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Basics of power system design

Table of contents
System design
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Basic Principles. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Trends in Systems Design
. . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Goals of System Design. . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Designing a Distribution System. . . . . . . . . . . . . . . . . . . . . 6
Development of a System One-Line
. . . . . . . . . . . . . . . . . . . 6
Importance of the System One-Line . . . . . . . . . . . . . . . . . . 7
Standardized Drawing Symbols . . . . . . . . . . . . . . . . . . . . . . 10
Additional Drawings, Schedules and Specifications . . . . . 20
Power System Voltages. . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Voltage Classifications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Incoming Service Voltage. . . . . . . . . . . . . . . . . . . . . . . . . . 22
Incoming Service Considerations. . . . . . . . . . . . . . . . . . . . 23
Utilization Voltage Selection . . . . . . . . . . . . . . . . . . . . . . . . 24
Types of Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Types of Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Power System Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Systems Analysis
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
Short-Circuit Currents—General. . . . . . . . . . . . . . . . . . . . . 38
Fault Current Waveform Relationships. . . . . . . . . . . . . . . . 40
Fault Current Calculations. . . . . . . . . . . . . . . . . . . . . . . . . . 41
Fault Current Calculations for Specific Equipment—
Exact Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
Application Quick Check Table
. . . . . . . . . . . . . . . . . . . . . . . 45
Medium-Voltage Fuses—Fault Calculations. . . . . . . . . . . . 48
Low-Voltage Power Circuit Breakers—
Fault Calculations
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
Molded Case Breakers and Insulated Case
Circuit Breakers—Fault Calculations. . . . . . . . . . . . . . . . . . 50
Low-Voltage Circuit Breaker Interrupting
Derating Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
Short-Circuit Calculations . . . . . . . . . . . . . . . . . . . . . . . . . . 51
Determining X and R Values from
Transformer Loss Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Voltage Drop. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
System Protection Considerations. . . . . . . . . . . . . . . . . . . 59
Overcurrent Protection and Coordination. . . . . . . . . . . . . . 59
Grounding/Ground Fault Protection . . . . . . . . . . . . . . . . . 64
Grounding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
Typical Components of a Power System. . . . . . . . . . . . . . 76
Typical Power System Components. . . . . . . . . . . . . . . . . . . 76
Transformers. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79
Generators and Generator Systems . . . . . . . . . . . . . . . . . 88
Generator Short-Circuit Characteristics. . . . . . . . . . . . . . . 91
Generator Set Sizing and Ratings . . . . . . . . . . . . . . . . . . . 95
Generator Set Installation and Site Considerations. . . . . . 96
Capacitors and Power Factor . . . . . . . . . . . . . . . . . . . . . . . 97
Motor Power Factor Correction
. . . . . . . . . . . . . . . . . . . . . . 98
Typical Application by FacilityType. . . . . . . . . . . . . . . . . . 100
Healthcare Facilities
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100
Quick Connect Generator and Load Bank Capabilities. . . . 106
Power Quality. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 107
Power Quality Terms Technical Overview. . . . . . . . . . . . . . 107
Other Application Considerations
. . . . . . . . . . . . . . . . . . . 120
Seismic Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . 120
Reference Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
Codes and Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131
Suggested IEEE Designations for Suffix Letters . . . . . . . 136
Ampacities for Conductors Rated 0–2000 V
(Excerpted from NFPA 70-2014, 310.15). . . . . . . . . . . . . . 142

Basic Principles
The best distribution system is one that
will, cost-effectively and safely, supply
adequate electric service to both present
and future probable loads—this section
is intended to aid in selecting, designing
and installing such a system.
The function of the electric power
distribution system in a building or an
installation site is to receive power at
one or more supply points and to deliver
it to the lighting loads, motors and all
other electrically operated devices.The
importance of the distribution system
to the function of a building makes it
imperative that the best system be
designed and installed.
In order to design the best distribution
system, the system design engineer
must have information concerning the
loads and a knowledge of the types of
distribution systems that are applicable.
The various categories of buildings have
many specific design challenges, but
certain basic principles are common to
all. Such principles, if followed, will
provide a soundly executed design.
The basic principles or factors requiring
consideration during design of the power
distribution system include:
■ Functions of structure, present
and future
■ Life and flexibility of structure
■ Locations of service entrance and
distribution equipment, locations and
characteristics of loads, locations of
unit substations
■ Demand and diversity factors of loads
■ Sources of power; including normal,
standby and emergency
■ Continuity and quality of power
available and required
■ Energy efficiency and management
■ Distribution and utilization voltages
■ Busway and/or cable feeders
■ Distribution equipment and
motor control
■ Power and lighting panelboards
and motor control centers
■ Types of lighting systems
■ Installation methods
■ Power monitoring systems
■ Electric utility requirements
Trends in Systems Design
There are many new factors to consider in
the design of power distribution systems.
Federal and state legislation has been
introduced to reduce the output of carbon
emissions into the environment; the
intent being the reduction of their impact
on climate change. In order to address the
subsequent need for clean power, there
has been an accelerating trend toward
the incorporation of solar and other
sustainable energy sources into existing
and new building designs. Energy storage
systems (ESS) are now making renewable
energy a more viable option by helping
to stabilize power output during transient
dips or interruptions to power production.
Utility deregulation has also provided
financial incentives for building owners
and facility managers to participate in
peak demand load shaving programs.
These programs are intended to reduce
load on the utility grid in response to a
1 hour or 1 day ahead signal from the
utility.The users shedding or cycling of
non
essential loads is generally initiated
by a building management system (BMS)
in conjunction with power monitoring
and lighting control equipment.To
ensure uninterrupted operation of key
customer loads, incorporation of other
types of distributed generation such as
fuel cells and diesel or natural gas fired
reciprocating generator sets may be
desired or required.
Hospital complexes and college campuses
are increasingly adopting the design of
central utilities plants (CUPs). In lieu of a
separate boiler plant, cogeneration is used
to produce electricity and the wasted heat
from the combustion process is recaptured
to provide hot water for the campus.
Large cogeneration plants (3 MW and
above) often include large turbines or
reciprocating engines as their prime
movers for the generators.To enhance
service continuity, these generators use a
continuous source of natural gas as their
fuel supply. Cogen plants generally have
higher power conver
sion efficiencies and
produce lower carbon emissions.
The growing impact of adverse weather
conditions such as hurricanes and
flooding is now driving incoming service
and distribution equipment rooms to
be located out of basements and other
low lying areas. Regions prone to these
storms often experience downed utility
power lines and/or flooded manholes,
resulting in a loss of power to thousands
of customers. In order to quickly return
power to these facilities, additional
on-site backup generation is being
included in both new designs and as
upgrades to existing sites.
This trend for resiliency is increasing
among grocery stores, large chain stores
and other distribution facilities requiring
refrigeration to keep products from
spoiling as well as large multifamily
dwelling complexes in low lying flood
plain areas.
Building costs continue to rise and
rentable or usable space is now at a
premium.To solve both problems, many
design and construction firms are looking
at off-site prefabrication of key elements.
Forest City Ratner’s 32-story residential
complex adjacent to Barclay’s Arena in
Brooklyn, NY, advanced the modular
concept with individual building sections
constructed at a factory off-site and
erected by crane into place. Resiliency
from storms and floods involving the
relocation of electrical equipment out
of flood prone areas is costly, time
consuming and takes up precious floor
space in a building. Electro Centers or
Integrated Power Assemblies (IPA) can
be fitted out with a variety of electrical
distribution equipment and shipped to
the site in preassembled modules for
mounting on elevated foundation piles,
building setbacks or rooftops.
Finally, the need to have qualified
building electrical operators,
maintenance departments and facility
engineers has collided with growing
expectations for improved productivity
and reduced overall operating costs.The
increasing proliferation of smart devices
and enhanced connectivity with power
distribution equipment has expanded
facility owner’s options.These capabilities
allow for automated communication of
vital power system information including
energy data, equipment wellness and
predictive diagnostics, and electrical
equipment control.
System design
2 EATON Basics of power system design Eaton.com/consultants

The future “Internet ofThings” promises
to add millions of more sensors and
other devices to collect operational
data and send it through the Internet
to “cloud-based” comput
ing services.
There, information from multiple
devices can be analyzed and actions
can be taken to optimize performance
and reduce downtime.
Various sections of this guide cover
the application and selection of such
systems and components that may be
incorporated into the power equipment
being designed.
Goals of System Design
When considering the design of an
electrical distribution system for a given
customer and facility, the electrical
engineer must consider alternate design
approaches that best fit the following
overall goals.
1. Safety: The No. 1 goal is to design
a power system that will not present
any electrical hazard to the people who
use the facility, and/or the utilization
equipment fed from the electrical
system. It is also important to design
a system that is inherently safe for
the people who are responsible for
electrical equipment maintenance
and upkeep.
The Occupational Safety and Health
Administration (OSHA) is a federal
agency whose “mission is to assure
safe and healthful workplaces by
setting and enforcing standards, and
by providing training, outreach,
education and assistance.
” OSHA’s
electrical requirements are covered
under several categories, the broadest
being 1910 Subpart 10 Electrical
including references to the National
Fire Protection Agency (NFPA) 70
and 70E.
To address the concerns for personnel
safety from arc flash hazards, the 2014
Edition of the NEC as well as the 2015
Edition of NFPA 70E have enhanced the
requirements for personnel protection
when working on or near live equip
ment.The 2014 NEC introduces new
arc flash labeling requirements.
Additionally, Article 240.87 offers a
number of prescriptive alternative
methods for arc flash energy
reduction; one of which must be
provided, for speeding up the clearing
time of a circuit breaker that can be set
to trip at 1200 A or above. Eaton’s
Arcflash Reduction Maintenance
SystemE is avail
able in various
electronic trip units for molded case
and power circuit breakers to improve
clear
ing time and reduce the incident
energy level.
The National Electrical CodeT (NECT),
NFPAT 70 and NFPA 70E, as well
as local electrical codes, provide
minimum standards and requirements
in the area of wiring design and
protection, wiring methods and
materials, as well as equipment for
general use with the overall goal of
providing safe electrical distribution
systems and equipment.
The NEC also covers minimum
requirements for special occupan
cies
including hazardous locations and
special use type facilities such as
healthcare facilities, places of
assembly, theaters and the like, as
well as the equipment and systems
located in these facilities. Special
equipment and special conditions
such as emergency systems, standby
systems and communication systems
are also covered in the code.
2. Regulatory Requirements: Over the
course of the past century, electrical
product safety and performance
standards have been developed in
cooperation between various
agencies such as: American National
Standards Institute (ANSI) as well as
industry groups such as the Institute
of Electrical and Electronics Engineers
(IEEE) and the National Electrical
Manufacturers Association (NEMA).
These are often referenced together
with specific test standards developed
in conjunction with Underwriters
Laboratories (UL). As an example,
low-voltage switchgear falls under
ANSI C37.20.1 and is tested in
compliance with UL 1558.
The 2014 National Electrical Code
(NEC) Article 110.2 states that: “The
conductors and equipment required
or permitted by this Code shall be
acceptable only if approved.
”The
informational note references the
definitions in Article 100 for Approved,
Identified, Labeled and Listed.
OSHA has qualified a number of
Nationally RecognizedTesting
Laboratories (NRTL) to demon
strate
and certify “product conformance to
the applicable product safety test
standards.
” Among the oldest and
most respected of these electrical
product testing organizations is
Underwriters Laboratories (UL),
which was founded in 1894.
It is the responsibility of the design
engineer to be familiar with the NFPA
and NEC code requirements as well
as the customer’s facility, process
and operating procedures in order
to design a system that protects
personnel from live electri
cal
conductors and uses adequate circuit
protective devices that will selectively
isolate overloaded or faulted circuits
or equipment as quickly as possible.
In addition to NFPA and NEC
guidelines, the design professional
must also consider International
Building Code (IBC) and local
municipality, state and federal
requirements.The United States
Department of Energy, for example,
mandates minimum efficiencies for
transformers and other equipment.
Many of these regulatory codes
reference ANSI/ASHRAE/IES Standard
90.1-2013 “Energy Standard for
Buildings Except Low-Rise Residential
Buildings”
. Section 8.1 covers power
and includes receptacle load control.
Subsection 8.4.3 is titled Electrical
Energy Monitoring and covers
metering and monitoring systems that
notify building tenants and engineers
of the increased use of electric power.
Section 9.1 covers lighting and lighting
control system requirements.
Other building standards organiza
tions that offer certifications, such
as the U.S. Green Building Council’s
LEED Accreditation, require measure
ment and verification that actual
energy and water use meet initial
building design criteria.The U.S.
Green Building Council has teamed
with ANSI and ASHRAE to produce
ANSI/ASHRAE/USGBC/IES Standard
189.1-2014 titled, “Standard for the
Design of High-Performance Green
Build
ings Except Low Rise Buildings”
.
3
EATON Basics of power system design
Eaton.com/consultants
System design

Finally, utility incoming service
standards for customer intercon
nects
are key elements in the selection of
both the incoming service voltage and
the protection required for this
equipment. Knowledge of these
standards is particularly important
when incorporating renewable energy
or distributed generation resources
into a design. a
a Contact Eaton’s local application engineer for
assistance with design compliance.
3. Minimum Initial Investment:
The owner’s overall budget for first
cost purchase and installation of the
electrical distribution system and
electrical utilization equipment will
be a key factor in determining which
of various alternate system designs
are to be selected.When trying to
minimize initial investment for
electrical equipment, consideration
should be given to the total cost of
the installation.This includes reducing
on-site assembly time and cost by
prefabricating various electrical
components into a single deliverable
system and reducing floor space and
possible extra cooling requirements.
4. Maximum Service Continuity:
The degree of service continuity and
reliability needed will vary depending
on the type and use of the facility as
well as the loads or processes being
supplied by the electrical distribution
system. For example, for a smaller
commercial office building, a power
outage of considerable time, say
several hours, may be acceptable,
whereas in a larger commercial
building or industrial plant only a few
minutes may be acceptable. In other
facilities such as hospitals, many
critical loads permit a maximum of
10 seconds outage and certain loads
cannot tolerate a loss of power for
even a few cycles.
Typically, service continuity and
reliability can be increased by:
a. Supplying multiple utility power
sources or services.
b. Supplying multiple connection
paths to the loads served.
c. Using short-time rated power
circuit breakers.
d. Providing alternate customer-
owned power sources such as
generators or batteries supplying
Energy Storage Systems or
uninterruptable power supplies.
e. Selecting the highest quality
elec
trical equipment and
conductors.
f. Using the best installation
methods, including proper
system grounding design.
g. Designing appropriate system
alarms, monitoring and
diagnostics.
h. Selecting preventative mainte
nance systems or equipment to
alarm before an outage occurs.
5. Maximum Flexibility and
Expandability: In many industrial
manufacturing plants, electrical
utilization loads are periodically
relocated or changed requiring
changes in the electrical distribu
tion
system. Consideration of the layout
and design of the electrical distribution
system to accommodate these
changes must be considered. For
example, pro
viding many smaller
transformers or loadcenters associated
with a given area or specific groups
of machinery may lend more flexibility
for future changes than one large
transformer; the use of plug-in
busways to feed selected equip
ment in
lieu of conduit and wire may facilitate
future revised equipment layouts.
In addition, consideration must be
given to future building expansion,
and/or increased load require
ments
due to added utilization equipment
when designing the electrical
distribution system. In many cases
considering transformers with
increased capacity or fan cooling to
serve unexpected loads as well as
including spare additional protective
devices and/or provision for future
addition of these devices may be
desirable. Also to be considered
is increasing appropriate circuit
capacities to assure future capacity
for growth.
Power monitoring communication
systems connected to electronic
metering can provide the trending
and historical data necessary to
ensure future capacity for growth.
6. Maximum Electrical Efficiency
(Minimum Operating Costs): Electrical
efficiency can generally be maximized
by designing systems that minimize
the losses in conductors, transformers
and utilization equipment. Proper
voltage level selection plays a key
factor in this area and will be
discussed later.
Selecting equipment, such as
transformers, with lower operating
losses, generally means higher
first cost and increased floor space
requirements.Thus there is a balance
to be considered between the owner’s
long-term utility cost for the losses in
the transformer or other equipment
versus the initial budget and cost
of money.
7. Minimum Maintenance Cost:
Usually the simpler the electrical
system design and the simpler the
electrical equipment, the lower
the associated maintenance costs
and operator errors. As electrical
systems and equipment become
more complicated to provide greater
service continuity or flexibility, the
maintenance costs and chance for
operator error increases.
When designing complex systems, the
engineer should consider add
ing an
alternate power circuit to take electrical
equipment (requiring periodic
maintenance) out of service without
dropping essential loads. Use of
drawout type protec
tive devices such
as breakers and combination starters
can also minimize maintenance cost
and out-of-service time. Utilizing
sealed equipment in lieu of ventilated
equipment may minimize mainte
nance
costs and out-of-service time as well.
System design

8. Maximum Power Quality: The power
input requirements of all utilization
equipment has to be considered,
including the acceptable operating
range of the equipment. Consequently,
the electrical distribution system has
to be designed to meet these needs.
For example, what is the required
input voltage, current, power factor
requirement? Consideration to
whether the loads are affected by
harmonics (multiples of the basic 60 Hz
sine wave) or generate harmonics
must be taken into account as well as
transient voltage phenomena.
The above goals are interrelated and in
some ways contradictory. As more
redundancy is added to the electrical
system design along with the best quality
equipment to maximize service continuity,
flexibility and expandability, and power
quality, the more initial investment and
maintenance are increased.Thus, the
designer must weigh each factor based on
the type of facility, the loads to be served,
the owner’s past experience and criteria.
Summary
It is to be expected that the engineer will
never have complete load infor
mation
available when the system is designed.
The engineer will have to expand the
information made avail
able to him or
her on the basis of experience with
similar projects.
Of course, it is desirable that the engi
neer
has as much definite information as
possible concerning the function,
requirements, and characteristics of
the utilization devices.
The engineer should know whether
cer
tain loads function separately or
together as a unit, the magnitude of the
demand of the loads viewed separately
and as units, the rated voltage and
frequency of the devices, their physical
location with respect to each other
and with respect to the source and
the probability and possibility of the
relocation of load devices and addition
of loads in the future.
Coupled with this information, a
knowledge of the major types of electric
power distribution systems equips the
engineers to arrive at the best system
design for the particular building.
It is beyond the scope of this guide to
present a detailed discussion of loads that
might be found in each of several types of
buildings. Assuming that the design
engineer has assembled the necessary
load data, the following pages discuss
some of the various types of electrical
distribution systems that can be used.
This revision of this Design Guide
includes updates based on changes to the
2014 National Electrical Code (NEC), 2015
NFPA 99 and other pertinent ANSI/IEEE
Standards. It also includes a significant
revision in the flow of the material
presented. Additional new information
has been added to the document in
recognition that users will be at differing
levels of experience. For those engineers
either beginning their careers or early
into them, guidance is provided for the
design and development of Power
Systems One-Line Diagrams.
An expanded section on voltage
selection, including both service and
utilization voltages, has been added.This
narrative discusses consider
ations for
utility metering at medium and low
voltages. However, the description of
types of systems and the diagrams used
to explain the types of systems on the
following pages omit the location of
utility revenue metering equipment for
clarity. Further pages address short-circuit
calculations, coordination, overcurrent
protection, voltage drop, ground fault
protection, motor protection and
application considerations for typical
equipment utilized in a power system.
5
System design

Development of a
System One-Line
Power system designers communicate
their design requirements through a
combination of drawings, schedules
and specifications.
One of the key tools in developing and
documenting an electrical power system is
the System One-Line (also called a Single
Line Diagram).This drawing starts with the
incoming power source from the utility
service and/or on-site generation and their
associated distribution equipment. It then
follows the power flow down through the
various conductors as well as any voltage
transformations to feed distribution
equipment buses for the key loads served.
Initially, the System One-Line provides
a framework for the incorporation of
different types of required information
such as:
1. Incoming service voltage and
utilization voltages required.
2. Electrical distribution equipment
ampacity and short-circuit ratings.
3. Overcurrent/short-circuit protection.
4. Conductor types (i.e., cable or busway)
and sizes. (Cable lengths may also be
estimated to determine voltage drop
and any upsizing necessary.)
5. Transformer kVA sizes, ampacity,
impedance and voltages.
6. Generator kW sizes and voltages.
7. Motor loads and voltages.
8. Other power quality equipment such
as surge protection devices, power
factor correction capacitors or
uninterruptible power supplies.
A System One-Line may start out in the
Design Development Phase of a project
as a basic concept. Other information can
be added throughout the design cycle. It
can then be copied and modified to create
a number of alternate drawings showing
different system approaches.This permits
the power system designer to analyze
the impact of each arrangement on cost,
redundancy and projected physical
space requirements.
The System One-Line takes on
increasingly more importance as the
project evolves through the Design
Development Phase. Input from the
other architectural, mechanical,
plumbing, electrical and fire protection
professionals on the design team helps
to better define the various equipment
loads and develop the power system
one-line to accommodate them.
At some point in this stage, a construction
manager may be brought in to assist
the owner and architect in assessing
the design’s constructability.Various
improve
ments that could increase energy
efficiency and/or reduce construction
costs are often suggested.
Moving toward the end of the Design
Development Phase, the One-Line and
associated drawings such as equipment
room elevations and floorplans are
provided to the client for their review and
approval. At this point, both the client’s
comments and the construction manager’s
additional inputs are integrated into the
design.This final set of approved design
development drawings, which include the
Power System One-Line, are used as the
basis for the development of the
construction drawings.
Moving into the Construction Document
Phase of a project, alterations are made
to the Design Development Electrical
Drawing set. At some level of completion
(typically 90%), these drawings are sent
out to finalize budgetary estimates and
narrow the field of contractors to be
included in the selection process. During
the push from 90% to 100% completion
of the construction documents, the
construction manager or the general
contractor is asked to provide a
Guaranteed Maximum Price (GMP).
During the Bid or Negotiation Phase of a
project, Bid Document Drawing Sets are
sent out to a list of potential contractors.
Estimators at these contractors review
the Bid Package and tabulate the value
of the electrical equipment, conduit and
cable costs plus manpower necessary to
build out the project.
Designing a Distribution System

Importance of the
System One-Line
It is important for the power system
designer to ensure the System One-Line
and other design documents contain as
much information as possible, to assure
that bidding contractors include all the
correct requirements in their pricing.
Errors and/or omissions on the
construction contract documents can
lead to expensive contractor change
orders and project cost overruns after
the contract is awarded.
During the various stages of a project
design, changes are made often to reflect
the client’s preferences and budget.
As the design process continues,
coordination between the MEP
(Mechanical, Electrical and Plumbing)
design disciplines become more critical.
If the design professionals are not
synchronized on these changes, a
previously unanticipated piece of
equipment may be chosen or added
to the project. As an example, where an
engineer had previously allocated a 250 A
circuit breaker to feed the anticipated
load, as a result of an equipment change,
a 400 A breaker must now be provided.
The impact of this change can result in a
contractor bid that does not include both
the correct breaker AND the correct cable
sizes to feed the larger load.
Oftentimes, requirements such as
electronic trip units or their protective
functions such as Long, Short,
Instantaneous and Ground (LSIG) or
Ground Alarm (LSIA) are not indicated on
the One-Line.This can lead to equipment
being supplied with standard thermal-
magnetic trip units that may lack the
setting capabilities to achieve the proper
selective coordination required.
Other requirements such as: Zone
Selective Interlocking of breakers, 100%
rated breakers, drawout or electrically
operated breakers and key interlock
schemes can be overlooked if they are
not documented on a One-Line and
coordinated in the specifications.
Finally, electrical equipment is subject to
environmental issues such as wet areas
and may require specific enclosure types
to be provided. Nomenclature on the
One-Line, such as 3R or 4X, adjacent to
these items can clarify what enclosure
type is to be provided.
The proper use of notes on the One-Line
can further define the requirements. As an
example, a note can be added clarifying
that all NEMA 4X rated enclosures are to
be of 316 stainless steel versus the less
expensive 304 Grade.The difference
between these two grades is critical as
316 Stainless is far more resistant to
saltwater, sulfuric acid and chlorides,
and is preferred in several applications
including pharma
ceutical manufacturing
and wastewater treatment plants.
Figure 1. Example of Notes on One-Line
The System One-Line is the common map
that all the other project documents must
reference and be checked against.To
ensure consistency and avoid conflicts
after a project is awarded to a contractor,
distribution panelboard schedules and
specifica
tions also need to include the
correct information about details such
as the enclosure type required.
For these reasons, it is critical that
the engineer be vigilant and take a
proactive role in identifying changes
and updating the System One-Line
and associated design documents
appropriately and consistently.
The One-Line diagram on the following
pages is an example developed for
illustrative purposes only and was
developed to show a wide range of
product applications.This diagram will
be referenced throughout the remainder
of this section.
The references to external drawings is
for illustration only and not referencing
actual documents within this section
or elsewhere.
150AF 150AF
150AF 150AF
UNITS
FOP-1
15AT 90AT
CH-1
15AT 90AT
HEAT
HRU-1,2,3,4
PUMP
FUEL HVAC
AHU-1,2,3,4
2
COMFORT
COOLING
4X
REJ.
3Ø, 3W, 65 KAIC
480 V, 600 A,
DSB-DF2A
7

Figure 2. Power System One-Line (Continued on Next Page)
13.8 kV, 3Ø, + GND 60Hz
UTILITY FEEDER #1 UTILITY
METERING
(2) UTILITY PT's
14,400:120V
(4) GROUND STUDS (3-Ø, 1-GND)
(6) LIVE LINE INDICATORS (2/Ø) 10A
CT's (2)
500:5
UTILITY
52
C/S
M1-L
50/51N 50/51
M1
(1) (3)
(4) GROUND STUDS
120:1
52-M1
1200A
59
M1
27
M1
(1)
86
T1
(1)
87
T1
71
T1
49
T1
63
T1
13.8kV, 1200A,
50 kA SYM S.C.
(15kV - 95KV BIL RATED)
M1
86
N.C.
M1
(1)
M1-00
SPLICE IN PROPERTY LINE MANHOLE M1
M1-00
2000A BUSWAY
(3-Ø, 1-GND)
H1 H3
H2
X
X
X
X0
1
3
2
51G
T1
(1)
14,400:120V
(3)
(3) SINGLE PHASE POTHEADS (1/Ø)
TRANSFORMER "T1"
PRIMARY UNIT SUBSTATION STYLE
13.8KV DELTA PRIMARY - 95KV BIL
4.16/2.4KV GROUNDEDWYE - 60KV BIL
EATON "PEAK" 55C/65C/75C
7500/8400/9156 KVA KNAN
9375/10500/11445 KVA KNAF
FR-3 FLUID FILLED, 6.5% MINIMUM Z
WITH SURGE + LIGHTNING ARRESTERS
(3)
G R A
PXM6000
METER
(1)
TRIP M1
TRIP S1
TRIP M1
TRIP S1
TRIP M1
TRIP S1
(3)
(3)
52
C/S
S1-L
(3) 2000:5
STD (C200)
51
S1
(3)
52-S1
2000A
S1
86
N.C.
STD (C200)
(3) 2000:5
G R A
(1)
TRIP S1
52
C/S
F1-L
(3) 600:5
STD (C100)
50/51
F1
(3)
52-F1
1200A
F1
86
N.C.
G R A
(3) 600:5 MR
Set at 400:5
(1)
TRIP F1
86
B1
(1)
87
B1
(3)
TRIP S1
TRIP F1
TRIP F2
TRIP F3
4200V:
(3) PT'S
(3) 2000:5
STD (C200)
(3) 2000:5
STD (C200)
(1) 600:5
HI (C200)
STD (C100)
(3) 800:5
(3) 800:5
STD (C100)
(3) 600:5 MR
Set at 350:5
(4) GROUND STUDS
(3-Ø, 1-GND)
(4) GROUND STUDS
(3-Ø, 1-GND)
52
C/S
F2-L
(3) 600:5
STD (C100)
52-F2
1200
F2
86
N.C.
G R A
(3) 600:5 MR
Set at 300:5
(1)
TRIP F2
(3) 2000:5
STD (C200)
52
C/S
F3-L
(3) 600:5
STD (C100)
50/51
F3
52-F3
1200
F3
86
N.C.
G R A
(3) 600:5 MR
Set at 600:5
(1)
TRIP F3
(3) 2000:5
STD (C200)
M1-02
M1-02
(3)
ETR-5000-T1
(1)
EDR-5000-M1
EDR
3000-S1
50/51N
F1
(1)
50/51
F2
(3)
EDR
3000-F2
50/51N
F2
(1)
50/51N
F3
EDR
3000-F3
(1)
(3)
M1-03
N.O.
A
RESIDENCE
HALL A
P=104A S=2082A
P
AL
1000kVA
200E
A
P=139A S=1203A
P
AL
A
P=104A S=2082A
P
AL
1500kVA
300E
A
P=208A S=1804A
P
AL
4.16 kV, 3Ø, 60Hz
FROM PSG-2A (SEE DWG E102)
(SEE DWG E103)
N.C.
N.O.
N.C.
N.O.
N.C.
N.O.
N.C.
M1A LO
S1A LO
F1A LO F2A LO
F3A LO
RESIDENCE
HALL B
(SEE DWG E105)
E SWITCH
400A
ISOLATION
(3)
M
CHILLER #1
CUP
(SEE DWG E107)
M1-04
MV-VFD
SC9000EP
24 PULSE
INTEGRAL
INVERTER
DC TO AC
XFMR
DRAW-OUT
120V
M. H
1
M. H
2
M. H
3
M. H
4
M. H
5
M. H
6
M. H
7
M. H
8
1
1
USG-1A
PSG-1A
P/FA=479A
S/FA=1589A
RHAP-F3A
DFP-F3A
RHBP-F3A
RBP-F3A
CONVERTER
AC TO DC
CONTACTOR
VFD-F2A
EDR
3000-F1
35:1
(3) PT'S
EBR
3000
-B1
CU
LO
F3B
LO
LO
F3D
LO
2000 AF
1800 AT
E.O. "RBS-F3A"
LSG
(3) 2000:5
480V:120V
PT'S
MAIN CB
(3)
250KA
/Ø.SPD
BUSWAY RISER
(SEE DWG E106)
DINING
FACILITY
(SEE DWG E104)
TS
TS
TS
TS
TS
SB SB
TS
SB
SB TS SB
SB
(4) GROUND STUDS
(3-Ø, 1-GND)
SB
SB
(4) GROUND STUDS
(3-Ø, 1-GND)
SB
SB
TS
TS
TS
TS
TS
SB
4 6
PXM6000
METER
PXM6000
METER
PXM6000
METER
PXM6000
METER
"POINT A" 11.65KA SCA
AVAILABLE FROM UTILITY
"POINT B"T1 - 11.32KA
SCAWITHOUT MOTOR SCA,
CABLE % ZTOT1 &
BUSWAY % Z
"POINT D" - 40,400 SCA
WITH UNLIMITED PRIMARY SCA
& 50% MOTOR CONTRIBUTION
SEE XFMRTABLE 1.6-7 FOR
T2 ESTIMATING PURPOSES.
5.75% Z
4.16kV-480/277V
5.75% Z
4.16kV-480/277V
"POINT C" F3A -
11.32KA SCA
WITHOUT MOTOR
SCA & CABLE ZTO
T1 &T2-RHAP
T2-RHAP-F3A
T3-DFP-F3A
T4-RHBP-F3A
T5-RBP-F3A
VFI-2A
600A
VFI-3A
600A
SELECTOR SWITCH
W/SURGE+LIGHTNING
ARRESTERS
750kVA FR3VFI PADMOUNT
55/65C 5.75% Z
4.16kV-60KV BIL
208/120V-20KV BIL
SELECTOR SWITCH
W/SURGE+LIGHTNING
ARRESTERS
750kVA FR3VFI PADMOUNT
55/65C 5.75% Z
4.16kV-60KV BIL
208/120V-20KV BIL
M
"BUS A" 4.16KV,
2000A, 60KV BIL,
40KA SC RATED

Figure 2. Power System One-Line (Continued)
MAIN SWGR. BUS "A" 85KA, 480/277V, 4000A, 3-PH, 4W
02A
600 AT
800AF
2000AT
2000AF
FDR
"G"
G
ENGINE
DIESEL
PORTABLE
LOAD BANK
2000AF
2000AT
4000 AF
4000 AT
E.O.
"GB"
"MB-F1A"
2
Provide M1 Electrical InterlockWith S1 Breaker. M1 Cannot Close if S1 is
Open. S1 Cannot Close Until M1 is Closed. Include Key Interlocks as Shown.
LSG
LSIG
02B
600 AT
800AF
LSIG
"DF1A" "DF2A"
02C
1600 AT
1600AF
LSIG
"DF3A"
02D
"DF4A"
03A
"DF9A"
03B
800 AT
800AF
LSIG
"DF6A"
03C
400 AT
800AF
LSIG
"DF7A"
03D
600 AT
800AF
LSIG
"DF8A"
04A
"DF5A"
04B
400 AT
800AF
LSIG
"DF1OA"
04C
500 AT
800AF
LSIG
"DF11A"
04D
500 AT
800AF
LSIG
"DF12A"
4000 AF
4000 AT
"LTA"
2
LSG
01D
01B
A
P
N.O.
LO
F1A
LO
N.C.
115C AA/FA
2500/3333kVA
XFMR "ST-F1A"
600A
M. H
10
M. H
9
P FA=461A
S FA=4000A
CLE
SECONDARY UNIT SUBSTATION "SUS-F1A"
1
2
150AF 150AF
150AF 150AF 150AF
HEAT
UNITS
HRU-1,2,3,4
PUMP
FUEL
FOP-1
GYCOL
PUMP
GCP-1
10
40AT
HVAC
AHU-1,2,3,4
2 4X
15AT 90AT
HEAT
HRU-5-9
COMFORT
COOLING
CH-1
4X
REJ.
100AT 90AT
UNITS
REJ.
3Ø, 3W, 65 KAIC
480V, 600A,
DSB-DF2A
SPARE SPACE 2X
480-208/120V
300KVA
BAT-A
300KVA
UPS1
PDU-1
SEE SCHEDULE PDU-1
42 Circuit
FOR CRITICAL LOADS
RP-DF8A
SEE SCHEDULE RP-DF8A
FOR LOADS
480-208/120V
300KVA
SPARE
SPARE
IFS-DF7A
SEE SCHEDULE IFS-DF7AP & DF7AS
225A
FOR NORMAL & CONTROLLED LOADS
4.16KV-480/277V
150A
CWP-1
96FLA
75
SIZE4
3Ø, 3W, 65 KAIC
480V, 1600A,
MCC-DF3A
1600A
MLO
(SEE DWG E108)
E.O. E.O. E.O. E.O. E.O.
E.O. E.O. E.O. E.O. E.O. E.O.
FVNR
150A
75
SIZE4
FVNR
400A
CWP-4
96FLA
75
SIZE5
FVNR
400A
CHWP-1
180FLA
150
SIZE5
FVNR
CHWP-2
180FLA
150A
CT-1
96FLA
75
SIZE4
FVNR
150A
CT-2
96FLA
75
SIZE4
FVNR
150A
CT-3
96FLA
75
SIZE4
FVNR
150
150A
SIZE4
FVNR
CWP-3
96FLA
75
150A
SIZE4
FVNR
CWP-2
96FLA
150A
CT-4
96FLA
75
SIZE4
FVNR
150A
SA-1
96FLA
75
SIZE4
FVNR
150A
EF-1
96FLA
75
SIZE4
FVNR
400A
FR10
NCHWP-1
240FLA
200
PULSE
261A
SSRV SSRV
CUP-F1A
P=361A
S=833A
208/120V, 1200A,
3Ø, 4W, 65 KAIC
P=361A
S=833A
208/120V, 225A,
3Ø, 4W, 10 KAIC
PP-DF6A
SEE SCHEDULE PP-DF6A
FOR LOADS
480/277V, 800A,
3Ø, 4W, 65 KAIC
225AF 400AF
175AT 250AT
3Ø, 4W, 65 KAIC
480V, 1600A,
DSB-DF4A
1600AF
1600AT
SPARE SPACE 2X
XFMR-DF8A
XFMR-UPS1
E.O.
3
E.O.
LO LO LO
MGTA
LSG
N.C. N.O. N.O.
(3) 4000:5
480V:
(3) PT'S
120V
Provide MB-F1A Key InterlockWith Generator Breaker "GB" andTie Breaker
"LTA". Only the Single "MGTA" Key Can be Used to Close Any of these Breakers.
3
Provide Priority Load Shed Controls for Feeder Breakers in SUS-F1A Switchgear.
Provide InterfaceWith Generator Breaker "GB" to Enable OperationWhen Non-
Priority Loads have Been Shed.
4
Provide All Magnum Breakers in SUS-F1A & RBS-F3A SwitchgearWith DT1150+
Trip Units Including Zone Selective Interlocking (ZSI) and Arc Flash Reduction
Maintenance System (ARMS) in Compliance with Article 240.87 of the 2014 NEC.
6
Wire All DT1150+Trip Units Communications Ports to an Ethernet GatewayWith
BACnet IP Connectivity. BMSVendorWill Provide FieldWiring and Integrate Into
BMS System on a Separate Contract.
SEE SCHEDULE DSB-DF4A
FOR LOADS
TOUCH
SCREEN
5
Provide RemoteTouchscreen PanelWith "Switchgear Dashboard Interface" to
Monitor OperationalVariables and Enable Arc Flash Reduction Maintenance Mode.
DRAWING NOTES
5
EG
ETHERNET
GATEWAY
TO DT1150
TRIP UNITS
BACNET IP
TO BMS
4.16 kV, 3Ø, 60Hz
4000A BUSWAYTO
TIE CB "LTB" IN
"SUS-F1B"
CU
MAIN CB TIE CB
18
VFD
P=90A
S=208A
150A
480/277V 225A
3Ø, 4W, 65KA
POW-R-COMMAND
LIGHTING CONTROL
"DF7AP"
POW-R-COMMAND
RECEPTACLE CONTROL
480-
75KVA
XFMR-DF7A
208/120V
225A
SS0L
SS0L
SS0L
SS0L SS0L SS0L SS0L
PXM6000
METER
120KA/Ø
SPD
120KA/Ø
SPD
120KA/Ø
SPD
250KA/Ø
SPD
2S2W
3R
6 POLE
3R
6 POLE
3R
6 POLE
SS0L
2S2W
SS0L
2S2W
3R
6 POLE
SS0L
2S2W
Z=5.75%
800AF
800AT
600AF
600AT
400AF
400AT
1200AF
1000AT
400AF
400AT
SPARE
RIB
MIS
BIB
Eaton 9395 UPS
600AF
500AT
400AF
400AT
208/120V, 3Ø, 4W
CDP-A
42 Circuit
CDP-B
120KA/Ø
SPD
480V-3Ø
3W,65kA
DC-DS-A
480V, 600A,
3Ø, 3W, 65 KAIC
ATS-A
(SEE DWG E109)
FROM GEN A
1600 AT
1600AF
LSIG
ATC-900
TRANSFER
CONTROL
800AF
800AT
600AF
600AT
400AF
250AT
225AF
200AT
400AF
250AT
1600 AT
1600AF
LSIG
150AF
100AT
150AF
100AT
W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP
NORMAL
SOURCE
GENERATOR
SOURCE
FREEDOM FLASHGARD MCC
MBP
BYPASS
ISOLATION
ATS
SPARE
MAINTENANCE
ISOLATION
BYPASS
9

Standardized Drawing Symbols
In the North American market, the
American National Standards Institute
or ANSI for short, in cooperation with
the Institute of Electrical & Electronics
Engineers has developed standardized
drawing symbols and nomenclature to
represent common devices represented
on one-lines, control schematics and
other electrical drawings.The existing
Standard for North America (including
the Canadian Standard CSA Z99) is IEEE
315-1975 (Reaffirmed 1993)/ANSIY32.2.
This version recognizes that “Electrical
diagrams are a factor in international
trade: the use of one common symbol
language ensures a clear presentation
and economical diagram preparation
for a variety of users.
” Consequently,
the Standards Coordinating Committee
has added various International
Electrotechnical Commission (IEC)
symbols that are in use worldwide.
Item A4.1.1 of IEEE 315 defines a
Single-Line or (One-Line) Diagram as:
“A diagram which shows, by means of
single lines and graphic symbols, the
course of an electric circuit or system of
circuits and the component devices or
parts used therein.
”
Components such as those represent
ing
circuit protective devices like fuses and
circuit breakers are indicated in their most
basic form. Device repre
sentations can
be created by adding other components
and nomenclature to the base component
drawing. Low-voltage <1000V circuit
breakers are represented by the first
two of the following symbols shown in
Figure 3.
Figure 3. Circuit Breaker Symbols
Medium-voltage circuit breakers shown
on a one-line typically incorpo
rate
the Basic Square Breaker symbol with
the ANSI Device Number 52 inside.
Medium-voltage breakers may be
either fixed mount (square with device
number inside) or drawout as shown in
Figure 3 as well as the system one-line on
Page 8.
It is important to develop a naming
convention so personnel working on or
responding to an event on the power
system can readily identify the equipment
experiencing any problems.This naming
convention is also useful for those doing
preventa
tive maintenance in documenting
which specific switchgear, breaker,
transformer or protective relay they
need to address.
Transformers are common compo
nents
of a power system and are used on
both medium-voltage and low-voltage
applications to step a voltage up or down
to a desired level.They are available in
a variety of winding configurations as
detailed in the “Typical Components of
a Power System” in this document.)
Because there are many types and
configurations of transformers available,
it is necessary to properly document the
specific requirements on the One-Line.
Primary unit substation transformers
are used to convert a medium voltage to
another medium voltage.
Secondary Unit SubstationTransformers
transform a MediumVoltage to a Low
Voltage Level, generally under 1000Vac.
They are available in Fluid-Filled and
Dry-Type styles.
Both types of unit substation
transformers can be supplied with
fans to increase the transformer’s kVA
ratings. Figure 4 from the medium-
voltage half of the system one-line
on Page 8 shows “T1” as Eaton
“Peak” StyleTripleTemperature Rated,
7.5 MVA, FR3 EnvirotempE Fluid Filled,
PowerTransformer.
The transformer’s kVA ratings are
indicated at the KNAN, (Natural Air Cooled
by Convection—Over 300C Fire Point Fluid
Filled) and KNAF (Forced Air Cooled Over
300C Fire Point Fluid Filled) ratings.
The “T1” transformer is described as
“Delta” Primary, “Wye” Secondary
configuration in the text as well as further
depicted by the relationship of the “H1,
H2 and H3” connections to the X1, X2, X3
and X0 symbols adjacent to it. Similarly,
the verbiage in the text calls for surge
and lightning protection. Symbols for the
arrester and the capacitor are shown
connected to the incoming terminations.
Their actual ratings should be defined
on the drawing or in the specifications.
Both the transformer’s primary and
secondary amps are included as a
reference for sizing the conductors.This is
useful to determine the quantity and size
of the MV cables per NEC Article 310.60.
While medium-voltage conductors are
available in 90C (MV90) or 105C (MV105)
ratings, the actual terminations in the
transformer or switchgear cable
compartments are limited to 90C.When
sizing the MV cables, the NEC derating
factors must also be applied depending
on the type of raceway or duct bank that
will be required.
Where higher transformer secondary
currents are involved, a busway flange
and non-segregated busway can be
supplied to connect it to the down
stream
MV switchgear (as shown in Figure 4).
Proper selection and application of the
busway requires that the rated short time
and short circuit withstand current values
be specified.
Figure 4. Transformer Information and Symbols
DRAW-OUT
POWER
CIRCUIT
BREAKER
52
FIXED
MOUNT
CIRCUIT
BREAKER
LOW
VOLTAGE
LOW
VOLTAGE
DRAW-OUT
POWER
CIRCUIT
BREAKER
MEDIUM
VOLTAGE
(1)
71
T1
49
T1
63
T1
(1)
M1-00
2000 A BUSWAY
(1) 600:5
HI (C200)
(1)
TRANSFORMER “T1”
PRIMARY UNIT SUBSTATION STYLE
13.8 KV DELTA PRIMARY - 95KV BIL
4.16/2.4 KV GROUNDED WYE - 60KV BIL
EATON “PEAK” 55C/65C/75C
7500/8400/9156 KVA KNAN
9375/10500/11445 KVA KNAF
FR-3 FLUID FILLED, 6.5% MINIMUM Z
WITH SURGE + LIGHTNING ARRESTERS
P/FA = CURRENT RATING. PRIMARY, FORCED AIR.
S/FA = CURRENT RATING. SECONDARY, FORCED AIR.
H1 H3
H2
X
X
X
X0
1
3
2
P/FA = 479A
S/FA = 1589A
CU

Short-circuit values are critical in the
design and specification of all electrical
equipment in a power system.The
transformer’s Impedance, (often
abbreviated as %Z) must be shown
on the One-Line in order to calculate
the required ratings of downstream
equipment as indicated in Figure 5.
It is important to remember that all
transformers designed to ANSI standards
have a plus and minus 7.5% tolerance for
impedance. If a transformer requires an
absolute minimum impedance to ensure
the secondary short-circuit level does not
exceed a critical value, it must be noted
on the One-Line and in the accompanying
project specifications.
Consideration must also be given to the
types of cable terminations based on the
available short-circuit ratings.Where the
available short-circuit exceeds 12.5 kA,
medium-voltage molded rubber
deadfront termina
tions are generally
not an option. In these cases, the type
of terminations must be specified. Stress
Cone cable terminations are available
in either Hot Shrink or Cold Shrink
configurations. Porcelain terminators or
potheads are a more expensive option,
but often have higher short-circuit ratings.
Current transformers are used in both
low- and medium-voltage applications as
sensing devices for protective relays and
meters.They are available in “donut” style,
which encircle the conductor, as well as
bar style, which is bolted in series with the
load conductors. Both styles work on the
principal of electromagnetic coupling; a
current flowing through the conductor
they surround induces a proportional
isolated low level signal (either 1 A or
5 A) that can be measured by an
electromechanical or electronic device.
Current transformers may be shown
in several formats as indicated in
Figure 6.
The dots, X’s or boxes are used to denote
the instantaneous polarity orientation
of the CT.The polarity marks on the
conductor generally face toward the
source of the current flow.The polarity
mark on the CT winding represents the
relationship of the CT’s X1 secondary
terminal to the H1 medium-voltage
terminal on bar type CTs or its input
orientation for donut style CTs.
Figure 5. Incoming Service Calculation
Figure 6. Current Transformer Symbols
In the case of Differential Protection
Circuits such as the 87-T1Transformer
Differential or the 87-B1 Bus Differential,
the CTs are oriented in opposing
directions as illustrated in Figure 7.This
permits the Differential Relays
to measure the current going into a
transformer or bus bar and deduct the
current flowing out of it.When more
current is flowing into the zone of
protection than is proportionally flowing
out, the relay senses the “differential”
and trips the circuit breakers at high
speed to protect against a fault anywhere
in the zone.
Note the “Y” symbol, as well as the
quantity “(3)” next to the CTs.This
represents three CTs configured in a
three-phase grounded wye arrange
ment.
While most of the CTs on the system
one-line on Page 8 are shown this
way, the CTs on the output side of
the 2000 A breaker S1A are not grounded.
This is done to indicate to the equip
ment
manufacturer or installing contractor that
the CT inputs to the relay should not be
grounded in more than one location.
CTs generally are wired to shorting
ter
minal blocks as indicated by the “SB”
in the box shown in Figure 7.These are
used to short out the secondary of the CTs
prior to equipment installation or when
servicing them.
Figure 7. Example of Differential Circuit with
Current Transformer Symbols
INCOMING SERVICE CALCULATIONS
Megawatts Required 8.17 MW KW = 8170 KVA = 10,213
KVA Conversion = Kilowatts x Power Factor PF = 0.8
NUMBER OF INCOMING SERVICES PARALLELED 1
Contingency = 0 Feeders
Transformers Must Be Sized to have: 1 Carry Entire Load. Min KVA Each = 10,213
Primary Temp Rise % Capacity Primary Secondary Secondary % Available
Voltage KV Rating Increase KVA Rating Current Voltage Current Impedence Sec SC *
13.8 55C KNAN Base Rating 7500 313.8 4.16 1040.9 6.5 16014
13.8 65C KNAN 12.0% 8400 351.4 4.16 1165.8
13.8 75C KNAN 22.1% 9158 383.1 4.16 1271.0
13.8 55C KNAF 25.0% 9375 392.2 4.16 1301.2
13.8 65C KNAF 40.0% 10500 439.3 4.16 1457.3
13.8 75C KNAF 52.6% 11445 478.8 4.16 1588.5
Transformer Available Amps for Contingency Conditions = 1588.5
Calculated Required Amps for Contingency Conditions = 1417.4
SHORT CIRCUIT CALCULATIONS AND SWITCHGEAR MVA SELECTION CRITERIA
5kV Max If Known SC= 11650 Available Primary SC Fault Current
Breaker KA Rating f = 2.4132649 FORMULA = (SC*PV*1000*1.732*Z)/(100000*KVA)
50 VCP-W 25 25 M = 0.2929746 FORMULA = 1/(1+f)
50 VCP-W 40 40 I2 = 11323 FORMULA = (PV/SV)*M*SC
50 VCP-W 50 50 # of Services Paralleled = 1
50 VCP-W 63 63 With Known SC Current * Unlimited short circuit
Available Secondary Short Circuit Current 11,323 16014
NOTE: CALCULATION DOES NOT INCLUDE DOWNSTREAM MOTOR CONTRIBUTION
OR
OR
CT’s (2)
500:5
UTILITY
52
C/S
M1-L
(4) GROUND STUDS
120:1
52-M1
1200 A
(1)
71
T1
49
T1
63
T1
13.8 kV, 1200 A, 50 kA SYM S.C.
(15 kV - 95 KV BIL RATED)
M1
86
N.C.
(1)
M1-00
2000 A BUSWAY
(3-Ø, 1-GND)
14,400:120 V
(3)
(3)
G R A
52
C/S
S1-L
(3) 2000:5
STD (C200)
52-S1
2000 A
S1
86
N.C.
STD (C200)
(3) 2000:5
G R A
(3) 2000:5
STD (C200)
(1) 600:5
HI (C200)
STD (C100)
(3) 800:5
(3) 800:5
STD (C100)
(3) 600:5 MR
Set at 350:5
(4) GROUND STUDS
(3-Ø, 1-GND)
(1)
(3) PT'S
TS
SB
SB
SB
SB
SB
86
T1
(1)
87
T1
51G
T1
(1) (3)
TS
TS
TS
TS
“POINT B” T1 - 11.32 KA
SCA WITHOUT MOTOR SCA,
CABLE % Z TO T1 &
BUSWAY % Z
1
1
TRIP M1
TRIP S1
TRIP S1
“BUS A” 4.16 KV, 2000 A, 60 KV BIL, 40 KA SC RATED
TRIP M1
TRIP S1
ETR-5000-T1
H3
H2
X
X
X0
1
3
2
(1)
(1)
M1A LO
S1A LO
P/FA=479 A
S/FA=1589 A
CU
11

It is highly recommended that the design
engineer showTest Switches on the
System One-Line and include them in the
specifications.These are shown on the
one-line as a box with “TS” in it.Test
switches are used during protective relay
testing to provide an alternate path to
inject current and voltage from a test set,
when commissioning these devices in
the field.
When designing a power system, it is
necessary to select the ratio and the
accuracy class for the CT’s. For protective
relaying, the CT must be sized to ensure
they do not saturate under fault
conditions.This may result in a higher
accuracy class with more physical mass
or a higher CT ratio being specified.
Most of the CTs shown on Figure 7
are Standard Accuracy Class for the
ratios selected.The exception is the single
600:5 CT in transformerT1’s Neutral to
Ground Connection.This is shown as a
high accuracy CT.
When selecting CTs for metering
purposes, such as those connected to the
Eaton PXM-6000 Power Quality Meter
(seeTab 3 for details) it is best to use the
CT ratio as close to the actual load as
possible.This is done to increase the
accuracy at the low end of the range
because the CT’s excitation begins to
deteriorate at about 10% of its ratio
setting. As an example, a 600:5A fixed
ratio CT would begin to lose accuracy
at 60 A.
Where loads are light, during
construction or during early build out
stages, the actual current that must be
measured by the meter may be only
100 A. Multi-ratio CTs are frequently used
to set the maximum ratio lower. If set at
100:5A, this would improve accuracy
down to 10 A for a 100 A load. Conversely,
as the end loads grow, the maximum
ratio setting can be easily increased by
changing the CT tap settings.
Voltage transformers are used to step
higher voltages down to safe levels for
inputs to relays and meters.Traditionally,
voltage transformers (VTs) utilize a higher
primary voltage winding that is a fixed
ratio to the 120Vac secondary winding.
Examples shown on the One-Line are
14,400 V:120 V (a ratio of 120:1) or
4200 V:120 V (a ratio of 35:1).Voltage
transformers are often referred to as
potential transformers or PTs.They are
illustrated symbolically as shown in
Figure 8.
Figure 8. Voltage Transformer Symbol
The secondary output of both voltage and
current transformers are measured by
protective relays and used in calcula
tions
involving preset thresholds.
Voltage monitoring elements of protective
relays compare the input from theVTs
against a desired set-point to see if the
system voltage is over or under that
nominal value. If the value exceeds a
plus or minus tolerance band around the
set-point, an output contact or contacts in
the relay change state to signal an alarm
or trip the circuit breaker open.
Microprocessor-based relays offer
tremendous functionality over the
older electromechanical and solid-state
predecessors. Many of these devices
offer multiple types of voltage and
current protective elements.
Protective relay elements are generally
denoted by a number or characters as
defined in the ANSI/IEEE C37.2
Standard for Device Function Numbers,
Acronyms and Contact Designations.
See Table 56 in Power Distribution
Systems Reference Data Section of this
document for Device Function Number
information.
These element numbers are shown in
a circle on the One-Line. A given relay
may have multiple voltage and current
elements shown in a common box, such
as the EDR 5000-M1 protecting the 52-M1
breaker in Figure 9.
The numbers in parenthesis define the
quantity of each specific element. In many
cases this quantity is (3); one for each of
the three phases. In some cases, such as
the 50/51N function, this is shown as a
quantity of (1).The symbol to the right of
this relay represents a transition from (3)
individual phase elements to a single
residual neutral protective element.
The output of each protective function
is shown with a dashed line and arrow
indicating what action is to be taken if
the relay determines the monitored
values exceed the preset thresholds.
The EDR-5000-M1 Relay’s 50/51 Elements
(Instantaneous Overcurrent andTime
Overcurrent respectively) are shown
tripping a high-speed 86-M1 Lockout
Relay.The elements of the ETR-5000-T1
Transformer Differential Relay are
shown similarly, also tripping an 86-T1
lockout relay.
Figure 9. Protective Relay Element Symbols
4200 V:
(3) PT’S
120 V
35:1
(2) UTILITY PT’s
14,400:120 V
(4) GROUND STUDS (3-Ø, 1-GND)
(6) LIVE LINE INDICATORS (2/Ø) 10 A
CT’s (2)
500:5
UTILITY
52
C/S
M1-L
50/51
M1
(4) GROUND STUDS
120:1
52-M1
1200A
59
M1
27
M1
13.8 kV, 1200 A, 50 kA SYM S.C.
(15 kV - 95 kV BIL RATED)
M1
86
N.C.
M1
(3-Ø, 1-GND)
14,400:120 V
(3)
(3) SINGLE PHASE POTHEADS (1/Ø)
(3)
G R A
(3)
(3)
STD (C100)
(3) 800:5
(3) 800:5
STD (C100)
(3) 600:5 MR
Set at 350:5
USG-1A
(3) PT’S
TS
TS SB
SB
“POINT A” 11.65 KA SCA
AVAILABLE FROM UTILITY
86
T1
(1)
87
T1
51G
T1
(1) (3)
TS
TS
TS
TS
1
PXM6000
METER
TRIP M1
TRIP S1
TRIP M1
TRIP S1
EDR-5000-M1 TRIP M1
TRIP S1
ETR-5000-T1
50/51N
(1) (3) (1)
M1A LO

In both cases, the associated (86) lockout
relay then trips the incoming main
breaker “M1” and the transformer
secondary breaker “S1”
. Lockout relays
are used to multiply the tripping contacts
for a given function so they can be wired
into multiple breaker’s separate control
circuits as indicated for the 86-B1 device
on the System One-Line.Their primary
function, however, is to require a manual
reset of the Lockout Relay mechanism by
trained personnel after the cause of the
fault is determined and corrected.
The 27 and 59 functions shown in the
EDR-5000 relay monitor undervoltage
and overvoltage respectively.Their
outputs are shown combined into a
single dashed line directly tripping
both the incoming main breaker “M1”
and the transformer secondary breaker
“S1”
.This reflects the engineer’s desire
to have only one output contact for both
the 27 and 59 functions. Because two
breakers need to be tripped, this will
only require two separate relay contacts
instead of four individual output contacts
otherwise necessary.
The direct trip shown on the System
One-Line purposely does not use an
86 lockout relay, as this under or over
voltage disturbance is anticipated to be
caused by the utility and not a fault on the
end user’s power system. In these
instances, a separate contact from the
relay may be allocated to start a backup
generator or to initiate a Main-Tie-Main
Transfer Scheme.
The EDR-5000 Relay and the ETR-5000
Relay are programmable multi-function
devices with many protective elements
that can be utilized simultaneously. In a
more fully developed protection scheme,
certain protective elements (such as the
50/51 functions) can be used in both
relays to back each other up in the event
of a failure. Figure 10 shows the many
protective elements available in the
EDR-5000 Feeder Protective Relay.
Eaton’s “E Series” relays include an ANSI
74 element to monitor the trip coil of the
circuit breaker or lockout relay they are
tripping.This circuit ensures the integrity
of the device to operate correctly when
a trip signal is applied.The example
One-Line should show the relay circle
with the “74” in it next to the “86” lockout
relay and breaker “52” symbols.These
were purposely not shown on the
drawing as it would make it more
crowded and difficult to read.
Figure 10. EDR-5000 Protective Relay Elements Available
Figure 9 shows some additional
important information about the
equipment required in the dashed
box that comprises utility switchgear
“USG-1A”
. This switchgear is defined as
15 kV Class with a 95 kV basic impulse
rating.The bus is rated to handle 1200 A
even though the actual ampacity flowing
through it will be under 500 A.The
equipment will be operating at 13.8 kV
and have a short-circuit rating of 50 kA
Symmetrical.
Because this One-Line is for educational
purposes, a hypothetical short-circuit
value at “Point A” from the Utility is
shown for reference at 11.65 kA. In
actuality, this value would be part of a
short-circuit study. If using a program
such as SKM to calculate the down
stream
short-circuit values, the cable lengths
and conduit types as well as the
transformer impedance would factor
into the calculations.
The “USG-1A” switchgear on the
One-Line is shown with a 50 kA rating
when other lower ratings such as 40 kA
and 25 kA are available at 15 kV.This has
been done as an example to future design
engineers who may be involved in urban
areas with medium-voltage services.
These MV services typically have higher
available short-circuit capacity. In most
cases, the serving utility may have
specific specifications for the switchgear
and breakers used as medium-voltage
service equipment.
One such requirement is the breaker’s
close and latch rating.Where higher fault
current values exist, some utilities specify
this value at 130 kA peak, which is more in
line with the older 1000 MVA rated design.
Because the 40 kA K=1 design’s close and
latch rating is only 104 kA, the 130 kA close
and latch rating for the 50 kA breaker
would dictate it being used instead. It is
very important to be cognizant of nuances
in all utility specifications to avoid costly
problems or delays in energization.
Certain utilities mandate the type of cable
termination that must be provided in the
switchgear such as the (3) single-phase
pot-heads illustrated on Figure 9.
Utilities may also require neon glow
tubes or other live line indicators to be
located on all three incoming phases.
These devices are intended to caution
personnel that the incoming circuit may
be energized.
However, it is always best to follow
Occupational Safety and Health
Administration (OSHA) approved
practices and assume that the circuit
is live until a calibrated voltage
reading probe attached to a hot-stick
determines otherwise.
Most utilities and institutions involved
in the distribution of medium-voltage
power use portable ground cables
that are applied only after no voltage
presence has been confirmed.This
requires that ground studs be mounted
in the switchgear in order to facilitate their
OSHA compliant grounding procedure.
3
1
3
1
EDR-5000
CTS SOTF CLPU
74
TC
50
BF
51R
50R 50P 51P 67P 67N LOP
46
59N
59
A
27
A
55
A/D
25
47
27
M
59
M
81
U/O 81R 78V 50X 51X 51V
IRIG-B00X Zone Interlocking Breaker Wear Disturbance recorder
67G 32 32V
IRIG-B00X Zone Interlocking Breaker Wear Disturbance recorder
Event recorder
Fault recorder
Metering and
Statistics
Current and volt.:
unbalance
%THD and THD
Fund. and RMS
min./max./avg.
angles
Power:
Fund. and RMS
MVA, Mwatt, Mvar,
PF
13

As shown on the System One-Line, there
are ground studs on the incom
ing and
outgoing sides of both the “USG-1A”
,
(13.8 kV) and “PSG-1A”(4.16 kV)
switchgear. Applying these portable
ground cables requires a safe
disconnection of power in the zone
to be grounded to ensure personnel
safety. Consequently, a Key Interlock
Scheme would be required to prevent
grounding unless the respective breakers
in the zone were withdrawn from their
connected position and locked open.
The symbol representing the key interlock
shown on the One-Line next to the “M1”
and “S1” breaker is the box with the circle
and the letters “LO” inside it.The “LO”
nomenclature indicates that the key
“M1A” or key “S1A” respectively is
only removable when the device
(breaker or fused switch) is in the
Locked Open position.
Key interlocks are also shown on the
MVS switches in two of the (4) Primary
Selective Step-Down substations fed
from MV Feeder Breaker F3A, as well as
on the medium-voltage switch “CUP-F1A”
.
This is done to prevent paralleling of the
two different sources involved in the
Primary Selective Scheme.
The 750 kVA pad-mounted transformers
on the One-Line, feeding “Residence Hall
A” and “B”
, are shown with internal
vacuum fault interrupters (VFIs) as their
overcurrent protection.TheVFIs offer
many of the benefits of a circuit breaker,
such as disconnection of all three phases
simultaneously, and may be used with
external protective relays such as
EDR-3000 Distribution or ETR-3000
Transformer Differential Relay.The
VFI option is available for fluid-filled
transformers in both pad-mounted and
unit substation configurations.
Key interlocks are also used in the
Main-Generator-Tie “Bus A” half of
double-ended 480/277Vac secondary unit
substation as shown in Figure 11 and
Figure 12.This scheme permits only one
source to feed “Bus A” of the double-
ended switchgear at a time.
This arrangement, while functional in
physically blocking multiple sources such
as “MB-F1A”
, “GB” and “MB-F1B” from
being paralleled, does not permit Bus “B”
of the double-ended substation to be
alternately fed from the “MV-F1A” breaker
or the “GB” breaker.This may or may not
be the intent of the design engineer. In
either case, the engineer must think
through the intent of the key interlock
scheme and develop the logic accordingly.
Key interlocks are available in a variety of
configurations including transfer blocks
to capture keys from multiple sources.
They are often used as part of Lockout and
Tag-Out procedures. It is recommended
that the design engineer refer to a key
interlock manufacturer such as Kirk or
Superior for further documentation and
specific operational details.
Drawing Notes are extremely important
as they describe specific functional
requirements. In Figure 12, Note 3 above
switchgear “SUS-F1A” describes an
additional requirement for a Priority Load
Shed Scheme to ensure the generator is
not overloaded.The details of this scheme
would need to be coordinated with the
generator manufacturer and further
defined in the switchgear specifications.
Note 4 calls for DT1150+ electronic
breaker trip units that include an Arcflash
Reduction Maintenance Mode.This feature
limits arc flash energy in compliance with
Article 240.87 of the 2014 NEC by using an
alternate high-speed analog instantaneous
trip setting to reduce arcing time. Note 5
requires a touchscreen panel to monitor
the operating variables as well as be used
to activate the Arcflash Reduction
Maintenance Mode remotely.
This permits personnel who will be
working on the equipment to be in a
safe location outside of the arc flash zone
when enabling the Arcflash Reduction
Maintenance Mode.
Note 4 also requires Zone Selective
Interlocking.This feature permits higher
speed tripping of the Main breaker, if it
does not receive a restraining signal from
a downstream feeder breaker that it is
tripping to clear a fault.
Note 6 adds a requirement for BACnet
communications functionality to a future
Building Management System. It also
provides a point of demarcation between
the scope of work to be provided by the
installing contractor and what portion of
the wiring and interface will be required
of the BMS vendor.
Each of the circuit breaker symbols in the
“SUS-F1A” switchgear are surrounded
by double arrows signify
ing that these
breakers are drawout versus fixed mount.
Additionally, the “E.O.
” nomenclature
in the middle of the breaker symbol
represents “Electrically Operated”
.
This function makes it easier to open
and close the breaker. It also enables the
opportunity for remote control from a
handheld pendant operating station or
a wall-mounted control panel.
Figure 11. Drawing Notes and Key Interlock Scheme in LV Switchgear
M1-03
RHAP-F3A
DFP-F3A
RHBP-F3A
RBP-F3A
2000 AF
1800 AT
E.O. “RBS-F3A”
LSG
(3) 2000:5
480 V:120 V
PT’S
MAIN CB
(3)
250 KA
/Ø.SPD
“POINT D” - 40,400 SCA
WITH UNLIMITED PRIMARY SCA
& 50% MOTOR CONTRIBUTION
SEE XFMR TABLE 1.6-7 FOR
T2 ESTIMATING PURPOSES.
“POINT C” F3A -
11.32 KA SCA
WITHOUT MOTOR
SCA & CABLE Z TO
T1 & T2-RHAP
T2-RHAP-F3A
T3-DFP-F3A
T4-RHBP-F3A
T5-RBP-F3A
VFI-2A
600 A
VFI-3A
600 A
750 kVA FR3 VFI PADMOUNT
55/65C 5.75% Z
4.16 kV-60 KV BIL
208/120 V-20 KV BIL
750 kVA FR3 VFI PADMOUNT
55/65C 5.75% Z
4.16 kV-60 KV BIL
208/120 V-20 KV BIL
4 6
PXM6000
METER
SELECTOR SWITCH
W/SURGE+LIGHTNING
ARRESTERS
SELECTOR SWITCH
W/SURGE+LIGHTNING
ARRESTERS
N.O.
A
RESIDENCE
HALL A
P=104A S=2082A
P
1000kVA
200E
A
P=139A S=1203A
P
A
P=104A S=2082A
P
1500 kVA
300E
A
P=208A S=1804A
P
(SEE DWG E103)
N.C.
N.O.
N.C.
N.O.
N.C.
N.O.
N.C.
RESIDENCE
HALL B
(SEE DWG E105)
M.H
1
M.H
2
M.H
3
M.H
4
M.H
5
M.H
6
M.H
7
M.H
8
LO
F3B
LO
LO
F3D
LO
BUSWAY RISER
(SEE DWG E106)
DINING
FACILITY
(SEE DWG E104)
5.75% Z
4.16kV-480/277V
5.75% Z
4.16 kV-480/277 V
4.16 kV, 3Ø, 60Hz
AL
AL
AL
AL

