Download version 0.1 of EM 1110-2-3006 Hydroelectric Power Plants Electrical Design.pdf

Download version 0.1 of EM 1110-2-3006 Hydroelectric Power Plants Electrical Design.pdf
Department of the Army
EM 1110-2-3006
U.S. Army Corps of Engineers
Washington, DC 20314-1000
Engineering and Design
Distribution Restriction Statement
Approved for public release; distribution is
30 June 1994
EM 1110-2-3006
30 June 1994
US Army Corps
of Engineers
Hydroelectric Power Plants
Electrical Design
U.S. Army Corps of Engineers
Washington, DC 20314-1000
No. 1110-2-3006
EM 1110-2-3006
30 June 1994
Engineering and Design
1. Purpose. This manual provides guidance and assistance to design engineers in the development of
electrical designs for new hydroelectric power plants.
2. Applicability. This manual is applicable to all civil works activities having responsibilities for the
design of hydroelectric power plants.
Colonel, Corps of Engineers
Chief of Staff
U.S. Army Corps of Engineers
Washington, DC 20314-1000
EM 1110-2-3006
No. 1110-2-3006
30 June 1994
Engineering and Design
Table of Contents
Chapter 1
Purpose . . . . . . . . . . . . . .
Applicability . . . . . . . . . . .
References . . . . . . . . . . . .
Scope . . . . . . . . . . . . . . . .
Codes . . . . . . . . . . . . . . . .
Criteria . . . . . . . . . . . . . . .
Hydroelectric Design Center
Chapter 2
Basic Switching Provisions
One-Line Diagrams . . . . . . . .
Plant Scope . . . . . . . . . . . . . .
Unit Switching Arrangements .
Substation Arrangements . . . .
Fault Current Calculations . . . .
Chapter 3
General . . . . . . . . . . . . . . .
Electrical Characteristics . . .
Generator Neutral Grounding
Generator Surge Protection .
Mechanical Characteristics .
Excitation Systems . . . . . . .
Generator Stator . . . . . . . .
Rotor and Shaft . . . . . . . . .
Brakes and Jacks . . . . . . . .
Bearings . . . . . . . . . . . . . .
Temperature Devices . . . . .
Final Acceptance Tests . . . .
Fire Suppression Systems . .
Chapter 4
Power Transformers
General . . . . . . . . . . . . . . . . . . . . . .
Rating . . . . . . . . . . . . .
Cooling . . . . . . . . . . . .
Electrical Characteristics .
Terminals . . . . . . . . . . .
Accessories . . . . . . . . . .
Oil Containment Systems
Fire Suppression Systems
. . . . . . . 6-5
. . . . . . . 6-6
. . . . . . . 6-7
Chapter 7
Station Service System
Power Supply . . . . . . . . . . . . . . . . . . . 7-1
Chapter 5
High Voltage System
Definition . . . . . . . . . . . . . . . .
Switchyard . . . . . . . . . . . . . . .
Switching Scheme . . . . . . . . . .
Bus Structures . . . . . . . . . . . . .
Switchyard Materials . . . . . . . .
Transformer Leads . . . . . . . . . .
Powerhouse - Switchyard Power
Control and Signal Leads . . . .
Circuit Breakers . . . . . . . . . . . .
Disconnect Switches . . . . . . . . .
Surge Arresters . . . . . . . . . . . .
Chapter 6
Generator-Voltage System
General . . . . . . . . . . . . . . . . .
Generator Leads . . . . . . . . . .
Neutral Grounding Equipment .
Instrument Transformers . . . . .
Single Unit and Small
Power Plant Considerations . .
Excitation System Power
Potential Transformer . . . . . .
Circuit Breakers . . . . . . . . . . .
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Chapter 13
Grounding Systems
General . . . . . . . . . . .
Safety Hazards . . . . .
Field Exploration . . . .
Ground Mats . . . . . . .
Powerhouse Grounding
Switchyard Grounding
Grounding Devices . .
Relays . . . . . . . . . . . . . . . . . .
Control and Metering Equipment
Load/Distribution Centers . . . . .
Estimated Station Service Load .
Chapter 8
Control System
General . . . . . . . . . . . . . . . .
Control Equipment . . . . . . . .
Turbine Governor . . . . . . . .
Large Power Plant Control . .
Small Power Plant Control . .
Protective Relays . . . . . . . . .
Automatic Generation Control
Chapter 9
Annunciation System
General . . . . . . . . . . . . . .
Audio and Visual Signals .
Annunciator . . . . . . . . . .
Sequential Events Recorder
Trouble Annunciator Points
Chapter 10
Communication System
General . . . . . . . . . . . . . . . . . . . .
Voice Communication System . . . .
Dedicated Communications System
Communication System Selection .
Chapter 11
Direct-Current System
General . . . . . . . . . . . . . . .
Batteries . . . . . . . . . . . . . .
Battery-Charging Equipment
Inverter Sets . . . . . . . . . . .
Battery Switchboard . . . . . .
Chapter 14
Conduit and Tray Systems
General . . . . . . . . . . . . . . . . . . . . .
Conduit . . . . . . . . . . . . . . . . . . . .
Cable Trays . . . . . . . . . . . . . . . . .
Chapter 15
Wire and Cable
General . . . . . . . . . . . . . . . .
Cable Size . . . . . . . . . . . . .
Cable System Classification .
Conduit and Cable Schedules
Chapter 16
Procedure for Powerhouse Design
Design Initiation . . . . . . . . . . . . . . 16-1
Design Process . . . . . . . . . . . . . . . 16-2
Chapter 17
General Design Memorandum
Requirements . . . . . . . . . . . . . . . .
Chapter 12
Lighting and Receptacle Systems
Design . . . . . . . . . . . . . . . . . . . . . .
Illumination Requirements . . . . . . . .
Efficiency . . . . . . . . . . . . . . . . . . . .
Conductor Types and Sizes . . . . . . . .
Emergency Light Control . . . . . . . . .
Control Room Lighting . . . . . . . . . . .
Hazardous Area Lighting . . . . . . . . .
Receptacles . . . . . . . . . . . . . . . . . . .
Chapter 18
Feature Design Memorandums and Drawings
Design Memorandum
Topics and Coverage . . . . . . . . . . . 18-1
Feature Design Memorandums . . . . 18-2
Engineering Documentation . . . . . . 18-3
Design Drawings . . . . . . . . . . . . . . 18-4
Chapter 19
Construction Specifications and Drawings
Specifications . . . . . . . . . . . . . . . . 19-1
Construction Drawings . . . . . . . . . . 19-2
Chapter 20
Analysis of Design
Permanent Record . . . . . . . . . . . . .
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Up-To-Date Values . . . . . . . . . . . . .
Expansion . . . . . . . . . . . . . . . . . . . .
Appendix A
References . . . . . . . . . . . . . . . . . .
Appendix B
Power Transformer Studies
and Calculations . . . . . . . . . . . .
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Chapter 1
indicated to secure a degree of uniformity in plants of
similar size and character. These preferred designs should
be followed unless unusual conditions make them unsuitable or unreasonably expensive.
1-1. Purpose
1-5. Codes
This manual provides guidance and assistance to design
engineers in the development of electrical designs for new
hydroelectric power plants. The manual should be used
when preparing electrical designs for hydroelectric power
plants for civil works facilities built, owned, or operated
by the Corps of Engineers. Treatment of electrical systems for pumped storage plants is not covered in the
manual, although much of the information is applicable to
pumped storage plant systems and subsystems.
Portions of the codes, standards, or requirements published by the associations or agencies listed below are
applicable to the work. A complete listing of codes,
standards, and guides is contained in Appendix A,
American National Standards Institute (ANSI)
1-2. Applicability
This manual is applicable to all civil works activities having responsibilities for the design of hydroelectric power
Electric Power Research Institute (EPRI)
Illuminating Engineering Society (IES)
1-3. References
Required and
Appendix A.
Institute of Electrical and Electronics Engineers
1-4. Scope
a. Generator rating. The manual presents good engineering practice in designing electrical systems for hydroelectric power plants employing generating units of up to
approximately 300 MW in rating.
b. Plant features. The manual deals with the electrical features of hydroelectric power plants, and covers the
generating equipment, station service, various switchyard
and transmission line arrangements, details of lighting,
communication and control, and protective devices for
plant equipment and related auxiliaries. Generators and
power transformers are treated under their respective
headings, but other equipment, materials, and devices are
discussed under the distinct functional systems in which
they are used.
c. Specification preparation. Information is presented
to facilitate the preparation of specifications for major
items of equipment using pertinent approved guide specifications, and specifications for suggested plant design
features which take into consideration the numerous ancillary and control details that are required to carry out the
intended plant function. Where alternate designs of
functional systems are discussed, a preferred design is
National Fire Protection Association (NFPA)
Underwriters Laboratory (UL)
1-6. Criteria
a. Preferred methods. The design methods, assumptions, electrical characteristics criteria, details, and other
provisions covered in this manual should be followed
wherever practicable. The manual was prepared for use
by engineers with basic knowledge of the profession, and
judgment and discretion should be used in applying the
material contained herein. In cases where preferred alternatives are not identified, designers should follow recommendations contained in the reference materials listed in
the Bibliography that apply to the work to be performed.
b. Deviations from preferred methods. Departures
from these guides may be necessary in some cases in
order to meet special requirements or conditions of the
work under consideration. When alternate methods, procedures, and types of equipment are investigated, final
selection should not be made solely on first cost, but
should be based on obtaining overall economy and
security by giving appropriate weight to reliability of
service, ease (cost) of maintenance, and ability to restore
service within a short time in event of damage or
abnormal circumstances. Whether architect-engineers or
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Hydroelectric Design Center personnel design the power
plant, the criteria and instructions set out in Appendix A
of Guide Specification CE-4000 should be followed.
c. Prepare preliminary design reports and the feature
design memorandums for hydroelectric power plants for
the requesting FOA.
1-7. Hydroelectric Design Center (HDC)
d. Prepare plans and specifications for supply and
construction contracts and supplemental major equipment
testing contracts.
The engineering of hydroelectric projects is a highly specialized field, particularly the engineering design and
engineering support of operational activities. In order to
assist field operating activities (FOA), the Corps of
Engineers has established the Hydroelectric Design Center
(HDC) as the center of expertise in the Corps of Engineers for this work. The FOA will retain complete
responsibility and authority for the work, including funding, inspection, testing, contract management, and
administration. The HDC will perform the following
engineering and design services:
e. Provide technical review of shop drawings.
f. Provide technical assistance to the Contracting
Officer’s representative at model and field tests. The
HDC will analyze results and make recommendations.
g. Assist in preparation of Operation and Maintenance Manuals.
a. Provide the technical portions of reconnaissance
reports and other pre-authorization studies for inclusion by
the requesting FOA in the overall report.
h. Provide necessary engineering and computer-aided
drafting (CAD) work to incorporate “as-built” changes
into the electronically readable “record” drawing files, and
assure complete coordination for such changes.
b. Provide the architectural, structural, electrical, and
mechanical design for the powerhouse including switchyards, related facilities, and all hydraulic transient studies.
i. Participate in review of plans and specifications
for non-Federal development at Corps of Engineers projects in accordance with ER 1110-2-103.
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Chapter 2
Basic Switching Provisions
2-1. One-Line Diagrams
a. General. The development of a plant electrical
one-line diagram should be one of the first tasks in the
preliminary design of the plant. In evaluating a plant for
good electrical system design, it is easy to discuss system
design in terms of the plant’s one-line electrical diagram.
The relationship between generators, transformers, transmission lines, and sources of station service power are
established, along with the electrical location of the associated power circuit breakers and their control and protection functions. The development of the plant one-line
diagram and the switching arrangement required to implement the one-line may help determine the rating of generators and consequently the rating of the turbines and the
size of the powerhouse. In developing plant one-line
diagram alternatives, use should be made of IEEE C37.2
to aid those reviewing the alternatives.
b. Evaluation factors. Some factors to consider in
evaluating one-line diagrams and switching arrangements
include whether the plant will be manned or unmanned,
equipment reliability, whether the plant will be used in a
“peaking” versus a base load mode of operation, the need
to maintain a minimum flow past the plant, or whether
there is a restriction on the rate of change of flow past the
plant. The base load mode implies a limited number of
unit start-stop operations, and fewer breaker operations
than would be required for peaking operation. Unmanned
operation indicates a need for reliable protection and
control, and simplicity of operation. If there are severe
flow restrictions, coupled with a need for continuous
reliable power output, it may be necessary to consider the
“unit” arrangement scheme because it provides the minimum loss of generation during first contingency
c. Design characteristics. In general, a good plant
electrical one-line should be developed with the goal of
achieving the following plant characteristics:
(1) Safety and reliability.
(2) Simplicity of operation.
(3) Good technical performance.
(4) Readily maintainable (e.g., critical components
can be removed from service without shutting down the
balance of plant).
(5) Flexibility to deal with contingencies.
(6) Ability to accommodate system changes.
2-2. Plant Scope
a. Extent of project. When considering switching
schemes, there are two basic power plant development
scopes. Either the project scope will include a transmission-voltage switchyard associated with the plant or, electrically, the project scope ends at the line terminals of the
high-voltage disconnect switch isolating the plant from the
transmission line. Frequently, the Corps of Engineers
project scope limit is the latter situation with the interconnecting switchyard designed, constructed, and operated by
the Federal Power Marketing Agency (PMA), wielding
the power or by the public utility purchasing the power
through the PMA.
b. Medium-voltage equipment. Whether or not the
scope includes a switchyard, the one-line development
will involve the switching arrangement of the units, the
number of units on the generator step-up (GSU) transformer bank, and the arrangement of power equipment
from the generator to the low voltage terminals of the
GSU transformer. This equipment is medium-voltage
(0.6 kv-15 kV) electrical equipment.
This chapter
describes selection of appropriate switching schemes,
including development of equipment ratings, economic
factors, and operational considerations. Chapter 6, “Generator Voltage System,” describes equipment types and
application considerations in selecting the medium-voltage
equipment used in these systems. Switching schemes for
generating units and transformers may be of either the
indoor or outdoor type, or a combination of both.
c. High-voltage equipment. When development does
include a switchyard or substation, the same considerations apply in developing the generator voltage switching
schemes described in paragraph 2-2b. Combined development does provide the opportunity to apply cost and technical trade-offs between the medium-voltage systems of
the power plant and the high-voltage systems of the
switchyard. Chapter 5, “High-Voltage System,” describes
switchyard arrangements, equipment and application considerations in developing the switchyard portion of the
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30 Jun 94
one-line diagram. Switchyards are predominately outdoor
installations although in special cases (e.g., an
underground power plant) high-voltage SF6 insulated
equipment systems may find use.
higher in first cost than schemes that have multiple generators on a single transformer and transmission line.
Medium-voltage equipment for the unit systems includes
bus leads from the generator to the GSU transformer and
isolation disconnects for maintenance purposes.
2-3. Unit Switching Arrangements
b. Multiple unit arrangements.
a. “Unit” arrangement. A “unit” scheme showing
outdoor switching of the generator and transformer bank
as a unit on the high-voltage side only, is shown in Figure 2-1a. The unit scheme is well-suited to small power
systems where loss of large blocks of generation are
difficult to tolerate. The loss of a transformer bank or
transmission line in all other arrangements would mean
the loss of more than a single generation unit. Small
power systems are systems not able to compensate for the
loss of multiple units, as could occur using other arrangements. The “unit” scheme makes maintenance outages
simpler to arrange and is advantageous where the plant is
located near the high-voltage substation making a short
transmission distance. This scheme, with a transformer
and transmission line for each generator unit, tends to be
Figure 2-1. Main unit switching schemes
(1) In larger power systems, where loss of larger
blocks of generation may be tolerable or where the plant
is interconnected to an EHV grid (345 kV and above), two
or more generators together with their transformer (or
transformer bank) may be connected to one switchyard
position. Some of the commonly used schemes are discussed in the following paragraphs. Refer to Chapter 3,
“Generators” for discussion on the protection requirements
for generator arrangements.
(2) Two generators may be connected to a twowinding transformer bank through Medium-Voltage Circuit Breakers (MVCBs) as shown on Figure 2-1b. This
arrangement has the advantage of requiring a single transmission line for two units, rather than the two lines that
would be required for a “unit” arrangement. This provides a clear savings in line right-of-way cost and
maintenance. A single transformer, even though of higher
rating, is also less costly than the two transformers that
would be needed for a “unit” system. Again, the space
requirement is also less than for two separate transformers. There are trade-offs: an MVCB for each generator
is needed, the generator grounding and protection scheme
becomes more complex, and additional space and equipment are needed for the generator medium-voltage (delta)
bus. An economic study should be made to justify the
choice of design, and the transformer impedance requirements should be evaluated if the power system is capable
of delivering a large contribution to faults on the generator side of the transformer.
(3) For small generating plants, a scheme which
connects the generators through MVCBs to the generator
bus is shown in Figure 2-1c. One or more GSU transformers can be connected to the bus (one is shown), with
or without circuit breakers; however, use of multiple
transformers, each with its own circuit breaker, results in
a very flexible operating arrangement. Individual transformers can be taken out of service for testing or maintenance without taking the whole plant out of service. The
impedances of the transformers must be matched to avoid
circulating currents. As noted above, the protection
scheme becomes more complex, but this should be considered along with the other trade-offs when comparing
this scheme with the other plant arrangements possible.
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30 Jun 94
(4) Two or more generators can be connected to
individual transformer banks through generator MVCBs
with the transformers bused through disconnect switches
on the high-voltage side as shown in Figure 2-1d. This
arrangement has some of the advantages of the “unit”
system shown in Figure 2-1a, and discussed above, along
with the advantage of fewer transmission lines, which
results in less right-of-way needs. There is some loss of
operational flexibility, since transmission line service
requires taking all of the units out of service, and a line
fault will result in sudden loss of a rather large block of
power. Again, needs of the bulk power distribution system and the economics of the arrangement must be
(5) Two or more generators may be connected to a
three-winding transformer bank as shown in Figure 2-1e
and f. The generators would be connected to the two
low-voltage windings through generator MVCBs. This
arrangement allows specification of a low value of
“through” impedance thus increasing the stability limits of
the system and allowing the specification of a high value
of impedance between the two low-voltage GSU transformer windings. This reduces the interrupting capacity
requirements of the generator breakers. This scheme is
particularly advisable when the plant is connected to a
bulk power distribution system capable of delivering high
fault currents. Again, transformer or line faults will result
in the potential loss to the bulk power distribution system
of a relatively large block of generation. Transformer
maintenance or testing needs will require loss of the generating capacity of all four units for the duration of the
test or maintenance outage. This scheme finds application
where plants are interconnected directly to an EHV grid.
2-4. Substation Arrangements
a. General.
High-voltage substation arrangements
and application considerations are described in Chapter 5,
“High-Voltage System.” High-voltage systems include
those systems rated 69 kV and above. The plant switching arrangement should be coordinated with the switchyard arrangement to ensure that the resulting integration
achieves the design goals outlined in paragraph 2-1c in a
cost-effective manner.
b. Substation switching. Some plants may be electrically located in the power system so their transmission
line-voltage buses become a connecting link for two or
more lines in the power system network. This can require
an appreciable amount of high-voltage switching equipment. The desirability of switching small units at generator voltage should nevertheless be investigated in such
Chapters 5, “High-Voltage System” and 6,
“Generator-Voltage System,” discuss switching and bus
arrangements in more detail.
2-5. Fault Current Calculations
a. General. Fault current calculations, using the
method of symmetrical components, should be prepared
for each one-line scheme evaluated to determine required
transformer impedances, generator and station switchgear
breaker interrupting ratings, and ratings of disconnect
switches and switchyard components. Conventional methods of making the necessary fault current calculations and
of determining the required ratings for equipment are
discussed in IEEE 242 and 399. A number of software
programs are commercially available for performing these
studies on a personal computer. Two of these programs
are: ETAP, from Operation Technology, Inc., 17870 Skypark Circle, Suite 102, Irvine, CA 92714; and DAPPER
and A-FAULT, from SKM Systems Analysis, Inc.,
225 S Sepulveda Blvd, Suite 350, Manhattan Beach,
CA 90266.
b. Criteria. The following criteria should be followed in determining values of system short-circuit
capacity, power transformer impedances, and generator
reactances to be used in the fault current calculations.
(1) System short-circuit capacity.
This is the
estimated maximum ultimate symmetrical kVA shortcircuit capacity available at the high-voltage terminals of
the GSU transformer connected to the generator under
consideration, or external to the generator under consideration if no step-up transformer is used. It includes the
short-circuit capacity available from all other generators in
the power plant in addition to the short-circuit capacity of
the high-voltage transmission system. System shortcircuit capacity is usually readily available from system
planners of the utility or the PMA to which the plant will
be connected.
