isolation points (for isolating equipment for maintenance)
f) Protection devices (e.g., battery bank disconnect switches and fuses for downstream protection of
cables and panels)
g) Commissioning and maintenance procedures (ability to transfer loads and isolate sources)

5.3.2 Number of battery systems

The designer should evaluate the criticality of the substation facilities and owner’s preference or regulatory
requirements. High-voltage and extra-high voltage (EHV) protective relay systems are normally designed
with two independent systems. The systems are inclusive from the dc feeds to independent trip coils in the
circuit breakers. The designer should review whether separate battery systems and panels are required, a single
battery system with independent dc panels, or one battery system and panel. Independent systems may provide
better opportunities for maintenance or replacement in the event of equipment failure or the need to upgrade in
the future. The ability to tie redundant dc systems may also aid in maintenance activities.

The number of battery systems may depend on the voltage level of the equipment. For example, if a
communication system requires 48 V (dc) and the substation equipment is 125 V (dc), the designer needs to
consider whether the communication equipment would be supplied by its own battery and charger as noted in
5.2, or be supplied by a dc-dc converter. The decision should consider reliability and control enclosure space
among other issues. The number of battery systems has a direct impact on the size of the control house as
battery systems typically occupy wall space that can dictate building size.

5.3.3 Load transfer

The designer needs to account for any dc load transfer requirements. Load transfer could be automatic or
manual and serves to backup one dc system in the event of a charger failure from another system or similar
event. The need to transfer and the details of a transfer scheme can be dictated by owner’s preference or design

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criteria, criticality of the substation, or other similar reasons. All equipment that could serve additional load
upon transfer should be sized appropriately for that additional load.

There may be regulatory requirements that require the ability to transfer the dc load to enhance reliability of
the protection systems for the electric transmission system. In North America, the North American Electric
Reliability Corporation (NERC) and regional transmission organizations have established requirements for dc
system reliability.

5.4 DC batteries
5.4.1 Battery types

Battery types and their characteristics are discussed extensively in several other IEEE guides (refer to Annex
A). Common types of batteries used in substation applications include: valve regulated lead acid (VRLA),
vented lead acid (VLA) which are commonly referred to as flooded, and nickel-cadmium (NiCd). This may
change with time due to continued development of new battery technologies. Vented lead acid batteries are the
most common battery types used in substation applications. The intent of this document is not to focus on lead
acid batteries, and any references or examples that utilize lead-acid batteries is for convenience.

The type of battery used should be based on reliability and economic criteria. Designers, through the use of
various IEEE guides, manufacturer’s specifications, and owner’s preference, should familiarize themselves
with the impact of each type of battery on the design of the overall dc system. Considerations for selecting
different battery types should include: battery load requirement, environmental conditions (temperature range,
moisture), battery life, design, duty cycle, capacity, and planned maintenance cycle.

In most utility substation applications, the battery is not exposed to many deep cycles, so the ability
to accommodate many cycles may not be as important compared to other factors, such as battery life and
maintenance.

Typically, the battery charger supports substation loads with the battery available to supply energy for short-
duration activities, such as breaker trips and closes where the battery charger response time or capacity cannot
support the transient. The battery is also available to supply critical long- and short-duration loads when there
is loss of dc output from the battery charger.

5.4.2 Criteria for battery rating

5.4.2.1 Introduction

IEEE Std 485™, IEEE Std 1115™, and IEEE Std 1189™ are standards that should be referenced for
determining the battery size needed (based on the type of batteries used) for the dc system of substations.
These standards include requirements a designer should consider for obtaining the appropriate battery rating.
However, to aid the designer, some considerations are repeated here. In addition, this guide places emphasis
on substation specific application considerations.

5.4.2.2 Continuous loads

First using the one-line or equivalent document, the designer should review all the continuous loads such as
protective relays, SCADA systems, emergency lighting, indicating lights, communication equipment (power
line carrier, radio, telecom, microwave, fiber optic), security systems, fire protection, etc. Continuous loads
can be obtained for new substations by reviewing vendor literature or calculations from previous designs. For
upgrades at existing facilities, the data may need to be obtained by field testing, or by examining the existing
charger load, as vendor data may not be readily available. The field-obtained continuous load measurements
should be evaluated for end-of-load-cycle voltage and operating experience. When reviewing the literature,
the continuous loads should be evaluated at the final battery voltage (end of discharge or minimum cell voltage)

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selected (for example 105 V). For example, if a device has a load of 125 W, one may be tempted to have the
load at 1 A for a 125 V (dc) system. However, at final battery voltage of 105 V the load would be 1.19 A.

Care should be taken to tabulate all known loads. The designer should also review the design for future loads
and “phantom” loads that may be added by personnel other than the substation designer. For example, the
control enclosure may be designed by another person who includes a fire-protection system to meet local
codes and may add dc emergency lighting.

Substation designers should consider limiting loads connected to substation batteries used primarily for
protection purposes to provide a longer-lasting source to the protective system. Reduction of continuous loads
to help reduce the required battery size may be considered.

5.4.2.3 Momentary loads

Momentary loads are those such as breaker open or close that occur at various times through the duty cycle
(see IEEE Std 485). Many substation momentary loads such as breaker operations, lockout relays, and
communication system operations operate in time frames of several cycles (electrical cycles or Hz, not to be
confused with duty or load cycles) and careful analysis using IEEE guides and the battery manufacturer may
be required. For example, an EHV system may detect a fault in ¼ cycle, initiate communications for 1 cycle,
operate protective devices in ½ cycle, and open the circuit breaker(s) in 2 cycles. The whole operation is over
in less than 5 cycles from detection. Typical sizing per IEEE Std 485 looks at loads of 1 minute as the shortest
period. After all momentary loads are considered and the initial battery size selected, it may be advisable to
contact the battery vendor to verify the selected battery can respond to the expected loads and duration of the
load. See Figure 22.

Figure 22—Possible load case

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If a discrete load sequence can be determined, the peak one-minute load can be determined more accurately
than if the loads are summed. For example, if a substation bus trips on differential via a lockout relay (LOR)
that trips three breakers with logic that opens a motor-operated disconnect (MOD) after the breakers open,
the peak current would be either the LOR current, the sum of the three breaker trip coil currents, or the motor-
operated disconnect locked rotor current. The single max current (breaker trips or locked rotor of MOD) would
be used as the peak one-minute load. This reduces the likelihood of an overly conservative battery size. It
requires careful examination of the trip sequence to understand the peak momentary loads. Computer analysis
programs may be used. As described in IEEE Std 485, all load cases should be analyzed to verify that the proper
case is identified. A traditional load case that may have been used over an eight-hour period, for example, may
not be applicable in a situation where the substation may be required to cycle multiple loads, or an extended
period in order to restore the system after a blackout. When sizing momentary loads for motor-operated
disconnects, the locked rotor value should be used for the dc load of the motor operator to accommodate for
misoperations of the motor-operated switch. Multiple protection events should be considered, and the highest
current draw should be the worst case momentary load. Examination of the station’s ac single lines and dc
protection schematics is required to determine the protection events.

Another important issue when determining the worst case momentary load is whether to consider a breaker-
failure situation where a breaker-fail relay can operate a group of devices around a failed breaker to isolate
the fault. When utilized, breaker-failure relaying is a form of the secondary power system protection that
requires a second contingency to operate. If breaker-failure protection is used, a second contingency to operate
the breaker fail may provide the worst case tripping scenario, and this contingency should be considered to
properly size the battery. In many cases, the breaker-fail operation may put a larger load on the battery, and
both loads may occur within a minute time frame because the breaker fail would occur in a matter of cycles. In
a breaker-failure event, the highest fault current in the sequence of events in that one-minute duration should
be used for the worst case. If the original trip included a motor-operated device, it would still be operating
when breaker fail occurred, and thus should be included in both conditions before and after the breaker-fail
operation to determine the worst case scenario.

As mentioned above, restoration from “black-start,” or system restoration scenario, may need to be
considered. During “black-start” or system restoration, several trip and close cycles may be required to restore
the transmission system after a collapse. It would not be uncommon for two or three attempts to be made to
get the system to restore and become stable. As part of the “black start,” all the station breakers may be opened
prior to closing in a selected transmission path.