Each circuit breaker is named and its
Frame Size (AF),Trip Rating (AT) and
protective functions such as Long,
Short and Ground (LSG) or Long, Short,
Instantaneous and Ground (LSIG) are
noted accordingly. Since this equipment
is drawout UL 1558 switchgear, the 4 cell
high structure number and associated
breaker cell are illustrated.
“Spare” breakers have been located in the
top “A” cells 02A and 04A as well as cells
04B and 4C in structure #4.The generator
breaker is also located in top cell 03A of
structure #3, for cable and conduit egress
out the top. In this example, all other
breaker cables “feeding loads exit out the
bottom of the switchgear.This avoids
bottom exiting cables from covering
access to the lugs for the spare and
generator breakers. Consequently, it
permits room to terminate the future
cables, coming into the top of the
switchgear, easily at a later date.
It is always wise to include spare breakers
of important frame and trip sizes in a
drawout switchgear lineup.These spare
breakers can either allow for future load
growth or provide a readily available
backup that can be used in the event that
an active breaker requires maintenance
or service.
Note that interference interlocks are
supplied on breakers and in switchgear
compartments where the compartments
are of the same physical size.This
rejection feature ensures that an
insufficient short circuit or incorrect
ampacity rated breaker cannot be
inserted into the wrong size cell.
As an example, a 1600 A breaker cannot
be used in a cell configured for 800 A
as it would not likely protect the cell
bus runbacks and outgoing cables
appropriately. Likewise, a 65 kA short
circuit rated breaker could not be inserted
into a switchgear cell rated for 85 kA.
Figure 12 shows the main bus for the
switchgear rated at 4000 A with an 85 kA
short-circuit rating. A busway symbol
is illustrated above the tie breaker,
indicating that it is connecting to the other
half of a double-ended switchgear lineup.
Eaton’s low-voltage busway can be
supplied in ratings of 6–30 cycles.The
4000 A busway shown has a 200 kA 6 cycle
rms symmetrical short-circuit rating that
exceeds the 85 kA rating of the “SUS-F1A”
switch
gear bus on the drawing.
The calculated short-circuit rating
required for the “SUS-F1A” switchgear
is dependent on a number of factors
including: the available short circuit
upstream, the inclusion of the cable and
transformer impedances feeding it, as
well as the short-circuit contribution
from the motors downstream.
In actuality, the short-circuit current
available may be lower than the 85 kA
shown on the drawing, permitting a
potential cost and space savings, if the
rating required is dropped to 65 kA or
below. A short-circuit study would need
to be done to confirm this.
Consequently, it is very important to
indicate the actual breaker short-circuit
rating as well as the switchgear bus
ratings on the One-Line.These also need
to be consistent with other schedules and
drawings, as well as in the equipment
specifications.This can prevent a bidder
from incorrectly quoting 85 kA rated
switchgear with 65 kA rated breakers.
The System One-Line shows the
incoming surge protective device (SPD)
in “SUS-F1A” is rated at 250 kA per phase.
As shown in Figure 13, SPDs in the other
downstream equipment are rated
at 120 kA per phase.This surge protection
scheme as shown is applied in a tiered
approach per the IEEE Emerald Book. In
this arrangement, the highest level of
surge protection is at the incoming
source. Downstream switchboards or
panelboards closer to the loads provide
the next of surge protection.
There is a considerable amount of
distribution equipment illustrated on
the example System One-Line. For
that reason, reference is made to other
drawings and schedules that would
comprise the hypothetical bid package.
As an example, 1600 A distribution
switchboard DSB-DF4A has a note to see
schedule DSB-DF4A for the end loads.The
same is true for power panel PP-DF6A.
Figure 12. Drawing Notes and Key Interlock Scheme in LV Switchgear
MAIN SWGR. BUS “A” 85 KA, 480/277 V, 4000 A, 3-PH, 4W, (ALL BREAKERS RATED SC AT 85 KA)
02A
600 AT
800AF
2000AT
2000AF
FDR
“G”
G
ENGINE
DIESEL
PORTABLE
LOAD BANK
2000AF
2000AT
4000 AF
4000 AT
E.O.
“GB”
“MB-F1A”
LSG
LSIG
02B
600 AT
800AF
LSIG
“DF1A” “DF2A”
02C
1600 AT
1600AF
LSIG
“DF3A”
02D
600 AT
800AF
LSIG
“DF4A”
03A
600 AT
800AF
LSIG
“DF9A”
03B
800 AT
800AF
LSIG
“DF6A”
03C
400 AT
800AF
LSIG
“DF7A”
03D
600 AT
800AF
LSIG
“DF8A”
04A
“DF5A”
04B
400 AT
800AF
LSIG
“DF1OA”
04C
500 AT
800AF
LSIG
“DF11A”
04D
500 AT
800AF
LSIG
“DF12A”
4000 AF
4000 AT
“LTA”
LSG
01D
01B
SECONDARY UNIT SUBSTATION “SUS-F1A”
SPARE
SPARE
CUP-F1A
E.O. E.O.
LSG
(3) 4000:5
480 V:
(3) PT’S
120 V
MAIN CB TIE CB
SPARE SPARE
2 2
1
2
3
3
4
6
5
5
250KA/Ø
SPD
Provide M1 Electrical Interlock With S1 Breaker. M1 Cannot Close if S1 is
Open. S1 Cannot Close Until M1 is Closed. Include Key Interlocks as Shown.
Provide MB-F1A Key Interlock With Generator Breaker “GB” and Tie Breaker
“LTA”. Only the Single “MGT” Key Can be Used to Close Any of these Breakers.
Provide Priority Load Shed Controls for Feeder Breakers in SUS-F1A Switchgear.
Provide Interface With Generator Breaker “GB” to Enable Operation When Non-
Priority Loads have Been Shed.
Provide All Magnum Breakers in SUS-F1A & RBS-F3A Switchgear With DT1150+
Trip Units Including Zone Selective Interlocking (ZSI) and Arc Flash Reduction
Maintenance System (ARMS) in Compliance with Article 240.87 of the 2014 NEC.
Wire All DT1150+ Trip Units Communications Ports to an Ethernet Gateway With
BACnet IP Connectivity. BMS Vendor Will Provide Field Wiring and Integrate Into
BMS System on a Separate Contract.
TOUCH
SCREEN
Provide Remote Touchscreen Panel With “Switchgear Dashboard Interface” to
Monitor Operational Variables and Enable Arc Flash Reduction Maintenance Mode.
DRAWING NOTES
ETHERNET
GATEWAY
TO DT1150
TRIP UNITS
BACNET IP
TO BMS
4000 A BUSWAY TO
TIE CB “LTB” IN
“SUS-F1B”
PXM6000
METER
A
P
N.O.
LO
F1A
LO
N.C.
115C AA/FA
2500/3333 kVA
XFMR “ST-F1A”
600 A
P FA=461 A
S FA=4000 A
CLE
4.16 KV-480/277 V
(SEE DWG E108)
LO LO LO
MGT
N.C. N.O. N.O.
EG
4.16 kV, 3Ø, 60Hz
PSG-2A (SEE DWG E102)
Z=5.75%
CU
15

Figure 13. Distribution Equipment Downstream of the SUS-P1A Switchgear
Typical loads are shown, however, for the
various motors being fed out of motor
control center MCC-DF3A. Each motor’s
designation and full load amps are shown
below the motor symbol that contains the
motor’s horsepower rating.
Safety switch symbols are shown
between the MCC and the motor symbol.
Safety switches are used to electrically
isolate the motor during maintenance or
to ensure it does not start unexpectedly
when personnel are working on or in the
equipment it is powering.The operating
handles of safety switches have
provisions for applying a lock-out tag-out
device.They are generally provided with
fuse protection to ensure adequate
short-circuit ratings for the application.
For those situations requiring a short-
circuit rating of 10 kA or less, a non-fused
safety switch may be specified.
Motor control centers are used to group
overcurrent protection and different starter
types for the motors in a portion of a
power system.They may also contain
associated control and distribution
equipment as well as connectivity
interfaces to industrial control or Building
Management Systems (BMS). Motor
starters, and motor protective overload
relays are available in both electro
mechanical and electronic solid-state
configurations.
In a motor control center application, the
starter is provided with either a thermal-
magnetic circuit breaker or high magnetic
circuit protector (HMCP) selected to
permit the high inrush current of the
motor while starting. Either type of
overcurrent protective device provided
must be selected to coordinate with the
motor overload protection relay.
This combination starter is mounted in
a removable “bucket”
. Lower ampacity
buckets are wired to stabs on the rear
of the bucket and manually plugged
directly onto the vertical power bus bars
in the MCC.
Note: Larger hp starter sizes may be physically
hardwired to the bus.
Eaton’s FlashGardE motor control center
“bucket” shown in Figure 14 adds
an additional level of personnel safety.
The FlashGard design incorpo
rates a
RotoTract™ lead screw assembly that
withdraws the stab assembly off the
energized bus bars and into the bucket. A
spring-loaded shutter then automatically
closes off access to the bus bars.
MAIN SWGR. BUS “A” 85 KA, 480/277 V, 4000 A, 3-PH, 4W
02A
600 AT
800AF
2000AT
4000 AT
LSG
LSIG
02B
600 AT
800AF
LSIG
“DF1A” “DF2A”
02C
1600 AT
1600AF
LSIG
“DF3A”
02D
“DF4A”
03A
“DF9A”
03B
800 AT
800AF
LSIG
“DF6A”
03C
400 AT
800AF
LSIG
“DF7A”
03D
600 AT
800AF
LSIG
“DF8A”
04A
“DF5A”
04B
400 AT
800AF
LSIG
“DF1OA”
04C
500 AT
800AF
LSIG
“DF11A”
04D
500 AT
800AF
LSIG
“DF12A”
4000 AT
LSG
01D
01B
SECONDARY UNIT SUBSTATION “SUS-F1A”
150AF 150AF
150AF 150AF 150AF
UNITS
FOP-1
GCP-1
40AT 15AT 90AT
CH-1
100AT 90AT
UNITS
SPARE SPACE 2X
BAT-A
300 KVA
UPS1
PDU-1
RP-DF8A
SPARE
SPARE
IFS-DF7A
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
400 A
SIZE5
FVNR
400 A
SIZE5
FVNR
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
150 A
SIZE4
FVNR
400 A
FR10
261A
PP-DF6A
225AF 400AF
175AT 250AT
SPARE SPACE 2X
XFMR-DF8A
XFMR-UPS1
LSG
(3) 4000:5
XFMR-DF7A
SPARE
RIB
MIS
BIB
Eaton 9395 UPS
DC-DS-A
ATS-A
(SEE DWG E109)
FROM GEN A
1600 AT
1600AF
LSIG
800AF
800AT
600AF
600AT
400AF
250AT
225AF
200AT
400AF
250AT
1600 AT
1600AF
LSIG
150AF
100AT
150AF
100AT
MBP
SPARE
HEAT
HRU-1,2,3,4
PUMP
FUEL
GYCOL
PUMP
10
HVAC
AHU-1,2,3,4
2 4X
HEAT
HRU-5-9
COMFORT
COOLING
4X
REJ. REJ.
3Ø, 3W, 65 KAIC
480V, 600A,
DSB-DF2A
480-208/120 V
300 KVA
SEE SCHEDULE PDU-1
42 Circuit
FOR CRITICAL LOADS
SEE SCHEDULE RP-DF8A
FOR LOADS
480-208/120 V
300 KVA
SEE SCHEDULE IFS-DF7AP & DF7AS
225A
FOR NORMAL & CONTROLLED LOADS
CWP-1
96FLA
75
3Ø, 3W, 65 KAIC
480 V, 1600 A,
MCC-DF3A
1600 A
MLO
75
CWP-4
96FLA
75
CHWP-1
180FLA
150
CHWP-2
180FLA
CT-1
96FLA
75
CT-2
96FLA
75
CT-3
96FLA
75
150
CWP-3
96FLA
75
CWP-2
96FLA
CT-4
96FLA
75
SA-1
96FLA
75
EF-1
96FLA
75
NCHWP-1
240FLA
200
PULSE SSRV SSRV
208/120 V, 1200 A,
3Ø, 4W, 65 KAIC
208/120 V, 225 A,
3Ø, 4W, 10 KAIC
SEE SCHEDULE PP-DF6A
FOR LOADS
480/277V, 800A,
3Ø, 4W, 65 KAIC
3Ø, 4W, 65 KAIC
480V, 1600A,
DSB-DF4A
1600AF
1600AT
SEE SCHEDULE DSB-DF4A
FOR LOADS
18
VFD
150 A
480/277 V 225A
3Ø, 4W, 65KA
POW-R-COMMAND
LIGHTING CONTROL
“DF7AP”
POW-R-COMMAND
RECEPTACLE CONTROL
480-
75KVA
208/120 V
225 A
SS0L
SS0L
SS0L
SS0L SS0L SS0L SS0L
120KA/Ø
SPD
120 KA/Ø
SPD
120 KA/Ø
SPD
250 KA/Ø
SPD
2S2W
3R
6 POLE
3R
6 POLE
3R
6 POLE
SS0L
2S2W
SS0L
2S2W
3R
6 POLE
SS0L
2S2W
800AF
800AT
600AF
600AT
400AF
400AT
1200AF
1000AT
400AF
400AT
600AF
500AT
400AF
400AT
208/120 V, 3Ø, 4W
CDP-A
42 Circuit
CDP-B
120 KA/Ø
SPD
480 V, 600 A,
3Ø, 3W, 65 KAIC
W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP
FREEDOM FLASHGARD MCC
ETHERNET
GATEWAY
TO DT1150
TRIP UNITS
PXM6000
METER
ATC-900
TRANSFER
CONTROL
NORMAL
SOURCE
GENERATOR
SOURCE
BYPASS
ISOLATION
ATS
MAINTENANCE
ISOLATION
BYPASS
P=361A
S=833A
P=361A
S=833A
N.C. N.O. N.O.
P=90A
S=208A
480V-3Ø
3W,65 kA

Figure 14. Freedom FlashGard FVNR Starter
The 75 hp CirculatingWater Pump
motors CWP1 through CWP4 shown
in Figure 13 are examples of full voltage
non-reversing starters (FVNR).The
drawing documents these as having a full
load amp (FLA) rating of 96 A.
Based on rating of 96 A (75 hp),
which would require a NEMA Size 4
combination starter.
The starter symbol shown on the drawing
includes a normally open contactor.This
is followed by an over
load relay symbol.
The overload relay measures the current
flowing through the starter contacts to the
motor and calculates when an extended
overload condition is present that will
damage the motor. A contact from the
overload relay is wired into the control
circuit of the starter, which deenergizes the
con
tactor coil in the event of an overload.
Electromechanical overload relays sense
an overcurrent by directing the current
through a melting eutectic element or a
heater pack.The heat is proportional to
the amount of current flowing.When the
eutectic element melts or the bimetal
bends due to the heat from the heater
pack, the relay opens the control circuit.
The “SSOL
” nomenclature next to the
overload relay shows these particular
starters as having solid-state overload
relays.The text “W/GFP” calls for ground
fault equipment protection. In the past,
this would have had to be added as a
separate relay, however, many of the new
overload relays use microprocessors to
monitor a number of variables including
voltage to the motor. Eaton’s C440, C441
and C445 all include phase loss and
ground fault protection.
Eaton’s solid-state overload relays also
have the ability to communicate status
including current per phase and other
key operational variables back to a
control system.
Motors are available in a number of
winding styles and performance
characteristics.The 75 hp CT-1 through
CT-4 motors shown fed from MCC-DF3A
are of the two-speed, two-winding
variety. Note that six-pole disconnects
are required for two-speed, two-wind
ing
motors. Because the cooling towers are
typically located outdoors on a roof, a
NEMA 3R drip-proof safety switch would
be required.
Many two-speed starters are applied on
motor loads such as cooling towers,
where the fan needed to run at a lower
speed or higher speed, to optimize the
heat transfer and main
tain water
temperature in the return supply to
the chiller.
ASHRE 90.1 is recommending the use
of variable frequency drives in
applications where they can reduce
energy consumption and improve the
performance of the equipment they are
powering. As an example, in lieu of
two-speed motors on cooling towers,
VFDs are being used to maximize
efficiency of the cooling process. In these
cases, a sensor is placed in the wet well
of the cooling tower to monitor the
temperature of the water. A set-point
controller in theVFD utilizes the output
signal from a sensor mounted in the
return water pan as feedback to modulate
the speed of the fan.
The 150 hp CHWP-1 and CHWP-2 chilled
water pumps in MCC-DF3A are shown
being fed from solid-state reduced
voltage starters (SSRV).These SSRV
starters reduce the motor inrush and
ramp them up smoothly to their full
running speed. SSRV Starters can be
used to reduce the “water hammer”
effect where the pipes in the system
experience a sudden thrust of pressure.
Recent declines in the cost ofVFDs and
their associated energy savings capability
have led to their growing popularity in a
number of HVAC applications.WhileVFDs
still have a higher initial purchase cost
than standard starters or solid-state
reduced voltage starters, they have a
relatively short payback period. A savvy
building owner and design engineer will
recognize that the total cost of ownership
and energy savings must be considered
when electing to specifyVFDs.
Figure 13 illustrates a Clean Power,
(18 Pulse)VFD in the MCC-DF3A feeding
NCHWP-1, a 200 hp motor.ThisVFD
contains a phase shifting transformer that
feeds an AC to DC converter.This DC
voltage is main
tained in capacitors on its
DC Bus. Insulated Gate BipolarTransistors
(IGBTs) are switched ON and OFF at a
high frequency to simulate an AC
sinusoidal output waveform.
The output voltage and frequency of this
VFD can be set by a digital signal from the
keypad or an external analog signal such
as 4–20 mA. A set-point controller in the
VFD can also be used to maintain a
temperature, flow rate or pressure level
by utilizing an external feedback signal
from a sensor.
The use ofVFDs in heating, ventilating,
air conditioning (HVAC) has been
popularized due to theVFD’s ability to
save energy.When motors on centrifugal
fans and pumps are oper
ated at reduced
speeds, the energy required to produce
the torque at motor’s output shaft is
reduced by the cube of the speed. See
Eaton Application Paper IA04003002E
for details.
This type of centrifugal load is best
served by a variable torqueVFD that
optimizes the volts per hertz relation
ship
throughout the speed range. In addition
to the dramatic energy savings that can
be experienced below 80% of the motor’s
base speed,VFDs ensure a soft motor
start and acceleration throughout the
speed range.
Eaton’s CPX Clean Power (18 Pulse)VFDs
are available in low voltage for operation
with 208V, 230V, 480V and 575V motors.
RackingTool Receiver Unit Latch
Internal
Shutter
Position
n Open
n Close
Pilot Device
Island
n Start, Stop,
Auto/Man
Power Stab
Position
n Connected
n Disconnected
Handle
Mechanism
Breaker
Starter
17

As illustrated on the Power
System One-Line on Page 8, a
medium-voltage Clean PowerVFD is
available for use with 4.16 kV motors.
The input voltage can be either 4.16 kV
or its internal phase shifting transformer
can be configured to step-down a higher
input voltage, such as 13.8 kV, to power
a 4.16 kV motor.
Medium-voltageVFDs are used to start
and control the speed of high horse
power
motors in sewage and fresh water
pumping applications.They are also
used on medium-voltage high hp HVAC
chillers. SeeTab 10 for details.
Below the MCC in Figure 13 is IFS-DF7A.
This is an assembly that allows several
pieces of electrical distribution equipment
to be pre-wired into a switchboard at
Eaton’s manufacturing facility. As shown,
the IFS includes a 480/277V main breaker
feeding a 480/277Vac 225 A lighting
control panelboard.
A 75 kVA 480V to 208/120V transformer is
also part of the IFS switchboard. It feeds a
208/120V panelboard with remote control
breakers to feed various receptacle loads.
The Integrated Facility System
Switchboard (IFS) arrangement,
as shown in Figure 15 is a great
alternative to traditional wall-mounted
panelboards and floor or trapeze
mounted transformers. Because all
of this equipment comes as a prewired
assembly, it generally takes less floor and
wall space than traditional con
struction
methods. It also reduces installation time
and labor costs.
Figure 15. Integrated Facility
System Switchboards
Figure 16 shows one possible application
of an Eaton 9395 uninterruptable power
supply (UPS-1) being fed through
automatic transfer switch (ATS-A).This
arrangement addresses a potential loss
of power from switchgear SUS-F1A.
Figure 16. UPS-1 Connection Option 1
During normal operation, power flows
from the “Preferred” Normal source from
breaker DF12A in switchgear SUS-F1A,
through the ATS feeding the inputs to the
rectifier input breaker (RIB) and manual
isolation switch (MIS).
When power is lost at the input to ATS-A,
the ATS sends a run command to
Generator A.While the generator is
starting and no power is available to the
UPS, the UPS inverter will use the DC
energy stored in its batteries to generate
an AC sine wave to feed the loads.
As soon as generator power is available,
the ATS will transfer to the generator
source and begin to feed the UPS’s
inverter section.
In this arrangement, consideration would
need to be given to generator stability. An
ATS or generator failure would potentially
result in the UPS running on batteries
until they were out of reserve power.
If this approaches is utilized, the ATS
should be of the BYPASS/ISOLATION
design as indicated on the One-Line.
Eaton’s contactor-based BYPASS/
ISOLATION transfer switch is available
with removable contactors.This permits
them to be interchanged with a spare or
the alternate source contactor during
maintenance and testing.
A second option for feeding the UPS
would be to avoid providing the ATS
and feed the “MBP” and “BIB” from
one breaker in switchgear SUS-F1A and
the “RIB” input breaker from one breaker
in switchgear SUS-F1A and the “BIB”
input breaker from another as shown
in Figure 17.
Figure 17. UPS-1 Connection Option 2
04C
500 AT
800AF
LSIG
“DF11A”
04D
500 AT
800AF
LSIG
“DF12A”
BAT-A
300 KVA
UPS1
E.O. E.O.
RIB
MIS
BIB
Eaton 9395 UPS
DC-DS-A
ATS-A
(SEE DWG E109)
FROM GEN A
MBP
SWITCHGEAR “SUS-F1A”
4000 AF
4000 AT
“LTA”
LSG
E.O.
TIE CB
480 V, 600 A,
3Ø, 3W, 65 KAIC
2
ATC-900
TRANSFER
CONTROL
NORMAL
SOURCE
GENERATOR
SOURCE
BYPASS
ISOLATION
ATS
LO
N.O.
LOAD
04C
500 AT
800AF
LSIG
“DF11A”
04D
500 AT
800AF
LSIG
“DF12A”
BAT-A
300 KVA
UPS1
E.O. E.O.
RIB
MIS
BIB
Eaton 9395 UPS
DC-DS-A
MBP
SWITCHGEAR “SUS-F1A”
4000 AF
4000 AT
“LTA”
LSG
E.O.
TIE CB
2
LO
N.O.
LOAD

This would provide an alternate
path to supply the UPS during a
maintenance event, such as servicing
a breaker or cable termination.
Unfortunately, in the event of a power
outage to the “SUS-F1A” switchgear, due
to substation transformer failure or
maintenance, power to both the UPS
Inverter and static switch would be lost.
Since the purpose of the static bypass is
to operate in the event of a downstream
fault, the UPS inverter would not be
capable of responding to faults of this
nature. It would, however, continue to
use battery power to feed the loads until
the batteries were fully discharged.
Because most UPS battery systems are
not intended to provide long periods of
standby power under the aforemen
tioned
condition, resumption of Normal power
from the “SUS-F1A” switchgear would
need to be done quickly.This may be
difficult as personnel would need to first
open the 4000 A “MB-F1A” main breaker.
They would then need to manually operate
the Key Interlock Scheme to enable a
second source, such as the 2000 kW
generator or the tie breaker to the other
half of the double-ended switchgear.
To ensure a quick resumption of power,
transfer switches are also used in a
number of healthcare and mission-critical
applications to automatically connect to
an alternate source should main power
fail.While UPSs are traditionally used
to back up sensitive servers and data
processing equip
ment, there are
many other places they are utilized. In
healthcare, they ensure a continuous
source of reliable power is available for
electronic imaging equipment.
Larger kVA UPSs are used in industrial
applications such as microprocessor
chip manufacturing operations.They
are also used to power ultraviolet
purification equipment at fresh water
pumping stations.
In a data center application, a UPS may be
used to feed power to one or more power
distribution units (PDUs).These PDUs
are similar in functionality to an IFS
Switchboard.They incorporate an integral
trans
former to step down the incoming
480 V UPS feed to a 208/120 V supply.
The end utilization voltage is distrib
uted
through integrated panelboards out to the
various computer loads. Individual circuits
have CTs so each can be monitored on the
common touchscreen display.
Eaton PDUs can be provided in a variety
of configurations including other larger
frame breakers that can feed remote
power panels (RPPs).
Figure 18. Power Distribution Unit
19

Additional Drawings,
Schedules and Specifications
While a Power System One-Line is the
basis for defining the interrelation
ships
between the various types of distribution
equipment, there is often more
information that needs to be conveyed.
Because the end loads and the conductors
feeding them are the basis for proper
selection and application of the circuit
breakers, a valuable step in the selection
process is developing a schedule.
The overcurrent protection of many
loads, such as motors and distribution
transformers, must conform to the
requirements of Articles 240, 430 and
450 of the National Electrical Code.
Particular consideration needs to
be given to the length and type of
conductors that will need to connect
the distribution equipment.
As cable length increases, so does its
resistance in the circuit leading to a drop in
the voltage at the end of the conductor run
feeding the loads. Cable lengths exceeding
100 feet generally need to be upsized to
offset for voltage drop concerns.
Cable length, size and the raceway they
are installed in, also have an impact on
the impedance of the conductor in the
circuit. Greater impedance helps to
reduce the available short circuit at the
terminals of the distribution equipment
or end load.
The 310.15(B) (3) from the National
Electrical Code defines the Allowable
Ampacities of Insulated Conductors rated
0-90 degrees C.While details of this table
are included in the reference section of
this chapter, it should be noted that Listed
Distribution Equipment is provided with
terminations rated at 75 °C.
From a pragmatic standpoint, this means
that the equipment could be fed from
conductors rated at either 60 °C or 75 °C.
Derating would be required for the
conductor ampacity at 60 °C making it
less practical. It also means that the
equipment could be fed from 90 °C
conductors, but only if applied at the
75 °C ratings due to the limitations of
the equipment ratings.
The following tables are adjusted in
accordance with NEC 240.4(D) to show
the actual allowable ampacities of copper
and aluminum conductors terminating in
electrical distribution assemblies.
A schedule based on the allowable
ampacity of copper conductors in
Table 1 is shown in Figure 19.
It includes the relevant requirements
for secondary unit substation “SUS-F1A”
shown on the One-Line.This schedule
outlines the breaker frame sizes, trip
settings and particulars of the trip
units required.
It also annotates the names for
the breakers as well as their circuit
nameplate designations.The cable
sizes and quantities are determined
by utilizing the tables in the NEC,
(as condensed into Table 1).
The equipment ground sizes are per
NECTable 250.122 based on the trip
rating of the overcurrent device pro
tecting the phase and neutral conduc
tors.
Note that they do not take voltage drop
into consideration.
Table 1. Ampacity of CU Conductors
ConductorAmpacity (Copper)
Conductor
Size
Amperes
at 75 ºC
Conductor
Size
Amperes
at 75 ºC
14 15 3/0 200
12 20 4/0 230
10 30 250 255
8 50 300 285
6 65 350 310
4 85 400 335
3 100 500 380
2 115 600 420
1 130 700 460
1/0 150 750 475
2/0 175 1000 545
Table 2. Ampacity of AL Conductors
ConductorAmpacity (Aluminum)
Conductor
Size
Amperes
at 75 ºC
Conductor
Size
Amperes
at 75 ºC
14 — 3/0 155
12 15 4/0 180
10 25 250 205
8 40 300 230
6 50 350 250
4 65 400 270
3 75 500 310
2 90 600 340
1 100 700 375
1/0 120 750 385
2/0 135 1000 445
Figure 19. Unit Substation Cable Entry Position
1C MB-F1A 4000 4000 LSG + ZSI MAIN BREAKER "MB-F1A" Close Coupled
2A DF1A 800 600 LSIG + ZSI 3N SPARE Future OVERHEAD
2B DF2A 800 600 LSIG + ZSI 3N DSB-DF2A (2) sets (4)#350MCM +(1)#1G 2 3" UNDERGROUND
2C DF-3A 1600 1600 LSIG + ZSI 3 MCC-DF3A (4) sets (3)#600MCM + (1)#4/0G 4 4" UNDERGROUND
2D DF-4A 1600 1600 LSIG + ZSI 3N DSB-DF4A (4) sets (3)#600MCM + (1)#4/0G 4 4" UNDERGROUND
3A DF-5A 800 600 LSIG + ZSI 3N SPARE Future OVERHEAD
3B DF6A 800 800 LSIG + ZSI 3N PP-DF6A (2) sets (4)#600MCM + (1)#1/0G 2 3.5" UNDERGROUND
3C DF7A 800 400 LSIG + ZSI 3N IFS-DF7A (1) set (4)#600MCM + (1)#3G 1 3.5" UNDERGROUND
3D DF8A 800 600 LSIG + ZSI 3 XFMR-DF8A (2) sets (4)#350MCM +(1)#1G 2 3" UNDERGROUND
4A DF9A 800 600 LSIG + ZSI 3N SPARE Future OVERHEAD
4B DF10A 800 400 LSIG + ZSI 3N SPARE Future OVERHEAD
4C DF11A 800 500 LSIG + ZSI 3N SPARE Future OVERHEAD
4D DF12A 800 500 LSIG + ZSI 3 UPS1-INPUT-DF12A (2) sets (3)#250MCM +(1)#2G 2 2" UNDERGROUND
5C LTA 4000 4000 LSG + ZSI 3N TIE CB "LTA" 4000A Busway OVERHEAD
Note 1: Looking at the front of the Unit Substation; Right of the Main Breaker is BUS 1. The TIE Breaker is on the far Right of the Lineup and connects to
Switchgear "SUS-F1B" Through 4000A Busway
SUS
-
F1A
SECONDARY UNIT SUBSTATION "SUS-F1A"
Poles, N bar
connection
Cable Entry Position
into Unit Substation
Frame Size Trip Size Circuit Nameplate Feeder Size
Breaker
Name
BUS
Location
4000A, 480/277VAC, 3-PH, 4W, 85kA Rated Switchgear and Circuit Breakers
Structure
Cell #
Trip
Function
Conduit
Quantity
Conduit
Size

In order to provide an effective ground
fault path as required by 250.4(A)(5) and
250.4(B)(4) of the 2014 NEC, upsizing of
the equipment ground conductors are
required by Article 250.122(B) “when
the ungrounded conductors are
increased in size from the minimum
size that has a sufficient ampacity for
the intended installation”
.
In these cases, “wire-type equipment
grounding conductors, where installed,
shall be increased in size proportionally
according to the circular mil area of the
ungrounded conductors”
.
When developing schedules, it is
important to remember that conductor
sizing is also impacted by the derating
tables for ambient temperature and
conductor fill when installed in raceways.
There are a number of ways to create
cable schedules, the most common of
which is to name the conductor as is
shown on the medium-voltage portion
of the One-Line on Page 8.
Schedules are most often used to
define requirements for low-voltage
switchboards and panelboards.They
may also be utilized to enumerate the
various automatic transfer switches
and the cables connecting them to the
normal and emergency sources as well
as the end load.
Other drawings that are necessary to
produce the installation package are floor
plans that include room dimensions,
equipment locations allocated within the
space, appropriate clearances per code
requirements and means of egress from
the area where the equipment is located.
These drawings have been done primarily
in 2D CAD programs with boxes showing
equipment dimensions on the floorplan.
A front view of the equipment is also
used to detail the elevation requirements.
Equipment occasionally requires top-hats
or pullboxes that add height above the
switchboard or switchgear.
On other occasions, the room does not
have enough height to accommodate
standard equipment. In these cases,
special reduced height switchboards
or switchgear may be provided.
While this equipment may not be
documented as standard, Eaton can
provide assistance in developing a
reduced height alternative solution.
As design and drafting tools have
evolved, the push to include 3D drawings
has subsequently evolved into an
enhanced technology called Building
Information Modeling (BIM). BIM
drawings include the 3D aspect but
also include the capability to assign
equipment performance parameters and
interdependencies.This permits architects
and construction firms to be alerted to
potential “collisions” between incoming/
outgoing conduits and other potential
obstructions such as existing conduits/
busduct, HVAC duct or plumbing in the
space above or below the equipment.
Figure 20. Equipment Floorplan and Elevation
There is an expectation that further
advances will enable the potential to
integrate maintenance, spare parts
and actual performance data into these
BIM models. Eaton offers a suite of
BIM component models ranging
from automatic transfer switches to
panelboards and switchboards that are
available from the Eaton website. Larger
manufactured to order switch
gear BIM
models are available from your local
Eaton application engineer or sales office.
Figure 21. BIM 3D Model Top View
Power System Voltages
The System One-Line on
Page 8, shows an Incoming utility
primary service feeding different types of
distribution equipment at
each of the various utilization voltages
necessary to power the actual loads.
The One-Line illustrates a number of
voltage transformations and is a good
example of the types of choices and
challenges a power systems design
engineer faces today.
AIRWAY
CONDUIT AREA
OUTGOING
FRONT VIEW
TOP VIEW
30.00
36.00
225 KVA
90.00
30.00
PANEL PA3
PRIMARY MCB
CONTACTOR
& RELAY
COMPARTMENT
21

Voltage Classifications
ANSI and IEEET standards define various
voltage classifications for single-phase
and three-phase systems.The terminology
used divides voltage classes into:
■ Low voltage
■ Medium voltage
■ High voltage
■ Extra-high voltage
■ Ultra-high voltage
Table 3 presents the nominal system
voltages for these classifications.
Table 3. Standard Nominal System
Voltages and Voltage Ranges
(From IEEE Standard 141-1993)
Voltage
Class
Nominal SystemVoltage
Three-Wire Four-Wire
Low
voltage
240/120
240
480
600
208Y/120
240/120
480Y/277
—
Medium
voltage
2400
4160
4800
6900
13,200
13,800
23,000
34,500
46,000
69,000
4160Y/2400
8320Y/4800
12000Y/6930
12470Y/7200
13200Y/7620
13800Y/7970
20780Y/12000
22860Y/13200
24940Y/14400
34500Y/19920
High
voltage
115,000
138,000
161,000
230,000
—
—
—
—
Extra-high
voltage
345,000
500,000
765,000
—
—
—
Ultra-high
voltage
1,100,000 —
The 2014 National Electrical Code has
ushered in a change to the definition
of low voltage.The NEC elevated the
maximum voltage threshold for this
category from 600 V maximum to
1000 V maximum.This was done to
accommodate the growing solar
market where voltages up to 1000 V
are becoming more commonplace.
In general, the voltage classes above
medium voltage are utilized for trans
mission of bulk power from generating
stations to the utilities substations that
transform it to the distribution voltage
used on their system.
A power system design engineer should
attempt to familiarize them
selves with
the application of all equipment available
in the various voltage classes.This is
particularly true if they are involved in
designing industrial facilities or campus
arrange
ments that may be served by a
utility at medium or high voltage.
Incoming Service Voltage
When designing a new power
distribution system, the engineer needs
to be knowledgeable of the local utility
requirements including the service
voltage that is available to be provided
for their client. Meeting with the utility’s
customer service representative
responsible for the installation site,
early in the design process, can help
set expectations for both parties and
avoid subsequent delays.
Most utilities will require a load letter
when requesting a new service or
upgrade to an existing utility service.
The letter must include calculated values
for the types of continuous and non-
continuous loads that will be served.
Article 220 of the NEC covers branch-
circuit, feeder and service calculations.
It also includes references to other
articles that pertain to specific types
of installations requiring special
calculation considerations.
The determination of the utility service
voltage is driven by a combination of
factors including the engineers initial
load letter, prevailing utility standards
and the type of facility being served.
Excessively high megawatt loads such
as those required by large wastewater
treatment plants or complex process
facilities like petrochemical refining will
typically exceed the utility’s infra
structure
to serve the end customer at low-voltage.
In these instances, a medium voltage
service at 34.5, 33 kV, 26.4 kV, 13.8 kV,
13.2 kV, 12.47 kV or 4.16 kV will be
mandated. Extremely large loads may
even involve a utility interconnect at the
69 kV or high voltage level.
The System One-Line on Page 8 is an
example of a power system for a
hypothetical college campus with a design
load over 8 megawatts at a 0.8 power
factor.This would require a Utility service
of over 400 A at 13.8 kV.
The most common service voltage
arrangements are in the low-voltage
range (<600Vac). Normal residential
services are at 240/120 three-wire,
(two phases each at 240 and a Neutral
Conductor). Connection from each 240 V
phase to neutral provides 120 V for the
lighting and plug loads.
A three-phase, four-wire low-voltage
service is generally provided for
commercial customers. It includes
a neutral and may be provided at
208/120Vac wye, 240/120Vac wye or
480 /277Vac wye.
Typical applications for the commercial
category of three-phase low-voltage
services are small commercial buildings,
department stores, office buildings,
kindergarten through 12th grade schools
and light manufacturing facilities.
There are a number of other older service
configurations utilized in rural locations
such as Delta Hi Leg.These were used
as an inexpensive way to supply
240 V three-phase and 240 V or 120 V
single-phase from a single-pole mount
transformer.
As a general rule, the serving utility will
offer a basic service option that is outlined
in the tariff documents that have been
approved by the governing authority or
agency that regulates the utility.This basic
service option is one that minimizes the
utility costs and best accommodates their
system requirements.
The utility may alternately offer to
upcharge the client for extending or
reinforcing cable connections to a
location on their overhead or under
ground grid where they can supply the
service the user is requesting. In major
cities where the serving utility utilizes
underground spot networks, the option to
select a voltage other than that available
is either limited or extremely expensive.
Utility metering requirements vary from
one serving entity to another and are
more complex for medium-voltage
switchgear used as service equipment.
Commercial low-voltage utility
metering (<600V) is more common
and includes standardized designs
that can be provided in various low-
voltage switchboard and drawout
switchgear configurations.

Incoming Service
Considerations
Article 230 of the National Electrical
Code: “covers service conductors and
equipment for the protection of services
and their installation requirements”
.
Figure 22 provides the scope of pertinent
references that apply to incoming service
equipment.These range from conductor
types from overhead service utility drops
to underground utility feeds and their
proper installation.
PartsV,VI andVII of Article 230 spell out
the common requirements for low-
voltage service equipment <1000Vac.
These parts cover locations permitted,
various marking require
ments including
Section 230.66 that requires service
equipment be listed and marked as
Suitable for Use as Service Equipment,
(SUSE). Also included is Section 230.71,
which limits the number of incoming
main service disconnects to a maximum
of six.
Section 230.95 of this Article requires
equipment ground fault protection for
service disconnect(s) 1000 A and above
when applied on solidly grounded wye
services, where the phase to ground
voltage exceeds 150 V.
Article 250 of the NEC contains the
requirements for grounding and bonding
of electrical systems. Specific details
pertaining to grounding for the incoming
service equipment begin at Section 250.24.
These include application of the
grounding electrode conductor in Section
250.50 to its sizing in accor
dance with
Table 250.66. Requirements for bonding
of service equipment begins in Section
250.90. Sizing of the main bonding
jumper and system bonding jumper are
also covered inTable 250.102(C)(1).
A more in-depth discussion of ground
fault protection can be found in Section
1.5 of this Design Guide.
Figure 22. Application Zones of 2014 NEC Articles Related to Incoming Utility Services
The NEC Article 230 does not specifi
cally
require that electrical service rooms be
fire rated rooms or that sprinklers be
provided. However, survivability
requirements for fire pump disconnects
in local building code requirements, in
addition to NEC Article 450 or additional
utility specifications may require fire
rated rooms, particularly if medium-
voltage service is being supplied.
Space allocation should be considered
when laying out equipment in a service
room. Both low- and medium-voltage
utility metering typically adds an
additional equipment structure, or
structures, to an incoming service lineup.
These are used to accommo
date the
current transformers and potential taps
or voltage transformers necessary for
the external utility revenue meter to
calculate usage.
Article 110 of the NEC covers a broad
range of requirements for electrical
installations. It includes provisions that
govern the construction and spatial
requirements for egress, clearances
and working space in rooms containing
electrical distribu
tion and service
equipment.
Table 4 includes combined tables from
NEC Article 110, showing the minimum
“depth of the working space in the
direction of live parts” required in front
and behind medium-voltage equipment
and low-voltage equipment.
Table 4. NEC Minimum Depth of Clear Working Space at Equipment
Minimum Depth of ClearWorking Space at Electrical Equipment
Combined NECTables 110.26 (A) & 110.34 (A)
Nominal (Phase)
to GroundVoltage
Typical System
Voltage
Condition
1 Live Parts to
Ungrounded Surfaces
Condition
2 Live Parts to
Grounded Surfaces
Condition
3 Live Parts
to Live Parts
Feet Feet Feet
0–150V
151–600V
601–2500V
208/120V
480/277V
4160V
3 ft
3 ft
3 ft
3 ft
3 ft 6 in
4 ft
3 ft
4 ft
5 ft
2501–9000V
9001–25,000V
13,800V
34,500V
4 ft
5 ft
5 ft
6 ft
6 ft
9 ft
NEC Definition of Live Parts: “Energized conductive Components.
”
NEC Definition of Energized: “Electrically Connected to, or is a source of voltage.
”
MVTransformers with Snubber Capacitors or MV EPR Cables holding a capacitive charge are considered
“Live” until the voltage is bled off by grounding procedures.
HVAC
480–208/120 V
75 kVa
Panelboard
Lighting
Panel
Distribution
Panel
Distribution
UTILITY OWNED POLE MOUNT
TRANSFORMER
Part II - Overhead Service Conductors
230.24 - Clearances
Service Head
Part IV - Service Entrance Conductors
Part V - Service Equipment General
Article 250 - Grounding & Bonding
Part VI - Service Equipment Disconnecting Means
Part VII - Service Equipment Overcurrent Protection
230-95 - Ground Fault Protection of Equipment
Article 408 - Switchboards, Switchgear & Panelboards
Article 240 - Overcurrent Protection
Articles 215 & 225 - Feeders
Articles 210 & 225 - Branch Circuits
UTILITY OWNED PADMOUNT TRANSFORMER
OR UNDERGROUND DISTRIBUTION
Part III - Underground Service Conductors
230.32 - Depth of Burial & Protection
Terminal Box, Meter or Other Enclosure
1000 A & Above Main CB at
480/277 Vac to be Provided with
Equipment Ground Fault Protection
APPLICATION ZONES OF ARTICLE 230 - SERVICES PARTS I - VII & ASSOCIATED APPLICABLE NEC ARTICLES
Utility
Meter
23

Additional work space may need to be
allocated for OSHA required grounding
practices, prior to servicing deenergized
medium-voltage equip
ment. As an
example, 6-foot-long insulated hot sticks
are typically used to keep personnel at a
safe distance, while applying portable
ground cables.This procedure is utilized
to discharge any residual capacitive
voltage present on cables terminating
in a medium-voltage transformer
primary cable compartment or in the
rear cable compartment of medium-
voltage switchgear.
As renewable energy or cogeneration
are added, power systems are becoming
more complex and so too is their service
interface for utility power. Many Public
Service Commissions have adopted
Standard Interface Requirements (SIR)
for Distributed Energy Resources (DER)
based on IEEE 1547.These are intended
to protect the utility system from user-
owned generation back-feeding into a
fault or dead cable on the utility grid.
Utilities may have their own specifica
tions and tariffs for the interconnection of
this Dispersed or Distributed Generation
(DG).These include capacity limitations
and/or the addition of charges for the
“spinning reserves” they must keep on
hand, should the user’s DG assets fail or
load increase.
Consequently, the design engineer must
be aware that special relaying protection
may need to be included in the design.
Also, additional analysis of the utility
tariffs and rate structures may be
necessary to validate the projected
payback of participation in peak
demand reduction programs using
owner-supplied generation.
Utilization Voltage Selection
Very large inductive loads such as higher
horsepower motors used on HVAC
chillers, sewage treatment pumps and
in process or other Industries can draw
tremendous amounts of power. Motors
also inherently have high inrush currents
during full voltage starting, which can
cause a significant voltage dip on the
power system feeding it. As a result,
many utilities have limitations on the
maximum horsepower motor that can be
line started directly from their system.
To limit the impact of this phenomena,
a variety of techniques can be used to
reduce the motor’s starting inrush
current.These generally involve the
use of electromechanical or solid-state
reduced voltage starters.Variable
frequency drives in both low and
medium voltage are also available
as shown on the System One-Line on
Page 8. See Components of a Power
System section for further details.
Voltage Recommendations
by Motor Horsepower
Some factors affecting the selection
of motor operating voltage include:
■ Motor, motor starter and cable first cost
■ Motor, motor starter and cable
installation cost
■ Motor and cable losses
■ Motor availability
■ Voltage drop
■ Qualifications of the building
operating staff; and many more
The following table is based in part
on the above factors and experience.
Because all the factors affecting the
selection are rarely known, it is only
an approximate guideline.
Table 5. Selection of Motor Horsepower Ratings
as a Function of System Voltage
MotorVoltage
(Volts)
Motor
hp Range
System
Voltage
460
2300
4000
Up to 500
250 to 2000
250 to 3000
480
2400
4160
4600
13,200
250 to 3000
Above 2000
4800
13,800
In higher motor hp applications, a motor’s
4.16 kV utilization voltage may be the
same as the 4.16 kV service voltage. In
these cases, the service equipment would
need to feed power through cables or
busway to a medium-voltage starter or
variable frequency drive.
However, in installations where there are
many long cable runs that are feeding
other large loads, the medium-voltage
distribution may have a higher service
voltage such as 13.8 kV. In this case, the
service voltage would need to be
stepped-down to the 4.16 kV utilization
voltage through a primary unit substation
transformer as illustrated by the System
One-Line on Page 8.
Conversely, small end loads, short runs
and a high percentage of lighting and/or
receptacle loads would favor lower
utilization voltages such as 208 Y/120 V.
If the incoming service was at 13.8 kV,
as noted in the previous example,
secondary unit substations, pad-mounted
transformers or unitized power centers
could be used to step-down to the
208 Y/120 V utilization voltage required.
This approach is often used to reduce
or offset voltage drop issues on multi
building sites such as college or hospital
campuses. It is also used in large single
building sites like distribution warehouses
and high rise “skyscraper” buildings.
Note: The “Types of Systems” section of this
Design Guide illustrates a number of power
system designs that improve reliability and
uptime during maintenance or service outages.
Among these schemes are a variety of
configurations showing medium-voltage
sources feeding substation or pad-mounted
transformers that step it down to the
appropriate low voltage for end load utilization.
A problem can arise, however, when a
low-voltage service is the only utility
service option and cable distances
between the incoming service and the
utilization loads are great. In these
instances, a practical way to offset for
the voltage drop to the end utilization
loads is the use of low-voltage busway
in lieu of cable.
Another technique to address voltage
drop concerns for long cable runs is
to use a step-up and step-down
transformer arrangement.

To accomplish this, a step-up trans
former
is added after the low-voltage service.The
transformer primary is configured in a
delta and is fed by the grounded and
bonded low-voltage incoming utility
service.The step-up transformer wye
secondary is often at medium voltage,
typically at 4.16 kV, with the transformers
wye secondary grounded.
A 4.16 kV delta primary step-down
transformer is then located near the
served load and has its wye secondary
grounded in accordance with NEC Article
250.30 to create a separately derived
system.This step-down transformer’s
secondary voltage may be the same as
the incoming service, or it may be at
higher utilization voltage.
Caution must be taken when selecting the
step-up transformers to be used in this
type of application. Step-up transformers,
particularly designs that are not optimized
for step-up purposes, such as a reverse-fed
standard transformer, exhibit extremely
high inrush during energization.
Unless the step-up transformers are
specifically wound for low inrush,
the magnetizing current during initial
energization, may exceed the 6X make
capabilities of a low-voltage fused
bolted pressure switch.This can result
in a condition where a portion of the
switch contact surface can weld before
full engagement.The current passing
through the smaller contact area will
then eventually cause the switch to
overheat and fail.
Many step-up transformer applications
involve a 208Vac incoming service
stepping this voltage up to the utilization
voltage of 480Vac for HVAC motor loads
in a building.The design engineer must
be aware of some potential pitfalls and
plan ahead when involved in this type
of application.
Larger step-up transformers offer fewer
transformer voltage taps, if any at all.They
also exhibit poor voltage regulation when
experiencing transient shock loads, such
as motors starting.When designing power
systems utilizing step-up transformers
to feed motor loads, a Motor Starting
Analysis should be performed to ensure
that the motors will start and operate
as intended.
Low-Voltage Utilization
With most low-voltage services, the
service voltage is the same as the
utilization voltage. However, when
the engineer is faced with a decision
between 208Y/120V and 480Y/277V
secondary distribution for commercial
and institutional buildings, the choice
depends on several factors.The most
important of these are the size and types
of loads (motors, fluorescent lighting,
incandescent lighting, receptacles) and
length of feeders. In general, power
system designs with HVAC equipment
with a significant quantity of motors,
predominantly fluorescent lighting loads,
and long feeders, will tend to make
480Y/277V more economical.
Industrial installations with large motor
loads are almost always 480V resistance
grounded, wye systems (see further
discussion on this topic in the Grounding/
Ground Fault Protection section of this
Design Guide).
Practical Factors
Because most low-voltage distribution
equipment available is rated for up to
600 V, and conductors are insulated for
600V, the installation of 480V systems
uses the same techniques and is
essentially no more difficult, costly or
hazardous than for 208V systems.The
major difference is that an arc of 120V
to ground tends to be self-extinguishing,
while an arc of 277V to ground tends to
be self-sustaining and likely to cause
severe damage.
For this reason, Article 230.95 of the
National Electrical Code requires
ground fault protection of equipment
on grounded wye services of more than
150 V to ground, but not exceeding
600V phase-to-phase (for practical
purpose, 480Y/277V services), for any
service disconnecting means rated
1000 A or more.
Article 215.10 of the NEC extends this
equipment ground fault requirement to
feeder conductors and clarifies the need
for equipment ground fault protection
for 1000 A and above, feeder circuit
protective devices on the 480/277Vac
secondary of trans
formers. Article 210.13
has been added to the 2014 NEC,
essentially recognizing the same need
for equipment ground fault protection on
1000 A branch circuits being fed from the
480/277Vac secondary of transformers.
The National Electrical Code permits
voltage up to 300V to ground on circuits
supplying permanently installed electric
discharge lamp fixtures, provided the
luminaires do not have an integral
manual switch and are mounted at least
8 ft (2.4 m) above the floor.This permits
a three-phase, four-wire, solidly grounded
480Y/277V system to supply directly all
of the fluorescent and high-intensity
discharge (HID) lighting in a building at
277V, as well as motors at 480V.
Technical Factors
The principal advantage of the use of
higher secondary voltages in buildings is
that for a given load, less current means
smaller conductors and lower voltage
drop. Also, a given conductor size can
supply a large load at the same voltage
drop in volts, but a lower percentage
voltage drop because of the higher
supply voltage. Fewer or smaller circuits
can be used to transmit the power from
the service entrance point to the final
distribution points. Smaller conductors
can be used in many branch circuits
supplying power loads, and a reduction
in the number of lighting branch circuits
is usually possible.
It is easier to keep voltage drops within
acceptable limits on 480V circuits than
on 208V circuits.When 120V loads are
supplied from a 480V system through
step-down transformers, voltage drop
in the 480V supply conductors can be
compensated for by the tap adjust
ments
on the transformer, resulting in full 120V
output. Because these transformers are
usually located close to the 120V loads,
secondary voltage drop should not be
a problem. If it is, taps may be used to
compensate by raising the voltage at
the transformer.
The interrupting ratings of circuit
breakers and fuses at 480V have
increased considerably in recent years,
and protective devices are now available
for any required fault duty at 480V.
In addition, many of these protective
devices are current limiting, and can be
used to protect down
stream equipment
against these high fault currents.
25

Economic Factors
Utilization equipment suitable for
principal loads in most buildings
is available for either 480V or 208V
systems.Three-phase motors and
their controls can be obtained for either
voltage, and for a given horsepower are
less costly at 480V. LED lighting as well as
earlier technologies including fluorescent,
HID and high pressure sodium can all be
applied in either 480V or 208V systems.
However, in almost all cases, the installed
equipment will have a lower total cost at
the higher voltage.
Figure 23. Typical Power Distribution and Riser Diagram for a Commercial Office Building
a Include ground fault trip.
1 1 1 1 1 1 1
1
Spare
Building and
Miscellaneous
Loads
4000A
Main CB
Automatic
Transfer Switch
Typical
Gen. CB
4000A at 480Y/277V
100,000A Available Fault Current
Utility
Metering
CTs
PTs
Utility
Service
HVAC
Feeder
Busway
Riser
Elevator
Riser
Elevator
Panel
(Typical Every
Third Floor)
480Y/277V
Panel
208Y/120V
Panel
Emergency
Lighting
Riser
HVAC
Panel
Dry Type Transformer
480∆-208Y/120 V
(Typical Every Floor)
Emergency
Lighting Panel
Typical
Typical
Typical
Typical
Typical
Typical
Typical
Emergency
or Standby
Generator

Types of Systems
In many cases, power is supplied by
the utility to a building at the utilization
voltage. In these cases, the distribution
of power within the building is achieved
through the use of a simple radial
distribution system.
Simple Radial System
In a conventional low-voltage radial
system, the utility owns the pole-mounted
or pad-mounted transformers that step
their distribution voltage down from
medium voltage to the utilization voltage,
typically 480/277 Vac or 208/120 Vac. In
these cases, the service equipment is
generally a low-voltage main distribution
switchgear or switch
board. Specific
requirements for service entrance
equipment may be found in NEC
Article 230, Services.
Low-voltage feeder circuits are run
from the switchboard or switchgear
assemblies to panelboards that are
located closer to their respective loads
as shown in Figure 24. Each feeder is
connected to the switchgear or switch
board bus through a circuit breaker or
other overcurrent protective device. A
relatively small number of circuits are
used to distribute power to the loads.
Because the entire load is served from
a single source, full advantage can be
taken of the diversity among the loads.
This makes it possible for the utility
to minimize the installed transformer
capacity. However, if capacity require
ments grow, the voltage regulation and
efficiency of this system may be poor
because of the low-voltage feeders and
single source.Typically, the cost of the
low-voltage feeder circuits and their
associated circuit breakers are high
when the feeders are long and the
peak demand is above 1000 kVA.
Where a utility’s distribution system is fed
by overhead cables, the likelihood of an
outage due to a storm, such as a hurricane
or blizzard, increases dramatically.Wind
or ice formation can cause tree branches
to fall on these suspended cables, causing
an unplanned power outage.The failure
of pole-mounted utility transformers can
result in an outage lasting a day or more.
Additionally, a fault on the Service
Switchgear or Switchboards low-voltage
bus will cause the main overcurrent
protective device to operate, interrupting
service to all loads. Service cannot be
restored until the necessary repairs have
been made. A fault on a low-voltage
feeder circuit will interrupt service to all
the loads supplied by that feeder.
An engineer needs to plan ahead for
these contingencies by incorporating
backup power plans during the initial
design of the power system. Resiliency
from storms, floods and other natural
disasters can be accomplished with the
addition of permanently installed standby
generation, or by including a provision in
the incoming Service equipment for the
connection of a portable roll-up
temporary generator.
Note: See Generator and Generator Systems
in the Typical Power Systems Components
section of this Design Guide for further details.
Figure 24. Low-Voltage Radial System
Utility
Medium-Voltage
Distribution
Utility Owned
Pole or Padmount
Transformer
Utility
Meter
480/277 Vac
Service Entrance
Equipment
(VT’s or Tap by Utility)
(CT’s by Utility)
75 kVA
480–208/120 V
Distribution
Panel
Distribution
Panel
Lighting
Panelboard
HVAC
Types of Systems
27

Figure 25 shows a typical incoming
service switchboard with the addition of
a key interlocked generator breaker. In
this design, the breaker pair shares a
single key that can only be used to close
one breaker at a time.This arrangement
ensures against parallel
ing with the utility
but requires manual intervention in the
event of an outage.
In a typical standby generation arrange
ment, automatic transfer switches are
used to feed either Nor
mal utility power
or an alternate gener
ator source of
backup power to the critical loads.The
transfer switches sense the loss of power
from the Nor
mal source and send a run
command to the generator to start.
Once the generator is running, the
transfer switches sense that voltage is
available and automatically open the
Normal contactor and close the Generator
contactor.When the Normal source
returns, the transfer switch opens the
Generator contactor and closes the
Normal source contactor.
The location and type of the transfer
switches depends on the Utility and the
overall design intent.Transfer switches
can be Service Entrance Rated and
used as the main Service Disconnect
feeding all the loads downstream.
See Figure 26.
Transfer switches can be also be incor
porated into the service switchboard as
an integral part of the assembly.
Alternately, they can be located down
stream of the incoming service and
applied only to the individual loads they
are feeding.This approach of isolating
only those critical loads that must
function during a power outage can
reduce the generator kVA necessary.This
can reduce space and cost requirements.
It is important to consider the ground
ing
of the generator neutral when using
automatic transfer switches in power
system design. If the generator neutral is
grounded at the generator, a sepa
rately
derived system is created.This requires
the use of four-pole transfer switches for
a three-phase system.
If the three-phase generator neutral
is brought back through the transfer
switches and grounded at the service
entrance, a three-pole transfer switch
with solid neutral should be provided.
Figure 25. Typical Incoming Service Switchboard
Figure 26. Main Service Disconnect Feeding Downstream
Utility
Medium-Voltage
Distribution
Utility Owned
Pole or Padmount
Transformer
Utility
Meter
480/277 Vac
Service Entrance
Equipment
(VT’s or Tap by Utility)
(CT’s by Utility)
G
K1 K1
75 kVA
480–208/120 V
Distribution
Panel
Distribution
Panel
Lighting
Panelboard
HVAC
Typical Transfer Switch Installation
Typical Transfer Switch Installation
Rated for Service Entrance
Utility Service Utility Service
Service
Disconnect
Service
Disconnect
Generator
Breaker
Generator
Breaker
ATS ATS
Load
Load
G
G
Types of Systems

In cases where the utility service voltage is
at some voltage higher than the utilization
voltage within the building, the system
design engineer has a choice of a number
of types of systems that may be used.This
discussion covers several major types of
distribution systems and practical
modifications of them.
1. Simple medium-voltage radial
2. Loop-primary system—
radial secondary system
3. Primary selective system—
secondary radial system
4. Two-source primary—
secondary selective system
5. Sparing transformer system
6. Simple spot network
7. Medium-voltage distribution
system design
In those cases where the customer
receives his supply from the primary
system and owns the primary switch and
transformer along with the secondary
low-voltage switchboard or switchgear,
the equipment may take the form of
a separate primary switch, separate
transformer, and separate low-voltage
switchgear or switch
board.This
equipment may be combined in the
form of an outdoor pad-mounted
transformer with internal primary
fused switch and secondary main
breaker feeding an indoor switchboard.
Another alternative would be a
secondary unit substation where the
primary fused switch, transformer and
secondary switchgear or switchboard
are designed and installed as a close-
coupled single assembly.
A modern and improved form of the
conventional simple medium-voltage
radial system distributes power at a
primary voltage.The voltage is stepped
down to utilization level in the several
load areas within the building typically
through secondary unit substation
transformers.The transformers are
usually connected to their associated
load bus through a circuit breaker, as
shown in Figure 28.
Each secondary unit substation is an
assembled unit consisting of a three-
phase, liquid-filled or air-cooled
transformer, an integrally connected
primary fused switch, and low-voltage
switchgear or switchboard with circuit
breakers or fused switches. Circuits are
run to the loads from these low-voltage
protective devices.
Because each transformer is located
within a specific load area, it must have
sufficient capacity to carry the peak load
of that area. Consequently, if any diversity
exists among the load area, this modified
primary radial system requires more
transformer capacity than the basic form
of the simple radial system.
However, because power is distributed
to the load areas at a primary voltage,
losses are reduced, voltage regulation is
improved, feeder circuit costs are reduced
substantially, and large low-voltage feeder
circuit breakers are eliminated. In many
cases the inter
rupting duty imposed on
the load circuit breakers is reduced.
This modern form of the simple radial
system will usually be lower in initial
investment than most other types of
primary distribution systems for build
ings in which the peak load is above
1000 kVA. A fault on a primary feeder
circuit or in one transformer will cause
an outage to only those secondary loads
served by that feeder or trans
former.
In the case of a primary main bus fault
or a utility service outage, service is
interrupted to all loads until the trouble
is eliminated.
Figure 27. Simple Radial System
Figure 28. Primary and Secondary Simple Radial System
Primary Fused Switch
Transformer
600V Class
Switchboard
Distribution
Dry-Type
Transformer
Lighting
Panelboard
Distribution
Panel
MCC Distribution
Panel
Secondary Unit
Substation
Primary Main Breaker
Primary Feeder Breakers
Primary
Cables
52
52 52 52 52 52 52
29
Types of Systems

Reducing the number of transformers per
primary feeder by adding more primary
feeder circuits will improve the flexibility
and service continuity of this system;
the ultimate being one secondary unit
substation per primary feeder circuit.This
of course increases the investment in the
system but minimizes the extent of an
outage resulting from a transformer or
primary feeder fault.
Primary connections from one secondary
unit substation to the next secondary unit
substation can be made with “double”
lugs on the unit substation primary switch
as shown, or with load break or non-load
break separable connectors made in
manholes or other locations. See Eaton’s
Cooper PowerE series Molded Rubber
MediumVoltage Connectors on Eaton’s
website for more details.
Depending on the load kVA connected
to each primary circuit and if no ground
fault protection is desired for either the
primary feeder conductors and trans
formers connected to that feeder or the
main bus, the primary main and/or feeder
breakers may be changed to primary
fused switches.This will significantly
reduce the first cost, but also decrease
the level of conductor and equipment
protection.Thus, should a fault or
overload condition occur, downtime
increases significantly and higher costs
associated with increased damage levels
and the need for fuse replacement is
typically encountered. In addition, if only
one primary fuse on a circuit opens, the
secondary loads are then single phased,
causing damage to low-voltage motors.
Another approach to reducing costs is
to eliminate the primary feeder breakers
completely, and use a single primary main
breaker or fused switch for protection of
a single primary feeder circuit with all
secondary unit substations supplied
from this circuit. Although this system
results in less ini
tial equipment cost,
system reliability is reduced drastically
because a single fault in any part of the
primary conductor would cause an outage
to all loads within the facility.
2. Loop Primary System—
Radial Secondary System
This system consists of one or more
“PRIMARY LOOPS” with two or more
transformers connected on the loop.This
system is typically most effective when
two services are available from the utility
as shown in Figure 29. Each primary loop
is operated such that one of the loop
sectionalizing switches is kept open to
prevent parallel operation of the sources.
When secondary unit substations are
used, each transformer may have its
own duplex (2-load break switches with
load side bus connection) sectionalizing
switches and primary load break fused
switch as shown in Figure 30 or
utilizing three on-off switches or a
four-position sectionalizing switch and
vacuum fault interrupter (VFI) internal
to the transformer saving cost and
reducing footprint.
When pad-mounted compartmental
ized
transformers are used, they are furnished
with loop-feed oil-immersed gang-
operated load break sectionalizing
switches and Bay-O-Net expulsion
fuses in series with partial range back-up
current-limiting fuses. By operating the
appropriate sectionalizing switches, it
is possible to disconnect any section of
the loop conductors from the rest of
the system. In addition, it is possible to
disconnect any transformer from the loop.
Figure 29. Loop Primary—Radial Secondary System
NC NC
NO
Loop A
Loop B
Tie
Breaker Loop Feeder Breaker
Primary Main Breaker 2
Secondary Unit Substations Consisting of:
Duplex Primary Switches/Fused Primary Switches/
Transformer and Secondary Main Feeder Breakers
NO NC NC NC
NC NC
NC
52 52
52
52
52
52 52
Fault Sensors
Primary Main Breaker 1
Types of Systems

Figure 30. Secondary Unit Substation
Loop Switching
Figure 31. VFI / Selector Switch Combination
Figure 32. Pad-Mounted Transformer
Loop Switching
Figure 33. Basic Primary Selective—Radial Secondary System
A key interlocking scheme is normally
recommended to prevent closing all
sectionalizing devices in the loop. Each
primary loop sectionalizing switch and
the feeder breakers to the loop are
interlocked such that to be closed they
require a key (which is held captive until
the switch or breaker is opened) and one
less key than the number of key interlock
cylinders is furnished. An extra key is
provided to defeat the interlock under
qualified supervision.
In addition, the two primary main
breakers, which are normally closed,
and primary tie breaker, which is
normally open, are either mechanically
or electrically interlocked to prevent
paralleling the incoming source lines.
For slightly added cost, an automatic
throw-over scheme can be added
between the two main breakers and tie
breaker. During the more common event
of a utility outage, the automatic transfer
scheme provides significantly reduced
power outage time.
The system in Figure 29 has higher costs
than in Figure 28, but offers increased
reliability and quick restora
tion of service
when 1) a utility outage occurs, 2) a
primary feeder conductor fault occurs, or
3) a transformer fault or overload occurs.
Should a utility outage occur on one of
the incoming lines, the associated
pri
mary main breaker is opened and the
tie breaker closed either manually or
through an automatic transfer scheme.
When a primary feeder conductor
fault occurs, the associated loop feeder
breaker opens and interrupts service to
all loads up to the normally open primary
loop load break switch (typically half of
the loads). Once it is determined which
section of primary cable has been faulted,
the loop sectionalizing switches on each
side of the faulted conductor can be
opened, the loop sectionalizing switch
that had been previously left open can
then be closed to all secondary unit
substations while the faulted conduc
tor
is replaced. If the fault should occur in a
conductor directly on the load side of
one of the loop feeder breakers, the loop
feeder breaker is kept open after tripping
and the next load side loop sectionalizing
switch manually opened so that the
faulted conductor can be sectionalized
and replaced.
Under this condition, all secondary unit
substations are supplied through the
other loop feeder circuit breaker, and thus
all conductors around the loop must be
sized to carry the entire load connected
to the loop.Where separable load break
or non-load break connectors are used,
they too must be sized to handle the
entire load of the loop. Increasing the
number of primary loops (two loops
shown in Figure 33) will reduce the extent
of the outage from a conductor fault, but
will also increase the system investment.
Loop
Feeder
Loop
Feeder
Load Break
Loop Switches
Fused
Disconnect
Switch
3-Position
Selector Switch
Vacuum Fault
Interrupter (VFI)
Alternate Source
Main Source
Loop Feeder Loop Feeder
4-Position
T-Blade
Sectionalizing
Load-Break
Switch
Bay-O-Net
Expulsion Fuse
Partial Range
Current-Limiting Fuse
Primary Metal-Clad
Switchgear Lineup
Bus A Bus B
Feeder A1 Feeder B1
Primary Feeder Breaker
Feeder B2
Feeder A2
Primary Main Breaker
To Other
Substations
Typical Secondary Unit
Substation Duplex Primary
Switch/Fuses
Transformer/600V Class
Secondary Switchgear
52 52
52
52
52
52 52
NO
NC
NO
NC
NO
NC
31
Types of Systems

