CHAPTER 1. PRINCIPLES OF POWER SYSTEMS.

1.1 TYPICAL POWER NETWORK. An understanding of basic design principles is essential in

the operation of electric power systems. This chapter briefly describes and defines electric power
generation, transmission, and distribution systems (primary and secondary). A discussion of
emergency and standby power systems is also presented. Figure 1-1 shows a one-line diagram
of a typical electrical power generation, transmission, and distribution system.

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1.2 ELECTRIC POWER GENERATION. A generator is a machine that transforms mechanical
energy into electric power. Prime movers such as engines and turbines convert thermal or
hydraulic energy into mechanical power. Thermal energy is derived from the fission of nuclear
fuel or the burning of common fuels such as oil, gas, or coal. The alternating current generating
units of electric power utilities generally consist of steam turbine generators, gas combustion
turbine generators, hydro (water) generators, and internal-combustion engine generators.

1.2.1 Prime Movers. The prime movers used for utility power generation are predominantly
steam turbines and internal-combustion machines. High-pressure/high-temperature and
high-speed (1800 to 3600 rotational speed (rpm)) steam turbines are used primarily in large
industrial and utility power generating stations. Internal-combustion machines are normally of
the reciprocating-engine type. The diesel engine is the most commonly used internal-combustion
machine, although some gasoline engines are also used.

1.2.2 Generators.

1.2.2.1 Generator Capacity. Turbine units can be built for almost any desired capacity.
The capacity of steam turbine driven generators in utility plants range from 5 MW to 1000 MW.
Most of the installed steam turbine generators are rated less than 500 MW. Gas turbine
generators for electric power generation generally have capacities ranging from 100 kW to 20
MW (but are used in multiple installations). The applications of gas turbine generators include
both continuous and peak load service. Diesel engine generator sets have capacities ranging
from 500 kW to 6500 kW. These units are widely used in auxiliary or standby service in
portable or stationary installations, but they may be used as the primary power source in some
locations. Smaller units (steam turbine, gasoline, or diesel engine) are also available for special
applications or industrial plants. See NAVFAC MO-322 for testing procedures.

1.2.2.2 Generator Voltage. Large generators used by commercial utilities are usually
designed with output voltages rated between 11 and 18 kV. Industrial plant generators are
normally rated 2.4 kV to 13.8 kV, coinciding with standard distribution voltages. The generated
voltage is stepped up to higher levels for long distance power transmission.

1.2.2.3 Generator Frequency. Power generation in the United States is standardized at 60

Hz. The standard frequency is 50 Hz in most foreign countries. Generators operating at higher
frequencies are available for special applications.

1.2.3 Voltage and Frequency Controls.

1.2.3.1 Voltage Control. The terminal voltage of a generator operating in isolation is a

function of the excitation on the rotor field winding. The generator output terminal voltage is
normally maintained at the correct level by an automatic voltage regulator that adjusts the field
current.

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 1.2.3.2 Frequency Control. Electrical frequency is directly proportional to the rpm of the
rotor which is driven by the prime mover. Because of this relationship, prime movers are
controlled by governors that respond to variation in speed or frequency. The governor is
connected to the throttle control mechanism to regulate speed, accomplishing frequency control
automatically.

1.2.4 Parallel Operation of Generators. Large power plants normally have more than one
generator in operation at the same time. When generators are to be paralleled, it is necessary to
synchronize the units before closing the paralleling circuit breaker. This means that the
generators must be brought to approximately the same speed, the same phase rotation and
position, and the same voltage. Proper synchronization is accomplished with the aid of a
synchroscope, an instrument which indicates the difference in phase position and in frequency of
two sources. Paralleling of generators is accomplished either manually or automatically with one
incoming unit at a time.

1.2.5 DC Generation. The requirement for direct current power is limited largely to special
loads; for example, electrochemical processes, railway electrification, cranes, automotive
equipment, and elevators. Direct current power may be generated directly as such, but is more
commonly obtained by conversion or rectification of AC power near the load.

1.3 ALTERNATING CURRENT POWER TRANSMISSION SYSTEM. The transmission

system is the bulk power transfer system between the power generation station and the
distribution center from which power is carried to customer delivery points. The transmission
system includes step-up and step-down transformers at the generating and distribution stations,
respectively. The transmission system is usually part of the electric utility's network. Power
transmission systems may include subtransmission stages to supply intermediate voltage
levels. Subtransmission stages are used to enable a more practical or economical transition
between transmission and distribution systems.