5.4.2.4 Duty cycle

The duty cycle of a battery is defined in IEEE Std 485 as the loads a battery is expected to supply during
specified time periods. The duration of the duty cycle and the specific loads on the battery during that time
period determines the size of a battery based on IEEE Std 485 battery sizing. An important consideration for
determining the length of the duty cycle is the response time required to restore the ac and dc auxiliary systems
to normal operation. For example, a realistic sequence of events that would follow a battery charger failure
may include the following:

a) Charger fails and initiates an alarm to SCADA

b) Dispatcher notices alarm
c) Dispatcher attempts to contact substation personnel
d) Substation personnel drives to substation
e) Substation personnel investigates alarm
f) Substation personnel determines that charger has failed and notifies dispatcher that a technician is
needed to repair the charger
g) Dispatcher attempts to contact technician

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h) Technician drives to substation

i) Technician attempts to repair charger
j) Technician determines that the charger cannot be repaired and the substation supervisor is notified
k) Substation supervisor locates spare charger
l) Substation supervisor attempts to contact additional substation personnel
m) Additional substation personnel report to service center to pick up vehicle and charger
n) Additional substation personnel drives to substation
o) Charger is replaced

It is not difficult to imagine this process taking longer than the 8-hour duration typically used in substation
designs. Under certain circumstances (particularly during major storms where there are multiple station
outages) the acknowledgement of the initial alarm is likely delayed due to other priorities, thus increasing the
battery duty cycle duration. The lack of availability of personnel to respond to an alarm may also increase the
duration during weekends or holidays. The battery may function properly supporting continuous load during
an extended time to replace the charger, but may not fulfill its design basis if called upon. Remote devices may
be needed to clear a fault having a greater impact.

Another important impact is loss of ac to the control enclosure. Similar to the loss of the charger, the battery
supports critical station loads during this type of event. However, many control enclosures may not have been
designed to limit temperature minimums or maximums without the heating or cooling systems available. The
designer should review the battery capability during this type of event.

5.4.2.5 Battery voltage and number of cells

The operating voltages of batteries are usually greater than their nominal voltage ratings. For example, on
a 48-nominal-volt systems, operating voltages are typically over 50 V and operating voltages are typically
over 130 V for 125-nominal-volt systems. The operating voltages vary depending on the chemistry and
specific gravity of the battery electrolyte. The float voltages (voltage in the nominal charged condition) for
an individual cell vary from approximately 2.17 V per cell to 2.25 V per cell, depending on the type of battery
and number of cells. In some cases, these batteries are equalize charged (continuation of the regular charge at
a higher voltage). It is important to verify that the equalization charge voltage does not exceed the maximum
system voltage of the dc system which is typically dictated by equipment ratings.

In substation applications, the maximum dc system voltage is typically limited to 140 V. In this case, the
maximum cell voltage depends on the number of cells in the battery. The designer should review with the
owner if the required equalization voltage would exceed alarm limits or normal equipment ratings (typically
140 V for 125 V (dc) systems). In that case, the number of cells may need to be reduced or the equalization
voltage reduced, increasing the recharge time. The minimum voltage for lead acid battery cells is typically 1.75
V per cell, which is normally considered fully discharged. Other battery types will have differing discharge
values. The designer should verify that the final battery voltage would support the equipment terminal voltage
sufficient for the equipment operation. Voltage drop calculations need to be included in this consideration.
Make sure to check connected equipment ratings if there are any questions. The voltage of the battery is
calculated by using the following formula:

( voltage of the cell) × (number of cells in series) = battery system voltage (13)

The number of cells and the end voltage of a battery system can be calculated using the following formulas:

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maximum allowable battery voltage 140 V

number of cells = → = 60 cells (14)
maximum cell vooltage required for charging 2.33 Vpc

minimum allowable battery voltage 105 V

end of discharge = × = 1.75 V (15)
number of cellls 60 cells

NOTE—Equation (14) and Equation (15) include the equation and an example in the second half that results in, or uses,
60 cells.

5.5 Battery chargers

5.5.1 Introduction

Battery chargers are discussed in detail in other IEEE guides. The battery charger is the dc power supply
that is normally used to provide the continuous loads of the station, and as a means to maintain charge on the
battery, recharge after an event, and to provide an equalizing charge to bring the battery back into specification
when cell voltages are outside manufacturer’s tolerances. The charger filtering requirements may differ per
connected load. The filtering levels are typically adequate to accommodate the continuous load currents to the
duty cycle, however they may not be adequate to accommodate the tripping transient current requirements on
most substation applications. Thus, even with a battery eliminator type filtering, removing the battery from the
dc circuit may also compromise system protection requirements.

There are four types of battery chargers commonly available as described in IEEE Std 1375™ [B16]:

a) Ferroresonant and controlled ferroresonant

b) Phase control silicon controlled rectifier (SCR)
c) Magnetic amplifier chargers
d) High-frequency switched-mode power supply (SMPS)

Battery charger type depends largely on owner’s preference or design criteria.

5.5.2 Battery charger sizing

Battery charger sizing is based on the amount of energy required to recharge a battery that has been discharged
per its full design duty cycle, the desired recharge time, the continuous dc load supported by the charger during
the recharging period, and various factors.

For a given battery duty cycle, the amount of amp-hours removed is known from the battery sizing calculation
(either manual or via computer program). This amount of charge is what the battery charger needs to supply
in order to recharge the battery in a certain amount of time. If the amp-hours removed is not known from an
available design calculation, a conservative method is to use the 8-hour amp-hour rating of the battery. This
method will typically lead to a larger-than-necessary charger, as the amp-hours removed from a battery during
a full duty cycle is typically less than the amp-hour rating of the battery.

For the recharge time, the designer should consider the owner’s preference or design criteria. Typical times of
8 hours to 24 hours are used. While a shorter recharge time may restore a fully discharged battery faster, this
may cause other problems. A faster recharge may lead to plate damage of the battery due to overheating, or
the charger being oversized for day-to-day operations. The designer needs to review the probability of a worst
case event happening during recharge, and use that to help determine battery size. For large charger sizes, the
designer may consider installing two chargers operating in parallel. Since, under normal operating conditions,

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the full capacity of the charger is not needed, it can allow for routine maintenance, or even a single charger
failure to occur, without an effect on battery performance.

The recharge factor accounts for additional energy needed to fully recharge the battery. During charging,
the recharge efficiency of the battery should be considered, including losses (e.g., heat) experienced during
recharging that are not included in the amp-hours removed. The recharge factor depends on the battery
technology. The battery manufacturer’s specifications and literature should be consulted, but typical values
include 1.1 for VLA, 1.15 for VRLA, 1.3 for vented Ni-Cd, and 1.4 for valve-regulated Ni-Cd.

A design margin factor may be included at the discretion of the designer. While chargers do not age or lose
capacity over time like batteries, it may be desirable to add an additional design margin to account for
future station load growth, changes in the battery duty cycle, or other factors. If the battery duty cycle amp-
hours removed is used in the charger sizing, then there is typically no additional design margin already
included. If the conservative method of using the 8-hour amp-hour rating of the battery for the amp-hours
removed in charger sizing, then a design margin from the battery sizing calculation may already be
included. Note the charging rate should be limited to 20% of the 8-hour capacity per battery manufacturer
recommendations.

An altitude/temperature correction factor may be needed based on the installation conditions or the charger.
The charger manufacturer’s specifications and literature should be consulted to determine these factors.

Sizing—The following formula may be used to determine the required dc output of the battery charger.

éæ A ö ù
I = êçç ÷÷÷ e + I C ú (d )(k ) (16)
êëçè t ø úû

where

I is the calculated battery charger output, dc amperes

A is the ampere-hours to be replaced
t is the time in which the battery should be recharged
e is the recharge factor
IC is the continuous dc load current
d is the design margin factor
k is the altitude correction factor

5.5.3 Battery charger connections

The designer should review the owner’s preference, or design criteria, regarding the method of connecting
the battery charger to the dc system. All connection methods have benefits and drawbacks. The charger can
be connected at various points in the system including:

a) Directly to the battery terminals

b) Source side of battery disconnect switch, if one exists
c) Load side of battery disconnect switch, if one exists
d) DC panel main lugs
e) DC panel branch circuit
f) DC bus terminal block
Figure 23, Figure 24, and Figure 25 demonstrate three connection options.

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Figure 23—Battery with breaker disconnect and charger at dc panels

Figure 24—Battery with fuse disconnect and charger at dc panels

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Figure 25—Battery with no disconnect

If the charger is connected directly to the battery or on the source side of the disconnect switch, it could be
considered a reliable method of charging the battery, since there are minimal points of failure in between the
charger and battery. However, since the charger also serves to supply power to continuous loads under normal
operation, a fault on the battery, or removal of the battery for replacement (by opening the battery disconnect
switch [Figure 23] or disconnecting the main battery leads/cables [Figure 25]), may disconnect the charger
from the loads.

The charger size does not typically accommodate the worst case tripping current requirements. Most chargers
do not have capability to source more current than the rating or a tripping transient (even with the battery
eliminator option on some chargers). Substation design and operation activities need to coordinate to prevent
operating or sourcing continuous load with charger and without a battery. Even though this may be functional,
it removes the capacity of the battery to accommodate the higher loads of worse case tripping scenarios, and
thus provides a false sense of security by compromising the capability of the dc system to provide the required
dc power for the system protection.