When a transformer fault or overload
occurs, the transformer primary fuses
open, and the transformer primary switch
manually opened, disconnecting the
transformer from the loop, and leaving
all other secondary unit substation loads
unaffected.
A basic primary loop system that
uses a single primary feeder breaker
connected directly to two loop feeder
switches which in turn then feed the
loop is shown in Figure 34. In this
basic system, the loop may be normally
operated with one of the loop section
alizing switches open as described above
or with all loop sectionalizing switches
closed. If a fault occurs in the basic
primary loop system, the single loop
feeder breaker trips, and secondary
loads are lost until the faulted conductor
is found and eliminated from the loop
by opening the appropriate loop
sectionalizing switches and then
reclosing the breaker.
Figure 34. Single Primary Feeder—
Loop System
3. Primary Selective System—
Secondary Radial System
The primary selective—secondary radial
system, as shown in Figure 33, differs
from those previously described in that
it employs at least two primary feeder
circuits in each load area. It is designed
so that when one primary circuit is out
of ser
vice, the remaining feeder or
feeders have sufficient capacity to carry
the total load. Half of the transformers
are normally connected to each of the
two feeders.When a fault occurs on one
of the primary feeders, only half of the
load in the building is dropped.
Duplex fused switches as shown in
Figure 33 and detailed in Figure 35 may be
utilized for this type of system. Each
duplex fused switch consists of two load
break three-pole switches each in their
own separate structure, connected
together by bus bars on the load side.
Typically, the load break switch closest to
the transformer includes a fuse assembly
with fuses.
Mechanical and/or key interlocking is
furnished such that both switches cannot
be closed at the same time (to prevent
parallel operation) and interlocking
such that access to either switch or fuse
assembly cannot be obtained unless both
switches are opened.
Figure 35. Duplex Fused Switch in
Two Structures
One alternate to the duplex switch
arrangement, a non-load break selector
switch mechanically interlocked with a
load break fused switch can be used as
shown in Figure 36.The non-load break
selector switch is physically located in the
rear of the load break fused switch, thus
only requiring one structure and a lower
cost and floor space savings over the
duplex arrangement.The non-load break
switch is mechanically interlocked to
prevent its operation unless the load
break switch is opened.The main
disadvantage of the selector switch is
that conductors from both circuits are
terminated in the same structure.
Figure 36. Fused Selector Switch in
One Structure
This means limited cable space especially
if double lugs are furnished for each line
as shown in Figure 33.The downside is
that should a faulted primary conductor
have to be changed, both lines would
have to be de-energized for safe changing
of the faulted conductors.
A second alternative is utilizing a three-
position selector switch internal to the
transformer, allowing only one primary
feeder to be connected to the transformer
at a time without the need for any inter
locking.The selector switch is rated for
load-breaking. If overcurrent protection is
also required, a vacuum fault interrupter
(VFI), also internal to the transformer, may
be utilized, reducing floor space.
In Figure 33 when a primary feeder fault
occurs, the associated feeder breaker
opens and the transformers normally
supplied from the faulted feeder are out
of service.Then manually, each primary
switch connected to the faulted line must
be opened and then the alternate line
primary switch can be closed connect
ing
the transformer to the live feeder, thus
restoring service to all loads. Note that
each of the primary circuit conductors for
Feeder A1 and B1 must be sized to handle
the sum of the loads normally connected
to both A1 and B1. Similar sizing of
Feeders A2 and B2, etc., is required.
If a fault occurs in one transformer, the
associated primary fuses blow and
interrupt the service to just the load
served by that transformer. Service
cannot be restored to the loads normally
served by the faulted transformer until
the transformer is repaired or replaced.
Cost of the primary selective—secondary
radial system is greater than that of
the simple primary radial system of
Figure 27 because of the additional
primary main breakers, tie breaker,
two-sources, increased number of feeder
breakers, the use of primary-duplex or
selector switches, and the greater amount
of primary feeder cable required.
The benefits from the reduction in the
amount of load lost when a primary feeder
is faulted, plus the quick restoration of
service to all or most of the loads, may
more than offset the greater cost.
Having two sources allows for either
manual or automatic transfer of the two
primary main breakers and tie breaker
should one of the sources become
unavailable.
Loop A Loop A
In cases where only one primary line
is available, the use of a single primary
breaker provides the loop connections
to the loads as shown here.
52
Primary
Feeders
Load Break
Switches
Fuses
Primary
Feeders
Non-Load Break
Selector Switches
Fuses
Load Break
Disconnect
Inter-
lock
Types of Systems

The primary selective-secondary radial
system, however, may be less costly
or more costly than a primary loop—
secondary radial system of Figure 29
depending on the physical location of the
transformers. It also offers comparable
downtime and reliability.The cost of
conductors for the types of systems may
vary depending on the location of the
transformers and loads within the facility.
The cost differences of the conductors
may offset cost of the primary switching
equipment.
4. Two-Source Primary—
Secondary Selective System
This system uses the same principle of
duplicate sources from the power supply
point using two primary main breakers
and a primary tie breaker.The two primary
main breakers and primary tie breaker
being either manually or electrically
interlocked to prevent closing all three at
the same time and paralleling the sources.
Upon loss of voltage on one source, a
manual or automatic transfer to the
alternate source line may be used to
restore power to all primary loads.
Each transformer secondary is arranged
in a typical double-ended unit substation
arrangement as shown in Figure 37.The
two secondary main breakers and
secondary tie breaker of each unit
substation are again either mechanically
or electrically interlocked to prevent
parallel operation. Upon loss of secondary
source voltage on one side, manual or
automatic transfer may be used to transfer
the loads to the other side, thus restoring
power to all secondary loads.
This arrangement permits quick restora-
tion of service to all loads when a primary
feeder or transformer fault occurs by
opening the associated secondary main
and closing the secondary tie breaker.
If the loss of secondary voltage has
occurred because of a primary feeder
fault with the associated primary feeder
breaker opening, then all secondary loads
normally served by the faulted feeder
would have to be transferred to the
opposite primary feeder.
This means each primary feeder conductor
must be sized to carry the load on both
sides of all the secondary buses it is
serving under secondary emergency
transfer If the loss of voltage was due to
a failure of one of the transformers in the
double-ended unit substation, then the
associated primary fuses would open
taking only the failed transformer out of
service, and then only the secondary loads
normally served by the faulted transformer
would have to be transferred to the
opposite transformer.
In either of the above emergency
conditions, the in-service transformer
of a double-ended unit substation would
have to have the capability of serving the
loads on both sides of the tie breaker. For
this reason, transform
ers used in this
application must have equal kVA ratings
on each side of the double-ended unit
substation.The transformers are sized
so the normal operating maximum load
on each transformer is typically about
2/3 base nameplate kVA rating.
Typically these transformers are furnished
with fan-cooling and/or lower than
normal temperature rise such that
under emergency conditions they can
continuously carry the maximum load
on both sides of the secondary tie breaker.
Because of this spare transformer capacity,
the voltage regulation provided by the
double-ended unit substation system
under normal conditions is better than
that of the systems previously discussed.
The double-ended unit substation
arrangement can be used in conjunction
with any of the previous systems
discussed, which involve two primary
sources. Although not recommended,
if allowed by the utility, momentary
re-transfer of loads to the restored
source may be made closed transition
(anti-parallel interlock schemes would
have to be defeated) for either the
primary or secondary systems.
Under this condition, all equipment
interrupt
ing and momentary ratings
should be suitable for the fault current
available from both sources.
For double-ended unit substations
equipped with ground fault systems
special consideration to transformer
neutral grounding and equipment
operation should be made—see
Grounding/Ground Fault Protection
section of this Design Guide.Where
two single-ended unit substations
are connected together by busway
or external tie conductors, it is
recommended that a tie breaker
be furnished at each end of the tie
conductors.The second tie breaker
provides a means to isolate the
interconnection between the two
single-ended substations for
maintenance or servicing purposes.
.
Figure 37. Two-Source Primary—Secondary Selective System
Primary Main Breakers
Primary Feeder Breakers
To Other Substations
To Other Substations
Secondary Main Breaker
Tie Breaker
Primary Fused Switch Transformer
Typical
Double-Ended
Unit
Substation
52 52
52
52 52 52 52
33
Types of Systems

5. Sparing Transformer System
The sparing transformer system concept
came into use as an alternative to the
capital cost intensive double-ended
secondary unit substation distribution
system (seeTwo-Source Primary—
Secondary Selective System). It essen
tially replaces double-ended substations
with single-ended substations and one or
more “sparing” transformer substa
tions
all interconnected on a common
secondary bus—see Figure 38.
Generally no more than three to five
single-ended substations are on a
sparing loop.
The essence of this design philosophy is
that conservatively designed and loaded
transformers are highly reliable electrical
devices and rarely fail.There
fore, this
design provides a single com
mon backup
transformer for a group of transformers
in lieu of a backup trans
former for each
and every transformer.This system
design still maintains a high degree of
continuity of service.
Referring to Figure 38, it is apparent that
the sparing concept backs up primary
switch and primary cable failure as well.
Restoration of lost or failed utility power
is accomplished similarly to primary
selective scheme previously discussed. It
is therefore important to use an automatic
throw-over system in a two source lineup
of primary switchgear to restore utility
power as discussed in the “Two-Source
Primary” scheme—see Figure 37.
A major advantage of the sparing
transformer system is the typically lower
total base kVA of transformation. In a
double-ended substation design, each
transformer must be rated to carry the
sum of the loads of two buses and usually
requires the addition of cooling fans to
accomplish this rating. In the “sparing”
concept, each transformer carries only
its own load, which is typically not a
fan-cooled rating. In addition to first
cost savings, there is a side benefit of
reduced equipment space.
The sparing transformer system operates
as follows:
■ All main breakers, including the sparing
main breaker, are normally closed; the
tie breakers are normally open
■ Once a transformer (or primary cable
or primary switch/fuse) fails, the
associated secondary main breaker is
opened.The associated tie breaker is
then closed, which restores power to
the single-ended substation bus
■ Schemes that require the main to
be opened before the tie is closed
(“open transition”), and that allow any
tie to be closed before the substation
main is opened, (“closed transition”)
are possible
With a closed transition scheme, it is
common to add a timer function that
opens the tie breaker unless either main
breaker is opened within a time interval.
This closed transition allows power to
be transferred to the sparing transformer
without interruption, such as for routine
maintenance, and then back to the
substation.This closed transition transfer
has an advantage in some facilities;
however, appropriate interrupting
capacities and bus bracing must be
specified suitable for the momentary
parallel operation.
In facilities without qualified electrical
power operators, an open transition with
key interlocking is often a prudent design.
Note: Each pair of “main breaker/tie breaker”
key cylinders should be uniquely keyed to
prevent any paralleled source operations.
Careful sizing of these transformers
as well as careful specification of the
transformers is required for reliability.
Low temperature rise specified with
continuous overload capacity or
upgraded types of transformers should
be considered.
One disadvantage to this system is
the external secondary tie system, see
Figure 38. As shown, all single-ended
substations are tied together on the
secondary with a tie busway or cable
system. Location of substations is
therefore limited because of voltage
drop and cost considerations.
Routing of busway, if used, must be
carefully layed out. It should also be
noted, that a tie busway or cable fault will
essentially prevent the use of the sparing
transformer until it is repaired. Commonly,
the single-ended substa
tions and the
sparing transformer must be clustered.
This can also be an advantage, as more
kVA can be supported from a more
compact space layout.
Figure 38. Sparing Transformer System
K
K K
K K
K K
Sparing Transformer
Typical Secondary Busway Loop
Typical Single-Ended Substation
Types of Systems

6. Simple Spot Network Systems
The ac secondary network system is the
system that has been used for many years
to distribute electric power in the high-
density, downtown areas of cities, usually
in the form of utility grids. Modifications
of this type of system make it applicable
to serve loads within buildings.
The major advantage of the secondary
network system is continuity of service.
No single fault anywhere on the primary
system will interrupt service to any of the
system’s loads. Most faults will be cleared
without interrupting service to any load.
Another outstanding advantage that the
network system offers is its flexibil
ity
to meet changing and growing load
conditions at minimum cost and minimum
interruption in service to other loads on
the network. In addition to flexibility and
service reliability, the secondary network
system provides exceptionally uniform
and good voltage regulation, and its high
efficiency materially reduces the costs of
system losses.
Three major differences between the
network system and the simple radial
system account for the outstanding
advantages of the network. First, a
network protector is connected in the
secondary leads of each network
transformer in place of, or in addition
to, the secondary main breaker, as shown
in Figure 39. Also, the secondaries
of each transformer in a given location
(spot) are connected together by a
switchgear or ring bus from which the
loads are served over short radial feeder
circuits. Finally, the primary supply has
sufficient capacity to carry the entire
building load with
out overloading when
any one primary feeder is out of service.
A network protector is a specially
designed heavy-duty air power breaker,
spring close with electrical motor-charged
mechanism, with a network relay to
control the status of the protector
(tripped or closed).
The network relay is usually a solid-state
microprocessor-based component
integrated into the protector enclosure
that functions to automatically close
the protector only when the voltage
conditions are such that its associated
transformer will supply power to the
secondary network loads. It also serves
to automatically open the protector when
power flows from the secondary to the
network transformer.
The purpose of the network protector is
to protect the integrity of the network
bus voltage and the loads served from it
against transformer and primary feeder
faults by quickly disconnecting the
defective feeder-transformer pair from
the network when backfeed occurs.
The simple spot network system
resembles the secondary-selective radial
system in that each load area is supplied
over two or more primary feeders through
two or more trans
formers. In network
systems, the transformers are connected
through network protectors to a common
bus, as shown in Figure 39, from
which loads are served. Because the
transformers are connected in parallel,
a primary feeder or transformer fault
does not cause any service interrup
tion
to the loads.
The paralleled transformers supplying
each load bus will normally carry equal
load currents, whereas equal loading of
the two separate transformers supplying
a substation in the secondary-selective
radial system is difficult to obtain.The
interrupting duty imposed on the out
going
feeder breakers in the network will be
greater with the spot network system.
The optimum size and number of primary
feeders can be used in the spot network
system because the loss of any primary
feeder and its associated transformers
does not result in the loss of any load
even for an instant. In spite of the spare
capacity usually supplied in network
systems, savings in primary switch
gear
and secondary switchgear costs often
result when compared to a radial system
design with similar spare capacity.
This occurs in many radial systems
because more and smaller feeders
are often used in order to minimize the
extent of any outage when a primary
fault event occurs.
In spot networks, when a fault occurs on
a primary feeder or in a transformer, the
fault is isolated from the system through
the automatic tripping of the primary
feeder circuit breaker and all of the
network protectors associated with that
feeder circuit.This operation does not
interrupt service to any loads. After the
necessary repairs have been made, the
system can be restored to normal
operating conditions by closing the
primary feeder breaker. All network
protectors associated with that feeder
will close automatically.
The chief purpose of the network bus
normally closed ties is to provide for the
sharing of loads and a balancing
of load currents for each primary
service and transformer regardless of
the condition of the primary services.
Also, the ties provide a means for
isolating and sectionalizing ground fault
events within the switchgear network bus,
thereby saving a portion of the loads from
service interruptions, yet isolating the
faulted portion for corrective action.
The use of spot network systems provides
users with several important advantages.
First, they save trans
former capacity.
Spot networks permit equal loading of
transformers under all conditions. Also,
networks yield lower system losses and
greatly improve voltage conditions.
Figure 39. Three-Source Spot Network
Customer
Loads
Customer
Loads
Customer
Loads
NC NC
Tie
Tie
Typical Feeder
To Other
Networks
Drawout
Low-Voltage
Switchgear
Fuses
Primary Circuit
Network Transformer
Network Protector
Optional Main, 50/51
Relaying and/or
Network Disconnect
LV Feeder
35
Types of Systems

The voltage regulation on a network
system is such that both lights and
power can be fed from the same load
bus. Much larger motors can be started
across-the-line than on a simple radial
system.This can result in simplified motor
control and permits the use of relatively
large low voltage motors with their less
expensive control.
Finally, network systems provide a
greater degree of flexibility in adding
future loads; they can be connected to
the closest spot network bus.
Spot network systems are economical for
buildings that have heavy concen
trations
of loads covering small areas, with
considerable distance between areas,
and light loads within the distances
separating the concentrated loads.They
are commonly used in hospitals, high rise
office buildings, institutional buildings
or laboratories where a high degree of
service reliabil
ity is required from the
utility sources. Spot network systems
are especially economical where three
or more primary feeders are available.
Principally, this is due to supplying
each load bus through three or more
transformers and the reduction in spare
cable and transformer capacity required.
They are also economical when
compared to two transformer double-
ended substations with normally opened
tie breakers.
Emergency power should be connected
to network loads downstream from the
network, or upstream at primary voltage,
not at the network bus itself.
7. Medium-Voltage Distribution
System Design
A. Single Bus, Figure 40
The sources (utility and/or generator(s))
are connected to a single bus. All feeders
are connected to the same bus.
This configuration is the simplest system;
however, outage of the utility results in
total outage.
Normally the generator does not have
adequate capacity for the entire load.
A properly relayed system equipped
with load shedding, automatic voltage/
frequency control may be able to
maintain partial system operation.
Any future addition of breaker sections to
the bus will require a shutdown of the
bus, because there is no tie breaker.
Figure 40. Single Bus
B. Single Bus withTwo Sources from
the Utility, Figure 41
Same as the single bus, except that two
utility sources are available.This system is
operated normally with the main breaker
to one source open. Upon loss of the
normal service, the transfer to the standby
normally open (NO) breaker can be
automatic or manual. Automatic transfer
is preferred for rapid service restoration
especially in unattended stations.
Retransfer to the “Normal” can be closed
transition subject to the approval of the
utility. Closed transition momen
tarily
(5–10 cycles) parallels both utility sources.
Caution: when both sources are paralleled,
the fault current available on the load
side of the main device is the sum of the
available fault current from each source
plus the motor fault contribution. It is
recommended that the short-circuit ratings
of the bus, feeder breakers and all load
side equipment are rated for the increased
available fault current.
If the utility requires open transfer, the
disconnection of motors from the bus
must be ensured by means of suitable
time delay on reclosing as well as
supervision of the bus voltage and its
phase with respect to the incoming
source voltage.
This busing scheme does not preclude the
use of cogeneration, but requires the use
of sophisticated automatic syn
chronizing
and synchronism checking controls, in
addition to the previously mentioned
load shedding, automatic frequency and
voltage controls.
This configuration is more expensive
than the scheme shown in Figure 40, but
service restoration is quicker. Again,
a utility outage results in total outage to
the load until transfer occurs. Extension
of the bus or adding breakers requires a
shutdown of the bus.
If paralleling sources, reverse current,
reverse power and other appropriate
relaying protection should be added as
requested by the utility.
Figure 41. Single Bus with Two-Sources
52
Utility
Main Bus
G
One of Several Feeders
52
52
Utility #2
Utility #1
Normal Standby
NC NO
Loads
52 52
Types of Systems

C. Multiple Sources withTie Breaker,
Figure 42 and Figure 43
This configuration is similar to the
configuration shown in Figure 41.
It differs significantly in that both utility
sources normally carry the loads and also
by the incorporation of a normally open
tie breaker.The outage to the system load
for a utility outage is limited to half of
the system. Again, the closing of the tie
breaker can be manual or automatic.The
statements made for the retransfer of the
configu
ration shown in Figure 41 apply to
this scheme also.
Figure 42. Two-Source Utility with
Tie Breaker
If looped or primary selective distribution
system for the loads is used, the buses
can be extended without a shutdown by
closing the tie breaker and transferring
the loads to the other bus.
This configuration is more expensive
than the configuration shown in
Figure 41.The system is not limited
to two buses only. Another advantage
is that the design may incorporate
momentary paralleling of buses on
retransfer after the failed line has been
restored to prevent another outage.
See the Caution for Figure 41,
Figure 42 and Figure 43.
In Figure 43, closing of the tie breaker
following the opening of a main breaker
can be manual or auto
matic. However,
because a bus can be fed through two tie
breakers, the control scheme should be
designed to make the selection.
The third tie breaker allows any bus to be
fed from any utility source.
Caution for Figure 41,
Figure 42 and Figure 43:
If continuous paralleling of sources is
planned, reverse current, reverse power
and other appropriate relaying protection
should be added.When both sources are
paralleled for any amount of time, the
fault current available on the load side of
the main device is the sum of the
available fault current from each source
plus the motor fault contribution. It is
required that bus bracing, feeder breakers
and all load side equipment is rated for
the increased available fault current.
Summary
The medium-voltage system configu
rations shown are based on using
metal-clad drawout switchgear.The
service continuity required from electrical
systems makes the use of single-source
systems impractical.
In the design of a modern medium-
voltage system, the engineer should:
1. Design a system as simple as possible.
2. Limit an outage to as small a portion
of the system as possible.
3. Provide means for expanding the
system without major shutdowns.
4. Design a protective relaying
system so that only the faulted
part is removed from service, and
damage to it is minimized consistent
with selectivity.
5. Specify and apply all equipment
within its published ratings and
national standards pertaining to
the equipment and its installation.
Figure 43. Triple-Ended Arrangement
Utility #1
NC
Bus #1 Bus #2
Load Load
Utility #2
NC
NO
52 52
52
52 52
NO
NC
Bus #1 Bus #2
Utility #1 Utility #2
NC
NO NO
Utility #3
Bus #3
NC
Tie Busway
52 52 52
52
52
52
52 NO
Typical Feeder
52 52
52
37
Types of Systems

Systems Analysis
A major consideration in the design of
a distribution system is to ensure that it
provides the required quality of service to
the various loads.This includes: serving
each load under normal conditions, under
abnormal conditions and providing the
desired protection to service and system
apparatus so that interruptions of service
are minimized.
Under normal conditions, the important
technical factors include voltage profile,
losses, load flow, effects of motor
starting, service continuity and reliability.
The prime considerations under faulted
conditions are apparatus protection, fault
isolation service continuity and of course
personnel safety.
During the system preliminary planning
stage, before selection of the distribution
apparatus, several distribution systems
should be analyzed and evaluated,
including both economic and technical
factors. During this stage, if system
size or complexity warrant, it may be
appropriate to provide a thorough review
of each system under both normal and
abnormal conditions.
This type of dynamic analysis is typically
done using Computer Simulation
Software. Selection of components such
as circuit breakers, cables, transformers,
equipment motors and generators are
entered into a power flow one-line of the
system. Changes to these variables,
including the type of breaker as well as its
trip unit settings, the size and length of
conductors, the hp of motors and kVA
of transformers and generators, can
be adjusted to reflect the impact this
will have on the short-circuit energy
available at various points in the power
The principal types of computer
programs used to provide system
studies include:
■ Short circuit—identify three-phase
and line-to-ground fault currents and
system impedances
■ Arc flash—calculates arc flash energy
levels, which leads to the proper
selection of personal protective
equipment (PPE)
■ Circuit breaker duty—identify
asymmetrical fault current based
on X/R ratio
■ Protective device coordination—
determine characteristics and set
tings
of medium voltage protective relays
and fuses, and entire low voltage circuit
breaker and fuse coordination
■ Load flow—simulate normal and
abnormal load conditions of system
voltages, power factor, line and
transformer loadings
■ Motor starting—identify system
voltages, motor terminal voltage,
motor accelerating torque, and
motor accelerating time when
starting large motors
Short-circuit calculations define
momentary and steady-state fault
currents for specific points in the electrical
system.This information is used to select
protective devices and to determine
required equipment bus bracing and
withstand levels.These calculations are
generated for both normal, emergency
and alternative system configurations.
Computer software programs can
identify the fault current at any bus in
the distribution system under any
number of scenarios of source and load
combinations. It is often necessary to
evaluate the distribution system in all the
possible operating states of sources and
loads to understand available fault
currents in all possible states.The results
of these calculations permit optimizing
service to the loads while properly
applying distribution appara
tus within
their intended limits.
Articles 110.21(B) and 110.24 of 2014
National Electrical Code (NEC) have
increased the field-applied available
fault current marking requirements for
electrical equipment. Article 110.24(A)
states: “Service equipment in other than
dwelling units shall be legibly marked in
the field with the maximum available fault
current.The field mark
ing(s) shall include
the date the fault-current calculation was
performed and be of sufficient durability
to withstand the environment involved.
”
Article 110.24(B) then takes this a step
further stating: “When modifications to
the electrical installation occur that affect
the maximum available fault current at
the service, the maximum available fault
current shall be verified or recal
culated as
necessary.The required field marking(s)
in 110.24(A) shall be adjusted to reflect
the new level of maximum available
fault current.
”
The following additional studies should
be considered depending upon the
type and complexity of the distribution
system, the type of facility and the type
of loads to be connected to the system:
■ Harmonic analysis
■ Transient stability
■ Insulation coordination
■ Grounding study
■ Switching transient
The Power Systems EngineeringTeam
within Eaton’s Electrical Services &
Systems division can provide any of the
system studies discussed in this section.
Short-Circuit Currents—
General
The amount of current available in a
short-circuit fault is determined by the
capacity of the system voltage sources
and the impedances of the system,
including the fault.Voltage sources
include the power supply (utility or
on-site generation) plus all rotating
machines connected to the system at the
time of the fault, and are not connected
through power conversion equipment
such as variable frequency drives.
A fault may be either an arcing or bolted
fault. In an arcing fault, part of the circuit
voltage is consumed across the arc and
the total fault current is somewhat smaller
than for a bolted fault.The bolted fault
condition results in the highest fault
magnitude fault currents, and therefore is
the value sought in the fault calculations.
Basically, the short-circuit current is
determined by applying Ohm’s Law to
an equivalent circuit consisting of a
constant voltage source and a time-
varying impedance. A time-varying
impedance is used in order to account for
the changes in the effective voltages of
the rotating machines during the fault.
In an AC system, the resulting short-
circuit current starts out higher in
magnitude than the final steady-state
value and asymmetrical (due to the DC
offset) about the X-axis.The current then
decays toward a lower symmetrical
steady-state value.
Power System Analysis

The time-varying characteristic of the
impedance accounts for the symmetrical
decay in current.The ratio of the
reactive and resistive components
(X/R ratio) accounts for the DC decay,
see Figure 44.The fault current consists of
an exponentially decreasing direct-
current component superimposed upon a
decaying alternating-current.
The rate of decay of both the DC and AC
components depends upon the ratio of
reactance to resistance (X/R) of the circuit.
The greater this ratio, the longer the
current remains higher than the steady-
state value that it would eventually reach.
The total fault current is not symmetrical
with respect to the time-axis because of
the direct-current component, hence it is
called asymmetrical current.The DC
component depends on the point on the
voltage wave at which the fault is initiated.
See Figure 45 for multiplying factors that
relate the rms asymmetrical value of total
current to the rms symmetrical value, and
the peak asymmetrical value of total
current to the rms symmetrical value.
The AC component is not constant if
rotating machines are connected to the
system because the impedance of this
apparatus is not constant.The rapid
variation of motor and generator
impedance is due to these factors:
Subtransient reactance (Xd
), deter
mines
fault current during the first cycle, and
after about 6 cycles this value increases to
the transient reactance. It is used for the
calculation of the momentary interrupting
and/or momentary withstand duties of
equipment and/or system.
Transient reactance (Xd
), which
determines fault current after about
6 cycles and this value in 1/2 to 2 seconds
increases to the value of the synchronous
reactance. It is used in the setting of the
phase overcurrent relays of generators
and medium-voltage circuit breakers.
Synchronous reactance (Xd
), which
determines fault current after steady-
state condition is reached. It has no
effect as far as short-circuit calculations
are concerned, but is useful in the
determination of relay settings.
Transformer impedance, in percent, is
defined as that percent of rated primary
voltage that must be applied to the
transformer to produce rated current
flowing in the secondary, with the
secondary shorted through zero
resistance. It is important to note that
the transformer percent impedance is
a per-unit value typically expressed on
the base kVA rating of the transformer.
Therefore, it is not necessary to calcu
late
maximum fault current produced at
the fan-cooled rating or the higher
temperature rise kVA ratings because the
per-unit impedance at those kVA ratings
increases by the same ratio, making the
fault current calculation results the same.
Therefore, assuming the primary voltage
can be sustained (generally referred to
as an infinite or unlimited supply), the
maximum current a transformer can
deliver to a fault condition is the quantity
of (100 divided by percent impedance)
times the transformer rated secondary
current. Limiting the power source fault
capacity to the transformer primary will
thereby reduce the maximum fault
current from the transformer secondary.
The electric network that determines the
short-circuit current consists of an AC
driving voltage equal to the pre-fault
system voltage and an impedance
corresponding to that observed when
looking back into the system from the
fault location.
In industrial medium- and high-voltage
work, it is generally satisfactory to regard
reactance as the entire imped
ance;
resistance may be neglected. However,
this is normally permissible only if the
X/R ratio of the medium voltage system
is equal to or more than 25.
In low-voltage (1000V and below)
calculations, it is usually worthwhile to
attempt greater accuracy by including
resistance with reactance in dealing
with impedance. It is for this reason,
plus ease of manipulating the various
impedances of cables and buses and
transformers of the low-voltage circuits,
that computer studies are recommended
before final selection of apparatus and
system arrangements.
When evaluating the adequacy of
short-circuit ratings of medium voltage
circuit breakers and fuses, both the rms
symmetrical value and asymmetrical
value of the short-circuit current should
be determined.
For low-voltage circuit breakers and
fuses, the rms symmetrical value should
be determined along with either: the
X/R ratio of the fault at the device or the
asymmetrical short-circuit current.
Figure 44. Structure of an Asymmetrical Current Wave
3.0
2.5
2.0
1.5
1.0
0.5
0
0.5
–1.0
–1.5
–2.0
Total Current—A Wholly Offset
Asymmetrical Alternating Wave
rms Value of Total Current
Alternating Component -
Symmetrical Wave
rms Value of
Alternating Component
Direct Component—The Axis
of Symmetrical Wave Time in Cycles of
a 60 Hz Wave
1 2 3 4
Scale
of
Curent
Values
39

Fault Current Waveform
Relationships
The following Figure 45 describes the
relationship between fault current peak
values, rms symmetrical values and rms
asymmetrical values depending on the
calculated X/R ratio.The table is based on
the following general formulas:
1.
2.
Where:
I = Symmetrical rms current
Ip
= Peak current
e = 2.718
w = 2 p f
f = Frequency in Hz
t =Time in seconds
Based on a 60 Hz system and t = 1/2 cycle (ANSI/IEEE C37.13.2015)
Peak multiplication factor =
rms multiplication factor =
Example for X/R =15
Figure 45. Relation of X/R Ratio to Multiplication Factor
2.8
2.7
2.6
2.5
2.4
2.3
2.2
2.1
2.0
1.9
1.8
1.7
1.6
1.5
1.4
1.5
1 2 2.5 3 4 5 6 7 8 9 10 15 20 25 30 40 50 60 70 80 90 100
1.8
1.7
1.6
1.5
1.4
1.3
1.2
1.1
P
E
A
K
M
U
L
T
I
P
L
I
C
A
T
I
O
N
F
A
C
T
O
R
RMS MULTIPLICATION
FACTOR
CIRCUIT X/R RATIO (TAN PHASE)
Based Upon: rms Asym = DC2
+ rms Sym2
with DC Value
Taken at Current Peak
RMS
MULTIPLICATION
FACTOR
=
RMS
MAXIMUM
ASYMMETRICAL
RMS
SYMMETRICAL
PEAK
MULTIPLICATION
FACTOR
=
PEAK
MAXIMUM
ASYMMETRICAL
RMS
SYMMETRICAL

Fault Current Calculations
The calculation of asymmetrical currents
is a laborious procedure since the degree
of asymmetry is not the same on all three
phases. It is common practice for medium
voltage systems, to calculate the rms
symmetrical fault current, with the
assumption being made that the DC
component has decayed to zero, and then
apply a multi
plying factor to obtain the
first half-cycle rms asymmetrical current,
which is called the “momentary current.
”
For medium-voltage systems (defined
by IEEE as greater than 1000V up to
69,000 V) the multiplying factor is
established by NEMAT and ANSI
standards depending upon the
operating speed of the breaker.
For low-voltage systems, short-circuit
study software usually calculates the
symmetrical fault current and the faulted
system X/R ratio using UL and ANSI
guidelines. If the X/R ratio is within the
standard (lower than the breaker test
X/R ratio), and the breaker interrupting
current is under the symmetrical fault
value, the breaker is properly rated.
If the X/R ratio is higher than UL or ANSI
standards, the study applies a multiplying
factor to the symmetrical calculated value
(based on the X/R value of the system
fault) and compares that value to the
breaker symmetrical value to assess if
it is properly rated.
In the past, especially using manual
calculations, a multiplying factor of 1.35
(based on the use of an X/R ratio of 6.6
representing a source short-circuit power
factor of 15%) was used to calculate
the asymmetrical current.These values
take into account that medium voltage
breakers are rated on maximum
asymmetry and low voltage breakers
are rated average asymmetry.
To determine the motor contribution
during the first half-cycle fault current,
when individual motor horsepower load
is known, the subtransient reactances
found in the IEEE Red Book should be
used in the calculations.
For motors fed through adjustable
frequency drives or solid-state soft
starters, there is no contribution to
fault current, unless 1) they have an
internal run contactor or 2) they have
a bypass contactor.
When the motor load is not known, the
following assumptions generally are
made.The following percentage estimates
are based on design load or transformer
nameplate rating, when known.
208Y/120V Systems
■ Assume 50% lighting and 50%
motor load
or
■ Assume motor feedback contribu
tion
of twice full load current of transformer
or
240/480/600VThree-Phase,
Three-Wire or Four-Wire Systems
■ Assume 100% motor load
or
■ Assume motors 25% synchronous
and 75% induction
or
tion
of four times full load current
of transformer
480Y/277V Systems in
Commercial Buildings
■ Assume 50% induction motor load
or
tion
of two times full load current of
transformer or source
Medium-Voltage Motors
If known, use actual values otherwise
use the values indicated for the same
type of motor.
Calculation Methods
The following pages describe various
methods of calculating short-circuit
currents for both medium- and low-
voltage systems. A summary of the
types of methods and types of
calculations is as follows:
■ Medium-voltage switchgear—
exact method. . . . . . . . . . . . . . . Page 42
■ Medium-voltage switchgear—
quick check table . . . . . . . . . . . . Page 45
■ Medium-voltage switchgear
Example 1—verify ratings of
breakers. . . . . . . . . . . . . . . . . . . Page 46
Example 2—verify ratings
of breakers with rotating
loads. . . . . . . . . . . . . . . . . . . . . . Page 47
Example 3—verify ratings
of breakers with
generators. . . . . . . . . . . . . . . . . Page 48
■ Medium-voltage fuses—
exact method. . . . . . . . . . . . . . . Page 48
■ Power breakers—asymmetry
derating factors. . . . . . . . . . . . . Page 49
■ Molded case breakers—
asymmetry derating
factors. . . . . . . . . . . . . . . . . . . . . Page 50
■ Short-circuit calculations—
short cut method for
a system. . . . . . . . . . . . . . . . . . . Page 51
■ Short-circuit calculations—
short cut method for
end of cable . . . . . . . . . . . . . . . . Page 55
■ Short-circuit currents—
chart of transformers
300–3750 kVA. . . . . . . . . . . . . . Page 139
41

Fault Current Calculations
for Specific Equipment—
Exact Method
The purpose of the fault current calcu
lations is to determine the fault current
at the location of a circuit breaker, fuse
or other fault interrupting device in order
to select a device adequate for the
calculated fault current or to check the
thermal and momentary ratings of non-
interrupting devices.When the devices to
be used are ANSI-rated devices, the fault
current must be calculated and the device
selected as per ANSI standards.
The calculation of available fault
current and system X/R rating is also
used to verify adequate bus bar bracing
and momentary withstand ratings of
devices such as contactors.
Medium-Voltage VCP-W
Metal-Clad Switchgear
MVA breaker ratings first originated
many years ago to describe the preferred
ratings of air-magnetic circuit breakers
that had published short-circuit current
interruption ratings based on their
rated maximum voltage.These
breakers, however, could achieve
higher interruption ratings at lower
operating voltages until the maximum
interruption rating was exceeded.
The ratio of these two interruption ratings
is called rated voltage range indicator (K).
The rated voltage range indicator, K, is
greater than 1 for MVA rated breakers.
For example, an Eaton 150VCP-W 500,
(15 kV – 500 MVA rated breaker with a
K=1.30 rating has a published interruption
rating of 18 kA at 15 kV, but has a
maximum interrup
tion rating of 23 kA
(18 kA x 1.30) at 11.5 kV (15 kV divided
by 1.30).
As new vacuum interrupting technologies
were developed, scientists discovered
that reducing the operating voltage did
not increase the short-circuit current
interrupting capability of new interrupters.
In fact, as the operating voltage is
reduced, the short-circuit current inter-
rupting capability changes only little.
There
fore the MVA (K >1.0) basis of rating
no longer accurately reflected the true
interrupting characteristics of the newer
circuit breaker designs.
Ultimately, as vacuum circuit breakers
became more and more prevalent in the
industry, the IEEE C37.06-2000 standard
was published to recognize both MVA
and K = 1 rated breakers.
The following is a review of the meaning
of the ratings. Additional information on
this topic can be found in the VacClad-W
Metal-Clad Switchgear Design Guides.
The Rated MaximumVoltage
This designates the upper limit of design
and operation of a circuit breaker. For
example, a circuit breaker with a 4.76 kV
rated maximum voltage cannot be used
in a 4.8 kV system.
K-RatedVoltage Factor
The rated voltage divided by this factor
determines the system kV a breaker can
be applied up to the short-circuit kVA
rating calculated by the formula
Note: Interrupting capabilities of some of
today’s vacuum breakers may have K=1,
whereby the interrupting current is constant
across its entire operating range.
Rated Short-Circuit Current
For K = 1 breakers, this is the symmetri
cal
current that a breaker can interrupt across
it’s operational range.With MVA rated
breakers (K >1), this is the symmetrical
rms value of current that the breaker can
interrupt at rated maximum voltage. For
example, with an Eaton 50VCP-W 250
circuit breaker, it should be noted that the
product x 4.76 x 29,000 = 239,092 kVA
is less than the nominal 250,000 kVA
listed.This rating (29,000 A) is also the
base quantity that all the “related”
capabili
ties are referred to.
Maximum Symmetrical
Interrupting Capability
With K=1 breakers, the short-time
withstand current and the maximum
symmetrical interrupting current are
equal to the rated symmetrical
interrupting current. For MVA rated
breakers (K >1), this is expressed in rms
symmetrical amperes or kiloamperes
and is K x I rated; 1.24 x 29,000 = 35,960
rounded to 36 kA.
This is the rms symmetrical current
that the breaker can interrupt down
to a voltage equal to maximum rated
voltage divided by K (for example,
4.76/1.24 = 3.85). If this breaker is applied
in a system rated at 2.4 kV, the calculated
fault current must be less than 36 kA.
For example, consider the following case:
Assume a 12.47 kV system with 20,000 A
symmetrical available. In order to
determine if an EatonType 150VCP-W 500
vacuum breaker is suitable for this
application, check the following:
From the Standard Metal-Clad
SwitchgearAssembly Ratings table,
found in the Eaton VacClad-W Design
Guides, under column “Rated Maximum
Voltage”V = 15 kV, under column “Rated
short-circuit Current” I = 18 kA, “Rated
Voltage Range Factor” K = 1.3.
Test 1 forV/Vo x I or 15 kV/12.47 kV x
18 kA = 21.65; also check K x I (which is
shown in the column headed “Maximum
Symmetrical Interrupting Capability”)
or 1.3 x 18 kA = 23.4 kA. Because both of
these numbers are greater than the
available system fault current of 20,000 A,
the breaker is acceptable (assumes the
breaker’s momentary and fault close
rating is also acceptable).
Note: If the system available fault current were
22,000 A symmetrical, this breaker could not be
used even though the “Maximum Symmetrical
Interrupting Capability” is greater than 22,000
becauseTest 1 calculation is not satisfied.
For approximate calculations, Table 6
provides typical values of % reactance
(X) and X/R values for various rotating
equipment and transformers. For
sim
plification purposes, the transformer
impedance (Z) has been assumed to
be primarily reactance (X). In addition,
the resistance (R) for these simplified
cal
culations has been ignored. For
detailed calculations, the values from
the IEEE Red Book Standard 141, for
rotating machines, and ANSI C57 and/or
C37 for transformers should be used.

Table 6. Reactance X
System
Component
Reactance X Used for TypicalValues and Range
on Component Base
Short-Circuit
Duty
Close and Latch
(Momentary) % Reactance X/R Ratio
Two-pole turbo generator
Four-pole turbo generator
X
X
X
X
9 (7–14)
15 (12–17)
80 (40–120)
80 (40–120)
Hydro generator with damper wedges
and synchronous condensers
X X 20 (13–32) 30 (10–60)
Hydro generator without
damper windings
0.75X 0.75X 16 (16–50) 30 (10–60)
All synchronous motors 1.5X 1.0X 20 (13–35) 30 (10–60)
Induction motors above 1000 hp,
1800 rpm and above 250 hp, 3600 rpm
1.5X 1.0X 17 (15–25) 30 (15–40)
All other induction motors
50 hp and above
3.0X 1.2X 17 (15–25) 15 (2–40)
Induction motors below 50 hp
and all single-phase motors
Neglect Neglect — —
Distribution system from
remote transformers
X X As specified
or calculated
15 (5–15)
Current limiting reactors X X As specified
or calculated
80 (40–120)
Transformers
ONAN to 10 MVA, 69 kV X X 8.0 18 (7–24)
ONAN to 10 MVA, above 69 kV X X 8.0 to 10.5
Depends
on primary
windings
BIL rating
18 (7–24)
OFAF 12–30 MVA X X 20 (7–30)
OFAF 40–100 MVA X X 38 (32–44)
Table 7. Typical System X/R Ratio Range (for Estimating Purposes)
Type of Circuit X/R Range
Remote generation through other types of circuits such as transformers rated 10 MVA
or smaller for each three-phase bank, transmission lines, distribution feeders, etc.
15 or less
Remote generation connected through transformer rated 10 MVA to 100 MVA for each
three-phase bank, where the transformers provide 90% or more of the total equivalent
impedance to the fault point
15–40
Remote generation connected through transformers rated 100 MVA or larger for each
three-phase bank where the transformers provide 90% or more of the total equivalent
impedance to the fault point
30–50
Synchronous machines connected through transformers rated 25–100 MVA for each
three-phase bank
30–50
Synchronous machines connected through transformers rated 100 MVA and larger 40–60
Synchronous machines connected directly to the bus or through reactors 40–120
The Close and Latch Capability
K = 1 and K >1 breakers also differ in the
calculations for the breaker’s close and
latch rating.With K = 1 breakers, this is
a calculated peak value using 2.6 x the
breaker’s symmetrical interrupting rating.
For MVA rated breakers (K >1), this is
also a related quantity expressed in rms
asymmetri
cal amperes by 1.6 x maximum
symmetrical interrupting capability.
For example, 1.6 x 36 = 57.6 or 58 kA,
or 1.6 K x rated short-circuit current.
Another way of expressing the close and
latch rating is in terms of the peak current,
which is the instantaneous value of the
current at the crest. ANSI Standard C37
.09
indicates that the ratio of the peak to rms
asymmetrical value for any asymmetry
of 100% to 20% (percent asymmetry is
defined as the ratio of DC component of
the fault in per unit to ) varies not more
than ±2% from a ratio of 1.69.Therefore,
the close and latch current expressed
in terms of the peak amperes is = 1.6 x
1.69 x K x rated short-circuit current.
In the calculation of faults for the purposes
of breaker selection, the rotating machine
impedances specified in ANSI Standard
C37.010 Article 5.4.1 should be used.
The value of the impedances and their
X/R ratios should be obtained from
the equipment manufacturer. At initial
short-circuit studies, data from manufac-
turers is not available.Typical values of
imped
ances and their X/R ratios are given
in Table 6.
The ANSI Standard C37.010 allows the
use of the X values only in determin
ing
the E/X value of a fault current.The
R values are used to determine the
X/R ratio, in order to apply the proper
multiplying factor, to account for the
total fault clearing time, asymmetry,
and decrement of the fault current.
43

The steps in the calculation of fault
currents and breaker selection are
described hereinafter:
Step 1: Collect the X and R data of the
circuit elements. Convert to a common
kVA and voltage base. If the reactances
and resistances are given either in ohms
or per unit on a different voltage or kVA
base, all should be changed to the same
kVA and voltage base.This caution does
not apply where the base voltages are the
same as the transformation ratio.
Step 2: Construct the sequence networks
and connect properly for the type of fault
under consideration. Use the X values
required by ANSI Standard C37.010 for the
“interrupting” duty value of the short-
circuit current.
Step 3: Reduce the reactance network
to an equivalent reactance. Call this
reactance XI
.
Step 4: Set up the same network for
resistance values.
Figure 46. Three-phase Fault Multiplying Factors
that Include Effects of AC and
DC Decrement
Step 5: Reduce the resistance network
to an equivalent resistance. Call this
resistance RI
.The above calculations of
XI
and RI
may be calculated by several
computer programs.
Step 6: Calculate the E/XI
value, where E
is the prefault value of the voltage at the
point of fault nominally assumed 1.0 pu.
Step 7: Determine X/R =
XI
RI
as
previously calculated.
Step 8: Go to the proper curve for
the type of fault under consideration
(three-phase, phase-to-phase, phase-to-
ground), type of breaker at the loca
tion
(2, 3, 5 or 8 cycles), and contact parting
time to determine the multi
plier to the
calculated E/XI
.
See Figure 46, Figure 47 and Figure 48
for 5-cycle breaker multiplying factors.
Use Figure 48 if the short circuit is fed
predominantly from generators removed
from the fault
Figure47.Line-to-GroundFaultMultiplying Factors
that Include Effects of AC and
DC Decrement
by two or more transformations or the per
unit reactance external to the generation
is 1.5 times or more than the subtran
sient
reactance of the generation on a common
base. Also use Figure 48 where the fault is
supplied by a utility only.
Step 9: Interrupting duty short-circuit
current = E/XI
x MFx
= E/X2
.
Step 10: Construct the sequence
(positive, negative and zero) networks
properly connected for the type of fault
under consideration. Use the X values
required by ANSI Standard C37.010 for
the “Close and Latch” duty value of the
short-circuit current.
Step 11: Reduce the network to
an equivalent reactance. Call the
reac
tance X. Calculate E/X x 1.6 if the
breaker close and latch capability is
given in rms amperes or E/X x 2.7 if the
breaker close and latch capability is given
in peak or crest amperes.
Figure 48. Three-phase and Line-to-Ground Fault
Multiplying Factors that Include Effects of DC
Decrement Only
6
5
4
C
O
N
T
A
C
T
P
A
R
T
I
N
G
T
IM
E
3
5-CYCLE
BREAKER
1.0 1.1 1.2 1.3 1.4
Multiplying Factors for E / X Amperes
Ratio
X/R
130
120
110
100
90
80
70
60
50
40
30
20
10
7
8
5-CYCLE
BREAKER
1.0 1.1 1.2 1.3 1.4
3
4
5
Ratio
X/R
130
120
110
100
90
80
70
60
50
40
30
20
10
4
5-CYCLE
BREAKER
1.0 1.1 1.2 1.3 1.4
6
8
1
0
1
2
C
O
N
T
A
C
T
P
A
R
T
I
N
G
T
IM
E
3
Ratio
X/R
130
120
110
100
90
80
70
60
50
40
30
20
10

Step 12: Select a breaker whose:
A. Maximum voltage rating exceeds the
operating voltage of the system:
B.
Refer toVCP-W Current Rating tables in
the VacClad-W Metal-Clad Switchgear
Design Guide.
Where:
I = Rated short-circuit current
Vmax
= Rated maximum voltage
of the breaker
Vo
= Actual system voltage
KI = Maximum symmetrical
interrupting capacity
C. E/X x 1.6 ≤ rms closing and
latching capability of the breaker
and/or
E/X x 2.7 ≤ Crest closing and
latching capability of the breaker.
The ANSI standards do not require the
inclusion of resistances in the calcula
tion
of the required interrupting and close
and latch capabilities.Thus the calculated
values are conservative. However, when
the capa
bilities of existing switchgear
are investi
gated, the resistances should
be included.
For single line-to-ground faults, the
sym
metrical interrupting capability
is 1.15 x the symmetrical interrupting
capability at any operating voltage, but
not to exceed the maximum symmetrical
capability of the breaker.
ANSI C37 provides further guidance for
medium voltage breaker application.
Reclosing Duty
ANSI Standard C37.010 indicates the
reduction factors to use when circuit
breakers are used as reclosers. Eaton
VCP-W breakers are listed at 100% rating
factor for reclosing.
Application Quick Check Table
For application of circuit breakers in
a radial system supplied from a single
source transformer, short-circuit duty
was determined using E/X amperes and
1.0 multiplying factor for X/R ratio of 15
or less and 1.25 multiplying factor for
X/R ratios in the range of 15 to 40. Refer
to Table 9 below.
ApplicationAbove 3,300 ft (1,000 m)
The rated one-minute power frequency
withstand voltage, the impulse with
stand
voltage, the continuous current rating,
and the maximum voltage rating must be
multiplied by the appropriate correction
factors below to obtain modified ratings
that must equal or exceed the application
requirements.
Note: For assemblies containing vacuum
breakers at high altitudes, system voltage
is not derated.
Note: Intermediate values may be obtained
by interpolation.
Table 8. Altitude Derating
Altitude in
Feet (Meters)
Correction Factor
Current Voltage
3300 (1006) (and below)
5000 (1524)
10,000 (3048)
1.00
0.99
0.96
1.00
0.95
0.80
Table 9. Application Quick Check Table
Source
Transformer
MVA Rating
OperatingVoltage
kV
Motor Load 2.4 4.16 6.6 12 13.8
100% 0%
1
1.5
2
1.5
2
2.5
50VCP-W250
12 kA
50VCP-W250
10.1 kA
50VCP-W250
33.2 kA
150VCP-W500
23 kA
150VCP-W500
22.5 kA
150VCP-W500
19.6 kA
2.5
3
3
3.75
50VCP-W250
36 kA
3.75
5
5
7.5
7.5
10 a
10
10
50VCP-W350
49 kA
10 12 a
75VCP-W500
41.3 kA
12 15 50VCP-W350
46.9 kA
15 20
150VCP-W750
35 kA
150VCP-W750
30.4 kA
20 a 20 BreakerType and symmetrical interrupting
capacity at the operating voltage
25
30
50 a 150VCP-W1000
46.3 kA
150VCP-W1000
40.2 kA
a Transformer impedance 6.5% or more, all other transformer impedances are 5.5% or more.
45

Application of K >1 Breakers on a Symmetrical Current Rating Basis
Example 1—Fault Calculations
Given a circuit breaker interrupting and momentary rating in the table below,
verify the adequacy of the ratings for a system without motor loads, as shown.
Table 10. Short-Circuit Duty
Type
Breaker
V Max. Three-Phase Symmetrical Interrupting Capability Close and Latch
or Momentary
atV Max. Max. KI at 4.16 kV Oper.Voltage
50VCP–W250 4.76 kV 29 kA 36 kA
(29) = 33.2 kA I1
58 kA I3
LG symmetrical interrupting capability
— 36 kA 1.15 (33.2) = 38.2 kA I2
Note: Interrupting capabilities I1
and I2
at operating voltage must not exceed maximum symmetrical
interrupting capability Kl.
Check capabilities I1
, I2
and I3
on the following utility system
where there is no motor contribution to short circuit.
Figure 49. Example 1—One-Line Diagram
From transformer losses per unit or
percent R is calculated
On 13.8 kV System, 3.75 MVA Base
ForThree-Phase Fault
would use 1.0 multiplying factor for
short-circuit duty, therefore, short-
circuit duty is 8.6 kA sym. for three-
phase fault I1
and momentary duty is
8.6 x 1.6 = 13.7 kA I3
.
For Line-to-Ground Fault
For this system, X0
is the zero sequence
reactance of the transformer, which is
equal to the transformer positive sequence
reactance and X1 is the posi
tive sequence
reactance of the system.
Therefore,
Using 1.0 multiplying factor
(see Table 11), short-circuit
duty = 9.1 kA Sym. LG (I2
)
Answer
The 50VCP-W250 breaker capabilities
exceed the duty requirements and
may be applied.
With this application, shortcuts could
have been taken for a quicker check of
the application. If we assume unlimited
short circuit available at 13.8 kV and that
Trans. Z = X
X/R ratio 15 or less multiplying factor is
1.0 for short-circuit duty.
The short-circuit duty is then
9.5 kA Sym. (I1
, I2
) and momentary
duty is 9.5 x 1.6 kA = 15.2 kA (I3
).
13.8 kV
375 MVA
Available
13.8 kV
3750 kVA
4.16 kV
50VPC-W250
= 15
X
R

Given the system shown with motor loads,
calculate the fault currents and determine
proper circuit breaker selection.
All calculations on per unit basis.
7.5 MVA base
Table11. MultiplyingFactorforE/XAmperes
(ANSI C37)
System
X/R
TypeVCP-WVacuum Circuit Breaker
Rated InterruptingTime, 5-Cycle
Type of Fault
Ratio Three-
Phase
LG Three-Phase
and LG
Source of Short Circuit
Local Remote
1
15 a
20
25
30
1.00
1.00
1.00
1.00
1.04
1.00
1.00
1.02
1.06
1.10
1.00
1.00
1.05
1.10
1.13
36
40
45
50
55
1.06
1.08
1.12
1.13
1.14
1.14
1.16
1.19
1.22
1.25
1.17
1.22
1.25
1.27
1.30
60
65
70
75
80
1.16
1.17
1.19
1.20
1.21
1.26
1.28
1.29
1.30
1.31
1.32
1.33
1.35
1.36
1.37
85
90
95
100
—
1.22
—
1.23
—
1.32
—
1.33
1.38
1.39
1.40
1.41
100
120
130
1.24
1.24
1.24
1.34
1.35
1.35
1.42
1.43
1.43
a Where system X/R ratio is 15 or less, the
multiplying factor is 1.0.
Source of
Short-Circuit Current
Interrupting
E/XAmperes
Momentary
E/XAmperes
X
R
X (1)
R (X)
1
R
I1
SourceTransformer 0.628
0.070 = 8.971
0.628
0.070 = 8.971
11 11
0.070
= 157
I2
3000 hp Syn. Motor 0.628
(1.5) 0.638 = 0.656
0.628
0.638 = 0.984
25 25
0.638
= 39
I3
2500 hp Ind. Motor 0.628
(1.5) 0.908 = 0.461
0.628
0.908 = 0.691
35 35
0.908
= 39

I3F
= 10.088
or 10.1 kA
10.647 Total 1/R = 235
x 1.6
17.0 kA Momentary Duty
System = 0.062 (235) = 14.5 is a Multiplying Factor of 1.0 from Table 11
Table 12. Short-Circuit Duty = 10.1 kA
Breaker
Type
V
Max.
Three-Phase Symmetrical Interrupting Capability Close and Latch
or Momentary
atV Max. Max. KI at 6.9 kV Oper.Voltage
75VCP-W500 8.25 kV 33 kA 41 kA 8.25
6.9 (33) = 39.5 kA
66 kA
150VCP-W500 15 kV 18 kA 23 kA 15 (18)
6.9 (39.1) = 23 kA
(But not to exceed KI)
37 kA
Answer
Either breaker could be properly applied,
but price will make the type 150VCP-W500
the more economical selection.
Z = 5.53% = 10
13.8 kV
7500 kVA
6.9 kV
13.8 kV System
3
21 kA Sym. Available = 15
X
R
X = 5.5%
R = 0.55%
X
R
X
R
= 25
X
R
= 35
3000 hp
1.0 PF
Syn.
2500 hp
Ind.
2
197A FL
X'' = 20%
d
173A FL
X'' = 25%
d
1
47

Check breaker application or generator bus for the system of generators shown.
Each generator is 7.5 MVA, 4.16 kV 1040 A full load, IB
= 1.04 kA
Sub transient reactance Xd” = 11% or, X = 0.11 pu
Answer
The 50VCP-W250 breaker could be applied.The use of a specific generator circuit
breaker such as the EatonVCP-WG should also be investigated.
Medium-Voltage Fuses—
Fault Calculations
There are two basic types of medium
voltage fuses.The following definitions
are taken from ANSI Standard C37.40.
Expulsion Fuse (Unit)
A vented fuse (unit) in which the expulsion
effect of the gases produced by internal
arcing, either alone or aided by other
mechanisms, results in current interruption.
Current-Limiting Fuse (Unit)
A fuse unit that, when its current-
responsive element is melted by a
current within the fuse’s specified
current-limiting range, abruptly
introduces a high resistance to reduce
current magnitude and duration, resulting
in subsequent current interruption.
There are two classes of fuses; power and
distribution.They are distinguished from
each other by the current ratings and
minimum melting type characteristics.
The current-limiting ability of a current-
limiting fuse is specified by its threshold
ratio, peak let-through current and I2
t
characteristics.
Interrupting Ratings of Fuses
Modern fuses are rated in amperes rms
symmetrical.They also have a listed
asymmetrical rms rating that is 1.6 x the
symmetrical rating.
Refer to ANSI/IEEE C37.48 for fuse
interrupting duty guidelines.
Calculation of the Fuse Required
Interrupting Rating:
Step 1—Convert the fault from the utility to
percent or per unit on a convenient voltage
and kVA base.
Step 2—Collect the X and R data of all the
other circuit elements and convert to a
percent or per unit on a conve
nient kVA
and voltage base same as that used in
Step 1. Use the substran
sient X and R for
all generators and motors.
Step 3—Construct the sequence networks
using reactances and connect properly for
the type of fault under consideration and
reduce to a single equivalent reactance.
Table 11
G1 G2 G3
4.16 kV

Step 4—Construct the sequence networks
using resistances and connect properly
for the type of fault under consideration
and reduce to a single equivalent
resistance.
Step 5—Calculate the E/XI
value, where E
is the prefault value of the voltage at the
point of fault normally assumed 1.0 in pu.
For three-phase faults E/XI
is the fault
current to be used in determining the
required interrupting capability of the fuse.
Note: It is not necessary to calculate a single
phase-to-phase fault current.This current is
very nearly x three-phase fault.The
line-to-ground fault may exceed the three-
phase fault for fuses located in generating
stations with solidly grounded neutral
generators, or in delta-wye trans
formers with
the wye solidly grounded, where the sum of the
positive and negative sequence impedances on
the high voltage side (delta) is smaller than the
impedance of the transformer.
For single line-to-ground fault:
Step 6—Select a fuse whose published
interrupting rating exceeds the calculated
fault current.
Figure 45 should be used where older
fuses asymmetrically rated are involved.
The voltage rating of power fuses used on
three-phase systems should equal or
exceed the maximum line-to-line voltage
rating of the system. Current limiting
fuses for three-phase systems should be
so applied that the fuse voltage rating is
equal to or less than 1.41 x nominal
system voltage.
Low-Voltage Power Circuit
Breakers—Fault Calculations
The steps for calculating the fault current
for the selection of a low voltage power
circuit breaker are the same as those
used for medium voltage circuit breakers
except that where the connected loads to
the low voltage bus includes induction
and synchronous motor loads.
The assumption is made that in
208Y/120 V systems the contribution
from motors is two times the full load
current of the step-down transformer.
This corresponds to an assumed
50% motor aggregate impedance
on a kVA base equal to the transformer
kVA rating or 50% motor load.
For 480V, 480Y/277V and 600V
sys
tems, the assumption is made
that the contribution from the motors
is four times the full load current of
the step-down transformer, which
corresponds to an assumed 25%
aggregate motor impedance on a
kVA base equal to the transformer
kVA rating or 100% motor load.
In low-voltage systems that contain
generators, the subtransient reactance
should be used.
The X/R ratio is calculated in the same
manner as that for medium-voltage
circuit breakers. If the X/R at the point
of fault is greater than 6.6, a multiply
ing
factor (MF) must be applied.
The calculated symmetrical amperes
should be multiplied by the multiply
ing
factor (MF) and compared to the
nameplate rating to ensure the breaker
is applied within its rating.
The multiplying factor MF can be
calculated by the formula:
If the X/R of system feeding the breaker
is not known, use X/R = 15.
For fused breakers by the formula:
If the X/R of the system feeding the
breaker is not known, use X/R = 20.
Refer to Table 13 for the standard ranges
of X/R and power factors used in testing
and rating low voltage breakers. Refer
to Table 14 for the circuit breaker
interrupting rating derating factors to be
used when the calculated X/R ratio or
power factor at the point the breaker is
to be applied in the power distribution
system falls outside of the X/R or power
factors used in test
ing and rating the
circuit breakers.The derating factors
shown in Table 13 are the inverse of
the MF (multiplying factors) calculated
above.These derat
ing factors are applied
to the nameplate interrupting rating of
the breaker to indicate the device’s
interrupting capacity at the elevated
X/R ratio.
49

Molded Case Breakers and
Insulated Case Circuit
Breakers—Fault Calculations
The method of fault calculation is the
same as that for low voltage power circuit
breakers.The calculated fault current
times the MF must be less than the breaker
interrupting capacity. Because molded
case breakers are tested at lower X/R
ratios, the MFs are different than those
for low voltage power circuit breakers.
Low-Voltage Circuit Breaker
Interrupting Derating Factors
Refer to Table 13 for the standard ranges
of X/R and power factors used in testing
and rating low voltage breakers. Refer to
Table 14 for the circuit breaker
interrupting rating de-rating factors to
be used when the calculated X/R ratio or
power factor at the point the breaker is
to be applied in the power distribution
system falls outside of the Table 13
X/R or power factors used in testing and
rating the circuit breakers.
Normally the short-circuit power factor
or X/R ratio of a distribution system need
not be considered in applying low voltage
circuit breakers.This is because the ratings
established in the applicable standard are
based on power factor values that amply
cover most applications.
Established standard values include
the following:
Table 13. Standard Test Power Factors
Interrupting
Rating in kA
Power Factor
Test Range
X/RTest
Range
Molded Case Circuit Breaker
10 or Less
Over 10 to 20
Over 20
0.45–0.50
0.25–0.030
0.15–0.20
1.98–1.73
3.87–3.18
6.6–4.9
Low-Voltage Power Circuit Breaker
All 0.15 Maximum 6.6 Minimum
For distribution systems where the
calculated short-circuit current X/R ratio
differs from the standard values given
in the above table, circuit breaker
interrupting rating derating factors from
Table 14 table should be applied.
Table 14. Circuit Breaker Interrupting Rating Derating Factors
% P
.F. X/R Interrupting Rating
Molded Case or Insulated Case Power Circuit Breaker
≤ / = 10 kA
>10 kA
≤ / = 20 kA > 20 kA Unfused Fused
50
30
25
1.73
3.18
3.87
1.000
0.847
0.805
1.000
1.000
0.950
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
1.000
20
15
12
4.90
6.59
8.27
0.762
0.718
0.691
0.899
0.847
0.815
1.000
0.942
0.907
1.000
1.000
0.962
1.000
0.939
0.898
10
8.5
7
9.95
11.72
14.25
0.673
0.659
0.645
0.794
0.778
0.761
0.883
0.865
0.847
0.937
0.918
0.899
0.870
0.849
0.827
5 19.97 0.627 0.740 0.823 0.874 0.797
Note: These are derating factors applied to the breaker and are the inverse of MF
.