(2) Calculating system short-circuit capacity. The
transmission system short-circuit capacity can also be
calculated with reasonable accuracy when sufficient information regarding the planned ultimate transmission system
is available, including the total generating capacity connected to the system and the impedances of the various
transmission lines that provide a path from the energy
sources to the plant.
(3) Estimating power system fault contribution.
When adequate information regarding the transmission
system is unavailable, estimating methods must be used.
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30 Jun 94
In all cases, the system short-circuit capacity for use in
the fault current calculations should be estimated on a
conservative basis, i.e., the estimate should be large
enough to allow for at least a 50-percent margin of error
in the system contribution. This should provide a factor
of safety, and also allow for addition of transmission lines
and generation capacity not presently planned or contemplated by system engineers and planners. Only in exceptional cases, such as small-capacity generating plants with
only one or two connecting transmission lines, should the
estimated ultimate system short-circuitry capacity be less
than 1,000 MVA.
(4) Power transformer impedances.
(a) Actual test values of power transformer
impedances should be used in the fault calculations, if
they are available. If test values are not available, design
values of impedance, adjusted for maximum IEEE standard minus tolerance (7.5 percent for two-winding transformers, and 10 percent for three-winding transformers
and auto-transformers) should be used. Nominal design
impedance values are contained in Table 4-1 of Chapter 4, “Power Transformers.” For example, if the impedance of a two-winding transformer is specified to be
8.0 percent, subject to IEEE tolerances, the transformer
will be designed for 8.0 percent impedance. However,
the test impedance may be as low as 8.0 percent less a
7.5-percent tolerance, or 7.4 percent, and this lower value
should be used in the calculations, since the lower value
of impedance gives greater fault current.
(b) If the impedance of the above example transformer is specified to be not more than 8.0 percent, the
transformer will be designed for 7.44 percent impedance,
so that the upper impedance value could be 7.998 percent,
and the lower impedance value (due to the design tolerance) could be as low as 6.88 percent, which is 7.44 percent less the 7.5 percent tolerance, which should be used
in the calculations because the lower value gives a higher
fault current. Using the lower impedance value is a more
conservative method of estimating the fault current,
because it anticipates a “worst case” condition. Impedances for three-winding transformers and auto-transformers should also be adjusted for standard tolerance in
accordance with the above criteria. The adjusted impedance should then be converted to an equivalent impedance
for use in the sequence networks in the fault current calculations. Methods of calculating the equivalent impedances and developing equivalent circuits are described in
IEEE 242.
(5) Generator reactances.
Actual test values of
generator reactances should also be used in the calculations if they are available. If test values are not available,
calculated values of reactances, obtained from the generator manufacturer and adjusted to the appropriate MVA
base, should be used. Rated-voltage (saturated) values of
the direct-axis transient reactance (X’d), the direct-axis
subtransient reactance (X"d), and the negative-sequence
reactance (X2), and the zero-sequence reactance (Xo), are
the four generator reactances required for use in the fault
current calculations. If data are not available, Figure 3-2
in Chapter 3, “Generators,” provides typical values of
rated-voltage direct-axis subtransient reactance for waterwheel generators based on machine size and speed.
Design reactance values are interrelated with other specified machine values (e.g., short-circuit ratio, efficiency) so
revised data should be incorporated into fault computations once a machine has been selected.
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Chapter 3
3-1. General
a. Design constraints. Almost all of the hydraulicturbine-driven generators used in Corps’ powerhouses will
be synchronous alternating-current machines, which produce electrical energy by the transformation of hydraulic
energy. The electrical and mechanical design of each
generator must conform to the electrical requirements of
the power distribution system to which it will be connected, and also to the hydraulic requirements of its
specific plant. General Corps of Engineers waterwheel
generator design practice is covered by the Guide Specification CW-16210.
should have sufficient continuous capacity to handle the
maximum horsepower available from the turbine at
100-percent gate without the generator exceeding its rated
nameplate temperature rise. In determining generator
capacity, any possible future changes to the project, such
as raising the forebay level and increasing turbine output
capability, should be considered. Figure 3-1 shows a
typical capability curve for a hydroelectric generator.
b. Design characteristics. Since waterwheel generators are custom designed to match the hydraulic turbine
prime mover, many of the generator characteristics (e.g.,
short-circuit ratio, reactances) can be varied over a fairly
wide range, depending on design limitations, to suit specific plant requirements and power distribution system
stability needs. Deviations from the nominal generator
design parameters can have a significant effect on cost, so
a careful evaluation of special features should be made
and only used in the design if their need justifies the
increased cost.
3-2. Electrical Characteristics
a. Capacity and power factor. Generator capacity is
commonly expressed in kilovolt-amperes (kVA), at a given
(“rated”) power factor. The power factor the generator
will be designed for is determined from a consideration of
the electrical requirements of the power distribution system it will be connected to. These requirements include a
consideration of the anticipated load, the electrical location of the plant relative to the power system load centers,
and the transmission lines, substations, and distribution
facilities involved. (See paragraph 3-2f).
b. Generator power output rating.
The kilowatt
rating of the generator should be compatible with the
horsepower rating of the turbine. The most common
turbine types are Francis, fixed blade propeller, and
adjustable blade propeller (Kaplan). See detailed discussion on turbine types and their selection and application in
EM 1110-2-4205. Each turbine type has different operating characteristics and imposes a different set of generator
design criteria to correctly match the generator to the
turbine. For any turbine type, however, the generator
Figure 3-1. Typical hydro-generator capability curve
c. Generator voltage. The voltage of large, slowspeed generators should be as high as the economy of
machine design and the availability of switching equipment permits. Generators with voltage ratings in excess
of 16.5 kV have been furnished, but except in special
cases, manufacturing practices generally dictate an upper
voltage limit of 13.8 kV for machines up through
250 MVA rating. Based on required generator reactances,
size, and Wk2, a lower generator voltage, such as 6.9 kV,
may be necessary or prove to be more economical than
higher voltages. If the generators are to serve an established distribution system at generator voltage, then the
system voltage will influence the selection of generator
voltage, and may dictate the selection and arrangement of
generator leads also. Generators of less than 5,000 kVA
should preferably be designed for 480 V, 2,400 V, or
4,160 V, depending on the facilities connecting the generator to its load.
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d. Insulation.
(1) The generator stator winding is normally supplied
with either Class B or Class F insulation materials, with
the insulation system meeting the temperature limits and
parameters of ANSI C50.12 (e.g., 75 °C rise above a
40 °C ambient). The choice of insulation system types
depends on machine size, how the machine will be
operated, and desired winding life. Modern hydro units
are subjected to a wide variety of operating conditions but
specifications should be prepared with the intent of
achieving a winding life expectancy of 35 or more years
under anticipated operating conditions.
winding is of the Roebel bar type. Epoxy is usually
preferred because of its higher Tg, and the polyester insulation system may not be available in the future.
(5) Thermosetting insulation system materials are
hard and do not readily conform to the stator slot surface,
so special techniques and careful installation procedures
must be used in applying these materials. Corps guide
specification CW-16210 provides guidance on types of
winding and coil fabrication techniques, and installation,
acceptance, and maintenance procedures to be used to
ensure long, trouble-free winding life.
e. Short-circuit ratio.
(2) The choice between Class B or Class F insulation
systems for the stator winding will depend on the
expected use of the generator. If it will be operated continuously at or near rated load, or has a high probability
of operating overloaded for longer than 2 hr at a time,
then the Class F insulation system should be specified.
For generators that can be expected to be operated below
rated load most of the time, and at or near full load for
only limited periods, a Class B insulation system would
be satisfactory. An insulation system using a polyester
resin as a binder should be considered a Class B system,
since the softening temperature of polyester resin is close
to the Class F temperature limit.
(3) Stator winding insulation systems consist of a
groundwall insulation, usually mica, with a suitable insulation binder, generally a thermosetting epoxy or polyester
material. These thermosetting systems achieve dielectric
strengths equivalent to that of older thermoplastic insulation systems with less thickness than the older systems,
allowing the use of additional copper in a given stator
slot, achieving better heat transfer, and permitting cooler
Thermosetting insulation systems tolerate
higher continuous operating temperatures than older systems with less mechanical deterioration.
(4) Polyester resin has a lower softening temperature
(known as the glass transition temperature, Tg) than the
more commonly available epoxy insulation system, but it
has the advantage of being slightly more flexible than the
epoxy system. This slight flexibility is an advantage
when installing multi-turn coils in stator slots in small
diameter generators. The plane of the coil side coincides
with the plane of the slot once the coil is installed. During installation, however, the coil side approaches the slot
at a slight angle so that the coil must be slightly distorted
to make the side enter the slot. Polyester is less likely to
fracture than epoxy when distorted during installation.
Polyester has no advantage over epoxy if the stator
(1) The short-circuit ratio of a generator is the ratio
of the field current required to produce rated open circuit
voltage, to the field current required to produce rated
stator current when the generator output terminals are
short-circuited. The short-circuit ratio is also the reciprocal of the per unit value of the saturated synchronous
reactance. The short-circuit ratio of a generator is a measure of the transient stability of the unit, with higher ratios
providing greater stability. Table 3-1 lists nominal shortcircuit ratios for generators. Short-circuit ratios higher
than nominal values can be obtained without much
increase in machine size, but large values of short-circuit
ratio must be obtained by trade-offs in other parameters of
generator performance. Increasing the short-circuit ratio
above nominal values increases the generator cost and
decreases the efficiency and the transient reactance.
Included in Table 3-1 are expected price additions to the
generator basic cost and reductions in efficiency and
transient reactance when higher than nominal short-circuit
ratio values are required.
(2) In general, the requirement for other than nominal short-circuit ratios can be determined only from a
stability study of the system on which the generator is to
operate. If the stability study shows that generators at the
electrical location of the plant in the power system are
likely to experience instability problems during system
disturbances, then higher short-circuit ratio values may be
determined from the model studies and specified. If the
power plant design is completed and the generators purchased prior to a determination of the exterior system
connections and their characteristics, i.e., before the connecting transmission lines are designed or built, this will
preclude making a system study to accurately determine
the short-circuit ratio required. Where it is not feasible to
determine the short-circuit ratio and there are no factors
indicating that higher than nominal values are needed,
then nominal short-circuit ratios should be specified.
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Table 3-1
Generator Short-Circuit Ratios
Short-Circuit Ratios
Not More
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f. Line-charging and condensing capacities. Nominal
values for these generator characteristics are satisfactory
in all except very special cases. If the generator will be
required to energize relatively long EHV transmission
lines, the line-charging requirements should be calculated
and a generator with the proper characteristics specified.
The line-charging capacity of a generator having normal
characteristics can be assumed to equal 0.8 of its normal
rating multiplied by its short-circuit ratio, but cannot be
assumed to exceed its maximum rating for 70 °C temperature rise. Often it will be desirable to operate generators
as synchronous condensers. The capacity for which they
are designed when operating over-excited as condensers is
as follows, unless different values are specified:
Power Factor
Condenser Capacity
of Basic
g. Power factor.
(1) The heat generated within a machine is a function of its kVA output; the capacity rating of a generator is
usually expressed in terms of kVA and power factor.
(Larger machine ratings are usually given in MVA for
convenience.) The kilowatt rating is the kVA rating multiplied by the rated power factor. The power-factor rating
for the generator should be determined after giving consideration to the load and the characteristics of the system
that will be supplied by the generator. The effect of
power factor rating on machine capability is illustrated in
Figure 3-1.
(2) The power factor at which a generator operates
is affected by the transmission system to which it is connected. Transmission systems are designed to have resistive characteristics at their rated transmission capacities.
Consequently, a generator connected to a transmission
system will typically operate at or near unity power factor
during maximum output periods. During lightly loaded
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conditions, however, the generator may be required to
assist in transmission line voltage regulation. A generator
operating on an HV transmission system with relatively
short transmission distances will typically be required to
supply reactive power (i.e., operate with a lagging power
factor in an overexcited condition), due to the inductive
characteristic of the unloaded transmission line. A generator operated on a long, uncompensated EHV transmission
line will typically be required to absorb reactive power
(i.e., operate with a leading power factor in an underexcited condition), due to the capacitive characteristic of
the unloaded transmission line. In the latter case, the
generator field current requirements are substantially
below rated field currents, thus reducing the generator
field strength. With reduced field strength, the generator
operates closer to its stability limit (see Figure 3-1), making it more susceptible to loss of synchronism or pole
slipping in the event of a system disturbance.
(3) It is highly desirable that the generator be
designed for the power factor at which it will operate in
order to improve system stability. In general, unless
studies indicate otherwise, the power factor selected
should be 0.95 for medium and large generators unless
they will be at the end of a long transmission line, in
which case a value approaching unity may be desirable.
(3) Typical values of transient reactances for large
water wheel generators indicated by Figure 3-2 are in
accordance with industry standard practice. Guaranteed
values of transient reactances will be approximately
10 percent higher.
(4) Average values of standard reactance will probably be sufficiently close to actual values to determine the
rating of high-voltage circuit breakers, and should be used
in preliminary calculations for other equipment. As soon
as design calculations for the specific machine are available, the design values should be used in rechecking the
computations for other items of plant equipment.
i. Amortisseur windings.
(1) Amortisseur windings (also referred to as damper
windings in IEEE 399; Dawes 1947; Fitzgerald and Kingsley 1961; and Puchstein, Lloyd, and Conrad 1954) are
essentially a short-circuited grid of copper conductors in
the face of each of the salient poles on a waterwheel
generator. Two types of amortisseur windings may be
specified. In one, the pole face windings are not interconnected with each other, except through contact with
the rotor metal. In the second, the pole face windings are
intentionally connected at the top and bottom to the adjacent damper windings.
h. Reactances.
(1) The eight different reactances of a salient-pole
generator are of interest in machine design, machine testing, and in system stability and system stability model
studies. A full discussion of these reactances is beyond
the scope of this chapter, but can be found in electrical
engineering texts (Dawes 1947; Fitzgerald and Kingsley
1961; Puchstein, Lloyd, and Conrad 1954), and system
stability texts and standards (IEEE 399).
(2) Both rated voltage values of transient and
subtransient reactances are used in computations for determining momentary rating and the interrupting ratings of
circuit breakers. A low net through reactance of the
generator and step-up transformer combined is desirable
for system stability. Where nominal generator and transformer design reactances do not meet system needs, the
increase in cost of reducing either or both the generator
and transformer reactances and the selection of special
generator reactance should be a subject for economic
study. Such a study must include a consideration of
space and equipment handling requirements, since a
reduction in reactance may be accomplished by an
increase in generator height or diameter, or both.
(2) The amortisseur winding is of major importance
to the stable operation of the generator. While the generator is operating in exact synchronism with the power
system, rotating field and rotor speed exactly matched,
there is no current in the damper winding and it essentially has no effect on the generator operation. If there is
a small disturbance in the power system, and the
frequency tends to change slightly, the rotor speed and the
rotating field speed will be slightly different. The rotor
mass is perturbed when synchronizing power tends to pull
the rotor back into synchronism with the system. That
perturbation tends to cause the rotor-shaft-turbine runner
mass to oscillate about its average position as a torsional
pendulum. The result is relatively large pulsations in the
energy component of the generator current. In worst case,
the oscillations can build instead of diminishing, resulting
in the generator pulling out of step with possible consequential damage.
(3) At the onset of the oscillations, however, the
amortisseur winding begins to have its effect. As the
rotating field moves in relation to the rotor, current is
induced in the amortisseur windings. Induction motor
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action results, and the rotor is pulled back toward synchronism by the amortisseur winding action.
(4) The amortisseur (damper) winding is of importance in all power systems, but even more important to
systems that tend toward instability, i.e., systems with
large loads distant from generation resources, and large
intertie loads.
(5) In all cases, connected amortisseur windings are
recommended. If the windings are not interconnected, the
current path between adjacent windings is through the
field pole and the rotor rim. This tends to be a high
impedance path, and reduces the effectiveness of the
winding, as well as resulting in heating in the current
path. Lack of interconnection leads to uneven heating of
the damper windings, their deterioration, and ultimately
damage to the damper bars.
(6) The amortisseur winding also indirectly aids in
reducing generator voltage swings under some fault conditions. It does this by contributing to the reduction of the
ratio of the quadrature reactance and the direct axis reactance, Xq"/Xd". This ratio can be as great as 2.5 for a
salient pole generator with no amortisseur winding, and
can be as low as 1.1 if the salient pole generator has a
fully interconnected winding.
j. Efficiencies. The value of efficiency to be used in
preparing the generator specification should be as high as
can be economically justified and consistent with a value
manufacturers will guarantee in their bids. Speed and
power factor ratings of a generator affect the efficiency
slightly, but the selection of these characteristics is governed by other considerations. For a generator of any
given speed and power factor rating, design efficiencies
are reduced by the following:
on the generators and connected equipment under phaseto-ground fault conditions, and to permit the application
of suitable ground fault relaying. Suitable neutral grounding equipment should be provided for each generator in
hydroelectric power plants. The generator neutrals should
be provided with current-limiting devices in the neutral
circuits to limit the winding fault currents and resulting
mechanical stresses in the generators in accordance with
IEEE C62.92.2 requirements.
Also, generator circuit
breakers are designed for use on high impedance
grounded systems, where the phase-to-ground short-circuit
current will not exceed 50A. High impedance grounding
with distribution transformers and secondary resistors is
the method of choice for waterwheel generators.
b. Choice of grounding method. The choice of
generator neutral grounding type for each installation, and
the selection of the most suitable type and rating of neutral grounding equipment, should be made after preparation of fault current calculations and consideration of the
following factors:
(1) Limitation of winding fault current and resulting
mechanical stresses in the generator.
(2) Limitation of transient overvoltages due to
switching operations and arcing grounds.
(3) Limitation of dynamic overvoltages to ground on
the unfaulted phases.
(4) Generator surge protection (see paragraph 3-4).
(5) Generator ground fault relaying (see paragraph 8-6b(3)).
(6) Limitation of damage at the fault.
(1) Higher Short-Circuit Ratio (see paragraph 3-2e).
(7) Neutral switchgear requirements.
(2) Higher Wk2 (see paragraph 3-5b).
(8) Cost of neutral grounding equipment.
(3) Above-Normal Thrust.
Calculated efficiencies should be obtained from the supplier as soon as design data for the generators are available. These design efficiencies should be used until test
values are obtained.
c. Solid neutral grounding. Solid neutral grounding
is the simplest grounding method, since transient
overvoltages and overvoltages to ground on the unfaulted
phases during phase-to-ground faults are held to a minimum. Solid neutral grounding does produce maximum
ground fault current and possible damage at the fault.
Solid neutral grounding is not recommended.
3-3. Generator Neutral Grounding
a. General. The main reasons for grounding the neutrals of synchronous generators are to limit overvoltages
d. Reactor neutral grounding.
Reactor neutral
grounding has certain desirable characteristics similar to
those of solid neutral grounding. It is a preferred method
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of grounding in cases where a neutral current-limiting
device is required to meet ANSI/IEEE short-circuit
requirements and where the ratio of the zero sequence
reactance to the positive sequence subtransient reactance
at the fault does not exceed 6.0. Reactor neutral grounding limits transient overvoltages and overvoltages to
ground on the unfaulted phases to safe values where the
above reactance ratio does not exceed approximately 6.0.
However, in most hydro applications, this reactance ratio
approaches or exceeds 6.0, and since the high impedance
distribution transformer-secondary resistor system is more
economical, reactor neutral grounding does not find widespread use in hydro applications.
e. Resistor neutral grounding.
Resistor neutral
grounding can be considered in cases where solid neutral
grounding or reactor neutral grounding would not be
satisfactory; where several generators are paralleled on a
common bus, especially in the case of generators of small
or medium kVA rating; and where there are no exposed
overhead feeders supplied at generator voltage. The resistor is usually rated to limit the generator neutral current
during a phase-to-ground fault to a value between 100 and
150 percent of the generator full-load current. Possible
damage at the fault is thus materially reduced, yet sufficient ground fault current is available to permit the application of satisfactory and selective ground fault relaying.
The technique does produce high voltage to ground,
exposing insulation systems of equipment connected to
the generator to the possibility of insulation failure.
f. Distribution transformer-secondary resistor neutral
(1) This is the preferred method of generator neutral
grounding and is, in effect, high-resistance neutral grounding. This is the method used in most North American
hydro installations because the cost of grounding devices
and neutral switchgear for other grounding methods is
excessive due to the large values of ground fault current.
It is also applicable to generators connected directly to
delta-connected windings of step-up power transformers,
especially where there are no overhead feeders supplied at
generator voltage. The characteristics of this method of
grounding, with respect to transient overvoltages to
ground on the unfaulted phases and the requirement for
the use of ungrounded-neutral rated surge arresters for
generator surge protection, are similar to those of resistor
neutral grounding.