If the charger is connected on the load side of the battery disconnect switch (Figure 23), or at the dc panel
(Figure 24), it maintains a connection to the continuous loads even in the event of a battery failure or
replacement. However, if the charger gets disconnected from the battery due to an event at the dc panel, the
battery loses its means to re-charge.

5.5.4 Charger circuit protection

Although the charger may be equipped with integral ac and dc circuit breakers or fuses, the designer may
consider external protection as well. The ac feed breaker from the main ac source should be protected in
accordance with applicable local codes. The dc output may need to be connected with another overcurrent
device to coordinate with the overall dc system. Typical charger overcurrent protection is conservatively sized
at 140% of the charger current rating. The cables connecting the charger to the dc system need to be sized to
accommodate the overcurrent protection ratings of the charger dc output and the overcurrent protection in
the dc cabinet (if the charger is connected to a dc panel with overcurrent protection). This overcurrent device
could be either a fuse or circuit breaker depending in owner preference, local codes, or coordination needs.
Both the ac and dc external protection should be used to protect the external circuit and cabling. The current
limiting characteristics of the selected charger should be reviewed in accordance with IEEE Std 1375 [B16].

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5.6 DC panels
5.6.1 Introduction

The dc panels are used to distribute power to various loads in a substation and can come in many varieties.
Panels can come with overcurrent protection on the main feed or main lug only (where the main dc feed
connects directly to the dc bus). Branch circuits can be protected by circuit breakers, fuses, fuses with knife
blade isolation, or combinations of these, such as a circuit breaker in the positive leg and knife switch isolation
in the negative. The designer should review applicable local codes and owner’s preference as to what type
should be used.

5.6.2 Critical and non-critical loads

The designer should review if there is separation required by local codes, owner’s preference, or design
criteria. This could be based on whether there is a need to separate loads as critical or non-critical. Critical
loads are those that would be required to have dc power under unusual system conditions, such as loss of
power to the site, black start path, loss of the charger, etc.

5.6.3 Circuit size

The designer should size the dc panel to accommodate the required number of circuits needed for existing load
as well as planned load growth. Branch circuits should be sized in accordance with the NEC, local codes, or
owner’s design criteria, as applicable. Branch circuits should coordinate with downstream devices, such as
fuses or circuit breakers. The installed cable should be sized to exceed the required load. Circuit size should
also account for any voltage drop. Voltage drop includes the effects of current through all interconnecting cable
to and from the remote device. The cable should be sized so the device can operate at minimum battery voltage
(i.e., 105 V [dc] on a 125 V [dc] battery) so that the minimum device voltage (90 V [dc] typical minimum pick-
up) is available at the remote device. It may be prudent to build some conservatism in the design calculation to
allow for variations in field conditions due to cable lengths, device tolerances, etc.

5.7 Load transfer methods

5.7.1 Introduction

To provide for a more robust dc system, it may be determined that a load transfer or paralleling scheme is
required. The designer should consider the additional load that will be applied in a paralleling scheme and is
accounted for in calculations that size the battery, charger, cables, etc. that are part of the dc system(s) that may
accommodate the added load. The specific details and method of transfer should also be reviewed.

When designing a load transfer between two dc systems, the fault currents and arcing currents should be
considered. Panels and protection devices should be rated for the maximum fault current of the entire system.
The designer should also consider if the two systems should be run in parallel or interlocked to not allow
parallel operation. Paralleling the battery banks will result in increasing the available fault current. It is also
recommended that paralleled battery banks should be the same type and size to ensure equal load sharing.
Additionally, if battery chargers are to be operated in parallel, the designer should verify that the selected
chargers will operate when paralleled. Consideration of paralleling two batteries with different state of charge
may cause unexpected current flows and excessive loading on the good battery.

5.7.2 DC paralleling—dc transfer scheme

Manual transfer of dc load can be accomplished with disconnect switches or temporary cables. Manual load
transfer should be accomplished in a safe manner using switching procedures, electrical isolation, physical
locks, and other methods. The equipment (cable, switch, lugs, etc.) that actually transfers the load from one
system to the other should be sized for the expected load to be transferred, as well as future load growth. Figure
26 and Figure 27 show two possible manual transfer schemes.

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Figure 26—Simplified parallel/transfer with two disconnects

Figure 27—Simplified parallel/transfer with one disconnect

In the above examples, the manual disconnect switches are sized for the larger of the two connected panel
loads. The cabling to the switches is sized for the total dc system loads. Means to provide isolation of the
switches for maintenance should be considered.

A simple paralleling/transfer system may be the use of a normally open breaker or fuse position in each of
the main dc panels tying the two together when both are closed. Administrative control procedures should be
established to implement the paralleling or transfer of the two systems. Both battery systems will be sized for
the total station dc load and load profile. While more costly than battery systems designed for single segregated
loads, it provides for maintenance of the battery(s) with no disruption in supply.

5.7.3 DC transfer

DC transfer could be accomplished via transfer switches similar to those used on ac systems. Figure 28
illustrates one version of that method. This configuration creates a single point of failure, and a complete

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dc outage would be required to upgrade or replace a failed automatic transfer switch (ATS). This may be
acceptable in non-critical applications since there is only one circuit to the dc panels. Other methods may
include bypass switches to allow maintenance of the transfer switch while still powering the dc loads.
Automatic transfer switches can be purchased with internal bypass switches and removable transfer switches
for maintenance. As with the transfer/paralleling schemes, the batteries and equipment in the transfer scheme
are to be sized for the total station dc load.

Figure 28—DC transfer scheme

5.8 Design considerations

5.8.1 Battery monitoring

5.8.1.1 Introduction

The battery and dc system has many options for monitoring. The battery charger itself may be equipped with
monitoring functions such as loss of dc, low dc, battery grounds, and loss of charger ac. Some microprocessor-
based chargers have programmable flexibility to provide many other forms of battery monitoring, such as
battery temperature, impedance, and an on-line partial battery capacity test. Many microprocessor-based
relays have the option to monitor the dc source voltage to the relay and can provide additional alarm capability.
An auxiliary relay may be used to monitor systems where automatic monitoring may not be available. Through
the use of communication links, continuous loads may be monitored from the charger directly to a SCADA
remote terminal unit (RTU) or other similar device. A dc shunt may be used to measure battery current directly
and connect to a monitoring device. Please refer to IEEE Std 1491™ [B18].

5.8.1.2 Battery location

5.8.1.2.1 Fire considerations

While the battery is not normally a direct fire hazard, several conditions may present hazards. If the battery
main terminals become shorted between the main terminals, and there is no protection (fuse or circuit breaker)
as allowed by IEEE Std 1375 [B16] for overcurrent, the short-circuited battery would become a fire hazard.
The availability of fire-resistant jars may be specified to reduce fire hazards. Thermal runaway conditions
also present fire hazards. Another common hazard is the generation of hydrogen gas produced by VLA, Ni-
Cad, and VRLA batteries during charging—especially when an equalizing charge is applied. Removal of any
potential hydrogen build-up should be considered by the designer. This build-up may be removed through
normal building exhaust or leakage, direct exhaust of the battery area, or by inclusion of fresh air into the

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building ventilation system. IEEE Std 1635™ [B20] notes several other recommendations. The designer
should be aware of any restrictions imposed by the AHJ in regards to battery ventilation. IEEE Std 979™
[B10] provides guidance for fire protection in substation applications. IEEE Std 1375 [B16] provides some
additional guidance as well on physical protection of batteries. Local codes or the owner’s preference should
be reviewed as to whether the battery should be housed in its own room or enclosure.

The battery charger also does not present any direct fire hazard. However they generate heat as part of the
ac–dc conversion and care should be taken to restrict flammable material from being located above the vent
openings.

Working clearance meeting the requirements of the NESC [B1] Table 125-1 (or local codes) should be used to
provide safe access to the equipment for workers and in the event of an emergency.

5.8.1.2.2 Maintenance considerations

As discussed in 5.8.1.2.1, working space meeting the requirements of NESC [B1] Table 125-1, or other
jurisdictional codes, should be maintained. In retrofit designs of older stations, the designer should check
clearances that may have been compromised over the life of the substation, or in replacing equipment that was
installed prior to code applicability. Consideration should also be given to a method for removing battery cells
in the future. Space for a permanent or temporary lifting device may be needed. Typical substation battery
cells weigh 20 kg to 70 kg (44 lb to 154 lb). Lifting cells of that weight can be very difficult for maintenance
from upper steps or tiers of a battery rack.

An eyewash station (or equivalent device) should be available to support workers in the event of acid contact.
Provisions should be made for storing the specific gravity tester and an acid-resistant cloak if required by the
owner. Consideration should be given to using a spill containment system around the battery to absorb acid in
the event of a catastrophic cell failure. Refer to 5.8.1.3 and IEEE Std 1578™ [B19] for further information.