1.3.1 Transmission Voltage. Usually, generated power is transformed in a substation, located

at the generating station, to 46 kV or more for transmission. Standard nominal transmission
system voltages are: 69 kV, 115 kV, 138 kV, 161 kV and 230 kV. Some transmission voltages,
however, may be at 23 kV to 69 kV, levels normally categorized as primary distribution system
voltages. There are also a few transmission networks operating in the extra-high-voltage class
(345 kV to 765 kV).

1.3.2 Transmission Lines. Transmission lines supply distribution substations equipped with
transformers which step the high voltages down to lower levels. The transmission of large
quantities of power over long distances is more economical at higher voltages. Power
transmission at high voltage can be accomplished with lower currents which lower the I 2R
(Power) losses and reduce the voltage drop. The consequent use of smaller conductors

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requires a lower investment. Standard power transmission systems are 3-phase, 3-conductor,
overhead lines with or without a ground conductor. Transmission lines are classed as
unregulated because the voltage at the generating station is controlled only to keep the lines
operating within normal voltage limits and to facilitate power flow.

1.4 PRIMARY DISTRIBUTION SYSTEMS. The transmission system voltage is stepped-down

to lower levels by distribution substation transformers. The primary distribution system is that
portion of the power network between the distribution substation and the utilization transformers.
The primary distribution system consists of circuits, referred to as primary or distribution feeders,
that originate at the secondary bus of the distribution substation. The distribution substation is
usually the delivery point of electric power in large industrial or commercial applications.

1.4.1 Nominal System Voltages. Primary distribution system voltages range from 2,400 V to
69,000 V. Some of the standard nominal system voltages are:

Volts Phase Wire

  

4,160Y/2,400 Three Four

4,160 Three Three

6,900 Three Three

12,470Y/7,200 Three Four

12,470 Three Three

13,200Y/7,620 Three Four

13,200 Three Three

13,800Y/7,970 Three Four

13,800 Three Three

24,940Y/14,400 Three Four

34,500 Three Three

69,000 Three Three

The primary distribution voltages in widest use are 12,470 V and 13,200 V, both three wire and
four wire. Major expansion of distribution systems below the 15 kV nominal level (12 kV - 14.4

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kV) is not recommended due to the increased line energy costs inherent with lower voltage
systems.

1.4.2 Distribution Substations. A substation consists of one or more power transformer

banks together with the necessary voltage regulating equipment, buses, and switchgear.

1.4.2.1 Substation Arrangements. A simple substation arrangement consists of one

incoming line and one transformer. More complicated substation arrangements result when there
are two or more incoming lines, two or more power transformers, or a complex bus network.

Some typical distribution substation arrangements are shown in Figure 1-2. Specific sections are
identified as follows:

(a) A primary section provides for the connection of one or more incoming
high-voltage circuits. Each circuit is provided with a switching device or a combination
switching and interrupting device.

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 (b) A transformer section includes one or more transformers with or without automatic
load-tap-changing (voltage regulating) capability.

(c) A secondary section provides for the connection of one or more secondary feeders.
Each feeder is provided with a switching and interrupting device.

1.4.2.2 Substation Bus Arrangements. A bus is a junction of two or more incoming and
outgoing circuits. The most common bus arrangement consists of one source or supply circuit
and one or more feeder circuits. The numerous other arrangements and variations are mainly
intended to improve the service reliability through the bus to all or part of the load during
scheduled maintenance or unexpected power outages. Typical bus arrangements are shown in
Figure 1-3.

The arrangements are normally referred to as:

(a) Double-bus.
(b) Two-source sectionalizing bus.
(c) Three-source sectionalizing bus.
(d) Star or synchronizing bus.

When two sources are used simultaneously, but must not be operated in parallel, a normally open
bus-tie circuit breaker is interlocked with the source circuit breakers. This permits serving both
bus sections from one of the sources when the other is not available. For normally parallel
sources, a single straight bus may be used. It is preferable, however, to use a normally closed
bus-tie circuit breaker to split the system so that service continuity can be retained on either
section when the other section is out of service.

1.4.2.3 Substation Operation. Substations may be attended by operators or designed for

automatic or remote control of the switching and voltage regulating equipment. Most large new
substations are either automatic or remotely controlled.

(a) In an automatic substation, switching operations are controlled by a separately

installed control system. Major apparatus, such as transformers and converting equipment, may
be placed in or taken out of service automatically. Feeder circuit breakers, after being opened,
can be reclosed by protective relays or by the control system.