(2) With this method of grounding, the generator
neutral current, during a phase-to-ground fault, is limited
to a very low value, usually between 5A and 15A, by the
use of a relatively low-ohm resistor shunted across the
secondary of a conventional step-down transformer whose
primary is connected in the generator neutral circuit. The
possible damage at the fault is therefore least of any of
the various grounding methods. However, the type of
generator ground fault relaying which can be applied has
certain disadvantages when compared to the relaying
which can be used with other grounding methods. Due to
relatively low relay sensitivity, a considerable portion of
the generator windings near the neutral ends cannot be
protected against ground faults, the relaying is not selective, and the relay sensitivity for ground faults external to
the generator varies greatly with the fault resistance and
the resistance of the return circuit for ground fault current.
The kVA rating of the grounding transformer should be
based on the capacitive current which would flow during
a phase-to-ground fault with the generator neutral
(3) Due to the relative infrequence and short duration of ground faults, a rating of 25 to 100 kVA is usually
adequate for the transformer. The voltage rating of the
transformer high-voltage winding should be equal to rated
generator voltage, and the transformer low-voltage winding should be rated 240 V. The rating of the secondary
resistor is based on making the resistor kW loss at least
equal to the capacitive fault kVA.
g. Generator neutral equipment.
(1) An automatic air circuit breaker should be provided in the neutral circuit of each generator whose neutral is solidly grounded, reactor grounded, or resistor
grounded. The circuit breaker should be a metal-clad,
drawout type, either 1-pole or 3-pole, with a voltage rating at least equal to rated generator voltage, and with
adequate ampere interrupting capacity, at rated voltage,
for the maximum momentary neutral current during a
single phase-to-ground fault. For generator neutral service, the circuit breakers may be applied for interrupting
duties up to 115 percent of their nameplate interrupting
ratings. When 3-pole breakers are used, all poles should
be paralleled on both line and load sides of the breaker.
(2) A single-pole air-break disconnect should be
provided in each generator neutral circuit using distribution transformer-secondary resistor type grounding. The
disconnect should have a voltage rating equal to rated
generator voltage, and should have the minimum available
momentary and continuous current ratings.
disconnect, distribution transformer, and secondary resistor should be installed together in a suitable metal enclosure. The distribution transformer should be of the dry
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type, and its specifications should require a type of insulation that does not require a heater to keep moisture out of
the transformer.
3-4. Generator Surge Protection
a. Surge protection equipment. Since hydroelectric
generators are air-cooled and physically large, it is neither
practical nor economical to insulate them for as high
impulse withstand level as oil-insulated apparatus of the
same voltage class. Because of this and the relative cost
of procuring and replacing (or repairing) the stator winding, suitable surge protection equipment should be provided for each generator. The equipment consists of
special surge arresters for protection against transient
overvoltage and lightning surges, and special capacitors
for limiting the rate of rise of surge voltages in addition
to limiting their magnitude.
b. Insulation impulse level. The impulse level of the
stator winding insulation of new generators is
approximately equal to the crest value of the factory lowfrequency withstand test voltage, or about 40.5 kV for
13.8-kV generators. The impulse breakdown voltages for
surge arresters for 13.8-kV generator protection are
approximately 35 kV for 12-kV grounded-neutral rated
arresters, and approximately 44 kV for 15 kV ungroundedneutral rated arresters. Grounded-neutral rated surge
arresters therefore provide better protection to generators
than ungrounded-neutral rated arresters.
c. Grounded-neutral rated arresters. To correctly
apply grounded-neutral rated arresters without an unacceptable risk of arrester failure, the power-frequency
voltage applied across the arrester under normal or fault
conditions must not exceed the arrester voltage rating.
This requirement is usually met if the ratio of zero
sequence reactance to positive sequence subtransient reactance at the fault, for a single phase-to-ground fault, does
not exceed approximately 6.0. Since distribution transformer-secondary resistor grounding does not meet this
requirement, only ungrounded-neutral rated surge arresters
should be applied for generator surge protection.
d. Arrester arrangement. In most cases, one surge
arrester and one 0.25-microfarad surge capacitor are connected in parallel between each phase and ground. In
certain cases, however, such as the condition where the
generators supply distribution feeders on overhead lines at
generator voltage, or where two or more generators will
be operated in parallel with only one of the generator
neutrals grounded, two of the above capacitors per phase
should be provided. A separate set of surge protection
equipment should be provided for each generator. The
equipment should be installed in metal enclosures located
as close to the generator terminals as possible.
3-5. Mechanical Characteristics
The section of Guide Specification CW-16120 covering
mechanical characteristics of the generator provides for
the inclusion of pertinent data on the turbine. Since generator manufacturers cannot prepare a complete proposal
without turbine characteristics, the generator specification
is not advertised until data from the turbine contract are
a. Speeds.
(1) Hydraulic requirements fix the speed of the unit
within rather narrow limits. In some speed ranges, however, there may be more than one synchronous speed
suitable for the turbine, but not for the generator because
of design limitations.
(2) Generators below 360 r/min and 50,000 kVA and
smaller are nominally designed for 100 percent overspeed.
Generators above 360 r/min and smaller than 50,000 kVA
are generally designed for 80 percent overspeed. Generators larger than 50,000 kVA, regardless of speed, are
designed for 85 percent overspeed. Because of the high
overspeed of adjustable blade (Kaplan) turbines, in some
cases more than 300 percent of normal, it may be impracticable to design and build a generator to nominal design
limitations. Where overspeeds above nominal values are
indicated by the turbine manufacturer, a careful evaluation
of the operating conditions should be made. Also, the
designer should be aware that turbine and generator overspeed requirements are related to the hydraulic characteristics of the unit water inlet structures.
transients that might result from load rejections or sudden
load changes need to be considered.
(3) Generators for projects with Kaplan turbines
have been designed for runaway speeds of 87-1/2 percent
of the theoretical maximum turbine speed. In accordance
with requirements of Guide Specification CW-16120, the
stresses during design runaway speeds should not exceed
two-thirds of the yield point. However, where the design
overspeed is less than the theoretical maximum runaway
speed, calculated stresses for the theoretical maximum
speed should be less than the yield points of the materials.
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b. Flywheel effect.
(1) The flywheel effect (Wk²) of a machine is
expressed as the weight of the rotating parts multiplied by
the square of the radius of gyration. The Wk² of the
generator can be increased by adding weight in the rim of
the rotor or by increasing the rotor diameter. Increasing
the Wk² increases the generator cost, size, and weight, and
lowers the efficiency. The need for above-normal Wk²
should be analyzed from two standpoints, the effect on
power system stability, and the effect on speed regulation
of the unit.
(2) Electrical system stability considerations may in
special cases require a high Wk² for speed regulation. As
Wk² is only one of several adjustable factors affecting
system stability, all factors in the system design should be
considered in arriving at the minimum overall cost. Sufficient Wk² must be provided to prevent hunting and afford
stability in operation under sudden load changes. The
index of the relative stability of generators used in electrical system calculations is the inertia constant, H, which is
expressed in terms of stored energy per kVA of capacity.
It is computed as:
H = kW s = 0.231 (Wk²) (r/min)² x 10-6
(3) The inertia constant will range from 2 to 4 for
slow-speed (under 200 r/min) water wheel generators.
Transient hydraulic studies of system requirements furnish
the best information concerning the optimum inertia constant, but if data from studies are not available, the necessary Wk² can be computed or may be estimated from a
knowledge of the behavior of other units on the system.
Estimates of the effect of increased Wk² on the generator
base cost are indicated by Figure 3-3.
(4) The amount of Wk² required for speed regulation
is affected by hydraulic conditions (head, length of penstock, allowable pressure rise at surge tank, etc.) and the
rate of governor action. The speed increase when full
load is suddenly dropped should be limited to 30 to
40 percent of normal speed. This allowable limit may
sometimes be increased to 50 percent if the economics of
the additional equipment costs are prohibitive. When
station power is supplied from a main generator, the
effect of this speed rise on motor-driven station auxiliaries
should be considered. Smaller generators servicing isolated load blocks should have sufficient Wk² to provide
satisfactory speed regulation. The starting of large motors
on such systems should not cause a large drop in the
isolated system frequency.
Figure 3-3. Effect of increased Wk2 on generator cost
(included by permission of Westinghouse Electric
(5) The measure of stability used in turbine and
governor calculations is called the flywheel constant and
is derived as follows:
Flywheel Constant = (Wk²) (r/min)²
If the horsepower (hp) in this formula is the value corresponding to the kVA (at unity power factor) in the formula
for the inertia constant (H), the flywheel constant will be
numerically equal to 3.23 x 106 multiplied by the inertia
constant. As the actual turbine rating seldom matches the
generator rating in this manner, the flywheel constant
should be computed with the above formula.
c. Cooling.
(1) Losses in a generator appear as heat which is
dissipated through radiation and ventilation. The generator rotor is normally constructed to function as an axial
flow blower, or is equipped with fan blades, to circulate
air through the windings. Small- and moderate-size generators may be partially enclosed, and heated generator air
is discharged into the generator hall, or ducted to the
outside. Larger machines are enclosed in an air housing
with air/water heat exchangers to remove heat losses.
(2) Open cooling systems are normally adequate for
small- and medium-size generators (less than 10 MW). If
special ventilating and air cleaning equipment is required
to accommodate an open cooling system, the cost of these
features should be compared against the cost of having a
generator with a closed air recirculating system with air/
water heat exchangers.
(3) An enclosed air housing with a recirculated air
cooling system with air/water heat exchangers is preferred
for units of 10 MW and larger. Cooling of the generator
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can be more easily controlled with such a system, and the
stator windings and ventilating slots in the core kept
cleaner, reducing the rate of deterioration of the stator
winding insulation system. The closed system also permits the addition of automatic fire protection systems,
attenuates generator noise, and reduces heat gains that
must be accommodated by the powerhouse HVAC
(4) Water-cooled heat exchangers used in a recirculated air cooling system consist of groups of thin-walled
finned tubes with appropriate water boxes, valves, and
headers. Standard air coolers are designed for 50-poundper-square-inch (psi) working pressure, but can be supplied for 100-psi working pressure for a slightly higher
price. The 100-psi rated coolers should be used where
the hydraulic head of the cooling water source is greater
than 100 ft. For best service, tube sheets of 90/10 Cu/Ni
should be used for air and bearing lube oil coolers. The
turbine spiral case is normally used as the cooling water
source for projects with heads of up to 250 ft. Where
project head exceeds approximately 250 ft, pumped systems using a tailwater source are preferred.
(5) The design pressure for the stator heat exchangers
should be based on pump shut-off head if a pumped
source of cooling water is used. Design pressure for
spiral case cooling water sources should be based on
maximum project pool level, plus a surge allowance.
Heat exchanger hydrostatic tests should be performed at
pressures of 150 percent of rated pressure. Design cooling water temperature should be the maximum temperature of the cooling water source, plus a contingency
(6) The water supply line to the air coolers should be
separate from the water line to the thrust-bearing cooler.
It may prove desirable to modulate the water flow to the
air coolers to control the generator temperature, or to shut
it off entirely when the unit is being stopped. It is desirable to keep a full flow of water through the thrust bearing oil cooler whenever the unit is turning. Each cooling
water supply line should be equipped with a flow indicator. The flow indicator should be equipped with an alarm
contact for low flow.
(7) Each air cooler should be equipped with water
shut-off valves so a cooler can be cut out if in trouble, or
be serviced while the generator is operating. Coolers
should be designed with as great a number of heat
exchanger tubes in the air flow passage as practical in
order to reduce water usage. Adequate floor drains inside
the air housing should be provided to remove any water
that may condense on or leak from the coolers. The unit
drain header should empty into the tailwater if plant conditions permit, but the drain should not be terminated
where it will be subject to negative pressures from the
draft tube, since this will impose negative pressures on
the heat exchangers.
(8) Heated air from the generator enclosure should
not be used for plant space heating because of the possibility of exposure of plant personnel to ozone, and the
possibility of CO2 being discharged into the plant. Water
from the coolers may be used as a heat source in a heat
pump type of heating system, but if water flow modulation is used, there may not be enough heat available during periods of light loading, or when the plant is shut
d. Weights and dimensions.
(1) Estimating weights and dimensions of the generators should be obtained from generator manufacturers for
plant design purposes. These figures should be rechecked
after bid data are available on the particular generator
selected. The contemplated speed, Wk², short-circuit ratio,
reactance, and over-speed are the usual factors that have
the greatest effect on weight variation. Where a high
value Wk² is required, a machine of the next larger frame
size with consequent increase in diameter may be
(2) Dimensions of the rotor and the method of
assembling the rotor and the shaft in the generator have
an important bearing on crane clearances. The number
and location of air coolers and the shape of the air housing on a generator with the closed type of cooling system
should be studied for their effect on the dimensions of the
generator room. Generator and turbine access should be
considered, as well as the possible need for suppressing
noise radiated into the powerhouse.
3-6. Excitation Systems
a. General. Current practice in the design of Corps
of Engineers power plants is to use solid state bus-fed
excitation systems for the generator exciter and voltage
regulator function. Solid state excitation systems currently available from reputable manufacturers exhibit
reliability comparable to, and in some cases better than,
older mechanical systems. Excitation system specifications should be carefully prepared, with attention to
requirements of the power system to which the generator
will be connected.
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b. Large generators.
(1) The stability of a large turbine-generator set while
connected to its power system is critically important.
However, the designer must also consider the unit’s characteristics when operating alone, or in an isolated “island”
much smaller than the normal power system.
(2) One example of a unit operating alone is a main
unit serving as the station service source in a plant that
becomes separated from its power distribution system.
The unit will have to accept motor starting loads, and
other station service demands such as gate and valve
operation, while maintaining a safe and stable output
voltage and frequency. All this will be accomplished
while operating at a fraction of its rated output.
(3) When operating in an “island,” the unit may be
required to operate in parallel with other units while running at speed-no-load in order to provide enough capacity
to pick up blocks of load without tripping off line. In this
case, stable operation without the stabilizing effect of a
very large system is critically important to restoring service, and putting the system back together.
c. Small units. For small units producing energy for
a very large system, stability is not so critical since system voltage support will be beyond the small unit’s capability. Nonetheless, for its own safe operation, good
voltage control is important. An extremely high response
system is not necessary, but the system should respond
rapidly enough to prevent dangerous voltage excursions.
d. Excitation system characteristics.
(1) In general, there are two types of static excitation
systems: one using a full-inverting power bridge, and the
other using a semi-inverting power bridge. The fullinverting system uses six (or more) silicon controlled
rectifiers (SCRs) in the power bridge so the generator
field voltage can be forced both positive and negative.
The semi-inverting system allows the generator field
voltage to be forced positive, and reduced to zero.
(2) The full-inverting bridge allows boost and buck
operation much like that available in older systems, but
with the potential for a faster response. Faster response
means less phase shift in the control action, and the
reduction of phase shift permits control action to increase
the stability of voltage regulation (see also
paragraph 3-6g(6)).
(3) Dips in output voltage can be reduced, and voltage recovery speed improved, with the field forcing function.
Increasing the field voltage helps greatly in
overcoming the lag caused by the inductance of the generator field, and increases the speed of response of generator output voltage to control action. However, the exciter
ceiling voltage (maximum forcing voltage available) to
the generator field must be limited to a value that will not
damage field insulation. The manufacturer will determine
the exciter ceiling voltage based on the nominal response
(4) The semi-inverting system also provides for fast
response, but without the capability to force the field
voltage negative with respect to its normal polarity. This
slows the generator output voltage response capability.
One or more diodes provide a path for decaying field
current when the AC contactor is opened.
(5) Power system requirements and machine voltage
performance during unit load rejections should be considered in evaluating the use of a semi-inverting system. If
stability requirements can be met and adequate voltage
performance maintained during unit load rejections, then
either a semi-inverting or a full-inverting system is
acceptable. If either criterion appears compromised, a
full-inverting system is recommended.
(6) If the particular generator (or plant) in question
has sufficient capacity to affect the control area to which
it is connected, a full-inverting voltage regulating system
would be justified if the control area has a high ratio of
energy import (or export) to load, and is marginally stable
or experiences tie line separations. A full-inverting system can force voltage down if an export tie line is lost,
and can force generator voltage down if the machine is
suddenly tripped off line while carrying a substantial load.
Both cases will reduce voltage stresses on the generator;
the first example will assist in maintaining system
stability, the second will help protect the generator winding from dangerous overvoltages.
e. Excitation system arrangement.
(1) In general, bus-fed solid state excitation systems
are made up of three elements: the power potential transformer (PPT), the power bridge (or rectifier), and the
control section (voltage regulator function).
(2) Location of the PPT will depend on the supply
source chosen. If power to the PPT is supplied from the
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generator leads, the bus arrangement will be affected, and
that must be considered in the initial design and layout of
the powerhouse. If the PPT is fed from the generator
delta bus, its location must be selected so that it will be
reasonably close to the power bridge equipment. The
PPT should be specified to be self-cooled, and the
designer should consider this in determining its location.
(3) For either power source to the PPT, protection
should be provided by current-limiting fuses. The available fault current at the input to the PPT will be quite
large, so it will be necessary to limit it to prevent destructive releases of energy at the fault location. Current-limiting fuses also provide circuit clearing without current
surges that can cause voltage transients which are dangerous to the integrity of the generator insulation. When the
fusible element melts, the fuse essentially becomes a
resistor in series with the fault. Voltage and current
across the resistor are thus in phase, and the circuit is
cleared at the first zero crossing, without danger of arc
restrike (if the fuse works properly).
(4) The excitation system should also provide for a
means of disconnecting power from the generator field.
In general, this requires that power be interrupted at the
bridge input, at the generator field input, or at both places,
and that a means of dissipating energy stored in the field
be provided. Energy dissipation is a major consideration,
because without it the field inductance will cause field
voltage to rise sharply when field current is interrupted,
possibly rupturing the field insulation. Several methods
exist to perform the field removal function.
(a) One method of field removal for a semi-inverting
system uses a contactor in the AC input to the power
bridge. For field discharge, a diode (called a freewheeling diode) can be used to provide a path for the
field current to dissipate field energy. Another method is
to provide a shorting contact in series with a discharge
resistor across the generator field. When the Device 41
AC breaker opens, the auxiliary Device 41 shorting contact closes.
(b) A method which can be used with a full-inverting
bridge uses a field breaker and discharge resistor. This is
a straightforward method where the power from the
bridge to the field is interrupted, and the field is
simultaneously short-circuited through a discharge resistor.
(c) With either a semi- or full-inverting bridge, it is
possible to use a device 41 in the DC side of the bridge,
with a thyristor element to control field energy
dissipation. The thyristor device is a three- (or more)
junction semiconductor with a fast OFF to ON switching
time that is capable of going to the conducting state
within a very short time (about one quarter of a cycle)
after the Device 41 opens.
(d) With either a semi- or full-inverting bridge, it is
possible to use a device 41 in the AC (input) side of the
bridge, with a thyristor element to control field energy
dissipation. The thyristor device is a three- (or more)
junction semiconductor with a fast OFF to ON switching
time that is capable of going to the conducting state
within a very short time (about one quarter of a cycle)
after the Device 41 opens.
(5) Power bridge equipment should be housed in a
cubicle by itself, for safety and reduction of electromagnetic noise, and be located near or beside the excitation
control cubicle. Both cubicles should be designed for
reduction of radiated electromagnetic interference (EMI).
(6) The power electronics equipment in the excitation system can be either fan-cooled or self-cooled.
Fan-cooled excitation systems are usually smaller than
self-cooled systems, but require extra equipment for the
lead-lag fan controls. Fan-cooled excitation systems may
require additional maintenance resulting from such things
as fans failing to start, air flow switches failing, fan air
flow causing oil from the turbine pit to be deposited on
filters, and worn-out fan motors causing noise to be
applied to the regulator control system. Self-cooled
excitation systems may require larger cubicles and higherrated equipment to allow for heat transfer. On large
generators, it may not be practical to use a self-cooled
system. On smaller units it may be preferable. Each unit
should be judged on its life cycle costs.
(7) If the capability of connecting a unit to a
de-energized transmission system will be necessary
(“black start” capability), there may be a requirement for
operating the generator at around 25 percent of nominal
voltage to energize transformers and transmission lines
without high inrush currents. This requirement may
impose the need for an alternate power source to the PPT
since the power bridge might not operate reliably at
reduced voltage levels. If an alternate supply source is
needed, provide switching and protection, and ensure that
the normal PPT source and the emergency source cannot
be connected in parallel. The power transmission authority should be consulted to determine the voltage necessary
for charging lines and transformers to re-energize a power
system. Requiring additional power sources not only adds
costs to the project, but complexity to the system, which
may not be justified. The complexity of a system is
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usually proportional to its maintenance, failure, and misoperation rate.
f. Excitation system regulators.