5.8.1.2.3 Reliability considerations

The designer should review owner’s preference or local codes for separation of multiple battery systems.
Physical separation or barriers may be required for multiple systems to reduce the likelihood of a catastrophic
event (e.g., fire or short circuit) on one dc system propagating to other dc systems. This can include physical
separation by air gap or installation of a barrier (a wall or locating batteries in separate rooms). As the battery
system is crucial in allowing most substation equipment to successfully operate, care should be given to
provide as much protection to the battery system as reasonably possible.

Reliability is also dependent on battery area temperature. Battery area temperature should be monitored and
kept constant (refer to 5.8.1.2.5 and 5.8.1.4). Owner’s operating practice for response to building high or
low temperatures should be reviewed to determine effect on battery performance and reliability. Low or high
temperatures outside the design of the battery load profile can impact reliability.

Reliability of the dc system is also affected by the placement location of dc panels. Separation of dc panels
may reduce the likelihood of a single panel fire removing both dc systems, and should be considered. Cable
routing should also be reviewed. Some utilities run dc cables from different systems in separate locations to
enhance reliability.

5.8.1.2.4 Battery room door requirements

If the battery is placed in its own room due to owner’s preference or local codes, the battery room door should
have a fire rating at least equal to the fire rating of the walls. The battery room door should also incorporate
all necessary signage to inform workers of potential hazards of the area, such as acid containing, explosive
mixtures, etc., as required by the AHJ. Interior signage should identify the exit doors. Depending on room
design and local codes, the battery room door may also need to incorporate a blast louver to relieve pressure
in the event of a hydrogen build-up and explosion. The battery room door should have a panic bar on the

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inside, and open outward into the control room or outside to allow safe egress of personnel in the event of an
emergency. Requirements for securing the door such as locks should be reviewed by the designer.

5.8.1.2.5 Battery area temperature

Battery temperature plays a key role in battery performance. Battery specifications are generally published at
25 °C (77 °F) and temperatures that vary from this can affect performance. During the battery sizing calculation
the designer should consider the minimum and maximum temperature that the battery area could reach. For
example, in a cold weather climate in winter, the battery area could easily reach 13 °C (55 °F) during a loss of
ac to the substation, depending on building insulation levels during the needed response time. Conversely, in a
warm weather climate in summer, the same loss of ac could drive the battery area over 40 °C (104 °F). Normal
operating practices should also be reviewed to determine baseline conditions as part of the battery calculation.
If the owner keeps the battery area cooler than the battery manufacturer’s recommended temperature, battery
performance may be below published data and the designer should account for the discrepancy in the design
calculation. Batteries that are installed outdoors, or in non-climate control enclosures, may be subject to large
variations in temperature.

5.8.1.3 Acid spill containment

The designer should review applicable local codes regarding acid containment. It is typical practice to install a
spill-containment system that contains the acid to an area immediately adjacent to the battery and neutralizes
it for safe handling and disposal. Use of acid-resistant paint on the floors and walls of the battery area is
recommended to reduce damage to the building in the event of a spill. If permanent spill containment is not
installed, the designer should review local codes or owner’s preference to determine if on-site temporary
acid-absorbent material or temporary containment is required. For example, in the United States, the NFPA 1
[B33] requires spill containment for an individual vessel with more than 208 liters of electrolyte or multiple
containers exceeding 3785 liters. Most substation batteries have electrolyte volumes below those limits. Refer
to IEEE Std 1578 [B19] for further information.

The designer should review the footprint required for a containment system. The designer should consider
adequate worker access and remove tripping hazards that may be created by installation of a mechanical
containment system.

5.8.1.4 Battery racks

When selecting a battery rack, there are several things that should be considered, including temperature
differences, weight of the battery, available space, and maintenance requirements. Battery racks generally
come in three types—step, tier, or stepped tier as shown in Figure 29. A step rack is designed so the battery
levels are “stepped” from one another (usually offset by the depth of a cell). A tiered rack has the levels of
batteries on top of each other. A stepped tier is a combination of the two.

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Figure 29—Rack designs

For substation applications, steps and tiers are usually limited to two levels. Step racks generally have a larger
footprint than an equivalent tiered rack, and cells can be easier to access. Tiered racks tend to save floor space
due to their smaller footprint. Other considerations with larger batteries include height and weight. Battery
weight can also be an issue for battery installation or removal, especially in tight space and/or with taller racks.
Battery weight should be considered during structural design.

The height variations between upper and lower levels of a battery rack are a concern. Height variations can
cause cell temperature differences within the same battery system. Since cell temperature can impact battery
characteristics, interconnecting cells at different temperatures can lead to an early failure of the battery system.
As a general rule, temperature gradients in excess of 3 °C should be avoided.

Battery racks should have an acid-resistant coating applied to the structural frame to preserve its integrity. It
may also be advantageous to have a liner of polyethylene or similar material on the support rails to further
protect the rails from damage and provide electrical isolation.

The battery rack should be specified based on its correct seismic zone. A seismic rack has the same basic
design as a non-seismic rack with additional bracing applied to hold the rack and cells in place.

5.8.2 Circuit considerations

5.8.2.1 Grounded and ungrounded systems

Substation batteries used for operation and control of interrupting devices and protection system, SCADA,
etc. are typically ungrounded with ground fault detection. Communication systems, such as those used by
telecom companies, are typically a positively grounded 24 V (dc) or 48 V (dc) system. The designer should be
aware of the difference and not mix the two. Direct contact input to opposite systems should be avoided and
use of interposing relays or devices should be used. Addition of unintentional grounds should be reviewed
during the design and installation process.

5.8.2.2 Isolation of main dc cables

As discussed further in 5.8.2.3.2, the battery is the source of fault current for the dc system. The cables between
the main battery terminals and the first overcurrent protection device (breaker or fuse) are usually unprotected
(unless using a mid-point fuse). Thus, designs should place the main battery overcurrent protection as close
to the main terminals as possible to reduce this exposure. A short circuit to any portion of the battery main

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terminals can produce extreme heat and fire hazard. Any damage to the cables from the battery can subject a
worker to the full short-circuit capability of the battery. The designer should review the owner’s preference to
separate the positive and negative cables of the battery to reduce the possibility of a direct short circuit being
applied to the battery. When separating cables, cables should be placed in non-magnetic conduits to reduce
induced fields from causing other potential hazards. With multiple battery systems, the designer should not
route main dc cables near one another to preserve independence and reliability.

IEEE Std 1375 [B16] gives additional guidance on the methods of protecting the main dc feed to the load
device from the battery. They include:

a) Battery fuse (in both positive and negative leads for ungrounded systems)
b) Battery circuit breaker (including both positive and negative leads for ungrounded systems)
c) Battery disconnect switch (fused or non-fused) that allows the battery to be disconnected from the
load circuits
d) Mid-point battery fuse which protects for internal and external faults and limits fault energy by up to
half of the battery capacity for certain types of faults; cable only, no overcurrent provided

IEEE Std 1375 [B16] gives a description of the advantages and disadvantages of each method.

5.8.2.3 Circuit protection and coordination

5.8.2.3.1 Coordination of overcurrent protection

The designer needs to review the coordination between all devices in the dc circuit in accordance with the
NEC [B34], local codes, or owner’s design criteria. Overcurrent protection devices should be sized such that
an upstream device does not trip for a downstream operation. For example, if a dc panel circuit feeds both a
relay panel fuse and a circuit breaker trip coil, the relay panel fuse should operate due to a protective relay
power supply or circuit failure and leave the circuit breaker trip coil operational.

5.8.2.3.2 Short-circuit levels

Since the battery is the primary current source in case of short circuit, the battery data sheet or manufacturer
should be consulted to determine available fault current. The interrupting devices in downstream circuits
should be reviewed for their dc ratings. Many devices may appear to have sufficient interrupting capability, but
do not have the appropriate asymmetrical interruption current (AIC). Without proper AIC, a breaker may not
interrupt the current. It may weld closed or open without the ability to dissipate the energy. These conditions
could result in damage to equipment, injury to personnel, and/or other unintended operations. Similar
conditions apply to fuses used for interrupting faults.

The designer should consider protection of the main dc feed by use of circuit breakers or fuses. Subclause
5.8.2.2 and IEEE Std 1375 [B16] give more guidance on protection of the battery main feed.

5.8.2.3.3 Fuse and circuit breakers

The designer should consider local codes as well as owner’s preference or design criteria when selecting circuit
breakers or fuses. Fuses may have a lower initial installed cost, but may require additional spare material to be
stored on site to allow for replacement in the event of an operation. Fuses may also require a fuse monitor to
be installed to detect and provide indication that they have operated. Circuit breakers may have a higher initial
installed cost, but they provide indication they have operated, and usually do not require replacement after
they have operated.