(b) Remote control substations are often within a suitable distance from attended
stations. In such cases pilot-wire cables provide the communication link to receive indications of
circuit breaker or switch positions and to transmit control adjustments, as required. Microwave
radio, telephone lines, and carrier current are often used for remote-control links at distances
beyond the economic reach of pilot wire systems.

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 1.4.3 Types of Systems. There are two fundamental types of primary distribution systems;
radial and network. Simply defined, a radial system has a single simultaneous path of power
flow to the load. A network has more than one simultaneous path. Each of the two types of
systems has a number of variations. Figure 1-4 illustrates four primary feeder arrangements
showing tie, loop, radial and parallel feeders. There are other more complex systems, such as the
primary network (interconnected substations with feeders forming a grid) and dual-service
network (alternate feeder to each load). These systems, however, are simply variations of the
two basic feeder arrangements.

The following paragraphs discuss the functions and characteristics of the simpler feeder
arrangements.

1.4.3.1 Tie Feeder. The main function of a tie feeder is to connect two sources. It may
connect two substation buses in parallel to provide service continuity for the load supplied from
each bus.

1.4.3.2 Loop Feeder. A loop feeder has its ends connected to a source (usually a single
source), but its main function is to supply two or more load points in between. Each load point
can be supplied from either direction; so it is possible to remove any section of the loop from
service without causing an outage at other load points. The loop can be operated normally closed
or normally open. Most loop systems are, however, operated normally open at some point by
means of a switch. The operation is very similar to that of two radial feeders.

1.4.3.3 Radial Feeder. A radial feeder connects between a source and a load point, and it
may supply one or more additional load points between the two. Each load point can be supplied
from one direction only. Radial feeders are most widely used by the Navy because the circuits
are simple, easy to protect, and low in cost.

1.4.3.4 Parallel Feeder. Parallel feeders connect the source and a load or load center and
provide the capability of supplying power to the load through one or any number of the parallel
feeders. Parallel feeders provide for maintenance of feeders (without interrupting service to
loads) and quick restoration of service when one of the feeders fails.

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.
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1.5 SECONDARY DISTRIBUTION SYSTEMS. The secondary distribution system is that
portion of the network between the primary feeders and utilization equipment. The secondary
system consists of step-down transformers and secondary circuits at utilization voltage levels.
Residential secondary systems are predominantly single-phase, but commercial and industrial
systems generally use three-phase power.

1.5.1 Secondary Voltage Levels. The voltage levels for a particular secondary system are
determined by the loads to be served. The utilization voltages are generally in the range of 120 to
600 V. Standard nominal system voltages are:

Volts Phase Wire

  

120 Single 2
120/240 Single 3

208Y/120 Three 4

240 Three 3

480Y/277 Three 4
480 Three 3

600 Three 3

In residential and rural areas the nominal supply is a 120/240 V, single-phase, three-wire
grounded system. If three-phase power is required in these areas, the systems are normally
208Y/120 V or less commonly 240/120 V. In commercial or industrial areas, where motor loads
are predominant, the common three-phase system voltages are 208Y/120 V and 480Y/277 V.
The preferred utilization voltage for industrial plants, however, is 480Y/277 V. Three-phase
power and other 480 V loads are connected directly to the system at 480 V and fluorescent
lighting is connected phase to neutral at 277 V. Small dry-type transformers, rated
480-208Y/120 or 480-120/240 V, are used to provide 120 V single-phase for convenience outlets
and to provide 208 V single- and three-phase for small tools and other machinery.

1.5.2 Types of Systems. Various circuit arrangements are available for secondary power
distribution. The basic circuits are: simple radial system, expanded radial system, primary
selective system, primary loop system, secondary selective system, and secondary spot network.

1.5.2.1 Conventional Simple-Radial Distribution System. In the simple-radial system

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(Figure 1-5), distribution is at the utilization voltage. A single primary service and distribution
transformer supply all the feeders. There is no duplication of equipment. System investment is
the lowest of all circuit arrangements. Operation and expansion are simple. Reliability is high if
quality components are used, however, loss of a cable, primary supply, or transformer will cut off
service. Further, electrical service is interrupted when any piece of service equipment must be
deenergized to perform routine maintenance and servicing.

1.5.2.2 Expanded Radial Distribution System. The advantages of the radial system may
be applied to larger loads by using a radial primary distribution system to supply a number of unit
substations located near the load centers with radial secondary systems (Figure 1-6). The
advantages and disadvantages are similar to those described for the simple radial system.