(1) The voltage regulator function of modern solid
state excitation equipment is an integral part of the system, and will use digital control elements with microprocessor-based control. This type of control provides far
more flexibility in changing regulator characteristics than
the older mechanical element type of control. It also
provides more precise and predictable control action, and
will require far less maintenance.
(2) The voltage regulator function should provide
automatic and manual control of generator output voltage,
with “bumpless” transfer between modes, over a range of
at least plus or minus 10 percent from nominal generator
voltage. The bumpless transfer requirement means that
the regulator control modes must track each other so that
when the control mode is switched the generator voltage
(or reactive output) will not exhibit a step change of any
(3) Voltage regulator control to maintain generator
power factor, or maintain a selected var loading may also
be required. If the plant is to have an automatic control
system, provisions should be required for control inputs to
the regulator, and it may be possible to dispense with
some of the regulator control features, particularly if the
plant will not be manned.
g. Excitation system accessories.
(1) An AC input voltmeter, a DC output (field voltage) voltmeter, and a DC field ammeter are accessories
that should be considered essential for a quick check on
system operation. Rectifier failure detection should also
be considered, particularly for units controlled remotely.
(2) Remotely operated controls are also essential for
units controlled from locations remote from the unit
switchboards. Maximum and minimum excitation limiter
equipment should also be provided in all cases. This
equipment is critical to units that are direct connected
with other units on a common bus.
(3) Momentary connection of a DC source of proper
polarity to the generator field (field flashing) should also
be required. Field flashing provides prompt and reliable
buildup of generator voltage without reliance on residual
magnetism. Include protection against overlong application of the flashing source. The simplest source for field
flashing voltage is the station battery. If the unit is not
required to have black start capability, an alternative to
using the station battery is to use an AC power source
with a rectifier to furnish the necessary DC power for
field flashing. This alternative source could be considered
if it is determined to be significantly more economical
than providing additional station battery capacity.
Depending on the design, this alternative could require
additional maintenance in the long term for short-term
cost reductions. Project life cost should be considered
when evaluating the sources of field flashing. A rectifier
can be used as the DC source if the station battery size
can be reduced enough to provide economic justification.
(4) Reactive droop compensation equipment is
needed for units operated in parallel on a common lowvoltage bus to prevent unequal sharing of reactive load.
Reactive droop compensation reduces the generator output
voltage slightly as reactive output increases. The net
effect is to stabilize unit operation when operating in
parallel and tending to prevent var load swings between
(5) Active droop compensation (or “line drop” compensation) is simply a means of artificially relocating the
point where the generator output voltage is sensed for the
voltage regulation function. It consists of increasing the
generator output voltage in proportion to output current, to
compensate for the voltage drop between the generator
output terminals and the desired point on the system.
Active droop compensation should be considered if the
generator is connected to the system through a high
impedance unit transformer or to a long high-impedance
transmission line. Line drop compensation is usually not
required unless needed for power transmission system
voltage stability. This requirement will be established by
the power transmission authority. When used with automatic voltage control that derives its controlled-value
input from the same, or nearly the same, point as the line
drop compensation feature, caution should be used to
ensure that the automatic voltage control system is not
counteracting the effects of the voltage regulator line drop
compensation feature. Close coordination with the power
transmission authority is required to ensure power system
voltage stability.
(6) Power System Stabilizer (PSS) equipment should
be used on generators large enough to have a positive
effect on power system stability. The PSS function tends
to damp out generator rotor oscillations by controlling the
excitation system output in phase opposition to power
system oscillations to damp them out. PSS works by
sensing an input from the power system and reacting to
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oscillations in the power system. These oscillations typically show up in the unit as rotor angle oscillations and if
allowed to continue to build up in conjunction with other
synchronous machines in the system, set up unacceptable
power swings between major loads and major generating
plants in a widely dispersed power distribution grid.
h. Excitation system instrument transformers. Dedicated current and potential transformers should be supplied to service the excitation system voltage regulators.
They can often be advantageously mounted in metal-clad
switchgear, cubicles, or metal-enclosed bus runs, where
they are associated with similar instrument transformers
for metering and relay service. The latter are furnished
and mounted by the manufacturer of the cubicles or
buses, and a better layout can usually be devised, where
all instrument transformers are of the same general form,
than would result if space were provided for field installation of transformers supplied with the voltage regulator.
Multiple-secondary current transformers save considerable
space. The guide specifications provide for alternate
methods of procurement, assuming that the general design
of buses and generator leads will have been determined
before the generator is awarded.
3-7. Generator Stator
a. Stator core stampings. The stator primary component is the thin sheet steel stampings that, when stacked
together and clamped, form the stator core. The stamping
shapes are so designed that when they are correctly
stacked, they will form stator winding coil slots, with no
stamping protruding into the slot. Uneven slots are detrimental to coil life in several ways: wear on ground wall
insulation armor tape; prevention of adequate tightening
of coil in the slot; and, in extreme cases, erosion of the
ground wall insulation.
b. Stator frame.
(1) The stator frame is designed for rigidity and
strength to allow it to support the clamping forces needed
to retain the stator punchings in the correct core geometry. Strength is needed for the core to resist deformation
under fault conditions and system disturbances. Also, the
core is subjected to magnetic forces that tend to deform it
as the rotor field rotates. In a few large size machines,
this flexing has been known to cause the core to contact
the rotor during operation. In one instance, the core
deformed and contacted the rotor, the machine was
tripped by a ground fault, and intense heating caused local
stator tooth iron melting, which damaged the stator winding ground wall insulation.
(2) Even if the rotor and the stator core do not come
in contact, the varying air gap is a problem. In machines
with split phase windings where the split phase currents
are monitored for machine protection, the variation in the
air gap causes a corresponding variation in the split phase
currents. If the variations are significant, the machine
will trip by differential relay action, or the differential
relays will have to be desensitized to prevent tripping.
Desensitizing the relays will work, but it reduces their
effectiveness in protecting the machine from internal
(3) Further reading on this subject can be found in
the IEEE Transactions on Power Apparatus and Systems,
Vol PAS-102, Nos. 9 and 10, and in the AIEE Transactions of October 1953, as Paper 53-314.
c. Stator assembly. Small stator assemblies that can
be shipped in one or two pieces should be completely
assembled at the factory. If the stator frame assembly has
to be shipped in more than two pieces, the core should
probably be stacked in the field. Field stacking will avoid
splits in the stator core, the major source of stator core
problems. Stator frames are generally built at the factory
in sections that are as large as can be shipped to the erection site. Stator assembly is completed in the field by
bolting the sections together, stacking the core iron laminations, and winding the stator. Field stacking of the stator
core results in a higher initial cost for the generator, but
provides better service life and is preferred. Generator
Guide Specification CW-16120 contains a discussion on
stator assembly.
d. Multiturn coil stator windings. On smaller generators, and on certain sizes of larger machines, stator windings employing multiple turn coils are used.
effectively inserts more coils per armature slot, giving a
higher generated voltage per slot as compared with a
single turn bar winding. With this winding design, the
stator winding is divided into two or more parallel paths
per phase. On the neutral ends of the winding, one half
of each phase is connected to the ground point through a
current transformer (CT) of carefully selected ratio and
characteristics. On the generator output, other CTs measure the total phase current. Differential relays compare
the split phase current and total phase current; an internal
generator fault that results in unbalanced current between
the phase halves can usually be detected and the unit
tripped off quickly enough to prevent serious damage.
e. Roebel bar stator windings. For large generators,
winding designs using single turn coils are preferred, in
which case the neutral terminals are not divided and a
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different arrangement of CTs for the differential relays is
required. The single turn coils use a Roebel transposition,
rather than separate turns, to balance current in the conductors. This eliminates the possibility of turn-to-turn
faults, which are a common cause of winding failures.
Single turn coils cannot be used on machines with short
bore heights because there is not sufficient room to make
the Roebel transposition. There are also certain configurations of large machines which do not allow the use of
single turn coils.
3-8. Rotor and Shaft
a. Rotor assembly.
(1) Large generator rotors must be assembled in the
powerhouse. Manufacturing practice provides two types,
one in which the hub and arms are made of cast steel, the
other with a cast or fabricated hub to which are bolted
and keyed the fabricated rotor arms. For rotors with
bolted-on arms, a means of access to inspect and
re-tighten the bolts should be specified. Some mediumsized units have been built with rotors of stacked sheets,
but this type is limited by the rolling width of the sheets.
With both types the rotor rim is built up of sheet steel
(2) Pole pieces, assembled and wound in the factory,
are usually made with a dovetail projection to fit slots in
the rim punchings. The pole pieces are assembled to the
rotor using wedge-shaped keys, two keys per pole piece.
The field assembly program should make provisions for
handling large pole pieces without tying up the powerhouse bridge crane.
b. Generator shafts.
(1) Generator shafts 12-in. and larger diameter should
be gun-barrel drilled full length. This bore facilitates
inspection of the shaft forging, and in the case of Kaplan
units, provides a passage for the two oil pipes to the blade
servo-motor in the turbine shaft.
manufacturer) to which the rotor hub or shaft flange can
be bolted.
(3) If the design of the rotor and shaft provides for a
permanent connection between the shaft and rotor hub, it
may be necessary to locate the rotor erection plate in a
floor recess, or on a pedestal on the floor below the erection space, under a hole in the floor provided for the
shaft. Also, if the complete rotor is to be assembled on a
long shaft which extends below the rotor hub before the
shaft and rotor are placed in the stator, it may be convenient to provide a hole in the erection floor so that the
lower end of the shaft will rest on the floor below, thus
minimizing the crane lift during rotor assembly. When
the shaft must be handled with the rotor in assembling the
generator, the crane clearance above the stator frame may
be affected.
3-9. Brakes and Jacks
The brakes, which are used to stop rotation of the unit,
are actuated by 100-psi air pressure and are designed to
serve as rotor jacks when high-pressure oil is substituted
for air. As far as the generator alone is concerned, the
distance the rotor is to be lifted by the jacks depends on
the space required to change a thrust bearing shoe.
Blocks should be provided to hold the rotor in the raised
position without depending on the jacks. The usual lift
required to service a bearing is approximately 2 in. If the
generator is to be driven by a Kaplan turbine, the lift
must provide space for disconnecting the Kaplan oil piping. This lift may be as much as 12 in. The generator
manufacturer can usually design for this extra lift so
nothing on the generator need be disturbed except to
remove the collector brush rigging. Motor-operated jacking oil pumps can be permanently connected to large
Medium-sized and smaller generators can be
served with a portable motor-operated oil pump. Motoroperated pumps should be provided with suitable oil
supply and sump tanks so the oil system will be complete
and independent of the station lubricating oil system.
3-10. Bearings
(2) Generators designed with the thrust bearing
located below the rotor usually have either a bolted
connection between the bottom of the rotor hub and a
flange on the shaft, or the shaft projects through a hole in
the hub and is keyed to it. Provisions in the powerhouse
for rotor erection should consider the floor loading of the
rotor weight, concentrated on the area of the shaft hub or
the rotor flange, supported by the powerhouse floor.
Include a plate in the floor (included with the generator
specifications and to be supplied by the generator
a. Thrust bearing loading. The thrust bearing in the
generator is the most important bearing element in the
generator-turbine assembly as it carries not only the
weight of the rotating generator parts, but the weight of
the turbine shaft and turbine runner, in addition to the
hydraulic thrust on the runner. The allowable hydraulic
thrust provided in standard generator design is satisfactory
for use with a Francis runner, but a Kaplan runner
requires provision for higher-than-normal thrust loads. It
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is important that the generator manufacturer have full and
accurate information regarding the turbine.
b. Thrust bearing types. The most commonly used
types of thrust bearings are the Kingsbury, the modified
Kingsbury, and the spring-supported type. The spherical
type of thrust bearing has not been used on any Corps of
Engineers’ generators. All of these types have the bearing parts immersed in a large pot of oil that is cooled
either by water coils immersed in the oil or by the oil
pumped through a heat-exchanger mounted near the bearing. These various types of bearings are fully described
in available texts, such as “The Mechanical Engineers’
Handbook” (Marks 1951) and “Mechanical Engineers’
Handbook” (Kent 1950).
c. Thrust bearing lubrication. The basic principle of
operation of all bearing types requires a film of oil
between the rotating bearing plate and the babbitted stationary shoes. The rotating parts on some machines are
so heavy that when the machine is shut down for a few
hours, the oil is squeezed out from between the bearing
surfaces and it is necessary to provide means to get oil
between the babbitted surface and the bearing plate before
the unit is started. Specifications for generators above
10 MW, and for generators in unmanned plants, should
require provisions for automatically pumping oil under
high pressure between the shoes and the runner plate of
the thrust bearing just prior to and during machine startup,
and when stopping the machine.
d. Guide bearings. A guide bearing is usually provided adjacent to the thrust bearing and is lubricated by
the oil in the thrust bearing pot. Except for Kaplan units,
machines with guide bearings below the rotor seldom
require an upper guide bearing. When the thrust bearing
is above the rotor, a lower guide bearing is required.
Two guide bearings should always be provided on generators for use with Kaplan turbines. These separate guide
bearings have self-contained lubricating systems. Oil in
the bearings seldom needs to be cleaned or changed, but
when cleaning is necessary, the preferred practice is to
completely drain and refill the unit when it is shut down.
Valves on oil drains should be of the lock-shield type to
minimize possibility of accidental draining of the oil
during operation.
3-11. Temperature Devices
a. Types of temperature devices. All generator and
turbine bearings are specified to have three temperature
sensing devices: a dial-type indicating thermometer with
adjustable alarm contacts, embedded resistance
temperature detector (RTD) devices, and a temperature
relay (Device 38). The dial portions of the indicating
thermometers are grouped on a panel which can be part of
the governor cabinet, mounted on the generator barrel, or
on another panel where they can be easily seen by maintenance personnel or a roving operator.
b. Dial indicator alarms. The dial indicator alarm
contacts are set a few degrees above the normal bearing
operating temperatures to prevent nuisance alarms. When
approaching their alarm setpoint, these contacts tend to
bounce and chatter. If they are used with event recorders,
they can produce multiple alarms in rapid succession
unless some means are used to prevent this.
c. RTDs. RTD leads are brought out to terminal
blocks, which are usually mounted in the generator terminal cabinet on the generator air housing. Turbine bearing
RTD leads should be terminated in the same place as the
generator RTD leads. For bearings equipped with more
than one RTD, it is usually adequate to monitor only one,
and let the other(s) serve as spares. Thrust bearings may
have six or more RTDs. Monitoring three or four of
them is usually satisfactory. Generator stator windings
usually have several RTDs per phase. On the larger
machines, monitor two RTDs per phase, and keep the
remainder as spares.
d. RTD monitoring.
How the RTDs are used
depends partly on the decisions made about the plant
control system. They can be scanned by the analog input
section of a remote terminal unit (RTU) if the plant is
controlled remotely, or they can be used as inputs to a
local stand-alone scanner system, with provisions for
remote alarms and tripping the unit on high temperatures.
In any case, permanent records of bearing temperatures
are no longer retained.
e. Control action. Whether to alarm or trip on RTD
temperature indication depends on other decisions about
how the plant will be controlled, and what kind of control
system is used. For automated plants, stator temperature
increases can be used as an indication to reduce unit load
automatically, for instance.
f. Air temperature indicators. Air temperature indicators in air cooler air streams are used to balance the
cooling water flow, and to detect cooler problems. Air
temperature alarms should be taken to the control point,
or input to the plant control system if the plant is
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g. Temperature relays. Temperature relays are typically used to shut the unit down on high bearing temperatures, 105 °C or so. Separate contacts should also be
provided for alarming. Note that once a bearing temperature reaches the trip point, the damage has been done. It
is almost never possible to save the bearing. Tripping the
unit promptly is done to save damage to other parts of the
unit resulting from failure of the bearing. Temperature
relay alarm points should be taken to the annunciator, and
to the RTU or plant control system. It is not necessary to
provide sequence of event recording for the Device 38
because the bearing temperature event is such a slow
(3) Special field test (one unit of serial). These tests
consist of:
(a) Efficiency tests.
(b) Heat run tests.
(c) Machine parameter tests.
(d) Excitation test.
(e) Overspeed tests (optional).
c. Testing considerations.
3-12. Final Acceptance Tests
a. General. Because of the size of water wheel generators, they are normally assembled in the field, and
because of their custom design, it is advisable to perform
a series of acceptance and performance tests on the generators during and following their field assembly. The
purpose of these tests is to ensure that the units meet
contractual performance guarantees, to provide a quality
control check of field assembly work, and finally to provide a “bench mark” of “as-built” conditions serving as an
aid in future maintenance and repair activities. Certain
field tests are performed on every generator of a serial
(multi-unit) purchase; other tests are performed on only
one unit of the serial purchase, e.g., tests for ensuring
conformance with contractual guarantees.
b. Field acceptance tests and special field tests.
These tests are as follows:
(1) Field quality control tests (all units). A series of
dielectric and insulation tests for the stator and field windings, performed during field work, including turn-to-turn
tests, coil transposition group tests, and semiconducting
slot coating-to-stator iron resistance tests, to monitor field
assembly techniques.
(2) Field acceptance tests (all units).
consist of:
These tests
(a) Stator dielectric tests. These tests consist of:
Insulation resistance and polarization index, Corona probe
test, Corona visibility test, Final AC high potential test,
Partial discharge analysis (PDA) test, and Ozone detection
(b) Rotor dielectric tests.
(c) Stator and rotor resistance tests.
(1) Planning for tests on the generator after its
installation should begin prior to completion of the generator specifications. Any generator that must be assembled
in the powerhouse will require field testing after installation to measure values of efficiency and reactances, particularly when efficiency guarantees are included in the
purchase specifications.
The generator manufacturer
performs these tests with a different crew from those
employed for generator erection. Specification CW 16120
requires a second generator in the powerhouse with special switching equipment and “back-fed” excitation system
to permit performing retardation tests used to determine
generator efficiency. In addition, special arrangements are
required to use one of the generator-voltage class breakers
as a shorting breaker during sudden short-circuit tests.
(2) The manufacturer requires considerable advance
notice of desirable testing dates in order to calibrate test
instruments and ship in necessary switchgear and excitation equipment. If the associated turbine is to be given a
field efficiency test, it may be desirable to coordinate the
turbine and generator tests so that the electrical testing
instruments will be available to measure generator output
during the turbine test. The heat run requires a load on
the generator. Normally, the generator is loaded by connecting the generator output to the system load. If system
load isn’t sufficient to load the generator, IEEE 115 outlines alternative techniques to simulate load conditions.
(3) The testing engineer may elect to use the plant
instrument transformers instead of calibrated current and
potential transformers if reliable data on plant instrument
transformers are available.
(4) Generator erectors usually apply dielectric tests
on the armature (stator) and field windings before the
rotor is put into the machine. If the stator is wound in
the field, a high potential test is usually done once each
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day on all of the coils installed during that day. This
facilitates repairs if the winding fails under test and may
preclude missing scheduled “on-line” dates. The test
voltages for these intermediate tests must be planned so
that each one has a lower value than the previous test, but
greater than the test voltage specified for the final high
potential test.
(5) IEEE 43 describes the polarization index test.
This index is the ratio of the insulation resistance obtained
with a 10-min application of test voltage to that obtained
with a similar application for a 1-minute period. Recommended indices and recommended insulation resistance
values are also given in the referenced standard.
(b) Because of the relatively small amount of insulation on the field windings, simple insulation (Megger)
tests are adequate to determine their readiness for the
high-voltage test. Guide Specification CW-16120 requires
the dielectric test to be made with the field winding connected to the collector rings and hence the test cannot be
made until after the generator is assembled with the DC
leads of the static excitation system connected.
3-13. Fire Suppression Systems
Generators with closed air recirculation systems should be
provided with automatic carbon dioxide extinguishing
systems. See Chapter 15 of EM 1110-2-4205 for details.
On larger open ventilated generators, water spray installations with suitable detection systems to prevent false
tripping should be considered.
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Chapter 4
Power Transformers
4-1. General
a. Type. Step-up transformers for use with main
units should be of the oil immersed type for outdoor
operation, with a cooling system as described in paragraph 4-3, suited to the location. General Corps of Engineers power transformer design practice is covered by
Guide Specification for Civil Works Construction
b. Three-phase transformers.
In the majority of
applications, three-phase transformers should be used for
generator step-up (GSU) applications for the following
(1) Higher efficiency than three single-phase units of
equivalent capacity.
(2) Smaller space requirements.
(3) Lower installed cost.
(4) Lower probability of failure when properly protected by surge arresters, thermal devices, and oil preservation systems.
(5) Lower total weight.
(6) Reduction in weights and dimensions making
larger capacities available within practical weight and size
c. EHV applications. In applications involving interconnection to EHV (345 kV and above) systems, reliability and application considerations dictate the use of
single-phase units due to lack of satisfactory industry
experience with three-phase EHV GSU transformers. The
basic switching provisions discussed in Chapter 2 describe
the low-voltage switching scheme used with EHV
d. Transformer features.