Short-Circuit Calculations
Determination of Short-Circuit Current
Note: Transformer impedance generally relates to self-ventilated rating (e.g., with ONAN/ONAF/OFAF transformer use OA base).
Note: kV refers to line-to-line voltage in kilovolts.
Note: Z refers to line-to-neutral impedance of system to fault where R + jX = Z.
Note: When totalling the components of system Z, arithmetic combining of impedances as “ohms Z”
. “per unit Z”
. etc., is considered a shortcut
or approximate method; proper combining of impedances (e.g., source, cables transformers, conductors, etc.). should use individual R and
X components.ThisTotal Z =Total R + jTotal X (see IEEE “Red Book” Standard No. 141).
Page 53
51

Example Number 1
How to Calculate Short-Circuit Currents at Ends of Conductors
Figure 52. Example Number 1
Utility Source 500 MVA
1000 kV A
5.75%
480V
Switchboard Fault
100 ft (30m)
3–350 kcmil Cable
in Steel Conduit
Mixed Load—Motors and Lighting
Each Feeder—100 ft (30m) of 3–350 kcmil
Cable in Steel Conduit Feeding Lighting and
250 kVA of Motors
Cable Fault
Utility
Transformer
Major Contribution
Cables
Switchboard Fault
Cables
Cable Fault
A B C
0.002 pu
Switchboard Fault
0.027 pu
Cable Fault
A B C 0.0575pu
1.00 pu
0.027 pu
1.00 pu
0.027 pu
1.00 pu
0.027 pu
0.342 pu
0.027 pu
0.0507 pu
0.027 pu
Combining Series Impedances: ZTOTAL = Z1 + Z2 + ... +Zn
Combining Parallel Impedances:
ZTOTAL
1 =
Z1
1 +
Z2
1 + ...
Zn
1
0.0595 pu
F1
F2
Zu Zm Zm
Zm
Zc Zc
Zc
Zequiv
0.0777pu
Es
F2
F1
F1
Zc
F1 F1
F2
A. System Diagram B. Impedance Diagram (Using “Short Cut” Method for Combining Impedances and Sources).
C. Conductor impedance fromTable 61.
Conductors: 3–350 kcmil copper, single
conductors Circuit length: 100 ft (30 m),
in steel (magnetic) conduit Impedance
Z = 0.0617 ohms/ 1,000 ft (304.8 m).
ZTOT
= 0.00617 ohms (100 circuit feet)
D. Fault current calculations (combining
impedances arithmetically, using
approximate “Short Cut” method—
see Note 4, Page 53)

Example Number 2
Fault Calculation—Secondary Side of Single-PhaseTransformer
Figure 53. Example Number 2
Shortcut Method—End of Cable
This method uses the approximation of
adding Zs instead of the accurate method
of Rs and Xs.
For Example: For a 480/277V system with
30,000 A symmetrical available at the line
side of a conductor run of 100 ft (30 m) of
2–500 kcmil per phase and neutral, the
approximate fault current at the load side
end of the conductors can be calculated
as follows.
277V/30,000 A = 0.00923 ohms
(source impedance)
Conductor ohms for 500 kcmil conductor
from Table 61 in mag
netic conduit is
0.00551 ohms per 100 ft (30 m). For 100 ft
(30 m) and two conductors per phase
we have:
0.00551/2 = 0.00273 ohms
(conductor impedance)
Add source and conductor impedance or
0.00923 + 0.00273 = 0.01196 total ohms
Next, 277V/0.01196 ohms = 23,160 A rms
at load side of conductors
Figure 54. Short-Circuit Diagram
X 30,000 A available
100 ft (30 m)
2–500 kcmil per phase
X If
= 23,160 A
53

Determining X and R Values
from Transformer Loss Data
Method 1:
Given a 500 kVA, 5.5% Z transformer
with 9000W total loss; 1700W no-load
loss; 7300W load loss and primary
voltage of 480V.
Watts Load Loss = 3 x (I2
x R)
R = 0.0067 ohms
Method 2:
Using same values above.
HowtoEstimate Short-Circuit
Currents atTransformerSecondaries:
Method 1:
To obtain three-phase rms symmetrical
short-circuit current available at
transformer secondary terminals,
use the formula:
where %Z is the transformer impedance
in percent, from Table 61 through
Table 67, Page 139.
This is the maximum three-phase
sym
metrical bolted-fault current,
assuming sustained primary voltage
during fault, i.e., an infinite or unlimited
primary power source (zero source
impedance). Because the power source
must always have some impedance,
this is a conservative value; actual fault
current will be somewhat less.
Note: This will not include motor short-circuit
contribution.
Method 2:
Refer to Table 27 in the Reference section,
and use appropriate row of data based on
transformer kVA and primary short-circuit
current available.This will yield more
accurate results and allow for including
motor short-circuit contribution.
Voltage Drop Considerations
The first consideration for voltage drop is
that under the steady-state conditions of
normal load, the voltage at the utilization
equipment must be adequate. Fine-print
notes in the NEC recommend sizing
feeders and branch circuits so that the
maximum voltage drop in either does not
exceed 3%, with the total voltage drop for
feeders and branch circuits not to exceed
5%, for efficiency of operation. (Fine print
notes in the NEC are not mandatory.)
Local energy codes as well as the
standards for high performance
green buildings should be referenced
to determine any additional project
related voltage drop requirements.
In addition to steady-state conditions,
voltage drop under transient condi
tions,
with sudden high-current, short-time
loads, must be considered.The most
common loads of this type are motor
inrush currents during starting.These
loads cause a voltage dip on the system as
a result of the voltage drop in conductors,
transformers and generators under the
high current.This voltage dip can have
numerous adverse effects on equipment
in the system, and equipment and
conduc
tors must be designed and sized
to minimize these problems. In many
cases, reduced-voltage starting of motors
to reduce inrush current will be necessary.
Recommended Limits of
Voltage Variation
General Illumination: Flicker in
incandescent lighting from voltage dip
can be severe; lumen output drops about
three times as much as the voltage dips.
That is, a 10% drop in voltage will result
in a 30% drop in light output.While the
lumen output drop in fluorescent lamps
is roughly proportional to voltage drop, if
the voltage dips about 25%, the lamp will
go out momentarily and then restrike.
For high-intensity discharge (HID) lamps
such as mercury vapor, high-pressure
sodium or metal halide, if the lamp goes
out because of an excessive voltage dip, it
will not restrike until it has cooled.This will
require several minutes.These lighting
flicker effects can be annoying, and in the
case of HID lamps, sometimes serious.
In areas where close work is being
done, such as drafting rooms, precision
assembly plants, and the like, even a
slight variation, if repeated, can be very
annoying, and reduce efficiency.Voltage
variation in such areas should be held to
2 or 3% under motor-starting or other
transient conditions.
Computer Equipment:With the
proliferation of data-processing and
computer- or microprocessor-controlled
manufacturing, the sensitivity of
computers to voltage has become an
important consideration. Severe dips of
short duration can cause a computer to
“crash”—shut down completely, and
other voltage transients caused by
starting and stopping motors can cause
data-processing errors.While voltage
drops must be held to a mini
mum, in
many cases computers will require
special power-conditioning equipment
to operate properly.
Industrial Plants:Where large motors
exist, and unit substation transformers
are relatively limited in capacity,
voltage dips of as much as 20% may
be permissible if they do not occur too
frequently. Lighting is often supplied from
separate transformers, and is minimally
affected by voltage dips in the power
systems. However, it is usually best to
limit dips to between 5 and 10% at most.
One critical consideration is that a large
voltage dip can cause a dropout (opening)
of magnetic motor contactors and control
relays.The actual dropout voltage varies
considerably among starters of different
manufacturers.
The only standard that exists is that of
NEMA, which states that a starter must
not drop out at 85% of its nominal coil
voltage, allowing only a 15% dip.While
most starters will tolerate con
siderably
more voltage dip before dropping out,
limiting dip to 15% is the only way to
ensure continuity of oper
ation in all cases.
X-Ray Equipment: Medical x-ray and
similar diagnostic equipment, such as
CAT-scanners, are extremely sensitive to
low voltage.They present a small, steady
load to the system until the instant the
x-ray tube is “fired.
”This presents a brief
but extremely high instantaneous
momentary load.
In some modern x-ray equipment,
the firing is repeated rapidly to
create multiple images.The voltage
regulation must be maintained within
the manufacturer’s limits, usually 2 to 3%,
under these momentary loads, to ensure
proper x-ray exposure.

Motor Starting
Motor inrush on starting must be limited
to minimize voltage dips. Table 15 on the
next page will help select the proper type
of motor starter for various motors, and
to select generators of adequate
size to limit voltage dip. See Eaton’s
Low-Voltage Motor Control Center (MCC)
Design Guide for additional data on
reduced voltage motor starting.
Utility Systems
Where the power is supplied by a utility
network, the motor inrush can be assumed
to be small compared to the system
capacity, and voltage at the source can
be assumed to be constant during motor
starting.Voltage dips resulting from motor
starting can be calculated on the basis
of the voltage drop in the conductors
between the power source and the motor
resulting from the inrush current.
Where the utility system is limited, the
utility will often specify the maximum
permissible inrush current or the
maximum hp motor they will permit
to be started across-the-line.
Transformer Considerations
If the power source is a transformer, and
the inrush kVA or current of the motor
being started is a small portion of the
full-rated kVA or current of the transformer,
the transformer voltage dip will be small
and may be ignored. As the motor inrush
becomes a significant percentage of the
transformer full-load rating, an estimate of
the transformer voltage drop must be
added to the conductor voltage drop to
obtain the total voltage drop to the motor.
Accurate voltage drop calculation would
be complex and depend upon transformer
and conductor resistance, reactance and
impedance, as well as motor inrush
current and power factor. However, an
approximation can be made on the basis
of the low power-factor motor inrush
current (30–40%) and impedance of
the transformer.
For example, if a 480V transformer
has an impedance of 5%, and the
motor inrush current is 25% of the
transformer full-load current (FLC),
then the worst case voltage drop will
be 0.25 x 5%, or 1.25%.
The allowable motor inrush current
is determined by the total permissible
voltage drop in transformer and
conductors.
Engine Generator Systems
With an engine generator as the source
of power, the type of starter that will limit
the inrush depends on the characteristics
of the generator. Although automatic
voltage regulators are usually used with
all AC engine-generators, the initial dip
in voltage is caused by the inherent
regulation of the generator and occurs
too rapidly for the voltage regulator to
respond. It will occur whether or not a
regulator is installed.
Consequently, the percent of initial voltage
drop depends on the ratio of the starting
kVA taken by the motor to the generator
capacity, the inherent regulation of
the generator, the power-factor of the
load thrown on the generator, and the
percentage load carried by the generator.
A standard 80% power-factor engine-
type generator (which would be used
where power is to be supplied to motor
loads) has an inherent regulation of
approximately 40% from no-load to
full-load.This means that a 50% variation
in load would cause approximately 20%
variation in voltage (50% x 40% = 20%).
Assume that a 100 kVA, 80% PF engine-
type generator is supplying the power
and that the voltage drop should not
exceed 10%. Can a 7-1/2 hp, 220V,
1750 rpm, three-phase, squirrel-cage
motor be started without exceeding this
voltage drop?
Starting current (%F
.L.) =
From the nameplate data on the motor,
the full-load amperes of a 7-1/2 hp.
220V, 1750 rpm, three-phase, squirrel-
cage motor is 19.0 A.Therefore:
Starting current (%F
.L.) =
From Table 15, a NEMA design C or NEMA
design B motor with an autotrans
former
starter gives approximately this starting
ratio. It could also be obtained from a
properly set solid-state adjust
able
reduced voltage starter.
The choice will depend upon the torque
requirements of the load since the use of
an autotransformer starter reduces the
starting torque in direct proportion to the
reduction in starting current.
In other words, a NEMA design C motor
with an autotransformer would have a
starting torque of approximately full-load
(see Table 15) whereas the NEMA design
D motor under the same conditions
would have a starting torque of
approximately 1-1/2 times full-load.
Note: If a resistance starter were used for the
same motor terminal voltage, the starting
torque would be the same as that obtained
with autotransformer type, but the starting
current would be higher, as shown.
Shortcut Method
The last column in Table 15 has been
worked out to simplify checking.The
figures were obtained by using the
formula above and assuming 1 kVA
generator capacity and 1% voltage drop.
Example:
Assuming a project having a 1000 kVA
generator, where the voltage variation
must not exceed 10%. Can a 75 hp,
1750 rpm, 220V, three-phase, squirrel-cage
motor be started without objectionable
lamp flicker (or 10% voltage drop)?
From tables in the circuit protective
devices reference section, the full-load
amperes of this size and type of motor is
158 A.To convert to same basis as the last
column, 158 A must be divided by the
generator capacity and % voltage drop, or:
Checking against the table, 0.0158 falls
within the 0.0170–0.0146 range for a
NEMA A with an autotransformer starter.
This indicates that a general-purpose
motor with autotransformer starting can
be used.
Note: Designers may obtain calculated
information from engine generator
manufacturers.
The calculation results in conservative
results.The engineer should provide to the
engine-generator vendor the starting kVA
of all motors connected to the generator
and their starting sequence.The engineer
should also specify the maximum
allowable drop.The engineer should
request that the engine-generator vendor
consider the proper generator size when
closed-transition autotransformer reduced
voltage starters, and soft-start solid-state
starter are used; so the most economical
method of installation is obtained.
55

Table 15. Factors Governing Voltage Drop
Type of Motor a Starting
Torque
Starting
Current b
How
Started
Starting
Current
% Full-Load c
StartingTorque per Unit of
Full LoadTorque
Full-LoadAmperes
per kVA Generator
Capacity for Each
1%Voltage Drop
Motor Rpm
1750 1150 c 850
Design A Normal Normal Across-the-line
resistance
autotransformer
600–700
480–560 A
375–450 Á
1.5
0.96
0.96
1.35
0.87
0.87
1.25
0.80
0.80
0.0109–.00936
0.0136–.0117
0.0170–.0146
Design B Normal Low Across-the-line
resistance
autotransformer
500–600
400–480 A
320–400 Á
1.5
0.96
0.96
1.35
0.87
0.87
1.25
0.80
0.80
0.0131–.0109
0.0164–.01365
0.0205–.0170
Design C High Low Across-the-line
resistance
autotransformer
500–600
400–480 A
320–400 Á
—
—
—
0.2 to 2.5
1.28 to 1.6
1.28 to 1.6
—
—
—
0.0131–.0109
0.0164–.01365
0.0205–.0170
Wound rotor High Low Secondary controller 100% current
for 100%
torque
—
—
—
—
—
—
—
—
—
—
—
0.0655
Synchronous (for compressors)
Synchronous (for centrifugal pumps)
Low
Low
—
—
Across-the-line
Across-the-line
Autotransformer
300
450–550
288–350 d
40% Starting, 40% Pull-In
0.0218
0.0145–.0118
0.0228–.0197
a Consult NEMA MG-1 sections 1 and 12 for the exact definition of the design letter.
b In each case, a solid-state reduced voltage starter can be adjusted and controlled to provide the required inrush current and torque characteristics.
c Where accuracy is important, request the code letter of the motor and starting and breakdown torques from the motor vendor.
d Using 80% taps.
Voltage Drop Formulas
Approximate Method
Voltage Drop
where abbreviations are same as below “Exact Method.
”
Exact Methods
Voltage drop
Exact Method 1—If sending end voltage and load PF are known.
where:
EVD
=Voltage drop, line-to-neutral, volts
ES
= Source voltage, line-to-neutral, volts
I = Line (Load) current, amperes
R = Circuit (branch, feeder) resistance, ohms
X = Circuit (branch, feeder) reactance, ohms
cosq = Power factor of load, decimal
sinq = Reactive factor of load, decimal
If the receiving end voltage, load current and power factor (PF)
are known.
ER
is the receiving end voltage.
Exact Method 2—If receiving or sending mVA and its power
factor are known at a known sending or receiving voltage.
where:
ER
= Receiving line-line voltage in kV
ES
= Sending line-line voltage in kV
MVAR
= Receiving three-phase mVA
MVAS
= Sending three-phase mVA
Z = Impedance between and receiving ends
g =The angle of impedance Z
qR
= Receiving end PF
qS
= Sending end PF
, positive when lagging

Voltage Drop
Voltage Drop Tables
Note: Busway voltage drop tables are shown in
Eaton’s Low-Voltage Busway Design Guide.
Tables for calculating voltage drop for
copper and aluminum conductors, in
either magnetic (steel) or nonmagnetic
(aluminum or non-metallic) conduit,
appear on Page 50.These tables give
voltage drop per ampere per 100 ft (30 m)
of circuit length.The circuit length is from
the beginning point to the end point of the
circuit regardless of the number of
conductors.
Tables are based on the following
conditions:
1. Three or four single conductors in
a conduit, random lay. For three-
conductor cable, actual voltage
drop will be approximately the same
for small conductor sizes and high
power factors. Actual voltage drop
will be from 10 to 15% lower for
larger conductor sizes and lower
power factors.
2. Voltage drops are phase-to-phase,
for three-phase, three-wire or three-
phase, four-wire 60 Hz circuits. For
other circuits, multiply voltage drop
given in the tables by the following
correction factors:
3. Three-phase, four-wire,
phase-to-neutral x 0.577
Single-phase, two-wire x 1.155
Single-phase, three-wire,
phase-to-phase x 1.155
Single-phase, three-wire,
phase-to-neutral x 0.577
4. Voltage drops are for a conductor
temperature of 75 °C.They may be
used for conductor temperatures
between 60 °C and 90 °C with
reasonable accuracy (within ±5%).
However, correction factors in
Table 16 can be applied if desired.The
values in the table are in percent of
total voltage drop.
For conductor temperature of 60 °C–
SUBTRACT the percentage from
Table 16.
For conductor temperature of 90 °C–ADD
the percentage from Table 16.
Table 16. Temperature Correction Factors
for Voltage Drop
Conductor
Size
Percent Correction
Power Factors %
100 90 80 70 60
No. 14 to No. 4
No. 2 to 3/0
4/0 to 500 kcmil
600 to 1000 kcmil
5.0
5.0
5.0
5.0
4.7
4.2
3.1
2.6
4.7
3.7
2.6
2.1
4.6
3.5
2.3
1.5
4.6
3.2
1.9
1.3
Calculations
To calculate voltage drop:
1. Multiply current in amperes by the
length of the circuit in feet to get
ampere-feet. Circuit length is the
distance from the point of origin to
the load end of the circuit.
2. Divide by 100.
3. Multiply by proper voltage drop value
in tables. Result is voltage drop.
Example:
A 460V, 100 hp motor, running at 80% PF
,
draws 124 A full-load current. It is fed by
three 2/0 copper conductors in steel
conduit.The feeder length is 150 ft (46 m).
What is the voltage drop in the feeder?
What is the percentage voltage drop?
1. 124 A x 150 ft (46 m) = 18,600 A-ft
2. Divided by 100 = 186
3. Table: 2/0 copper, magnetic conduit,
80% PF = 0.0187
186 x 0.0187 = 3.48V drop

3.48 x 100 = 0.76% drop
460
4. Conclusion: 0.76% voltage drop
is very acceptable. (See NEC 2005
Article 215, which suggests that a
voltage drop of 3% or less on a feeder
is acceptable.)
To select minimum conductor size:
1. Determine maximum desired
voltage drop, in volts.
2. Divide voltage drop by
(amperes x circuit feet).
3. Multiply by 100.
4. Find nearest lower voltage drop value
in tables, in correct column for type of
conductor, conduit and power factor.
Read conductor size for that value.
5. Where this results in an oversized
cable, verify cable lug sizes for molded
case breakers and fusible switches.
Where lug size available is exceeded,
go to next higher rating.
Example:
A three-phase, four-wire lighting feeder
on a 208V circuit is 250 ft (76.2 m) long.
The load is 175 A at 90% PF
. It is desired to
use aluminum conductors in aluminum
conduit.What size conductor is required
to limit the voltage drop to 2% phase-
to-phase?
1.
2.
3.
4. In table, under aluminum conduc
tors,
nonmagnetic conduit, 90% PF
, the
nearest lower value is 0.0091.
Conductor required is 500 kcmil.
(Size 4/0THW would have adequate
ampacity, but the voltage drop would
be excessive.)
57

Table 17. Voltage Drop—Volts per Ampere per 100 Feet (30 m); Three-Phase, Phase-to-Phase
Conductor Size
AWG or kcmil
Magnetic Conduit (Steel) Nonmagnetic Conduit (Aluminum or Nonmetallic)
Load Power Factor, % Load Power Factor, %
60 70 80 90 100 60 70 80 90 100
Copper Conductors
      14
      12
      10
         8
0.3390
0.2170
0.1390
0.0905
0.3910
0.2490
0.1590
0.1030
0.4430
0.2810
0.1790
0.1150
0.4940
0.3130
0.1980
0.1260
0.5410
0.3410
0.2150
0.1350
0.3370
0.2150
0.1370
0.0888
0.3900
0.2480
0.1580
0.1010
0.4410
0.2800
0.1780
0.1140
0.4930
0.3120
0.1970
0.1250
0.5410
0.3410
0.2150
0.1350
         6
         4
         2
         1
0.0595
0.0399
0.0275
0.0233
0.0670
0.0443
0.0300
0.0251
0.0742
0.0485
0.0323
0.0267
0.0809
0.0522
0.0342
0.0279
0.0850
0.0534
0.0336
0.0267
0.0579
0.0384
0.0260
0.0218
0.0656
0.0430
0.0287
0.0238
0.0730
0.0473
0.0312
0.0256
0.0800
0.0513
0.0333
0.0270
0.0849
0.0533
0.0335
0.0266
     1/0
     2/0
     3/0
     4/0
0.0198
0.0171
0.0148
0.0130
0.0211
0.0180
0.0154
0.0134
0.0222
0.0187
0.0158
0.0136
0.0229
0.0190
0.0158
0.0133
0.0213
0.0170
0.0136
0.0109
0.0183
0.0156
0.0134
0.0116
0.0198
0.0167
0.0141
0.0121
0.0211
0.0176
0.0147
0.0124
0.0220
0.0181
0.0149
0.0124
0.0211
0.0169
0.0134
0.0107
   250
   300
   350
   500
0.0122
0.0111
0.0104
0.0100
0.0124
0.0112
0.0104
0.0091
0.0124
0.0111
0.0102
0.0087
0.0120
0.0106
0.0096
0.0080
0.0094
0.0080
0.0069
0.0053
0.0107
0.0097
0.0090
0.0078
0.0111
0.0099
0.0091
0.0077
0.0112
0.0099
0.0091
0.0075
0.0110
0.0096
0.0087
0.0070
0.0091
0.0077
0.0066
0.0049
   600
   750
1000
0.0088
0.0084
0.0080
0.0086
0.0081
0.0077
0.0082
0.0077
0.0072
0.0074
0.0069
0.0063
0.0046
0.0040
0.0035
0.0074
0.0069
0.0064
0.0072
0.0067
0.0062
0.0070
0.0064
0.0058
0.0064
0.0058
0.0052
0.0042
0.0035
0.0029
Aluminum Conductors
      12
      10
         8
0.3296
0.2133
0.1305
0.3811
0.2429
0.1552
0.4349
0.2741
0.1758
0.4848
0.3180
0.1951
0.5330
0.3363
0.2106
0.3312
0.2090
0.1286
0.3802
0.2410
0.1534
0.4328
0.2740
0.1745
0.4848
0.3052
0.1933
0.5331
0.3363
0.2115
         6
         4
         2
         1
0.0898
0.0595
0.0403
0.0332
0.1018
0.0660
0.0443
0.0357
0.1142
0.0747
0.0483
0.0396
0.1254
0.0809
0.0523
0.0423
0.1349
0.0862
0.0535
0.0428
0.0887
0.0583
0.0389
0.0318
0.1011
0.0654
0.0435
0.0349
0.1127
0.0719
0.0473
0.0391
0.1249
0.0800
0.0514
0.0411
0.1361
0.0849
0.0544
0.0428
     1/0
     2/0
     3/0
     4/0
0.0286
0.0234
0.0209
0.0172
0.0305
0.0246
0.0220
0.0174
0.0334
0.0275
0.0231
0.0179
0.0350
0.0284
0.0241
0.0177
0.0341
0.0274
0.0217
0.0170
0.0263
0.0227
0.0160
0.0152
0.0287
0.0244
0.0171
0.0159
0.0322
0.0264
0.0218
0.0171
0.0337
0.0274
0.0233
0.0179
0.0339
0.0273
0.0222
0.0172
   250
   300
   350
   500
0.0158
0.0137
0.0130
0.0112
0.0163
0.0139
0.0133
0.0111
0.0162
0.0143
0.0128
0.0114
0.0159
0.0144
0.0131
0.0099
0.0145
0.0122
0.0100
0.0076
0.0138
0.0126
0.0122
0.0093
0.0144
0.0128
0.0123
0.0094
0.0147
0.0133
0.0119
0.0094
0.0155
0.0132
0.0120
0.0091
0.0138
0.0125
0.0101
0.0072
   600
   750
1000
0.0101
0.0095
0.0085
0.0106
0.0094
0.0082
0.0097
0.0090
0.0078
0.0090
0.0084
0.0071
0.0063
0.0056
0.0043
0.0084
0.0081
0.0069
0.0085
0.0080
0.0068
0.0085
0.0078
0.0065
0.0081
0.0072
0.0058
0.0060
0.0051
0.0038

Overcurrent Protection
and Coordination
Overcurrents in a power distribution
system can occur as a result of both
normal (motor starting, transformer
inrush, etc.) and abnormal (overloads,
ground fault, line-to-line fault, etc.)
conditions. In either case, the funda
mental purposes of current-sensing
protective devices are to detect the
abnormal overcurrent and with proper
coordination, to operate selectively to
protect equipment, property and
personnel while minimizing the outage
of the remainder of the system.
With the increase in electric power
consumption over the past few decades,
dependence on the continued supply of
this power has also increased so that the
direct costs of power outages have risen
significantly. Power outages can create
dangerous and unsafe conditions as a
result of failure of lighting, elevators,
ventilation, fire pumps, security systems,
communications systems, and the like. In
addition, economic loss from outages can
be extremely high as a result of computer
downtime, or, especially in industrial
process plants, interruption of production.
Protective equipment must be adjusted
and maintained in order to function
properly when an overcurrent occurs.
Coordination, however, begins during
power system design with the knowledge
able analysis and selection and application
of each over
current protective device in
the series circuit from the power source(s)
to each load apparatus.
The objective of coordination is to localize
the overcurrent disturbance so that the
protective device closest to the fault on
the power-source side has the first chance
to operate. Each preceding protective
device upstream toward the power
source should be capable, within its
designed settings of current and time,
to provide backup and de-energize the
circuit if the fault persists. Sensitivity of
coordination is the degree to which the
protective devices can minimize the
damage to the faulted equipment.
To study and accomplish coordination
requires:
■ A one-line diagram, the roadmap
of the power distribution system,
showing all protective devices and
the major or important distribution
and utilization apparatus
■ Identification of desired degrees
of power continuity or criticality of
loads throughout system
■ Definition of operating-current
characteristics (normal, peak, starting)
of each utilization circuit
■ Equipment damage or withstand
characteristics
■ Calculation of maximum short-
circuit currents (and ground fault
currents if ground fault protection
is included) available at each
protective device location
■ Understanding of operating charac
teristics and available adjustments of
each protective device
■ Any special overcurrent protection
requirements including utility
limitations; refer to Figure 55
To ensure complete coordination, the
time-trip characteristics of all devices
in series should be plotted on a single
sheet of standard log-log paper. Devices
of different-voltage systems can be
plotted on the same sheet by converting
their current scales, using the voltage
ratios, to the same voltagebasis. Such
a coordination plot is shown in
Figure 55.
Figure 55. Time-Current Characteristic Curves for Typical Power Distribution System Protective Devices
Coordination Analysis
1000
10
9
7
6
.9
4
5
.5
.3
.2
100
90
30
20
500
300
200
10,000
8000
6000
9000
7000
5000
4000
3000
2000
1000
800
600
900
700
500
400
300
200
100
80
60
90
70
50
40
30
20
10
9
8
7
5 6
4
3
1 2
.9
.8
.7
.5 .6
600
900
800
700
400
40
8
50
80
60
70
3
1
2
.8
.7
.6
.4
.1
.09
.08
.07
.06
.05
.04
.03
.02
.01
10,000
8000
6000
9000
7000
5000
4000
3000
2000
1000
800
600
900
700
500
400
300
200
100
80
60
90
70
50
40
30
20
10
9
8
7
5 6
4
3
1 2
.9
.8
.7
.5 .6
1000
10
9
7
6
.9
4
5
.5
.3
.2
100
90
30
20
500
300
200
600
900
800
700
400
40
8
50
80
60
70
3
1
2
.8
.7
.6
.4
.1
.09
.08
.07
.06
.05
.04
.03
.02
.01
TIME
IN
SECONDS
SCALE X 100 = CURRENT IN AMPERES AT 480V
SCALE X 100 = CURRENT IN AMPERES AT 480V
TIME
IN
SECONDS
250 MVA
4.16 kV
250A
1000
kVA
5.75%
4,160V ∆
480/277V
19,600A
1,600A
24,400A
600A
D
C
B
A
M
20,000A
175A
100 hp –
124A FLC
X = Available fault current
including motor
contribution.
D
ANSI Three-Phase
Thru Fault
Protection Curve
(More Than 10 in
Lifetime)
C
B
A
C
B
A
B
C
Transformer
Inrush
Ground
Fault Trip
Max.
480V
Fault
Max.
Three-Phase
4.16
kV
Fault
M
System Protection Considerations
59

In this manner, primary fuses and circuit
breaker relays on the primary side of a
substation transformer can be coordinated
with the low voltage breakers.Transformer
damage points, based on ANSI standards,
and low voltage cable heating limits can
also be plotted on this set of curves to
ensure that apparatus limitations are
not exceeded.
Ground-fault curves may also be included
in the coordination study if ground-fault
protection is provided, but care must be
used in interpreting their meaning.
Standard definitions have been
established for overcurrent protective
devices covering ratings, operation
and application systems. Referring to
Figure 55, the Single Line Diagram
references the below defined equipment.
M—Motor (100 hp). Dashed line shows
initial inrush current, starting current
during 9-sec. acceleration, and drop to
124 A normal running current, all well
below CBA trip curve.
A—CB (175 A) coordinates selectively
with motor M on starting and running and
with all upstream devices, except that CB
B will trip first on low level ground faults.
B—CB (600 A) coordinates selectively
with all upstream and downstream
devices, except will trip before A on
limited ground faults, since A has no
ground fault trips.
C—Main CB (1600 A) coordinates
selectively with all downstream devices
and with primary fuse D, for all faults on
load side of CB.
D—Primary fuse (250 A, 4160V) coor
dinates selectively with all secondary
protective devices. Curve converted to
480V basis. Clears transformer inrush
point (12 x FLC for 0.1 sec.), indicating
that fuse will not blow on inrush. Fuse is
underneath right-half of ANSI three-phase
withstand curve, indicating fuse will
protect transformer for high-magnitude
faults up to ANSI rating.
Delta-wye transformer secondary
side short circuit is not reflected to the
primary by the following relation for L-L
and L-G faults.
For line-to-line fault, the secondary (low
voltage) side fault current is 0.866 x I
three-phase fault current.
However, the primary (high voltage) side
fault is the same as if the secondary fault
was a three-phase fault.
Therefore in coordination studies, the
knee of the short-time pickup setting
on the secondary breaker should be
multiplied by
before it is compared to the minimum
melting time of the upstream primary
fuse curve. In the example shown, the
knee is at 4000 A 30 sec., and the 30-sec.
trip time should be compared to the MMT
(minimum melt time) of the fuse curve at
4000 x 1.1547 = 4619 A. In this case, there
is adequate clearance to the fuse curve.
In the example shown, the ANSI
three-phase through fault transformer
protection curve must be multiplied
by 0.577 and replotted in order to
determine the protection given by the
primary for a single line to ground fault
in the secondary.
Maximum 480V three-phase fault
indicated on the horizontal current axis.
Maximum 4160V three-phase fault
indicated, converted to 480V basis.
The ANSI protection curves are
specified in ANSI C57.109 for liquid-
filled transformers and C57.12.59 for
dry-type transformers.
Illustrative examples such as shown
here start the coordination study from the
lowest rated device proceeding upstream.
In practice, the setting or rating of the
utility’s protective device sets the upper
limit. Even in cases where the customer
owns the medium voltage or higher
distribution system, the setting or rating
of the lowest set protective device at the
source deter
mines the settings of the
downstream devices and the coordination.
Therefore the coordination study should
start at the present setting or rating of the
upstream device and work toward the
lowest rated device. If this procedure
results in unacceptable settings, the
setting or rating of the upstream device
should be reviewed.Where the utility is
the sole source, they should be consulted.
Where the owner has its own medium or
higher voltage distribution, the settings
or ratings of all upstream devices should
be checked.
If perfect coordination is not feasible, then
lack of coordination should be limited to
the smallest part of the system.
Application data is available for all
protective equipment to permit systems
to be designed for adequate overcurrent
protection and coordination.
■ For circuit breakers of all types,
time-current curves permit selection of
instantaneous and inverse-time trips
■ For more complex circuit breakers,
with solid-state trip units, trip curves
include long- and short-time delays, as
well as ground-fault tripping, with a
wide range of settings and features to
provide selectivity and coordination
■ For current-limiting circuit breakers,
fuses, and circuit breakers with integral
fuses, not only are time-current
characteristic curves available, but also
data on current-limiting performance
and protection for downstream devices
In a fully rated system, all circuit breakers
must have an interrupting capacity
adequate for the maximum available fault
current at their point of application. All
breakers are equipped with long-time-
delay (and possibly short delay) and
instantaneous over
current trip devices.
A main breaker may have short time-
delay tripping to allow a feeder breaker
to isolate the fault while power is
maintained to all the remaining feeders.
A selective or fully coordinated system
permits maximum service continuity.
The tripping characteristics of each
overcurrent device in the system must
be selected and set so that the breaker
nearest the fault opens to isolate the
faulted circuit, while all other breakers
remain closed, continuing power to the
entire unfaulted part of the system.
The 2014 edition of the National Electrical
Code contains specific requirements for
designing certain circuits with selective
coordination. Article 100 defines selective
coordina
tion: Coordination (Selective), the
following definition: “Localization of an
overcurrent condition to restrict outages
to the circuit or equipment affected,
accomplished by the selec
tion and
installation of overcurrent protective
devices and their ratings or settings for
the full range of available overcurrents,
from overload to the maximum available
fault current, and for the full range of
overcurrent protective device opening
times associated with those overcurrents.
”

Article 620.62 (elevators, dumbwaiters,
escalators, moving walks, wheelchair
lifts, and stairway chair lifts) requires
“Where more than one driving machine
disconnecting means is supplied by a
single feeder, the overcurrent protective
devices in each disconnecting means
shall be selectively coordinated with any
other supply side overcurrent protective
device.
” A similar require
ment under
Article 700.28 is as follows; “Emergency
system(s) overcurrent devices shall be
selectively coordinated with all supply
side overcurrent protective devices.
”
Article 701.27 states that “Legally required
standby system(s) overcurrent devices
shall be selectively coordinated with all
supply side overcurrent devices.
”
Exception: Selective coordination shall
not be required between two overcurrent
devices located in series if no loads
are connected in parallel with the
downstream device.
In addition, for healthcare facilities,
Article 517.26, Application of Other
Articles requires that “The life safety
branch of the essential electrical system
shall meet the requirements of Article
700, except as amended by Article 517.
“
All Overcurrent Protective Devices must
have an interrupting capacity not less
than the maximum available short-circuit
current at their point of application. A
selective system is a fully rated system
with tripping devices chosen and adjusted
to provide the desired selectivity.
The tripping characteristics of each
overcurrent device should not over
lap,
but should maintain a minimum time
interval for devices in series (to allow
for normal operating tolerances) at all
current values. Generally, a maximum of
four low voltage circuit breakers can be
operated selectively in series, with the
feeder or branch breaker downstream
furthest from the source.
Specify true rms sensing devices in order
to avoid false trips due to rapid currents
or spikes. Specify tripping elements with
I2
t or I4t feature for improved coordination
with other devices having I2
t or I4
t
characteristics and fuses.
In general for systems such as shown in
Figure 55:
1. The settings or ratings of the
transformer primary side fuse and
main breaker must not exceed the
settings allowed by NEC Article 450.
2. At 12 x IFL the minimum melting time
characteristic of the fuse should be
higher than 0.1 second.
3. The primary fuse should be to the left
of the transformer damage curve as
much as possible.The correction factor
for a single line-to-ground factor must
be applied to the damage curve.
4. The setting of the short-time delay
element must be checked against the
fuse Minimum MeltTime (MMT) after
it is corrected for line-to-line faults.
5. The maximum fault current must be
indicated at the load side of each
protective device.
6. The setting of a feeder protective
device must comply with Article 240
and Article 430 of the NEC. It also must
allow the starting and acceleration
of the largest motor on the feeder
while carrying all the other loads on
the feeder.
Protection of Conductors (Excerpts
from NFPA 70-2014, Article 240.4)
Conductors, other than flexible cords and
fixture wires, shall be protected against
overcurrent in accordance with their
ampacities as specified in Section 310.15,
unless otherwise permitted or required in
240.4 (A) through (G).
A. Power Loss Hazard. Conductor
overload protection shall not be
required where the interruption of
the circuit would create a hazard,
such as in a material handling magnet
circuit or fire pump circuit. Short-
circuit protection shall be provided.
Note: FPN See NFPA 20-2013, standard for
the Installation of Stationary Pumps for
Fire Protection.
B. Devices Rated 800A or Less. The next
higher standard overcurrent device
rating (above the ampacity of the
conductors being protected) shall be
permitted to be used, provided all of
the following conditions are met.
1. The conductors being protected
are not part of a branch circuit
supplying more than one
receptacle for cord-and-plug-
connected portable loads.
2. The ampacity of the conductors
does not correspond with the
standard ampere rating of a fuse or
a circuit breaker without overload
trip adjustments above its rating
(but that shall be permitted to have
other trip or rating adjustments).
3. The next higher standard rating
selected does not exceed 800 A.
C. Overcurrent Devices Rated Over
800 A.Where the overcurrent device is
rated over 800 A, the ampacity of the
conductors it protects shall be equal
to or greater than the rating of the
overcurrent device as defined in
Section 240.6.
D. Small Conductors. Unless specifically
permitted in 240.4(E) or 240.4(G), the
overcurrent protection shall not
exceed 15 A for 14 AWG, 20 A for 12
AWG, and 30 A for 10 AWG copper; or
15 A for 12 AWG and 25 A for 10 AWG
aluminum and copper-clad aluminum
after any correction factors for
ambient temperature and number of
conductors have been applied.
E. Tap Conductors.Tap conductors shall
be permitted to be protected against
overcurrent in accordance with the
following:
1. 210.19(A)(3) and (A)(4) Household
Ranges and Cooking Appliances
and Other Loads.
2. 240.5(B)(2) FixtureWire.
3. 240.21 Location in Circuit.
4. 368.17(B) Reduction in Ampacity
Size of Busway.
5. 368.17(C) Feeder or Branch Circuits
(busway taps).
6. 430.53(D) Single MotorTaps.
61

Circuit Breaker Cable
Temperature Ratings
UL listed circuit breakers rated 125 A
or less shall be marked as being suitable
for 60 ºC (140 ºF), 75 ºC (167 ºF) only or
60/75 ºC (140/167 ºF) wire. All Eaton
breakers rated 125 A or less are marked
60/75 ºC (140/167 ºF). All UL listed circuit
breakers rated over 125 A are suitable for
75 ºC conductors.
Conductors rated for higher tempera
tures
may be used, but must not be loaded
to carry more current than the 75 ºC
ampacity of that size conductor for
equipment marked or rated 75 ºC or
the 60 ºC ampacity of that size conductor
for equipment marked or rated 60 ºC.
However, when applying derated factors,
so long as the actual load does not exceed
the lower of the derated ampacity or the
75 ºC or 60 ºC ampacity that applies.
Zone Selective Interlocking
Trip elements equipped with zone
selective interlocking, trip without
intentional time delay unless a restraint
signal is received from a protective device
downstream. Breakers equipped with this
feature reduce the damage at the point of
fault if the fault occurs at a location within
the zone of protection.
The upstream breaker upon receipt of
the restraint signal will not trip until
its time-delay setting times out. If the
breaker immediately downstream of the
fault does not open, then after timing out,
the upstream breaker will trip.
Breakers equipped with ground fault trip
elements should also be specified to
include zone interlocking for the ground
fault trip element.
Ground Fault Protection
Article 230.95 of NEC requires ground-
fault protection of equipment shall be
provided for solidly grounded wye
electrical services of more than 150V to
ground, but not exceeding 600V phase-
to-phase for each service disconnect
rated 1000 A or more.
The rating of the service disconnect shall
be considered to be the rating of the
largest fuse that can be installed or the
highest continuous current trip setting
for which the actual overcurrent device
installed in a circuit breaker is rated or
can be adjusted.
The maximum allowable settings are:
1200 A pickup, 1 second or less trip delay
at currents of 3000 A or greater.
The characteristics of the ground-fault trip
elements create coordination problems
with downstream devices not equipped
with ground fault protection.The National
Electrical Code exempts fire pumps and
continuous industrial processes from
this requirement.
The NEC has addressed the concern
that the impedance added by a step-up,
step-down or isolation transformer
causes the primary side ground fault
protection to be desensitized to faults
on its secondary side. Consequently,
Article 215.10 clarifies the need for
equipment ground fault protection on
1000 A and above 480Vac feeder circuit
disconnects on the secondary of these
transformers. Article 210.13 has been
added to the 2014 NEC, which recognized
the same need for branch circuits being
fed by transformers, as for feeder circuits
outlined in Article 215.10.
It is recommended that in solidly
grounded 480/277V systems where main
breakers are specified to be equipped with
ground fault trip elements that the feeder
breakers be specified to be equipped with
ground fault trip elements as well.
Suggested Ground Fault Settings
For the main devices:
A ground fault pickup setting equal to
20–30% of the main breaker rating but not
to exceed 1200 A, and a time delay equal
to the delay of the short- time element,
but not to exceed 1 second.
For the feeder ground fault setting:
A setting equal to 20–30% of the feeder
ampacity and a time delay to coordinate
with the setting of the main (at least
6 cycles below the main).
If the desire to selectively coordinate
ground fault devices results in settings
that do not offer adequate damage
protection against arcing single line-
ground faults, the design engineer
should decide between coordination
and damage limitation.
For low-voltage systems with high-
magnitude available short-circuit
currents, common in urban areas and
large industrial installations, several
solutions are available:
■ High interrupting molded case breakers
■ Current-limiting circuit breakers or
current-limiting fuses
■ Limiters integral with molded case
circuit breakers (TRI-PACT)
■ MDS-L power circuit breakers with
integral current-limiting fuses or
MDS-X without current-limiting fuses
To provide current limiting, these devices
must clear the fault completely within the
first half-cycle, limiting the peak current
(Ip
) and heat energy (I2
t) let-through to
considerably less than what would have
occurred without the device.
For a fully fusible system, rule-of-thumb
fuse ratios or more accurate I2
t curves
can be used to provide selectivity
and coordination. For fuse-breaker
combinations, the fuse should be selected
(coordinated) so as to permit the breaker
to handle those overloads and faults
within its capacity; the fuse should
operate before or with the current breaker
only on large faults, approaching the
current interrupting capacity of the
breaker, to minimize fuse blowing.
The three-pole FDCE breakers include
a Digitrip 310+ electronic trip unit and
are available in three models covering
loads from 15 A through 225 A. Optional
equipment ground fault allows the
designer to extend protection to smaller
loads that are more likely to cause a
ground fault trip, such as motors or
lighting. Zone Selective Interlocking is
also available to ensure coordinated
tripping with upstream breakers.
The Series G high performance, current-
limiting circuit breaker series offers
interrupting ratings to 200 kA. Frames
are EGC, JGC and LGU.

Any of these current-limiting devices—
fuses, fused breakers or current-limit
ing
breakers—cannot only clear these large
faults safely, but also will limit the Ip
and
I2
t let-through significantly to prevent
damage to apparatus downstream,
extending their zone of protection.
Without the current limitation of the
upstream device, the fault current could
exceed the withstand capability of the
downstream equipment.
Underwriters Laboratories tests and lists
these series combinations. Application
information is available for combinations
that have been tested and ULT-listed for
safe operation.
Protective devices in electrical distribution
systems may be properly coordinated
when the systems are designed and built,
but that is no guarantee that they will
remain coordinated. System changes
and additions, plus power source
changes, frequently modify the protection
requirements, sometimes causing loss
of coordination and even increasing
fault currents beyond the ratings of
some devices.
The 2014 National Electrical Code (NEC)
included new marking require
ments for
electrical equipment. Article 110.24 applies
to service equipment in other than
dwelling units and mandates that they
“shall be legibly marked in the field with
the maximum available fault current.
The field marking(s) shall include the
date the fault-current calculation was
performed and be of sufficient durability
to withstand the environ
ment involved.
”
Article 110.24 (B) requires that: “When
modifications to the electrical installation
occur that affect the maximum available
fault current at the service, the maximum
available fault current shall be verified or
recalculated as necessary.The required
field marking(s) in 110.24 (A) shall be
adjusted to reflect the new level of
maximum available fault current.
”
Consequently, periodic study of
protective-device settings and ratings is
as important for safety and preventing
power outages as is periodic maintenance
of the distribution system.
In addition, NFPA 70E 130.3 requires the
study be reviewed periodically, but not
less than every 5 years, to account for
changes in the electrical distribution
system that could affect the original
arc-flash analysis.
Arc Flash Considerations
The Arcflash Reduction Maintenance
System™ is available on power circuit
breakers, insulated case circuit breakers
and molded case circuit breakers.The
trip units have maintenance settings of
2.5 to 4 times the current setting.These
breakers deliver faster clearing times
than standard instantaneous trip by
eliminating the microprocessor
processing latencies.This system
is superior to simply reducing the
instantaneous setting and results in
arc energy reduction that can allow
for reduced PPE, improving worker
dexterity and mobility.The system can
also include a remote activation switch
with status indicator.
NEC 2014 240.87 requires Arc Energy
Reduction “Where the highest continu
ous
current trip setting for which the actual
overcurrent device installed in a circuit
breaker is rated or can be adjusted is
1200 A or higher, 240.87(A) and (B)
shall apply.
A. Documentation shall be available to
those authorized to design, install,
operate or inspect the installation as
to the location of the circuit breaker(s).
B. Method to Reduce ClearingTime.
One of the following or approved
equivalent means shall be provided:
1. Zone-selective interlocking
2. Differential relaying
3. Energy-reducing maintenance
switching with local status indicator
4. Energy-reducing active arc flash
mitigation system
5. An approved equivalent means”
63

Grounding
Grounding encompasses several
different but interrelated aspects of
electrical distribution system design and
construction, all of which are essential to
the safety and proper operation of the
system and equip
ment supplied by it.
Among these are: equipment grounding,
system grounding, static and lightning
protection, and connection to earth as a
reference (zero) potential.
1. Equipment Grounding
Equipment grounding is essential to
safety of personnel. Its function is to
ensure that all exposed noncurrent-
carrying metallic parts of all structures
and equipment in or near the electrical
distribution system are at the same
potential, and that this is the zero
reference potential of the earth.
Equipment grounding is required by both
the National Electrical Code (Article 250)
and the National Electrical Safety Code
regardless of how the power system is
grounded. Equipment grounding also
provides a return path for ground fault
currents, permitting protective devices
to operate.
Accidental contact of an energized
conductor of the system with an
improperly grounded noncurrent-
carrying metallic part of the system
(such as a motor frame or panelboard
enclosure) would raise the potential of
the metal object above ground poten
tial.
Any person coming in contact with such an
object while grounded could be seriously
injured or killed. In addi
tion, current flow
from the accidental grounding of an
energized part of the system could
generate sufficient heat (often with
arcing) to start a fire.
To prevent the establishment of such
unsafe potential difference requires that:
■ The equipment grounding conductor
provide a return path for ground fault
currents of sufficiently low impedance
to prevent unsafe voltage drop
■ The equipment grounding conductor
be large enough to carry the maximum
ground fault current, without burning
off, for sufficient time to permit
protective devices (ground fault relays,
circuit breakers, fuses) to clear the fault
The grounded conductor of the system
(usually the neutral conductor), although
grounded at the source, must not be used
for equipment grounding.
The equipment grounding conductor may
be the metallic conduit or raceway of the
wiring system, or a separate equipment
grounding conductor, run with the circuit
conductors, as permitted by NEC. If a
separate equipment grounding conductor
is used, it may be bare or insulated; if
insulated, the insulation must be green,
green with yellow stripe or green tape.
Conductors with green insulation may
not be used for any purpose other than
for equipment grounding.
The equipment grounding system must
be bonded to the grounding electrode at
the source or service; however, it may be
also connected to ground at many other
points.This will not cause problems with
the safe operation of the electrical
Where computers, data processing,
or microprocessor-based industrial
process control systems are installed,
the equipment grounding system must
be designed to minimize interference
with their proper operation. Often,
isolated grounding of this equipment,
or isolated electrical supply systems
are required to protect microprocessors
from power system “noise” that does
not in any way affect motors or other
electrical equipment.
Such systems must use single-point
ground concept to minimize “noise”
and still meet the NEC requirements.
Any separate isolated ground mat must
be tied to the rest of the facility ground
mat system for NEC compliance.
2. System Grounding
System grounding connects the electrical
supply, from the utility, from transformer
secondary windings, or from a generator,
to ground. A system can be solidly
grounded (no intentional impedance to
ground), impedance grounded (through
a resistance or reactance), or ungrounded
(with no intentional connection to ground.
3. Medium-Voltage System: Grounding
Table 18. Features of Ungrounded and Grounded Systems (from ANSI C62.92)
Description A
Ungrounded
B
Solidly Grounded
C
Reactance Grounded
D
Resistance Grounded
E
Resonant Grounded
(1) Apparatus
insulation
Fully insulated Lowest Partially graded Partially graded Partially graded
(2) Fault to
ground current
Usually low Maximum value rarely
higher than three-phase
short circuit current
Cannot satisfactorily be
reduced below one-half
or one-third of values
for solid grounding
Low Negligible except when
Petersen coil is short
circuited for relay
purposes when it may
compare with solidly
grounded systems
(3) Stability Usually unimportant Lower than with other
methods but can be
made satisfactory by use
of high-speed breakers
Improved over solid
grounding particularly
if used at receiving end
of system
Improved over solid
grounding particularly
if used at receiving end
of system
Is eliminated from
consideration during
single line-to-ground faults
unless neutralizer is short
circuited to isolate fault by
relays
(4) Relaying Difficult Satisfactory Satisfactory Satisfactory Requires special
provisions but can be
made satisfactory
(5) Arcing
grounds
Likely Unlikely Possible if reactance
is excessive
Unlikely Unlikely
(6) Localizing
faults
Effect of fault transmitted
as excess voltage on
sound phases to all parts
of conductively
connected network
Effect of faults localized to
system or part of system
where they occur
Effect of faults localized to
system or part of system
where they occur unless
reactance is quite high
Effect of faults transmitted
sound phases to all
parts of conductively
connected network
Effect of faults transmitted
sound phases to all
parts of conductively
connected network

Table 18. Features of Ungrounded and Grounded Systems (Continued)
Description A
Ungrounded
B
Solidly Grounded
C
Reactance Grounded
D
Resistance Grounded
E
Resonant Grounded
(7) Double faults Likely Likely Unlikely unless reactance
is quite high and insulation
weak
Unlikely unless resistance
is quite high and insulation
weak
Seem to be more likely but
conclusive information
not available
(8) Lightning
protection
Ungrounded neutral
service arresters must be
applied at sacrifice in cost
and efficiency
Highest efficiency and
lowest cost
If reactance is very high
arresters for ungrounded
neutral service must be
applied at sacrifice in cost
and efficiency
Arresters for ungrounded,
neutral service usually
must be applied at sacrifice
in cost and efficiency
Ungrounded neutral
service arresters must
be applied at sacrifice in
cost and efficiency
(9)Telephone
interference
Will usually be low except
in cases of double faults
or electrostatic induction
with neutral displaced but
duration may be great
Will be greatest in
magnitude due to higher
fault currents but can be
quickly cleared particularly
with high speed breakers
Will be reduced from
solidly grounded values
Will be reduced from
solidly grounded values
Will be low in magnitude
except in cases of double
faults or series resonance
at harmonic frequencies,
but duration may be great
(10) Radio
interference
May be quite high during
faults or when neutral
is displayed
Minimum Greater than for
solidly grounded,
when faults occur
Greater than for solidly
grounded, when faults
occur
May be high during faults
(11) Line
availability
Will inherently clear
themselves if total length
of interconnected line is
low and require isolation
from system in increasing
percentages as length
becomes greater
Must be isolated for
each fault
each fault
each fault
Need not be isolated but
will inherently clear itself
in about 60 to 80 percent
of faults
(12) Adaptability
to
interconnection
Cannot be interconnected
unless interconnecting
system is ungrounded or
isolating transformers
are used
Satisfactory indefinitely
with reactance-grounded
systems
Satisfactory indefinitely
with solidly-grounded
systems
Satisfactory with solidly-
or reactance-grounded
systems with proper
attention to relaying
Cannot be interconnected
unless interconnected
system is resonant
grounded or isolating
transformers are used.
Requires coordination
between interconnected
systems in neutralizer
settings
(13) Circuit
breakers
Interrupting capacity
determined by three-phase
conditions
Same interrupting
capacity as required for
three-phase short circuit
will practically always be
satisfactory
fault conditions
fault conditions
fault conditions
(14) Operating
procedure
Ordinarily simple but
possibility of double faults
introduces complication
in times of trouble
Simple Simple Simple Taps on neutralizers must
be changed when major
system switching is
performed and difficulty
may arise in intercon
nected systems. Difficult
to tell where faults are
located
(15)Total cost High, unless conditions
are such that arc tends to
extinguish itself, when
transmission circuits may
be eliminated, reducing
total cost
Lowest Intermediate Intermediate Highest unless the arc
suppressing characteristic
is relied on to eliminate
transmission circuits when
it may be lowest for the
particular types of service
Because the method of grounding
affects the voltage rise of the unfaulted
phases above ground, ANSI C62.92
classifies systems from the point of view
of grounding in terms of a coefficient
of grounding
This same standard also defines systems
as effectively grounded when COG is less
than or equal to 0.8. Such a system would
have X0
/X1
less than or equal to 3.0 and
R0
/X1
less than or equal to 1.0. Any other
grounding means that does not satisfy
these conditions at any point in a system
is not effectively grounded.
The aforementioned definition is
of significance in medium-voltage
distribution systems with long lines and
with grounded sources removed during
light load periods so that in some locations
in the system the X0
/X1
, R0
/X1
may exceed
the defining limits. Other standards (cable
and lightning arrester) allow the use of
100% rated cables and arresters selected
on the basis of an effectively grounded
system only where the criteria in the above
are met. In effectively grounded system
the line-to-ground fault current is high and
there is no significant voltage rise in the
unfaulted phases.
With selective ground fault isolation the
fault current should be at least 60% of the
three-phase current at the point of fault.
Damage to cable shields must be checked.
Although this fact is not a problem
except in small cables, it is a good idea
to supplement the cable shields returns
of ground fault current to prevent
damage, by installing an equipment
grounding conductor.
The burdens on the current transformers
must be checked also (for saturation
considerations), where residually
connected ground relays are used and the
current transformers supply current to
phase relays and meters.
65

If ground sensor current transformers
(zero sequence type) are used they must
be of high burden capacity.
Table 19 taken from ANSI-C62.92 indicates
the characteristics of the
various methods of grounding.
Reactance Grounding
It is generally used in the grounding of the
neutrals of generators directly connected
to the distribution system bus, in order to
limit the line-to-ground fault to somewhat
less than the three-phase fault at the
generator terminals. If the reactor is so
sized, in all probability the system will
remain effectively grounded.
Resistance Grounded
Medium-voltage systems in general
should be low resistance grounded.The
ground fault is typically limited to about
200–400 A but less than 1000 A (a cable
shield consideration).With a properly
sized resistor and relaying application,
selective fault isolation is feasible.The
fault limit provided has a bearing on
whether residually connected relays
are used or ground sensor current
transformers are used for ground
fault relaying.
In general, where residually connected
ground relays are used (51N), the fault
current at each grounded source should
not be limited to less than the current
transformers rating of the source.This
rule will provide sensitive differential
protection for wye-connected generators
and transformers against line-to-ground
faults near the neutral.
Of course, if the installation of ground
fault differential protection is feasible, or
ground sensor current transformers are
used, sensitive differential relaying in
resistance grounded system with greater
fault limitation is feasible. In general,
ground sensor current transformers
(zero sequence) do not have high
burden capacity.
Resistance grounded systems limit the
circulating currents of triplen harmonics
and limit the damage at the point of fault.
This method of grounding is not suitable
for line-to-neutral connection of loads.
On medium-voltage systems, 100% cable
insulation is rated for phase-to-neutral
voltage. If continued operation with
one phase faulted to ground is desired,
increased insulation thickness is required.
For 100% insulation, fault clearance is
recommended within one minute; for
133% insulation, one hour is acceptable;
for indefinite operation, as long as
necessary, 173% insulation is required.
Table 19. Characteristics of Grounding
Grounding Classes
and Means
Ratios of Symmetrical
Component Parameters a
Percent Fault
Current
Per UnitTransient
LGVoltage
A. Effectively d
1. Effective
2.Very effective
X0
/X1
0-3
0-1
R0
/X1
0-1
0-0.1
R0
/X0
—
—
b
>60
>95
c
≤2
<1.5
B. Noneffectively
1. Inductance
a. Low inductance
b. High inductance
2. Resistance
a. Low resistance
b. High resistance
3. Inductance and resistance
4. Resonant
5. Ungrounded/capacitance
a. Range A
b. Range B
3-10
>10
0-10
—
>10
e
∞ to -40 f
-40 to 0
0-1
—
—
>100
—
—
—
—
—
<2
Š2
≤(-1)
>2
—
—
—
>25
<25
<25
<1
<10
<1
<8
>8
<2.3
≤2.73 g
<2.5
≤2.73
≤2.73
≤2.73
≤3 i
>3 hi
a Values of the coefficient of grounding (expressed as a percentage of maximum phase-to-phase voltage)
corresponding to various combinations of these ratios are shown in the ANSI C62.92 Appendix figures.
Coefficient of grounding affects the selection of arrester ratings.
b Ground-fault current in percentage of the three-phase short-circuit value.
c Transient line-to-ground voltage, following the sudden initiation of a fault in per unit of the crest of the
prefault line-to-ground operating voltage for a simple, linear circuit.
d In linear circuits, Class A1 limits the fundamental line-to-ground voltage on an unfaulted phase to 138%
of the prefault voltage; Class A2 to less than 110%.
e See ANSI 62.92 para. 7.3 and precautions given in application sections.
f Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive (negative).
g Under restriking arcing ground fault conditions (e.g., vacuum breaker interrupter operation), this value
can approach 500%.
h Same as NOTE (6) and refer to ANSI 62.92 para. 7.4. Each case should be treated on its own merit.
i Under arcing ground fault conditions, this value can easily reach 700%, but is essentially unlimited.
Grounding Point
The most commonly used grounding point
is the neutral of the system.This may be
a neutral point created by means of a
zigzag or a wye-broken delta grounding
transformer in a system that was operating
as an ungrounded delta system.
In general, it is a good practice that all
source neutrals be grounded with the
same grounding impedance magnitude.
However, neutrals should not be tied
together to a single resistor.Where one of
the medium-voltage sources is the utility,
their consent for impedance grounding
must be obtained.
The neutral impedance must have a
voltage rating at least equal to the rated
line-to-neutral voltage class of the system.
It must have at least a 10-second rating
equal to the maximum future line-to-
ground fault current and a continuous
rating to accommodate the triplen
harmonics that may be present.
4. Low-Voltage System: Grounding
Solidly grounded three-phase systems
(Figure 56) are usually wye-connected, with
the neutral point grounded. Less common
is the “red-leg” or high-leg delta, a 240V
system supplied by some utilities with
one winding center-tapped to provide 120
V to ground for lighting.This 240V,
three-phase, four-wire system is used
where 120V lighting load is small
compared to 240V power load, because
the installation is low in cost to the utility.
Figure 56. Solidly Grounded Systems
•
• • •
•
Phase B
Phase C
Phase A
Neutral
Center-Tapped (High-Leg) Delta
Grounded Wye
•
•
• •
• Phase C
Phase A
Phase B
Neutral
N
• Phase A
Phase B
Phase C
•
• •
Corner-Grounded Delta

A corner-grounded three-phase delta
system is sometimes found, with one
phase grounded to stabilize all voltages
to ground. Better solutions are available
for new installations.
Ungrounded systems (Figure 57)
can be either wye or delta, although
the ungrounded delta system is far
more common.
Figure 57. Ungrounded Systems
Resistance-grounded systems
(Figure 58) are simplest with a
wye connection, grounding the neutral
point directly through the resistor.
Delta systems can be grounded by
means of a zig-zag or other grounding
transformer.Wye broken delta
transformer banks may also be used.
Figure 58. Resistance-Grounded Systems
These arrangements create a derived
neutral point, which can be either solidly
or impedance-grounded. If the grounding
transformer has sufficient capacity, the
neutral created can be solidly grounded
and used as part of a three-phase,
four-wire system.
Most transformer-supplied systems are
either solidly grounded or resis
tance
grounded. Generator neutrals are often
grounded through a reactor, to limit
ground fault (zero sequence) currents to
values the generator can withstand.
Selecting the Low-Voltage System
Grounding Method
There is no one “best” distribution system
for all applications. In choosing among
solidly grounded, resistance grounded,
or ungrounded power distribution, the
characteristics of the system must be
weighed against the requirements of
power loads, lighting loads, continuity
of service, safety and cost.
Under ground fault conditions, each
system behaves very differently:
■ A solidly grounded system produces
high fault currents, usually with arcing,
and the faulted circuit must be cleared
on the first fault within a fraction of a
second to minimize damage
■ An ungrounded system will pass limited
current into the first ground fault—
only the charging current of the system,
caused by the distributed capacitance
to ground of the system wiring and
equip
ment. In low-voltage systems,
this is rarely more than 1 or 2 A
Therefore, on first ground fault, an
ungrounded system can continue in
service, making it desirable where power
outages cannot be tolerated. However, if
the ground fault is intermittent, sputtering
or arcing, a high voltage—as much as
6 to 8 times phase voltage—can be built
up across the system capacitance, from
the phase conductors to ground.
Similar high voltages can occur as
a result of resonance between system
capacitance and the inductances of
transformers and motors in the system.
However, the phase-to-phase voltage is
not affected.This high transient phase-to-
ground voltage can puncture insulation
at weak points, such as motor windings,
and is a frequent cause of multiple motor
failures on ungrounded systems.
Locating a first fault on an ungrounded
system can be difficult. If, before the first
fault is cleared, a second ground fault
occurs on a different phase, even on a
different, remote feeder, it is a high-
current phase-to-ground-to-phase fault.
These faults are usually arcing and can
cause severe damage if at least one of
the grounds is not cleared immediately.
If the second circuit is remote, enough
current may not flow to cause protection
to operate.This can leave high voltages
and stray currents on structures and
jeopardize personnel.
In general, where loads will be connected
line-to-neutral, solidly grounded systems
are used. High resistance grounded
systems are used as substitutes for
ungrounded systems where high
system availability is required.
With one phase grounded, the voltage to
ground of the other two phases rises 73%,
to full phase-to-phase voltage. In low-
voltage systems this is not important,
since conductors are insulated for 600V.
A low-voltage resistance grounded
system is normally grounded so that
the single line-to-ground fault current
exceeds the capacitive charging current
of the system. If data for the charging
current is not available, use 40–50 ohm
resistor in the neutral of the transformer.
In commercial and institutional
installations, such as office buildings,
shopping centers, schools and hospitals,
lighting loads are often 50% or more of
the total load. In addition, a feeder outage
on first ground fault is seldom crucial—
even in hospitals, that have emergency
power in critical areas. For these reasons,
a solidly grounded wye distribution, with
the neutral used for lighting circuits, is
usually the most economical, effective
and convenient design. In some
instances, it is an NEC requirement.
In industrial installations, the effect of
a shutdown caused by a single ground
fault could be disastrous. An interrupted
process could cause the loss of all the
materials involved, often ruin the process
equipment itself, and sometimes create
extremely danger
ous situations for
operating personnel.
On the other hand, lighting is usually only
a small fraction of the total industrial
electrical load. Conse
quently, a solidly
grounded neutral circuit conductor is not
imperative.When required, a neutral to
feed the lighting loads can be obtained
from inexpensive lighting transformers.
Phase B
• Phase A
Phase C
• •
Ungrounded Delta
Ungrounded Wye
•
• •
• Phase C
Phase A
Phase B
N
•
Resistance-Grounded Wye
• •
• Phase C
Phase A
Phase B
R
N
• • Phase A
•
•
•
•
Phase B
Phase C
• •
Delta With Derived Neutral Resistance-
Grounded Using Zig-Zag Transformer
•
R
N
67

Because of the ability to continue in
operation with one ground fault on the
system, many existing industrial plants
use ungrounded delta distribu
tion.
Today, new installations can have all
the advantages of service continuity of
the ungrounded delta, yet minimize the
problems of the system, such as the
difficulty of locating the first ground fault,
risk of damage from a second ground
fault, and damage transient overvoltages.
A high-resistance grounded wye
distribution can continue in operation
with a ground fault on the system and
will not develop transient overvoltages.
And, because the ground point is
established, locating a ground fault is
less difficult than on an ungrounded
system especially when a “pulsing
contactor” design is applied.When
combined with sensitive ground-fault
protection, damage from a second
ground fault can be nearly eliminated.
Ungrounded delta systems can be
converted to high-resistance grounded
systems, using a zig-zag or other
grounding transformer to derive a neutral,
with similar benefits.While the majority
of manufacturing plants use solidly
grounded systems, in many instances,
the high-resistance grounded distribu
tion
will be the most advantageous.
Ground Fault Protection
A ground fault normally occurs in one
of two ways: by accidental contact of
an energized conductor with normally
grounded metal, or as a result of an
insulation failure of an energized
conductor.When an insulation failure
occurs, the energized conductor contacts
normally noncurrent-carrying grounded
metal, which is bonded to or part of the
equipment grounding conductor.
In a solidly grounded system, the fault
current returns to the source primarily
along the equipment grounding
conductors, with a small part using parallel
paths such as building steel or piping. If
the ground return impedance was as low
as that of the circuit conductors, ground
fault currents would be high, and the
normal phase overcurrent protection
would clear them with little damage.
Unfortunately, the impedance of the
ground return path is usually higher,
the fault itself is usually arcing and the
impedance of the arc further reduces the
fault current. In a 480Y/277V system, the
voltage drop across the arc can be from
70 to 140V.
The resulting ground fault current is
rarely enough to cause the phase
overcurrent protection device to open
instantaneously and prevent damage.
Sometimes, the ground fault is below the
trip setting of the protective device and it
does not trip at all until the fault escalates
and extensive damage is done. For these
reasons, low level ground protection
devices with mini
mum time delay
settings are required to rapidly clear
ground faults.This is emphasized by the
NEC requirement that a ground fault relay
on a service shall have a maximum delay
of one second for faults of 3000 A or more.
The NEC (Sec. 230.95) requires that
ground fault protection, set at no more
than 1200 A, be provided for each service
disconnecting means rated 1000 A or
more on solidly grounded wye services
of more than 150V to ground, but
not exceeding 600V phase-to-phase.
Practically, this makes ground fault
protection mandatory on 480Y/277V
services, but not on 208Y/120V services.
On a 208V system, the voltage to ground
is 120V. If a ground fault occurs, the arc
goes out at current zero, and the voltage
to ground is often too low to cause it
to restrike.Therefore, arcing ground
faults on 208V systems tend to be
self-extinguishing.
On a 480V system, with 277V to
ground, restrike usually takes place
after current zero, and the arc tends to
be self-sustaining, causing severe and
increasing damage, until the fault is
cleared by a protective device.
The NEC requires ground fault service
disconnecting means rated 1000 A or
higher.This protection works so fast that
for ground faults on feeders, or even
branch circuits, it will often open the
service disconnect before the feeder or
branch circuit overcurrent device can
operate.This is highly undesirable, and
in the NEC (230.95), an informational
note states that “additional ground fault
protective equipment may be needed
on feeders and branch circuits where
maximum continuity of electric service
is necessary.
”
Unless it is acceptable to disconnect the
entire service on a ground fault almost
anywhere in the system, such additional
stages of ground fault protection must
be provided. At least two stages of
protection are mandatory in healthcare
facilities (NEC Sec. 517.17).
Overcurrent protection is designed
to protect conductors and equipment
against currents that exceed their
ampacity or rating under prescribed
time values. An overcurrent can result
from an overload, short circuit or (high
level) ground fault condition.
When currents flow outside the normal
current path to ground, supplementary
ground fault protection equipment will be
required to sense low-level ground fault
currents and initiate the protection
required. Normal phase overcurrent
protection devices provide no protection
against low-level ground faults.
There are three basic means of sensing
ground faults.The most simple and direct
method is the ground return method as
illustrated in Figure 59.This sensing
method is based on the fact that all
currents supplied by a trans
former
must return to that transformer.
Figure 59. Ground Return Sensing Method
When an energized conductor faults to
grounded metal, the fault current returns
along the ground return path to the
neutral of the source transformer.This
path includes the main bonding jumper
as shown in Figure 59.
A current sensor on this conductor
(which can be a conventional bar-type or
window type CT) will respond to ground
fault currents only. Normal neutral
currents resulting from unbalanced loads
will return along the neutral conductor
and will not be detected by the ground
return sensor.
This is an inexpensive method of sensing
ground faults where protection per
NEC (230.95) is desired. For it to operate
properly, the neutral must be grounded
in only one place as indicated in
Figure 59. In many installations, the
servicing utility grounds the neutral at the
transformer and additional grounding is
required in the service equipment per
NEC (250.24(A)(2)).
Main
GFR
Neutral
Typical
Feeder
Sensor
Main Bonding
Jumper
Equipment
Grounding
Conductor
Grounding
Electrode
Conductor
Typical
4W Load
Service
Transformer
Ground Bus