1.5.2.3 Primary Selective Distribution System. Protection against loss of a primary supply
can be gained through use of a primary selective system (Figure 1-7). Each unit substation is
connected to two separate primary feeders through switching equipment to provide a normal and
an alternate source. When the normal source feeder is out of service for maintenance or a fault,
the distribution transformer is switched, either manually or automatically, to the alternate source.
An interruption will occur until the load is transferred to the alternate source. Cost is somewhat
higher than for a radial system because primary cable and switchgear are duplicated.

1.5.2.4 Loop Primary-Radial Distribution System. The loop primary system (Figure 1-8)
offers nearly the same advantages and disadvantages as the primary selective system. The failure
of the normal source of a primary cable fault can be isolated and service restored by
sectionalizing. Finding a cable fault in the loop, however, may be difficult and dangerous. The
quickest way to find a fault is to sectionalize the loop and reclose, possibly involving several
reclosings at the fault. A section may also be energized at both ends, thus, effecting another
potential danger. The cost of the primary loop system may be somewhat less than that of the
primary selective system. The savings may not be justified, however, in view of the
disadvantages.

1.5.2.5 Secondary Selective-Radial Distribution System. When a pair of unit substations

are connected through a normally open secondary tie circuit breaker, the result is a secondary
selective-radial distribution system (Figure 1-9). If the primary feeder or a transformer fails, the
main secondary circuit breaker on the affected transformer is opened and the tie circuit breaker is
closed. Operation may be manual or automatic. Normally, the stations operate as radial systems.
Maintenance of primary feeders, transformer, and main secondary circuit breakers is possible
with only momentary power interruption, or no interruption, if the stations may be operated in
parallel during switching. With the loss of one primary circuit or transformer, the total substation
load may be supplied by one transformer. In this situation, however, if load shedding is to be
avoided, both transformers and each feeder must be oversized to carry the total load. A
distributed secondary selective system has pairs of unit substations in different locations
connected by tie cables and normally open tie circuit breakers. The secondary selective system
may be combined with the primary selective system to provide a high degree of reliability.

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 1.5.2.6 Secondary Network Distribution System. In a secondary network distribution
system, two or more distribution transformers are each supplied from a separate primary
distribution feeder (Figure 1-10).

The secondaries of the transformers are connected in parallel through a special type of circuit
breaker, called a network protector, to a secondary bus. Radial secondary feeders are tapped
from the secondary bus to supply loads. A more complex network is a system in which the
low-voltage circuits are interconnected in the form of a grid or mesh.

(a) If a primary feeder fails, or a fault occurs on a primary feeder or distribution

transformer, the other transformers start to feed back through the network protector on the faulted
circuit. This reverse power causes the network protector to open and disconnect the faulty supply
circuit from the secondary bus. The network protector operates so fast that there is minimal
exposure of secondary equipment to the associated voltage drop.

(b) The secondary network is the most reliable for large loads. A power interruption
can only occur when there is a simultaneous failure of all primary feeders or when a fault occurs
on the secondary bus. There are no momentary interruptions as with transfer switches on
primary selective, secondary selective, or loop systems. Voltage dips which could be caused by
faults on the system, or large transient loads, are materially reduced.

(c) Networks are expensive because of the extra cost of the network protector and
excess transformer capacity. In addition, each transformer connected in parallel increases the
available short-circuit current and may increase the duty rating requirement of secondary
equipment.

1.5.2.7 Secondary Banking. The term banking means to parallel, on the secondary side, a
number of transformers. All of the transformers are connected to the same primary feeder.
Banking is usually applied to the secondaries of single-phase transformers, and the entire bank
must be supplied from the same phase of the primary circuit. All transformers in a bank are
usually of the same size and should have the same nominal impedance.

(a) The advantages of banking include: reduction in lamp flicker caused by starting
motors, less transformer capacity required because of greater load diversity, and better average
voltage along the secondary.

(b) Solid banking, where the secondary conductors are connected without overcurrent
protection, is usually not practiced because of the obvious risks. Three methods of protecting
banked transformers are shown in Figure 1-11. In each arrangement the transformers are
connected to the primary feeder through high-voltage protective links or fuses. Each method
has different degrees of protection, depending on the location of the protective devices in the

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secondary. Figure 1-11(A) offers the least protection due to the slow acting fuses normally used
in this configuration. In the arrangement of Figure 1-11(B), the secondary circuit is
sectionalized and the faulted section can be isolated by the fuses.