Regardless of winding
configuration, for any given voltage and kVA rating, with
normal temperature rise, the following features should be
analyzed for their effect on transformer life cycle costs:
(1) Type of cooling.
(3) Departure from normal design impedance.
Examples of typical transformer studies which should be
performed are contained in Appendix B of this manual.
e. Transformer construction. There are two types of
construction used for GSU transformers. These are the
core form type and the shell form type. Core form transformers generally are supplied by manufacturers for lower
voltage and lower MVA ratings. The core form unit is
adaptable to a wide range of design parameters, is economical to manufacture, but generally has a low kVA-toweight ratio. Typical HV ranges are 230 kV and less and
75 MVA and less. Shell form transformers have a high
kVA-to-weight ratio and find favor on EHV and high
MVA applications. They have better short-circuit strength
characteristics, are less immune to transit damage, but
have a more labor-intensive manufacturing process. Both
forms of construction are permitted by Corps’ transformer
guide specifications.
4-2. Rating
The full load kVA rating of the step-up transformer should
be at least equal to the maximum kVA rating of the generator or generators with which they are associated.
Where transformers with auxiliary cooling facilities have
dual or triple kVA ratings, the maximum transformer
rating should match the maximum generator rating.
4-3. Cooling
a. General. The standard classes of transformer cool
ing systems are listed in Paragraph 5.1, IEEE C57.12.00.
Transformers, when located at the powerhouse, should be
sited so unrestricted ambient air circulation is allowed.
The transformer rating is based on full use of the transformer cooling equipment.
b. Forced cooling. The use of forced-air cooling
will increase the continuous self-cooled rating of the
transformer 15 percent for transformers rated 2499 kVA
and below, 25 percent for single-phase transformers rated
2500 to 9999 kVA and three-phase transformers rated
2500 to 11999 kVA, and 33-1/3 percent for single-phase
transformers rated 10000 kVA and above and three-phase
transformers rated 12000 kVA and above. High-velocity
fans on the largest size groups will increase the selfcooled rating 66-2/3 percent. Forced-oil cooled transformers, whenever energized, must be operated with the
circulating oil pumps operating. Forced-oil transformers
with air coolers do not have a self-cooled rating without
(2) Insulation level of high-voltage winding.
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the air-cooling equipment in operation unless they are
special units with a “triple rating.”
c. Temperature considerations. In determining the
transformer rating, consideration should be given to the
temperature conditions at the point of installation. High
ambient temperatures may necessitate increasing the transformer rating in order to keep the winding temperature
within permissible limits. If the temperatures will exceed
those specified under “Service Conditions” in IEEE
C57.12.00, a larger transformer may be required. IEEE
C57.92 should be consulted in determining the rating
required for overloads and high temperature conditions.
d. Unusual requirements. Class OA/FA and Class
FOA meet all the usual requirements for transformers
located in hydro plant switchyards. The use of triplerated transformers such as Class OA/FA/FA is seldom
required unless the particular installation services a load
with a recurring short time peak.
e. Class FOA transformers. On Class FOA transformers, there are certain considerations regarding static
electrification (build-up of charge on the transformer
windings due to oil flow). Transformer suppliers require
oil pump operation whenever an FOA transformer is
energized. Static electrification is important to consider
when designing the desired operation of the cooling, and
can result in the following cooling considerations:
(2) Consideration should also be given to the voltage
rating specified for the low-voltage winding. For plants
connected to EHV systems, the low-voltage winding
rating should match the generator voltage rating to
optimally match the generator’s reactive capability in
“bucking” the transmission line voltage. For 230-kV
transmission systems and below, the transformer lowvoltage rating should be 5 percent below the generator
voltage rating to optimally match the generator’s reactive
capability when “boosting” transmission line voltage.
IEEE C57.116 and EPRI EL-5036, Volume 2, provide
further guidance on considerations in evaluating suitable
voltage ratings for the GSU transformer.
b. High-voltage BIL.
(1) Basic Impulse Insulation Levels (BIL) associated
with the nominal transmission system voltage are shown
in Table 1 of IEEE C57.12.14. With the advent of metal
oxide surge arresters, significant economic savings can be
made in the procurement of power transformers by specifying reduced BIL levels in conjunction with the application of the appropriate metal oxide arrester for transformer
surge protection. To determine appropriate values, an
insulation coordination study should be made (see Appendix B for a study example). Studies involve coordinating
and determining adequate protective margins for the following transformer insulation characteristics:
(a) Chopped-Wave Withstand (CWW).
(1) Decrease in oil flow velocity requirements (for
forced-oil cooled units).
(2) Modifying of cooling equipment controls to have
pumps come on in stages.
(3) Operation
4-4. Electrical Characteristics
a. Voltage.
(1) Voltage ratings and ratios should conform to
ANSI C84.1 preferred ratings wherever possible. The
high-voltage rating should be suitable for the voltage of
the transmission system to which it will be connected,
with proper consideration for increases in transmission
voltage that may be planned for the near future. In some
cases this may warrant the construction of high-voltage
windings for series or parallel operation, with bushings
for the higher voltage, or windings suitable for the higher
voltage tapped for the present operating voltage.
(b) Basic Impulse Insulation Level (BIL).
(c) Switching Surge Level (SSL).
(2) If there is reason to believe the transmission
system presently operating with solidly grounded neutrals
may be equipped with regulating transformers or neutral
reactors in the future, the neutral insulation level should
be specified to agree with Table 7 of IEEE C57.12.00.
c. Impedance.
(1) Impedance of the transformers has a material
effect on system stability, short-circuit currents, and transmission line regulation, and it is usually desirable to keep
the impedance at the lower limit of normal impedance
design values. Table 4-1 illustrates the range of values
available in a normal two-winding transformer design
(values shown are for GSU transformers with
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Table 4-1
Nominal Design Impedance Limits for Power Transformers Standard Impedance Limits (Percent)
13.8-kV low voltage). Impedances within the limits
shown are furnished at no increase in transformer cost.
Transformers can be furnished with lower or higher values ofimpedance at an increase in cost. The approximate
effect of higher- or lower-than-normal impedances on the
cost of transformers is given in Table 4-2. The value of
transformer impedance should be determined giving consideration to impacts on selection of the interrupting capacities of station breakers and on the ability of the generators to aid in regulating transmission line voltage.
Transformer impedances should be selected based on system and plant fault study results (see Chapter 2). Impedances shown are subject to a tolerance of plus or minus
7.5 percent. (See IEEE C57.12.00).
Table 4-2
Increase In Transformer Cost For Impedances Above
and Below The Standard Values
(2) In making comparisons or specifying the value of
impedance of transformers, care should be taken to place
all transformers on a common basis. Impedance of a
18 .75
transformer is a direct function of its rating, and when a
transformer has more than one different rating, it has a
different impedance for each rating. For example, to
obtain the impedance of a forced-air-cooled transformer at
the forced-air-cooled rating when the impedance at its
self-cooled rating is given, it is necessary to multiply the
impedance for the self-cooled rating by the ratio of the
forced-air-cooled rating to the self-cooled rating.
d. Transformer efficiency. Transformer losses represent a considerable economic loss over the life of the
power plant. A study should be made to select minimum
allowable efficiencies for purposes of bidding. Included
in the study should be a determination of the present
worth cost of transformer losses. This value is used in
evaluating transformer bids that specify efficiency values
that exceed the minimum acceptable value. Examples of
typical studies are included in Appendix B of this manual.
IEEE C57.120 provides further guidance on transformer
loss evaluation.
4-5. Terminals
Where low-voltage leads between the transformer and
generator are of the metal-enclosed type, it is desirable to
extend the lead housing to include the low-voltage terminals of the transformer. This arrangement should be
indicated on the specification drawings and included in
the specifications in order that the manufacturer will coordinate his transformer top details with the design of the
housing. It is sometimes preferable to have the transformer builder furnish the housing over the low-voltage
bushings if it simplifies the coordination. All bushing
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characteristics should conform to the requirements of
IEEE C57.19.01. The voltage rating should correspond to
the insulation level of the associated winding. Where
transformers are installed at elevations of more than
3,300 ft above sea level, bushings of the next higher
voltage classification may be required. Bushings for
neutral connections should be selected to suit the insulation level of the neutral, as discussed in paragraph 4-4.
4-6. Accessories
a. Oil preservation systems. Three different oil preservation systems are available, as described below. The
first two systems are preferred for generator step-up
(1) Inert gas pressure system. Positive nitrogen gas
pressure is maintained in the space between the top of the
oil and the tank cover from a cylinder or group of cylinders through a pressure-reducing valve.
(2) Air-cell, constant-pressure, reservoir tank system.
A system of one or more oil reservoirs, each containing
an air cell arranged to prevent direct contact between the
oil and the air.
(3) Sealed tank. Gas is admitted to the space above
the oil and the tank is sealed. Expansion tanks for the
gas are provided on some sizes. Sealed tank construction
is employed for 2,500 kVA and smaller sizes.
b. Oil flow alarm. Transformers that depend upon
pumped circulation of the oil for cooling should be
equipped with devices that can be connected to sound an
alarm, to prevent closing of the energizing power circuit,
or to deenergize the transformer with loss of oil flow. In
forced-oil-cooled units, hot spot detectors should be provided which can be connected to unload the transformer if
the temperature exceeds that at which the second oil
pump is expected to cut in. FOA transformers should
employ control schemes to ensure pump operation prior to
energizing the transformer.
c. Surge arresters. Surge arresters are located near
the transformer terminals to provide protection of the
high-voltage windings. Normal practice is to provide
brackets on the transformer case (230-kV HV and below)
for mounting the selected surge arrester.
d. Fans and pumps. The axial-flow fans provided for
supplementary cooling on Class OA/FA transformers are
equipped with special motors standardized for 115-V and
230-V single-phase or 208-V three-phase operation. Like-
wise, oil circulating pumps for FOA transformers are set
up for single-phase AC service. Standard Corps of Engineers practice is to supply 480-V, three-phase power to
the transformer and have the transformer manufacturer
provide necessary conversion equipment.
e. On-line dissolved gas monitoring system. The
detection of certain gases, generated in an oil-filled transformer in service, is frequently the first available indication of possible malfunction that may eventually lead to
the transformer failure if not corrected. The monitoring
system can provide gas analysis of certain gases from gas
spaces of a transformer. The system output contacts can
be connected for an alarm or to unload the transformer if
the gas levels exceed a set point. The type of gases generated, during the abnormal transformer conditions, is
described in IEEE C57.104.
f. Temperature detectors. A dial-type temperature
indicating device with adjustable alarm contacts should be
provided for oil temperature indication. Winding RTDs
should be provided, and monitored by the plant control
system or a stand-alone temperature recorder, if one is
provided for the generator and turbine RTDs. At least
two RTDs in each winding should be provided.
g. Lifting devices. If powerhouse cranes are to be
used for transformer handling, the manufacturer’s design
of the lifting equipment should be carefully coordinated
with the crane clearance and with the dimensions of the
crane hooks. The lifting equipment should safely clear
bushings when handling the completely assembled transformer, and should be properly designed to compensate
for eccentric weight dispositions of the complete transformer with bushings.
h. On-line monitoring systems. In addition to the
on-line dissolved gas monitoring system described in
paragraph 4-6e, other on-line systems are available to
monitor abnormal transformer conditions. These include:
(1) Partial discharge analysis.
(2) Acoustical monitoring.
(3) Fiber-optic winding temperature monitoring.
(4) Bearing wear sensor (forced-oil-cooled units).
(5) Load tap changer monitor (if load tap changers
are used).
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Early detection of the potential for a condition leading to
a forced outage of a critical transformer bank could more
than offset the high initial costs of these transformer
accessories by avoiding a more costly loss of generation.
i. Dial-type indicating devices.
devices should be provided for:
Dial-type indicating
(1) Liquid level indication.
(2) Liquid temperature indicator.
(3) Oil flow indicators (see paragraph 4-6b).
These are in addition to the dial-type indicators that are
part of the winding temperature systems (see
paragraph 4-6f).
4-7. Oil Containment Systems
If any oil-filled transformers are used in the power plant,
provisions are made to contain any oil leakage or spillage
resulting from a ruptured tank or a broken drain valve.
The volume of the containment should be sufficient to
retain all of the oil in the transformer to prevent spillage
into waterways or contamination of soil around the transformer foundations. Special provisions (oil-water separators, oil traps, etc.) must be made to allow for separation
of oil spillage versus normal water runoff from storms,
etc. IEEE 979 and 980 provide guidance on design considerations for oil containment systems.
transformers are located in close proximity to adjacent
transformers, plant equipment, or power plant structures.
Oil-filled transformers contain the largest amount of combustible material in the power plant and so require due
consideration of their location and the use of fire suppression measures. Fires in transformers are caused primarily
from breakdown of their insulation systems, although
bushing failures and surge arrester failures can also be
causes. With failure of the transformer’s insulation system, internal arcing follows, creating rapid internal tank
pressures and possible tank rupture. With a tank rupture,
a large volume of burning oil may be expelled over a
large area, creating the possibility of an intense fire.
b. Suppression measures.
Suppression measures
include the use of fire quenching pits or sumps filled with
coarse rock surrounding the transformer foundation and
physical separation of the transformer from adjacent
equipment or structures. Physical separation in distance is
also augmented by the use of fire-rated barriers or by firerated building wall construction when installation prevents
maintaining minimum recommended separations. Economical plant arrangements generally result in less than
recommended minimums between transformers and adjacent structures so water deluge systems are supplied as a
fire prevention and suppression technique. The systems
should be of the dry pipe type (to prevent freeze-up in
cold weather) with the system deluge valves actuated
either by thermostats, by manual break-glass stations near
the transformer installation, or by the transformer differential protective relay.
4-8. Fire Suppression Systems
a. General. Fire suppression measures and protective
equipment should be used if the plant’s oil-filled
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Chapter 5
High-Voltage System
5-1. Definition
The high-voltage system as treated in this chapter includes
all equipment and conductors that carry current at transmission line-voltage, with their insulators, supports,
switching equipment, and protective devices. The system
begins with the high-voltage terminals of the step-up
power transformers and extends to the point where transmission lines are attached to the switchyard structure.
High-voltage systems include those systems operating at
69 kV and above, although 34.5-kV and 46-kV systems
that are subtransmission-voltage systems are also covered
in this chapter. Transmission line corridors from the
powerhouse to the switchyard should allow adequate
clearance for maintenance equipment access, and clear
working space. Working clearances shall be in accordance with the applicable sections of ANSI C2, Part 2.
5-2. Switchyard
a. Space around the switchyard. Adequate space
should be allowed to provide for extension of the switchyard facilities when generating units or transmission lines
are added in the future. The immediate surroundings
should permit the building of lines to the switchyard area
from at least one direction without the need for heavy
dead-end structures in the yard.
b. Switchyard location. Subject to these criteria, the
switchyard should be sited as near to the powerhouse as
space permits, in order to minimize the length of control
circuits and power feeders and also to enable use of service facilities located in the powerhouse.
c. Switchyard fencing. A chain link woven wire
fence not less than 7 ft high and topped with three strands
of barbed wire slanting outward at a 45-deg angle, or concertina wire, with lockable gates, should be provided to
enclose the entire yard. Other security considerations are
discussed in EM 1110-2-3001.
5-3. Switching Scheme
The type of high-voltage switching scheme should be
selected after a careful study of the flexibility and protection needed in the station for the initial installation, and
also when the station is developed to its probable maximum capacity. A detailed discussion of the advantages
and disadvantages of various high-voltage switching
schemes is included in this chapter.
a. Minimum requirements. The initial installation
may require only the connecting of a single transformer
bank to a single transmission line. In this case, one circuit breaker, one set of disconnects with grounding
blades, and one bypass disconnecting switch should be
adequate. The high-voltage circuit breaker may even be
omitted under some conditions. The receiving utility
generally establishes the system criteria that will dictate
the need for a high side breaker.
b. Bus structure. When another powerhouse unit or
transmission line is added, some form of bus structure
will be required. The original bus structure should be
designed with the possibility of becoming a part of the
ultimate arrangement. Better known arrangements are the
main and transfer bus scheme, the ring bus scheme, the
breaker-and-a-half scheme, and the double bus-double
breaker scheme.
c. Main and transfer bus scheme.
(1) The main and transfer bus scheme, Figure 5a,
consists of two independent buses, one of which is normally energized. Under normal conditions, all circuits are
tied to the main bus. The transfer bus is used to provide
service through the transfer bus tie breaker when it
becomes necessary to remove a breaker from service.
(2) Advantages of the main and transfer bus arrangement include:
(a) Continuity of service and protection during breaker maintenance.
(b) Ease of expansion.
(c) Small land area requirements.
(d) Low cost.
(3) Disadvantages include:
(a) Breaker failure or bus fault causes the loss of the
entire station.
(b) Bus tie breaker must have protection schemes to
be able to substitute for all line breakers.
(c) An additional tie breaker is required.
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(d) Double feed to each circuit.
(e) Expandable to breaker-and-a-half scheme.
(3) Disadvantages include:
(a) Each circuit must have its own potential source.
(b) Usually limited to four circuits.
e. Breaker-and-a-half scheme.
(1) The breaker-and-a-half arrangement, Figure 5-1c,
provides for two main buses, both normally energized.
Between the buses are three circuit breakers and two
circuits. This arrangement allows for breaker maintenance without interruption of service. A fault on either
bus will cause no circuit interruption. A breaker failure
results in the loss of two circuits if a common breaker
fails and only one circuit if an outside breaker fails.
(2) The advantages of the breaker-and-a-half scheme
(a) High reliability and operational flexibility.
(b) Capability of isolating any circuit breaker or
either main bus for maintenance without service
Figure 5-1. Switchyard bus arrangements
d. Ring bus scheme.
(1) The ring bus, Figure 5-1b, consists of a loop of
bus work with each bus section separated by a breaker.
Only limited bus sections and circuits can be removed
from service in the event of a line or bus fault. A line
fault results in the loss of the breakers on each side of the
line, while a breaker failure will result in the removal of
two bus sections from service. The ring bus arrangement
allows for circuit breaker maintenance without interruption of service to any circuit.
(2) The advantages of the ring bus scheme include:
(a) Low cost (one breaker per line section).
(b) High reliability and operational flexibility.
(c) Continuity of service during breaker and bus
(c) A bus fault does not interrupt service.
(d) Double feed to each circuit.
(e) All switching can be done with circuit breakers.
(3) The disadvantages include:
(a) Added cost of one half breaker for each circuit.
(b) Protection
f. Double bus-double breaker scheme.
(1) The double bus-double breaker arrangement,
Figure 5-1d, consists of two main buses, both normally
energized. Between the main buses are two breakers and
one circuit. This arrangement allows for any breaker to
be removed from service without interruption to service to
its circuit. A fault on either main bus will cause no circuit outage. A breaker failure will result in the loss of
only one circuit.
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(2) The advantages of the double bus-double breaker
scheme include:
(2) Structural considerations including ice and wind
loading, short-circuit forces, and seismic loads.
(a) Very high reliability and operational flexibility.
The spacing of bus supports should limit bus sag under
maximum loading to not greater than the diameter of the
bus, or 1/150th of the span length. IEEE 605 provides
further information on substation electrical, mechanical,
and structural design considerations.
(b) Any breaker or either bus can be isolated without
service interruption.
(c) A bus fault does not interrupt service.
5-5. Switchyard Materials
(d) There is a double feed to each circuit.
(e) All switching is done with circuit breakers.
(f) Only one circuit is lost if a breaker fails.
(3) The disadvantages include the high cost of two
breakers per circuit.
g. Recommended scheme.
The breaker-and-a-half
scheme is generally recommended, as it provides flexibility and a reasonably simple method of providing full
relay protection under emergency switching conditions.
The number of sections (line “bays”) needed is dependent
on the number of transmission lines and generation
sources coming into the substation. The breaker-and-ahalf scheme is normally designed and operated as a ring
bus until system requirements dictate more than six
breakers and six lines.
5-4. Bus Structures
a. Arrangements. The flat or low profile type of bus
construction with pedestal-supported rigid buses and Aframe line towers is ordinarily the most economical where
space and topography are favorable. Congested areas
may require the use of a high, narrow steel structure and
the use of short wire bus connections between disconnecting switches and the buses. Switchyard layouts should
provide adequate access for safe movement of maintenance equipment and the moving of future circuit breakers
or other major items of equipment into position without
de-energizing primary buses. Clearances to energized
parts should, as a minimum, comply with ANSI C2, Section 12. Equipment access requirements should be based
on the removal of high-voltage bushings, arresters, and
conservators and radiators from large power transformers.
b. Bus design criteria. The design of rigid bus systems is influenced by the following criteria:
(1) Electrical considerations including corona and
ampacity limitations.
a. General. After design drawings showing a general layout of the switchyard and details of electrical
interconnections have been prepared, a drawing should be
made up to accompany the specifications for the purchase
of the structures. This drawing should show the size,
spacing, and location of principal members and the loadings imposed by electrical equipment and lines. Design
load assumptions for bus structures are described in
EM 1110-2-3001.
b. Structure materials. The following are four types
of material most commonly used for substation structures:
(1) Steel. Steel is the most commonly used material.