In such cases, and others including
multiple source with multiple, inter
connected neutral ground points,
residual or zero sequence ground
sensing methods should be employed.
A second method of detecting ground
faults involves the use of a zero sequence
sensing method, as illus
trated in
Figure 60.This sensing method requires a
single specially designed sensor, either of
a toroidal or rectangular shaped
configuration.This core balance current
transformer surrounds all the phase and
neutral conductors in a typical three-
phase, four-wire distribution system.
This sensing method is based on the fact
that the vectorial sum of the phase and
neutral currents in any distribution circuit
will equal zero unless a ground fault
condition exists downstream from the
sensor. All currents that flow only in the
circuit conductors, including balanced or
unbalanced phase-to-phase and phase-
to-neutral normal or fault currents, and
harmonic currents, will result in zero
sensor output.
However, should any conductor become
grounded, the fault current will return
along the ground path—not the normal
circuit conductors. Consequently, the
sensor will have an unbalanced magnetic
flux condition.The ground fault relay will
sense the unbalance and provide a trip
signal to the breaker.
Figure 60. Zero Sequence Sensing Method
Zero sequence sensors are available with
various window openings for circuits with
small or large conductors, and even with
large rectangular win
dows to fit over bus
bars or multiple large size conductors in
parallel. Some sensors have split cores
for installation over existing conductors
without disturbing the connections.
This method of sensing ground faults
can be employed on the main discon
nect
where protection per NEC (230.95) is
desired. It can also be easily employed
in multi-tier systems where additional
levels of ground fault protection are
desired for added service continuity.
Additional grounding points may be
employed upstream of the sensor, but
not on the load side.
Ground fault protection employing
ground return or zero sequence sensing
methods can be accomplished by the use
of separate ground fault relays (GFRs)
and disconnects equipped with standard
shunt trip devices. Alternately, it can be
done by circuit breakers using electronic
trip units with integral ground fault
protection using external connections
from sensors arranged for this mode of
sensing. In some cases, a reliable source
of control power is needed.
The third basic method of detecting
ground faults involves the use of multiple
current sensors connected in a residual
sensing method as illus
trated in
Figure 61.This is a very common sensing
method used with circuit breakers
equipped with elec
tronic trip units,
current sensors and integral ground fault
protection.The three-phase sensors are
required for normal phase overcurrent
protection. Ground fault sensing is
obtained with the addition of an identically
rated sensor mounted on the neutral.
In a residual sensing scheme, the
relationship of the polarity markings—
as noted by the “X” on each sensor—is
critical. Because the vectorial sum of the
currents in all the conductors will total
zero under normal, non-ground faulted
conditions, it is imperative that proper
polarity connections are employed to
reflect this condition.
Figure 61. Residual Sensing Method
As with the zero sequence sensing
method, the resultant residual sensor
output to the ground fault relay or integral
ground fault tripping circuit will be zero if
all currents flow only in the circuit
conductors. Should a ground fault occur,
the current from the faulted conductor
will return along the ground path, rather
than on the other circuit conductors, and
the resid
ual sum of the sensor outputs
will not be zero.When the level of ground
fault current exceeds the pre-set current
and time delay settings, a ground fault
tripping action will be initiated.
This method of sensing ground faults can
be economically applied on main service
disconnects where circuit break
ers with
integral ground fault protection are
provided. It can be used in protec
tion
schemes per NEC (230.95) or in multi-tier
schemes where additional levels of
ground fault protection are desired for
added service continuity. Additional
grounding points may be employed
upstream of the residual sensors, but
not on the load side.
Both the zero sequence and residual
sensing methods have been commonly
referred to as “vectorial summation”
methods.
Most distribution systems can use either
of the three sensing methods exclusively
or a combination of the sensing methods
depending upon the complexity of the
system and the degree of service
continuity and selective coordination
desired. Different methods will be
required depending upon the number
of supply sources, and the number and
location of system grounding points.
As an example, one of the more
frequently used systems where continuity
of service to critical loads is a factor is
the dual source system illustrated in
Figure 62.This system uses tie-point
grounding as permitted under NEC Sec.
250.24(A)(3).The use of this grounding
method is limited to services that are
dual fed (double-ended) in a common
enclosure or grouped together in
separate enclo
sures, employing a
secondary tie.
Zero
Sequence
Sensor
Main
Neutral
Typical
Feeder
Alternate
Sensor
Location
Typical
4W Load
GFR
GFR
Typical
4W Load
Sensor
Polarity
Marks
Neutral
Typical
Feeder
Main
Residual
Sensors
69

This scheme uses individual sensors
connected in ground return fashion. Under
tie breaker closed operating conditions,
either the M1 sensor or M2 sensor could
see neutral unbalance currents and
possibly initiate an improper tripping
operation. However, with the polarity
arrangements of these two sensors along
with the tie breaker auxiliary switch (T/a)
and interconnections as shown, this
possibility is eliminated.
Selective ground fault tripping coordina
tion between the tie breaker and the
two main circuit breakers is achieved by
pre-set current pickup and time delay
settings between devices GFR/1, GFR/2
and GFR/T.
The advantages of increased service
continuity offered by this system can only
be effectively used if additional levels of
ground fault protection are added on each
downstream feeder. Some users prefer
individual grounding of the transformer
neutrals. In such cases, a partial
differential ground fault scheme should
be used for the mains and tie breaker.
An example of a residual partial differ
ential scheme is shown in Figure 63.The
scheme typically relies upon the vector
sum of at least two neutral sensors in
combination with each breakers’ three-
phase sensors.To reduce the complexity
of the drawing, each of the breakers’
three-phase sensors have not been
shown. It is absolutely critical that the
sensors’ polarities are supplied as shown,
the neutral sensor ratings of the mains
and tie are the same, and that there are no
other grounds on the neutral bus made
downstream of points shown.
An infinite number of ground fault
protection schemes can be developed
depending upon the number of alternate
sources, the number of grounding points
and system interconnections involved.
Depending upon the individual system
configuration, either mode of sensing
or a combination of all types may be
employed to accomplish the desired
end results.
The NEC (230.95) limits the maximum
setting of the ground fault protection used
on service equipment to 1200 A (and timed
tripping at 3000 A for one second). In order
to prevent tripping of the main service
disconnect on a downstream feeder
ground fault, ground fault protection
must be provided on all the feeders.
Figure 62. Dual Source System—Single Point Grounding
Note: This GF scheme requires trip units to be set to source ground sensing.
Figure 63. Dual Source System—Multiple Point Grounding
To maintain maximum service continu
ity,
more than two levels (zones) of ground
fault protection will be required, so that
ground fault outages can be localized and
service interrup
tion minimized.To obtain
selectivity between different levels of
ground fault relays, time delay settings
should be employed with the GFR furthest
downstream having the minimum time
delay.This will allow the GFR nearest the
fault to operate first.
With several levels of protection, this will
reduce the level of protection for faults
within the upstream GFR zones. Zone
interlocking was developed for GFRs to
overcome this problem.
The use of GFRs (or circuit breakers with
integral ground fault protection) that
incorporate Zone Selective Interlocking,
allows a coordinated response in a
system by operating in a time delayed
mode for ground faults occurring most
remote from the source.This time delayed
mode is only actuated when the GFR
protecting the zone containing the fault
sends a restraining signal to the upstream
GFRs.The absence of a restraining signal
from a downstream GFR is an indication
to the next upstream GFR that a ground
fault is within its zone of protection and it
will operate instantaneously to clear the
fault with minimum damage and
maximum service continuity.
Typical
4-Wire
Feeder
4-Wire
Load
Neutral
ØA, ØB, ØC
Power
Transformer
Power
Transformer
4-Wire
Load
Typical
4-Wire
Feeder
Neutral
ØA, ØB, ØC
33-
52-T
52-T
a
52-T
a
Tie Bkr.
52-T
Neutral Sensor
Main Bkr. 52-2
Neutral Sensor
Tie Bkr. 52-T
Neutral Sensor
Main Bkr. 52-1
Digitrip
Main Bkr.
52-1
Main
Bkr.
52-2
Main
Bkr.
52-1
Digitrip
Digitrip
Main Bkr.
52-2 Digitrip
B4 B5
B5 B4 B4 B5 B4 B5
B4 B5
( )B4
( )B5
M1N
M1G
M2G
M2N
TG
TN
( )B4
( )B5
Digitrip
Main Bkr.
52-T
Trip Unit
Main Breaker
52-1
Trip Unit
Tie Breaker
52-T
Power
Transformer
52-T
a
52-2
a
Neutral Sensor
Tie Breaker 52-T
X
X
Typical
Four-Wire
Feeder
Trip
Unit
Four-Wire Load
X
X
52-1
a
Neutral Neutral
Tie Breaker
52-T
Neutral
Sensor Main
Breaker 52-1
X
X
X
X
Main
Breaker
52-1
Phase A,
Phase B,
Phase C
Trip Unit
Main Breaker
52-2
Typical
Four-Wire
Feeder
Trip
Unit
Four-Wire Load
X
X
Phase A,
Phase B,
Phase C
Power
Transformer
Neutral
Sensor Main
Breaker 52-2 Main
Breaker
52-2

This operating mode permits all GFRs to
operate instantaneously for a fault within
their zone and still provide complete
selectivity between zones.
The National Electrical Manufacturers
Association (NEMA) states, in their
application guide for ground fault
protection, that zone interlocking is
necessary to minimize damage from
ground faults. A two-wire connection is
required to carry the restraining signal
from the GFRs in one zone to the GFRs in
the next zone.
Circuit breakers with integral ground fault
protection and standard circuit breakers
with shunt trips activated by the ground
fault relay are ideal for ground fault
protection. Eaton’s Pringle Bolted
PressureType fused switches have an
optional integral ground fault protection
relay and meet UL Class 1 requirements
to open safely on faults up to 12 times
their rating. Eaton’s ShuntTrip Safety
Switches have passed Class 1 ground
fault testing and include an integral shunt
trip mechanism that can be field wired to
an external ground fault relay.
Power distribution systems differ widely
from each other, depending upon the
requirements of each end user’s facility
type and application. A power system
design professional needs to carefully
evaluate total system overcurrent
protection, including ground fault
currents, to meet these needs.
Experienced and knowledgeable
engineers have to consider the impact
on all power sources (utility and on-site
generation), the effects of outages and
the cost impact of downtime, as well as
safety for people and equipment from
arc flash hazards, when balancing
enhanced protection schemes against
initial equipment cost.They must
apply protective devices, analyzing the
time-current characteristics and fault
interrupting capacity, as well as selectivity
and coordination methods to provide
the most safe and cost-effective
Further Information
■ PRSC-4E—System Neutral Ground
ing
and Ground Fault Protection
(ABB Publication)
■ PB 2.2—NEMA Application Guide
for Ground Fault Protective Devices
for Equipment
■ IEEE Standard 142—Grounding of
Industrial and Commercial Power
Systems (Green Book)
■ IEEE Emerald Book (Standard 1100)
■ UL 96A, Installation Requirements for
Lightning Protection Systems
Lightning and Surge Protection
Physical protection of buildings from
direct damage from lightning is beyond
the scope of this section. Requirements
will vary with geographic location,
building type and environ
ment, and
many other factors (see IEEE/ANSI
Standard 142, Grounding of Industrial
and Commercial Power Systems). Any
lightning protection system must be
grounded, and the lightning protection
ground must be bonded to the electrical
equipment grounding system.
Grounding Electrodes
At some point, the equipment and
system grounds must be connected
to the earth by means of a grounding
electrode system.
Outdoor substations usually use a ground
grid, consisting of a number of ground
rods driven into the earth and bonded
together by buried copper conductors.The
required grounding electrode system for a
building is spelled out in NEC Article 250.
The preferred grounding electrode is a
metal underground water pipe in direct
contact with the earth for at least 10 ft
(3 m). However, because underground
water piping is often plastic outside the
building, or may later be replaced by
plastic piping, the NEC requires this
electrode to be supplemented by
and bonded to at least one other
grounding electrode.
These supplemental grounding
electrodes include: the effectively
grounded metal frame of the building,
a concrete-encased electrode, a copper
conductor ground ring encircling the
building, or a made electrode such as one
or more driven ground rods or a buried
plate.Where any of these electrodes are
present, they must be bonded together
into one grounding electrode system.
One of the most effective grounding
electrodes is the concrete-encased
electrode, sometimes called the Ufer
ground, named after the man who
developed it. It consists of at least 20 ft
(6 m) of steel reinforcing bars or rods not
less than 1/2 inches (12.7 mm) in
diameter, or at least 20 ft (6 m) of bare
copper conductor, size No. 4 AWG
or larger, encased in at least 2 inches
(50.8 mm) of concrete. It must be located
within and near the bottom of a concrete
foundation or footing that is in direct
contact with the earth.Tests have shown
this electrode to provide a low-resistance
earth ground even in poor soil conditions.
The electrical distribution system and
equipment ground must be connected
to this grounding electrode system by
a grounding electrode conductor. All
other grounding electrodes, such as those
for the lightning protection system, the
telephone system, television antenna and
cableTV system grounds, and computer
systems, must be bonded to this
grounding electrode system.
There are many books written about the
design and application of grounding
systems. For those diligent engineers
seeking more information, the following
publications are recommended reading:
■ Soares Book on Grounding and
Bonding, 2014 NEC. IAEI 12th Edition
by International Association of
Electrical Inspectors
■ McGraw Hill’s National Electrical Code
2014 Grounding & Earthing Handbook
71

Medium-Voltage Equipment Surge
Protection Considerations
Transformers
If the voltage withstand/BIL rating of
the transformer is less than that of the
switchgear feeding the transformer,
surge protection is recommended at
the transformer terminals, in line with
established practices. In addition,
consideration should be given to using
surge arresters and/or surge capacitors
for transformers having equal or greater
withstand/BIL ratings than that of the
switchgear feeding the transformer for
distribution systems where reflected
voltage waves and/or resonant conditions
may occur.
Typically incoming voltage surges are
reflected at the transformer primary
terminals, resulting in voltages at the
ends of the transformer primary
terminals/windings of up to two times
the incoming voltage wave. System
capacitance and inductance values
combined with the transformer
impedance values can cause resonant
conditions resulting in amplified reflected
waves. Surge arresters/capacitors when
required, should be located as close to
the transformer primary terminals
as practical.
Where concerns exist for transformer
failures or life reduction due to
switching transients, Eaton offers an
environmentally friendly oil-filled
hardened transformer solution.
Motors
Surge capacitors and, where appropriate,
surge arresters should be applied at the
motor terminals.
Generators
Surge capacitors and station class surge
arresters should be properly applied at
the machine terminals.
Surge Protection
Eaton’sVacClad-W metal-clad switch
gear
is applied over a broad range of circuits,
and is one of the many types of equipment
in the total system.The distribution system
can be subject to voltage transients caused
by lighting or switching surges.
Recognizing that distribution system can
be subject to voltage transients caused
by lighting or switching, the industry
has developed standards to provide
guidelines for surge protection of electrical
equipment.Those guide
lines should be
used in design and protection of electrical
distribution systems independent of the
circuit breaker interrupting medium.The
industry standards are:
ANSI C62
Guides and Standards for
Surge Protection
IEEE 242—Buff Book
IEEE Recommended Practice for
Protection and Coordination of
Industrial and Commercial
Power Systems
IEEE 141—Red Book
Recommended Practice for Electric
Power Distribution for Industrial Plants
IEEE C37.20.2
Standards for Metal-Clad Switchgear
Eaton’s medium-voltage metal-clad and
metal-enclosed switchgear that uses
vacuum circuit breakers is applied over
a broad range of circuits. It is one of the
many types of equipment in the total
distribution system.Whenever a
switching device is opened or closed,
certain interactions of the power system
elements with the switching device can
cause high frequency voltage transients
in the system.
Due to the wide range of applications
and variety of ratings used for different
elements in the power systems, a given
circuit may or may not require surge
protection.Therefore, Eaton does not
include surge protection as standard
with its metal-clad or metal-enclosed
medium-voltage switchgear.
The system designer must specify
the optional type and extent of surge
protection necessary, depending on the
individual circuit characteristics and cost
considerations. Because transformers
have both high initial installation and
replacement costs, the specifying
engineer should consider commissioning
an optional study.These switching
transient studies and their associated
recommendations can be provided by
Eaton’s Engineering Services & Systems
group (EESS).
The following are Eaton’s recommenda
tions for surge protection of medium-
voltage equipment. Please note these
recommendations are valid when using
Eaton’s vacuum breakers only.
Surge Protection Recommendations
1. For circuits exposed to lightning,
surge arresters should be applied in
line with Industry standard practices.
2. Transformers—Because each
installation is unique, a variety of
different factors can impact how the
various electrical components interact
as a system (i.e.,: transformer type
and MVA rating, system impedances,
the Manufacturer’sVacuum
Interrupter Current Chop Rating, etc.).
Consequently, there is no singular
answer for all situations.The optimum
application of snubbers may require
recommendations from a switching
transient study.
Typical rules of thumb are:
a. Close-coupled to medium-
voltage primary breaker: Provide
transients surge protection, such
as Surge Arrester in parallel with
RC Snubber.The surge protection
device selected should be located
and connected at the transformer
primary terminals or it can be
located inside the switchgear and
connected on the transformer side
of the primary breaker.
b. Cable-connected to medium-
voltage primary breaker: Provide
transient surge protection, such
as surge arrester in parallel with
RC Snubber for transformers
connected by cables with lengths
up to 150 feet.The surge protection
device should be located and
connected at the transformer
terminals. Surge protection
is generally not needed for
transformers with lightning
impulse withstand ratings equal
to that of the switchgear and
connected to the switchgear by
cables at least 150 feet or longer.
For transformers with lower BIL,
provide surge arrester in parallel
with RC Snubber.
c. When special transient resis
tant
transformer designs are used, RC
snubbers may not be required for
power transformer protection.
However, they may be needed for
instrument transformer protection.

RC Snubber to dampen internal
transformer resonance:
The natural frequency of transformer
windings can under some circum-
stances be excited to resonate.
Transformer windings in resonance
can produce elevated internal
voltages that produce insulation
damage or failure. An RC Snubber
applied at the transformer terminals
as indicated above can dampen
internal winding resonance and
prevent the production of damag
ing
elevated internal voltages.This is
typically required where rectifiers,
UPS or similar electronic equipment
is on the transformer secondary.
3. Arc-FurnaceTransformers—Provide
Surge Arrester in parallel with RC
Snubber at the trans
former terminals.
4. Motors—Provide Surge Arrester in
parallel with RC Snubber at the motor
terminals. For those motors using
VFDs, surge protection should be
applied and precede theVFD devices
as well.
5. Generators—Provide station class
Snubber at the generator terminals.
6. Capacitor Switching—No surge
protection is required. Make sure
that the capacitor’s lightning impulse
withstand rating is equal to that of
the switchgear.
7. Shunt Reactor Switching—Provide
Snubber at the reactor terminals.
8. Motor Starting Reactors or Reduced
Voltage Auto-Transformers—
Provide Surge Arrester in parallel
with RC Snubber at the reactor or
RVAT terminals.
9. Switching Underground Cables—
Surge protection should be properly
applied as determined by a switching
transient study.
Types of Surge Protection Devices
Generally surge protective devices should
be located as closely as possible to the
circuit component(s) that require
protection from the transients, and
connected directly to the terminals of the
component with conductors that are as
short and flat as possible to minimize the
inductance. It is also important that surge
protection devices should be properly
grounded for effectively shunting high
frequency transients to ground.
SurgeArresters
Modern metal-oxide surge arresters are
recommended as this design ensures
better performance and high reliability of
surge protection schemes. Manufacturer’s
technical data must be consulted for
correct application of a given type of
surge arrester.
Many manufacturer’s published arrester
MCOV (maximum continuous operating
voltage) ratings are based on 40 ºC or
45 ºC ambient temperature. In general, the
following guidelines are recommended for
arrester selections, when installed inside
Eaton’s medium-voltage switchgear:
A. Solidly Grounded Systems: Arrester
MCOV rating should be equal to
1.05 xVLL/(1.732 xT), whereVLL is
nominal line-to-line service voltage,
1.05 factor allows for +5% voltage
variation above the nominal voltage
according to ANSI C84.1, andT is
derating factor to allow for operation
at 55 ºC switchgear ambient, which
should be obtained from the arrester
manufacturer for the type of arrester
under consideration.Typical values of
T are: 0.946 to 1.0.
B. Low Resistance Grounded Sys
tems
(systems grounded through resistor
rated for 10 seconds): Arrester
10-second MCOV capability at 60 ºC,
which is obtained from manufacturer’s
data, should be equal to 1.05 xVLL,
whereVLL is nominal line-to-line
service voltage, and 1.05 factor allows
for +5% voltage variation above the
nominal voltage.
C. Ungrounded or Systems Grounded
through impedance other than a
10-second resistor: Arrester MCOV
rating should be equal to 1.05 xVLL
/T,
whereVLL
andT are as defined above.
Refer to Table 20 for recommended
ratings for metal-oxide surge arresters
that are sized in accordance with the
above guidelines, when located in
Eaton’s switchgear.
Surge Capacitors
Metal-oxide surge arresters limit the
magnitude of prospective surge over
voltage, but are ineffective in control
ling
its rate of rise. Specially designed surge
capacitors with low internal inductance
are used to limit the rate of rise of this
surge overvoltage to protect turn-to-turn
insulation. Recommended values for
surge capacitors are: 0.5 µf on 5 and
7.5 kV, 0.25 µf on 15 kV, and 0.13 µf on
systems operating at 24 kV and higher.
Figure 64. Surge Protection Devices
73

RC Snubber
A RC Snubber device consists of a
non-inductive resistor R sized to match
surge impedance of the load cables,
typically 20 to 30 ohms, and connected in
series with a Surge Capacitor C.The Surge
Capacitor is typically sized to be 0.15 to
0.25 microfarad. Under normal operating
conditions, impedance of the capacitor
is very high, effectively “isolating” the
resistor R from the system at normal
power frequencies, and minimizing heat
dissipation during normal operation.
Under high frequency transient conditions,
the capacitor offers very low impedance,
thus effectively “inserting” the resistor R in
the power system as a cable terminating
resistor, thus minimizing reflection of the
steep wave-fronts of the voltage transients
and prevents voltage doubling of the
traveling wave.The RC Snubber provides
protection against high frequency
transients by absorbing and damping
the transients.
An RC Snubber is most effective in
mitigating fast-rising transient volt
ages,
and in attenuating reflections and
resonances before they have a chance
to build up, but does not limit the peak
magnitude of the transient.Therefore,
the RC Snubber alone may not provide
adequate protection.To limit peak
magnitude of the transient, application of
a surge arrester should also be considered.
RC Snubber with Surge Suppressor
This type of device consists of parallel
combination of Resistor (R) and Zinc
OxideVoltage Suppressor (ZnO),
connected in series with a Surge
Capacitor.The resistor R is sized to match
the surge impedance of the load cables,
typically 20 to 30 ohms.The ZnO is a
gapless metal-oxide nonlinear arrester,
set to trigger at 1 to 2 PU voltage, where
1 PU = 1.412*(VL-L
/1.732).The Surge
Capacitor is typically sized to be 0.15 to
0.25 microfarad. As with RC Snubber,
under normal operating conditions,
impedance of the capacitor is very high,
effectively “isolating” the resistor R and
ZnO from the system at normal power
frequencies, and minimizing heat
dissipation during normal operation.
Under high frequency transient
conditions, the capacitor offers very low
impedance, thus effectively “inserting”
the resistor R and ZnO in the power
system as a cable terminating network,
thus minimizing reflection of the steep
wave-fronts of the voltage transients and
prevents voltage doubling of the traveling
wave.The ZnO element limits the peak
voltage magnitudes.
The combined effects of R, ZnO,
and capacitor of this device provides
optimum protection against high
frequency transients by absorbing,
damping, and by limiting the peak
amplitude of the voltage wave-fronts.
Please note that this suppressor is not a
lightning protection device. If lightning
can occur or be induced in the electrical
system, a properly rated and applied
surge arrester must precede this device.
Surge Protection Summary
Minimum protection: Surge Arrester for
protection from high overvoltage peaks,
or Surge Capacitor for protection from
fast-rising transient. Please note that
the surge arresters or surge capacitor
alone may not provide adequate surge
protection from escalating voltages
caused by circuit resonance. Note that
when applying surge capacitors on both
sides of a circuit breaker, the surge
capacitor on one side of the breaker must
be an RC Snubber or RC Snubber with
surge suppressor, to mitigate possible
virtual current chopping.
Good protection: Surge arrester in parallel
with surge capacitor for protection from
high overvoltage peaks and fast rising
transient.This option may not provide
adequate surge protection from escalating
voltages caused by circuit resonance.
When applying surge capacitors on
both sides of a circuit breaker, the surge
capacitor on one side of the breaker must
be an RC Snubber or RC Snubber with
surge suppressor, to mitigate possible
virtual current chopping.
Better protection: An RC Snubber in
parallel with Surge Arrester for protection
from high frequency transients and
voltage peaks.
Best protection: RC Snubber with surge
suppressor, plus proper surge arrester
preceding it where needed for protection
against lightning.The RC Snubber with
surge suppressor provides protection
from high frequency voltage transients
and limits peak magnitude of the
transient to 1 to 2 PU. A surge arrester
provides protection from higher voltage
peaks resulting from lightning surges.
Note that special design liquid-filled and
dry-type transformers are avail
able that do
not require the addition of RC Snubbers to
mitigate switching transients.
Further Information
■ IEEE/ANSI Standard 142—Grounding
Industrial and Commercial Power
Systems (Green Book)
■ IEEE Standard 241—Electric Power
Systems in Commercial Buildings
(Gray Book)
■ IEEE Standard 141—Electric Power
Distribution for Industrial Plants
(Red Book)

Table 20. Surge Arrester Selections—Recommended Ratings
Service
Voltage
Line-to-Line
kV
Distribution ClassArresters Station ClassArresters
Solidly
Grounded System
Low Resistance
Grounded System
High Resistance or
Ungrounded System
Solidly
Grounded System
Low Resistance
Grounded System
High Resistance or
Ungrounded System
Arrester Ratings kV Arrester Ratings kV
Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV
2.30
2.40
3.30
3
3
3
2.55
2.55
2.55
3
3
3
2.55
2.55
2.55
3
6
6
2.55
5.10
5.10
3
3
3
2.55
2.55
2.55
3
3
3
2.55
2.55
2.55
3
6
6
2.55
5.10
5.10
4.00
4.16
4.76
3
6
6
2.55
5.10
5.10
6
6
6
5.10
5.10
5.10
6
6
9
5.10
5.10
7.65
3
6
6
2.55
5.10
5.10
6
6
6
5.10
5.10
5.10
6
6
9
5.10
5.10
7.65
4.80
6.60
6.90
6
6
6
5.10
5.10
5.10
6
6
6
5.10
5.10
5.10
9
9
9
7.65
7.65
7.65
6
6
6
5.10
5.10
5.10
6
6
9
5.10
5.10
7.65
9
9
9
7.65
7.65
7.65
7.20
8.32
8.40
6
9
9
5.10
7.65
7.65
6
9
9
5.10
7.65
7.65
10
12
12
8.40
10.20
10.20
6
9
9
5.10
7.65
7.65
9
9
9
7.65
7.65
7.65
10
12
12
8.40
10.20
10.20
11.00
11.50
12.00
9
9
10
7.65
7.65
8.40
9
10
10
7.65
8.40
8.40
15
18
18
12.70
15.30
15.30
9
9
10
7.65
7.65
8.40
10
12
12
8.40
10.20
10.20
15
18
18
12.70
15.30
15.30
12.47
13.20
13.80
10
12
12
8.40
10.20
10.20
12
12
12
10.20
10.20
10.20
18
18
18
15.30
15.30
15.30
10
12
12
8.40
10.20
10.20
12
12
15
10.20
10.20
12.70
18
18
18
15.30
15.30
15.30
14.40
18.00
20.78
12
15
18
10.20
12.70
15.30
12
15
18
10.20
12.70
15.30
21
27
30
17.00
22.00
24.40
12
15
18
10.20
12.70
15.30
15
18
21
12.70
15.30
17.00
21
27
30
17.00
22.00
24.40
22.00
22.86
23.00
18
18
18
15.30
15.30
15.30
18
21
21
15.30
17.00
17.00
30
—
—
24.40
—
—
18
18
18
15.30
15.30
15.30
21
24
24
17.00
19.50
19.50
30
36
36
24.40
29.00
29.00
24.94
25.80
26.40
21
21
21
17.00
17.00
17.00
24
24
24
19.50
19.50
19.50
—
—
—
—
—
—
21
21
21
17.00
17.00
17.00
24
24
27
19.50
19.50
22.00
36
36
39
29.00
29.00
31.50
33.00
34.50
38.00
27
30
30
22.00
24.40
24.40
30
30
—
24.40
24.40
—
—
—
—
—
—
—
27
30
30
22.00
24.40
24.40
36
36
36
29.00
29.00
29.00
45
48
—
36.50
39.00
—
75

Typical Power System
Components
The System One-line on Page 8,
illustrates schematically the various types
of power distribution equipment that an
engineer will encounter during the design
of a power system. It is important to
consider the various physical attributes of
the various pieces of electrical equipment
that will be utilized as well as the
constraints that will be encountered in
their application.
Electrical equipment that distributes
power has a heat loss due to the
impedance and/or resistance of its
conductors.This heat is radiated into the
electrical room where the equip
ment is
placed and must be removed to ensure
excess heat does not cause failures.
Table 21 provides heat loss in watts
for typical power distribution equipment
that may be used in the sizing of
HVAC equipment.
As indicated on the one-line, a number of
distribution components, are provided
with a description of the physical structure
in which they are to be enclosed.The
National Electrical Manufacturers
Association (NEMA) has developed a
set of standards to ensure the consistent
application performance of enclosures.
As an example, the panelboard shown
in Figure 2 is called out as being NEMA
4X. Table 22 and Table 23, show the
various performance data for these
enclosures in indoor and outdoor
applications respectively. Table 24 covers
enclosures to be installed in explosive or
hazardous environments.
Because the majority of medium- and
low-voltage switchgear is mounted
indoors, they are typically provided
in NEMA 1A enclosures. In these
applications, ventilation openings
are normally provided to allow heat
to escape from the enclosures.Where
required, optional dust screens and
gasketing can be provided.
Many indoor applications are in base
ments or areas where condensation
on the ceiling may leak on top of the
switchgear. Additional concerns may
arise where sprinklers are provided above
the switchgear or alternately, on the floor
above. Eaton can provide “sprinkler
resistant” low-voltage switchgear or
low- and medium-voltage switchgear
with a drip hood.
For outdoor environments, this equip
ment may be mounted in a NEMA 3R
drip-proof enclosure.Where equipment
is located outdoors, the humidity in the
air may condense during evening hours,
resulting in water droplets fall
ing on
the bus bars in the equipment. Under
these circumstances, an optional space
heater may be provided and wired to a
thermostat or humidistat for control.
Because many countries around the
world refer to International Electro
technical Commission standards (IEC),
designers should reference Table 25
to determine the appropriate alternate
enclosure rating.
Power Equipment Losses
Table 21. Power Equipment Losses
Equipment Watts
Loss
Medium-Voltage Switchgear
(Indoor, 5 and 15 kV)
1200 A breaker
2000 A breaker
3000 A breaker
4000 A breaker
600
1400
2100
3700
Medium-Voltage Switchgear
(Indoor, 5 and 15 kV)
600 A unfused switch
1200 A unfused switch
100 A CL fuses
500
750
840
Medium-Voltage Starters (Indoor, 5 kV)
400 A starter FVNR
800 A starter FVNR
600 A fused switch
1200 A fused switch
600
1000
500
800
Low-Voltage Switchgear (Indoor, 480V)
800 A breaker
1600 A breaker
2000 A breaker
400
1000
1500
3200 A breaker
4000 A breaker
5000 A breaker
2400
3000
4700
Fuse limiters—800 A CB
200
500
750
Fuse truck—3200 A CB
Fuse truck—4000 A CB
3600
4500
Structures—3200 A
Structures—4000 A
Structures—5000 A
4000
5000
7000
High resistance grounding 1200
Panelboards (Indoor, 480V)
225 A, 42 circuit 300
Low-Voltage Busway (Indoor, Copper, 480V)
800 A
1200 A
1350 A
44 per foot
60 per foot
66 per foot
1600 A
2000 A
2500 A
72 per foot
91 per foot
103 per foot
3200 A
4000 A
5000 A
144 per foot
182 per foot
203 per foot
Motor Control Centers (Indoor, 480V)
NEMA Size 1 starter
NEMA Size 2 starter
NEMA Size 3 starter
39
56
92
NEMA Size 4 starter
NEMA Size 5 starter
Structures
124
244
200
Adjustable Frequency Drives (Indoor, 480V)
Adjustable frequency drives > 96%
efficiency
Note: The information provided on power
equipment losses is generic data intended to
be used for sizing of HVAC equipment.
Typical Components of a Power System

Enclosures
The following are reproduced from NEMA 250.
Table 22. Comparison of Specific Applications of Enclosures for Indoor Nonhazardous Locations
Provides a Degree of ProtectionAgainst the
Following Environmental Conditions
EnclosureType
1 a 2 a 4 4X 5 6 6P 12 12K 13
Incidental contact with the enclosed equipment
Falling dirt
Falling liquids and light splashing
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
Circulating dust, lint, fibers and flyings b
Settling airborne dust, lint, fibers and flyings b
Hosedown and splashing water
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
Oil and coolant seepage
Oil or coolant spraying and splashing
Corrosive agents n n
n n n
n
Occasional temporary submersion
Occasional prolonged submersion
n n
n
a These enclosures may be ventilated.
b These fibers and flying are nonhazardous materials and are not considered the Class III type ignitable fibers or combustible flyings. For Class III type ignitable
fibers or combustible flyings, see the National Electrical Code, Article 500.
Table23.ComparisonofSpecificApplicationsofEnclosuresforOutdoorNonhazardousLocations
EnclosureType
3 3R c 3S 4 4X 6 6P
Rain, snow and sleet d
Sleet e
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
Windblown dust
Hosedown
Corrosive agents
n n n
n
n
n
n
n
n
n
n
n
n n
n
c These enclosures may be ventilated.
d External operating mechanisms are not required to be operable when the enclosure is ice covered.
e External operating mechanisms are operable when the enclosure is ice covered.
Table 24. Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations
Provides a Degree of ProtectionAgainst
AtmospheresTypically Containing
(For Complete Listing, See NFPA 497M)
Class EnclosureTypes
7 and 8, Class I Groups f
EnclosureType
9, Class II Groups f
A B C D E F G 10
Acetylene
Hydrogen, manufactured gas
diethyl ether, ethylene, cyclopropane
I
I
I
n
n
n
Gasoline, hexane, butane, naphtha, propane, acetone, toluene, isoprene
Metal dust
Carbon black, coal dust, coke dust
I
II
II
n
n
n
Flour, starch, grain dust
Fibers, flyings g
Methane with or without coal dust
II
III
MSHA
n n
n
n
f For Class III type ignitable fibers or combustible flyings, see the National Electrical Code, Article 500.
g Due to the characteristics of the gas, vapor or dust, a product suitable for one class or group may not be suitable for another class or group unless so marked on
the product.
Note: If the installation is outdoors and/or additional protection is required by Table 22 and Table 23, a combination-type enclosure is required.
77

Table 25. Conversion of NEMA Enclosure Type Ratings to IEC 60529 Enclosure Classification Designations (IP) (From NEMA Publication 250)
(Cannot be Used to Convert IEC Classification Designations to NEMA Type Ratings)
NEMA Enclosure Type
IP
First
Character
IP
Second
Character
IP0–
IP1–
IP2–
IP3–
IP4–
IP5–
IP6–
IP–0
IP–1
IP–2
IP–3
IP–4
IP–5
IP–6
IP–7
IP–8
1 2 3 4
3R 5 6 6P 12 13
12K
3S 4X
A B A B A B A B A B A B A B A B A B A B A B A B A B
A = A shaded block in the “A” column indicates that the NEMA Enclosure Type exceeds the requirements for the respective IEC 60529
IP First Character Designation. The IP First Character Designation is the protection against access to hazardous parts and solid
foreign objects.
B = A shaded block in the “B” column indicates that the NEMA Enclosure Type exceeds the requirements for the respective IEC 60529
IP Second Character Designation. The IP Second Character Designation is the protection against the ingress of water.
EXAMPLE OF TABLE USE
An IEC IP45 Enclosure Rating is specified. What NEMA Type Enclosures meet and exceed the IP45 rating?
Referencing the first character, 4, in the IP rating and the row designated “IP4–” in the leftmost column in the
table; the blocks in Column “A” for NEMA Types 3, 3S, 4, 4X, 5, 6, 6P, 12, 12K and 13 are shaded. These NEMA
ratings meet and exceed the IEC protection requirements against access to hazardous parts and solid foreign
objects. Referencing the second character, 5, in the IP rating and the row designated “IP–5” in the rightmost
column in the table; the blocks in Column “B” for NEMA Types 3, 3S, 4, 4X, 6 and 6P are shaded. These NEMA
ratings meet and exceed the IEC requirements for protection against the ingress of water. The absence of shading
in Column “B” beneath the “NEMA Enclosure Type 5” indicates that Type 5 does not meet the IP45 protection
requirements against the ingress of water. Likewise, the absence of shading in Column “B” for NEMA Type 12,
12K and 13 enclosures indicates that these enclosures do not meet the IP45 requirements for protection against
the ingressof water. Only Types 3, 3S, 4, 4X, 6 and 6P have both Column “A” in the “IP4–” row and Column “B”
in the “IP–5” row shaded and could be used in an IP45 application.
The NEMA Enclosure Type 3 not only meets the IP45 Enclosure Rating, but also exceeds the IEC requirements
because the NEMA Type requires an outdoor corrosion test; a gasket aging test; a dust test; an external icing
test; and no water penetration in the rain test. Slight differences exist between the IEC and NEMA test methods,
but the IEC rating permits the penetration of water if “it does not deposit on insulation parts, or reach live parts.”
The IEC rating does not require a corrosion test; gasket aging test; dust test or external icing test. Because the
NEMA ratings include additional test requirements, this table cannot be used to select IP Designations for NEMA
rated enclosure specifications.
IEC 60529 specifies that an enclosure shall only be designated with a stated degree of protection indicated by
the first characteristic numeral if it also complies with all lower degrees of protection. Furthermore, IEC 60529
states that an enclosure shall only be designated with a degreeof protection indicated by the second characteristic
numeral if it also complies with all lower degrees of protection up to and including the secondcharacteristic
numeral 6. An enclosure designated with a second characteristic numeral 7 or 8 only is considered unsuitable
for exposure to water jets (designated by second characteristic numeral 5 or 6) and need not comply with
requirements for numeral 5 or 6 unless it is dual coded. Because the IEC protection requirements become more
stringent with increasing IP character value up through 6, once a NEMA Type rating meets the requirements for
an IP designation up through 6, it will also meet the requirements for all lower IP designations. This is apparent
from the shaded areas shown in the table.

Transformers
The work of early electrical pioneer
Michael Faraday, in documenting the
principal of electro-magnetic induction,
led to a discovery that voltage flowing
through a coil wrapped around a donut
shaped piece of iron could induce a
voltage in a second coil of wire also
wrapped around the iron.This discovery
was key to Faraday’s work in 1831 and
became the basis for others in the
development of transformer technology.
While Sebastian Ferranti and others
continued to develop and patent
transformer technology, it was a
demonstration of a power transformer
during 1884 inTurin, Italy that caught the
attention of GeorgeWestinghouse. In
1885,Westinghouse purchased the
American rights to manufacture the
transformer developed by Lucien
Gaulard and John Gibbs.
In subsequent years,William Stanley, Jr.,
Westinghouse’s chief engineer, would
alter the Gaulard and Gibbs design by
changing the series coil arrangement
to a parallel coil design. Stanley also
developed the “E” coil using laminated
stamped steel core pieces. Both of these
innovations improved the transformer
by stabiliz
ing its regulation as well
as improving its manufacturability
and efficiency.
Transformers were the key component
in the growth of alternating current (AC)
distribution systems over the direct
current (DC) alternative promoted by
Thomas Edison.
NEMA has worked through the years to
standardize transformer primary and
secondary full load amperes (FLA).
Table 26 is a compilation of various
transformers kVA and primary voltages
along with their primary FLA.
Transformers are designed with a specific
number of primary versus secondary
winding turns.These are a ratio of the
primary voltage to the secondary voltage.
Each winding has a specific amount of
resistance, however, when first energized,
acts like a short circuit drawing a high
inrush current that falls off as the core
material magnetizes.This combination of
electrical properties is termed impedance.
Dry-type power transformers that meet
the ANSI C57 standard follow a specific
requirement for impedance based on
their kVA rating and type. Lower
impedances allow more secondary
short-circuit current to flow versus
higher impedance versions.
For example, a 300 kVA three-phase
power transformer has 5% impedance
whereas higher kVA transformers have
5.75%. See Table 27 for information on
transformer secondary FLA ratings and
short-circuit current available.
Because there are a number of
categories with the ANSI C57 family,
the design engineer needs to pinpoint
the transformer design type.When
designing systems involving different
types of transformers such as larger
fluid-filled units like the 7500 kVA (7.5
MVA) unit “T1” shown in Figure 2
on Page 8, the impedance can be 6.5%
or greater.
Table 28 through Table 33 provide further
information on the impedances and
electrical characteris
tics of various styles
of transformers. Note that smaller
dry-type distribution transformers may
not have uniform impedances across
various manufac
turers due to design
characteristics and construction
tolerances.
Eaton offers dry-type distribution
transformers, secondary substation
transformers in liquid and dry
configurations, liquid and dry net
work
transformers, tamper-proof pad-
mounted, liquid filled transformers,
and liquid-filled and dry-type primary
substation transformers.The features of
each type of transformer are explained on
our web page and in the Design Guide
associated with each product.
Table 26. Transformer Full-Load Current, Three-Phase, Self-Cooled Ratings
Voltage, Line-to-Line
kVA 208 240 480 600 2400 4160 7200 12,000 12,470 13,200 13,800 22,900 34,400
30
45
75
83.3
125
208
72.2
108
180
36.1
54.1
90.2
28.9
43.3
72.2
7.22
10.8
18.0
4.16
6.25
10.4
2.41
3.61
6.01
1.44
2.17
3.61
1.39
2.08
3.47
1.31
1.97
3.28
1.26
1.88
3.14
0.75
1.13
1.89
0.50
0.76
1.26
112-1/2
150
225
312
416
625
271
361
541
135
180
271
108
144
217
27.1
36.1
54.1
15.6
20.8
31.2
9.02
12.0
18.0
5.41
7.22
10.8
5.21
6.94
10.4
4.92
6.56
9.84
4.71
6.28
9.41
2.84
3.78
5.67
1.89
2.52
3.78
300
500
750
833
1388
2082
722
1203
1804
361
601
902
289
481
722
72.2
120
180
41.6
69.4
104
24.1
40.1
60.1
14.4
24.1
36.1
13.9
23.1
34.7
13.1
21.9
32.8
12.6
20.9
31.4
7.56
12.6
18.9
5.04
8.39
12.6
1000
1500
2000
2776
4164
—
2406
3608
4811
1203
1804
2406
962
1443
1925
241
361
481
139
208
278
80.2
120
160
48.1
72.2
96.2
46.3
69.4
92.6
43.7
65.6
87.5
41.8
62.8
83.7
25.2
37.8
50.4
16.8
25.2
33.6
2500
3000
3750
—
—
—
—
—
—
3007
3609
4511
2406
2887
3608
601
722
902
347
416
520
200
241
301
120
144
180
116
139
174
109
131
164
105
126
157
63.0
75.6
94.5
42.0
50.4
62.9
5000
7500
10,000
—
—
—
—
—
—
—
—
—
4811
—
—
1203
1804
2406
694
1041
1388
401
601
802
241
361
481
231
347
463
219
328
437
209
314
418
126
189
252
83.9
126
168
79

Table 27. Secondary Short-Circuit Current of Typical Power Transformers
Transformer
Rating
Three-Phase
kVA and
Impedance
Percent
Maximum
Short-
Circuit kVA
Available
from
Primary
System
208V,Three-Phase 240V,Three-Phase 480V,Three-Phase 600V,Three-Phase
Rated
Load
Contin-
uous
Current,
Amps
rms SymmetricalAmps
Rated
Load
Contin-
uous
Current,
Amps
rms SymmetricalAmps
Rated
Load
Contin-
uous
Current,
Amps
rms SymmetricalAmps
Rated
Load
Contin-
uous
Current,
Amps
rms SymmetricalAmps
Trans-
former
Alone a
50%
Motor
Load b
Com-
bined
Trans-
former
Alone a
100%
Motor
Load b
Com-
bined
Trans-
former
Alone a
100%
Motor
Load b
Com-
bined
Trans-
former
Alone a
100%
Motor
Load b
Com-
bined
300
5%
50,000
100,000
150,000
834
834
834
14,900
15,700
16,000
1700
1700
1700
16,600
17,400
17,700
722
722
722
12,900
13,600
13,900
2900
2900
2900
15,800
16,500
16,800
361
361
361
6400
6800
6900
1400
1400
1400
7800
8200
8300
289
289
289
5200
5500
5600
1200
1200
1200
6400
6700
6800
250,000
500,000
Unlimited
834
834
834
16,300
16,500
16,700
1700
1700
1700
18,000
18,200
18,400
722
722
722
14,100
14,300
14,400
2900
2900
2900
17,000
17,200
17,300
361
361
361
7000
7100
7200
1400
1400
1400
8400
8500
8600
289
289
289
5600
5700
5800
1200
1200
1200
6800
6900
7000
500
5%
50,000
100,000
150,000
1388
1388
1388
21,300
25,200
26,000
2800
2800
2800
25,900
28,000
28,800
1203
1203
1203
20,000
21,900
22,500
4800
4800
4800
24,800
26,700
27,300
601
601
601
10,000
10,900
11,300
2400
2400
2400
12,400
13,300
13,700
481
481
481
8000
8700
9000
1900
1900
1900
9900
10,600
10,900
250,000
500,000
Unlimited
1388
1388
1388
26,700
27,200
27,800
2800
2800
2800
29,500
30,000
30,600
1203
1203
1203
23,100
23,600
24,100
4800
4800
4800
27,900
28,400
28,900
601
601
601
11,600
11,800
12,000
2400
2400
2400
14,000
14,200
14,400
481
481
481
9300
9400
9600
1900
1900
1900
11,200
11,300
11,500
750
5.75%
50,000
100,000
150,000
2080
2080
2080
28,700
32,000
33,300
4200
4200
4200
32,900
36,200
37,500
1804
1804
1804
24,900
27,800
28,900
7200
7200
7200
32,100
35,000
36,100
902
902
902
12,400
13,900
14,400
3600
3600
3600
16,000
17,500
18,000
722
722
722
10,000
11,100
11,600
2900
2900
2900
12,900
14,000
14,500
250,000
500,000
Unlimited
2080
2080
2080
34,400
35,200
36,200
4200
4200
4200
38,600
39,400
40,400
1804
1804
1804
29,800
30,600
31,400
7200
7200
7200
37,000
37,800
38,600
902
902
902
14,900
15,300
15,700
3600
3600
3600
18,500
18,900
19,300
722
722
722
11,900
12,200
12,600
2900
2900
2900
14,800
15,100
15,500
1000
5.75%
50,000
100,000
150,000
2776
2776
2776
35,900
41,200
43,300
5600
5600
5600
41,500
46,800
48,900
2406
2406
2406
31,000
35,600
37,500
9800
9800
9800
40,600
45,200
47,100
1203
1203
1203
15,500
17,800
18,700
4800
4800
4800
20,300
22,600
23,500
962
962
962
12,400
14,300
15,000
3900
3900
3900
16,300
18,200
18,900
250,000
500,000
Unlimited
2776
2776
2776
45,200
46,700
48,300
5600
5600
5600
50,800
52,300
53,900
2406
2406
2406
39,100
40,400
41,800
9800
9800
9800
48,700
50,000
51,400
1203
1203
1203
19,600
20,200
20,900
4800
4800
4800
24,400
25,000
25,700
962
962
962
15,600
16,200
16,700
3900
3900
3900
19,500
20,100
20,600
1500
5.75%
50,000
100,000
150,000
4164
4164
4164
47,600
57,500
61,800
8300
8300
8300
55,900
65,800
70,100
3609
3609
3609
41,200
49,800
53,500
14,400
14,400
14,400
55,600
64,200
57,900
1804
1804
1804
20,600
24,900
26,700
7200
7200
7200
27,800
32,100
33,900
1444
1444
1444
16,500
20,000
21,400
5800
5800
5800
22,300
25,800
27,200
250,000
500,000
Unlimited
4164
4164
4164
65,600
68,800
72,500
8300
8300
8300
73,900
77,100
80,800
3609
3609
3609
56,800
59,600
62,800
14,400
14,400
14,400
71,200
74,000
77,200
1804
1804
1804
28,400
29,800
31,400
7200
7200
7200
35,600
37,000
38,600
1444
1444
1444
22,700
23,900
25,100
5800
5800
5800
28,500
29,700
30,900
2000
5.75%
50,000
100,000
150,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2406
2406
2406
24,700
31,000
34,000
9600
9600
9600
34,300
40,600
43,600
1924
1924
1924
19,700
24,800
27,200
7800
7800
7800
27,500
32,600
35,000
250,000
500,000
Unlimited
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2406
2406
2406
36,700
39,100
41,800
9600
9600
9600
46,300
48,700
51,400
1924
1924
1924
29,400
31,300
33,500
7800
7800
7800
37,200
39,100
41,300
2500
5.75%
50,000
100,000
150,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3008
3008
3008
28,000
36,500
40,500
12,000
12,000
12,000
40,000
48,500
52,500
2405
2405
2405
22,400
29,200
32,400
9600
9600
9600
32,000
38,800
42,000
250,000
500,000
Unlimited
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3008
3008
3008
44,600
48,100
52,300
12,000
12,000
12,000
56,600
60,100
64,300
2405
2405
2405
35,600
38,500
41,800
9600
9600
9600
45,200
48,100
51,400
3000
5.75%
50,000
100,000
150,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3609
3609
3609
30,700
41,200
46,600
14,000
14,000
14,000
44,700
55,200
60,600
2886
2886
2886
24,600
33,000
37,300
11,500
11,500
11,500
36,100
44,500
48,800
250,000
500,000
Unlimited
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
3609
3609
3609
51,900
56,800
62,800
14,000
14,000
14,000
65,900
70,800
76,800
2886
2886
2886
41,500
45,500
50,200
11,500
11,500
11,500
53,000
57,000
61,700
3750
5.75%
50,000
100,000
150,000
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4511
4511
4511
34,000
47,500
54,700
18,000
18,000
18,000
52,000
65,500
72,700
3608
3608
3608
27,200
38,000
43,700
14,400
14,400
14,400
41,600
52,400
58,100
250,000
500,000
Unlimited
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
4511
4511
4511
62,200
69,400
78,500
18,000
18,000
18,000
80,200
87,400
96,500
3608
3608
3608
49,800
55,500
62,800
14,400
14,400
14,400
64,200
69,900
77,200
a Short-circuit capacity values shown correspond to kVA and impedances shown in this table. For impedances other than these, short-circuit currents are inversely
proportional to impedance.
b The motor’s short-circuit current contributions are computed on the basis of motor characteristics that will give four times normal current. For 208V, 50% motor
load is assumed while for other voltages 100% motor load is assumed. For other percentages, the motor short-circuit current will be in direct proportion.

Approximate Impedance Data
Table 28. Typical Impedances—
Three-Phase Transformers Liquid-Filled a
kVA Liquid-Filled
Network Padmount
37.5
45
50
—
—
—
—
—
—
75
112.5
150
—
—
—
3.4
3.4
3.4
225
300
500
—
5.00
5.00
3.4
3.4
4.6
750
1000
1500
5.00
5.00
7.00
5.75
5.75
5.75
2000
2500
3000
7.00
7.00
—
5.75
5.75
5.75
3750
5000
—
—
6.00
6.50
a Values are typical. For guaranteed values, refer
to transformer manufacturer.
Table 29. 15 kV Class Primary—
Oil Liquid-Filled Substation Transformers
kVA %Z %R %X X/R
65 °C Rise
112.5
150
225
5.00
5.00
5.00
1.71
1.88
1.84
4.70
4.63
4.65
2.75
2.47
2.52
300
500
750
5.00
5.00
5.75
1.35
1.50
1.41
4.81
4.77
5.57
3.57
3.18
3.96
1000
1500
2000
5.75
5.75
5.75
1.33
1.12
0.93
5.59
5.64
5.67
4.21
5.04
6.10
2500 5.75 0.86 5.69 6.61
Table 30. DOE 2016 Transformer Efficiencies—
Medium-Voltage Three-Phase Distribution
Transformers b
kVA % Efficiency
Liquid-
Filled
DryTransformers
All
BILs
25–45
kV BIL
46–95
kV BIL
M96 kV
BIL
15
30
45
98.65
98.83
98.92
97.5
97.9
98.1
97.18
97.63
97.86
—
—
—
75
112.5
150
99.03
99.11
99.16
98.33
98.52
98.65
98.13
98.36
98.51
—
—
—
225
300
500
99.23
99.27
99.35
98.82
98.93
99.09
98.69
98.81
98.99
98.57
98.69
98.89
750
1000
1500
99.40
99.43
99.48
99.21
99.28
99.37
99.12
99.2
99.3
99.02
99.11
99.21
2000
2500
99.51
99.53
99.43
99.47
99.36
99.41
99.28
99.33
b Based on transformer operating at 50% of
nameplate base kVA.
Table 31. 15 kV Class Primary—
Dry-Type Substation Transformers
kVA %Z %R %X X/R
150 °C Rise
300
500
750
4.50
5.75
5.75
2.87
2.66
2.47
3.47
5.10
5.19
1.21
1.92
2.11
1000
1500
2000
5.75
5.75
5.75
2.16
1.87
1.93
5.33
5.44
5.42
2.47
2.90
2.81
2500 5.75 1.74 5.48 3.15
80 °C Rise
300
500
750
4.50
5.75
5.75
1.93
1.44
1.28
4.06
5.57
5.61
2.10
3.87
4.38
1000
1500
2000
5.75
5.75
5.75
0.93
0.87
0.66
5.67
5.68
5.71
6.10
6.51
8.72
2500 5.75 0.56 5.72 10.22
Table 32. 600 V Primary Class Three-Phase DOE
2016 Energy-Efficient Dry-Type Distribution
Transformers, Aluminum Wound
kVA %Z %X %R X/R
150 °C RiseAluminum
15
30
45
4.04
2.52
3.75
2.08
1.13
2.64
3.46
2.25
2.67
0.60
0.50
0.99
75
112.5
150
4.05
4.66
3.48
3.34
4.22
3.09
2.29
1.99
1.61
1.46
2.12
1.92
225
300
4.20
4.46
3.96
4.26
1.39
1.32
2.85
3.23
115 °C RiseAluminum
15
30
45
3.77
2.34
4.26
2.08
1.37
3.44
3.14
1.90
2.52
0.66
0.72
1.37
75
112.5
150
4.45
5.17
3.89
3.90
4.81
3.59
2.14
1.89
1.49
1.83
2.54
2.41
225
300
4.90
4.80
4.73
4.65
1.28
1.21
3.69
3.85
80 °C RiseAluminum
15
30
45
4.19
2.50
2.43
2.94
1.76
2.01
2.98
1.78
1.37
0.99
0.99
1.46
75
112.5
150
225
3.11
2.61
2.80
3.35
2.81
2.31
2.64
3.20
1.32
1.21
0.93
0.99
2.12
1.92
2.85
3.23
Table 33. 600V Primary Class Three-Phase DOE
2016 Energy-Efficient Dry-Type Distribution
Transformers, Copper Wound
kVA %Z %X %R X/R
150 °C Rise Copper
15
30
45
3.10
2.52
3.80
1.59
0.79
2.60
2.66
2.39
2.77
0.60
0.33
0.94
75
112.5
150
2.84
3.63
3.02
1.94
3.11
2.64
2.08
1.88
1.46
0.93
1.66
1.81
225
300
4.34
3.48
3.98
3.19
1.73
1.38
2.31
2.31
115 °C Rise Copper
15
30
45
2.90
2.35
3.85
1.59
0.97
2.87
2.43
2.14
2.57
0.66
0.45
1.12
75
112.5
150
2.86
4.02
3.34
2.12
3.59
3.05
1.92
1.82
1.37
1.10
1.97
2.23
225
300
5.03
4.14
4.78
3.94
1.58
1.29
3.02
3.06
80 °C Rise Copper
15
30
45
3.09
2.53
1.70
2.04
1.73
1.16
2.32
1.85
1.25
0.88
0.94
0.93
75
112.5
150
225
2.42
2.27
2.89
3.11
2.07
1.98
2.65
2.95
1.25
1.09
1.15
0.96
1.66
1.81
2.31
3.06
81

Transformer Loss Data
Transformer Losses at Reduced Loads
Information on losses based on actual
transformer test data can be obtained
from the manufacturer.Transformer
manufacturers provide no load watt
losses and total watt losses in accor
dance
with ANSI standards.The calculated
difference between the no load losses and
the total losses are typically described
as the load losses. Although transformer
coils are manufactured with either
aluminum or copper conductors, the
industry has sometimes referred to
these load losses as the “copper losses.
”
Transformer losses for various loading
can be estimated in the following manner.
The no load watt losses of the transformer
are due to magnetization and are present
whenever the transformer is energized.
The load watt losses are the difference
between the no load watt losses and the
full load watt losses.The load watt losses
are proportional to I2R and can be
estimated to vary with the transformer
load by the square of the load current.
For example, the approximate watts loss
data for a 1000 kVA oil-filled substation
transformer is shown in the table as
having 1800 watts no load losses and
15,100 watts full load losses, so the load
losses are approxi
mately 13,300 watts
(15,100–1800).The transformer losses can
be calculated for various loads as follows.
At 0% load:
1800 watts
At 50% load:
1800 watts + (13,300)(0.5)2
=
1800 watts + 3325 watts = 5125 watts
At 100% load:
1800 watts + 13,300 watts = 15,100 watts
At 110% load:
1800 watts + (13,300)(1.1)2
=
1800 watts + 16,093 watts = 17,893 watts
Because transformer losses vary between
designs and manufacturers, additional
losses such as from cooling fans can be
ignored for these approximations.
Note: 1 watthour = 3.413 Btu.

Table 34. Three-Phase Transformer Winding Connections
Phasor Diagram Notes
1. Suitable for both ungrounded and effectively grounded sources.
2. Suitable for a three-wire service or a four-wire service with a mid-tap ground.
2. Suitable for a three-wire service or a four-wire grounded service with XO grounded.
3. With XO grounded, the transformer acts as a ground source for the secondary system.
4. Fundamental and harmonic frequency zero-sequence currents in the secondary lines
supplied by the transformer do not flow in the primary lines. Instead the zero sequence
currents circulate in the closed delta primary windings.
5. When supplied from an effectively grounded primary system does not see load
unbalances and ground faults in the secondary system.
2. Suitable for a three-wire service or a four-wire delta service with a mid-tap ground.
3. Grounding the primary neutral of this connection would create a ground source for
the primary system.This could subject the transformer to severe overloading during
a primary system disturbance or load unbalance.
4. Frequently installed with mid-tap ground on one leg when supplying combination
three-phase and single-phase load where the three-phase load is much larger than
single-phase load.
5. When used in 25 kV and 35 kV three-phase four-wire primary systems, ferroresonance
can occur when energizing or de-energizing the transformer using single-pole switches
located at the primary terminals.With smaller kVA transformers the probability of
ferroresonance is higher.
2. Suitable for a three-wire service only, even if XO is grounded.
3. This connection is incapable of furnishing a stabilized neutral and its use may
result in phase-to-neutral overvoltage (neutral shift) as a result of unbalanced
phase-to-neutral load.
4. If a three-phase unit is built on a three-legged core, the neutral point of the primary
windings is practically locked at ground potential.
1. Suitable for four-wire effectively grounded source only.
2. Suitable for a three-wire service or for four-wire grounded service with
XO grounded.
3. Three-phase transformers with this connection may experience stray flux tank
heating during certain external system unbalances unless the core configuration
(four or five legged) used provides a return path for the flux.
4. Fundamental and harmonic frequency zero-sequence currents in the secondary
lines supplied by the transformer also flow in the primary lines (and primary
neutral conductor).
5. Ground relay for the primary system may see load unbalances and ground
faults in the secondary system.This must be considered when coordinating
overcurrent protective devices.
6. Three-phase transformers with the neutral points of the high-voltage and low-
voltage windings connected together internally and brought out through an
HOXO bushing should not be operated with the HOXO bushing ungrounded
(floating).To do so can result in very high voltages in the secondary systems.
2. Suitable for a three-wire service or a four-wire service with a mid-tap ground.
3. When using the tap for single-phase circuits, the single-phase load kVA should
not exceed 5% of the three-phase kVA rating of the transformer.The three-phase
rating of the transformer is also substantially reduced.
H2
H1 H3
X2
X1 X3
DELTA-DELTA Connection
Phasor
Diagram:
Angular Displacement (Degrees): 0
H2
H1 H3
X2
X1
X3
DELTA-WYE Connection
Phasor
Diagram:
X0
H2
H1 H3
X2
X1
X3
WYE-DELTA Connection
Phasor
Diagram:
H2
H1 H3
WYE-WYE Connection
Phasor
Diagram:
X2
X1 X3
X0
H2
H1 H3
GROUNDED WYE-WYE Connection
Phasor
Diagram:
X2
X1 X3
X0
H0
H2
H1 H3
X2
X1 X3
DELTA-DELTA Connection with Tap
Phasor
Diagram:
X4
83

Sound Levels
Sound Levels of Electrical Equipment
for Offices, Hospitals, Schools and
Similar Buildings
Insurance underwriters and building
owners require that the electrical
apparatus be installed for maximum
safety and minimum impact on normal
functioning of the property. Architects
should take particular care with the
designs for hospitals, schools and similar
buildings to keep the sound perception
of such equipment as motors, blowers
and transformers to a minimum.
Even though transformers are relatively
quiet, resonant conditions may exist near
the equipment, which will amplify their
normal 120 Hz hum.Therefore, it is
important that consid
eration be given
to the reduction of amplitude and to the
absorption of energy at this frequency.
This problem begins in the designing
stages of the equipment and the building.
There are two points worthy of
consideration:
■ What sound levels are desired in
the normally occupied rooms of
this building?
■ To effect this, what sound level in
the equipment room and what type
of associated acoustical treatment
will give the most economical
installation overall?
A relatively high sound level in the
equipment room does not indicate an
abnormal condition within the apparatus.
However, absorption may be necessary
if sound originating in an unoccupied
equipment room is objectionable outside
the room. Furthermore, added absorption
material usually is desirable if sound is
magnified due to reflections.
While some sound reduction or
attenuation takes place as the sound
waves travel through building walls, the
remainder may be reflected in various
directions, resulting in a build-up or
apparent higher levels.This is especially
true if resonance occurs because of room
dimensions or material characteristics.
Area Consideration
In determining permissible sound lev
els
within a building, it is necessary to
consider how the rooms are to be used
and what levels may be objectionable to
occupants of the building.The ambient
sound level values given in Table 35 are
representative average values and may
be used as a guide in determining
suitable building levels.
The decrease in sound level varies at an
approximate rate of 6 dB for each
doubling of the distance from the source
of sound to the listener. For example, if
the level 6 ft (1.8 m) from a transformer
is 50 dB, the level at a distance of 12 ft
(3.7 m) would be 44 dB and at 24 ft
(7.3 m) the level decreases to 38 dB,
etc. However, this rule applies only to
equipment in large areas equivalent to
an out-of-door installation, with no
nearby reflecting surfaces.
Table 35. Typical Sound Levels
Description Average
Decibel
Level (dB)
Radio, recording andTV studios
Theatres and music rooms
Hospitals, auditoriums and churches
25–30
30–35
35–40
Classrooms and lecture rooms
Apartments and hotels
Private offices and conference rooms
35–40
35–45
40–45
Stores
Residence (radio,TV off) and
small offices
Medium office (3 to 10 desks)
45–55
53
58
Residence (radio,TV on)
Large store (5 or more clerks)
Factory office
60
61
61
Large office
Average factory
Average street
64
70
80
Transformer Sound Levels
Transformers emit a continuous 120 Hz
hum with harmonics when connected to
60 Hz circuits.The fundamental frequency
is the “hum” that annoys people primarily
because of its continuous nature. For
purposes of reference, sound measuring
instruments convert the different
frequencies to 1000 Hz and a 40 dB
level.Transformer sound levels based
on NEMA publicationTR-1 are listed in
Table 36.
Because values given in Table 36 are
in general higher than those given in
Table 35, the difference must be
attenuated by distance and by proper use
of materials in the design of the building.
It may appear that a transformer is noisy
because the level in the room where it
is located is high.Two transformers of
the same sound output in the same
room increase the sound level in the
room approximately 3 dB, and three
transformers by about 5 dB, etc. A good
engineer needs to consider these factors
while designing the electrical rooms and
allocating locations for the transformers.
In many buildings, floors between
different levels can act like the sound
board in a piano. In these cases, sounds
due to structure-transmitted vibrations
originating from the trans
former are
lowered by mounting the transformers
on vibration dampeners or isolators.
There are a number of different sound
vibration isolating materials that may
be used with good results.
Dry-type power transformers are
often built with an isolator mounted
between the transformer support and
case members.The natural period
of the core and coil structure when
mounted on vibration dampeners is
about 10% of the fundamental frequency.
The reduction in the transmitted vibration
is approximately 98%.
If the floor or beams beneath the
transformer are light and flexible,
the isolator must be softer or have
improved characteristics in order to
keep the transmitted vibrations to a
minimum. (Enclosure covers and
ventilating louvers are often improperly
tightened or gasketed and their vibration
can produce unnecessary noise.)
The building structure will assist the
dampeners if the transformer is mounted
above heavy floor members or if mounted
on a heavy floor slab. Positioning of the
transformer in relation to walls and other
reflecting surfaces has a great effect on
reflected noise and resonances. Often,
placing the transformer at an angle to
the wall, rather than parallel to it, will
reduce noise.
Electrical connections to a substation
transformer should be made with flexible
braid or conductors; connections to an
individually mounted transformer should
be in flexible conduit.