The third scheme, shown in Figure 1-11(C), utilizes special transformers designed exclusively
for banked secondary operation. These transformers, known as completely self-protecting
transformers for banking (CSPB), contain in one integral unit the high-voltage protective link
and the two secondary breakers. When excessive current flows in one of the breakers, it will trip
independently of the other. Fault current protection and sectionalizing of secondary banks are
more efficiently accomplished by this method.

1.6 EMERGENCY AND STANDBY POWER SYSTEMS. The principle and practices of
emergency and standby power systems is presented in this section. Mobile equipment and
uninterruptible power supply (UPS) systems are also discussed. Technical information is
included on typical equipment and systems.

1.6.1 Definitions.

1.6.1.1 Emergency Power System. An emergency power system is an independent reserve

source of electric energy. Upon failure or outage of the normal or primary power source, the
system automatically provides reliable electric power within a specified time. The electric power
is provided to critical devices and equipment whose failure to operate satisfactorily would
jeopardize the health and safety of personnel or result in damage to property. The emergency
power system is usually intended to operate for a period of several hours to a few days. See
NAVFAC MO-322 for testing procedures.

1.6.1.2 Standby Power System. An independent reserve source of electric energy which,
upon failure or outage of the normal source, provides electric power of acceptable quality and
quantity so that the user's facilities may continue satisfactory operation. The standby system is
usually intended to operate for periods of a few days to several months, and may augment the
primary power source under mobilization conditions.

1.6.1.3 Uninterruptible Power Supply (UPS). UPS is designed to provide continuous

power and to prevent the occurrence of transients on the power service to loads which cannot
tolerate interruptions and/or transients due to sensitivity or critical operational requirements.

1.6.2 System Description.

1.6.2.1 Emergency Power Systems. Emergency power systems are of two basic types:

(a) An electric power source separate from the prime source of power, operating in
parallel, which maintains power to the critical loads should the prime source fail.

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 (b) An available reliable power source to which critical loads are rapidly switched
automatically when the prime source of power fails.

Emergency systems are frequently characterized by a continuous or rapid availability of electric

power. This electric power operates for a limited time and is supplied by a separate wiring
system. The emergency power system may in turn be backed by a standby power system if
interruptions of longer duration are expected.

1.6.2.2 Standby Power Systems. Standby power systems are made up of the following
main components:

(a) An alternate reliable source of electric power separate from the prime source.

(b) Starting and regulating controls when on-site standby generation is selected as the
source.

(c) Controls which transfer loads from the prime or emergency power source to the
standby source.

1.6.3 Engine-Driven Generators. These units are work horses which fulfill the need for
emergency and standby power. They are available from fractional kW units to units of several
thousand kW. When properly maintained and kept warm, the engine driven generators reliably
come on line within 8 to 15 seconds. In addition to providing emergency power, engine-driven
generators are also used for handling peak loads and are sometimes used as the preferred source
of power. They fill the need of backup power for uninterruptible power systems.

1.6.3.1 Generator Voltage. The output of engine-driven generators used for emergency or
standby power service is normally at distribution or utilization voltages. Generators rated at 500
kW or less operate at utilization voltages of 480Y/277 V, 208Y/120 V, or 240Y/120 V. Higher
rated generators usually operate at nominal distribution system voltages of 2400 V, 4160 V, or
13,800 V.

1.6.3.2 Diesel Engine Generators. The ratings of diesel engine generators vary from about
2.5 kW to 6500 kW. Typical ratings for emergency or standby power service are 100 kW, 200
kW, 500 kW, 750 kW, 1000 kW, 1500 kW, 2000 kW, and 2500 kW. Two typical operating
speeds of diesel engine generators in emergency and standby service are 1800 rpm and 1200 rpm.
Lower speed units are heavier and costlier, but are more suitable for continuous power while
nearly all higher speed (1800 rpm) sets are smaller.

1.6.3.3 Gasoline Engine Generators. Gasoline engines are satisfactory for installations up
to approximately 100 kW output. They start rapidly and are low in initial cost as compared to
diesel engines. Disadvantages include: higher operating costs, a great hazard due to the storing

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and handling of gasoline, and a generally lower mean time between overhaul.

1.6.3.4 Gas Engine Generators. Natural gas and liquid propane (LP) gas engines rank
with gasoline engines in cost and are available up to about 600 kW. They provide quick starting
after long shutdown periods because of the fresh fuel supply. Engine life is longer with reduced
maintenance because of the clean burning of natural gas.