Its availability and good structural characteristics make it
economically attractive. Steel, however, must have adequate corrosion protection such as galvanizing or painting.
Due to the maintenance associated with painting, galvanizing is generally preferred. Galvanized steel has an
excellent service record in environments where the pH
level is in the range of 5.4 through 9.6 (i.e., a slightly
alkaline environment). Most industrial environments are
in this pH range leading to the widespread use and excellent service record of galvanized steel structures. Because
of the unbroken protective finish required, structures
should not be designed to require field welding or drilling.
Adequate information to locate mounting holes, brackets,
and other devices must be provided to the fabricator to
allow all detail work to be completed before the protective finish is applied to the steel part.
(2) Aluminum. In environments where the pH level
is below 5.4 (i.e. an acidic environment, such as conditions existing in a brine mist), galvanized structures would
give poor service. In these environments, consideration
should be given to structures fabricated with aluminum
members. Aluminum structures are satisfactory at other
locations, if the installed cost is comparable to the cost of
the equivalent design using galvanized steel members.
Structures designed for aluminum are constructed of Alloy
6061-T6 and should be designed, fabricated, and erected
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in accordance with the Aluminum Association’s specifications for aluminum structures.
line is terminated on a dead-end structure near the
(3) Concrete. Pre-cast, pre-stressed concrete structures may be economical in some applications such as
pull-off poles and switch structures. Care should be taken
to avoid the use of detrimental additives, such as calcium
chloride, to the concrete used in the structures. Due to
the larger structural sizes and weights involved, special
equipment may be required for concrete erection.
c. Test terminals. To provide a safe and accurate
method of transformer dielectric testing, accommodations
should be made for easily isolating transformer bushings
from the bus work. Double test terminals should be provided on transformer high-voltage and neutral bushings in
accordance with Corps of Engineers practice. The design
should provide adequate clearance from energized lines
for personnel conducting the tests.
(4) Wood. Wood pole and timber structures may be
economical for temporary structures or simple switch
structures. Wood members must be treated with an
appropriate preservative. Structural properties and size
tolerances of wood are variable and must be considered
during the design process.
c. Bus materials. The materials most commonly used
for rigid and wire bus are aluminum and copper. Rigid
bus fittings should be limited to bolted connections for
copper, and welded connections on aluminum. Bus fittings for aluminum wire should be compression type.
Either bolted or compression fittings are acceptable for
use with copper wire bus.
5-6. Transformer Leads
a. High-voltage terminal connections. The connections between the high-voltage terminals of the transformer and the disconnect switch (or breaker) will usually
be made with bare overhead conductors when the transformer is located in the switchyard. However, in cases
where the transformer is in line with the axis of the disconnect, the connection between the disconnect terminals
and the high-voltage bushing terminals can be made with
suitably supported and formed rigid bus of the same type
used in the rest of the switchyard. The fittings and interconnection systems between the high-voltage bus and the
disconnect switches should be designed to accommodate
conditions of frequent load cycling and minimal
b. Overhead conductors. Bare overhead conductors
from the transmission line termination to the high-voltage
bushings can occasionally be used when the transformers
are installed at the powerhouse, and overhead lines to the
switchyard are used. An example of this would be when
the transmission line is dead-ended to the face of the dam,
and the transformer is located at the base of the dam near
its face, and behind the powerhouse. However, locating
the transformers at the powerhouse usually requires the
use of high-voltage bus to the line termination when the
5-7. Powerhouse - Switchyard Power Control and
Signal Leads
a. Cable tunnel.
(1) A tunnel for power and control cables should be
provided between the powerhouse and switchyard whenever practical. Use of a tunnel provides ready access to
the cables, provides for easy maintenance and expansion,
and offers the easiest access for inspection. This tunnel
should extend practically the full length of the switchyard
for access to all of the switchyard equipment.
(2) The control and data (non-signal) cables should
be carried in trays in the tunnel, and continued in steel
conduits from the trays to circuit breakers and other controlled equipment so as to eliminate the need for manholes and handholes. If there is a control house in the
switchyard, it should be situated over the tunnel. The
tunnel should be lighted and ventilated and provided with
suitable drains, or sumps and pumps.
(3) If the generator leads, transformer leads, or station service feeders are located in the tunnel, the amount
of heat dissipated should be calculated and taken into
consideration in providing tunnel ventilation. The power
cables should be carefully segregated from the control and
data acquisition cables to prevent electromagnetic interference, and to protect the other cables from damage resulting from power cable faults. If the tunnel lies below a
possible high-water elevation, it should be designed to
withstand uplift pressures.
(4) Signal cables should be physically separated
from power and control circuits. If practical, the signal
cable should be placed in cable trays separate from those
used for either control or power cables. In no case should
signal cables be run in conduit with either control or
power cables. The physical separation is intended to
reduce the coupling of electromagnetic interference into
the signal cable from pulses in the (usually unshielded)
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control cables, or power system frequency energy from
power cables. Even though the signal cable will be
shielded, commercially available shielding does not provide 100 percent coverage or perfect shielding, and the
separation is needed to reduce electrical noise superimposed on the signal.
b. Duct line. For small installations having a limited
amount of transforming and switching equipment, it may
be desirable and economical to use duct lines instead of a
cable tunnel for control and power cables. The duct
system should use concrete encased nonmetallic conduit,
and manholes or handholes of adequate number and size
should be provided. Separate ducts for the power cables
and the control and data acquisition cables should be
provided. At least 30 percent spare duct capacity should
be provided for power cables, and 50 percent spare capacity provided for control and data acquisition cables. The
manholes should be designed to drain unless costs are
c. High-voltage bus.
(1) General. There are three categories of high-voltage connection systems that find application in hydroelectric installations requiring high-voltage interconnection
between the power plant and the switchyard or utility grid
interconnection. These are as follows:
(a) Oil or SF6 gas-insulated cable with paper-insulated
conductors. Cables commonly used for circuits above
69 kV consist of paper-insulated conductors pulled into a
welded steel pipeline, which is filled with insulating oil or
inert gas. The oil or gas in the pipe type construction is
usually kept under about 200 psi pressure. These cables
can safely be installed in the same tunnel between the
powerhouse and the switchyard that is used for control
(b) Solid dielectric-insulated cable. Solid dielectricinsulated cables are also available for systems above
69 kV. Their use may be considered, but careful evaluation of their reliability and performance record should be
made. They offer advantages of ease of installation,
elimination of oil or gas system maintenance, and lower
cost. Their electrical characteristics should be considered
in fault studies and stability studies.
(c) SF6 gas-insulated bus. An example of a typical
installation is an underground power plant with a unit
switching scheme and the GSU transformer located underground in the plant. A high-voltage interconnection is
required through a cable shaft or tunnel to an aboveground on-site switchyard.
(2) Direct burial. While insulated cable of the type
described can be directly buried, the practice is not recommended for hydroelectric plants because the incremental cost of a tunnel normally provided for control circuits
and pipelines is moderate. In case of oil leaks or cable
failure, the accessibility of the cable pipes in the tunnel
will speed repairs and could avoid considerable loss in
revenue. Space for the location of cable terminal equipment should be carefully planned.
(3) Burial trench. If the power cables from the
powerhouse to the switchyard must be buried directly in
the earth, the burial trench must be in accordance with
safety requirements, provide a firm, conforming base to
lay the cable on, and provide protection over the cable.
The cable must have an overall shield, which must be
well-grounded, to protect, so far as possible, people who
might accidently penetrate the cable while digging in the
burial area.
(4) SF6 gas-insulated systems. SF6 gas-insulated
systems offer the possibility of insulated bus and complete
high-voltage switchyard systems in a compact space.
Gas-insulated substation systems should be considered for
underground power plant installations or any situation
requiring a substation system in an extremely confined
space. The design should accommodate the need for
disassembly of each part of the system for maintenance or
repair. The designer should also consider that the gas is
inert, and in a confined space will displace oxygen and
cause suffocation. After exposure to arcing, SF6 gas
contains hazardous byproducts and special precautions are
needed for evacuating the gas and making the equipment
safe for normal maintenance work. SF6 gas pressure
varies with temperature and will condense at low ambient
temperatures. When SF6 equipment is exposed to low
temperatures, heating must be provided. The manufacturer’s recommendations must be followed.
C37.123 provides guidance on application criteria for gas
insulated substation systems.
5-8. Circuit Breakers
a. Interrupting capacity. The required interrupting
rating of the circuit breakers is determined by short-circuit
fault studies. (See Chapter 2.) In conducting the studies,
conservative allowances should be made to accommodate
ultimate system growth. If information of system capacity and characteristics is lacking, an infinite bus at the end
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of the transmission interconnection can be assumed.
Using an infinite bus will result in conservative values of
fault kVA to be interrupted, and will probably not unduly
influence the final result. ANSI C37.06 provides performance parameters of standard high-voltage breakers.
b. Design considerations.
(1) Breakers for 69 kV and above generally are SF6
gas-insulated, with the dead tank design preferred for
seismic considerations. The details of the relaying will
determine the number of CTs required, but two CTs per
pole should generally be the minimum. Three CTs may
be required for the more complex switching arrangements,
such as the breaker-and-a-half scheme.
(2) At 230 kV and above, two trip coils are preferred.
The integrity of the tripping circuit(s) should be monitored and if remotely controlled, the status should be
telemetered to the control point. The gas system of SF6
breakers should be monitored since loss of SF6 gas or low
gas pressure blocks breaker operation.
(3) Breaker auxiliary “a” and “b” switch contacts are
used extensively to initiate and block the operation of
backup relaying schemes. As breakers are added, and
protection added to cover new system contingencies, the
protective relay schemes become more complex. To
accommodate these situations, breakers should be purchased with at least eight “a” and eight “b” spare auxiliary contacts.
(4) Layout of the substation should consider access
required for maintenance equipment, as well as horizontal
and vertical electrical clearance for the switches in all
normal operating positions.
(5) Specifications prepared for outdoor applications of
SF6 power circuit breakers should provide the expected
ambient operating temperature ranges so the breaker manufacturer can provide adequate heating to ensure proper
operation of the breaker through the ambient operating
range. Minimum standard operating ambient for SF6
equipment is -30 °C (IEEE Standard C37.122).
5-9. Disconnect Switches
a. Disconnect operators. Manual or motor-operated
gang-operated disconnect switches should be provided for
isolating all circuit breakers. For operating voltages of
230 kV or greater, or for remotely operated disconnects,
the disconnects should be motor operated. In some cases,
depending on the switching scheme and substation layout,
one or both of the buses will be sectionalized by disconnects. The sectionalizing disconnect switches may be
either manual or motor-operated, depending on their voltage rating and the requirements of station design. The
manual operating mechanism for heavy, high-voltage
disconnects should preferably be of the worm gear, crankoperated type.
b. Remotely operated disconnects. Remotely operated disconnect switches should be installed only as line
or breaker disconnects. Use of a remotely operated disconnect switch to serve as generator disconnect is strongly
discouraged. Operation of generator disconnects should
require visual verification (through operator presence) of
the open position and a lockable open position to prevent
the possibility of misoperation or misindication by reconnecting an out-of-service generator to an energized line.
c. Disconnect features.
All disconnect switches
should be equipped with arcing horns. The disconnect
switch on the line side of the line circuit breakers should
be equipped with grounding blades and mechanically
interlocked operating gear. At 230 kV and above, line
and generator disconnect switches should be of the rotating insulator, vertical break type, with medium- or highpressure contacts. Circuit breaker isolation switches may
be either a two-insulator “V” or a side break type. Both
the contacts and the blade hinge mechanism should be
designed and tested to operate satisfactorily under severe
ice conditions. At 345 kV and 500 kV, vertical break
disconnects are preferred since they allow for reduced
phase spacing and installation of surge suppression resistors. Each switch pole should have a separate motor
5-10. Surge Arresters
a. Preferred arrester types. Surge arresters should
be of the station type (preferably a metal oxide type) that
provides the greatest protective margins to generating
station equipment.
b. Arrester location. Arresters should be located
immediately adjacent to the transformers, if the connection between the transformers and switching equipment is
made by overhead lines. If high-voltage cable is used for
this connection, the arresters should be placed both near
the switchyard terminals of the cable and adjacent to the
transformer terminals. Arrester connections should be
designed to accommodate removal of the arrester without
removing the main bus connection to the high-voltage
bushing. Location of arresters should be in accordance
with IEEE C62.2.
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c. Arrester protection. In all cases, enough space
should be allowed between arresters and other equipment
to prevent damage if the arresters should fail. If arresters
are located where they form a hazard to operating personnel, they should be suitably enclosed. This can generally
be accomplished with a woven wire fence provided with a
lockable gate. The design of the enclosure should consider the clearance requirements for the switchyard operating voltage.
d. Arrester voltage rating. The voltage rating of the
arresters should be selected to provide a reasonable margin between the breakdown voltage of the arrester and the
basic impulse insulation level (BIL) of the equipment
protected. The rating, in the majority of cases, should be
the lowest satisfactory voltage for the system to which the
arresters are connected.
e. Grounded-neutral arresters.
(1) In applying grounded-neutral rated arresters, the
designer should consider whether, under all conditions of
operation, the system characteristics will permit their use.
Grounded-neutral arresters should not be used unless one
of the following conditions will exist:
(a) The system neutral will be connected to the system ground through a copper grounding conductor of
adequate size (solidly grounded) at every source of supply
of short-circuit current.
(b) The system neutral is solidly grounded or is
grounded through reactors at a sufficient number of the
sources of supply of short-circuit current so the ratio of
the fundamental-frequency zero-sequence reactance, Xo, to
the positive sequence reactance, X1, as viewed from the
point of fault, lies between values of 0 and 3.0 for a
ground fault to any location in the system, and for any
condition of operation. The ratio of the zero-sequence
resistance, Ro, to the positive sequence reactance, X1, as
viewed from the ground fault at any location, should be
less than 1.0. The arrester should have suitable characteristics so that it will not discharge during voltage rises
caused by switching surges or fault conditions.
(2) Consideration should be given to the protection
of transmission line equipment that may be located
between the arresters and the incoming transmission line
entrance to the substation. In cases where the amount of
equipment is extensive or the distance is substantial, it
will probably be desirable to provide additional protection
on the incoming transmission line, such as spark gaps or
(3) If the station transformers are constructed with
the high-voltage neutral connection terminated on an
external (H0) bushing, a surge arrester should be applied
to the bushing.
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Chapter 6
Generator-Voltage System
6-1. General
The generator-voltage system described in this chapter
includes the leads and associated equipment between the
generator terminals and the low-voltage terminals of the
GSU transformers, and between the neutral leads of the
generator and the power plant grounding system. The
equipment generally associated with the generator-voltage
system includes switchgear; instrument transformers for
metering, relaying, and generator excitation systems;
neutral grounding equipment; and surge protection equipment. The equipment is classified as medium-voltage
6-2. Generator Leads
a. General. The term “generator leads” applies to the
circuits between the generator terminals and the lowvoltage terminals of the GSU transformers. The equipment selected depends upon the distance between the
generator and transformer, the capacity of the generator,
the type of generator breakers employed, and the economics of the installation. There are two general classes of
generator leads: those consisting of metal-enclosed buses
and those consisting of medium-voltage cables. The two
classes, their advantages, disadvantages, and selection
criteria are discussed in the following subparagraphs.
b. Metal-enclosed buses. There are three categories
of metal-enclosed bus: nonsegregated-phase, segregatedphase, and isolated-phase. Each type has specific applications dependent mainly on current rating and type of
circuit breaker employed with the bus.
(1) Nonsegregated-phase buses. All phase conductors
are enclosed in a common metal enclosure without barriers, with phase conductors insulated with molded material
and supported on molded material or porcelain insulators.
This bus arrangement is normally used with metal-clad
switchgear and is available in ratings up to 4,000 A
(6,000 A in 15-kV applications) in medium-voltage
switchgear applications.
(2) Segregated-phase buses. All phase conductors are
enclosed in a common enclosure, but are segregated by
metal barriers between phases. Conductor supports usually are of porcelain. This bus arrangement is available in
the same voltage and current ratings as nonsegregatedphase bus, but finds application where space limitations
prevent the use of isolated-phase bus or where higher
momentary current ratings than those provided by the
nonsegregated phase are required.
(3) Isolated-phase buses. Each phase conductor is
enclosed by an individual metal housing, which is separated from adjacent conductor housings by an air space.
Conductor supports are usually of porcelain. Bus systems
are available in both continuous and noncontinuous housing design. Continuous designs provide an electrically
continuous housing, thereby controlling external magnetic
flux. Noncontinuous designs provide external magnetic
flux control by insulating adjacent sections, providing
grounding at one point only for each section of the bus,
and by providing shorting bands on external supporting
steel structures. Noncontinuous designs can be considered
if installation of the bus will be at a location where competent field welders are not available. However, continuous housing bus is recommended because of the difficulty
in maintaining insulation integrity of the noncontinuous
housing design during its service life. Isolated-phase bus
is available in ratings through 24,000 A and is associated
with installations using station cubicle switchgear (see
discussion in paragraph 6-7b).
c. Metal-enclosed bus application criteria.
(1) For most main unit applications, the metalenclosed form of generator leads is usually preferred, with
preference for the isolated-phase type for ratings above
3,000 A. Enclosed buses that pass through walls or floors
should be arranged so as to permit the removal of housings to inspect or replace insulators.
(2) On isolated-phase bus runs (termed “delta bus”)
from the generators to a bank of single-phase GSU transformers, layouts should be arranged to use the most
economical combination of bus ratings and lengths of
single-phase bus runs. The runs (“risers”) to the singlephase transformers should be sized to carry the current
corresponding to the maximum kVA rating of the
(3) Metal-enclosed bus connections to the GSU
transformer that must be supported at the point of connection to the transformer should have accommodations permitting the bus to be easily disconnected should the
transformer be removed from service. The bus design
should incorporate weather-tight closures at the point of
disconnection to prevent moisture from entering the interior of the bus housing.
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(4) On all enclosed bus runs, requirements for
enclosing the connections between the bus and the lowvoltage bushings of the GSU transformer should be coordinated and responsibilities for scopes of supply clearly
defined between transformer supplier and bus supplier.
Details of the proposed design of the connector between
the GSU transformer bushing terminals and the bus terminal should be evaluated to ensure probability of reliable
service life of the connection system.
d. Insulated cables.
(1) Cables may be appropriate for some small generators or in installations where the GSU transformer is
located in the plant’s switchyard. In the latter situation,
economic and technical evaluations should be made to
determine the most practical and cost-effective method to
make the interconnection. Cables, if used, should have
copper conductors. Acceptable cable types include:
(a) Single conductor, ethylene-propylene-rubber
(EPR) insulated, with non-PVC jacket.
(b) Multi-conductor, ethylene-propylene-rubber (EPR)
insulated cables, with aluminum or steel sheath, and nonPVC jacket, in multiple if necessary to obtain capacity.
(c) Oil-pipe cable systems.
(2) Oil-filled cable terminations with cables terminated with a conductor lug and a stress cone should be
used for terminating oil-pipe cable systems. Cold shrink
termination kits should be used for terminating single and
multi-conductor EPR cables. Termination devices and
kits should meet the requirements of IEEE 48 for Class I
(3) When cables of any type are run in a tunnel, the
effect of cable losses should be investigated to determine
the safe current-carrying capacity of the cable and the
extent of tunnel ventilation required to dissipate the heat
generated by these losses. Locations where hot spots may
occur, such as risers from the tunnel to equipment or
conduit exposed to the sun, should be given full
6-3. Neutral Grounding Equipment
Equipment between the generator neutral and ground
should, insofar as practicable, be procured along with the
generator main leads and switchgear. The conductor may
be either metal-enclosed bus or insulated cable in nonmagnetic conduit. Generator characteristics and system
requirements determine whether the machine is to be
solidly grounded through a circuit breaker (usually not
possible), through a circuit breaker and reactor (or resistor), or through a disconnecting switch and a distribution
type of transformer (See Chapter 3.) Solidly grounded
systems do not find wide application because resulting
fault currents initiated by a stator to ground fault are
much higher than currents produced by alternative neutral
grounding systems. Higher ground fault currents lead to
higher probability of damage to the stator laminations of
the connected generator. If a circuit breaker is used in
the grounding scheme, it can be either a single-pole or a
standard 3-pole air circuit breaker with poles paralleled to
form a single-pole unit. Suitable metal enclosures should
be provided for the reactors, resistors, or grounding transformers used in the grounding system.