Table 36. Maximum Average Sound Levels for Medium-Voltage Transformers—Decibels
kVA Liquid-FilledTransformers Dry-TypeTransformers
Self-Cooled
Rating (OA)
Forced-Air
Cooled Rating (FA)
Self-Cooled
Rating (AA)
Forced-Air
Cooled Rating (FA)
300
500
750
55
56
57
—
—
67
58
60
64
67
67
67
1000
1500
2000
58
60
61
67
67
67
64
65
66
67
68
69
2500
3000
3750
62
63
64
67
67
67
68
68
70
71
71
73
5000
6000
7500
65
66
67
67
68
69
71
72
73
73
74
75
10,000 68 70 — 76
85

Motor Protection
Consistent with the 2014 NEC 430.6(A)(1)
circuit breaker, HMCP and fuse rating
selections are based on full load currents
for induction motors running at speeds
normal for belted motors and motors
with normal torque characteristics using
data taken from NECTable 430.250
(three-phase). Actual motor nameplate
ratings shall be used for selecting motor
running overload protection. Motors
built special for low speeds, high
torque characteristics, special starting
conditions and applications will require
other considerations as defined in the
application section of the NEC.
These additional considerations may
require the use of a higher rated HMCP
,
or at least one with higher magnetic
pickup settings.
Circuit breaker, HMCP and fuse
ampere rating selections are in line with
maximum rules given in NEC 430.52
andTable 430.250. Based on known
characteristics of Eaton type breakers,
specific units are recom
mended.The
current ratings are no more than the
maximum limits set by the NEC rules for
motors with code letters F toV or without
code letters. Motors with lower code
letters will require further considerations.
In general, these selections were
based on:
1. Ambient—outside enclosure not more
than 40 °C (104 °F).
2. Motor starting—infrequent starting,
stopping or reversing.
3. Motor accelerating time—10 seconds
or less.
4. Locked rotor—maximum 6 times
motor FLA.
Type HMCP motor circuit protector may
not set at more than 1300% of the motor
full-load current to comply with NEC
430.52. (Except for NEMA Design B
energy high-efficiency motors that can
be set up to 1700%.)
Circuit breaker selections are based on
types with standard interrupting ratings.
Higher interrupting rating types may be
required to satisfy specific system
application requirements.
For motor full load currents of 208V and
200V, increase the corresponding 230V
motor values by 10 and 15% respectively.
Table 37. Motor Circuit Protector (MCP), Circuit Breaker and Fusible Switch Selection Guide
Horsepower Full Load
Amperes
(NEC) FLA
Fuse Size NEC 430.52
MaximumAmperes
Recommended Eaton
Circuit
Breaker
Motor Circuit
ProtectorType HMCP
Time Delay Non-Time Delay Amperes Amperes Adj. Range
230V,Three-Phase
1
1-1/2
2
3
3.6
5.2
6.8
9.6
10
10
15
20
15
20
25
30
15
15
15
20
7
15
15
30
21–70
45–150
45–150
90–300
5
7-1/2
10
15
15.2
22
28
42
30
40
50
80
50
70
90
150
30
50
60
90
30
50
50
70
90–300
150–500
150–500
210–700
20
25
30
40
54
68
80
104
100
125
150
200
175
225
250
350
100
125
150
150
100
150
150
150
300–1000
450–1500
450–1500
750–2500
50
60
75
100
130
154
192
248
250
300
350
450
400
500
600
800
200
225
300
400
150
250
400
400
750–2500
1250–2500
2000–4000
2000–4000
125
150
200
312
360
480
600
700
1000
1000
1200
1600
500
600
700
600
600
600
1800–6000
1800–6000
1800–6000
460V,Three-Phase
1
1-1/2
2
3
1.8
2.6
3.4
4.8
6
6
6
10
6
10
15
15
15
15
15
15
7
7
7
15
21–70
21–70
21–70
45–150
5
7-1/2
10
15
7.6
11
14
21
15
20
25
40
25
35
45
70
15
25
35
45
15
30
30
50
45–150
90–300
90–300
150–500
20
25
30
40
27
34
40
52
50
60
70
100
90
110
125
175
50
70
70
100
50
70
100
100
150–500
210–700
300–1000
300–1000
50
60
75
100
65
77
96
124
125
150
175
225
200
150
300
400
110
125
150
175
150
150
150
150
450–1500
750–2500
750–2500
750–2500
125
150
200
156
180
240
300
350
450
500
600
800
225
250
350
250
400
400
1250–2500
2000–4000
2000–4000
575V,Three-Phase
1
1-1/2
2
3
1.4
2.1
2.7
3.9
3
6
6
10
6
10
10
15
15
15
15
15
3
7
7
7
9–30
21–70
21–70
21–70
5
7-1/2
10
15
6.1
9
11
17
15
20
20
30
20
30
35
60
15
20
25
40
15
15
30
30
45–150
45–150
90–300
90–300
20
25
30
40
22
27
32
41
40
50
60
80
70
90
100
125
50
60
60
80
50
50
50
100
150–500
150–500
150–500
300–1000
50
60
75
100
52
62
77
99
100
110
150
175
175
200
250
300
100
125
150
175
100
150
150
150
300–1000
750–2500
750–2500
750–2500
125
150
200
125
144
192
225
300
350
400
450
600
200
225
300
250
250
400
1250–2500
1250–2500
2000–4000

Table 38. 60 Hz, Recommended Protective Setting for Induction Motors
hp Full Load
Amperes
(NEC) FLA
MinimumWire Size
75 °C CopperAmpacity
at 125% FLA
Minimum Conduit Size,
Inches (mm)
Fuse Size NEC 430.52
MaximumAmperes a
Recommended Eaton:
Circuit
Breaker b
Amperes
Motor Circuit
Protector
THW THWN
XHHN
Time
Delay
Non-Time
Delay
Size Amperes Amperes Adjustable Range
115V, Single-Phase
3/4
1
1-1/2
13.8
16
20
14
14
12
20
20
30
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
25
30
35
45
50
60
30
35
40
Two-pole device
not available
2
3
5
7-1/2
24
34
56
80
10
8
4
3
30
50
85
100
0.50 (12.7)
0.75 (19.1)
1.00 (25.4)
1.00 (25.4)
0.50 (12.7)
0.50 (12.7)
0.75 (19.1)
1.00 (25.4)
45
60
100
150
80
110
175
250
50
70
100
150
230V, Single-Phase
3/4
1
1-1/2
6.9
8
10
14
14
14
20
20
20
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
15
15
20
25
25
30
15
20
25
Two-pole device
not available
2
3
5
7-1/2
12
17
28
40
14
12
10
8
20
30
50
50
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.75 (19.1)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
0.50 (12.7)
25
30
50
70
40
60
90
125
30
40
60
80
a Consult fuse manufacturer’s catalog for smaller fuse ratings.
b Types are for minimum interrupting capacity breakers. Ensure that the fault duty does not exceed breaker’s I.C.
87

Generators and
Generator Systems
Typical Diesel Genset—Caterpillar
Introduction
The selection and application of
generators into the electrical distribution
system will depend on the particular
application.There are many factors to
consider, including code requirements,
environmental constraints, fuel sources,
control complexity, utility requirements
and load requirements.The healthcare
requirements for legally required
emergency standby generation
systems are described starting on
Page 100.
Systems described in this section are
applicable to healthcare requirements,
as well as other facilities that may require
a high degree of reliability.The electrical
supply for data centers, financial
institutions, telecommunications,
government and public utilities also
require high reliability.Threats of disaster
or terror attacks have prompted many
facilities to require complete self-
sufficiency for continuous operation.
NEC Changes Related to
Generator Systems
Article 250.30—Grounding Separately
Derived AC Systems—was completely
rewritten for clarity and for usability in
the 2011 NEC. Most notably, the term
equipment bonding jumper was
changed to supply-side bonding jumper
(see 250.30(A)(2)).This was necessary
to ensure proper identification and
installation of bonding conductors
within or on the supply side of service
equipment and between the source of a
separately derived system and the first
disconnecting means.
The other requirements for grounded
systems were renumbered to accom
modate the 250.30(A)(2) change. 250.30(B)
(3)—Ungrounded Systems—was added
and this language requires a supply-side
bonding jumper to be installed from the
source of a sepa
rately derived system
to the first dis
connecting means in
accordance with 250.30(A)(2). Another
new require
ment, 250.30(C)—Outdoor
Source—was added that requires a
grounding electrode connection at the
source location when the separately
derived system is located outside of the
build
ing or the structure being supplied.
Article 445.19—Generators Supplying
Multiple Loads—was also revised
to require that the generator have
overcurrent protection per 240.15(A)
when using individual enclosures
tapped from a single feeder.
Article 517.17(B)—Feeder Ground Fault
Protection (Healthcare Facilities)—now
allows, but does not require, multiple
levels of Ground Fault Protection
Equipment (GFPE) upstream of the
transfer switch when the choice is made
to provide GFPE on the alternate power
source (i.e., generator).
Article 701.6(D)—Signals (Legally
Required Standby Systems)—now
requires ground fault indication for
legally required standby systems of
more than 150V to ground and OCPDs
rated 1000 A or more.
Types of Engines
Many generator sets are relatively small
in size, typically ranging from several
kilowatts to several megawatts.These
units are often required to come online
and operate quickly.They need to have
the capacity to run for an extended period
of time.
The internal combustion engine is an
excellent choice as the prime mover
for the majority of these applications.
Diesel-fueled engines are the most
common, but other fuels used include
natural gas, digester gas, landfill gas,
propane, biodiesel, crude oil, steam
and others.
Some campuses and industrial facilities
use and produce steam for heating and
other processes.These facilities may find
it economically feasible to produce
electricity as a byproduct of the steam
production.These installations would
typically be classified as a cogeneration
facility producing a fairly constant power
output and operating in parallel with the
electric utility system.
Types of Generators
Generators can be either synchronous
or asynchronous. Asynchronous
generators are also referred to as
induction generators.The construction
is essentially the same as an induction
motor. It has a squirrel-cage rotor and
wound stator. An induction generator
is a motor driven above its designed
synchronous speed thus generating
power. It will operate as a motor if it is
running below synchronous speed.
The induction generator does not have
an exciter and must operate in parallel
with the utility or another source.The
induction generator requiresVARs from
an external source for it to generate
power.The induction generator operates
at a slip frequency so its output frequency
is automatically locked in with the utility’s
frequency.
An induction generator is a popular choice
for use when designing cogeneration
systems, where it will operate in parallel
with the utility.This type of generator
offers certain advantages over a
synchronous generator. For example,
voltage and frequency are controlled by
the utility; thus voltage and frequency
regulators are not required. In addition,
the generator construction offers high
reliability and little maintenance. Also, a
minimum of protective relays and controls
are required. Its major disadvantages are
that it requiresVARs from the system and
it normally cannot operate as a standby/
emergency generator.
Synchronous generators, however, are the
most common.Their output is determined
by their field and governor controls.
Varying the current in the DC field
windings controls the voltage output.
The frequency is controlled by the speed
of rotation.The torque applied to the
generator shaft by the driving engine
controls the power output. In this manner,
the synchro
nous generator offers precise
control over the power it can generate. In
cogeneration applications, it can be used
to improve the power factor of the system.

Generator Systems
Emergency Standby Generator System
There are primarily three types of
generator systems.The first and simplest
type is a single generator that operates
independently from the electric utility
power grid.This is typically referred to
as an emergency standby generator
system. Figure 65 shows a single standby
generator, utility source and
a transfer switch.
In this case, the load is either supplied
from the utility or the generator.The
generator and the utility are never
continuously connected together.This
simple radial system has few require
ments for protection and control. It also
has the least impact on the complete
electric power distribution system.
It should be noted that this type of
generator system improves overall
electrical reliability but does not provide
the redundancy that some facilities
require if the generator fails to start
or is out for maintenance.
Figure 65. Emergency Standby
Generator System
Multiple Isolated Standby Generators
The second type of generator system
is a multiple isolated set of standby
generators. Figure 66 shows multiple
generators connected to a paralleling
bus feeding multiple transfer switches.
The utility is the normal source for the
transfer switches.The generators and the
utility are never continuously connected
together in this scheme.
Multiple generators may be required to
meet the load requirements (N system).
Generators may be applied in an N+1
or a 2N system for improved system
reliability.
Figure 66. Multiple Isolated Set of
Standby Generators
In an N system, where N is the number of
generators required to carry the load; if a
generator fails or is out for maintenance,
then the load may be dropped.This is
unacceptable for most critical 24/7
operations. In an N + 1 system, N is the
number of generators needed to carry
the load and 1 is an extra generator for
redundancy. If one generator fails to start
or is out for maintenance, it will not affect
the load.
In a 2N system, there is complete 100%
redundancy in the standby generation
system such that the failure of one
complete set of generators will not
affect the load.
Multiple generator systems have a
more complex control and protection
requirement as the units have to be
synchronized and paralleled together.
The generators are required to share the
load proportionally without swings or
prolonged hunting in voltage or frequency
for load sharing.They may also require
multiple levels of load shedding and/or
load restoration schemes to match
generation capacity.
Multiple Generators Operating in
Parallel with Utility System
The third type of system is either one
with a single or multiple generators that
operate in parallel with the utility system.
Figure 67 shows two generators
and a utility source feeding a switchgear
lineup feeding multiple loads.This system
typically requires generator capacity
sufficient to carry the entire load or
sophisticated load shedding schemes.
This system will require a complete and
complex protection and control scheme.
The electric utility may have very stringent
and costly protection requirements for the
system. IEEE standard 1547 describes the
interconnection require
ments for
paralleling to the utility.
Figure 67. Multiple Generators Operating in
Parallel with Utility System
Utility
ATS
Load
G1
Utility
ATS-1
Load 1
ATS-2
Load 2
G1 G2
Switchgear
Utility
Switchgear
Load 1 Load 2 Load 3
G1 G2
89

Generator Fundamentals
A generator consists of two primary
components, a prime mover and an
alternator.The prime mover is the
energy source used to turn the rotor
of the alternator. It is typically a diesel
combustion engine for most emergency
or standby systems. In cogeneration
applications, the prime mover may
come from a steam driven turbine or
other source. On diesel units, a governor
and voltage regulator are used to control
the speed and power output.
The alternator is typically a synchro
nous
machine driven by the prime mover. A
voltage regulator controls its voltage
output by adjusting the field.The output of
a single generator or multiple paralleled
generator sets is controlled by these
two inputs.The alternator is designed
to operate at a specified speed for the
required output frequency, typically 60 or
50 Hz.The voltage regulator and engine
governor along with other systems define
the generator’s response to dynamic load
changes and motor starting characteristics.
Generators are rated in power and
voltage output. Most generators are
designed to operate at a 0.8 power factor.
For example, a 2000 kW generator at
277/480V would have a kVA rating of
2500 kVA (2000 kW/ 08 pf) and a
continuous current rating of 3007A
.
Typical synchronous generators for
industrial and commercial power systems
range in size from 100–3000 kVA and from
208V–13,800V. Other ratings are available
and these discussions are applicable to
those ratings as well.
Generators must be considered in the
short-circuit and coordination study as
they may greatly impact the rating of the
electrical distribution system.This is
especially common on large installations
with multiple generators and systems
that parallel with the utility source.
Short-circuit current contribution from
a generator typically ranges from 8 to
12 times full load amperes.
The application of generators adds
special protection requirements to
the system.The size, voltage class,
importance and dollar investment
will influence the protection scheme
associated with the generator(s).The
mode of operation will influence the
utility company’s interface protection
requirements. Paralleling with the electric
utility is the most complicated of the
utility inter-tie requirements. IEEE ANSI
1547 provides recom
mended practices.
Generator Grounding and Bonding
(Ref. NEC 2014, Article 250.30(A)(1)
and (2))
Generator grounding methods need
to be considered and may affect the
distribution equipment and ratings.
Generators may be connected in delta
or wye, with wye being the most typical
connection. A wye-connected generator
can be solidly grounded, low impedance
grounded, high impedance grounded
or ungrounded.The Grounding/Ground
Fault Protection section of this Design
Guide discusses general ground
ing
schemes, benefits of each and protection
considerations.
A solidly grounded generator may have a
lower zero sequence impedance than its
positive sequence impedance. In this case,
the equipment will need to be rated for the
larger available ground fault current.The
generator’s neutral may be connected to
the system-neutral; if it is, the generator
is not a separately derived system and a
three-pole transfer switch is used.
If the generator’s neutral is bonded to
ground separate from the system-neutral,
it is a separately derived system and a
four-pole transfer switch is required or
ground fault relays could misoperate
and unbalanced neutral current may be
carried on ground conductors.
An IEEE working group has studied the
practice of low resistance grounding of
medium-voltage generators within the
general industry.This “working group”
found that, for internal generator ground
faults, the vast majority of the damage
is done after the generator breaker is
tripped offline, and the field and turbine
are tripped.This is due to the stored
energy in the generator flux that takes
several seconds to dissipate after the
generator is tripped offline.
It is during this time that the low
resistance ground allows significant
amounts of fault current to flow into
the ground fault. Because the large fault
currents can damage the generator’s
winding, application of an alternate
protection method is desirable during
this time period. One of the solutions set
forth by this “working group” is a hybrid
high resistance grounding (HHRG)
scheme as shown in Figure 68.
In the HHRG scheme, the low resistance
ground (LRG) is quickly tripped offline
when the generator protection senses
the ground fault.The LRG is cleared at
the same time that the generator breaker
clears, leaving the high resistance ground
portion connected to control the transient
overvoltages during the coast-down
phase of the generator, thereby all but
eliminating generator damage.
Figure 68. Hybrid High Resistance Grounding Scheme
Gen 59G
51G
87GN
86
Phase
Relays
HRG
LRG
R
R

Generator Controls
The engine generator set has controls to
maintain the output frequency (speed)
and voltage.These controls consist of a
governor and voltage regulator. As loads
change on the system, the frequency and
voltage will change.The speed control will
then adjust the governor to correct for the
load (kW) change.The voltage regulator
will change the field current to adjust the
voltage to the desired voltage value.
These are the basic controls found on
all synchronous generators.
Multiple generator systems require more
sophisticated controls. Generators are
paralleled in a multi-generator system
and they must share the load.These
systems often have a load shed scheme,
which adds to the complexity.
Multiple generator schemes need a
master controller to prevent units from
being connected out-of-phase.The
sequence of operation is to send a start
signal to all generators simulta
neously.
The first unit up to frequency and voltage
will be permitted to close its respective
breaker and energize the paralleling bus.
During this time, the breakers for the
other generators are held open and not
permitted to close until certain conditions
are met. Once the paralleling bus is
energized, the remaining generators
must be synchronized to it before the
generators can be paralleled.
Synchronization compares the voltage
phasor’s angle and magnitude. Both
generators must be operating at the same
frequency and phase-matched within
typically 5 to 10 degrees with each other.
The voltage magnitude typically must be
within 20 to 24%.
A synch-scope is typically supplied on
paralleling gear.The synch-scope displays
the relative relationship between voltage
phasors on the generator to be paralleled
and the bus.
If the generator is running slower than
the bus (less than 60 Hz) then the needle
on the scope will spin in the counter-
clockwise direction. If it is running faster,
then it will rotate in the clockwise
direction.The greater the frequency
difference, the faster is the rotation. It
is important that the generators are in
phase before they are paralleled. Severe
damage will occur if generators are
paralleled out-of-phase.
Generator Short-Circuit
Characteristics
If a short circuit is applied directly to
the output terminals of a synchronous
generator, it will produce an extremely
high current initially, gradually decaying
to a steady-state value.This change is
represented by a varying reactive
impedance.Three specific reactances
are used for short-circuit fault currents.
They are:
■ Subtransient reactance Xd”
, which is
used to determine the fault current
during the first 1 to 5 cycles
■ Transient reactance Xd’, which is used
to determine the fault current during
the next 5 to 200 cycles
■ Synchronous reactance Xd”
, which is
used to determine the steady- state
fault current
The subtransient reactance Xd” will range
from a minimum of approxi
mately 9%
for a two-pole, wound-rotor machine to
approximately 32% for a low-speed,
salient-pole, hydro-generator.The initial
symmetrical fault current can be as much
as 12 times full load current.
Depending on the generator type, the
zero sequence impedance may be less
than the subtransient reactance and the
ground fault current substan
tially higher
than the three-phase short-circuit current.
For example, a 2500 kVA, 480/277V,
four-pole, 2/3 pitch standby generator has
a 0.1411 per unit subtransient reactance
Xd” and a 0.033 per unit zero sequence
Xo reactance.The ground current is
approximately a third larger than the
three-phase fault current.The ground fault
current can be reduced to the three-phase
level by simply adding a small reactance
between the generator neutral and
ground while still being considered
solidly grounded.
An electric power system analysis must
be performed based on the worst- case
operating conditions.Typically this is
when all sources are paralleled. If the
system can operate with both the utility
supply and generators in parallel, then
the equipment must be rated for the
combined fault current plus motor
contribution. If the generator and utility
will not be paralleled, then both cases will
need to be looked at independently and
the worst case used for selecting the
equipment ratings.
91

Generator Protection
Generator protection will vary and
depend on the size of the generator,
type of system and importance of the
generator. Generator sizes are defined as:
small—1000 kVA maximum up to 600V
(500 kVA maximum when above 600V);
medium over 1000 kVA to 12,500 kVA
maximum regardless of voltage; large—
from 12,500–50,000 kVA.
The simplest is a single generator system
used to feed emergency and/or standby
loads. In this case, the generator is the
only source available when it is operating
in the emergency mode and must keep
operating until the normal source returns.
Figure 69 Part (A) shows minimum
recommended protection for a single
generator used as an emergency or
standby system. Phase and ground time
overcurrent protection (Device 51 and
51G) will provide protection for external
faults. For medium-voltage generators,
a voltage controlled time overcurrent
relay (Device 51V) is recommended for
the phase protec
tion as it can be set
more sensitive than standard overcurrent
relays and is less likely to false operate
on normal overloads.
This scheme may not provide adequate
protection for internal generator faults
when no other power source exists.
Local generator controllers may offer
additional protection for voltage and
frequency conditions outside the
generator’s capabilities.
Figure 69 Part (B) shows the
recommended protection for multiple,
isolated, medium-voltage, small
generators. Additional protection may
be desired and could include generator
differential, reverse power, and loss of
field protection. Differential protection
(Device 87) can be accom
plished with
either a self-balancing set of CTs as
in Figure 70 or with a percentage
differential scheme as in Figure 71
on Page 93.
The percentage differential scheme offers
the advantage of reducing the possibility
for false tripping due to CT saturation.
The self-balancing scheme offers the
advantages of increased sensitivity,
needing three current transformers in
lieu of six, and the elimination of current
transformer external wiring from the
generator location to the generator
switchgear location.
Figure 69. Typical Protective Relaying Scheme for Small Generators
Figure 70. Self-Balancing Generator Differential
Relay Scheme
51G
1
Preferred
Location
51
51G
1
1
Gen
51
1
Alternate
Location
1 1
51V 32 40
1
3
87
Gen
Generator Protection ANSI/IEEE
Std 242-1986
(A) (B)
(A) Single Isolated Generator on Low-Voltage System
(B) Multiple Isolated Generator on Medium-Voltage System
87-1
87-3
87-2
50/5A
50/5A
50/5A
R
Gen

Reverse power protection (Device 32) is
used to prevent the generator from being
motored. Motoring could damage (with
other hazards) the prime mover. A steam
turbine could overheat and fail. A diesel
or gas engine could either catch fire or
explode. A steam turbine can typically
withstand approx
imately 3% reverse
power where a diesel engine can
withstand up to 25% reverse power.
Loss of field protection (Device 40) is
needed when generators are operating
in parallel with one another or the power
grid.When a synchronous generator
loses its field, it will continue to generate
power as an induction generator
obtaining its excitation from the other
machines on the system.
During this condition, the rotor will
quickly overheat due to the slip frequency
currents induced in it. Loss of excitation
in one machine could jeopardize the
operation of the other machines beyond
their capability and the entire system.
Figure 71. Generator Percentage Differential Relay (Phase Scheme) and Ground Differential Scheme
Using a Directional Relay
87
01 R1
02 R2
03 R3
R1
R2
R3
PC
OC
87G
Grounding
Resistor
51G
To Main Bus
52
Gen
OC = Operating coil
PC = Permissive coil
93

Typical protection for larger generators
is shown in Figure 72. It adds phase
unbalance and field ground fault
protection. Phase unbalance (Device 46)
or negative sequence overcurrent
protection prevents the generator’s
rotor from overheating damage.
Unbalanced loads, fault conditions or
open phasing will produce a negative
sequence current to flow.The unbalanced
currents induce double system frequency
currents in the rotor, which quickly causes
rotor overheating. Serious damage will
occur to the generator if the unbalance is
allowed to persist.
Other protection functions such as under/
overvoltage (Device 27/59) could be
applied to any size generator.The voltage
regulator typically maintains the output
voltage within its desired output range.
This protection can provide backup
protection in case the voltage regulator
fails. Under/overfrequency protection
(Device 81U/81O) could be used for
backup protection for the speed control.
Sync check relays (Device 25) are typically
applied as a breaker permissive close
function where generators are paralleled.
Many modern protective relays are
microprocessor-based and provide a
full complement of generator protection
functions in a single package.The cost per
protection function has been drastically
reduced such that it is feasible to provide
more complete protection even to
smaller generators.
IEEE ANSI 1547 provides recommended
practices for utility inter-tie protection.
If the system has closed- transition or
paralleling capability, additional pro
tection
may be required by the utility.Typically,
no additional protection is required if the
generator is paralleled to the utility for
a maximum of 100 msec or less.
Systems that offer soft transfer, peak
shaving or co-generation will require
additional utility inter-tie protection.
The protection could include directional
overcurrent and power relays and even
transfer trip schemes. Please consult your
local utility for specific requirements.
Figure 72. Typical Protective Relaying Scheme for Large Generator
3
87B
3
87
1
87G
1
49
Gen
1
64
E
60
46
32
40
51V
3
Voltage Regulator and
Metering Circuits
51G
81U/O
27/59
1
1
1

Generator Set Sizing
and Ratings
Many factors must be considered when
determining the proper size or electrical
rating of an electrical power generator
set. The engine or prime mover is sized to
provide the actual or real power in kW, as
well as speed (frequency) control through
the use of an engine governor.
The generator is sized to supply the kVA
needed at startup and during normal
running operation. It also provides voltage
control through the use of a brushless
exciter and voltage regulator.Together the
engine and generator provide the energy
necessary to supply electrical loads in
many different applications encountered
in today’s society.
The generator set must be able to supply
the starting and running electrical load. It
must be able to pick up and start all motor
loads and low power factor loads, and
recover without excessive voltage dip or
extended recovery time.
Nonlinear loads like variable frequency
drives, uninterruptible power supply
(UPS) systems and switching power
supplies also require attention because
the SCR switching causes voltage and
current waveform distortion and
harmonics.The harmonics generate
additional heat in the generator wind
ings,
and the generator may need to be upsized
to accommodate this.
The type of fuel (diesel, natural gas,
propane, etc.) used is important as it
is a factor in determining generator set
response to transient overloads. It is also
necessary to determine the load factor
or average power consumption of the
generator set.This is typically defined as
the load (kW) x time (hrs. while under that
particular load) / total running time.When
this load factor or average power is taken
into consideration with peak demand
requirements and the other operating
parameters mentioned above, the
overall electrical rating of the genset
can be determined.
Other items to consider include the
unique installation, ambient, and site
requirements of the project.These
will help to determine the physical
configuration of the overall system.
Typical rating definitions for diesel
gensets are: standby, prime plus 10,
continuous and load management
(paralleled with or isolated from utility).
Any diesel genset can have several
electrical ratings depending on the
number of hours of operation per year
and the ratio of electrical load/genset
rating when in operation.The same
diesel genset can have a standby rating
of 2000 kW at 0.8 power factor (pf) and a
continuous rating of 1825 kW at 0.8 pf.
The lower continuous rating is due to the
additional hours of operation and higher
load that the continuous genset must
carry.These additional require
ments put
more stress on the engine and generator
and therefore the rating is decreased to
maintain longevity of the equipment.
Different generator set manufacturers use
basically the same diesel genset electrical
rating definitions.These are based on
International Diesel Fuel Stop Power
standards from organiza
tions like ISO,
DIN and others.
■ Standby diesel genset rating—
Typically defined as supplying
varying electrical loads for the
duration of a power outage with the
load normally connected to utility,
genset operating <100 hours per
year and no overload capability
■ Prime plus 10 rating—Typically defined
as supplying varying electrical loads
for the duration of a power outage with
the load normally connected to utility,
genset operating <500 hours per year
and overload capability of 10% above
its rating for 1 hour out of 12
■ Continuous rating—Typically defined
as supplying unvarying electrical loads
(i.e., base loaded) for an unlimited time
■ Load management ratings—Apply to
gensets in parallel operation with the
utility or isolated/islanded from utility
and these ratings vary in usability from
<200 hours per year to unlimited usage
Refer to generator set manufacturers for
further definitions on load manage
ment
ratings, load factor or average power
consumption, peak demand and how
these ratings are typically applied. Even
though there is some standardization of
these ratings across the manufacturers,
there also exists some uniqueness with
regard to how each manufacturer applies
their generator sets.
Electrical rating definitions for natural gas
powered gensets are typically defined as
standby or continuous with definitions
similar to those mentioned above for
diesels. Natural gas gensets recover
more slowly than diesel gensets when
subjected to block loads. Diesel engines
have a much more direct path from the
engine governor and fuel delivery system
to the combustion chamber, resulting in
a very responsive engine-generator.
A natural gas engine is challenged with
air-fuel flow dynamics and a much more
indirect path from the engine governor
(throttle actuator) and fuel delivery
system (natural gas pressure regulator,
fuel valve and actuator, carburetor mixer,
aftercooler, intake manifold) to the
combustion chamber.This results in a
less responsive engine-generator. Diesel
gensets recover about twice as fast as
natural gas gensets.
For the actual calculations involved for
sizing a genset, there are readily accessible
computer software programs that are
available on the genset manu
facturer’s
Internet sites or from the manufacturer’s
dealers or distributors.These programs
are used to quickly and accurately size
generator sets for their application.The
programs take into consideration the
many different parameters discussed
above, including the size and type of the
electrical loads (resistive, inductive, SCR,
etc.), reduced voltage soft starting devices
(RVSS), motor types, voltage, fuel type,
site conditions, ambient conditions and
other variables.
The software will optimize the starting
sequences of the motors for the least
amount of voltage dip and determine the
starting kVA needed from the genset. It
also provides transient response data,
including voltage dip magnitude and
recovery duration. If the transient
response is unaccept
able, then design
changes can be considered, including
oversizing the generator to handle the
additional kvar load, adding RVSS devices
to reduce the inrush current, improving
system power factor and other methods.
The computer software programs are
quite flexible in that they allow changes
to the many different variables and
parameters to achieve an optimum
design.The software calculates how
to minimize voltage dips and can
recommend using paralleled gensets
vs. a single genset.
95

Genset Sizing Guidelines
Some conservative rules of thumb for
genset sizing include:
1. Oversize genset 20–25% for reserve
capacity and for across the line
motor starting.
2. Oversize gensets for unbalanced
loading or low power factor
running loads.
3. Use 1/2 hp per kW for motor loads.
4. For variable frequency drives, oversize
the genset by at least 40% for six-
pulse technology drives.
5. For UPS systems, oversize the genset
by 40% for 6 pulse and 15% for 6 pulse
with input filters or 12 pulse.
6. Always start the largest motor first
when stepping loads.
For basic sizing of a generator system,
the following example could be used:
Step 1: Calculate RunningAmperes
■ Motor loads:
❏ 200 hp motor. . . . . . . . . . . . . 156 A
❏ 100 hp motor . . . . . . . . . . . . . . 78 A
❏ 60 hp motor. . . . . . . . . . . . . . . 48 A
■ Lighting load . . . . . . . . . . . . . . . . 68 A
■ Miscellaneous loads . . . . . . . . . . 95 A
■ Running amperes. . . . . . . . . . . . 445A
Step 2: Calculating StartingAmperes
Using 1.25 Multiplier
■ Motor loads:
❏ 200 hp motor. . . . . . . . . . . . . 195 A
❏ 100 hp motor . . . . . . . . . . . . . . 98 A
❏ 60 hp motor. . . . . . . . . . . . . . . 60 A
■ Lighting load . . . . . . . . . . . . . . . . 68 A
■ Miscellaneous loads . . . . . . . . . . 95 A
■ Starting amperes. . . . . . . . . . . . 516A
Step 3: Selecting kVA of Generator
■ Running kVA =
(445 A x 480V x 1.732)/1000 = 370 kVA
■ Starting kVA =
(516 A x 480V x 1.732)/1000 = 428 kVA
Solution
Generator must have a minimum starting
capability of 428 kVA and minimum
running capability of 370 kVA.
Also, please see section
“Factors GoverningVoltage Drop”
on Page 56 for further discussion on
generator loading and reduced voltage
starting techniques for motors.
Generator Set Installation
and Site Considerations
There are many different installation
parameters and site conditions that
must be considered to have a successful
generator set installation.The following
is a partial list of areas to consider when
conducting this design. Some of these
installation parameters include:
■ Foundation type (crushed rock,
concrete, dirt, wood, separate
concrete inertia pad, etc.)
■ Foundation to genset vibration
dampening (spring type, cork and
rubber, etc.)
■ Noise attenuation (radiator fan
mechanical noise, exhaust noise,
air intake noise)
■ Combustion and cooling air
requirements
■ Exhaust backpressure requirements
■ Emissions permitting
■ Delivery and rigging requirements
■ Genset derating due to high altitudes
or excessive ambient temperatures
■ Hazardous waste considerations for
fuel, antifreeze, engine oil
■ Meeting local building and
electrical codes
■ Genset exposure (coastal conditions,
dust, chemicals, etc.)
■ Properly sized starting systems
(compressed air, batteries and charger)
■ Allowing adequate space for
installation of the genset and for
maintenance (i.e., air filter removal,
oil changing, general genset
inspection, etc…)
■ Flex connections on all systems that
are attached to the genset and a rigid
structure (fuel piping, founda
tion
vibration isolators, exhaust, air intake,
control wiring, power cables, radiator
flanges/duct work, etc.)
■ Diesel fuel day tank systems
(pumps, return piping)
■ Fuel storage tank (double walled,
fire codes) and other parameters
Please see the generator set manufac
turer’s application and installation
guidelines for proper application
and operation of their equipment.
Figure 73. Typical Genset Installation
Note: Courtesy of Caterpillar, Inc.

Capacitors and Power Factor
Capacitor General Application
Considerations
Additional application information
is available in Eaton’s Power Factor
Capacitors and Harmonic Filters Design
Guide and on our website as follows:
■ Capacitor selection
■ Where to install capacitors in a plant
distribution system
■ Locating capacitors on reduced voltage
and multi-speed starters
■ Harmonic considerations
■ Eliminating harmonic problems
■ National Electrical Code requirements
Medium-Voltage
Capacitor Switching
Capacitance switching constitutes severe
operating duty for a circuit breaker. At the
time the breaker opens at near current
zero, the capacitor is fully charged. After
interruption, when the alternating voltage
on the source side of the breaker reaches
its opposite maximum, the voltage that
appears across the contacts of the open
breaker is at least twice the normal peak
line-to-neutral voltage of the circuit. If a
breakdown occurs across the open
contact, the arc is re-established. Due
to the circuit constants on the supply
side of the breaker, the voltage across the
open contact can reach three times the
normal line-to-neutral voltage. After
it is interrupted and with subsequent
alternation of the supply side voltage,
the voltage across the open contact is
even higher.
ANSI Standard C37.06 (indoor oilless
circuit breakers) indicates the preferred
ratings of Eaton’sTypeVCP-W vacuum
breaker. For capacitor switching, careful
attention should be paid to the notes
accompanying the table.The definition
of the terms are in ANSI Standard C37.04
Article 5.13 (for the latest edition).
The application guide ANSI/IEEE
Standard C37.012 covers the method
of calculation of the quantities covered
by C37.06 Standard.
Note that the definitions in C37.04 make
the switching of two capacitors banks in
close proximity to the switch
gear bus a
back-to-back mode of switching.This
classification requires a definite purpose
circuit breaker (breakers specifically
designed for capacitance switching).
We recommend that such application be
referred to Eaton.
A breaker specified for capacitor
switching should include as applicable:
1. Rated maximum voltage.
2. Rated frequency.
3. Rated open wire line charging
switching current.
4. Rated isolated cable charging and
shunt capacitor switching current.
5. Rated back-to-back cable charging
and back-to-back capacitor
switching current.
6. Rated transient overvoltage factor.
7. Rated transient inrush current and
its frequency.
8. Rated interrupting time.
9. Rated capacitive current switching life.
10. Grounding of system and
capacitor bank.
Load break interrupter switches are
permitted by ANSI/IEEE Standard C37.30
to switch capacitance, but they must have
tested ratings for the purpose.
Low-Voltage Capacitor Switching
Circuit breakers and switches for use
with a capacitor must have a current
rating in excess of rated capacitor
current to provide for overcurrent from
overvoltages at fundamental frequency
and harmonic currents.The following
percent of the capacitor-rated current
should be used as a general guideline:
Fused and unfused switches. . . . . 165%
Molded case breaker or
equivalent . . . . . . . . . . . . . . . . . . 150%
Insulated case breakers. . . . . . . . . 135%
Magnum DS power
circuit breaker. . . . . . . . . . . . . . . 135%
Contactors:
Open type. . . . . . . . . . . . . . . . . . . . 135%
Enclosed type. . . . . . . . . . . . . . . . . 150%
The NEC, Section 460.8(C), requires the
disconnecting means to be rated not less
than 135% of the rated capacitor current
(for 600V and below).
Refer to Eaton’s Power Factor Capacitors
and Harmonic Filters Design Guide for
switching device ampere ratings.They
re based on percentage of capacitor-
rated current as indicated (above).The
interrupting rating of the switch must
be selected to match the system fault
current available at the point of capacitor
application.Whenever a capacitor bank
is purchased with less than the ultimate
kvar capacity of the rack or enclosure, the
switch rating should be selected based on
the ultimate kvar capacity—not the initial
installed capacity.
and Harmonic Filters Design Guide for
recommended selection of capacitor
switching devices; recommended
maximum capacitor ratings for various
motor types and voltages; and for
required multipliers to determine
capacitor kvar required for power
factor correction.
97

Motor Power Factor
Correction
and Harmonic Filters Design Guide
containing suggested maximum
capacitor ratings for induction motors
switched with the capacitor.The data is
general in nature and representative of
general purpose induction motors of
standard design.The preferable means
to select capacitor ratings is based on
the “maximum recommended kvar”
information available from the motor
manufacturer. If this is not possible or
feasible, the tables can be used.
An important point to remember is that if
the capacitor used with the motor is too
large, self-excitation may cause a motor-
damaging over
voltage when the motor
and capacitor combination is disconnected
from the line. In addition, high transient
torques capable of damaging the motor
shaft or coupling can occur if the motor is
reconnected to the line while rotating and
still generating a voltage of self-excitation.
Low-speed pump motors, or motors with
more than four poles, will typically exhibit
low power factor and high FLA.
Definitions
kvar—rating of the capacitor in
reactive kilovolt-amperes.This value
is approximately equal to the motor
no-load magnetizing kilovars.
% AR (amp reduction) is the percent
reduction in line current due to the
capacitor. A capacitor located on the
motor side of the overload relay reduces
line current through the relay.Therefore,
a different overload relay and/or setting
may be necessary.The reduction in line
current may be determined by measuring
line current with and without the
capacitor or by calculation as follows:
If a capacitor is used with a lower kvar
rating than listed in tables, the % AR can
be calculated as follows:
The tables can also be used for other
motor ratings as follows:
A. For standard 60 Hz motors
operating at 50 Hz:
kvar = 1.7–1.4 of kvar listed
% AR= 1.8–1.35 of % AR listed
B. For standard 50 Hz motors
operating at 50 Hz:
kvar = 1.4–1.1 of kvar listed
% AR= 1.4–1.05 of % AR listed
C. For standard 60 Hz wound-rotor
motors:
kvar = 1.1 of kvar listed
% AR= 1.05 of % AR listed
Note: For A, B, C, the larger multipliers
apply for motors of higher speeds; i.e.,
3600 rpm = 1.7 mult., 1800 rpm = 1.65 mult., etc.
To derate a capacitor used on a system
voltage lower than the capacitor voltage
rating, such as a 240V capacitor used on a
208V system, use the following formula:
For the kVAC required to correct the
power factor from a given value of
COS f1 to COS f2, the formula is:
kVAC = kW (tan phase1–tan phase2)
Capacitors cause a voltage rise. At light
load periods the capacitive voltage rise
can raise the voltage at the location of
the capacitors to an unacceptable level.
This voltage rise can be calculated
approximately by the formula:
MVAR
is the capacitor rating and MVASC
is
the system short-circuit capacity.
With the introduction of variable speed
drives and other harmonic current
generating loads, the capacitor
impedance value determined must
not be resonant with the inductive
reactances of the system.

BIL—Basic Impulse Levels
ANSI standards define recommended and
required BIL levels for:
■ Metal-clad switchgear
(typically vacuum breakers)
■ Metal-enclosed switchgear
(typically load interrupters, switches)
■ Pad-mounted and overhead
distribution switchgear
■ Liquid immersed transformers
■ Dry-type transformers
Table 39 through Table 43
contain those values.
Table 39. Metal-Clad Switchgear Voltage and
Insulation Levels (From IEEE Std. C37.20.2-2015)
Rated Maximum
Voltage (kV rms)
Impulse
Withstand (kV)
4.76
8.25
15.0
60
95
95
27.0
38.0
125
150
Table 40. Metal-Enclosed
Switchgear Voltage and Insulation Levels
(From IEEE Std. C37.20.3-2013)
Rated Maximum
Voltage (kV rms)
Impulse
Withstand (kV)
4.76
8.25
15.0
60
95
95
27.0
38.0
125
150
Table 41. Pad Mounted and Overhead
Distribution Switchgear, Voltage and
Insulation Levels
Rated Maximum
Voltage Level (kV rms)
Impulse
Withstand (kV)
Pad Mount Switchgear (per IEEE C37.74-2014)
15.5
27
38
95
125
150
Overhead Switchgear (per IEEE C37.60-2012)
15
15.5
27
95
110
125
38
38
150
170
Table 42. Liquid-Immersed Transformers Voltage
and Basic Lightning Impulse Insulation Levels
(BIL) (From ANSI/IEEE C57.12.00)
Application Nominal
System
Voltage
(kV rms)
BIL
(kV Crest) a
Distribution 1.2
2.5
5.0
30
45
60
—
—
—
—
—
—
—
—
—
8.7
15.0
25.0
75
95
150
—
—
125
—
—
—
—
—
—
34.5
46.0
69.0
200
250
350
150
200
250
125
—
—
—
—
—
Power 1.2
2.5
5.0
45
60
75
30
45
60
—
—
—
—
—
—
8.7
15.0
25.0
95
110
150
75
95
—
—
—
—
—
—
—
34.5
46.0
69.0
200
250
350
—
200
250
—
—
—
—
—
—
115.0
138.0
161.0
550
650
750
450
550
650
350
450
550
—
—
—
230.0
345.0
500.0
765.0
900
1175
1675
2050
825
1050
1550
1925
750
900
1425
1800
650
—
1300
—
a BIL values in bold typeface are listed as
standard. Others listed are in common use.
Table 43. Dry-Type Transformers Voltage and
Basic Lightning Impulse Insulation Levels
(BIL)—From ANSI/IEEE C57.12.01-1998)
Nominal
System
Voltage
(kV rms)
BIL (kV Crest) b
1.2
2.5
5.0
8.7
—
—
—
—
10
20
30
45
20
30
45
60
30
45
60
95
15.0
25.0
34.5
—
95 c
—
60
110
125 c
95
125
150
110
150
200
b BIL values in bold typeface are listed as
standard. Others listed are in common use.
Optional higher levels used where exposure
to overvoltage occurs and higher protection
margins are required.
c Lower levels where surge arrester protective
devices can be applied with lower spark-
over levels.
99

Healthcare Facilities
Healthcare facilities are defined by
NFPA (National Fire Protection Agency)
as “Buildings or portions of buildings
in which medical, dental, psychiatric,
nursing, obstetrical, or surgical care
are provided.
” Due to the critical nature
of the care being provided at these
facilities and their increasing depen
dence
on electrical equipment for preservation
of life, healthcare facilities have special
requirements for the design of their
electrical distribution systems.These
requirements are typically much more
stringent than commercial or industrial
facilities.The following section
summarizes some of the unique
requirements of healthcare
facility design.
There are several agencies and organi
zations that develop requirements for
healthcare electrical distribution system
design.The following is a listing of some of
the specific NFPA (National Fire Protection
Agency) standards that affect healthcare
facility design and implementation:
■ NFPA 37-2015—Standard for Stationary
Combustion Engines and GasTurbines
■ NFPA 70-2014—National Electrical Code
■ NFPA 99-2015—Healthcare Facilities
■ NFPA 101-2015—Life Safety Code
■ NFPA 110-2016—Standard for
Emergency and Standby
Power Systems
■ NFPA 111-2016—Standard on Stored
Electrical Energy Emergency and
Standby Power Systems
In addition to NFPA guidelines, there
are additional standards documents
important in the design of healthcare
power distribution systems and
accreditation of those facilities including:
■ Joint Commission—Environment
of Care 2016
■ Facility Guidelines Institute (FGI)—
Guidelines for Design and
Construction of Hospitals and
Outpatient Facilities—2014
These codes, standards and guidelines
represent the most industry recognized
requirements for healthcare electrical
design. However, the electrical design
engineer should consult with the
authorities having jurisdiction over
the local region for specific electrical
distribution requirements.
Healthcare Electrical System
Requirements
Healthcare electrical systems usually
consist of two parts:
1. Non-essential or normal
electrical system.
2. Essential electrical system.
All electrical power in a healthcare facility
is important, though some loads are not
critical to the safe opera
tion of the facility.
These “non-essential” or “normal” loads
include things such as general lighting,
general lab equip
ment, non-critical
service equipment, patient care areas, etc.
These loads are not required to be fed
from an alternate source of power.
The electrical system requirements for
the essential electrical system (EES) vary
according to the associated risk to the
patients, visitors and staff that might
occupy that space. NFPA 99 assigns a
risk category to each space within the
healthcare facility based on the risk
associated with a failure of the power
distribution system serving that space.
These risk categories are summarized
in Table 44.
The risk category of the space within the
healthcare facility determines whether or
not that space is required to be served by
an Essential Electrical System (EES). If an
EES is required to serve the space, the risk
category also dictates whether the EES
must meetType 1 orType 2 requirements.
Table 45 lists the associated EESType
requirements for each risk category.
Table 44. Essential Electrical System (EES) Risk Categories
Risk Category Failure of Such Equipment or System is Likely to Cause:
Category 1 ...major injury or death of patients or caregivers…
Category 2 ...minor injury to patients or caregivers…
Category 3 ...patient discomfort…
Category 4 ...no impact on patient care…
Table 45. Essential Electrical System (EES) Risk Category by Type
Risk Category Essential Electrical System (EES)Type Example
Category 1 Type 1 Critical Care Space
Category 2 Type 2 General Care Space
Category 3 EES not required Basic Examination Space
Category 4 EES not required Waiting Room
Typical Application by Facility Type

Figure 74. Typical Large Hospital Electrical System—Type 1 Essential Electrical System
Type 1 Essential Electrical
Systems (EES)
Type 1 essential electrical systems (EES)
have the most stringent require
ments for
providing continuity of electrical service
and will, therefore, be the focus of this
section.Type 1 EES requirements meet
or exceed the requirements forType 2
facilities.
Sources:Type 1 systems are required to
have a minimum of two independent
sources of electrical power—a normal
source that generally supplies the entire
facility and one or more alter
nate sources
that supply power when the normal source
is interrupted.The alternate source(s) must
be an on-site generator driven by a prime
mover unless a generator(s) exists as the
normal power source. In the case where a
generator(s) is used as the normal source,
it is permissible for the alternate source to
be a utility feed.
Alternate source generators must be
classified asType 10, Class X, Level 1
gensets per NFPA 110Tables 4.1(a) and
4.2(b) that are capable of providing power
to the load in a maximum of 10 seconds.
Typically, the alternate sources of power
are supplied to the loads through a
series of automatic and/or manual
transfer switches.
The transfer switches can be non-delayed
automatic, delayed automatic or manual
transfer depending on the requirements
of the specific branch of the EES that they
are feeding. It is permissible to feed
multiple branches or systems of the EES
from a single automatic transfer switch
provided that the maximum demand on
the EES does not exceed 150 kVA.This
configuration is typically seen in smaller
healthcare facilities that must meetType 1
EES requirements (see Figure 75).
Figure 75. Small Healthcare Facility Electrical
System—Single EES Transfer Switch
Table 46. Type 1 EES Applicable Codes
Description Standard Section
Sources NFPA 99 6.4.1
Uses NFPA 99 6.4.1.1.8
Emergency
Power Supply
Classification
NFPA 110 4.1
Distribution NFPA 99
NEC
6.4.2
517.30
General NFPA 99
NEC
6.4.2.2.1
517.25 thru 517.31
Life Safety
Branch
NFPA 99
NEC
6.4.2.2.3
517.32
Critical
Branch
NFPA 99
NEC
6.4.2.2.4
517.33
Equipment
Branch
NFPA 99
NEC
6.4.2.2.5
517.34
Wiring NFPA 99
NEC
6.4.2.2.6
517.30.(C)
Normal Source Normal Source
G
Non-Essential Loads Non-Essential Loads
Essential Electrical System
Manual Transfer Switch
Normal Source Emergency Power Supply
Life Safety
Branch
Critical
Branch
Equipment
Branch
Delayed Automatic Transfer Switch
Automatic (Non-Delaying)
Transfer Switch
Normal Source
G
Non-Essential
Loads
Alternate
Source
Entire Essential
Electric System
(150 kVA or Less)
101

Essential Electrical System Branches:
TheType 1 EES consists of three separate
branches capable of supply
ing power
considered essential for life safety and
effective facility operation during an
interruption of the normal power source.
They are the life safety branch, critical
branch and equipment branch.
A. Life Safety Branch—supplies
power for lighting, receptacles
and equipment to perform the
following functions:
1. Illumination of means of egress.
2. Exit signs and exit direction signs.
3. Alarms and alerting systems.
4. Emergency communications
systems.
5. Task illumination, battery chargers
for battery powered lighting, and
select receptacles at the generator.
6. Elevator lighting control,
communication and signal
systems.
7. Automatic doors used for egress.
These are the only functions permitted
to be on the life safety branch. Life
safety branch equip
ment and wiring
must be entirely independent of all
other loads and branches of service.
This includes separation of raceways,
boxes or cabinets. Power must be
supplied to the life safety branch
from a non-delayed automatic
transfer switch.
B. Critical Branch—supplies power for
task illumination, fixed equipment,
selected receptacles and selected
power circuits for areas related to
patient care.The purpose of the critical
branch is to provide power to a limited
number of receptacles and locations
to reduce load and minimize the
chances of fault conditions.
The transfer switch(es) feeding the
critical branch must be automatic
type.They are permitted to have
appropriate time delays that will
follow the restoration of the life safety
branch, but should have power
restored within 10 seconds of normal
source power loss.
The critical branch provides power to
circuits serving the following areas
and functions:
1. Critical care areas.
2. Isolated power systems in
special environments.
3. Task illumination and selected
receptacles in the following patient
care areas: infant nurseries,
medication prep areas, pharmacy,
selected acute nursing areas,
psychiatric bed areas, ward
treatment rooms, nurses’ stations.
4. Specialized patient care task
illumination, where needed.
5. Nurse call systems.
6. Blood, bone and tissue banks.
7. Telephone equipment rooms
and closets.
8. Task illumination, selected
receptacles and selected power
circuits for the following: general
care beds (at least one duplex
receptacle), angiographic labs,
cardiac catheterization labs,
coronary care units, hemodialysis
rooms, selected emergency room
treatment areas, human
physiology labs, intensive care
units, selected postoperative
recovery rooms.
9. Additional circuits and single-
phase fraction motors as needed f
or effective facility operation.
C. Equipment Branch—consists of major
electrical equipment necessary for
patient care andType 1 operation.
The equipment branch of the EES that
consists of large electrical equipment
loads needed for patient care and
basic healthcare facility operation.
Loads on the equipment system that
are essential to generator operation
are required to be fed by a non-
delayed automatic transfer switch.
The following equipment must be
arranged for delayed automatic
transfer to the emergency power
supply:
1. Central suction systems for medical
and surgical functions.
2. Sump pumps and other equipment
required for the safe operation of a
major apparatus.
3. Compressed air systems for
medical and surgical functions.
4. Smoke control and stair
pressurization systems.
5. Kitchen hood supply and exhaust
systems, if required to operate
during a fire.
The following equipment must be
arranged for delayed automatic or manual
transfer to the emergency power supply:
1. Select heating equipment.
2. Select elevators.
3. Supply, return and exhaust ventilating
systems for surgical, obstetrical,
intensive care, coronary care, nurseries
and emergency treatment areas.
4. Supply, return and exhaust ventilating
systems for airborne infectious/
isolation rooms, labs and medical
areas where hazardous materials
are used.
5. Hyperbaric facilities.
6. Hypobaric facilities.
7. Autoclaving equipment.
8. Controls for equipment listed above.
9. Other selected equipment in kitchens,
laundries, radiology rooms and
central refrigeration as selected.
Any loads served by the generator that
are not approved as outlined above as
part of the essential electrical system
must be connected through a separate
transfer switch.These transfer switches
must be configured such that the loads
will not cause the generator to overload
and must be shed in the event the
generator enters an overload condition.
Ground fault protection—per NFPA 70
NEC Article 230.95, ground fault
protection is required on any feeder or
service disconnect 1000 A or larger on
systems with line to ground voltages
of 150V or greater and phase-to-phase
voltages of 600V or less. For healthcare
facilities (of any type), a second level of
ground fault protection is required to be
on the next level of feeder downstream.
This second level of ground fault is only
required for feeders that serve patient care
areas and equipment intended to support
life. 100% selective coordination of the two
levels of ground fault protection must be
achieved with a minimum six-cycle
separation between the upstream and
downstream device.
As of the 2011 NEC, ground fault
protection is allowed between the
generator(s) and the EES transfer
switch(es). However, NEC 517.17(B)
prohibits the installation of ground
fault protection on the load side of a
transfer switch feeding EES circuits
(see Figure 76—additional level of ground
fault).

Figure 76. Additional Level of Ground Fault Protection
a Ground fault protection is required for service disconnects 1000 A and larger or systems with less than 600V phase-to-phase and greater than 150V to ground
per NEC 230.95.
Careful consideration should be used in
applying ground fault protection on the
essential electrical system to prevent a
ground fault that causes a trip of the
normal source to also cause a trip on the
emergency source. Such an event could
result in complete power loss of both
normal and emergency power sources
and could not be recovered until the
source of the ground fault was located
and isolated from the system.To prevent
this condition, NEC 700.27 removes the
ground fault protection requirement for
the emergency system source.Typically,
the emergency system generator(s) are
equipped with ground fault alarms that
do not automatically disconnect power
during a ground fault.
Table 47. Ground Fault Protection
Applicable Codes
Services
Branch-Circuits
Feeders
NEC
NEC (see Article
100 Definition
for Applicability)
NEC
230.95
210.13
215.10
Additional Level NFPA 99
NEC
6.3.2.5
517.17
Alternate Source NEC
NEC
700.27
701.26
Wet procedure locations—A wet
procedure location in a healthcare facility
is any patient care area that is normally
subject to wet conditions while patients
are present. By default, operating rooms
are considered wet procedure locations
unless a risk assessment is performed to
show otherwise. Other examples of wet
procedure locations might include
anesthetizing locations, dialysis locations,
etc. (patient beds, toilets and sinks are not
considered wet locations).These wet
procedure locations require special
protection to guard against electric shock.
The ground fault current in these areas
must be limited to not exceed 5 mA.
Protection to patient and staff in wet
procedure locations can be provided
through the use of GFCI outlets, GFCI
breakers or isolated power systems. If
GFCI protection is utilized, each circuit
must have a dedicated GFCI outlet or
GFCI breaker. It is not permissible to use
a single GFCI device to protect multiple
outlets.This limits interruption resulting
from a ground fault to a single outlet.
Isolated power systems provide power
to an area that is isolated from ground
(or ungrounded).This type of system
limits the amount of current that flows
to ground in the event of a single
line-to-ground fault and maintains
circuit continuity.
Electronic line isolation monitors (LIM)
are used to monitor and display leakage
currents to ground.When leakage current
thresholds are exceeded, visible and/or
audible alarms are initiated to alert
occupants of a possible hazardous
condition.This alarm occurs without
interrupting power to allow for the safe
conclusion of critical procedures.
Table 48. Wet Procedure Location
Applicable Codes
General NFPA 99
NEC
6.3.2.2.8
517.20
GFCI Protection NFPA 99 6.3.2.2.8.8
Isolated Power
Systems
NFPA 99
NE
6.3.2.2.9, 6.3.2.6
517.160
Normal Source Normal Source(s)
G
480/277 V
Service
Entrance
1000 A
or Larger
GF
Service
Entrance
1000 A
or Larger
GF
480/277 V
GF
GF
GF GF
GF
GF
GF
GF
GF GF
GF
Service
Entrance
1000 A
or Larger
GF
480/277 V
GF
Non-Essential Loads Non-Essential Loads
Essential Electrical System
Additional Level
of Ground Fault
Protection
Ground Fault
is Permitted
Between Generator
and EES Transfer
Switches.
(NEC 517.17 (B))
Additional Level of Ground Fault is
not Permitted on Load Side of EES
Transfer Switches. (NEC 517.17(B)
= Ground Fault Protection Required
Generator Breakers are
Typically Supplied with
Ground Fault Alarm
Only. (NEC 700.27)

103

Maintenance andTesting
Regular maintenance and testing of
the electrical distribution system in a
healthcare facility is necessary to ensure
proper operation in an emergency and,
in some cases, to maintain government
accreditation. Any healthcare facility
receiving Medicare or Medicaid reim-
bursement from the government must
be accredited byThe Joint Commission.
The Joint Commission has established a
group of standards called the Environment
of Care, which must be met for healthcare
facility accredita
tion. Included in these
standards is the regular testing of the
emergency (alternate) power system(s).
Diesel-powered EPS installations must be
tested monthly in accordance with NFPA
110 Standard for Emergency and Standby
Power Systems. Generators must be
tested for a minimum of 30 minutes under
the criteria defined in NFPA 110.
Routine maintenance should be
performed on circuit breakers, transfer
switches, switchgear, generator equip
ment, etc. by trained professionals to
ensure the most reliable electrical system
possible. Eaton’s Electrical Services
Systems (EESS) provides engineers
trained in development and execution
of annual preventative maintenance
procedures of healthcare facility
electrical distribution systems.
Table 49. Maintenance and Testing Applicable
Codes
Grounding NFPA 99 6.3.3.1
Essential
Electrical
System
NFPA 99
Joint Commission
Environment of Care
6.4.4.1
EC.2.1.4(d)
Generator NFPA 110 8.4
Transfer
Switches
NFPA 110 8.3.5, 8.4.6
Breakers NFPA 99
NFPA 110
6.4.4.1.2.1
8.4.7
Paralleling Emergency Generators
Without Utility Paralleling
In many healthcare facilities (and other
large facilities with critical loads), the
demand for standby emergency power
is large enough to require multiple
generator sets to power all of the required
essential electrical system (EES) loads.
In these cases, it becomes more flexible
and easier to operate the required
multiple generators from a single location
using generator paral
leling switchgear.
Figure 77 shows an example of a typical
one-line for a paralleling switchgear
lineup feeding the EES.
A typical abbreviated sequence of
operation for a multiple emergency
generator and ATS system follows.
Note that other modes of operation such
as generator demand priority and
automated testing modes are available
but are not included below.
Figure 77. Typical One-Line for a Paralleling Switchgear Lineup Feeding the Essential Electrical System (EES)
Utility
Metering
Utility
Transformer
Service Main
Normal Bus
Optional
Electrically
Operated
Stored
Energy
Breakers
Non-Essential
Loads
EP1 EP2 EPX
Fx
F2
F1
EFx
EF2
EF1
Generators X = Number of Units
Typical
Generator
Breaker
Emergency Bus
Equipment
ATS # 1
Life Safety
ATS # 2
Critical
ATS # X
Typical
Panelboards
Gx
G2
G1
Optional Electrically
Operated Stored
Energy Breakers
Load Shed/Load
Add ATS Units
Optional Closed
Transition
Paralleling of
Generators and
Utility

1. Entering emergency mode
a. Upon loss of normal source,
automatic transfer switches
send generator control system
a run request.
b. All available generators are
started.The first generator up to
voltage and frequency is closed
to the bus.
c. Unsheddable loads and load shed
Priority 1 loads are pow
ered in less
than 10 seconds.
d. The remaining generators are
synchronized and paralleled to the
bus as they come up to voltage
and frequency.
e. As additional generators are
paralleled to the emergency bus,
load shed priority levels are added,
powering their associated loads.
f. The system is now in emergency
mode.
2. Exit from emergency mode
a. Automatic transfer switches sense
the utility source is within
acceptable operational toler
ances
for a time duration set at the
automatic transfer switch.
b. As each automatic transfer switch
transfers back to utility power, it
removes its run request from the
generator plant.
c. When the last automatic trans
fer
switch has retransferred to the
utility and all run requests have
been removed from the generator
plant, all generator circuit breakers
are opened.
d. The generators are allowed
to run for their programmed
cool-down period.
e. The system is now back in
automatic/standby mode.
With Utility Paralleling
Today, many utilities are offering their
customers excellent financial incen
tives
to use their on-site generation capacity to
remove load from the utility grid.These
incentives are sometimes referred to as
limited interruptible rates (LIP). Under
these incentives, utilities will greatly
reduce or eliminate kWhr or kW demand
charges to their customers with on-site
generation capabilities. In exchange,
during times of peak loading of the utility
grid, the utility can ask their LIP rate
customers to drop load from the grid by
using their on-site generation capabilities.
Healthcare facilities are ideally suited
to take advantage of these programs
because they already have significant
on-site generation capabilities due to
the code requirements described. Many
healthcare facilities are taking advantage
of these utility incentives by adding
generator capacity over and above the
NFPA requirements. Figure 78 shows an
example one-line of a healthcare facility
with complete generator backup and
utility interconnect.
NFPA 110 requirements state that the
normal and emergency sources must be
separated by a fire-rated wall.
The intent of this requirement is so that a
fire in one location cannot take out both
sources of power.To meet this require-
ment, the paralleling switchgear must be
split into separate sections with a tie bus
through a fire-rated wall.
Figure 78. Typical One-Line Healthcare Facility with Complete Generator Backup and Utility Interconnect
Utility
Transformer
Utility
Metering
Generators X = Number of Units
Typical
Generator
Breaker
Gx
G2
G1
Emergency Bus
Electrically Operated
Stored Energy
Breakers
EFx
EF2
EF1
Service Main
Normal Bus
Optional
Electrically
Operated
Stored
Energy
Breakers
Fx
F2
F1
Non-Essential
Loads
Equipment
ATS # 1
Life Safety
ATS # 2
Critical
ATS # X
Load Shed/
Load Add
ATS Units
Typical
Panelboards
EP1 EP2 EPX
Utility
Protective
Relay
TIE Optional TIE
Fire-Rated Wall
or Separation Barrier
Field Installed
Cable or Busway
Closed
Transition
Paralleling of
Generators and
Utility, Plus
Soft Loading/
Unloading
105

Quick Connect Generator and
Load Bank Capabilities
Quick-Connect Double-Throw
Many facilities are increasing their
resiliency by including quick connect
capabilities for temporary roll-up
generators. Quick-connect sections can
be added to generator switchboards to
allow for the use of temporary roll-up
generators when permanent genera
tors
are out-of-service for maintenance and
repair.The same quick-connect device can
also be used for convenient connection
of a load bank for periodic testing of the
permanent generators.
Another common application for
generator quick-connect structures is
on the normal service. Having a quick-
connect infrastructure in place provides
the ability to restore some or all normal
system loads such as HVAC, chillers, etc.
that can become crucial if there were a
long-term utility outage.The flexibility to
quickly and safely connect a temporary
generator to these normal system loads
can help resume more normal facility
opera
tion during an extended utility
outage. See Eaton’s website for additional
information on quick-connect switch
boards up to 4000 A and for quick-connect
safety switches up to 800 A.
Typical (1200A) Generator Quick Connect Switchboard
Cam-Type Receptacle Sub-Assembly

Power Quality Terms
Technical Overview
Introduction
Sensitive electronic loads deployed today
by users require strict require
ments for
the quality of power delivered to loads.
For electronic equipment, power
disturbances are defined in terms of
amplitude and duration by the elec
tronic
equipment operating envelope. Electronic
loads may be damaged and disrupted,
with shortened life
expectancy, by
these disturbances.
The proliferation of computers, variable
frequency motor drives, UPS systems
and other electronically controlled
equipment is placing a greater demand
on power producers for a disturbance-
free source of power. Not only do these
types of equipment require quality power
for proper operation; many times, these
types of equipment are also the sources
of power disturbances that corrupt the
quality of power in a given facility.
Power quality is defined according to IEEE
Standard 1100 (Recommended Practice
for Powering and Grounding Electronic
Equipment) as the concept of powering
and grounding electronic equipment in a
manner that is suitable to the operation
of that equipment. IEEE Standard 1159
(Recommended Practice for Monitoring
Electric Power Quality) notes that “within
the industry, alternate definitions or
interpretations of power quality have
been used, reflecting different points
of view.
”
In addressing power quality problems
at an existing site, or in the design stages
of a new building, engineers need to
specify different services or mitigating
technologies.The lowest cost and highest
value solution is to selectively apply a
combination of different products and
services as follows:
■ Power quality surveys, analysis
and studies
■ Power monitoring
■ Grounding products and services
■ Surge protection
■ Voltage regulation
■ Harmonic solutions
■ Lightning protection (ground rods,
hardware, etc.)
■ Uninterruptible power supply (UPS)
or motor-generator (M-G) set
Defining the Problem
Power quality problems can be resolved in
three ways: by reducing the variations in
the power supply (power disturbances), by
improving the load equipment’s tolerance
to those variations, or by inserting some
interface equipment (known as power
conditioning equipment) between the
electrical supply and the sensitive load(s)
to improve the compatibility of the two.
Practicality and cost usually determine the
extent to which each option is used.
Many methods are used to define power
quality problems. For example, one
option is a thorough on-site investigation,
which includes inspecting wiring and
grounding for errors, monitoring the
power supply for power disturbances,
investigating equipment sensitivity to
power disturbances, and determining
the load disruption and consequential
effects (costs), if any. In this way, the
power quality problem can be defined,
alternative solutions developed, and
optimal solution chosen.
Before applying power-conditioning
equipment to solve power quality
problems, the site should be checked
for wiring and grounding problems.
Often, correcting a relatively inexpen
sive
wiring error, such as a loose connection
or a reversed neutral and ground wire,
can avoid a more expensive power
conditioning solution.
Sometimes the investigative approach is
not viable, as the exact sensitivities of the
load equipment may be unknown and
difficult to determine. In other cases,
monitoring for power anomolies may
be needed over an extended period of
time to capture infrequent disturbances.
This added time and expense can be
impractical in smaller installations.
It is important to remember that while
the thorough on-site investigation can
identify and help solve observed
problems on existing installations, for
a power systems engineer designing a
new facility, there is no site or equip
ment
to investigate. Consequently, as in the
prior instances cited, it is often practical
to implement power quality solutions to
address common issues as a preemptive
measure. Using well-accepted practices,
such as tiered levels of surge protection
or UPS systems, an engineer can avoid
or alleviate the potential problems that
poor power quality can cause on a
power system.
Power QualityTerms
Power disturbance: Any deviation from
the nominal value (or from some selected
thresholds based on load tolerance) of the
input ac power characteristics.
Total harmonic distortion or distortion
factor:The ratio of the root-mean-square
of the harmonic content to the root-
mean-square of the fundamental
quantity, expressed as a percentage
of the fundamental.
Crest factor: Ratio between the peak
value (crest) and rms value of a periodic
waveform.
Apparent (total) power factor:The ratio of
the total power input in watts to the total
volt-ampere input.
Sag: An rms reduction in the ac voltage,
at the power frequency, for the duration
from a half-cycle to a few seconds. An
undervoltage would have a duration
greater than several seconds.
Interruption: The complete loss of voltage
for a time period.
Transient: A sub-cycle disturbance in
the ac waveform that is evidenced by a
sharp brief discontinuity of the waveform.
May be of either polarity and may be
additive to or subtractive from the
nominal waveform.
Surge or impulse: See transient.
Noise: Unwanted electrical signals that
produce undesirable effects in the circuits
of control systems in which they occur.
Common-mode noise:The noise
voltage that appears equally and in
phase from each current-carrying
conductor to ground.
Normal-mode noise: Noise signals
measurable between or among active
circuit conductors feeding the subject
load, but not between the equipment
grounding conductor or associated
signal reference structure and the
active circuit conductors.
Power Quality
107