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5.8.3 Equipment rating

5.8.3.1 Indoor and outdoor equipment ratings

The dc equipment should be selected to be of the proper rating for their intended location. Outdoor rated
equipment may be installed within indoor substation locations, but indoor rated equipment should not be
installed outdoors. It may be advantageous to have some dc panels placed closer to the loads they support,
such as circuit breakers in a large transmission substation. In this application, outdoor rated equipment may be
required, such as NEMA 3R or NEMA 4.

5.8.3.2 Equipment current and voltage ratings

As discussed previously, the dc equipment should be rated for interruption of fault current. System
configuration should be considered for determining ultimate fault current availability. If a main breaker is
used, it should be able to interrupt the maximum short-circuit current available from the battery for the life
of the battery. The designer should review interrupting capability during a battery replacement. Continuous
current rating should match or exceed the current drawn by existing loads and allow for future growth. Voltage
rating should match or exceed the maximum battery voltage (i.e., 250 V [dc] for a 125 V [dc] battery). Fault-
interrupting current ratings at a dc level should be known. A large battery may be capable of currents over 10
kA. DC interrupting capability of the main fuse or circuit breaker should be reviewed. The interrupting rating
of the distribution panel is based on the breaker(s) with the lowest fault current rating.

5.9 Maintenance provisions

5.9.1 Isolation switches

The designer should review local codes and owner’s preference or design criteria regarding the need to
provide isolation switches for the battery and charger. Main isolation switches can allow a temporary battery
to be installed during maintenance, upgrades, or replacement. Since it is usually not feasible to shut down an
entire substation during a battery change out, providing an isolation switch where a temporary battery can be
connected can be advantageous during upgrades or emergencies, such as battery failure. Similar logic can be
applied to chargers, though in case of a charger failure or replacement, it is usually easier to connect a charger
temporarily than a battery.

5.9.2 Equipment accessibility

As discussed previously, access per NESC [B1] Table 125-1 or other local codes should be maintained. Table
125-1 provides minimum clearances, but owner’s preference and design criteria should also be reviewed.
Battery cells/jars can be heavy enough that workers may not be able to lift without mechanical assistance.
Access room may need to be maintained for mechanical lifting devices to install or remove battery cells/jars.
Safe working clearances between the battery and other equipment should be maintained. Overhead lifting
devices may need to be anchored to building supports to remove battery cells.

Battery chargers may also require lifting devices. The designer should also consider the heat generated by
chargers when evaluating equipment accessibility.

5.9.3 Back-up supplies

The designer should review owner’s preference for any back-ups and/or spare parts. Based on the importance
of the substation, there may be a need for back-up equipment (either charger or battery bank). As discussed
previously, if provisions are made during design, then back-up supplies can easily be connected. If back-up
supplies are required, the design should account for the time frame required to facilitate timely or permanent
connection of any back-up supplies, including the location of back-up or temporary connections. Also, the
designer needs to review if automatic actions are required to place any back-up supplies in service.

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Annex A
(informative)

Bibliography
Bibliographical references are resources that provide additional or helpful material but do not need to be
understood or used to implement this standard. Reference to these resources is made for informational use
only.

[B1] Accredited Standards Committee C-2, National Electrical Safety Code® (NESC®).6,7

[B2] Distribution Transformer Handbook, First Edition, Transformer connections, General Electric, October
1951.

[B3] IEEE Std 141™, IEEE Recommended Practice for Electric Power Distribution for Industrial Plants
(IEEE Red Book™).

[B4] IEEE Std 242™, IEEE Recommended Practice for Protection and Coordination of Industrial and
Commercial Power Systems (IEEE Buff Book™).

[B5] IEEE Std 446™, IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial
and Commercial Applications (IEEE Orange Book™).

[B6] IEEE Std 450™, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented
Lead-Acid Batteries for Stationary Applications.

[B7] IEEE Std 484™, IEEE Recommended Practice for Installation Design and Installation of Vented Lead-
Acid Batteries for Stationary Applications.

[B8] IEEE Std 485™, IEEE Recommended Practice for Sizing Lead-Acid Batteries for Stationary
Applications.

[B9] IEEE Std 946™, IEEE Recommended Practice for the Design of DC Auxiliary Power Systems for
Generating Systems.

[B10] IEEE Std 979™, IEEE Guide for Substation Fire Protection.

[B11] IEEE Std 1106™, IEEE Recommended Practice for Installation, Maintenance, Testing, and Replacement
of Vented Nickel-Cadmium Batteries for Stationary Applications.

[B12] IEEE Std 1115™, IEEE Recommended Practice for Sizing Nickel-Cadmium Batteries for Stationary
Applications.

[B13] IEEE Std 1187™, IEEE Recommended Practice for Installation Design and Installation of Valve-
Regulated Lead-Acid Batteries for Stationary Applications.

[B14] IEEE Std 1188™, IEEE Recommended Practice for Maintenance, Testing, and Replacement of Valve
Regulated Lead-Acid (VRLA) Batteries and Stationary Applications.

6
The IEEE standards or products referred to in Annex A are trademarks owned by the Institute of Electrical and Electronics Engineers,
Incorporated.
7
IEEE publications are available from the Institute of Electrical and Electronics Engineers (http://standards.ieee.org/).

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[B15] IEEE Std 1189™, IEEE Guide for Selection of Valve-Regulated Lead-Acid (VRLA) Batteries for
Stationary Applications.

[B16] IEEE Std 1375™, IEEE Guide for the Protection of Stationary Battery Systems.

[B17] IEEE Std 1458™, IEEE Recommended Practice for the Selection, Field Testing, and Life Expectancy
of Molded Case Circuit Breakers for Industrial Applications.

[B18] IEEE Std 1491™, IEEE Guide for Selection and use of Battery Monitoring Equipment in Stationary
Applications.

[B19] IEEE Std 1578™, IEEE Recommended Practice for Stationary Battery Electrolyte Spill Containment
and Management.

[B20] IEEE Std 1635™, IEEE/ASHRAE Guide for the Ventilation and Thermal Management of Batteries for
Stationary Applications.

[B21] IEEE Std C57.12.00™, IEEE Standard for General Requirements for Liquid-Immersed Distribution,
Power, and Regulating Transformers.

[B22] IEEE Std C57.12.10™, IEEE Standard Requirements for Liquid-Immersed Power Transformers.

[B23] IEEE Std C57.12.20™, IEEE Standard for Overhead-Type Distribution Transformers 500 kVA and
Smaller: High Voltage, 34 500 V and Below; Low Voltage, 7970/13 800Y V and Below.

[B24] IEEE Std C57.91™, IEEE Standard for Loading Mineral-Oil-Immersed Transformers and Step-Voltage
Regulators.

[B25] IEEE Std C57.96™, IEEE Guide for Loading Dry-Type Distribution and Power Transformers.

[B26] IEEE Std C57.105™, IEEE Guide for Application of Transformer Connections in Three-Phase
Distribution Systems.

[B27] IEEE Std C62.22™, IEEE Guide for the Application of Metal-Oxide Surge Arresters for Alternating-
Current Systems.

[B28] International Code Council (ICC), International Building Code (IBC).8

[B29] NEMA 250, Enclosures for Electrical Equipment (1000 Volts Maximum).

[B30] NEMA AB-1, Molded-Case Circuit Breakers, Molded Case Switches, and Circuit-Breaker Enclosures.

[B31] NEMA PB 1, Panelboards.9

[B32] NEMA PB 2, Deadfront Distribution Switchboards.

[B33] NFPA 1, Uniform Fire Code®.10

[B34] NFPA 70, National Electrical Code® (NEC®).11

8
The Uniform Building Code is available from the International Code Council (http://iccsafe.org).
9
NEMA publications are available from the National Electrical Manufacturers Association (http://www.nema.org/).
10
NFPA publications are published by the National Fire Protection Association (http://www.nfpa.org/).
11
National Electrical Code, NEC, and NFPA 70 are registered trademarks of the National Fire Protection Association.

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[B35] NFPA 70, 2014 Edition, National Electrical Code® (NEC®).

[B36] NFPA 70E, Standard for Electrical Safety in the Workplace.

[B37] UL 50, Enclosures for Electrical Equipment, Non-Environmental Considerations.12

[B38] UL 67, Standard for Panelboards.

[B39] UL 98, Enclosed and Dead-Front Switches.

[B40] UL 489, Molded-Case Circuit Breakers, Molded-Case Switches, and Circuit-Breaker Enclosures.

[B41] UL 869A, Reference Standard for Service Equipment.

[B42] UL 891, Switchboards.

[B43] UL 991, Standard for Tests for Safety-Related Controls Employing Solid-State Devices.

[B44] UL 1008, Transfer Switch Equipment.