1.6.3.5 Gas Turbine Generators. Gas combustion turbine generators usually range in size
from 100 kW to 20 MW, but may be as large as 100 MW in utility power plants. The gas
turbines operate at high speeds (2000 to 5000 rpm) and drive the generators at 900 to 3600 rpm
through reduction gearing. Gas turbine generator voltages range from 208 V to 22,000 V. The
gas turbine generator system has a higher ratio of kW to weight or to volume than other prime
mover systems and operates with less vibration than the other internal combustion engines, but
with lower fuel efficiency.

1.6.4 Typical Engine Generator Systems. The basic electrical components are the engine
generator set and associated meters, controls, and switchgear. Most installations include a single
generator set designed to serve either all the normal electrical needs of a building or a limited
emergency circuit. Sometimes the system includes two or more generators of different types and
sizes, serving different types of loads. Also, two or more generators may be operating in parallel
to serve the same load. Automatic starting of multiple units and automatic synchronizing
controls are available and practical for multiple-unit installations.

1.6.4.1 Automatic Systems. In order for engine-driven generators to provide automatic

emergency power, the system must also include automatic engine starting controls, batteries, an
automatic battery charger, and an automatic transfer device. In most applications, the utility
source is the normal source and the engine generator set provides emergency power when utility
power fails. The utility power supply is monitored and engine starting is automatically initiated
once there is a failure or severe voltage or frequency reduction in the normal supply. Load is
automatically transferred as soon as the standby generator stabilizes at rated voltage and speed.
Upon restoration of normal supply, the load is transferred back to the normal source and the
engine is shut down.

(a) Automatic transfer devices (ATD) for use with engine-driven generator sets are
similar to those used with multiple-utility systems, except for the addition of auxiliary contacts
that close when the normal source fails. These auxiliary contacts initiate the starting and
stopping of the engine-driven generator. The auxiliary contacts include a paralleling contactor
(PC) and a load-dumping contactor (LDC), both electrically operated and mechanically held.

1.6.4.2 Engine Generators (Parallel operation). Figure 1-12 shows a standby power
system where failure of the normal source would cause both engines to automatically start. The
first generator to reach operating voltage and frequency will actuate load dumping control

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circuits and provide power to the remaining load. When the second generator is in synchronism,
it will be paralleled automatically with the first. After the generators are paralleled, power is
restored to all or part of the dumped loads. This system is the ultimate in automatic systems
requiring more complexity and cost than would be appropriate in most activity requirements.

(a) If one generator fails, it is immediately disconnected. A proportionate share of the

load is dumped to reduce the remaining load to within the capacity of the remaining generator.
When the failed generator is returned to operation, the dumped load is reconnected.

(b) When the normal source is restored, the load is transferred back to it and the
generators are automatically disconnected and shut down.

1.6.4.3 Peak Load Control System. With the peak load control system shown in Figure
1-13, idle standby generator sets can perform a secondary function by helping to supply power
for peak loads. Depending on the load requirements, this system starts one or more units to feed
peak loads while the utility service feeds the base loads.

1.6.4.4 Combined Utility-Generator Operation. The system shown in Figure 1-14

provides switching and control of utility and on-site power. Two on-site buses are provided, (1)
supply bus (primary) supplies continuous power for computer or other essential loads, and (2) an
emergency bus (secondary) supplies on-site generator power to emergency loads through an
automatic transfer device if the utility service fails.

In normal operation, one of the generators is selected to supply continuous power to the primary
bus (EG1 in Figure 1-14). Simplified semiautomatic synchronizing and paralleling controls
permit any of the idle generators to be started and paralleled with the running generator to
alternate generators without load interruption. Anticipatory failure circuits permit load transfer
to a new generator without load interruption. If the generator enters a critical failure mode,
however, transfer to a new generator is made automatically with load interruption.

1.6.5 Engine Generator Operation.

1.6.5.1 Governors and Regulation. Governors can operate in two modes, droop and
isochronous. With droop operation, the engine's speed is slightly higher at light loads than at
heavy loads, while an isochronous governor maintains the same steady speed at any load up to
full load:

speed regulation = (no-load rpm) - (full-load rpm) X 100%


(full-load rpm)

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 (a) A typical speed regulation for a governor operating with droop is 3 percent. Thus,
if speed and frequency at full load are 1800 rpm and 60 Hz, at no load they would be
approximately 1854 rpm and 61.8 Hz.