Methodology for Ensuring Effective
Power Quality to Electronic Loads
The power quality pyramid is an
effective guide for addressing power
quality problems at an existing facility.
The framework is also useful for
specifying engineers who are
designing a new facility.
Power quality starts with grounding
(the base of the pyramid) and then moves
upward to address the potential issues.
This simple, yet proven methodology, will
provide the most cost-effective approach.
As we move higher up the pyramid, the
cost per kVA of mitigating potential
problems increase and the quality of the
power increases (refer to Figure 79).
Figure 79. Power Quality Pyramid
1. Grounding
Grounding represents the foundation
of a reliable power distribution system.
Grounding and wiring problems can be
the cause of up to 80% of all power quality
problems. All other forms of power
quality solutions are dependent upon
good grounding procedures.
The proliferation of communication and
computer network systems has increased
the need for proper grounding and wiring
of ac and data/communication lines. In
addition to reviewing ac grounding and
bonding practices, it is necessary to
prevent ground loops from affecting
the signal reference point.
2. Surge Protection
Surge protection devices (SPDs) are
recommended as the next stage power
quality solutions. NFPA, UL 96A,
IEEE Emerald Book and equipment
manufacturers recommend the use of
surge protectors.The SPDs are used to
shunt short duration voltage disturbances
to ground, thereby preventing the surge
from affecting electronic loads.When
installed as part of the facility-wide
design, SPDs are cost-effective compared
to all other solutions (on a $/kVA basis).
The IEEE Emerald Book recommends the
use of a two-stage protection concept.
For large surge currents, diversion is best
accomplished in two stages: the first
diversion should be performed at the
service entrance to the building.Then, any
residual voltage resulting from the action
can be dealt with by a second protective
device at the power panel of the computer
room (or other critical loads).
The benefit of implementing cascaded
network protection is shown in
Figure 80. Combined, the two
stages of protection at the service
entrance and branch panel locations
reduce the IEEE 62.41 recommended
test wave (C3–20 kV, 10 kA) to less than
200V voltage, a harmless disturbance
level for 120V rated sensitive loads.
If surge protection is only provided for the
building entrance feeder, the let-through
voltage will be approximately 950V in a
277/480V system exposed to induced
lightning surges.This level of let-through
voltage can cause degradation or physical
damage of most electronic loads.
Wherever possible, consultants,
specifiers and application engineers
should ensure similar loads are fed from
the same source. In this way, disturbance-
generating loads are separated from
electronic circuits affected by power
disturbances. For example, motor loads,
HVAC systems and other linear loads
should be separated from the sensitive
process control and computer systems.
The most effective and economic solution
for protecting a large number of loads
is to install parallel style SPDs at the
building service entrance feeder and
panelboard locations.These SPDs are
either placed in parallel with the loads
directly on the equipment bus bars or
externally by means of a short cable.
This reduces the cost of protection for
multiple sensitive loads.
Figure 80. Cascaded System Protection
5. Uninterruptible Power Supply
(UPS, Gen. Sets, etc.)
4. Harmonic Distortion
3. Voltage Regulation
2. Surge Protection
1. Grounding
Cost
Per
kVA
Input—high energy
transient disturbance; IEEE Category
C3 Impulse 20,000V; 10,000A
Two stage (cascade
approach) achieves best
possible protection (less
than 200V at Stage 2)
Best achievable
performance with single SPD
at main panel (950V, at Stage 1)
25 uS 50 uS
TIME (MICROSECONDS)
20,000V
800V
400V
0
CP
SPD
SPD
480V 120/208V
Stage 1 Protection
(Service Entrance) Stage 2 Protection
(Branch Location)
Computer or
Sensitive
Loads
SystemTest Parameters:
IEEE C62.41[10] and C62.45 [10]
test procedures using category;
480V main entrance panels;
100 ft (30m) of three-phase wire;
480/208V distribution transformer;
and 208V branch panel.
= SPD
PEAK
VOLTAGE
Power Quality

The recommended system approach
for installing SPDs is summarized in
Figure 81.
Figure 81. System Approach for
Installing SPDs
There may be specific single-phase critical
loads within a facility that require a higher
level of protection. In these instances,
a series style SPD is best suited for
protecting such loads. Application of
the series style SPD involves wiring it
in series with the load it is feeding.
Advantages of the system approach are:
■ The lowest possible investment
in mitigating equipment to protect
a facility
■ Building entrance SPDs protect
the facility against large external
transients, including lightning
■ SPDs are bi-directional and prevent
transient and noise disturbances
from feeding back within a system
when installed at distribution or
branch panels
■ Two levels of protection safeguard
sensitive loads from physical damage
or operational upset
Side-Mounted SPD vs. Integral SPD
Directly connecting the surge suppresser
to the bus bar of electrical distribution
equipment results in the best possible
level of protection. Compared to side-
mounted devices, connecting the SPD
unit to the bus bar eliminates the need
for lead wires and reduces the let-through
voltage up to 50% (see Figure 82).
Given that surges are high frequency
disturbances, the inductance of the
installation wiring increases the let-
through voltage of the protective device.
Figure 83 shows that for every inch
of lead length, the let-through voltage
is increased by an additional 15–25V
above the manufacturers stated
suppression performance.
Lead length has the greatest effect on the
actual level of protection realized.Twisting
of the installation wires is the second most
important installation consideration.
By twisting the installation wires, the area
between wires is reduced and the mutual
inductance affect minimized.
Increasing the diameter of the installation
wires is of negligible benefit. Inductance
is a “skin effect” phenomenon and a
function of wire circumference. Because
only a marginal reduction in inductance
is achieved when the diameter of the
installation conductors is increased, the
use of large diameter wire results in only
minimal improvement (see Figure 83).
Further benefits provided by integrated
surge suppression designs are the
elimination of field installation costs
and the amount of expensive “outboard”
wall space taken up by side-mounted
SPD devices.
Building Entrance Feeder
Installation Considerations
Installing an SPD device immediately
after the switchgear or switchboard main
breaker is the optimal location for
protecting against external distur
bances
such as lightning.When placed in this
location, the disturbance is “intercepted”
by the SPD and reduced to a minimum
before reaching the distribution and/or
branch panel(s).
The use of a disconnect breaker
eliminates the need to de-energize the
building entrance feeder equip
ment
should the SPD fail or require isolation
for Megger testing.
Figure 82. Performance Comparison of Side-Mounted vs. Integrated SPD
1.
Identify Critical Loads
2.
Identify Non-Critical Loads
3.
Identify Noise and
Disturbance Generating Loads
4.
Review Internal Power Distribution Layout
5.
Identify Facility Exposure to
Expected Levels of Disturbance
6.
Apply Mitigating Equipment to:
a) Service Entrance Main Panels
b) Key Sub-Panels
c) Critical Loads
d) Data and Communication Lines

G R O U N D
G
N
G R O U N D
G
N
SPD
208Y/120 Panelboard
(integrated versus side mounted SPD)
Side-Mounted SPD Device
(assuming 14-inch (355.6 mm) lead length to bus)
Integrated SPD
(direct bus bar connection)
Surge
Event
Microseconds
SPD
Side-Mounted SPD
used for Retrofit
Applications
SPD Integrated
into Panelboards,
Switchboards, MCCs
1000
800
600
400
200
0
–200
–2.00 0.00 2.00 4.00 6.00 8.00 10.00
Let-Through
Voltage
at
Bus
Bar
109
Power Quality

Figure 83. The Effect of Installation Lead Length on Let-Through Voltage
a Additional to UL 1449 ratings.
The size or capacity of a suppressor is
measured in surge current per phase.
Larger suppressers rated at approxi
mately
250 kA per phase should be installed at the
service entrance to survive high-energy
surges associated with lightning.
A 250 kA per phase surge rating allows for
over a 25-year life expectancy assuming
an IEEE defined high exposure environ
ment. Lower surge rating devices may
be used; however, device reliability
and long-term performance may be
compromised.
For aerial structures, the 99.8 percentile
recorded lightning stroke current is less
than 220 kA.The magnitude of surges
conducted or induced into a facility
electrical distribution system is consider
ably lower given the presence of multiple
paths for the surge to travel along. It is
for this reason that IEEE C62.41
recommends the C3 (20 kV, 10 kA) test
wave for testing SPDs installed at
building entrance feeders.
SPDs with surge ratings greater than
250 kA are not required, however, higher
ratings are available and may provide
longer life.
Installing Panelboard Surge
Protection Devices
Smaller surge capacity SPDs (120 kA per
phase) are installed at branch panel
boards where power disturbances are
of lower energy, but occur much more
frequently.This level of surge current
rating should result in a greater than
25-year life expectancy.
When isolated ground systems are used,
the SPD should be installed such that any
common mode surges are shunted to the
safety ground.
The use of a disconnect breaker is
optional.The additional let-through
voltage resulting from the increased
inductance caused by the disconnect
switch is about 50–60V.
This increase in disturbance voltage can
result in process disruption and downtime.
Installing Dataline Surge Protection
Most facilities also have communica
tion
lines that are potential sources for
external surges. As identified by the
power quality pyramid, proper grounding
of communication lines is essential for
dependable operation. NEC Article 800
states that all data, power and cable lines
be grounded and bonded.
Power disturbances such as lightning can
elevate the ground potential between
two communicating pieces of electronic
equipment with different ground
references.The result is current flowing
through the data cable, causing
component failure, terminal lock-up,
data corruption and interference.
NFPA 780 D—4.8 warns that “surge
suppression devices should be installed
on all wiring entering or leaving elec
tronic equipment, usually power, data
or communication wiring.
”
Surge suppressers should be installed at
both ends of a data or communica
tion
cable. In those situations where one end
of the cable is not connected into an
electronic circuit (e.g., contactor coil),
protection on the electronic end only
is required.
To prevent the coupling or inducing of
power disturbances into communication
lines, the following should be avoided:
■ Data cables should not be run over
fluorescent lighting fixtures
■ Data cables should not be in the vicinity
of electric motors
■ The right category cable should be used
to ensure transmission performance
■ Data cables must be grounded at both
ends when communicating between
buildings
3. Voltage Regulation
Voltage regulation (i.e., sags or over
voltage) disturbances are generally site-
or load-dependent. A variety of mitigating
solutions are available depending upon
the load sensitivity, fault duration/
magnitude and the specific problems
encountered. It is recommended to install
monitoring equipment on the ac power
lines to assess the degree and frequency
of occurrences of voltage regulation
problems.The captured data will allow
for the proper solution selection.
4. Harmonics Distortion
Harmonics and Nonlinear Loads
In the past, most loads were primarily
linear in nature. Linear loads draw the
full sine wave of electric current at its
60 cycle (Hz) fundamental frequency—
Figure 84 shows balance single-phase,
linear loads. As the figure shows, little or
no current flows in the neutral conductor
when the loads are linear and balanced.
The advent of nonlinear electronic loads,
where the ac voltage is converted to a
dc voltage, altered the way power was
traditionally drawn from a normal ac sine
wave. During the ac to dc conversion,
power electronic devices are switched on
during a fraction of each 1/2 cycle causing
voltage and current to be drawn in pulses
to obtain the required dc output.This
deviation of voltage and current from the
normal sine wave results in harmonics.
It is important to note that the current
distortion caused by loads such as
rectifiers or switch mode power supplies
causes the voltage distortion.That voltage
distortion is caused by distorted currents
flowing through an impedance.The
amount of voltage distortion depends on:
■ System impedance
■ Amount of distorted current
Devices that can cause harmonic
disturbances include rectifiers,
thrusters and switching power supplies,
all of which are nonlinear. Further, the
proliferation of electronic equipment
such as computers, UPS systems,
variable speed drives, programmable
logic controllers, and the like: nonlinear
loads have become a significant part of
many installations.
14 AWG
10 AWG
4 AWG
0
100
200
300
400
500
600
700
800
900
209V (23%)
673V (75%)
Additional
Let-Through
Voltage
¿
Loose Wiring Twisted Wires
3 ft (914.4 mm)
Lead Length
1 ft (304.8 mm)
Lead Length,
Twisted Wires
Additional Let-Through Voltage Using IEEE C1(6000V, 3000A)[3]
Waveform (UL 1449 Test Wave)[12]
Power Quality

Other types of harmonic-producing
loads include arcing devices (such as
arc furnaces, welders and fluorescent
lighting).
Nonlinear load currents vary widely from
a sinusoidal wave shape; often they are
discontinuous pulses.This means that
nonlinear loads are extremely high in
harmonic content.
Triplen harmonics are the 3rd, 9th, 15th,...
harmonics. Further, triplen harmonics
are the most damaging to an electrical
system because these harmonics on the
A-phase, B-phase and C-phase are in
sequence with each other. Meaning, the
triplen harmonics present on the three
phases add together in the neutral, as
shown in Figure 85, rather than cancel
each other out, as shown in Figure 84.
Odd non-triplen harmonics are classified
as “positive sequence” or “negative
sequence” and are the 1st, 5th, 7th, 11th,
13th, etc.
In general, as the order of a harmonic
gets higher, its amplitude becomes
smaller as a percentage of the
fundamental frequency.
Figure 84. Balanced Neutral Current Equals Zero
Figure 85. Single-Phase Loads with Triplen Harmonics
Harmonic Issues
Harmonic currents may cause system
losses that over burden the distribution
system.This electrical overloading may
contribute to preventing an existing
electrical distribution system from
serving additional future loads.
In general, harmonics present on a
distribution system can have the
following detrimental effects:
1. Overheating of transformers and
rotating equipment.
2. Increased hysteresis losses.
3. Decreased kVA capacity.
4. Overloading of neutral.
5. Unacceptable neutral-to-ground
voltages.
6. Distorted voltage and current
waveforms.
7. Failed capacitor banks.
8. Breakers and fuses tripping.
9. Double sized neutrals to defy the
negative effects of triplen harmonics.
In transformers, generators and
uninterruptible power supplies (UPS)
systems, harmonics cause overheating
and failure at loads below their ratings
because the harmonic currents cause
greater heating than standard 60 Hz
current.This results from increased eddy
current losses, hysteresis losses in the
iron cores, and conductor skin effects of
the windings. In addition, the harmonic
currents acting on the impedance of the
source cause harmonics in the source
voltage, which is then applied to other
loads such as motors, causing them
to overheat.
The harmonics also complicate the
application of capacitors for power
factor correction. If, at a given harmonic
frequency, the capacitive impedance
equals the system reactive impedance,
the harmonic voltage and current can
reach dangerous magnitudes. At the
same time, the harmonics create
problems in the application of power
factor correction capacitors, they lower
the actual power factor.The rotating
meters used by the utilities for watthour
and various measurements do not detect
the distortion component caused by the
harmonics. Rectifiers with diode front
ends and large dc side capacitor banks
have displacement power factor of 90%
to 95%. More recent electronic meters are
capable of metering the true kVA hours
taken by the circuit.
A Phase
B Phase
C Phase
60 Hz Fundamental
Balance
Neutral
Current
120º
Lagging
120º
Lagging
A Phase
B Phase
C Phase
60 Hz Fundamental
Neutral
Triplen
Current
120º
Lagging
120º
Lagging
3rd Harmonic
PhaseTriplen Harmonics
Added in the Neutral

111
Power Quality

Single-phase power supplies for
computer and fixture ballasts are rich in
third harmonics and their odd multiples.
Even with the phase currents perfectly
balanced, the harmonic currents in the
neutral can total 173% of the phase
current.This has resulted in overheated
neutrals.The InformationTechnology
Industry Council (ITIC) formerly known
as CBEMA, recom
mends that neutrals in
the supply to electronic equipment be
oversized to at least 173% of the ampacity
of the phase conductors to prevent
problems. ITIC also recommends derating
transformers, loading them to no more
than 50% to 70% of their nameplate kVA,
based on a rule-of-thumb calculation, to
compensate for harmonic heating effects.
In spite of all the concerns they cause,
nonlinear loads will continue to increase.
Therefore, the systems that supply them
will have to be designed so that their
adverse effects are greatly reduced.
Table 50 shows the typical harmonic
orders from a variety of harmonic
generating sources.
Table 50. Source and Typical Harmonics
Source Typical
Harmonics a
6-pulse rectifier
12-pulse rectifier
18-pulse rectifier
5, 7, 11, 13, 17, 19…
11, 13, 23, 25…
17, 19, 35, 37…
Switch-mode power supply
Fluorescent lights
Arcing devices
Transformer energization
3, 5, 7, 9, 11, 13…
3, 5, 7, 9, 11, 13…
2, 3, 4, 5, 7…
2, 3, 4
a Generally, magnitude decreases as harmonic
order increases.
Total Harmonic Distortion
Revised standard IEEE 519-2014 indicates
the limits of current distortion allowed
at the PCC (Point of Common Coupling)
point on the system where the current
distortion is calculated.The 2014 revision
is more focused on harmonic limits on the
system over time. It now clearly indicates
that the PCC is the point of connection to
the utility.
The standard now primarily addresses
the harmonic limits of the supply volt
age
from the utility or cogenerators.
Table51.Low-VoltageSystemClassification and
Distortion Limits for 480 V Systems
Class C AN DF
Special application b
General system
Dedicated system
10
5
2
16,400
22,800
36,500
3%
5%
10%
b Special systems are those where the rate of
change of voltage of the notch might mistrigger
an event. AN
is a measurement of notch
characteristics measured in volt-microseconds,
C is the impedance ratio of total impedance to
impedance at common point in system. DF is
distortion factor.
Table 52. Utility or Cogenerator Supply Voltage
Harmonic Limits
Voltage
Range
2.3–69 kV 69–138 kV 138 kV
Maximum
individual
harmonic
3.0% 1.5% 1.0%
Total
harmonic
distortion
5.0% 2.5% 1.5%
Percentages are x 100 for each
harmonic
and
It is important for the system designer to
know the harmonic content of the utility’s
supply voltage because it will affect the
harmonic distortion of the system.
Table 53. Current Distortion Limits for
General Distribution Systems (120– 69,000 V)
Maximum Harmonic Current Distortion
in Percent of IL
Individual Harmonic Order (Odd Harmonics)
ISC
/IL
11 11
h
17
17
h23
23
h35
35
h
TDD
20 c
2050
50100
1001000
1000
4.0
7.0
10.0
12.0
15.0
2.0
3.5
4.5
5.5
7.0
1.5
2.5
4.0
5.0
6.0
0.6
1.0
1.5
2.0
2.5
0.3
0.5
0.7
1.0
1.4
5.0
8.0
12.0
15.0
20.0
c All power generation equipment is limited to
these values of current distortion, regardless
of actual ISC
/IL
where:
ISC
= Maximum short-circuit current at PCC.
IL
= Maximum demand load current
(fundamental frequency component) at PCC.
TDD =Total Demand Distortion. Even harmonics
are limited to 25% of the odd harmonic limits
above. Current distortions that result in a
dc offset, e.g., half-wave converters, are
not allowed.
When evaluating current distortion, it is
important to understand the difference
betweenTHD (Total Harmonic Distortion)
andTDD (Total Demand Distortion).THD
is the measured distortion on the actual
magnitude of current flowing at a given
instant.This could be referred to as a
“sine wave quality factor” as it is a
measure of the amount of distortion at
that given time, for that given magnitude
of current. It can be measured with a
simple harmonic current metering device.
CurrentTHD is not utilized anywhere in
the IEEE 519 standard. Instead, the IEEE
519 standard sets limits based onTDD,
orTotal Demand Distortion.TDD is a
calculated value based on the amount
of harmonic distortion related to the full
load capacity of the electrical system.The
formula for calculatingTDD is as follows:
The numerator of the formula is the
square root of the sum of the current
harmonics squared.This value is divided
by IL, which is the full load capacity of
the system. From this, you can see that
even heavily distorted currents (i.e., high
currentTHD) that are only a small fraction
of the capacity of the system will result in
a lowTDD.
Harmonic Solutions
In spite of all the concerns nonlinear
loads cause, these loads will continue to
increase.Therefore, the application of
nonlinear loads such as variable frequency
drives (VFDs) and the systems that supply
them will require further scrutiny by the
design profes
sional.The use of “Clean
Power” multi-pulseVFDs has become a
common approach so adverse harmonic
effects are greatly reduced. Table 54 and
depicts many harmonic solutions along
with their advantages and disadvantages.
Eaton’s Engineering Services Systems
Group (EESS) can perform harmonic
studies and recommend solutions for
harmonic problems.
VTHD
% = V2
+ V3
+ V4
+ V5
+ … x 100
V1
rms
( )
2 2 2 2
TDD = I2
+ I3
+ I4
+ I5
+ … x 100
IL
( )
2 2 2 2
Power Quality

Table 54. Harmonic Solutions for Given Loads
Load Type Solutions Advantages Disadvantages
Drives and rectifiers—
includes three-phase
UPS loads
Line reactors n Inexpensive
n For 6-pulse standard drive/rectifier, can reduce
harmonic current distortion from 80% down to
about 35–40%
n May require additional compensation
K-rated/drive isolation
transformer
n Offers series reactance (similar to line reactors)
and provides isolation for some transients
n No advantage over reactors for reducing
harmonics unless in pairs for shifting phases
dc choke n Slightly better than ac line reactors for 5th and
7th harmonics
n Not always an option for drives
n Less protection for input semiconductors
12-pulse convertor n 85% reduction versus standard 6-pulse drives n Cost difference approaches 18-pulse drive
and blocking filters, which guarantee
IEEE 519 compliance
Harmonic mitigating
transformers/phase shifting
n Substantial (50–80%) reduction in harmonics
when used in tandem
n Harmonic cancellation highly dependent on
load balance
n Must have even multiples of matched loads
Tuned filters n Bus connected—accommodates load diversity
n Provides PF correction
n Requires allocation analysis
n Sized only to the requirements of that system;
must be resized if system changes
Broadband filters n Makes 6-pulse into the equivalent of 18-pulse n Higher cost
n Requires one filter per drive
18-pulse converter n Excellent harmonic control for drives above 100 hp
n IEEE 519 compliant
n No issues when run from generator sources
n High cost
Active filters n Handles load/harmonic diversity
n Complete solution up to 50th harmonic
n High cost
Active front end n Excellent harmonic control
n Four quadrant (regen) capability
n High cost
n High complexity
n Can have system stability issues when run from
generator source
Computers/
switch-mode
power supplies
Neutral blocking filter n Eliminates the 3rd harmonic from load
n Relieves system capacity
n Possible energy savings
n High cost
n May increase voltage distortion
Harmonic mitigating
transformers
n 3rd harmonic recalculated back to the load
n When used as phase-shifted transformers, reduces
other harmonics
n Reduces voltage“flat-topping”
n Requires fully rated circuits and oversized
neutrals to the loads
Oversized neutral/derated
transformer
n Tolerate harmonics rather than correct
n Typically least expensive
n Upstream and downstream equipment
fully rated for harmonics
K-rated transformer n Tolerate harmonics rather than correct n Does not reduce system harmonics
Fluorescent
lighting
Harmonic mitigating
transformers
n 3rd harmonic recalculated back to the load
n When used as phase-shifted transformers, reduces
other harmonics
n Reduces voltage“flat-topping”
n Requires fully rated circuits and
oversized neutrals to the loads
K-rated transformer n Tolerate harmonics rather than correct them n Does not reduce system harmonics
Low distortion ballasts n Reduce harmonics at the source n Additional cost and typically more expensive
than “system” solutions
Welding/arcing
loads
Active filters n Fast response and broadband harmonic correction
n Reduces voltage flicker
n High cost
Tuned filters n SCR controlled tuned filters simulates an active
filter response
n SCR controlled units are high cost but fixed
filters are reasonable
System
solutions
Tuned filters n Provides PF correction
n Lower cost compared to other systems
n System analysis required to verify application.
Must be resized if system changes
Harmonic mitigating
transformers
n Excellent choice for new design or upgrade n No PF correction benefit
Active filters n Ideal solution and handles system diversity n Highest cost
113
Power Quality

5. Uninterruptible Power
Systems (UPS)
The advent and evolution of solid-state
semiconductors has resulted in a
pro
liferation of electronic computational
devices that we come in contact with on
a daily basis.These machines all rely on
a narrow range of nominal ac power in
order to work properly. Indeed, many
other types of equip
ment also require that
the ac electrical power source be at or
close to nominal voltage and frequency.
Disturbances of the power translate into
failed processes, lost data, decreased
efficiency and lost revenue.
The normal power source supplied by the
local utility or provider is typically not
stable enough over time to continuously
serve these loads with
out interruption. It
is possible that a facility outside a major
metropolitan area served by the utility
grid will experience outages of some
nature 15–20 times in one year. Certain
outages are caused by the weather, and
others by the failure of the utility supply
system due to equipment failures or
construction interruptions. Some outages
are only several cycles in duration, while
others may be for hours at a time.
In a broader sense, other problems exist
in the area of power quality, and many of
those issues also contribute to the failure
of the supply to provide that narrow range
of power to these sensitive loads.
Power quality problems take the form
of any of the following: power failure,
power sag, power surge, undervoltage,
overvoltage, line noise, frequency
variations, switching transients and
harmonic distortion. Regardless of the
reason for outages and power quality
problems, the sensitive loads can not
function normally without a backup
power source. Additionally, in many
cases, the loads must be isolated from
the instabilities of the utility supply and
power quality problems and given clean
reliable power on a continuous basis, or
be able to switch over to reliable clean
electrical power quickly.
Uninterruptible power supply (UPS)
systems have evolved to serve the needs
of sensitive equipment and can supply
a stable source of electrical power, or
switch to backup to allow for an orderly
shutdown of the loads without
appreciable loss of data or process. In
the early days of main
frame computers,
motor-generator sets provide isolation
and clean power to the computers.They
did not have deep reserves, but provided
extensive ride-through capability while
other sources of power (usually standby
emergency engine generator sets) were
brought online while the normal source
of power was unstable or unavailable.
UPS systems have evolved along the
lines of rotary types and static types
of systems, and they come in many
configurations, including hybrid designs
having characteristics of both types.The
discussion that follows attempts to
compare and contrast the two types of
UPS systems, and give basic guidance on
selection criteria.This discussion will focus
on the medium, large and very large UPS
systems required by users who need more
than 10 kVA of clean reliable power.
Power Ratings of UPS Systems
■ Small UPS:Typically 300VA to 10 kVA,
and sometimes as high as 18 kVA
■ Medium UPS: 10–60 kVA
■ Large UPS: 100–200 kVA units, and
higher when units are paralleled
■ Very Large UPS: 200–2 MW units, and
higher when units are paralleled
Each of these categories is arbitrary
because manufacturers have many
different UPS offerings for the same
application.The choice of UPS type and
the configuration of UPS modules for a
given application depends upon many
factors, including:
■ How many power quality problems the
UPS is expected to solve
■ How much future capacity is to be
purchased now for future loads
■ The nature of the sensitive loads and
load wiring
■ Which type of UPS system is favored,
rotary or static
■ Choices of battery or dc storage
technology considered
■ A host of other application issues
Rotary UPS Systems
Typical Ratings
300–3 MW maximum.
Typical Rotary Configurations
Rotary UPS systems are among the oldest
working systems developed to protect
sensitive loads. Many of these systems
are complicated engine-generator sets
coupled with high inertial flywheels
operated at relatively low rotational
speeds.These legacy types of hybrid
UPS systems are not the focus of this
discussion, because only one or two
vendors continue to offer them.
See Figure 1.9-8 for the modern high
speed Rotary UPS systems discussed
in this section of the guide.These types
of modern rotary UPS systems are
advanced, integrated designs using
scalable configurations of high-speed
flywheel, motor and generator in one
compact UPS package.The new rotary
technologies have the potential to
replace battery backup systems, or at
least reduce the battery content for
certain applications.The appeal of rotary
systems is the avoidance of the purchase,
maintenance and facility space required
by dc battery based backup systems.
High-Speed Rotary Concept
of Operation
The modern rotary type of UPS operation
is understood by reviewing the four
topics below: startup mode, normal
operation mode, discharge mode and
recharge mode.
Startup Mode
The UPS output is energized on bypass as
soon as power is applied from the source
to the system input.The UPS continues
the startup procedure automatically when
the front panel controls are placed into
the “Online” position. Internal UPS
system checks are performed then the
input contactor is closed.The static
disconnect switch is turned on and the
conduction angle is rapidly increased
from zero to an angle that causes the dc
bus voltage between the utility con
verter
and the flywheel converter to reach
approximately 650V through the
rectifying action of the freewheeling
diodes in the utility converter. As soon
as this level of dc voltage is reached,
the static disconnect turns on fully.
Power Quality

Figure 86. Typical-High Speed Modern Rotary UPS
The next step involves the utility converter
IGBTs to start firing, which allows the
converter to act as a rectifier, a regulating
voltage source and an active harmonic
filter. As the IGBTs begin to operate, the
dc bus is increased to a normal operating
voltage of approximately 800V, and the
output bus is transferred from bypass
to the output of the power electronics
module.The transfer from bypass is
completed when the output contactor is
closed and the bypass contactor opened
in a make-before-break manner.
The firing of the SCRs in the static
disconnect switch is now changed so
that each SCR in each phase is only turned
on during the half-cycle, which permits
real power to flow from the utility supply
to the UPS.This firing pattern at the static
disconnect switch prevents power from
the flywheel from feeding backward into
the utility supply and ensures that all of
the flywheel energy is available to
support the load.
Immediately after the output is
transferred from bypass to the power
electronic module, the flywheel field is
excited, which also provides magnetic
lift to unload the flywheel bearings.
The flywheel inverter is turned on and
gradually increases frequency at a
constant rate to accelerate the flywheel
to approximately 60 rpm.
Once the flywheel reaches 60 rpm, the
flywheel inverter controls the acceleration
to keep currents below the maximum
charging and the maximum input settings.
The point that the fly
wheel reaches
4000 rpm, the UPS is fully functional and
capable of support
ing the load during a
power quality event. Flywheel acceleration
continues until the Flywheel reaches
“full charge” at 7700 rpm.The total time
to complete startup is less than 5 minutes.
Normal Operation Mode
Once the UPS is started and the flywheel
is operating at greater than 4000 rpm,
the UPS is in the normal operating mode
where it is regulating output voltage and
supplying reactive and harmonic currents
required by the load. At the same time
it cancels the effect of load current
harmonics on the UPS output voltage.
Input current consists of three
components: real load current, charging
current, and voltage regulation current.
Real current is current that is in phase with
the supply voltage and supplies real power
to the load. Real current flowing through
the line inductor causes a slight phase
shift of the current lagging the voltage by
10 degrees and ensures that the UPS can
quickly transfer to bypass without causing
unacceptable switching transients.
The second component is charging
current required by the flywheel to keep
the rotating mass fully charged at rated
rpm, or to recharge the rotating mass after
a discharge.The power to maintain full
charge is low at 2 kW and is accomplished
by the IGBTs of the flywheel converter
gating to provide small pulses of motoring
current to he flywheel.This current can
be much higher if fast recharge times
are selected.
The final component of input current is
the voltage regulation current, which is
usually a reactive current that circulates
between the input and the utility
converter to regulate the output voltage.
Leading reactive current causes a voltage
boost across the line inductor, and a
lagging current causes a bucking voltage.
By controlling the utility converter to
maintain nominal output voltage, just
enough reactive current flows through
the line inductor to make up the
difference between the input voltage
and the output voltage.
The load current consists of three
components: the harmonic current
required by the load, the reactive load
current, and the real current, which does
the work.The utility converter supplies
both the harmonic and reactive currents.
Because these currents supply no net
power to the load, the flywheel supplies
no energy for these currents.They
circulate between the utility converter
and the load.
It = Ir + Ic + Ig
Id = Output Current
Ih = Harmonic Current
Ix = Reactive Load Current
Ir = Real Load Current
Source
Field Coil
Driver
Integrated Motor/Flywheel/
and Generator
ac
dc
dc
ac
Ih
Ix
Flywheel Converter Utility Converter Ic
Ig
Filter Inductor
Inverter
Fuse
Line Inductor
Output
Contactor
Input
Contactor
Static Disconnect
Switch
Bypass Contactor
Static Bypass Option
Load
Output Transformer
Id = Ih + Ix + Ir
It = Input Current
Ir = Real Load Current
Ic = Charging Current
Ig = Voltage Regulation Current
115
Power Quality

The power stage controls analyze the
harmonic current requirements of the
load and set the firing angle of the inverter
IGBTs to make the utility converter a very
low impedance source to any harmonic
currents.Thus, nonlinear load currents are
supplied almost entirely from the utility
converter with little effect on the quality
of the UPS output voltage waveform
and with almost no transmission of load
harmonics currents to the input of
the UPS.
Discharge Mode
The UPS senses the deviation of the
voltage or frequency beyond programmed
tolerances and quickly disconnects the
supply source by turning off the static
disconnect switch and opening the input
contactor.The disconnect occurs in less
than one-half cycle.Then the utility
converter starts delivering power from
the dc bus to the load, and the flywheel
converter changes the firing point of its
IGBTs to deliver power to the dc bus.
The UPS maintains a clean output voltage
within 3% or nominal voltage to the load
when input power is lost.
Recharge Mode
When input power is restored to
acceptable limits, the UPS synchronizes
the output and input voltages, closes the
input contactor and turns on the static
disconnect switch.The utility converter
then transfers power from the flywheel
to the input source by linearly increasing
the real input current.The transfer time
is program
mable from 1 to 15 seconds.
As soon as the load power is completely
transferred to the input source, the utility
converter and flywheel converter start
to recharge the flywheel and return to
normal operation mode.The flywheel
recharge power is programmable
between a slow and fast rate. Using the
fast rate results in an increase of UPS
input current over nominal levels.
Recharging the flywheel is accom
plished
by controlling the utility and flywheel
converter in a similar manner as is used
to maintain full charge in the normal
operation mode, however the IGBT
gating points are changed to increase
current into the flywheel.
High-Speed RotaryAdvantages
■ Addresses all power quality problems
■ Battery systems are not required
or used
■ No battery maintenance required
■ Unlimited discharge cycles
■ 150-second recharge time available
■ Wide range of operating tempera
tures
can be accommodated (–20 ° to 40 °C)
■ Small compact size and less floor space
required (500 kW systems takes 20 sq ft)
■ N+1 reliability available up to 900 kVA
maximum
■ No disposal issues
High-Speed Rotary Disadvantages
■ Flywheel does not have deep reserve
capacity—rides through for up to
13 seconds at 100% load
■ Some enhanced flywheel systems may
extend the ride through to 30 seconds
at 100% load
■ Mechanical flywheel maintenance
required every 2–3 years, and oil
changes required every year
■ Recharge fast rates require the input to
be sized for 125% of nominal current
■ Flywheels failures in field not
understood
■ Requires vacuum pumps for
high-speed flywheels
■ Limited number of vendors and
experience
Power Quality

Static UPS Systems
Typical Ratings
20 kW to 1 MVA / 1 MW, and higher when
multiple units are paralleled.
Typical Static UPS Configurations
Static UPS systems modules are available
in three basic types of configurations
known as standby, line interactive and
double conversion.The lower power
ratings are likely to be one of the first two
types of configurations, e.g., standby or
line interactive. Most medium or large
static UPS installations use the double
conversion technology in one or multiple
module configurations, i.e., or multiple
UPS units in parallel.
Special UPS high-efficiency operating
modes like Eco mode or ESS can provide
efficiency improvements to over 99%,
equating to less than 1% losses through
the UPS.These modes depend on the
system operating with the static switch
closed and power conversion sections
suspended (not off). Modern UPSs can
instantly revert to traditional double
conversion operation within 2 ms on
detection of any power anomaly.
Figure 87 illustrates the one-line diagram
of a simple single Double Conversion
UPS module. Brief explana
tions appear
for the standby and line interactive UPS
systems after the text explaining the
Double Conversion static UPS type of
system.
Double Conversion Concept
of Operation
The basic operation of the Double
Conversion UPS is:
1. Normal power is connected to the
UPS input through the facility
electrical distribution system.This
usually involves two input circuits
that can either come from the same
source or from separate sources such
as utility and site generation.
2. The Rectifier/Charger function
converts the normal ac power to
dc power to charge the battery and
power the inverter.The load is isolated
from the normal input source.
3. The battery stores dc energy for use
when input power to the UPS fails.
The amount of power available from
the dc battery system and time to
discharge voltage is a function of
the type of battery selected and the
ampere-hour sized used. Battery
systems should be sized for no less
than 5 minutes of clean power usage
from a fully charged state, and, in
many cases, are sized to provide
more time on battery power.
4. The dc link connects the output of the
rectifier/charger to the input of the
inverter and to the battery.Typically the
rectifier/charger is sized slightly higher
than 100% of UPS output because it
must power the inverter and supply
charger power to the battery.
5. The bypass circuit provides a path
for unregulated normal power to be
routed around the major electronic
sub-assemblies of the UPS to the
load so that the load can continue to
operate during maintenance, or if the
UPS electronics fails.The bypass static
switch can switch to conducting mode
in 1 millisecond.When the UPS
recognizes a requirement to transfer
to the bypass mode, it simultaneously
turns the static switch ON, the output
breaker to OPEN, and the bypass
breaker to CLOSE.The output breaker
opens and the bypass breaker
closes in about 50 milliseconds.The
restoration of normal conditions
at the UPS results in the automatic
restoration of the UPS module
powering the load through the
rectifier/charger and inverter with
load isolation from power quality
problems, and the opening of the
bypass circuit.
Static Double ConversionAdvantages
■ Addresses all power quality problems
■ Suitable for applications from 5 kVA to
over 2500 kVA
■ Simple battery systems are sized
for application
■ Long battery backup times and long life
batteries are available
■ Higher reliability is available using
redundant UPS modules
Figure 87. Typical Static UPS, Double Conversion Type with Battery Backup
Source
Battery
ac
dc
dc
ac
Inverter
Output
Breaker
Normal
Breaker
Bypass Static Switch
UPS Module
Load
Rectifier/Charger
Battery Breaker
Bypass Breaker (Optional)
117
Power Quality

Static Double Conversion
Disadvantages
■ Battery systems, battery maintenance
and battery replacement are required
■ Large space requirement for battery
systems (higher life takes more space,
e.g., 500 kW takes 80–200 sq ft
depending upon the type of battery
used,VRLA 10 year,VRLA 20 year
or flooded)
■ Limited discharge cycles of
battery system
■ Narrow temperature range
for application
■ Efficiencies are in the 90–97%
■ Bypass mode places load at risk unless
bypass has UPS backup
■ Redundancy of UPS modules results
in higher costs
■ Output faults are cleared by the
bypass circuit
■ Output rating of the UPS is 150%
■ Battery disposal and safety issues exist
Standby UPS Concept of Operation
The basic operation of the Standby
UPS is:
1. The Standby UPS topology is similar
to the double conversion type, but the
operation of the UPS is different in
significant ways. Normal power is
connected to the UPS input through
the facility electrical distribution
system.This usually involves two
input circuits that can come from
one or two sources such as utility
and site generation. See Figure 88 for
details.
2. The rectifier/charger function converts
the normal ac power to dc power to
charge the battery only, and does not
simultaneously power the inverter.
The load is connected to the bypass
source through the bypass static
switch.The inverter is in the standby
mode ready to serve the load from
battery power if the input power
source fails.
3. The battery stores dc energy for use
by the inverter when input power to
the UPS fails.The amount of power
available from the dc battery system
and time to discharge voltage is a
function of the type of battery selected
and the ampere-hour sized used.
Battery systems should be sized for
the anticipated outage.
4. The dc link connects the output of the
rectifier/charger to the input of the
inverter and to the battery.Typically
the rectifier/charger is sized only to
supply charger power to the battery,
and is rated far lower than in the
double conversion UPS.
5. The bypass circuit provides a direct
connection of bypass source to
the load.The load operates from
unregulated power.The bypass static
switch can switch to non-conducting
mode in 8 milliseconds.When the
UPS recognizes the loss of normal
input power, it transfers to battery/
inverter mode by simultaneously
turning the Inverter ON and the
static switch OFF
.
Static Standby UPSAdvantages
■ Lower costs than double conversion
■ Rectifier and charger are
economically sized
■ Efficient design
■ Batteries are sized for the application
Static Standby UPS Disadvantages
■ Impractical over 2 kVA
■ Little to no isolation of load from power
quality disturbances
■ Standby power is from battery alone
■ Battery systems, battery mainte
nance
■ Limited discharge cycles of
battery system
for application
■ Output faults are cleared by the
bypass circuit
Static Line Interactive UPS
Concept of Operation
The basic operation of the Line Interactive
UPS is:
1. The Line Interactive type of UPS has
a different topology than the static
double conversion and standby
systems.The normal input power is
connected to the load in parallel with
a battery and bi-directional inverter/
charger assembly.The input source
usually terminates at a line inductor
and the output of the inductor is
connected to the load in parallel
with the battery and inverter/charger
circuit. See Figure 89 for more details.
2. The traditional rectifier circuit is
eliminated and this results in
a smaller footprint and weight
reduction. However, line
conditioning is compromised.
3. When the input power fails, the
battery/inverter charger circuit
reverses power and supplies the
load with regulated power.
Static Line Interactive UPSAdvantages
■ Slight improvement of power
conditioning over standby
UPS systems
■ Small footprints and weights
■ Efficient design
■ Batteries are sized for the application
Static Line Interactive
UPS Disadvantages
■ Impractical over 10 kVA
■ Not as good conditioning as
double conversion
■ Standby power is from battery alone
■ Battery systems, battery maintenance
■ Limited discharge cycles for the
battery system
for application
Power Quality

Figure 88. Typical Static UPS, Standby Type with Battery Backup
Figure 89. Typical Static UPS, Line Interactive Type with Battery Backup
Source
ac
dc
dc
ac
UPS Module
Normal
Breaker
Rectifier/
Charger Inverter
Bypass Static Switch
Battery
Breaker
Output
Breaker
Battery
Load
Source
dc
ac
UPS Module
Bidirectional
Inverter/Charger
Battery
Load
Inductor
119
Power Quality

Seismic Requirements
General
In the 1980s, Eaton embarked on a
comprehensive program centered
around designing and building electrical
distribution and control equipment
capable of meeting and exceeding the
seismic load require
ments of the Uniform
Building Code (UBC) and California
Building Code (CBC).These codes
emphasize build
ing design requirements.
Electrical equipment and distribution
system components are considered
attach
ments to the building.The entire
program has been updated to show
compliance with the 2015 International
Building Code (IBC) and the 2016 CBC
seismic requirements.
A cooperative effort with the equip
ment
user, the building designer and the
equipment installer ensures that the
equipment is correctly anchored such
that it can withstand the effects of an
earthquake. Eaton’s electrical distribution
and control equipment has been tested
and seismically proven for requirements
in compliance with the IBC and CBC. Over
100 different assemblies representing
essentially all product lines have been
successfully tested and verified to seismic
require
ments specified in the IBC and CBC.
The equipment maintained structural
integrity and demonstrated the ability to
function immediately after the seismic
tests. A technical paper, Earthquake
Requirements and Eaton Distribution and
Control Equipment Seismic Capabilities
(SA12501SE), provides a detailed
explanation of the applicable seismic
codes and Eaton’s equipment qualification
program.The paper may be found at
www.eaton.com/seismic.Type in
SA12501SE in the document search field.
Figure 90. Typical Earthquake Ground Motion Map for the United States
International Building Code (IBC)
On December 9, 1994, the International
Code Council (ICC) was established as
a nonprofit organization dedicated to
developing a single set of compre
hensive
and coordinated codes.The ICC founders
—the Building Officials and Code
Administrators (BOCA), the International
Conference of Building Officials (ICBO),
and the Southern Building Code Congress
International (SBCCI)—created the ICC in
response to technical disparities among
the three nationally recognized model
codes now in use in the U.S.The ICC offers
a single, complete set of construction
codes without regional limitations—the
International Building Code.
Uniform Building Code (UBC)
1997 was the final year in which the UBC
was published. It has since been replaced
by the IBC.
California Building Code
The 2001 CBC was based upon the 1997
UBC. In August of 2006, it was repealed
by the California Building Standards
Commission (CBSC) and replaced by the
2007 CBC, California Code of Regulations
(CCR),Title 24, Part 2 and used the 2006
IBC as the basis for the code.The 2016
CBC is based upon the 2015 IBC, with
amendments as deemed appropriate by
the CBSC. Eaton’s seismic qualification
program fully envelopes the requirements
of the 2016 CBC with many of the
distribution and control products having
Seismic Certification Pre-approval with
the California Office of Statewide Health
Planning and Development (OSHPD).
Process
According to Chapter 16 of the 2015 IBC,
structure design, the seismic requirements
of electrical equipment in buildings may
be computed in two steps.The first step is
to determine the maximum ground
motion to be considered at the site.The
second step is to evaluate the equipment
mounting and attachments inside the
building or structure.These are then
evaluated to determine appropriate
seismic test requirements.The ground
motion, seismic requirements of the
equipment, and the seismic response
spectrum requirements are discussed
on Page 122, see Figure 92.

Ground Motion
The first step in the process is to
determine the maximum considered
earthquake spectral response accelera
tion at short periods of 0.2 seconds (SS)
and at a period of 1.0 second (S1
).These
values are determined from a set of
spectral acceleration maps (Figure 90)
and include numerous contour lines
indicating the severity of the earthquake
requirements at a particular location in
the country.
The spectral acceleration maps indicate
low to moderate seismic requirements
for the entire country, with the exception
of two particular areas; theWest Coast
and the Midwest (the New Madrid area).
The maps indicate that the high seismic
require
ments in both regions,West
Coast and Midwest, quickly decrease
as one moves away from the fault area.
Therefore, the high requirements are only
limited to a relatively narrow strip along
the fault lines. Just a few miles away from
this strip, only a small percentage of the
maximum requirements are indicated.
Assuming the worse condition, which
is a site directly located near a fault,
the maximum considered earthquake
spectral response acceleration at short
periods of 0.2 seconds (SS
) is equal to
285% gravity and at 1.0 second period (S1
)
is 124% gravity.These numbers are the
maximum numbers for the entire country.
To help understand the 2015 IBC (and
2016 CBC) seismic parameters for a
specific building location, the link to
the US Geological Society is extremely
helpful: http://earthquake.usgs.gov/
research/hazmaps/design/
The program will allow one to enter the
latitude and longitude of a location.The
IBC (CBC) seismic parameters for that
location will then be displayed.
To determine the maximum considered
earthquake ground motion for most
site classes (A through D), the code
introduces site coefficients, which when
applied against the location-specific site
class, produces the adjusted maximum
considered earthquake spectral response
acceleration for the required site.The
site coefficients are defined as Fa
at 0.2
seconds short period and FV
at 1.0 second
period. From the tables in the code, the
highest adjust
ing factor for SS
is equal to
1.0 and the highest adjusting factor for S1
is 1.50.
As a result, the adjusted maximum
considered earthquake spectral response
for 0.2 second short period (SMS
) and at
1.0 second (SM1
), adjusted for site class
effects, are determined from the
following equations:
SMS
= Fa
SS
= 1.0 x 3.73 g = 3.73 g
SM1
= Fv
S1
= 1.5 x 1.389 g = 2.08 g
ASCE 7 (American Society of Civil
Engineers) provides a plot of the final
shape of the design response spectra
of the seismic ground motion.The plot
is shown in Figure 91. ASCE 7 is
referenced throughout the IBC as
the source for numerous structural
design criteria.
The design spectral acceleration curve
can now be computed.The peak spec
tral
acceleration (SDS
) and the spectral
acceleration at 1.0 second (SD1
) may
now be computed from the following
formulas in the code:
SDS
= 2/3 x SMS
= 2/3 x 3.73 g = 2.49 g
SD1
= 2/3 x SM1
= 2/3 x 2.08 g = 1.39 g
SDS
, the peak spectral acceleration,
extends between the values of T0
andTS
.
T0
andTS
are defined in the codes as
follows:
T0
= 0.2 SD1
/SDS
= 0.2 x 1.39/2.49 =
0.112 seconds (8.96 Hz)
TS
= SD1
/SDS
= 1.39/2.49 =
5.585 seconds (1.79 Hz)
According to the IBC and ASCE 7, the
spectral acceleration (Sa
) at periods less
than 1.45 seconds may be com
puted by
using the following formula:
Sa
= SDS
(0.6T/T0
+ 0.4)
WhereT is the period where Sa
is being
calculated:
Therefore, the acceleration at 0.0417
seconds (24 Hz), for example, is equal to:
Sa
= 2.49 (0.6 ((0.0417/0.112) + 0.4) = 1.55 g
The acceleration at 0.03 seconds (33 Hz)
is equal to:
Sa
= 2.49 (0.6 (0.3/0.112) + 0.4) = 1.40 g
At zero period (infinite frequency),T = 0.0,
the acceleration (ZPA) is equal to:
Sa
= 2.49 (0.6 (0.0/0.112) + 0.4) = 0.996 g
(ZPA)
The acceleration to frequency
relationship in the frequency range of 1.0
Hz toTS
is stated equal to:
Sa
= SD1
/T
Where Sa
is the acceleration at theT period.
At 1.0 Hz (T=1.0) this equation yields the
following acceleration:
Sa
= 1.39/1 = 1.39 g
Figure 91. Design Response Spectrum
Spectural
Response
Acceleration
S
a
(g)
SDS
SD1
T0 TS TL
1.0
PeriodT (sec)
Sa =
Sa =
SD1
T
SD1 TL
T2
121

Testing has demonstrated that the lowest
dominant natural frequency of Eaton’s
electrical equipment is above 3.2 Hz.This
indicates that testing at 1.39 g at 1 Hz is
not necessary. In addition, having the
low end of the spectra higher than
realistically required forces the shake
table to move at extremely high
displacements to meet the spectral
acceleration at the low frequencies.
Testing to accommodate the low end
of the spectra using this acceleration
component can result in testing to a
factor 2 to 3 times greater than that
realistically required.
Through testing experience and data
analysis, the seismic acceleration at
1.0 Hz is taken equal to 0.7 g, which
will ensure that the seismic levels are
achieved well below 3.2 Hz.This yields
a more vigorous test over a wider range
of seismic intensities.
In developing the seismic requirements
above, it is important to recognize the
following:
T0
andTS
are dependent on SMS
and SD1
.
If SD1
is small relative to SMS
thenT0
andTS
will be smaller and the associated
frequencies will shift higher.The opposite
is also true.This must be realized in
developing the complete required
response spectrum (RRS).Therefore, it
is not adequate to stop the peak spectral
acceleration at 8.96 Hz.There are other
contour line combinations that will
produce higherT0
.To account for this
variation it is almost impossible to
consider all combinations. However, a
study of the spectral acceleration maps
indicates that all variations with high
magnitude of contour lines could very
well be enveloped by a factor of 1.25.
Therefore,T0
is recomputed as follows:
T0
= 0.2 SD1
/(SDS
x 1.25) = 0.2 x 1.39/
(2.49 x 1.25) = 0.089 seconds (11.20 Hz)
Eaton ensures maximum certification by
requiring peak acceleration during testing
to extend to 12 Hz.
It can be seen that Eaton has elected to
develop generic seismic requirements
that envelop two criteria:
■ The highest possible spectral peak
accelerations and ZPA
■ The maximum frequency range
required for many different sites
Figure 92. Design Response Spectrum
This completes the ground motion
design response spectrum.The spectral
accelerations are equal to 0.76 g at ZPA,
or 33 Hz, and increases linearly to a peak
acceleration of 1.90 g at 0.09 seconds
(or 11.49 Hz) and stays constant to
0.653 seconds (1.53 Hz), then gradually
decreases to 1.24 g at 1 second (or 1.0 Hz).
This curve is shown in Figure 92.
ASCE 7—Seismic Demands on
Non-Structural Components
ASCE 7 provides a formula for computing
the seismic requirements of electrical and
mechanical equipment inside a building
or a structure.The formula is designed for
evaluating the equipment attachment to
the equip
ment foundations.The seismic
loads are defined as:
Fp
= 0.4 ap
SDS
Wp
(1 + 2 Z/h)/(Rp
/Ip
)
Where:
Fp
= Seismic design force imposed at
the component’s center of gravity (C.G.)
and distributed relative to component
mass distribution.
ap
= Component amplification factor that
varies from 1.00 to 2.50.
SDS
= Ground level spectral acceleration,
short period.
Wp = Component operating weight.
Rp
= Component response modifica
tion
factor that for electrical equipment varies
from 2.5 to 6.0.
Ip
= Component importance factor that is
either 1.0 or 1.5.
Z = Highest point of equipment in a
building relative to grade elevation.
h = Average roof height of building
relative to grade elevation.
The following parameters produce the
maximum required force:
■ Z is taken equal to h (equipment on roof)
■ Ip
is taken equal to 1.5
■ ap
■ Rp
■ SDS
is equal to 2.49 g as indicated in the
previous section
The acceleration (Fp
/Wp
) at the C.G. of the
equipment is then computed equal to:
Acceleration = Fp
/Wp
= 0.4 x 2.5 x 2.49 g
(1 + 2) / (2.5/1.5) = 4.482 g
1
.1
.2
.3
.4
.5
.6
.7
.8
.9
2
3
4
5
6
7
8
9
10
1.0
2 3 4 5 6 7 8 9 10 20 30 40 60 80 100
Frequency Hz
Acceleration
(g
peak)
Test Response Spectrum
(TRS)
Spectrum Dip – Not Important
Because Frequency is Not an
Equipment Natural Frequency
Zero Period
Acceleration = Maximum
TableTest Motion
Zero Period
Acceleration = Maximum
Floor Motion
Required Response Spectrum
(RRS)

For equipment on (or below) grade, the
acceleration at the equipment C.G. is then
computed equal to:
Acceleration = Fp
/Wp
= 0.4 x 2.5 x 2.49 g
(1 + 0) / (2.5 /1.5) = 1.49 g
It is impractical to attempt to measure the
actual acceleration of the C.G. of a piece
of equipment under seismic test.The
seismic response at the middle of base
mounted equipment close to its C.G. is at
least 50% higher than the floor input at
the equipment natural frequency.The
base accelerations associated with the
accelerations of FP/WP at the C.G. of the
equipment could then be computed as
4.48 /1.5 = 2.99 g. It is the equipment base
input acceleration that is measured and
documented during seismic testing and is
the acceleration value shown on Eaton’s
seismic certificates.
Final Combined Requirements
To better compare all seismic levels and
determine the final envelope seismic
requirements, the 2016 CBC and 2015 IBC
for California are plotted in Figure 93. All
curves are plotted at 5% damping.
An envelopment of the seismic levels in
the frequency range of 3.2 Hz to 100 Hz is
also shown.This level is taken as Eaton’s
generic seismic test requirements for all
certifications. Eaton performed additional
seismic test runs on the equipment
at approximately 120% of the generic
enveloping seismic requirements
(see Figure 94). Eaton has established this
methodology to provide additional margin
to accommodate potential changes with
the spectral maps, thus eliminat
ing the
need for additional testing.
Figure 93. Required Response Spectrum Curve
Figure 94. Eaton Test Required Response Spectrum Curve
Eaton Seismic IBC 2015/CBC 2016
0.1
1
10
1 10 100
Acceleration
(g) Frequency (Hz)
Required Response Spectrum
0.1
1
10
1 10 100
Acceleration
(g)
Frequency (Hz)
100% vs. 120%
Eaton 100% Seismic Envelope Eation 120% Seismic Envelope
123

Product Specific Test Summaries
Table 55. Distribution Equipment
Tested and Seismically Proven Against
Requirements within IBC 2015
Note: For most current information,
see www.eaton.com/seismic.
Eaton Equipment
MV Metal-Clad Switchgear,VacClad-W
MV Metal-Enclosed Switchgear:
MEF Front Access
MV Metal-Enclosed Switchgear; MVS, MEB
MV Motor Starters: Ampgard
MVVariable Frequency Drives (VFD)
MV Busway: Non-Segregated
Unitized Power Centers
Spot Network Equipment
LV Metal-Enclosed Drawout Switchgear:
Magnum
LV Busway
LV Motor Control Centers (MCC)
Switchboards
Panelboards
Dry-Type DistributionTransformers (DTDT)
Transfer Switch Equipment
Enclosed Molded Case Circuit Breakers
Safety Switches
Elevator Control
Enclosed Motor Starters Contactors
Variable Frequency Drives (VFD)
Uninterruptible Power Supplies (UPS)
CAT Generator Paralleling Switchgear
Resistance Grounding Systems
IEC Equipment
Solar Systems Interconnect Equipment
Fire Pump Controllers
Residential/Light Commercial Metering
Distribution
Note: See www.eaton.com/seismic for
current seismic certificates.
Figure 95. Sample Seismic Certificate

Additional Design and
Installation Considerations
When installing electrical distribution and
control equipment, consideration must be
given as to how the methods employed
will affect seismic forces imposed on the
equipment, equipment mounting surface,
and conduits entering the equipment.
Eaton recommends that when specify
ing
a brand of electrical distribution and
control equipment, the designer
references the installation manuals of
that manufacturer to ascertain that the
requirements can be met through the
design and construction process.
For Eaton electrical distribution and
control products, the seismic installa
tion
guides for essentially all product lines
can be found at ourWeb site:
http://www.eaton.com/seismic.
Electrical designers must work closely
with the structural or civil engineers for
a seismic qualified installation.
Consideration must be given to the type
of material providing anchorage for the
electrical equipment.
If steel, factors such as thickness or
gauge, attachment via bolts or welding,
and the size and type of hardware must
be considered.
If concrete, the depth, the PSI, the type
of re-enforcing bars used, as well as the
diameter and embedment of anchorage
all must be considered.
The designer must also give consider
ation if the equipment will be secured to
the wall, versus stand-alone or free-
standing, which requires the equipment
to withstand the highest level of seismic
forces.Top cable entry should be avoided
for large enclosures, as accommodation
for cable/conduit flexibility will need to be
designed into the system.
For a manufacturer to simply state
“Seismic Certified” or “Seismic
Qualified” does not tell the designer
if the equipment is appropriate for the
intended installation.
Note: Eaton recommends that designers
confirm with the manufacturer if the seismic
certification supplied with the equipment is
based on:
1. ACTUAL shaker table test as required
by the IBC and CBC.
2. The seismic certificate and test data
clearly state if the equipment was
tested as free-standing—anchored at
the bottom of the equipment to the
shaker table.
3. Structure attached, that is, anchored
at the center of gravity (C.G.) or at the
TOP of the equip
ment to a simulated
wall on the shaker table.
Stand-Alone or Free-Standing
Equipment
If stand-alone or free-standing, then this
may require that additional width space
be allowed at each end of the equipment
for additional seismic bracing supplied by
the manufacturer.
Additional thought must be given to the
clearances around the equipment to rigid
structural edifices. Space must be
allowed for the differing motions of the
equipment and the structure, so that they
do not collide during a seis
mic event and
damage one another.
Note: If the equipment is installed as stand-
alone or free-standing, with additional seismic
bracing at each end and not attached to the
structure as tested, and yet, it is fitted tightly
against a structural wall, then this would be an
incorrect installation for the application of the
seismic certificate.
Furthermore, if conduits are to be
installed overhead into the equipment,
does the design call for flexible conduits
of sufficient length to allow for the
conflicting motion of the equipment and
the structure during a seismic event so as
to not damage the conductors contained
therein, and the terminations points
within the equipment.
StructureAttached Equipment
The designer must work closely with the
structural engineer if the equipment is to
be attached to the structure to ascertain
that the internal wall re-enforcement of
the structure, type of anchor, and depth
of embed
ment is sufficient to secure
the equipment so that the equipment,
conduits and structure move at or near
the same frequency.
Energy Conservation
Because of the greatly increased cost of
electrical power, designers must consider
the efficiency of electrical distribution
systems, and design for energy
conservation. In the past, especially in
commercial buildings, design was for
lowest first cost, because energy was
inexpensive.Today, even in the speculative
office building, operating costs are so
high that energy-conserving designs can
justify their higher initial cost with a rapid
payback and continuing savings.The
leading standard for energy conservation
is ASHRAE 90.1 (latest is 2016) and
International Energy Conservation Code
(IECC) as adopted by the International
Building Code (IBC).
There are four major sources of
electrical energy conservation in
a commercial building: 1) Lighting
Systems, 2) Motors and controls,
3)Transformers, 4) HVAC system.
The lighting system must take advantage
of the newest equipment and techniques.
New light sources, familiar light sources
with higher efficiencies, solid-state
ballasts with dimming controls, use of
daylight, environmental design, efficient
luminaires, computerized or programmed
control, and the like, are some of the
methods that can increase the efficiency
of lighting systems.They add up to
providing the necessary amount of light,
with the desired color rendition, from the
most efficient sources, where and when it
is needed, and not providing light where
or when it is not necessary.
The installation of energy-efficient
lighting provides the best payback for
the lowest initial investment and should
be considered the first step in a facility
energy reduction program.
Motors and controls are another cause
of wasted energy that can be reduced.
New, energy-efficient motor designs are
available using more and better core
steel, and larger windings.
125

For any motor operating 10 or more hours
per day, the use of energy-efficient types
is strongly recommended.These motors
have a premium cost of about 20% more
than standard motors. Depending on
loading, hours of use and the cost of
energy, the additional initial cost could be
repaid in energy saved within a few
months, and it rarely takes more than two
years. Because, over the life of a motor,
the cost of energy to operate it is many
times the cost of the motor itself, any
motor with many hours of use should be
of the energy-efficient type.
Where a motor drives a load with variable
output requirements such as a centrifugal
pump or a large fan, customary practice
has been to run the motor at constant
speed, and to throttle the pump output or
use inlet vanes or outlet dampers on the
fan.This is highly inefficient and wasteful
of energy. In order to achieve maximum
energy efficiency in these applications,
solid-state variable frequency, variable
speed drives for AC induction motors
are available as a reliable and relatively
inexpensive option. Using a variable-
speed drive, the throttling valves, inlet
vanes or output dampers can be
eliminated, saving their initial cost and
energy over the life of the system. An
additional benefit of both energy-efficient
motors and variable speed drives used to
control the speed of variable torque
loads, such as centrifu
gal fans and
pumps, is that the motors operate at
reduced temperatures, resulting in
increased motor life.
Transformers have inherent losses.
Transformers, like motors, are designed
for lower losses by using more and better
core materials, larger conductors, etc.,
and this results in increased initial cost.
Because the 480V to 208Y/120V
stepdown transformers in an office
building are usually energized 24 hours
a day, savings from lower losses can be
substantial, and should be consid
ered
in all transformer specifications. One
method of obtain
ing reduced losses is to
specify Premium Efficiency transformers
with no more than 80 °C (or sometimes
115 °C) average winding temperature rise
at full load.These transformers generate
less heat than standard 150 °C rise
transformers, resulting in lower HVAC
operating costs to remove the heat in
areas where they are located.
The U.S. Department of Energy (DOE) has
established energy efficiency standards
that manufacturers of distribution
transformers must comply with since
2007. As of January 1, 2016, the DOE
standard CFRTitle 10 Chapter II Part 431
(in Appendix A of Subpart K 2016)
requires increased minimum operat
ing
efficiencies for each distribution
transformer size at a loading equal to
35% of the transformer full load kVA.The
35% loading value in the NEMA standard
reflects field studies conducted by the
U.S. Department of Energy, which
showed that dry-type transformers
installed in commercial facilities are
typically loaded at an average of 35% of
their full load capacity over a 24-hour time
period. Figure 96 compares losses for
both low temperature riseTP-1 and DOE
2016 transformers using a 75 kVA design.
HVAC systems have traditionally been
very wasteful of energy, often being
designed for lowest first cost.This, too, is
changing. For example, reheat systems
are being replaced by variable air volume
systems, resulting in equal comfort with
substantial increases in efficiency.While
the electrical engineer has little influence
on the design of the HVAC system,
he/she can specify that all motors
with continuous or long duty cycles are
specified as energy-efficient types, and
that the variable-air-volume fans do not
use inlet vanes or outlet dampers, but
are driven by variable-speed drives.
Variable speed drives can often be
desirable on centrifugal compressor units
as well. Because some of these require-
ments will be in HVAC specifications, it
is important for the energy-conscious
electrical engineer to work closely with
the HVAC engineer at the design stage to
ensure that these systems are as energy
efficient as possible.
Figure 96. Former TP-1 NEW DOE 2016 Transformer Loss Comparison for 75 kVA Copper Wound
256
911
1040
1202
1426
1615
1612
1848
2146
2557
2903
193
857
976
1127
1334
1508
1333
1519
1753
2075
2346
300
545 598
666
759
838
360
1104
1238
1407
1640
1837
0
500
1000
1500
2000
2500
3000
3500
0% 25% 35% 50% 75% 100%
Watts
Losses
Percentage of Load
Former TP-1 Versus NEW DOE 2016 Transformer Loss Comparison
for 75 kVA Copper Wound
80C, 115C and 150C Temperature Rated Designs
DOE 2016 Efficient 150C TP-1 Efficient 150C DOE 2016 Efficient 115C
TP-1 Efficient 115C DOE 2016 Efficient 80C TP-1 Efficient 80C

Building Control Systems
In order to obtain the maximum benefit
from these energy-saving lighting, power
and HVAC systems, they must be
controlled to perform their functions
most efficiently. Constant monitoring
would be required for manual operation
but is impractical and not cost-effective
given the skilled labor rates of facilities
engineering personnel. In order to ensure
optimum energy performance, some
form of automatic control is required.
The simplest of these energy-saving
controls is a time clock to turn various
systems on and off.Where flexible control
is required, programmable controllers
may be used.These range from simple
devices, similar to multi-function
time clocks, to fully programmable,
microprocessor-based devices that run
dedicated software to control specific
loads or processes.
For complete control of all building
systems, building management systems
(BMS) with specialized software can be
used. Computers can not only control
lighting and HVAC systems, and provide
peak demand control to minimize the cost
of energy, but they can perform many
other functions. Fire detection and alarm
systems that generally have their own
dedicated control system can report back
information to the BMS System. Other
auxiliary systems, such as elevator
control and various aspects of access
and intrusion control, often have the
capability to be integrated to share
information with the BMS. Other building
systems, such as closed-circuit television
monitoring, are increasingly sharing data
and bandwidth over the same Ethernet
backbone with the building manage
ment
computer system.
The time clocks, programmable controllers
and computers can obtain data from
external sensors and control the lighting,
motors and other equipment by means of
hard wiring-separate wires to and from
each piece of equipment. In the more
complex systems, this would result in a
tremendous number of control wires, so
other methods are frequently used. A
single pair of wires, with electronic digital
multiplexing, can control or obtain data
from many different points.
Increasingly, advanced signaling is
being implemented utilizing sensors that
communicate wirelessly to gateways that
connect them back to the master control
system.The newest systems are using
fiber optic cables as the Ethernet backbone
to carry tremendous quantities of data,
free from electromagnetic interference
back to the master control system and
auxiliary building systems.While the
actual method used will depend on the
type, number and complexity of functions
to be performed, the commonality of
exchanging data at the Ethernet level is
a prime consideration in the selection of
equipment that will need to be integrated
into the overall system. Eaton offers a
variety of metering, protection and control
devices that can be used as localWeb
servers as well as to communicate over
Ethernet LANs by BACnet/IP or Modbus
TCP to other master control systems.
Because building design and control f
or maximum energy saving is important
and complex, and frequently involves
many functions and several systems,
it is necessary for the design engineer
to make a thorough building and
environmental study, and to weigh the
costs and advantages of many systems.
The result of good design and planning
can be economical, efficient operation.
Poor design can be wasteful and
extremely costly.
Distributed Energy Resources
Distributed energy resources (DER)
are increasingly becoming prominent
sources of electric power. Distributed
energy resources are usually small-to-
medium sources of electric generation,
either from renewable or non-renew
able
sources. Sources include:
■ Photovoltaic (PV) systems
(solar systems)
■ Energy storage systems (battery)
■ Wind
■ Fossil-fueled (diesel, natural gas,
landfill gas, coal-bed methane)
generators (reciprocating engines)
■ Gas-fired turbines (natural gas, landfill
gas, coal-bed methane)
■ Water-powered (hydro)
■ Fuel cells
■ Microturbines
■ Wave power
■ Coal-fired boilers
Distributed energy resources may also be
termed alternative energy resources.
Prime Power
DER can be used for generating prime
power or for cogeneration. Prime power
concerns a system that is electrically
separated from the electrical grid.
Prime power is generated at remote
sites where commercial electrical power
is not available.
Cogeneration
Cogeneration is another outgrowth of the
high cost of energy. Cogeneration is the
production of electric power con
currently
with the production of steam, hot water
and similar energy uses.The electric power
can be the main prod
uct, and steam or
hot water the byproduct, as in most
commercial installations, or the steam
or hot water can be the most required
product, and electric power a byproduct,
as in many industrial installations. In
some industries, cogeneration has been
common practice for many years, but until
recently it has not been economically
feasible for most commercial installations.
This has been changed by the high cost of
purchased energy, plus federal and state
policies incentivizing public utilities to
purchase any excess power generated
by the cogeneration plant. In many cases,
practical commercial cogeneration
systems have been built that provide some
or all of the electric power required, plus
hot water, steam, and sometimes steam
absorption-type air conditioning. Such
cogeneration systems are now operating
success
fully in hospitals, shopping
centers, high-rise apartment buildings
and even commercial office buildings.
Where a cogeneration system is being
considered, the electrical distribution
system becomes more complex.The
interface with the utility company is
critical, requiring careful relaying to
protect both the utility and the
cogeneration system. Many utilities
have stringent requirements that must
be incorporated into the system. Proper
generator control and protection is
necessary, as well. An on-site electrical
generating plant tied to an electrical utility
requires a sophisticated engineering
design, interconnection application and
system impact studies.
127

Utilities require that when the protective
device at their substation opens that
the device connecting a cogenerator
to the utility open also.This is often
accomplished byTransferTrip Systems
utilizing dedicated fiber optic connectivity
and local multiplex
ing equipment.
This can add considerable cost and
complexity to the design as well as
reoccuring monthly charges to pay
for the use of the dedicated fiber.
One reason for these complex
TransferTrip arrangements is that most
cogenerators are connected to feeders
serving other customers. Utilities desire
to reclose the feeder after a transient
fault is cleared. Reclosing in most cases
will damage the cogenerator if it had
remained connected to their system.
Islanding is another reason why the
utility insists on the disconnection of the
cogenerator. Islanding is the event that
after a fault in the utility’s system is cleared
by the operation of the protective devices,
a part of the system may continue to
be supplied by cogeneration. Such a
condition is dangerous to the utility’s
operation during restoration work.
Major cogenerators are connected to
the subtransmission or the transmission
system of a utility. Major cogenerators
have buy-sell agreements. In such cases,
utilities will use a trip transfer scheme to
trip the cogenerator breaker.
Guidelines that are given in IEEE 1547
and IEEE P2030 are starting points, but
the entire design should be coordinated
with the utility.
PV System Design Considerations
Successful photovoltaic (PV) design and
construction is a complex multi-discipline
endeavor. Proper planning includes site
survey and solar site assessment for
maximizing the sun’s energy harvesting
for solar module selection, and for
updating the electrical/mechanical design
and construction to the latest code and
local constraints, including fire marshal
and seismic regulations. Professionally
prepared bid, permit, construction and
as-built drawings must be required
and maintained.
For installation in/on/for existing
structures and sites, it is advised that, at
the minimum, pre-design and construction
tests be performed for existing power-
quality issues, water drainage and the
utility feeder/transformer.
Additionally, electrical distribution panel
ratings ampacity and short-circuit ratings
must be sufficient for the planned solar
system, and the necessary arc flash
studies be performed. Connection to the
utility is always preceded by a utility
inter
connect agreement (application)
process. Successful approval is typically
required for the available solar incentives
and programs offered by the utility,
municipality, state, and various federal
agencies and depart
ments. State,
and IRS tax incentives require well-
documented records.
Solar systems, while low maintenance,
do require periodic service.The solar
modules need to be washed-clean on a
regular basis and electrical termina
tions
require initial and annual checks. Cooling
system filters are periodic maintenance
items, with the re-fresh rate dependent
upon typical and unusual circumstances.
Solar systems installed near other new
construction where dust is generated
(e.g., grading, paving) or agricultural
environments may require additional
solar-system checks and services.
Planning for such contingencies is the
business of solar-system design,
construction and on-going operation.
Performance-based incentives require
verifiable metering, often by registered/
approved independent third parties. Such
monitoring periods are typically for 60 or
more months.
It is generally wise to involve engineer
ing
design firms that specialize in complete
solar systems “turn-key” calculations,
drawings, construction management
and procurement.
The following equations are the basis of
all solar system layout and design.
LowTemperature Equation
Voc_max =Voc + (temp-differential x
temp-coefficient-of-Voc)
The temp-differential is the difference
between the standard module rating
at 25 °C and the low temperature.The
voltage (Voc) will rise with temperatures
under 25 °C.
Seek the solar module data sheet for a
list of standard test condition (STC) data,
temperature coefficients, and any special
module-related information to determine
the low-temperature open circuit voltage.
The prevailing industry practice, requires
the use of the site’s Extreme Annual Mean
Minimum Design Dry BulbTemperature
data, available in the ASHRAE Handbook.
Code requires that the resulting
maximum voltage (Voc) when added
in the “string of modules” be under
maximum system voltage. Record low
temperatures provide an indication of
system performance when tempera
tures
drop to these levels. Power Xpert Solar
inverters are designed to 1000Vdc and
1500Vdc standards.
HighTemperature Equation
Once the maximum number of modules
per string is established, the minimum
number of modules per string needs to
be calculated. Here, more site-related
aspects come into play, as the voltage of
solar modules decreases with increasing
tempera
ture.The modules’ (photovoltaic
cell) temperature is influenced by the
ambient temperature, reflected sun-loads
from nearby structures, parapet walls,
roof-coatings, etc.
Air-flow above and behind the solar
modules affect the cell temperature.The
accepted industry standards to add to the
module heating are listed below. Unusual
mounting systems may adjust these
figures, and it is best to seek assistance
in establishing and planning such
installations.
■ 15–20 °C for ground or pole mounted
solar systems
■ 20–25 °C for roof-top solar systems
mounted at inclined angles (offers
improved air-flow behind the modules)
■ 25–30 °C for roof-top solar systems
mounted flat, yet at least 6.00 inches
(152.4 mm) above the roof surface
Vmp_min =Vmp + (temp-differential x
temp-coefficient-of-Vmp)
The temp-differential in this case includes
the above temperature “adders.
”TheVmp
and related temperature coefficients are
listed on the solar module’s data sheets.