12
UL publications are available from Underwriters Laboratories (http://www.ul.com/).

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Annex B
(informative)

Conductor selection examples

B.1 Example B-1
A designer is tasked with designing a load-distribution scheme for station service in an electrical substation.
The designer completes a load study, and once finished, contacts an ac panel supplier to purchase their ac panel
for the load-distribution scheme. The authority having jurisdiction (AHJ) has mandated that all station service
installations follow the NEC 2014. While waiting for specification back from the panel vendor, the designer
begins selecting the cables for the scheme.

One of the cables the designer is selecting will supply a 120 V, 200 A single-phase load, will be located outdoors,
and will be assumed to be connected to 75 °C termination. Based on the given information, the designer
selects a 600 V, 75 °C, 4/0, cross-linked polyethylene high heat-resistant water-resistant (XHHW) conductor,
per NEC 2014 Tables 310.104(A), 310.15(B)(16), and cable manufacturer recommendations. Upon receiving
specification back from the panel supplier, the designer discovers that the branch circuit breaker terminations
on the panel are only rated for 60 °C. The designer should now find a different solution for the 200 A load, as
their cable should be derated to the 60 °C temperature rating: 195 A [see Table 310.15(B)(16)].

In addition to temperature rating of terminations, the availability of terminations at the connected equipment
may be a limiting factor as well. For example, when sizing conductors it is determined that a single 250
kcmil conductor would meet the ampacity requirements. The equipment terminations are the tap-screw
type, however, and only allow two connections with sizes ranging from 4 AWG to 4/0 AWG. The designer
determines that two 1 AWG conductors would still meet the ampacity requirements of the circuit. So in this
case, the availability of terminations ultimately governed the conductor size.

The designer verifies the conductor is adequately sized based on the available fault current at the circuit
breaker termination. The AHJ has dictated that the short-circuit capability ratings be determined based on
IEEE Std 242-2001 [B4]. The available fault current in this case is 20 kA. Based on the manufacturer specs
and associated time-current trip curves, the circuit breaker feeding the load should trip within a maximum
time of 1.5 cycles. The designer has selected 1 AWG XHHW copper conductors, with a continuous operating
temperature of 60 °C, and a short-circuit temperature rating of 250 °C.

The designer first calculates the virtual available fault current based on IEEE Std 242-2001 [B4], Figure 9‑4:

KT = 1.2

virtual available fault current = 20 kA × 1.2 = 24 kA

Based on the virtual available fault current, and a fault-clearing time of 0.025 s, the designer determines that a
single 2 AWG copper conductor would be sufficient, based on IEEE Std 242-2001 [B4], Figure 9-2. Since two
1 AWG conductors are being used per phase, there is no need to change the size of the conductor.

B.2 Example B-2

A designer is tasked with designing a load-distribution scheme for station service in an electrical substation.
The AHJ has mandated that all station service installations for the project follow the NEC 2014 [B35]. A
majority of the scheme is designed to be three-phase, 208/120 V. The designer checks the design criteria, finds

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that the ambient temperature for the area is 29 °C, and as a result selects all of their cables based on 30 °C
ambient temperature ratings.

One of the branch circuits is designed to feed an SF6 gas cart for outdoor HV breaker servicing. The gas cart
product manual states that it has a power demand of 60 A, a power factor of 0.9, and requires a 208 V, 3-Ø, four-
wire supply. The circuit run is 61 m (200 ft) long and routed through a 4 in polyvinyl chloride (PVC) conduit
with two other 3-Ø, four-wire circuits. The supply conductor will be connected to copper termination points,
rated at 75 °C. Gas carts are rarely operated for more than two hours. Any load that is not expected to run for
three hours or more is considered a non-continuous load, per NEC Article 100. Based on this information and
NEC 210.19(A)(1), 310.15(B)(16), the designer initially selects the branch circuit conductor that supplies the
SF6 gas cart to be 6 AWG, copper thermoplastic heat and water-resistant nylon-coated (THWN) rated at 75 °C.

Once the initial selection has been made, the designer should account for conductor bundling effects and
voltage drop. The calculation for bundling effects is performed first, per NEC 310.15(B)(3)(a). There are two
ways that this process can be executed; the first one shown below is not recommended, but has been given for
demonstration purposes.

Note that the value used in the calculation is 70%, since, out of the total of 12 conductors in the PVC conduit,
only 9 are current-carrying:

I ′ = I × 0.7 = 65× 0.7 = 45.5 A (B.1)

where

I ' is the adjusted conductor ampacity per NEC Table 310.15(B)(3)(a)

I is the NEC conductor ampacity per NEC Table 310.15(B)(16)

It is clear from this conductor bundling calculation that the 6 AWG conductor does not have sufficient ampacity
to supply the load. At this point there are two ways to find the appropriate conductor to supply the load per
NEC 310.15(B)(3)(a): 1) select a conductor of the same type, yet with higher ampacity rating, and calculate
the adjusted ampacity of the conductor per NEC Table 310.15(B)(3)(a) until a sufficient conductor is selected,
or 2) apply the adjustment factor to the full load amperes, and then select a conductor of sufficient ampacity
from NEC Table 310.15(B)(16). The second option is the easiest route, as it only requires one calculation,
instead of iterative calculations:

I L ′ = I L ÷ 0.7 = 60 ÷ 0.7 = 85.71 A (B.2)

where

I L ' is the adjusted load amperes for conductor bundling

I L is the load amperes

Based on this calculation, the designer would select 3 AWG copper THWN. The designer also has the option
of routing one or two of the sets of 3-Ø, four-wire circuits through another raceway, in order to decrease, or
possibly eliminate, the correction factor for conductor bundling.

Next, the designer should consider the voltage drop of the conductor. The designer has designed the system
to where the voltage drop of the feeders does not exceed 2% to the point of termination at the panel, and 5%
overall. The voltage drop is calculated based on the initial information given, formula given in NEC 2011,
Table 9, Note 2, as well as the values given in Table 9, as shown below.

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First, effective Z is calculated for a 3 AWG copper wire running through PVC conduit. Note that if available,
the impedance given by the manufacturer should be used in the calculation. NEC Table 9 provides values
based on uncoated wires, and could be used for estimation:

Z e = R × pf + X L ×sin (arccos ( pf )) (B.3)

0.2253Ω
Z e = 0.25× 0.9 + .047 ×sin (arccos (0.9)) = (B.4)
kFT

Next, the voltage drop is calculated based on the effective impedance:

VD = I L × Z E × L × 3 (B.5)

VD = 60× 0.22537 × 0.2×1.73 = 4.68 V (B.6)

VD 4.68 V
%Drop = = ×100 = 2.25% (B.7)
VL 208 V
where

VD is the voltage drop expressed in volts

VL is the required load voltage expressed in volts
IL is the load amperes
ZE is the effective impedance of the conductor
L is the total distance of wire in circuit run, given in kFT

Note that the calculation above is essentially the same as the 3-Ø voltage drop calculation except it is simplified
into two separate equations.

In this case, the voltage drop is acceptable, as it is below the required 3% per NEC 210.19(A) (Note 4). Had
it been excessive, the designer would have to select a conductor with a lower impedance cable (usually larger
size), or find an alternate route to decrease the distance of the circuit feeding this load.

Further into the design of the auxiliary system, the designer finds out that the ambient temperature at the
substation is not 29 ° C—it is actually 33 °C. The load amperes should be recalculated to account for the
change in ambient temperature, per NEC Table 310.15(B)(2)(a):

IL 85.71
I L ′′ = = = 91.18 A (B.8)
0.94 0.94
where

I L " is the adjusted load amperes for change in ambient temperature

I L ' is the load amperes adjusted for conductor bundling

In this case, the conductor size does not need to be adjusted, as it can satisfy the load amperes requirement per
NEC Table 310.15(B)(16).

The last check the designer performs is for the short-circuit rating of the selected conductor. The AHJ has
dictated that the short-circuit capability ratings be determined based on IEEE Std 525. The available fault
current in this case is 10 kA. Based on the manufacturer specs and associated time-current trip curves, the

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circuit breaker feeding the load should trip within a maximum time of 0.5 cycles. The designer has selected
3 AWG copper THWN conductor, with a continuous operating temperature of 75 °C, and a short-circuit
temperature rating of 250 °C.

Based on the information provided, the designer performs a short-circuit capability calculation, based on
IEEE Std 525:

I
A= in circular mils (B.9)
0.0297 T + 234
log10 2
t T 1 +234
where

I is the short circuit in amperes = 10 000 A

t is the time of short circuit in seconds = ½ cycle = 0.0083 sec
T1 is the maximum conductor operating temperature = 75 °C
T2 is the maximum conductor short-circuit temperature = 250 °C

10 000
A= = 11 996.5 in circular mils ≈ 9AWG (B.10)
0.0297 250 + 234
log10
0.00833 75 + 234
The chosen conductor size, based on the calculated amount of area, is 9 AWG. This is smaller than selected
conductor size 3 AWG, so no change in conductor size is necessary.