A governor would be set for droop only when operating in parallel (in this mode f = 60 Hz +/- 0)
with a larger system or in parallel with another generator operating in the isochronous mode. In
this way, system frequency is maintained and the droop adjustment controls load distribution
among parallel engine generators.

(b) Under steady (or stable) load, frequency tends to vary slightly above and below the
normal frequency setting of the governor. The extent of this variation is a measure of the
stability of the governor. An isochronous governor should maintain frequency regulation within
+/- 1/4 percent under steady load.

(c) When load is added or removed, speed and frequency dip or rise momentarily,
usually for 1 to 3 seconds, before the governor causes the engine to settle at a steady speed at the
new load.

1.6.5.2 Starting Methods. Most engine generator sets use a battery-powered electric motor
for starting the engine. A pneumatic or hydraulic system normally is used only where starting of
the electric plant is initiated manually.

1.6.6 Turbine-Driven Generators. Steam and petroleum are two general types of turbine
prime movers for electrical generators currently available.

1.6.6.1 Steam Turbine Generators. Steam turbines are used to drive generators larger than
those driven by diesel engines. Steam turbines are designed for continuous operation and usually
require a boiler with a fuel supply and a source of condensing water. Because steam boilers
usually have electrically powered auxiliary fans and pumps, steam turbine generators cannot start
during a power outage. Steam turbine generators are, therefore, too large, expensive, and
unreliable for use as an emergency or standby power supply. They may also experience
environmental problems involving: fuel supply, noise, combustion product output, and heating of
the condensing water. Steam turbines may also be used in cogeneration systems, where steam
may be extracted from the turbine to serve process loads. In this configuration, no steam is
condensed at the turbine exhaust, but rather the turbine operates with a back pressure and serves
as a pressure reducing station.

1.6.6.2 Turbine Generators (Petroleum). The most common turbine-driven electric

generator units employed for emergency or standby power today use gas or oil for fuel. Various
grades of oil and both natural and propane gas may be used. Other less common sources of fuel
are kerosene or gasoline. Gas or oil turbine generators can start and assume load within 40
seconds to several minutes for larger units. Gas turbine generators are generally used as

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emergency backup power sources because they start quickly, can assume full load in only one or
two steps, and are less efficient than other prime movers. When there is a constant need for both
process steam (or hot water) and electricity, the gas turbine generator (with an exhaust heat
recovery system) may operate efficiently and continuously in a topping cycle cogeneration
configuration. Combustion turbine generator sets exhibit excellent frequency control, voltage
regulation, transient response, and behavior when operated in parallel with the utility supply.

1.6.7 Mobile Power Systems. One of the most important sources of emergency or standby
power is mobile (transportable) equipment. For most industrial applications, mobile equipment
will include only two types; diesel-engine-driven and gas-turbine-driven generators.

1.6.7.1 Ratings. Typical ratings of mobile generators range from kW to 2700 kW. Larger
power ratings are satisfied by parallel operation.

1.6.7.2 Accessories. Mobile generators come anywhere from a stripped down unit with
nothing but the prime mover and generator to units complete with soundproof chamber, control
panel, relaying, switchgear, intake and exhaust silencers, fuel tank, battery, and other required
operating and safety devices.

1.6.7.3 Navy Mobile Equipment. The Navy's Mobile Utilities Support Equipment
(MUSE) program provides specialized, easily transportable utility modules for short-term
support of shore utility systems. MUSE equipment includes generating units, substations, steam
boilers, water treatment plants, and auxiliary equipment. Policy, procedures, and guidance for
the management and use of MUSE are found in NAVFACENGCOM Instruction 11310.2.
Detailed technical and general application data for the equipment are provided in the MUSE
Application Guide, NEESA 50.1-001. Copies are available from Commanding Officer, Naval
Energy and Environmental Support Activity, Port Hueneme, CA 93043-5014.

(a) For power plants, the nominal ratings of diesel engine generators are 750 kW to
2,500 kW. The gas turbine generators are rated at 750 kW.

(b) The nominal capacities of MUSE substations range from 1,500 kVA to 5,000 kVA.
These substations are designed to provide maximum flexibility for transforming various system
voltages. Presently, transformers rated 3,750 kVA and larger are two winding units, providing
transformation between 13.2 kV or 11.5 kV and 4.16 kV. Either winding may be used as input
or output. Units smaller than 3,750 kVA have three winding transformers. Their High Voltage
(HV) winding nominal voltages are 13.2 kV or 11.5 kV; their Intermediate Voltage (IV) winding
nominal voltages are 4.16 kV or 2.4 kV; and their Low Voltage (IV) winding nominal voltage is
480 V. These units can be operated with the HV or the IV acting as the input or output. The IV
winding is an output winding only.