While the code doesn’t indicate the high
temperature to use (i.e., because it is
an equipment application issue), the
industry standard is to evaluate the
ASHRAE 2% high temperature figures,
coupled to known location differences.
Record high temperatures provide an
indication of system performance when
climatic condition reaches these levels.
Beyond the damaging temperature affects
on photovoltaic moduleVmp voltage
levels, voltage drop in PV conductors
under such conditions also need to be
calculated and evaluated, beyond normal
temperatures.The inverter only uses
(knows) theVmp voltage at the inverter,
not at the PV modules.
Increasing grid voltages also puts a
constraint on the minimumVmp voltage
at the DC input stage.
To ensure the full MPPT range without
power-clipping (reduced power output),
prudent PV system designs shall con
sider
the PV array’sVmp voltage drop to the
point of the inverter connection, ambient
temperatures and the PV system
installation type’s effects onVmp, solar
module miss-match and tolerance
variations, degradation of solar modules
over time (solar system life), etc.Typical
Vmp design values, based upon known
and expected conditions are 5–10% over
the minimum MPPT tracking voltage.
Reference NEC 2017 Section 690 and 691,
Solar Photovoltaic Systems.
Emergency Power
Most areas have requirements for
emergency and standby power systems.
The National Electrical Code does not
specifically call for any emergency or
standby power, but does have require
ments for those systems when they
are legally mandated and classed as
emergency (Article 700), legally required
standby (Article 701) by municipal,
state, federal or other codes, or by any
governmental agency having jurisdic
tion.
Optional standby systems, not legally
required, are also covered in the NEC
(Article 702).
Emergency systems are intended to
supply power and illumination essen
tial
for safety to human life, when the normal
supply fails. NEC requirements are
stringent, requiring periodic testing under
load and automatic transfer to emergency
power supply on loss of normal supply.
See Figure 97.
All wiring from emergency source to
emergency loads must be kept separate
from all other wiring and equipment, in
its own distribution and raceway system,
except in transfer equipment enclosures
and similar locations.
The most common power source for
large emergency loads is an engine-
generator set, but the NEC also permits
the emergency supply (subject to local
code requirements) to be storage
batteries, uninterruptible power supplies,
a separate emergency service, or a
connection to the service ahead of
the normal service discon
necting
means. Unit equipment for emergency
illumination, with a rechargeable battery,
a charger to keep it at full capacity when
normal power is on, one or more lamps,
and a relay to connect the battery to
the lamps on loss of normal power, is
also permitted.
Because of the critical nature of
emergency power, ground fault
protection is not required. It is considered
preferable to risk arcing damage, rather
than to disconnect the emergency supply
completely. For emergency power,
ground fault alarm is required by NEC
700.5(D) to indicate a ground fault in
solidly grounded wye emergency
systems of more than 150 V to ground
and circuit-protective devices rated
1000 A or more.
Legally required standby systems, as
required by the governmental agency
having jurisdiction, are intended to
supply power to selected loads, other
than those classed as emergency
systems, on loss of normal power.
These are usually loads not essential to
human safety, but loss of which could
create hazards or hamper rescue or
fire-fighting operations.
NEC requirements are similar to those for
emergency systems, except that wiring
may occupy the same distribu
tion and
raceway system as the normal wiring if
desired. Optional standby systems are
those not legally required, and are
intended to protect private business or
property where life safety does not depend
on performance of the system. Optional
systems can be treated as part of the
normal building wiring system. Both
legally required and optional standby
systems should be installed in such a
manner that they will be fully avail
able on
loss of normal power. It is preferable to
isolate these systems as much as possible,
even though not required by code.
Where the emergency or standby source,
such as an engine generator or separate
service, has capacity to supply the entire
system, the transfer scheme can be either
a full-capacity automatic transfer switch,
or, less costly but equally effective,
normal and emergency main circuit
breakers, electrically interlocked such
that on failure of the normal supply the
emergency supply is connected to the
load. However, if the emergency or
standby source does not have capacity
for the full load, as is usually the case,
such a scheme would require automatic
disconnection of the nonessential loads
before transfer.
A simpler and more economical approach
is a separate emergency bus, supplied
through an automatic transfer switch, to
feed all critical loads.The transfer switch
connects this bus to the normal supply,
in normal operation. On failure of the
normal supply, the engine-generator is
started, and when it is up to speed the
automatic switch transfers the emergency
loads to this source. On return of the
normal source, manual or automatic
retransfer of the emergency loads can
take place.
Peak Shaving
Many installations now have emergency
or standby generators. In the past, they
were required for hospitals and similar
locations, but not common in office
buildings or shopping centers. However,
many costly and unfortunate experiences
during utility blackouts in recent years
have led to the more frequent installa
tion
of engine generators in commer
cial and
institutional systems for safety and for
supplying important loads.
Industrial plants, especially in process
industries, usually have some form
of alternate power source to prevent
extremely costly shutdowns.These
standby generating systems are critical
when needed, but they are needed only
infrequently.They represent a large
capital investment.To be sure that their
power will be available when required,
they should be tested periodically
under load.
129

Figure 97. Typical Emergency Power System
The cost of electric energy has risen to
new high levels in recent years, and
utilities bill on the basis not only of power
consumed, but also on the basis of peak
demand over a small interval. As a result,
a new use for in-house generating
capacity has developed. Utilities measure
demand charges on the basis of the
maximum demand for electricity in any
given specific period (typically 15 or
30 minutes) during the month. Some
utilities have a demand “ratchet clause”
that will continue demand charges on a
given peak demand for a full year, unless
a higher peak results in even higher
charges. One large load, coming on at
a peak time, can create higher electric
demand charges for a year.
Obviously, reducing the peak demand can
result in considerable savings in the cost of
electrical energy. For those installations
with engine generators for emergency
use, modern control systems (computers
or programmable controllers) can monitor
the peak demand, and start the engine-
generator to supply part of the demand as
it approaches a preset peak value.
The engine-generator must be selected
to withstand the required duty cycle.
The simplest of these schemes transfer
specific loads to the generator. More
complex schemes operate the generator
in parallel with the normal utility supply.
The savings in demand charges can
reduce the cost of owning the emergency
generator equipment.
In some instances, utilities with little
reserve capacity have helped finance the
cost of some larger customer-owned
generating equipment. In return, the
customer agrees to take some or all of his
load off the utility system and on to his
own generator at the request of the utility
(with varying limitations) when the utility
load approaches capacity.
In some cases, the customer’s generator
is paralleled with the utility to help supply
the peak utility loads, with the utility
buying the supplied power. Some utilities
have been able to delay large capital
expenditures for additional generating
capacity by such arrangements.
It is important that the electrical sys
tem
designer providing a substantial source
of emergency and standby power
investigate the possibility of using it
for peak shaving, and even of partial
utility company financing. Frequently,
substantial savings in power costs can
be realized for a small additional outlay
in distribution and control equipment.
Peak shaving equipment operating in
parallel with the utility are subject to
the comments made under cogeneration
as to separation from the utility under
fault conditions.
To Normal
Distribution
Circuits
Optional Remote PC
with Software
N
LP1
ATS4
BP1 LP2 BP2 LP3 BP3 LP4 BP4
EDP1 EDP2 EDP3 EDP4
ATS3
ATS2
ATS1 E N E N E N E
To Emergency
Circuits
D1 D2 D3 D4
52G1 52G2 52G3 52G4
G1 G2 G3 G4
Main
Service
HMI
Touchscreen
Revenue
Metering
Utility
Source
Paralleling Switchgear
with Distribution
Typical Application: Three engine generator sets serve the load, plus one additional engine
generator set for redundancy to achieve N+1 level of performance. Open or Closed transition is available.

Codes and Standards
The National Electrical Code (NEC), NFPA
Standard No. 70, is the most prevalent
electrical code in the United States.The
NEC, which is revised every three years,
has no legal standing of its own, until it is
adopted as law by a jurisdiction, which
may be a city, county or state. Most
jurisdictions adopt the NEC in its entirety;
some adopt it with variations, usually
more rigid, to suit local conditions and
requirements. A few large cities, such as
NewYork and Chicago, have their own
electrical codes, basically similar to
the NEC.The designer must deter
mine
which code applies in the area of a
specific project.
The Occupational Safety and Health
Act (OSHA) of 1970 sets uniform
national requirements for safety in the
workplace—anywhere that people are
employed. Originally OSHA adopted the
1971 NEC as rules for electrical safety.
As the NEC was amended every three
years, the involved process for modifying
a federal law such as OSHA made it
impossible for the act to adopt each new
code revision.To avoid this problem, the
OSHA administration in 1981 adopted its
own code, a con
densed version of the
NEC containing only those provisions
considered related to occupational safety.
OSHA was amended to adopt this code,
based on NFPA Standard 70E, Part 1,
which is now federal law.
The NEC is a minimum safety standard.
Efficient and adequate design usually
requires not just meeting, but often
exceeding NEC requirements to provide
an effective, reliable, economical
electrical system.
Many equipment standards have been
established by the National Electrical
Manufacturers’ Association (NEMA) and
the American National Standards Institute
(ANSI). Underwriters Laboratories (UL)
has standards that equipment must meet
before UL will list or label it. Most
jurisdictions and OSHA require that
where equipment listed as safe by a
recognized labora
tory is available,
unlisted equipment may not be used.
UL is by far the most widely accepted
national laboratory, although Factory
Mutual Insurance Company lists some
equipment, and a number of other testing
laboratories have been recognized and
accepted.The Institute of Electrical and
Electronic Engineers (IEEE) publishes a
number of books (the “color book” series)
on recommended practices for the design
of industrial buildings, commercial
buildings, emergency power systems,
grounding, and the like. Most of these
IEEE standards have been adopted as
ANSI standards.They are excellent
guides, although they are not in any
way mandatory.
A design engineer should conform to all
applicable codes, and require equipment
to be listed by UL or another recognized
testing laboratory wherever possible, and
to meet ANSI or NEMA standards. ANSI/
IEEE recommended practices should be
followed to a great extent. In many cases,
standards should be exceeded to get a
system of the quality required.The design
goal should be a safe, efficient, long-
lasting, flexible and economical electrical
Professional Organizations
American National Standards Institute (ANSI)
Headquarters:
1899 L Street, NW
11th Floor
Washington, DC 20036
202-293-8020
Operations:
25West 43rd Street
4th Floor
NewYork, NY 10036
212-642-4900
www.ansi.org
Institute of Electrical and Electronic
Engineers (IEEE)
Headquarters:
3 Park Avenue
17th Floor
NewYork, NY 10016-5997
212-419-7900
Operations:
445 and 501 Hoes Lane
Piscataway, NJ 08854-4141
732-981-0060
www.ieee.org
International Association of Electrical
Inspectors (IAEI)
901WaterfallWay
Suite 602
Richardson,TX 75080-7702
972-235-1455
www.iaei.org
National Electrical Manufacturers
Association (NEMA)
1300 North 17th Street
Suite 900
Arlington,VA 22209
703-841-3200
www.nema.org
National Fire Protection Association (NFPA)
1 Batterymarch Park
Quincy, MA 02169-7471
617-770-3000
www.nfpa.org
Underwriters Laboratories (UL)
333 Pfingsten Road
Northbrook, IL 60062-2096
847-272-8800
www.ul.com
International Code Council (ICC)
500 New Jersey Avenue, NW
6th Floor
Washington, DC 20001
1-888-422-7233
www.iccsafe.org
The American Institute of Architects (AIA)
1735 NewYork Avenue, NW
Washington, DC 20006-5292
1-800 242-3837
www.aia.org
Reference Data
131

Table 56. Selected IEEE Device Numbers for Switchgear Apparatus
Device
Number
Function Definition Typical
Uses
2 Time-delay starting or closing relay A device that functions to give a desired amount of
time delay before or after any point of operation in a
switching sequence or protective relay system, except
as specifically provided by device functions 48, 62
and 79 described later.
Used for providing a time-delay for re-transfer
back to the normal source in an automatic
transfer scheme.
6 Starting circuit breaker A device whose principal function is to connect
a machine to its source of starting voltage.
—
19 Starting to running transition timer A device that operates to initiate or cause the
automatic transfer of a machine from the starting
to the running power connection.
Used to transfer a reduced voltage starter from
starting to running.
21 Distance relay A device that functions when the circuit admittance,
impedance or reactance increases or decreases
beyond predetermined limits.
—
23 Temperature control device A device that functions to raise or to lower the
temperature of a machine or other apparatus, or
of any medium, when its temperature falls below
or rises above, a predetermined level.
Used as a thermostat to control space heaters in
outdoor equipment.
24 Volts per hertz relay A device that operates when the ratio of voltage
to frequency is above a preset value or is below
a different preset value.The relay may have
any combination of instantaneous or time
delayed characteristics.
ETR-5000 transformer protective relays,
EGR-5000 generator protective relay.
25 Synchronizing or synchronism
check device
A device that operates when two AC circuits are within
the desired limits of frequency, phase angle or voltage,
to permit or cause the paralleling of these two circuits.
In a closed transition breaker transfer, a
25 relay is used to ensure two-sources are
synchronized before paralleling. Eaton
EDR-5000 feeder protective relays, EGR-5000
generator protective relay.
27 Undervoltage relay A device which functions on a given value
of undervoltage.
Used to protect a motor or other devices from
a sustained under-voltage and/or initiate an
automatic transfer when a primary source of
power is lost. Eaton EDR feeder protective relay,
EMR-4000/EMR-5000 motor protective relays,
ETR-5000 transformer protective relay, EGR-5000
30 Annunciator relay A non-automatically reset device that gives a number
of separate visual indications upon the functioning of
protective devices, and which may also be arranged to
perform a lockout function.
Used to remotely indicate that a protective relay
has functioned, or that a circuit breaker has
tripped.Typically, a mechanical “drop” type
annunciator panel is used.
32 Directional power relay A relay that functions on a desired value of power
flow in a given direction, or upon reverse power
resulting from arc back in the anode or cathode
circuits of a power rectifier.
Used to prevent reverse power from feeding
an upstream fault. Often used when primary
backup generation is used in a facility. Eaton
EDR-5000 feeder protective relay, EMR-4000/
EMR-5000 motor protective relays, ETR-5000
transformer protective relay, EGR-5000 generator
protective relay.
33 Position switch A device that makes or breaks contact when the main
device or piece of apparatus, which has no device
function number, reaches a given point.
Used to indicate the position of a drawout circuit
breaker (TOC switch).
34 Master sequence device A device such as a motor-operated multi-contact
switch, or the equivalent, or a programmable device,
that establishes or determines the operating sequence
of the major devices in equipment during starting and
stopping, or during sequential switching operations.
—
37 Undercurrent or underpower relay A relay that functions when the current or power
flow decreases below a predetermined value.
Eaton EMR-3000, EMR-4000, EMR-5000 motor
protective relays.
38 Bearing protective device A device that functions on excessive bearing
temperature, or on other abnormal mechanical
conditions, such as undue wear, which may
eventually result in excessive bearing temperature.
—
40 Field relay A device that functions on a given or abnormally
high or low value or failure of machine field current,
or on an excessive value of the reactive component
of armature current in an AC machine indicating
abnormally high or low field excitation.
41 Field circuit breaker A device that functions to apply, or to remove,
the field excitation of a machine.
—
Reference Data

Table 56. Selected IEEE Device Numbers for Switchgear Apparatus (Continued)
Device
Number
Uses
42 Running circuit breaker A device whose function is to connect a machine to its
source of running or operating voltage.This function
may also be used for a device, such as a contactor,
that is used in series with a circuit breaker or other
fault-protecting means, primarily for frequent opening
and closing of the circuit.
—
43 Manual transfer or selector device A manually operated device that transfers control
or potential circuits in order to modify the plan of
operation of the associated equipment or of some
of the associated devices.
—
44 Unit sequence starting relay A device that functions to start the next available
unit in multiple-unit equipment upon the failure or
non-availability of the normally preceding unit.
—
46 Reverse-phase, or phase balance,
current relay
A relay that functions when the polyphase currents are
of reverse-phase sequence, or when the polyphase
currents are unbalanced or contain the negative
phase-sequence components above a given amount.
Eaton EDR-3000/EDR-5000 feeder protective
relay, EMR-3000/EMR-4000/EMR-5000
motor protective relays, ETR-5000
transformer protective relay, EGR-5000
47 Phase-sequence voltage relay A relay that functions upon a predetermined value of
polyphase voltage in the desired phase sequence.
Eaton EDR-5000 feeder protective relay,
48 Incomplete sequence relay A relay that generally returns the equipment to the
normal, or off, position and locks it out of the normal
starting, or operating or stopping sequence is not
properly completed within a predetermined amount of
time. If the device is used for alarm purposes only, it
should preferably be designated as 48 A (alarm).
EMR-3000/EMR-4000/EMR-5000 motor
protective relays.
49 Machine, or transformer, thermal relay A relay that functions when the temperature of a
machine armature, or other load carrying winding or
element of a machine, or the temperature of a power
rectifier or power transformer (including a power
rectifier transformer) exceeds a predetermined value.
Eaton EMR-3000/EMR-4000/EMR-5000 motor
protective relays, ETR-4000/ETR-5000
transformer protective relay, EGR-5000 generator
protective relay. (Note:When used with external
RTD module.)
50 Instantaneous overcurrent,
or rate-of-rise relay
A relay that functions instantaneously on an excessive
value of current, or an excessive rate of current rise,
thus indicating a fault in the apparatus of the circuit
being protected.
Used for tripping a circuit breaker
instantaneously during a high-level short
circuit. Can trip on phase-phase (50), phase-
neutral (50N), phase-ground (50G) faults. Eaton
EDR-3000/EDR-5000 protective relays, MP-3000/
MP-4000/EMR-3000/EMR-4000/EMR-5000
motor protective relays, ETR-4000/ETR-5000
51 AC time overcurrent relay A relay with either a definite or inverse time
characteristic that functions when the current in
an AC circuit exceeds a predetermined value.
Used for tripping a circuit breaker after a time
delay during a sustained overcurrent. Used for
tripping a circuit breaker instantaneously during
a high-level short circuit. Can trip on phase (51),
neutral (51N) or ground (51G) overcurrents.
Eaton EDR-3000/EDR-5000 protective relays,
MP-3000/MP-4000/EMR-3000/EMR-4000/
EMR-5000 motor protective relays, ETR-4000/
52 AC circuit breaker A device that is used to close and interrupt an AC
power circuit under normal conditions or to interrupt
this circuit under fault or emergency conditions.
A term applied typically to medium voltage
circuit breakers, or low voltage power circuit
breakers. EatonVCP vacuum circuit breaker,
magnum DS low voltage power circuit breaker.
53 Exciter or DC generator relay A device that forces the DC machine field excitation to
build up during starting or that functions when the
machine voltage has built up to a given value.
—
55 Power factor relay A relay that operates when the power factor in an AC
circuit rises above or below a predetermined value.
Eaton EDR-5000 feeder protective relay and
56 Field application relay A device that automatically controls the application
of the field excitation to an AC motor at some
predetermined point in the slip cycle.
—
133
Reference Data

Table 56. Selected IEEE Device Numbers for Switchgear Apparatus (Continued)
Device
Number
Uses
59 Overvoltage relay A relay that functions on a given value of overvoltage. Used to trip a circuit breaker, protecting
downstream equipment from sustained
overvoltages. Eaton EDR-5000 feeder protective
relay and EMR-4000/EMR-5000 motor protective
relays, ETR-5000 transformer protective relay,
60 Voltage or current balance relay A relay that operates on a given difference in voltage,
or current input or output of two circuits.
—
62 Time-delay stopping or opening relay A time-delay relay that serves in conjunction with the
device that initiates the shutdown, stopping or opening
operation in an automatic sequence.
Used in conjunction with a 27 device to delay
tripping of a circuit breaker during a brief loss of
primary voltage, to prevent nuisance tripping.
63 Pressure switch A switch that operates on given values or on a given
rate of change of pressure.
Used to protect a transformer during a rapid
pressure rise during a short circuit.This device
will typically act to open the protective devices
above and below the transformer.Typically
used with a 63-X auxiliary relay to trip the
circuit breaker.
64 Ground protective relay A relay that functions on a failure of the insulation of a
machine, transformer or of other apparatus to ground,
or on flashover of a DC machine to ground.
Used to detect and act on a ground-fault
condition. In a pulsing high resistance grounding
system, a 64 device will initiate the alarm.
65 Governor A device consisting of an assembly of fluid, electrical or
mechanical control equipment used for regulating the
flow of water, steam or other media to the prime mover
for such purposes as starting, holding speed or load,
or stopping.
—
66 Notching or jogging device A device that functions to allow only a specified
number of operations of a given device, or equipment,
or a specified number of successive operations within
a given time of each other. It also functions to energize
a circuit periodically or for fractions of specified time
intervals, or that is used to permit intermittent
acceleration or jogging of a machine at low speeds
for mechanical positioning.
Eaton EMR-3000/EMR-4000/EMR-5000 motor
protective relays.
67 AC directional overcurrent relay A relay that functions on a desired value of AC
overcurrent flowing in a predetermined direction.
Eaton EDR-5000 feeder protective relay,
69 Permissive control device A device that is generally a two-position manually
operated switch that in one position permits the closing
of a circuit breaker, or the placing of equipment into
operation, and in the other position prevents the circuit
breaker to the equipment from being operated.
Used as a remote-local switch for circuit
breaker control.
71 Level switch A switch that operates on given values, or on a given
rate of change of level.
Used to indicate a low liquid level within a
transformer tank in order to save transformers
from loss-of-insulation failure. An alarm contact
is available as a standard option on a liquid level
gauge. It is set to close before an unsafe
condition actually occurs.
72 DC circuit breaker A device that is used to close and interrupt a DC power
circuit under normal conditions or to interrupt this
circuit under fault or emergency conditions.
—
73 Load-resistor contactor A device that is used to shunt or insert a step of load
limiting, shifting or indicating resistance in a power
circuit; to switch a space heater in circuit; or to switch
a light or regenerative load resistor of a power rectifier
or other machine in and out of circuit.
—
74 Alarm relay A device other than an annunciator, as covered under
device number 30, which is used to operate, or to
operate in connection with, a visible or audible alarm.
—
78 Phase-angle measuring relay A device that functions at a predetermined phase angle
between two voltages, between two currents,
or between voltage and current.
EDR-5000 feeder protective relay, EMR-4000/
EMR-5000 motor protective relays, ETR-5000
generator protective relay. (Note: ForVoltage
Only—78V.)
Reference Data

Table 56 Selected IEEE Device Numbers for Switchgear Apparatus (Continued)
Device
Number
Uses
79 AC reclosing relay A relay that controls the automatic closing and locking
out of an AC circuit interrupter.
Used to automatically reclose a circuit breaker
after a trip, assuming the fault has been cleared
after the power was removed from the circuit.
The recloser will lock-out after a predetermined
amount of failed attempts to reclose. EDR-5000
feeder protective relay, ETR-5000 transformer
protective relay, EGR-5000 generator protective
relay.
81 Frequency relay A relay that functions on a predetermined value of
frequency—either under or over, or on normal system
frequency—or rate of change frequency.
Used to trip a generator circuit breaker in the
event the frequency drifts above or below a given
value. Eaton EDR-5000 feeder protective relay
and EMR-4000/EMR-5000 motor protective
relays, ETR-5000 transformer protective relay,
83 Automatic selective control or
transfer relay
A relay that operates to select automatically between
certain sources or conditions in equipment, or
performs a transfer operation automatically.
Used to transfer control power sources in a
double-ended switchgear lineup.
85 Carrier or pilot-wire relay A device that is operated or restrained by a signal
transmitted or received via any communications
media used for relaying.
—
86 Locking-out relay An electrically operated hand, or electrically, reset
relay that functions to shut down and hold an
equipment out of service on the occurrence of
abnormal conditions.
Used in conjunction with protective relays to
lock-out a circuit breaker (or multiple circuit
breakers) after a trip.Typically required to be
manually reset by an operator before the breaker
can be reclosed.
87 Differential protective relay A protective relay that functions on a percentage or
phase angle or other quantitative difference of two
currents or of some other electrical quantities.
Used to protect static equipment, such as cable,
bus or transformers, by measuring the current
differential between two points.Typically the
upstream and/or downstream circuit breaker will
be incorporated into the “zone of protection.
”
Eaton EBR-3000 bus differential relay, ETR-4000/
ETR-5000 transformer protective relays,
EMR-5000 motor protective relay, EGR-5000
90 Regulating device A device that functions to regulate a quantity or
quantities, such as voltage, current, power, speed,
frequency, temperature and load, at a certain value or
between certain (generally close) limits for machines,
tie lines or other apparatus.
—
91 Voltage directional relay A device that operates when the voltage across an
open circuit breaker or contactor exceeds a given
value in a given direction.
—
94 Tripping or trip-free relay A relay that functions to trip a circuit breaker, contactor
or equipment, or to permit immediate tripping by
other devices, or to prevent immediate reclosure of a
circuit interrupter, in case it should open automatically
even though its closing circuit is maintained closed.
—
135
Reference Data

Suggested IEEE Designations
for Suffix Letters
Auxiliary Devices
These letters denote separate auxiliary
devices, such as the following:
C Closing relay/contactor
CL Auxiliary relay, closed
(energized when main
device is in closed position)
CS Control switch
D “Down” position switch relay
L Lowering relay
O Opening relay/contactor
OP Auxiliary relay, open
(energized when main
device is in open position)
PB Push button
R Raising relay
U “UP” position switch relay
X Auxiliary relay
Y Auxiliary relay
Z Auxiliary relay
Actuating Quantities
These letters indicate the condition or
electrical quantity to which the device
responds, or the medium in which it is
located, such as the following:
A Amperes/alternating
C Current
F Frequency/fault
I0 Zero sequence current
I-, I2 Negative sequence current
I+, I1 Positive sequence current
P Power/pressure
PF Power factor
S Speed
T Temperature
V Voltage/volts/vacuum
VAR Reactive power
VB Vibration
W Watts
Main Device
The following letters denote the main
device to which the numbered device is
applied or is related:
A Alarm/auxiliary power
AC Alternating current
BP Bypass
BT Bus tie
C Capacitor
DC Direct current
E Exciter
F Feeder/field
G Generator/ground
M Motor/metering
MOC Mechanism operated contact
S Synchronizing/secondary
T Transformer
TOC Truck-operated contacts
Main Device Parts
These letters denote parts of the
main device, except auxiliary con
tacts,
position switches, limit switches and
torque limit switches:
C Coil/condenser/capacitor
CC Closing coil/closing contactor
HC Holding coil
M Operating motor
OC Opening contactor
S Solenoid
SI Seal-in
T Target
TC Trip coil
Other Suffix Letters
The following letters cover all other
distinguishing features, characteristics or
conditions not specifically described in
Auxiliary Devices through Main Device
Parts, which serve to describe the use of
the device in the equipment, such as:
A Automatic
BF Breaker failure
C Close
D Decelerating/down
E Emergency
F Failure/forward
HS High speed
L Local/lower
M Manual
O Open
OFF Off
ON On
R Raise/reclosing/remote/reverse
T Test/trip
TDC Time-delay closing contact
TDDO Time delayed relay coil drop-out
TDO Time-delay opening contact
TDPU Time delayed relay coil pickup
THD Total harmonic distortion
Reference Data

Enclosures
The following are reproduced from NEMA 250.
Table57.ComparisonofSpecificApplicationsofEnclosuresforIndoorNonhazardousLocations
EnclosureType
1 a 2 a 4 4X 5 6 6P 12 12K 13
Falling dirt
Falling liquids and light splashing
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
Circulating dust, lint, fibers and flyings b
Settling airborne dust, lint, fibers and flyings b
Hosedown and splashing water
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
Oil and coolant seepage
Oil or coolant spraying and splashing
Corrosive agents n n
n n n
n
n n
n
a These enclosures may be ventilated.
b These fibers and flying are nonhazardous materials and are not considered the Class III type ignitable
fibers or combustible flyings. For Class III type ignitable fibers or combustible flyings, see the National
Electrical Code, Article 500.
Table 58. Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations
EnclosureType
3 3R c 3S 4 4X 6 6P
Rain, snow and sleet d
Sleet e
n
n
n
n
n
n
n
n
n
n
n
n
n
n
n
Windblown dust
Hosedown
Corrosive agents
n n n
n
n
n
n
n
n
n
n
n
n n
n
c These enclosures may be ventilated.
d External operating mechanisms are not required to be operable when the enclosure is ice covered.
e External operating mechanisms are operable when the enclosure is ice covered.
Table 59. Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations
Provides a Degree of ProtectionAgainst
AtmospheresTypically Containing
(For Complete Listing, See NFPA 497M)
Class EnclosureTypes
7 and 8, Class I Groups f
EnclosureType
9, Class II Groups f
A B C D E F G 10
Acetylene
Hydrogen, manufactured gas
diethyl ether, ethylene, cyclopropane
I
I
I
n
n
n
Gasoline, hexane, butane, naphtha, propane,
acetone, toluene, isoprene
Metal dust
Carbon black, coal dust, coke dust
I
II
II
n
n
n
Flour, starch, grain dust
Fibers, flyings g
Methane with or without coal dust
II
III
MSHA
n
n
n
f For Class III type ignitable fibers or combustible flyings, see the National Electrical Code, Article 500.
g Due to the characteristics of the gas, vapor or dust, a product suitable for one class or group may not be
suitable for another class or group unless so marked on the product.
Note: If the installation is outdoors and/or additional protection is required by Table 57 and
Table 58, a combination-type enclosure is required.
137
Reference Data

Table 60. Conversion of NEMA Enclosure Type Ratings to IEC 60529 Enclosure Classification Designations (IP)
(Cannot be Used to Convert IEC Classification Designations to NEMA Type Ratings)
NEMA Enclosure Type
IP
First
Character
IP
Second
Character
IP0–
IP1–
IP2–
IP3–
IP4–
IP5–
IP6–
IP–0
IP–1
IP–2
IP–3
IP–4
IP–5
IP–6
IP–7
IP–8
1 2 3 4
3R 5 6 6P 12 13
12K
3S 4X
A B A B A B A B A B A B A B A B A B A B A B A B A B
A = A shaded block in the “A” column indicates that the NEMA Enclosure Type exceeds the requirements for the respective IEC 60529
IP First Character Designation. The IP First Character Designation is the protection against access to hazardous parts and solid
foreign objects.
B = A shaded block in the “B” column indicates that the NEMA Enclosure Type exceeds the requirements for the respective IEC 60529
IP Second Character Designation. The IP Second Character Designation is the protection against the ingress of water.
EXAMPLE OF TABLE USE
An IEC IP45 Enclosure Rating is specified. What NEMA Type Enclosures meet and exceed the IP45 rating?
Referencing the first character, 4, in the IP rating and the row designated “IP4–” in the leftmost column in the
table; the blocks in Column “A” for NEMA Types 3, 3S, 4, 4X, 5, 6, 6P, 12, 12K and 13 are shaded. These NEMA
ratings meet and exceed the IEC protection requirements against access to hazardous parts and solid foreign
objects. Referencing the second character, 5, in the IP rating and the row designated “IP–5” in the rightmost
column in the table; the blocks in Column “B” for NEMA Types 3, 3S, 4, 4X, 6 and 6P are shaded. These NEMA
ratings meet and exceed the IEC requirements for protection against the ingress of water. The absence of shading
in Column “B” beneath the “NEMA Enclosure Type 5” indicates that Type 5 does not meet the IP45 protection
requirements against the ingress of water. Likewise, the absence of shading in Column “B” for NEMA Type 12,
12K and 13 enclosures indicates that these enclosures do not meet the IP45 requirements for protection against
the ingressof water. Only Types 3, 3S, 4, 4X, 6 and 6P have both Column “A” in the “IP4–” row and Column “B”
in the “IP–5” row shaded and could be used in an IP45 application.
The NEMA Enclosure Type 3 not only meets the IP45 Enclosure Rating, but also exceeds the IEC requirements
because the NEMA Type requires an outdoor corrosion test; a gasket aging test; a dust test; an external icing
test; and no water penetration in the rain test. Slight differences exist between the IEC and NEMA test methods,
but the IEC rating permits the penetration of water if “it does not deposit on insulation parts, or reach live parts.”
The IEC rating does not require a corrosion test; gasket aging test; dust test or external icing test. Because the
NEMA ratings include additional test requirements, this table cannot be used to select IP Designations for NEMA
rated enclosure specifications.
IEC 60529 specifies that an enclosure shall only be designated with a stated degree of protection indicated by
the first characteristic numeral if it also complies with all lower degrees of protection. Furthermore, IEC 60529
states that an enclosure shall only be designated with a degreeof protection indicated by the second characteristic
numeral if it also complies with all lower degrees of protection up to and including the secondcharacteristic
numeral 6. An enclosure designated with a second characteristic numeral 7 or 8 only is considered unsuitable
for exposure to water jets (designated by second characteristic numeral 5 or 6) and need not comply with
requirements for numeral 5 or 6 unless it is dual coded. Because the IEC protection requirements become more
stringent with increasing IP character value up through 6, once a NEMA Type rating meets the requirements for
an IP designation up through 6, it will also meet the requirements for all lower IP designations. This is apparent
from the shaded areas shown in the table.
Reference Data

Average Characteristics of 600 V
Conductors—Ohms per 1000 ft (305 m)
The tables below are average
characteristics based on data from IEEE
Standard 141-1993.Values from different
sources vary because of operating
temperatures, wire stranding, insulation
materials and thicknesses, overall
diameters, random lay of multiple
conductors in conduit, conductor spacing,
and other divergences in materials, test
conditions and calculation methods.
These tables are for 600V 5 kV and 15 kV
conductors, at an average temperature
of 75 °C. Other parame
ters are listed in
the notes. For medium voltage cables,
differences among manufacturers are
consider
ably greater because of the wider
vari
ations in insulation materials and
thicknesses, shielding, jacketing, over
all
diameters, and the like.Therefore, data
for medium voltage cables should be
obtained from the manufacturer of the
cable to be used.
Application Notes
■ Resistance and reactance are phase-
to-neutral values, based on 60 Hz AC,
three-phase, four-wire distribution, in
ohms per 100 ft (30 m) of circuit length
(not total conductor lengths)
■ Based upon conductivity of 100% for
copper, 61% for aluminum
■ Based on conductor temperatures
of 75 °C. Reactance values will have
negligible variation with temperature.
Resistance of both copper and
aluminum conductors will be
approximately 5% lower at 60 °C
or 5% higher at 90 °C. Data shown in
tables may be used without significant
error between 60 ° and 90 °C
■ For interlocked armored cable, use
magnetic conduit data for steel armor
and non-magnetic conduit data for
aluminum armor
■
■ For busway impedance data,
see Eaton’s Low-Voltage Busway
Design Guide
■ For PF (power factor) values less
than 1.0, the effective impedance
Ze
is calculated from
Ze
= R x PF + X sin (arc cos PF)
■ For copper cable data, resistance based
on tinned copper at 60 Hz; 600V and
5 kV nonshielded cable based on
varnished cambric insula
tion; 5 kV
shielded and 15 kV cable based on
neoprene insulation
■ For aluminum cable data, cable is
cross-linked polyethylene insulated
Table 61. 60 Hz Impedance Data for Three-Phase Copper Cable Circuits, in Approximate Ohms per 1000 ft (305 m) at 75 °C (a) Three Single Conductors
Wire Size,
AWG or
kcmil
In Magnetic Duct In Non-Magnetic Duct
600V and 5 kV Non-Shielded 5 kV Shielded and 15 kV 600V and 5 kV Non-Shielded 5 kV Shielded and 15 kV
R X Z R X Z R X Z R X Z
8
8 (solid)
6
6 (solid)
0.811
0.786
0.510
0.496
0.0754
0.0754
0.0685
0.0685
0.814
0.790
0.515
0.501
0.811
0.786
0.510
0.496
0.0860
0.0860
0.0796
0.0796
0.816
0.791
0.516
0.502
0.811
0.786
0.510
0.496
0.0603
0.0603
0.0548
0.0548
0.813
0.788
0.513
0.499
0.811
0.786
0.510
0.496
0.0688
0.0688
0.0636
0.0636
0.814
0.789
0.514
0.500
4
4 (solid)
2
1
0.321
0.312
0.202
0.160
0.0632
0.0632
0.0585
0.0570
0.327
0.318
0.210
0.170
0.321
0.312
0.202
0.160
0.0742
0.0742
0.0685
0.0675
0.329
0.321
0.214
0.174
0.321
0.312
0.202
0.160
0.0506
0.0506
0.0467
0.0456
0.325
0.316
0.207
0.166
0.321
0.312
0.202
0.160
0.0594
0.0594
0.0547
0.0540
0.326
0.318
0.209
0.169
1/0
2/0
3/0
4/0
0.128
0.102
0.0805
0.0640
0.0540
0.0533
0.0519
0.0497
0.139
0.115
0.0958
0.0810
0.128
0.103
0.0814
0.0650
0.0635
0.0630
0.0605
0.0583
0.143
0.121
0.101
0.0929
0.127
0.101
0.0766
0.0633
0.0432
0.0426
0.0415
0.0398
0.134
0.110
0.0871
0.0748
0.128
0.102
0.0805
0.0640
0.0507
0.0504
0.0484
0.0466
0.138
0.114
0.0939
0.0792
250
300
350
400
0.0552
0.0464
0.0378
0.0356
0.0495
0.0493
0.0491
0.0490
0.0742
0.0677
0.0617
0.0606
0.0557
0.0473
0.0386
0.0362
0.0570
0.0564
0.0562
0.0548
0.0797
0.0736
0.0681
0.0657
0.0541
0.0451
0.0368
0.0342
0.0396
0.0394
0.0393
0.0392
0.0670
0.0599
0.0536
0.0520
0.0547
0.0460
0.0375
0.0348
0.0456
0.0451
0.0450
0.0438
0.0712
0.0644
0.0586
0.0559
450
500
600
750
0.0322
0.0294
0.0257
0.0216
0.0480
0.0466
0.0463
0.0495
0.0578
0.0551
0.0530
0.0495
0.0328
0.0300
0.0264
0.0223
0.0538
0.0526
0.0516
0.0497
0.0630
0.0505
0.0580
0.0545
0.0304
0.0276
0.0237
0.0194
0.0384
0.0373
0.0371
0.0356
0.0490
0.0464
0.0440
0.0405
0.0312
0.0284
0.0246
0.0203
0.0430
0.0421
0.0412
0.0396
0.0531
0.0508
0.0479
0.0445
Note: More tables on Page 140.
139
Reference Data

Table 62. 60 Hz Impedance Data for Three-Phase Copper Cable Circuits, in Approximate Ohms per 1000 ft (305 m) at 75 °C (b) Three Conductor Cable
Wire Size,
AWG or
kcmil
In Magnetic Duct and Steel InterlockedArmor In Non-Magnetic Duct andAluminum InterlockedArmor
8
8 (solid)
6
6 (solid)
0.811
0.786
0.510
0.496
0.0577
0.0577
0.0525
0.0525
0.813
0.788
0.513
0.499
0.811
0.786
0.510
0.496
0.0658
0.0658
0.0610
0.0610
0.814
0.789
0.514
0.500
0.811
0.786
0.510
0.496
0.0503
0.0503
0.0457
0.0457
0.812
0.787
0.512
0.498
0.811
0.786
0.510
0.496
0.0574
0.0574
0.0531
0.0531
0.813
0.788
0.513
0.499
4
4 (solid)
2
1
0.321
0.312
0.202
0.160
0.0483
0.0483
0.0448
0.0436
0.325
0.316
0.207
0.166
0.321
0.312
0.202
0.160
0.0568
0.0508
0.0524
0.0516
0.326
0.317
0.209
0.168
0.321
0.312
0.202
0.160
0.0422
0.0422
0.0390
0.0380
0.324
0.315
0.206
0.164
0.321
0.312
0.202
0.160
0.0495
0.0495
0.0457
0.0450
0.325
0.316
0.207
0.166
1/0
2/0
3/0
4/0
0.128
0.102
0.0805
0.0640
0.0414
0.0407
0.0397
0.0381
0.135
0.110
0.0898
0.0745
0.128
0.103
0.0814
0.0650
0.0486
0.0482
0.0463
0.0446
0.137
0.114
0.0936
0.0788
0.127
0.101
0.0766
0.0633
0.0360
0.0355
0.0346
0.0332
0.132
0.107
0.0841
0.0715
0.128
0.102
0.0805
0.0640
0.0423
0.0420
0.0403
0.0389
0.135
0.110
0.090
0.0749
250
300
350
400
0.0552
0.0464
0.0378
0.0356
0.0379
0.0377
0.0373
0.0371
0.0670
0.0598
0.0539
0.0514
0.0557
0.0473
0.0386
0.0362
0.0436
0.0431
0.0427
0.0415
0.0707
0.0640
0.0576
0.0551
0.0541
0.0451
0.0368
0.0342
0.0330
0.0329
0.0328
0.0327
0.0634
0.0559
0.0492
0.0475
0.0547
0.0460
0.0375
0.0348
0.0380
0.0376
0.0375
0.0366
0.0666
0.0596
0.0530
0.0505
450
500
600
750
0.0322
0.0294
0.0257
0.0216
0.0361
0.0349
0.0343
0.0326
0.0484
0.0456
0.0429
0.0391
0.0328
0.0300
0.0264
0.0223
0.0404
0.0394
0.0382
0.0364
0.0520
0.0495
0.0464
0.0427
0.0304
0.0276
0.0237
0.0197
0.0320
0.0311
0.0309
0.0297
0.0441
0.0416
0.0389
0.0355
0.0312
0.0284
0.0246
0.0203
0.0359
0.0351
0.0344
0.0332
0.0476
0.0453
0.0422
0.0389
Table63.60HzImpedanceDataforThree-PhaseAluminumCableCircuits,inApproximateOhmsper1000Ft(305m)at90°C(a)ThreeSingleConductors
Wire Size,
AWG or
kcmil
In Magnetic Duct In Non-Magnetic Duct
6
4
2
1
0.847
0.532
0.335
0.265
0.053
0.050
0.046
0.048
0.849
0.534
0.338
0.269
—
0.532
0.335
0.265
—
0.068
0.063
0.059
—
0.536
0.341
0.271
0.847
0.532
0.335
0.265
0.042
0.040
0.037
0.035
0.848
0.534
0.337
0.267
—
0.532
0.335
0.265
—
0.054
0.050
0.047
—
0.535
0.339
0.269
1/0
2/0
3/0
4/0
0.210
0.167
0.133
0.106
0.043
0.041
0.040
0.039
0.214
0.172
0.139
0.113
0.210
0.167
0.132
0.105
0.056
0.055
0.053
0.051
0.217
0.176
0.142
0.117
0.210
0.167
0.133
0.105
0.034
0.033
0.037
0.031
0.213
0.170
0.137
0.109
0.210
0.167
0.132
0.105
0.045
0.044
0.042
0.041
0.215
0.173
0.139
0.113
250
300
350
400
0.0896
0.0750
0.0644
0.0568
0.0384
0.0375
0.0369
0.0364
0.0975
0.0839
0.0742
0.0675
0.0892
0.0746
0.0640
0.0563
0.0495
0.0479
0.0468
0.0459
0.102
0.0887
0.0793
0.0726
0.0894
0.0746
0.0640
0.0563
0.0307
0.0300
0.0245
0.0291
0.0945
0.0804
0.0705
0.0634
0.0891
0.0744
0.0638
0.0560
0.0396
0.0383
0.0374
0.0367
0.0975
0.0837
0.0740
0.0700
500
600
700
750
1000
0.0459
0.0388
0.0338
0.0318
0.0252
0.0355
0.0359
0.0350
0.0341
0.0341
0.0580
0.0529
0.0487
0.0466
0.0424
0.0453
0.0381
0.0332
0.0310
0.0243
0.0444
0.0431
0.0423
0.0419
0.0414
0.0634
0.0575
0.0538
0.0521
0.0480
0.0453
0.0381
0.0330
0.0309
0.0239
0.0284
0.0287
0.0280
0.0273
0.0273
0.0535
0.0477
0.0433
0.0412
0.0363
0.0450
0.0377
0.0326
0.0304
0.0234
0.0355
0.0345
0.0338
0.0335
0.0331
0.0573
0.0511
0.0470
0.0452
0.0405
Table 64. 60 Hz Impedance Data for Three-Phase Aluminum Cable Circuits, in Approximate Ohms per 1000 ft (30 m) at 90 °C (b) Three Conductor Cable
Wire Size,
AWG or
kcmil
In Magnetic Duct and Steel InterlockedArmor In Non-Magnetic Duct andAluminum InterlockedArmor
6
4
2
1
0.847
0.532
0.335
0.265
0.053
0.050
0.046
0.048
0.849
0.534
0.338
0.269
—
—
0.335
0.265
—
—
0.056
0.053
—
—
0.340
0.270
0.847
0.532
0.335
0.265
0.042
0.040
0.037
0.035
0.848
0.534
0.337
0.267
—
—
0.335
0.265
—
—
0.045
0.042
—
—
0.338
0.268
1/0
2/0
3/0
4/0
0.210
0.167
0.133
0.106
0.043
0.041
0.040
0.039
0.214
0.172
0.139
0.113
0.210
0.167
0.133
0.105
0.050
0.049
0.048
0.045
0.216
0.174
0.141
0.114
0.210
0.167
0.133
0.105
0.034
0.033
0.037
0.031
0.213
0.170
0.137
0.109
0.210
0.167
0.132
0.105
0.040
0.039
0.038
0.036
0.214
0.171
0.138
0.111
250
300
350
400
0.0896
0.0750
0.0644
0.0568
0.0384
0.0375
0.0369
0.0364
0.0975
0.0839
0.0742
0.0675
0.0895
0.0748
0.0643
0.0564
0.0436
0.0424
0.0418
0.0411
0.100
0.0860
0.0767
0.0700
0.0894
0.0746
0.0640
0.0563
0.0307
0.0300
0.0245
0.0291
0.0945
0.0804
0.0705
0.0634
0.0893
0.0745
0.0640
0.0561
0.0349
0.0340
0.0334
0.0329
0.0959
0.0819
0.0722
0.0650
500
600
700
750
1000
0.0459
0.0388
0.0338
0.0318
0.0252
0.0355
0.0359
0.0350
0.0341
0.0341
0.0580
0.0529
0.0487
0.0466
0.0424
0.0457
0.0386
0.0335
0.0315
0.0248
0.0399
0.0390
0.0381
0.0379
0.0368
0.0607
0.0549
0.0507
0.0493
0.0444
0.0453
0.0381
0.0330
0.0309
0.0239
0.0284
0.0287
0.0280
0.0273
0.0273
0.0535
0.0477
0.0433
0.0412
0.0363
0.0452
0.0380
0.0328
0.0307
0.0237
0.0319
0.0312
0.0305
0.0303
0.0294
0.0553
0.0492
0.0448
0.0431
0.0378
Reference Data

Current Carrying Capacities of Copper and Aluminum and Copper-Clad Aluminum Conductors
From National Electrical Code (NEC), 2014 Edition (NFPA 70-2014)
Table 65. Allowable Ampacities of Insulated Conductors Rated 0–2000 V, 60 ° to 90 °C (140° to 194 °F).
Not more than three current-carrying conductors in raceway, cable or earth (directly buried), based on ambient temperature of 30 °C (86 °F).
Size Temperature Rating of Conductor (SeeTable 310.15 [B][16]) Size
AWG or kcmil 60 °C (140 °F) 75 °C (167 °F) 90 °C (194 °F) 60 °C (140 °F) 75 °C (167 °F) 90 °C (194 °F) AWG or kcmil
Types Types
TW, UF RHW,THHW,
THW,THWN,
XHHW, USE, ZW
TBS, SA, SIS, FEP
,
FEPB, MI,
RHH, RHW-2,
THHN,THHW,
THW-2,THWN-2,
USE-2, XHH,
XHHW, XHHW-2,
ZW-2
TW, UF RHW,THHW,
THW,THWN,
XHHW, USE
TBS, SA, SIS,
THHN,THHW,
THW-2,THWN-2,
RHH, RHW-2,
USE-2, XHH,
XHHW, XHHW-2,
ZW-2
Copper Aluminum or Copper-CladAluminum
18
16
14 a
—
—
15
—
—
20
14
18
25
—
—
—
—
—
—
—
—
—
—
—
—
12 a
10 a
8
20
30
40
25
35
50
30
40
55
20
25
30
20
30
40
25
35
45
12 a
10 a
8
6
4
3
55
70
85
65
85
100
75
95
110
40
55
65
50
65
75
60
75
85
6
4
3
2
1
1/0
95
110
125
115
130
150
130
150
170
75
85
100
90
100
120
100
115
135
2
1
1/0
2/0
3/0
4/0
145
165
195
175
200
230
195
225
260
115
130
150
135
155
180
150
175
205
2/0
3/0
4/0
250
300
350
215
240
260
255
285
310
290
320
350
170
190
210
205
230
250
230
255
280
250
300
350
400
500
600
280
320
355
335
380
420
380
430
475
225
260
285
270
310
340
305
350
385
400
500
600
700
750
800
385
400
410
460
475
490
520
535
555
310
320
330
375
385
395
420
435
450
700
750
800
900
1000
1250
435
455
495
520
545
590
585
615
665
355
375
405
425
445
485
480
500
545
900
1000
1250
1500
1750
2000
520
545
560
625
650
665
705
735
750
435
455
470
520
545
560
585
615
630
1500
1750
2000
a See NEC Section 240.4 (D).
Note: For complete details of using Table 65, see NEC Article 310 in its entirety.
Table 66. Correction Factors From NFPA 70-2014 (See Table 310.15 [B][2][a])
Ambient
Temperature °C
For ambient temperatures other than 30 °C (86 °F), multiply the allowable ampacities shown
above by the appropriate factor shown below.
Ambient
Temperature °F
21–25
26–30
31–35
1.08
1.00
0.91
1.05
1.00
0.94
1.04
1.00
0.96
1.08
1.00
0.91
1.05
1.00
0.94
1.04
1.00
0.96
070–77
078–86
087–95
36–40
41–45
46–50
0.82
0.71
0.58
0.88
0.82
0.75
0.91
0.87
0.82
0.82
0.71
0.58
0.88
0.82
0.75
0.91
0.87
0.82
096–104
105–113
114–122
51–55
56–60
61–70
0.41
—
—
0.67
0.58
0.33
0.76
0.71
0.58
0.41
—
—
0.67
0.58
0.33
0.76
0.71
0.58
123–131
132–140
141–158
71–80 — — 0.41 — — 0.41 159–176
141
Reference Data

Ampacities for Conductors
Rated 0–2000 V (Excerpted from
NFPA 70-2014, 310.15)
Note: Fine Print Note (FPN) was changed
to Informational Note in the 2011 NEC.
(A) General.
(1) Tables or Engineering Supervision.
Ampacities for conductors shall be
permitted to be determined by tables
as provided in 310.15(B) or under
engineering supervision, as provided
in 310.15(C).
Note: Informational Note No. 1: Ampacities
provided by this section do not take voltage
drop into consideration. See 210.19(A),
Informational Note No. 4, for branch circuits
and 215.2(A), Informational No. 2, for feeders.
Note: Informational Note No. 2: For the
allowable ampacities ofType MTW wire, see
Table 13.5.1 in NFPA 79-2007, Electrical
Standard for Industrial Machinery.
(2) Selection ofAmpacity. Where more
than one ampacity applies for a given
circuit length, the lowest value shall be
used. Exception:Where two different
ampacities apply to adjacent portions
of a circuit, the higher ampacity shall
be permitted to be used beyond the
point of transition, a distance equal to
10 ft (3.0 m) or 10 percent of the circuit
length figured at the higher ampacity,
whichever is less.
Note: See 110.14(C) for conductor temperature
limitations due to termination provisions.
(B) Tables. Ampacities for conductors
rated 0–2000V shall be as specified
in the Allowable Ampacity
Table 310.15(B)(16) throughTable
310.15(B)(19), and AmpacityTable
310.15(B)(20) andTable 310.15(B)(21)
as modified by 310.15(B)(1) through
(B)(7).
Note: Table 310.15(B)(16) through
Table 310.15(B)(19) are application tables for
use in determining conductor sizes on loads
calculated in accordance with Article 220.
Allowable ampacities result from consideration
of one or more of the following:
(1) Temperature compatibility with
connected equipment, especially the
connection points.
(2) Coordination with circuit and
system overcurrent protection.
(3) Compliance with the requirements of
product listings or certifications. See
110.3(B).
(4) Preservation of the safety benefits of
established industry practices and
standardized procedures.
(1) General. For explanation of type
let
ters used in tables and for
recognized sizes of conductors for the
various conductor insulations, see
Table 310.104(A) andTable 310.104(B).
For installation requirements, see
310.1 through 310.15(A)(3) and the
various articles of this Code. For
flexible cords, seeTable 400.4,Table
400.5(A)(1) andTable 400.5(A)(2).
(3)Adjustment Factors.
(a) MoreThanThree Current-Carrying
Conductors in a Raceway or Cable.
Where the number of current-carrying
conductors in a raceway or cable
exceeds three, or where single
conductors or multi
conductor cables
are installed without maintaining
spacing for a continuous length longer
than 24.00-inch (600 mm) and are not
installed in raceways, the allowable
ampacity of each conductor shall be
reduced as shown inTable 310.15(B)(3)
(a). Each current-carry
ing conductor
of a paralleled set of conductors
shall be counted as a current-
carrying conductor.
Note: Informational Note No. 1: See Annex B,
Table B.310.15(B)(2)(11), for adjustment factors
for more than three current-carrying conductors
in a raceway or cable with load diversity.
Note: Informational Note No. 2: See 366.23(A)
for adjustment factors for conductors in
sheet metal auxiliary gutters and 376.22(B)
for adjustment factors for conductors in
metal wireways.
(1) Where conductors are installed in
cable trays, the provisions of 392.80
shall apply.
(2) Adjustment factors shall not apply
to conductors in raceways having
a length not exceeding 24.00-inch
(600 mm).
(3) Adjustment factors shall not apply to
underground conductors enter
ing or
leaving an outdoor trench if those
conductors have physical protection
in the form of rigid metal conduit,
intermediate metal conduit, rigid
polyvinyl chloride conduit (PVC), or
reinforced thermosetting resin conduit
(RTRC) having a length not exceeding
10 ft (3.05 m), and if the number of
conductors does not exceed four.
Reference Data

(4) Adjustment factors shall not apply to
Type AC cable or toType MC cable
under the following conditions:
a. The cables do not have an overall
outer jacket.
b. Each cable has not more than three
current-carrying conductors.
c. The conductors are 12 AWG copper.
d. Not more than 20 current-carrying
conductors are installed without
maintaining spacing, are stacked,
or are supported on”bridle rings.
”
(5) An adjustment factor of 60 percent
shall be applied toType AC cable or
Type MC cable under the following
conditions:
a. The cables do not have an overall
outer jacket.
b. The number of current carrying
conductors exceeds 20.
c. The cables are stacked or bundled
longer that 24.00-inch (600 mm)
without spacing being maintained.
(b) MoreThan One Conduit,Tube,
or Raceway. Spacing between
conduits, tubing, or raceways
shall be maintained.
(c) Circular Raceways Exposed to
Sunlight on Rooftops.
Where conductors or cables are installed
in circular raceways exposed to direct
sunlight on or above rooftops, the
adjustments shown in Table 67
shall be added to the outdoor
temperature to determine the applicable
ambient temperature for application of
the correction factors inTable 310.15(B)(2)
(a) orTable 310.15(B)(2)(b).
Note: Informational Note: One source for the
average ambient temperatures in various
locations is the ASHRAE Handbook
—Fundamentals.
Table 67. NEC (2014) Table 310.15(B)(3)(c)
Ambient Temperature Adjustment for Circular
Raceways or Cables Exposed to Sunlight On or
Above Rooftops
DistanceAbove Roof
to Bottom of Conduit
Temperature
Adder ºF (ºC)
0–0.51-inch (0–13.0 mm) 60 (33)
Above 0.51-inch (13.0 mm)–
3.54-inch (90.0 mm)
40 (22)
Above 3.54-inch (90.0 mm)–
11.81-inch (300.0 mm)
30 (17)
Above 12.00-inch (300.0 mm)–
36.00-inch (900.0 mm)
25 (14)
(4) Bare or Covered Conductors. Where
bare or covered conductors are
installed with insulated conductors,
the temperature rating of the bare or
covered conductor shall be equal to
the lowest temperature rating of the
insulated conductors for the purpose
of determining ampacity.
(5) Neutral Conductor.
(a) A neutral conductor that carries only
the unbalanced current from other
conductors of the same circuit shall
not be required to be counted when
apply
ing the provisions of 310.15(B)
(3)(a).
(b) In a three-wire circuit consisting of
two phase conductors and the neutral
conductor of a four-wire, three-phase,
wye-connected system, a common
conductor carries approximately the
same current as the line-to-neutral
load currents of the other conductors
and shall be counted when applying
the provisions of 310.15(B)(3)(a).
(c) On a four-wire, three-phase wye circuit
where the major portion of the load
consists of nonlinear loads, harmonic
currents are present in the neutral
conductor; the neutral conductor shall
therefore be con
sidered a current-
carrying conductor.
(6) Grounding or Bonding Conductor.
A grounding or bonding conductor
shall not be counted when applying
the provisions of 310.15(B)(3)(a).
143
Reference Data

Table 68. Formulas for Determining Amperes, hp, kW and kVA
To
Find
Direct
Current
Alternating Current
Single-Phase Two-Phase—Four-Wire 1 Three-Phase
Amperes (l) when
horsepower is known
Amperes (l) when
kilowatts is known
Amperes (l) when
kVA is known
—
Kilowatts
kVA —
Horsepower (output)
a For two-phase, three-wire circuits, the current in the common conductor is times that in either of the two other conductors.
Note: Units of measurement and definitions for E (volts), I (amperes), and other abbreviations are given below under Common ElectricalTerms.
Common ElectricalTerms
Ampere (l) = unit of current or rate of flow of electricity
Volt (E) = unit of electromotive force
Ohm (R) = unit of resistance
Ohms law: I = (DC or 100% pf)
Megohm = 1,000,000 ohms
Volt Amperes (VA) = unit of apparent power
= E x I (single-phase)
=
Kilovolt Amperes (kVA) = 1000 volt-amperes
Watt (W) = unit of true power
=VA x pf
= 0.00134 hp
Kilowatt (kW) = 1000 watts
Power Factor (pf) = ratio of true to apparent power
=
Watthour (Wh) = unit of electrical work
= 1 watt for 1 hour
= 3.413 Btu
= 2655 ft-lbs
Kilowatt-hour (kWh) = 1000 watthours
Horsepower (hp) = measure of time rate of doing work
= equivalent of raising 33,000 lbs 1 ft in 1 minute
= 746 watts
Demand Factor = ratio of maximum demand to the total connected load
Diversity Factor = ratio of the sum of individual maximum demands of
the various subdivisions of a system to the maximum
demand of the whole system
Load Factor = ratio of the average load over a designated period
of time to the peak load occurring in that period
How to Compute Power Factor
1. From watthour meter.
Watts = rpm of disc x 60 x Kh
Where Kh is meter constant printed
on face or nameplate
of meter.
If metering transformers are used,
above must be multiplied by the
transformer ratios.
2. Directly from wattmeter reading.
Where:
Volts = line-to-line voltage as
measured by voltmeter.
Amperes = current measured in line
wire (not neutral) by ammeter.
Table 69. Temperature Conversion
(F° to C°) C° = 5/9 (F°–32°)
(C° to F°) F° = 9/5(C°)+32°
C° –15 –10 –5 0 5 10 15 20
F° 5 14 23 32 41 50 59 68
Cº 25 30 35 40 45 50 55 60
F° 77 86 95 104 113 122 131 140
C° 65 70 75 80 85 90 95 100
F° 149 158 167 176 185 194 203 212
1 Inch = 2.54 centimeters
1 Kilogram = 2.20 lb
1 Square Inch = 1,273,200 circular mills
1 Circular Mill = 0.785 square mil
1 Btu = 778 ft lb
= 252 calories
1Year = 8760 hours
Reference Data

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Publication No. DG081001EN / Z23695
February 2020

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