6-4. Instrument Transformers
a. General. The instrument transformers required
for the unit control and protective relaying are included in
procurements for metal-clad switchgear breakers that are
to be employed for generator switching. The instrument
transformers are mounted in the switchgear line-up with
potential transformers mounted in draw-out compartments
for maintenance and service. Current transformers for the
GSU transformer zone differential relay are also mounted
in the metal-clad switchgear cubicles. In isolated-phase
bus installations, the instrument transformers are included
in procurement for the isolated-phase bus. The current
transformers, including those for generator differential and
transformer differential protection, are mounted “in-line”
in the bus with terminations in external terminal compartments. Required potential transformers are mounted in
dedicated compartments tapped off the main bus leads.
The dedicated compartments also contain the generator
surge protection equipment (see Chapter 3, “Generators”).
Specified accuracy classes for instrument transformers for
either type of procurement should be coordinated with the
requirements of the control, protective relaying, and
metering systems. Instrument transformers for the generator excitation system should be included in the appropriate
b. Current transformers. Current transformers of the
multiple secondary type are usually required and are
mounted in the isolated-phase bus or in the metal-clad
switchgear to obtain the necessary secondary circuits
within a reasonable space. Current transformers in the
neutral end of the generator windings are usually mounted
in the generator air housing. Accessibility for shortcircuiting the secondary circuits should be considered in
the equipment layout. The current transformers should be
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designed to withstand the momentary currents and shortcircuit stresses for which the bus or switchgear is rated.
c. Potential transformers. The potential transformers
for metering and for excitation system service are housed
in separate compartments of the metal-clad switchgear. If
station cubicle breakers or isolated-phase bus are
involved, a special cubicle for potential transformers and
surge protection equipment is provided in a variety of
arrangements to simplify generator lead connections.
Potential transformers should be protected by currentlimiting resistors and fuses. Draw-out type mountings are
standard equipment in metal-clad switchgear. Similar
arrangements are provided in cubicles associated with
isolated-phase bus. Cubicles with the isolated-phase buses
also provide phase isolation for transformers.
6-7. Circuit Breakers
a. General.
The particular switching scheme
selected from those described in Chapter 2, “Basic
Switching Provisions,” the generator voltage and capacity
rating, and results from fault studies will determine the
type of generator breaker used for switching, together
with its continuous current rating and short-circuit current
rating. If a “unit” switching scheme is chosen with
switching on the high side of the GSU transformer, then
criteria regarding high-voltage power circuit breakers as
described in Chapter 5, “High-Voltage System” are used
to select an appropriate breaker. If a generator-voltage
switching scheme is selected, then criteria outlined in this
paragraph should be used for breaker selection.
b. Generator-voltage circuit breaker types.
6-5. Single Unit and Small Power Plant
When metal-clad switchgear is used for generators in
small plants (having typically one or two generators of
approximately 40,000 kW or less) the switchgear may be
equipped with indicating instruments, control switches,
and other unit control equipment (e.g., annunciators and
recorders) mounted on the switchgear cell doors. This
arrangement can take the place of a large portion of the
conventional control switchboard. The switchgear may be
located in a control room, or the control room omitted
entirely, depending upon the layout of the plant. Current
philosophy is to make the smaller plants suitable for
unmanned operation, and remote or automatic control.
This scheme eliminates the need for a control room.
Arrangements for control equipment with this type of
scheme are described in more detail in Chapter 8,
“Control System.”
6-6. Excitation System Power Potential
The power potential transformer (PPT) is fed from the
generator leads as described in paragraph 3-6e(2), Chapter 3, “Generators.” The PPT is procured as part of the
excitation system equipment. The PPT should be a threephase, 60-Hz, self-cooled, ventilated dry type transformer.
The PPT is generally tapped at the generator bus with
primary current limiting fuses, designed for floor mounting, and with a low-voltage terminal chamber with provisions for terminating the bus or cable from the excitation
system power conversion equipment.
(1) When generator-voltage circuit breakers are
required, they are furnished in factory-built steel enclosures in one of three types. Each type of circuit breaker
has specific applications dependent on current ratings and
short-circuit current ratings. In general, Table 6-1 provides a broad overview of each breaker type and its range
of application for generator switching. The three types
are as follows:
(a) Metal-clad switchgear. Metal-clad switchgear
breakers can be used for generator switching on units of
up to 45 MVA at 13.8 kV, depending on interrupting duty
requirements. Details of construction are covered in
Guide Specification for Civil Works Construction CWGS16345. Either vacuum interrupters or SF6 interrupting
mediums are permitted by the guide specification.
(b) Station-type cubicle switchgear.
breakers can be used in generator switching applications
on units of approximately 140 MVA. Details of construction are covered in IEEE C37.20.2. For SF6 circuit
breakers, the insulating and arc-extinguishing medium is
the gas. For indoor equipment, in areas not allowed to
reach temperatures at or near freezing, the gas will probably not require heating provisions. However, special care
and handling is needed for SF6 gas.
(c) In-line isolated-phase bus breakers. For highcurrent, medium-voltage, generator breaker applications,
i.e., 15 kV, 6,000 Amp or higher, in-line breakers
mounted in the isolated-phase bus system have been
employed on high-capacity systems.
These breakers
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Table 6-1
Generator Breaker Application Table, 13.8-kV Application
Upper Limit
Rating, kA
Current Rating
@ 13.8 kV
Breaker Type
40 kA
Draw Out
SF6 or
63 kA
Station Cubicle
100 kA
In-line isolatedphase bus
air blast
* 478 MVA @ 20 kA
employ either SF6 or compressed air insulating and arc
extinguishing systems and can incorporate breaker isolating switches in the breaker compartment. This type of
breaker requires less space than a station type cubicle
breaker but has higher initial cost. It should receive consideration where powerhouse space is at a premium.
Technical operating parameters and performance are covered in IEEE C37.013.
(2) The essential features of draw-out metal-clad
switchgear and station type cubicle switchgear are covered
in IEEE C37.20.2. Essential features of in-line isolatedphase bus-type circuit breakers are covered in IEEE
C37.013 and C37.23. Specific current and interrupting
ratings available at other voltages are summarized in
Tables 6-2 and 6-3.
Table 6-2
Indoor Metal-Clad Switchgear, Removable Breaker Nominal Ratings
Phase protection is by insulated buses
1.2, 2
1.2, 2
1.2, 2
1.2, 2
1.2, 3
Voltage Rating
Note: The voltage range factor, K, is the ratio of maximum voltage to the lower limit of the range of operating voltage in which the required
symmetrical and asymmetrical current interrupting capabilities vary in inverse proportion to the operating voltage. See ANSI C37.06.
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Table 6-3
Indoor Metal-Enclosed Switchgear, Fixed Breaker Preferred Ratings For Generator Circuit Breakers 4/
Phase protection is by steel barriers
1/ Typical values, in kA: 6.3, 8.0, 10.0, 12.0, 16.0, 20.0, 25.0, 30.0 and 40.0.
2/ Typical values in kA: 63, 80, 100, 120, 160, 200, 250, 275.
3/ Symmetrical interrupting capability for polyphase faults shall not exceed the short-circuit rating. Single-phase-to-ground fault interrupting
capability shall not exceed 50A.
4/ IEEE C37.013.
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Chapter 7
Station Service System
7-1. Power Supply
a. General. A complete station service supply and
distribution system should be provided to furnish power
for station, dam auxiliaries, lighting, and other adjacent
features of the project. The loss of a station service
source, either through switching operations or due to
protective relay action, should not leave the plant without
service power. The station service system should have a
minimum of two full-capacity, redundant power sources.
b. Plant “black start” capability.
(1) General. “Black start” capability is desirable at
hydro plants since the plants can assist in re-establishing
generation for the power system in an emergency. “Black
start” capability is defined as the ability of the plant,
without an external source of power, to maintain itself
internally, start generating units, and bring them up to
speed-no-load conditions, close the generator breakers,
energize transformers and transmission lines, perform line
charging as required, and maintain units while the remainder of the grid is re-established. The plant must then
resynchronize to the grid.
(2) Power system problems.
(a) There are a number of circumstances that can lead
to collapse of all or parts of a bulk power distribution
system. Regardless of the circumstances, the triggering
event generally leads to regional and subregional mismatch of loads and generation and “islanding” (i.e., plants
providing generation to isolated pockets of load). Separation of generation resources from remote loads and
“islanding” can cause voltage or frequency excursions that
may result in the loss of other generation resources, particularly steam generation, which is more sensitive to
frequency excursions than hydroelectric turbine generators. Steam generation is also harder to return to service
than hydro generation, so the burden of beginning system
restoration is more likely to fall on hydro resources.
(b) When a transmission line is removed from service
by protective relay action, the power it was carrying will
either seek another transmission line route to its load, or
be interrupted. If its power is shifted to other transmission lines, those lines can become overloaded and also be
removed from service by protective relays.
failures are more likely to happen during heavy load periods, when failures cascade because of stress on the system. If the hydro units are running at or near full load
when the plant is separated from the system, they will
experience load rejections.
(c) Units subjected to a load rejection are designed
to go to speed-no-load until their operating mode is
changed by control action. Sometimes, however, they
shut down completely, and if station service is being
supplied by a unit that shuts down, that source will be
lost. Units can’t be started, or kept on line, without governor oil pressure, and governor oil pressure can’t be
maintained without a source of station service power for
the governor oil pumps.
(d) Assumptions made concerning plant conditions
when the transmission grid collapses, thus initiating the
need for a “black start,” will define the equipment
requirements and operating parameters which the station
service design must meet. At least one emergency power
source from an automatic start-engine-driven generator
should be provided for operating governor oil pumps and
re-establishing generation after losing normal station service power.
c. For large power plants.
(1) Two station service transformers with buses and
switching arranged so that they can be supplied from
either the main generators or the transmission system
should be provided, with each transformer capable of
supplying the total station load. A unit that will be operated in a base load mode should be selected to supply a
station service transformer, if possible. Station service
source selection switching that will allow supply from
either a main unit or the power system should be provided. The switching should be done by interlocked
breakers to prevent inadvertent parallel operation of alternate sources. If a main unit is switched on as a source,
then the supply should not depend on that unit being
connected to the power system. If the power system is
switched on as the source, then the supply should not
depend on any units being connected to the power system.
(2) To meet Federal Energy Regulatory Commission
(FERC) requirements, all reservoir projects should be
equipped with an engine-driven generator for emergency
standby service with sufficient capacity to operate the
spillway gate motors and essential auxiliaries in the dam.
The unit is usually installed in or near the dam rather than
in the powerhouse. It may also be used to provide emergency service to the powerhouse, although the use of long
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supply cables from the dam to the powerhouse could be a
(3) For a large power plant, a second automatic start
emergency power source may be required in the powerhouse. Besides diesel engine-generators, small combustion turbines are an option, although they are more
complex and expensive than diesel engine-generator sets.
(4) Any emergency source should have automatic
start control. The source should be started whenever
station service power is lost. The emergency source
control should also provide for manual start from the
plant control point. It is also important to provide local
control at the emergency source for non-emergency starts
to test and exercise the emergency source. A load shedding scheme may be required for any emergency source,
if the source capacity is limited.
d. For small, one-unit power plants. One station
service transformer supplied from the transmission system
should be provided for a normal station service bus, and
an emergency station service bus should be supplied from
an engine-driven generator. The emergency source should
have sufficient capacity to operate the spillway gate
motors and minimum essential auxiliaries in the dam and
powerhouse such as unwatering pumps, governor oil
pumps, and any essential preferred AC loads.
e. Station service distribution system.
(1) In many plants, feeders to the load centers can be
designed for 480-V operation. In a large plant, where
large loads or long feeder lengths are involved, use of
13.8-kV or 4.16-kV distribution circuits will be satisfactory
when economically justified.
Duplicate feeders (one
feeder from each station service supply bus) should be
provided to important load centers. Appropriate controls
and interlocking should be incorporated in the design to
ensure that critical load sources are not supplied from the
same bus. Feeder interlock arrangements, and source
transfer, should be made at the feeder source and not at
the distribution centers.
(2) The distribution system control should be thoroughly evaluated to ensure that all foreseeable contingencies are covered. The load centers should be located at
accessible points for convenience of plant operation and
accessibility for servicing equipment. Allowance should
be made for the possibility of additional future loads.
(3) All of the auxiliary equipment for a main unit is
usually fed from a motor control center reserved for that
Feeders should be sized based on maximum
expected load, with proper allowance made for voltage
drop, motor starting inrush, and to withstand short-circuit
currents. Feeders that terminate in exposed locations
subject to lightning should be equipped with surge arresters outside of the building.
(4) Three-phase, 480-V station service systems using
an ungrounded-delta phase arrangement have the lowest
first cost. Such systems will tolerate, and allow detection
of, single accidental grounds without interrupting service
to loads. Three-phase, grounded-wye arrangements find
widespread use in the industrial sector and with some
regulatory authorities because of perceived benefits of
safety, reliability, and lower maintenance costs over a
480-V delta system. Industrial plants also have a higher
percentage of lighting loads in the total plant load. Installation costs for providing service to large concentrations
of high-intensity lighting systems are lower with
480/277-V wye systems. Delta systems are still preferred
in hydro stations because of the cleaner environment,
good service record, and skilled electricians available to
maintain the system.
f. Station service switchgear.
(1) Metal-clad switchgear with SF6 or vacuum circuit
breakers should be supplied for station service system
voltage above 4.16 kV. Metal-enclosed switchgear with
600-V drawout air circuit breakers should be used on
480-V station service systems. The switchgear should be
located near the station service transformers.
(2) The station service switchgear should have a
sectionalized bus, with one section for each normal station
service source. Switching to connect emergency source
power to one of the buses, or selectively, to either bus
should be provided. If the emergency source is only
connected to one bus, then the reliability of the station
service source is compromised since the bus supplied
from the emergency source could be out of service when
an emergency occurred. It is preferable that the emergency source be capable of supplying either bus, with the
breakers interlocked to prevent parallel operation of the
buses from the emergency source.
(3) Each supply and bus tie breaker should be electrically operated for remote operation from the control
room in attended stations. As a minimum, bus voltage
indication for each bus section should be provided at the
remote point where remote plant operation is provided.
Transfer between the two normal sources should be automatic. Transfer to the emergency power sources should
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also be automatic when both normal power sources fail.
Feeder switching is performed manually except for specific applications.
(4) In large station service systems with a double bus
arrangement, source/bus tie breakers should be located at
each end of the switchgear compartment. The source/bus
tie breakers should not be located in adjacent compartments because a catastrophic failure of one breaker could
destroy or damage adjacent breakers leading to complete
loss of station service to the plant. In large plants where
there is sufficient space, it is even safer to provide a
separate, parallel cubicle lineup for each station service
bus for more complete physical isolation. Even with this
arrangement, feeder and tie breakers should not be located
in adjacent compartments.
(5) For 480-V station service systems, a deltaconnected, ungrounded system is recommended for the
following reasons:
(a) Nature of the loads. The load in a hydroelectric
power plant is made up predominantly of motor loads. In
a commercial or light industrial facility, where the load is
predominantly lighting, the installation of a 480/277 V,
wye-connected system is more economical due to the use
of higher voltages and smaller conductor sizes. These
economies are not realized when the load is predominantly motor loads. For high bay lighting systems, certain
installation economies may be realized through the use of
480/277-V wye-connected subsystems, as described in
Chapter 12.
(b) Physical circuit layout. Wye-connected systems
allow the ability to quickly identify and locate a faulted
circuit in a widely dispersed area. Although hydroelectric
power plants are widely dispersed, the 480-V system is
concentrated in specific geographic locales within the
plant, allowing rapid location of a faulted circuit, aided by
the ground detection system described in paragraph 7-2.
7-2. Relays
An overlapping protected zone should be provided around
circuit breakers. The protective system should operate to
remove the minimum possible amount of equipment from
service. Overcurrent relays on the supply and bus tie
breakers should be set so feeder breakers will trip on a
feeder fault without tripping the source breakers. Ground
overcurrent relays should be provided for wye-connected
station service systems. Ground detection by a voltage
relay connected in the broken delta corner of three potential transformers should be provided for ungrounded or
delta-connected systems (ANSI C37.96). Bus differential
relays should be provided for station service systems of
4.16 kV and higher voltage. The adjustable tripping
device built into the feeder breaker is usually adequate for
feeder protection on station service systems using 480-V
low-voltage switchgear.
7-3. Control and Metering Equipment
Indicating instruments and control should be provided on
the station service switchgear for local control. A voltmeter, an ammeter, a wattmeter, and a watthour meter are
usually sufficient. A station service annunciator should be
provided on the switchgear for a large station service
system. Contact-making devices should be provided with
the watthour meters for remote indication of station service energy use. Additional auxiliary cabinets may be
required for mounting breaker control, position indication,
protective relays, and indicating instruments. For large
plants, physical separation of control and relay cubicles
should be considered so control and relaying equipment
will not be damaged or rendered inoperable by the catastrophic failure of a breaker housed in the same or adjacent cubicle.
Load/Distribution Centers
Protective and control devices for station auxiliary equipment should be grouped and mounted in distribution
centers or, preferably, motor control centers. The motor
starters, circuit beakers, control switches, transfer
switches, etc., should all be located in motor control
7-5. Estimated Station Service Load
a. General.
(1) The maximum demand that is expected on the
station service system is the basis for developing station
service transformer ratings. The expected demand may be
determined from a total of the feeder loads with an appropriate diversity factor, or by listing all connected loads
and corresponding demand loads in kVA. A diversity
factor smaller than 0.75 should not be used. During high
activity periods or plant emergencies, higher than normal
station service loads can be expected and if a small diversity factor has been used, the system may not have adequate capacity to handle its loads.
(2) Demand factors used for developing station
service equipment capacities can vary widely due to the
type of plant (high head stand-alone power plant versus
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low head power plant integrated with a dam structure and
navigation lock). Development of demand factors for unit
auxiliaries should account for the type of auxiliaries in the
plant based on trends observed at similar plants. For
instance, the governor oil pump demand for a Kaplan
turbine will be greater than that for the governor oil pump
demand for a Francis turbine of the same output rating
because of the additional hydraulic capacity needed to
operate the Kaplan turbine blades. If the plant is base
loaded, governor oil pumps will not cycle as often as
governor oil pumps in a similar plant used for automatic
generation control or peaking service.
(3) Station service systems should be designed to
anticipate load growth. Anticipated growth will depend
on a number of factors including size of the plant, location, and whether the plant will become an administrative
center. A one- or two-unit isolated plant not suitable for
addition of more units would not be expected to experience a dramatic increase in demand for station service
power. For such a plant, a contingency for load growth
of 20 percent would be adequate. Conversely, some large
multi-purpose plants have experienced 100-percent
increases in the connected kVA loads on the station service system over original design requirements.
(4) Capacity deficits in existing station service systems have not been caused by the designer’s inability to
predict unit auxiliary requirements, but by unforeseeable
demands to provide service for off-site facilities added to
multipurpose projects. Examples of this have been the
development of extensive maintenance and warehouse
facilities outside the power plant, or electrical requirements resulting from environmental protection issues such
as fish bypass equipment. The station service design
should have provisions for unanticipated load growth for
multipurpose projects with navigation locks and fish ladders. For such projects, a minimum growth factor contingency adder of 50 percent could be justified.
b. Auxiliary demand. Demand varies greatly with
different auxiliaries, and the selection of demand factors
requires recognition of the way various power plant
equipments will be operated. One method illustrated in
Table 7-1 assumes 1 hp as the equivalent of 1 kVA and on
lights and heaters uses the kW rating as the kVA equivalent. The accuracy of the method is within the accuracy
of the assumptions of demand and diversity. The values
of demand and diversity factors correlate with trends
observed in recent years on station service loads.
Table 7-1
Estimated Station Service Load and Recommended Transformer Capacity
Load kVA
Unit Auxiliaries for 8 Units
Governor Oil Pump
Pump #1 Bus #1
Pump #2 Bus #2
Pump #3 Bus #1
Pump #4 Bus #2
Turbine Bearing Oil Pump
Head Cover Pump
Pump #1 Bus #1
Pump #2 Bus #2
High Bay Lights
Bus #1
Bus #2
Generator Housing Heater
Transformer Cooling Water Pumps
Bus #1
Bus #2
Transformer Oil Pump
Bus #1
Bus #2
ACB Air Compressor
Bus #1
Bus #2
100 hp
100 hp
25 hp
25 hp
1 hp
8 @ 2 hp
8 @ 2 hp
7 @ 13 kW
7 @ 13 kW
8 @ 18 kW
2 @ 50 hp
2 @ 50 hp
12 @ 2 hp
12 @ 2 hp
1 @ 5 hp
1 @ 10 hp
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Table 7-1 (Concluded)
Load kVA
High Pressure Thrust
Bearing Oil Pump
Governor Air Compressor
8 @ 10 hp
2 @ 15 hp
General Auxiliaries
Supply to Dam
Fire Pump
HVAC-Heat Pump
Transit Oil Processor
Transit Oil Pump
Battery Charger No. 1
Battery Charger No. 2
Power Outlets
Draft Tube Crane
Duplex Sump Pump
Powerhouse Crane No. 1
Air Compressor No. 1
Air Compressor No. 2
Filter Paper Oven
Lubricating Oil Purifier
Lubricating Oil Pump
Water Heater - 20 gal.