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Annex C
(informative)

Battery sizing example

Materials and information needed for calculation:

a) Metering and relaying drawing showing relaying and tripping sequences

b) DC system schematic showing dc loads connected to the battery
c) Materials and information needed for a battery sizing calculation
d) Battery discharge curves or tables

Figure C.1—Substation one-line diagram

Options for this example:

a) Single battery supplying dc power for the substation

b) Two independent redundant batteries—load is split between two batteries into primary and secondary
systems with no ties

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c) Two batteries with an automatic transfer switch

From a battery sizing standpoint, options A and C would require batteries with the same total A-hour
requirements as they both would require a single battery to accommodate the substation dc load. Option
B would likely require two smaller batteries, possibly different sizes depending on how the primary and
secondary loads are split.

Examples of steps to size a lead-acid battery based on IEEE Std 485:

1. Determine the voltage and number of cells—Select the number of battery cells to be used to support
voltage level
2. Battery sizing considerations—Determine adjustment factors like growth, aging, design margin, and
temperature correction
3. Select the battery type and determine the characteristics of the cell—Battery type is the specific
manufacture and style; characteristics of the cell include amperes per positive plate and construction
(lead calcium, lead selenium, etc.)
4. Determine the time span of the duty cycle—How long the system has to run without the battery under
charge
5. Construct the minute-by-minute load profile (the duty cycle), which is very site specific—Determine
the continuous loads on the dc system, and determine the momentary, worst case switching event (the
maximum stress on the dc system)
6. Calculate the required positive plates of the battery for each period in the duty cycle utilizing the cell-
sizing worksheet—Figure 3 in IEEE Std 485

Step 1

This example considers a 125 V nominal system with maximum dc voltage = 140 V and utilize a 60 cell
battery. The example utilizes a 1.75 V per cell end-of-life cycle = 105 V for 60 cell battery.

Step 2

Design margin = 10%

The design margin provides additional capacity to accommodate future substation additions or expansions
without requiring an upgrade to the substation battery due to capacity.

Temperature correction factor = 1.15 (68 °F)

Because a battery’s performance is affected by temperature, the temperature correction factor is needed to
adjust the required battery capacity for any environment above or below the standard battery temperature
rating.

Aging factor = 125%

IEEE Std 450™ [B6] and IEEE Std 1188™ [B14] recommend that a battery be replaced when the actual
capacity drops to 80% of its rated capacity. Based on end-of-life capacity, a 125% aging factor is typically
used.

Step 3

Select the battery type and cell characteristics.

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This example looks at several types of flooded batteries, including lead selenium and lead calcium, and selects
the correct size for each type.

Step 4

Determine the time span of the duty cycle.

This example assumes a 12-hour duty cycle with the event starting the duty cycle being a failure of the battery
charger. Thus, when the battery supplies the complete dc power for 12 hours, then the worst case tripping
would occur. The definition of worst case tripping in this case is a fault and sequence of events that would lead
to the highest tripping current during the last minute of the 12-hour duty cycle.

Step 5

Construct the minute-by-minute load profile (the duty cycle).

One of the most variable components of battery sizing is defining the duty cycle or the load(s) over a defined
time period that the battery may be required to supply dc power. It is not the intent of this example to define
the duty cycle for every battery application, but to provide guidance and discussion on some of the issues that
should be taken into consideration.

Some utilities may have a standard duty cycle defined for simplicity, or to provide consistency in the battery
sizing applications. Considerations should include: duration of duty cycle, worst case tripping current (applied
at beginning and/or end of duty cycle), continuous loading, and random loads.

The duty cycle with 16.5 A continuous load and 63 A worst case tripping, is shown in Figure C.2.

Figure C.2—Duty cycle tripping

Calculating continuous current:

New substation—Add all loads connected to battery that are on for the 12-hour duration of the duty cycle.

Existing substation expansion—Record the charger output current and float voltage under float charging.
Multiply the current by a correction factor (ratio of end-of-life voltage to float voltage) in order to accommodate
the current at the lower end-of-life voltage. Then, add all new loads connected to the battery being installed on
the expansion project.

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In manufacturer documentation for relays or similar devices, power supply burden/load is typically listed at
a range or a higher value than what is observed or calculated from battery charger readings. The maximum
current draw listed is generally assuming a maximum, or more significant, amount of data processing or contact
operation than what occurs during normal operation. During a fault or switching event, the load drawn by a
relay or other device is generally higher than what is measured during normal operation. In lieu of determining
load for every device in an existing station, the designer may consider adding a multiplier or safety factor to
the current measured on the battery charger in order to account for increased “continuous” loads during fault
or switching events.

Additional load calculation items for new or substation modifications:

From the dc panel schematic, add up the continuous loads to calculate the continuous current.

The total watts is divided by the end-of-life voltage (105 V in this example) to get the total calculated
continuous current. Note that Table C.1 is an example only and the designer should verify the manufacturer’s
published data.

Table C.1—DC load table

Equipment Continuous load Quantity Watts Total
Differential relay 525 kV bus primary 2 20 40
Differential relay 525 kV bus secondary 2 20 40
Distance relay 525 kV line primary 2 35 70
Distance relay 525 kV line secondary 2 30 60
Communication Line fiber pilot 2 10 20
Communication Line carrier pilot 2 27 54
Communication Satellite clock 1 15 15
Control Process automation controller 6 10 60
Differential relay Transformer primary 2 35 70
Differential relay Transformer secondary 2 13 26
Differential relay 34.5 kV bus primary 2 13 26
Voltage differential relay Capacitor bank primary 2 17.5 35
Over current relay Capacitor bank secondary 2 15 30
Breaker fail relay Breaker fail 0 17.5 0
Over current relay Feeder relay 12 25 300
M650 meter Transformer meter 2 20 40
M650 meter Feeder meter 12 15 180
Lights Lights 40 3 120
Communication Router 1 25 25
Tel protection Tel protection 1 25 25
SCADA Remote terminal unit/ 1 325 325
human machine interface
Fault recorder 1 15 15
Communication switch Ethernet switch 2 30 60
Miscellaneous Miscellaneous 1 100 100
Total watts Total watts 1736

Total additional amperes Total additional amperes 16.5

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For continuous current calculations, use the total watts divided by the end-of-life voltage.

Continuous current = 1736 W 105 V = 16.5 A ,

Review scenarios to determine worst case tripping—Two scenarios:

Case 1 = fault on 34.5 kV bus 1

Sequence Fault scenario Devices actuated Load type Amperes Amperes

Less than Greater
5 cycles than 5
cycles
New additional load Continuous 16.5 16.5
Existing continuous load Continuous 0.0 0.0

1st 34.5 kV bus 1 fault

Trip breakers FB1— 42
FB6 (6 breakers)
Trip Cap bank 7
Trip breaker BT1 7
Trip bus tie breaker TB1 7

Then Breaker failure on breaker BT1

LOR (BT1) 5
Trip breakers 5B2 and 42
5B3 TC2 (ABC)
Total 79.5 63.5

Case 2 = fault on TR1

Sequence Fault scenario Devices actuated Load type Amperes

Duration Ampere loading
Greater
Less than than 5
5 cycles cycles
New additional load Continuous 16.5 16.5
Existing continuous load Continuous 0.0 0.0

1st TR1 fault

Trip breakers 5B2 and
5B3 TC1 and 2 (ABC) 42
Trip breaker BT-1 TC1 7
Restore 34.5 kV bus
Then 1 via breaker TB1
Close TB1 3.5

Total 65.5 20.0

Step 6

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Calculate the required positive plates of the battery for each period in the duty cycle utilizing the cell-sizing
worksheet—Figure 3 in IEEE Std 485.

Since different types of batteries, and similar batteries by different manufacturers, have different plate designs
they also have different discharge curves. Thus it is important to calculate this step separately for each different
type of battery or manufacturer.

You can calculate the amperes per positive plate for a particular battery from the vendor battery discharge curve
or table of discharge rates for specific time and divide it by the number of positive plates. If the manufacturer
data provides the total number of plates, the number of positive plates can be calculated by the following:

( total plates −1)

= positive plates (C.1)
2

discharge rate
RTT = (C.2)
positive plates
where

RTT is the amperes per positive plate at time T

Typical battery discharge rate in amperes

to 1.75 VPC at 25 °C (77 °F)
Minutes
Total plates Positive plates 1 720
7 3 330 24.0
11 5 550 39.0

The discharge rate above shows the calculations of RT for Vendor B at 1 minute and 720 minute rates.

Continue this for other manufacturers to fill out table of amperes per positive plate (RT).