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 1.6.8 Uninterruptible Power Supply Systems. The UPS system includes all mechanical and
electrical devices needed to automatically provide continuous, regulated electric power to critical
loads during primary power system disturbances and outages. During normal conditions, the
UPS system receives input power from the primary source and acts as a precise voltage and
frequency regulator to condition output power to sensitive loads. During disturbance or loss of
the input power, the UPS draws upon its stored-energy source to maintain the regulated output
power. The stored energy source is usually sized to supply the UPS load for several minutes,
until emergency or the normal input power is restored, or until the loads have undergone an
orderly shutdown. There are two basic uninterruptible power supply systems: the rotary
(mechanical stored-energy) system and the static (solid-state electronic system with
storage-battery).

1.6.8.1 Rotary (Mechanical Stored-Energy) Systems. Upon loss of input power, rotary
systems deliver uninterruptible power by converting the kinetic energy contained in a rotating
mass to electric energy. These systems provide an excellent buffer between the prime power
source and loads that will not tolerate fluctuations in voltage and frequency. Many types of
systems are in use, but since static equipment has been used to replace rotary systems in the past
ten years, only one configuration will be described.

The rotating flywheel no break system is shown in Figure 1-15. An induction motor is driven
from the utility supply and this motor is directly coupled to an alternator with its own excitation
and voltage regulating system. Coupled directly to the motor generator set is a large flywheel
with one member of a magnetic clutch attached to the flywheel. The other half of the clutch is
connected to a diesel engine or other prime power. Upon loss of alternating current input power,
the generator is driven by energy stored in the flywheel until the engine can be started and drive
the generator and flywheel. The voltage regulator maintains the voltage and, with proper
selection of components to minimize the start and run times of the diesel engine, the frequency
dip can be kept to approximately 1.5 to 2 Hz. Thus with a steady-state frequency of 59.5 Hz, the
minimum transient frequency would be from 57.5 to 58 Hz. The time for the diesel to start,
come up to speed, and assume the load would normally be from 6 to 12 seconds.

1.6.8.2 Static (Solid-State Electronic Circuitry) Systems. The basic static UPS system
consists of a rectifier, battery, and DC-to-AC inverter. Static systems are very efficient power
conversion devices. The advantages of static systems are stable operation, frequency unaffected
by load changes, excellent voltage regulation, and fast transient response. These systems
normally operate at 480Y/277 V or 208Y/120 V, 3-phase, 60 Hz input voltage and provide an
output of 480Y/277 V or 280Y/120 V. Typical output specifications are: voltage regulation of +1
percent and frequency regulation of +0.001 percent. The ratings of these systems range from 50
VA to more than 1200 kVA. A UPS system can be designed with various combinations of
rectifiers and inverters to operate in a nonredundant or redundant configuration.

(a) A nonredundant UPS system is shown in Figure 1-16. During normal operation,

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the prime power and rectifier supply power to the inverter, and also charge the battery which is
floated on the direct current bus and kept fully charged. The inverter converts power from direct
to alternating current for use by the critical loads. The inverter governs the characteristics of the
alternating current output, and any voltage or frequency fluctuations or transients present on the
utility power system are completely isolated from the critical load. When momentary or
prolonged loss of power occurs, the battery will supply sufficient power to the inverter to
maintain its output for a specified time until the battery has discharged to a predetermined
minimum voltage. Upon restoration of the prime power, the rectifier section will again resume
feeding power to the inverter and will simultaneously recharge the battery.

(b) The nonredundant UPS system reliability can be improved by installing a static
switch and bypass parallel with the UPS as shown in Figure 1-17. When an inverter fault is
sensed, the critical load can be transferred to the bypass circuit in less than 5 milliseconds. The
static bypass adds about 20 percent to the cost of a nonredundant system, but is much more
reliable.

(c) In the redundant UPS system shown in Figure 1-18, each half of the system has a
rating equal to the full critical load requirements. The basic power elements (rectifier, inverter,
and interrupter) are duplicated, but it is usually not necessary to duplicate the battery since it is
extremely reliable. Certain control elements such as the frequency oscillator may also be
duplicated. The static interrupters isolate the faulty inverter from the critical bus and prevent the
initial failure from starting a chain reaction which might cause the remaining inverter to fail.
The static bypass switch can also be applied to the redundant system.

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