Minutes Vendor A Vendor B Vendor C

RT RT RT
1 63 110 47
720 7.3 8 4.8

Complete the battery cell–sizing worksheet from the vendor’s discharge curves that can be found in their
literature (see Figure C.3).

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Source: Figure 3 from IEEE Std 485.

Figure C.3—Completing the battery cell–sizing worksheet

Multiply the uncorrected values by the temperature correction factor, design margin, and aging factors to
calculate the number of positive plates and the total number of plates. Then, round the calculated number of
positive plates up to the next whole number.

Match the number of plates to the battery manufacturer’s size to obtain the 8-hour AH rating of the battery of
each type.

Manufacturer A = 456 AH

Manufacturer B = 440 AH

Manufacturer C = no match for 6 V block type battery

Compare the cost of Manufacturer A and Manufacturer B battery sizes to select the most economical battery
that is properly sized for this application.

Considerations for battery sizing:

Determining the worst case tripping current

Per IEEE Std 485 battery sizing guidelines, the time increment of the duty cycle in battery sizing should be
in one minute increments. Thus when determining the worst case scenario, the designer should look at the
sequence of events that would occur in the last minute and select the one that sums up to the highest value. For
example if there is a fault on transformer T1, the sequence of operations would be: trip breakers 5B2, 5B3,
and BT1. After BT1 is tripped, it would be likely that there would be an auto-restoration function to restore
the 34.5 kV bus via the bus tie breaker. This would likely occur in the same minute that the fault occurred and
tripped the breakers on the bus. However, all of the original tripping would have occurred prior to the reclosing
function. Therefore, the designer should look at the tripping load and the resulting restoration load and select
the higher value for the worse case tripping during the last minute. A more likely scenario would be for a
breaker-failure condition with motor operators rather than breakers. The motor operators would likely still be
operating when the breaker-fail function tripped more devices. In order to fully understand the sequence of
events, it is important to review a relay and metering diagram that shows what devices would trip for various
faults on the system. It is also important to include auxiliary relays, such as lock out relays if they are used.
For example, a bus differential relay may operate a lock out relay to trip all the equipment on the bus. The load

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of the lockout should be included in the calculation. The metering and relay diagram would also show all the
devices that would be tripped, reclosing schemes, and breaker-fail schemes.

Device load should be taken from the manufacturer’s nameplate data, for example breaker trip coil ratings.
For motor operators, the locked rotor value should be used in order to accommodate the worst case scenario of
operating a switch that may be iced up, or that the blade may be corroded and stuck in the jaws due to lack of
frequent operation.

Battery charging sizing

From 5.5.2, the following formula is used to determine the required dc output of the battery charger.

 A  
I =   e + I C  (d )(k ) (C.3)

 t  

where

I is the calculated battery charger output, dc amperes

A is the A-hours to be replaced
t is the time in which the battery should be recharged
e is the recharge factor
IC is the continuous dc load current
d is the design margin factor
k is the altitude correction factor (charger manufacturer data)

From the duty cycle shown above:

1 
A = 16.5 A×12h + 79.5 A× hours = 199.325 Ah removed
 60 

I C = 16.5 A

This example assumes the battery recharge time = 8 h

The recharge efficiency factor = 1.1

The design margin factor = 1.1

The estimate assumes the altitude is below 3300 ft and k = 1.0 (verify manufacturer data)

199.325 
I =  ×1.1 + 16.5×1.1×1 = 48.29
 8 

From manufacturer available sizes, select the closed size that is equal or greater than this value.

Suggested battery charger size = 50 A charger.

From the battery charger manufacturer data, verify the dc output breaker size to coordinate the cable size
between the charger and the dc system. For a 50 A battery charger, the dc breaker size is 70 A.

The cable should be sized to 125% of overload device. The cable to connect the charger to the dc system
should be sized to accommodate 87.5 A.

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From cable capacity tables select a 4 AWG copper conductor for this application.

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IEEE Guide For The Design of Low-Voltage Auxiliary Systems For Electric Power Substations

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IEEE Guide For The Design of Low-Voltage Auxiliary Systems For Electric Power Substations

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IEEE Guide for the Design of Low-

Voltage Auxiliary Systems for

IEEE Power and Energy Society

IEEE IEEE Std 1818™-2017

IEEE Guide for the Design of Low-

Approved 28 September 2017

IEEE-SA Standards Board

The Institute of Electrical and Electronics Engineers, Inc.

Copyright © 2017 by The Institute of Electrical and Electronics Engineers, Inc.

IEEE prohibits discrimination, harassment, and bullying.

Notice and Disclaimer of Liability Concerning the Use of IEEE Standards

Comments on standards should be submitted to the following address:

Secretary, IEEE-SA Standards Board

Laws and regulations

Hanna Abdallah, Co-Chair

Gary Beane Debra Longtin James Purcell

Hanna Abdallah James Houston Bansi Patel

Jean-Philippe Faure, Chair

Chuck Adams Thomas Koshy Robby Robson

Figure 1—Block diagram for typical substation ac auxiliary power�������������������������������������������������������������� 17

Figure 5—Single-phase transformer with phase-to-phase connections���������������������������������������������������������� 36

Figure 8—Grounded wye–grounded wye transformer connection���������������������������������������������������������������� 39

Figure 19—Secondary selective system with backup generator��������������������������������������������������������������������� 51

Figure 23—Battery with breaker disconnect and charger at dc panels����������������������������������������������������������� 68

Figure 24—Battery with fuse disconnect and charger at dc panels����������������������������������������������������������������� 68

Figure 26—Simplified parallel/transfer with two disconnects����������������������������������������������������������������������� 71

Figure 27—Simplified parallel/transfer with one disconnect������������������������������������������������������������������������� 71

Figure C.3—Completing the battery cell–sizing worksheet��������������������������������������������������������������������������� 91

Table 2—Typical kVA ratings for distribution transformers��������������������������������������������������������������������������� 31

Table 3—Distribution transformer short-circuit withstand capability������������������������������������������������������������ 33

Table 4—Transformer BIL ratings (IEEE Std C57.12.20 [B23])������������������������������������������������������������������� 34

pad-mounted transformer: An outdoor transformer utilized as part of an underground distribution system,

4. Design of substation ac auxiliary systems

Figure 1—Block diagram for typical substation ac auxiliary power

a) The design criteria for the station service.

4.2 Design criteria

4.2.2 System stability

4.2.3 Customer service and loss of revenue

4.2.4 Equipment protection

4.2.5 Design considerations

a) Location of ac equipment—indoor or outdoor

4.2.6 Selection of auxiliary system voltage

4.3 Station power source requirements

a) Power transformer tertiary

4.3.2 Power transformer tertiary

4.3.3 Substation bus

Figure 2—Possible SSVT locations

4.3.4 Distribution feeders

4.3.5 Standby generators

4.4 Load analysis

4.4.2 Load identification

a) Substation major equipment loads, including:

4.4.3 Equipment rating identification

4.4.4 Demand and load factors

maximum coincident system demand

average load over a designated time period

4.4.5 Load calculations

4.5 Conductor selection

Authorized licensed use limited to: Centro Universitário

type of work being performed.

HVAC system it is assumed that the load is

at 18:25:53 UTC from IEEE Xplore. Restrictions apply.

Authorized licensed use limited to: Centro Universitário

1ø and 3ø kVA totals 17.02 73.12

at 18:25:53 UTC from IEEE Xplore. Restrictions apply.

Figure 3—Conductor selection process flow chart

4.5.2 Conductor type

4.5.3 Cable insulation voltage rating

4.5.4 Cable insulation type

4.5.5 Cable temperature rating

4.5.7 Conductor size calculations

a) Required ampacity (initial conductor size selection)

4.5.7.2 Required ampacity (initial conductor size selection)

a) Resize the conductor (reduces voltage drop)

e) Consider a higher voltage distribution system and local step-down transformers

4.5.7.3 Temperature, burial depth, and bundling corrections

Figure 1—Block diagram for typical substation ac auxiliary power�� 17

Figure 5—Single-phase transformer with phase-to-phase connections�� 36

Figure 8—Grounded wye–grounded wye transformer connection�� 39

Figure 19—Secondary selective system with backup generator�� 51

Figure 23—Battery with breaker disconnect and charger at dc panels�� 68

Figure 24—Battery with fuse disconnect and charger at dc panels�� 68

Figure 26—Simplified parallel/transfer with two disconnects�� 71

Figure 27—Simplified parallel/transfer with one disconnect�� 71

Figure C.3—Completing the battery cell–sizing worksheet�� 91

Table 2—Typical kVA ratings for distribution transformers�� 31

Table 3—Distribution transformer short-circuit withstand capability�� 33

Table 4—Transformer BIL ratings (IEEE Std C57.12.20 [B23])�� 34