Water Heater - 100 gal.
Cable Tunnel Ventilating Fan
Power Outlets
Air Compressors
Machine Shop
Largest Machine
Total less heating
Total demand with diversity factor of
75 percent
873.4 kVA
Estimated total heating load
1055.0 kVA
Estimated total demand load with heating
1928.4 kVA
Recommended size of each station service transformer
1500.0 kVA
* Not on when generator running.
** Standby
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Chapter 8
Control System
controlled equipment is remote from the plant, the equipment is not “offsite.” Offsite control denotes control from
a location not resident to the plant, i.e., another plant or a
control complex at another location.
8-1. General
f. Control room location. In plants with a few units,
the control room location with its centralized controls
should provide ready access to the governor control cabinets. In plants with ultimately four or more units, the
control room should be located near the center of the
ultimate plant or at a location allowing ready access to the
units and adjacent switchyard. The relative number and
lengths of control circuits to the units and to the switchyard is a factor to consider, but is secondary to consideration of operating convenience. The control room should
be an elevation above maximum high water, if there is
any danger that the plant may be flooded. A decision on
the location of the control room should be reached at an
early stage of plant design, since many other features of
the plant are affected by the control room location. Control location definitions and control modes are further
described in IEEE 1010.
a. Scope. The control system as discussed in this
chapter deals with equipment for the control and protection of apparatus used for power generation, conversion,
and transmission. It does not include low-voltage panelboards and industrial control equipment as used with plant
auxiliaries. IEEE 1010 and EPRI EL-5036, Volume 10,
provide guidelines for planning and designing control
systems for hydroelectric power plants.
b. Control system components. The control system
consists primarily of a computer-based control system,
hard-wired logic or programmable logic, indicating and
recording instruments, control switches, protective relays,
and similar equipment. The greatest part of this equipment should be grouped at one location to facilitate
supervision and operation of the main generating units,
transmission lines, and station auxiliaries. The grouping
of these controls at one location within the confines of the
power plant is termed “centralized control.”
c. Start-stop sequence. Each generator unit control
system should be provided with a turbine/generator startstop sequencing logic using a master relay located at the
generator (or unit) switchboard. The starting sequence
begins with pre-start checks of the unit, followed by starting unit auxiliaries, and ends with the unit operating under
the speed-no-load condition. Manual or automatic synchronizing and closure of the unit breaker can be performed at the local control location.
The stopping
sequence should provide for four types of unit shutdown:
protective relaying, operator’s emergency stop switch,
mechanical problems, and normal shutdown.
d. Generator switchboards. Generator switchboards
in larger power plants are located near the controlled
generator. The switchboards provide local control of the
unit. In smaller power plants, where metal-clad switchgear is used for switching the generator, unit control
equipment is located on auxiliary panels of the switchgear
line-up. Like the switchboards, the auxiliary panel equipment provides local control of the unit.
e. Auxiliary equipment control. Large power plants
using high-voltage busing and switching or having an
adjacent switchyard as part of the development should
have control for this equipment located in the grouping
suggested in paragraph 8-1(b).
Even though the
g. Smaller plants. In smaller power plants, where
indoor generator-voltage busing and switching are used,
hinged instrument panels on the switchgear cubicles
should be used as mounting space for main control equipment. This results in the main group of control equipment being located at the main switchgear location.
8-2. Control Equipment
a. General. Centralized automatic and manual control equipment should be located in the control room of
large power plants. The control console, in conjunction
with supervisory control and data acquisition (SCADA)
equipment and the status switchboard, enables the control
room operator to control the powerhouse operation.
Equipment racks housing automatic synchronizing and
centralized auxiliary equipment should be located in or
adjacent to the control room to facilitate connections with
control room equipment. If the plant is controlled from
offsite, the plant’s SCADA equipment should be located
in or adjacent to the control room.
b. Space allocation.
Space allotted for control
equipment, whether in a separate control room or in the
main switchgear cubicle area, must be large enough to
accommodate the panels required for the ultimate number
of generating units and transmission lines. The space
requirement, as well as the size and location of openings
required in the floor, should be provided to the architectural and structural designers to ensure proper consideration in door, room, and floor slab designs.
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c. Cabinet construction. Generator switchboard panels and doors should be 1/8-in. thick or No. 11 U.S.S.
gauge smooth select steel with angle or channel edges
bent to approximately a 1/4-in. radius. Panels should be
mounted on sills ready for powerhouse installation in
groups as large as can be shipped and moved into the
installation area. All equipment on the switchboards
should be mounted and wired at the factory, and the
boards should be shipped to the powerhouse with all
equipment in place.
d. Equipment arrangement.
The arrangement of
equipment on the control switchgear, switchboard, or
control console should be carefully planned to achieve
simplicity of design and to replicate unit control placements familiar to the intended operating staff. Simplicity
of design is a definite aid to operation and tends to reduce
operating errors; therefore, the relative position of devices
should be logical and uniform. Switchboard and control
console design should be patterned after an appropriate
example to attain a degree of standardization in the
arrangement of indicating instruments and basic control
switches. Control switches should be equipped with
distinctive handles as shown in Table 8-1. Each item of
equipment should be located by consideration of its functions, its relation to other items of equipment, and by its
use by the operator.
8-3. Turbine Governor
The digital governor electrical control cabinet usually is
located adjacent to the generator switchboard separate
from the actuator cabinet. The control cabinet contains
governor electronic or digital “proportional-integralderivative” (P-I-D) control components. The actuator
cabinet housing the power hydraulics of the governor
system is located to minimize the pressure line runs
between the turbine servomotors, the actuator, and the
governor pressure tank. For smaller capacity governors
and smaller plants, governor electronic and hydraulic
controls are all located in the governor actuator cabinet.
For mechanical considerations of turbine governors, see
EM 1110-2-4205.
monitoring equipment in conjunction with a computerbased data acquisition and control system (DACS), provides control and indication access to individual items of
equipment to facilitate operation, supervision, and control.
Hard-wired pushbutton switches provide for direct operator manual control of unit start-stop, breaker close (initiating automatic synchronizing), breaker trip, voltage,
loading, and gate limit raise-lower. Analog or digital
panel meters and indicating lights continuously indicate
the status of all main units, breakers, transformers, and
lines. The DACS system display monitors and keyboards
are available to operator control. The unit controls and
instruments supplement or duplicate those on the generator switchboard, and provide the control room operator
with the ability to transfer control of any selected unit or
group of units to the generator switchboard in case of
system trouble. The control console may also provide
spillway gate control, fishway control, project communications, and other project equipment control functions
when required.
b. Equipment location. Arrangement of control and
instrument switches and mimic bus should simulate the
relative order of interconnections or physical order of the
plant arrangement assisting the operator in forming a
mental picture of connections. The top of the control
console panel should be inclined to provide easier access
to the control switches and to improve console visibility.
Layouts of console visual display terminals (VDTs)
should follow applicable guidelines contained in Chapter 12, “Lighting and Receptacle Systems,” to ensure good
visual acuity of the displays. Panels of the control console should be arranged for ultimate development, so that
the addition of a control panel for another generator or
another line will not disturb existing equipment.
c. Status switchboard. The status switchboard contains graphic and visual indication, generator load recorders, station total megawatts and megavars recorders, and
other required project data displays. The status switchboard should be located for easy observation from the
control console. The status switchboard should be a
standard modular vertical rack enclosure joined together
to form a freestanding, enclosed structure.
8-4. Large Power Plant Control
a. General. Centralized control system equipment is
located in the control room and is interconnected to the
generator switchboards located near the units. Required
control and monitoring of all functions of the hydroelectric power project are provided to the operators. The
control console with conventional control devices and
d. Equipment racks. Equipment racks should be
provided for mounting line relays, automatic synchronizing equipment, the common and outside annunciator
chassis, auxiliary relays, communication equipment, and
transfer trip equipment. The equipment racks should be
standard, modular, vertical rack enclosures.
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e. SCADA equipment. The SCADA and communication equipment should be located in the general control
8-5. Small Power Plant Control
a. General. Small power plants using medium-voltage metal-clad switchgear for generator control impose
different limitations on equipment arrangements than
arrangement limitations of generator switchboards for
local unit control. This is due to the variety of equipment
available with switchgear and, consequently, the different
possibilities for locations for major control equipment.
As noted in paragraph 8-1g, hinged instrument panels on
the main switchgear can be used for control equipment.
Where space and switchgear construction allow, it is
desirable to have hinged instrument panels on the side of
the stationary structure opposite the doors for removing
the breakers. These panels, however, provide space for
only part of the necessary control equipment, and one or
more auxiliary switchgear compartments will be required
to accommodate the remaining equipment.
b. Equipment location. Annunciator window panels,
indicating instruments, control switches, and similar
equipment should be mounted on the switchgear hinged
panels. The hinged panel for each breaker section should
be assigned to the generating unit, transmission line, or
station service transformer that the breaker serves and
only the indicating instruments, control switches, etc.,
associated with the controlled equipment mounted on the
panel. A hinged synchronizing panel should be attached
to the end switchgear cubicle.
c. Additional equipment location. Protective relays,
temperature indicators, load control equipment, and other
equipment needed at the control location and not provided
for on the switchgear panels should be mounted on the
auxiliary switchgear compartments.
d. SCADA equipment. Small power plants are frequently unattended and remotely controlled from an offsite location using SCADA equipment. The SCADA and
communication equipment should be located in the general control area.
The application of relays must be coordinated with the
partitioning of the electrical system by circuit breakers, so
the least amount of equipment is removed from operation
following a fault, preserving the integrity of the balance
of the plant’s electrical system.
(1) Generally, the power transmitting agency protection engineer will coordinate with the Corps of Engineers
protection engineer to recommend the functional requirements of the overlapping zones of protection for the main
transformers and high voltage bus and lines. The Corps
of Engineers protection engineer will determine the protection required for the station service generators and
transformers, main unit generators, main transformers, and
powerhouse bus.
(2) Electromechanical protective relays, individual
solid state protective relays, multi-function protective
relays, or some combination of these may be approved as
appropriate for the requirements. Traditional electromechanical protective relays offer long life but may malfunction when required to operate, while many less
popular designs are no longer manufactured. Individual
solid state protective relays and/or multi-function protective relays offer a single solution for many applications
plus continuous self diagnostics to alarm when unable to
function as required. Multi-function protective relays may
be cost-competitive for generator and line protection when
many individual relays would be required. When multifunction relays are selected, limited additional backup
relays should be considered based upon safety, the cost of
equipment lost or damaged, repairs, and the energy lost
during the outage or repairs if appropriate.
(3) When the protection engineer determines that
redundancy is required, a backup protective relay with a
different design and algorithm should be provided for
reliability and security. Fully redundant protection is
rarely justified even with multi-function relay applications.
Generators, main transformers, and the high voltage bus
are normally protected with independent differential
(4) When the protective relays have been approved,
the protection engineer will provide or approve the settings required for the application.
8-6. Protective Relays
b. Main generators.
a. General. The following discussion on protective
relays includes those devices which detect electrical faults
or abnormal operating conditions and trip circuit breakers
to isolate equipment in trouble or notify the operator
through alarm devices that corrective action is required.
(1) The general principles of relaying practices for
the generator and its excitation system are discussed in
IEEE standards C37.101, C37.102, and C37.106.
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Unless otherwise stated, recommendations contained in
the above guides apply to either attended or unattended
(2) Differential relays of the high speed, percentage
differential type are usually provided to protect the stator
windings of generators rated above 1500 kVA.
(3) A high-impedance ground using a resistanceloaded distribution transformer scheme is generally used,
thereby limiting generator primary ground fault current to
less than 25 A. A generator ground, AC overvoltage
relay with a third harmonic filter is connected across the
grounding impedance to sense zero-sequence voltage. If
the generator is sharing a GSU transformer with another
unit, a timed sequential ground relay operation to isolate
and locate generator and delta bus grounds should be
(4) Out-of-step relays are usually provided to protect
generators connected to a 500-kV power system, because
the complexity of a modern EHV power system sometimes leads to severe system frequency swings, which
cause generators to go out of step. The generator out-ofstep relays should incorporate an offset mho and angle
impedance relay system which can detect an out-of-step
condition when the swing locus passes through the generator or its transformer.
(5) Frequency relays, and under- and over-frequency
protection, are not required for hydraulic-turbine-driven
(6) Temperature relays are provided for thrust and
guide bearings as backup for resistance temperature detectors and indicating thermometers with alarms. The relays
are set to operate at about 105o C and are connected to
shut down the unit. Shutdown at 105o C will not save the
babbitt on the bearing but will prevent further damage to
the machine.
c. Generator breakers.
(1) Most breaker failure relaying schemes operate on
high phase or ground currents. When a trip signal is
applied to the breaker, the breaker should open and current flow should cease within the breaker interrupting
time. The breaker failure relay is usually applied to operate lockout relays to trip backup breakers after a time
delay based on the assumption the breaker has failed if
current flow continues after the breaker trip circuit has
been energized. These schemes do not provide adequate
protection if breaker failure occurs while current is near
zero immediately following synchronizing.
(2) Another scheme uses a breaker auxiliary contact
to detect breaker failure with fault detectors for phase
current balance, reverse power, and overcurrent relays.
Protective relay contact closing or operation of the
breaker control switch to the trip position energizes a
timing relay. If the breaker auxiliary contact does not
close within the breaker interrupting time, the timing relay
will close its contacts, enabling the phase current balance,
reverse power, and overcurrent relays to perform the
required trip functions.
(3) Some breaker control systems monitor the
breaker trip coil using a high resistance coil relay connected in series with the trip coil. A time delay relay is
required to allow the breaker to open during normal tripping without initiating an alarm.
(4) Provision should be made to trip generator breakers when there is a loss of the breaker trip circuit DC
control power or complete loss of DC for the entire plant.
A stored energy capacitor trip device can be used to trip
the breaker in case of a loss of control power.
d. Transformer protection.
(1) Transformers or transformer banks over
1500 kVA should be protected with high-speed percentage-type differential relays. The basic principles involved
in transformer protection are discussed in IEEE C37.91.
(2) Separate differential relay protection for generators and transformers should be provided even on unit
installations without a generator circuit breaker. The
relays applicable for generators can be set for much closer
current balance than transformer differential relays.
(3) Auto transformers can be treated as threewinding transformers and protected with suitable highspeed differential relays. The tertiary winding of an
auto-transformer usually has a much lower kVA rating
than the other windings. The current transformer ratios
should be based on voltage ratios of the respective windings and all windings considered to have the same
(highest) kVA rating.
(4) Thermal relays supplement resistance temperature detectors and thermometers with alarm contacts. The
relays are set to operate when the transformer temperature
reaches a point too high for safe operation, and are
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connected to trip breakers unloading the transformers.
These relays are important for forced-oil water-cooled
transformers which may not have any capacity rating
without cooling water.
system, speed of operation required to maintain system
stability, coordinating characteristics with relays on the
other end of the line, and the PMA or utility system operating requirements. The basic principles of relaying practices are discussed in IEEE C37.95.
e. Bus protection.
(1) High-voltage switchyard buses can be protected
with bus protection, but the necessity and type of bus
protection depends on factors including bus configuration,
relay input sources, and importance of the switchyard in
the transmission system. Application of bus protection
should be coordinated with the PMA or utility operating
agency. The basic principles of bus protection operation
are discussed in IEEE C37.97.
h. Shutdown relays. The shutdown lockout relays
stop the unit by operating shutdown equipment and tripping circuit breakers. The lockout relay operations are
usually divided into two groups. A generator electrical
lockout relay, 86GX, is initiated by protective relaying or
the operator’s emergency trip switch. The generator
mechanical lockout relay, 86GM, is triggered by
mechanical troubles, such as bearing high temperatures or
low oil pressure.
The unit shutdown sequence is
described in IEEE 1010.
(2) Large power plants with a complex station service
system configuration should be provided with station
service switchgear bus differential relay protection.
8-7. Automatic Generation Control (AGC)
(3) A ground relay should be provided on the deltaconnected buses of the station service switchgear. A
voltage relay, connected to the broken-delta potential
transformer secondary windings, is usually provided to
detect grounds. A loading resistor may be placed across
the broken delta to prevent possible ferroresonance. The
ground detector usually provides only an alarm indication.
f. Feeder protection. Feeder circuits that operate at
main generator voltage and 4160-V station service feeders
should be protected with overcurrent relays having instantaneous trip units and a ground relay. The setting of the
ground relay should be coordinated with the setting of the
generator ground relay to prevent shutdown of a generator
due to a grounded feeder.
g. Transmission line protection. Relays for the protection of transmission lines should be selected on the
basis of dependability of operation, selectivity required for
coordination with existing relays on the interconnected
For computer-based control systems, unit load can be
controlled in accordance with an error signal developed
by digital computers periodically sampling real power
flow over the tie line, line frequency, and generator power
output. These analog signals are continuously monitored
at the load dispatch control center to obtain the plant
generation control error. The control error digital quantity
is transmitted via telemetry to each plant and allocated to
the units by the computer-based plant control system.
AGC action by the plant control system converts the
raise/lower megawatt signal into a timed relay contact
closure to the governor. The governor produces a wicket
gate open/close movement to change the generator output
power. Other modes of operation include set point control, regulating, base loaded, ramped control, manual
control, and others relative to the nature of the project and
operating philosophy. Coordination of the engineering
planning of the AGC with the marketing agency should
begin at an early stage.
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9-3. Annunciator
Chapter 9
Annunciation Systems
9-1. General
EPRI EL-5036, Volume 10, provides guidelines and
considerations in planning and designing annunciation
systems for power plants.
9-2. Audio and Visual Signals
Every power plant should be provided with an annunciation system providing both audible and visual signals in
the event of trouble or abnormal conditions.
a. Audio signals. Howler horns and intermittent
gongs are used for audible signal devices. An intermittent
gong is provided in the plant control room. Howler horns
are used in the unit area and in areas where the background noise is high (e.g., in the turbine pit) or in areas
remote from the unit (e.g., plant switchyard).
b. Visual signals. Visual signals are provided by
lighted lettered window panels of the annunciator. In
larger plants, the annunciator panel indication is
augmented by unit trouble lamps located in a readily
visible position close to the unit. The plant sequence of
events recorder (SER) is normally located in the control
room. Separate annunciators (when provided) for station
service systems and switchyards should be located on
associated control panels of the station service switchgear
or on the switchyard control panels.
a. General.
The annunciator system should be
designed for operation on the ungrounded 125-V DC system discussed in Chapter 11. All remote contacts used
for trouble annunciation should be electrically independent
of contacts used for other purposes so annunciator circuits
are separated from other DC circuits. Auxiliary relays
should be provided where electrically independent contacts cannot otherwise be obtained. The annunciator
equipment should use solid-state logic units, lightedwindow or LED type, designed and tested for surge withstanding capability in accordance with ANSI C37.90.1,
and manufactured in accordance with ANSI/ISA S18.1.
b. The switchboard annunciator operational sequence
should be a manual or automatic reset sequence as listed
in Table 9-1.
Automatic reset should be employed when there is either
an SER or a SCADA system backup. When the plant is
controlled and dispatched through the SCADA system of
the wheeling utility, the design reset features of the
annunciator should be coordinated to ensure proper
c. The generator switchboard is provided with
annunciator alarm points for unit emergency shutdown,
generator differential lockout, generator incomplete start,
generator or 15-kV bus ground, generator overspeed,
generator overcurrent, generator breaker low pressure, unit
control power loss, generator CO2 power off, PT fuse
failure or undervoltage, and head cover high water.
Table 9-1
Switchboard Annunciator Operational Sequence
Pushbutton or Switch
or Repeater
Acknowledge or Silence
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Certain alarm points have several trouble contacts in
parallel by equipment group. Examples include generator
excitation system trip or trouble, turbine bearing oil
trouble, generator cooling water flow, unit bearing overheat, generator oil level, generator stator high temperature,
and governor oil trouble.
window indicating light annunciator provides backup for a
sequential event recorder. Unit switchboard annunciator
remote control switches to silence and reset the switchboard annunciator should be provided on the control
9-4. Sequence of Events Recorder (SER)
d. The generator switchboard may be provided with
an additional annunciator for the generator step-up transformer and unit auxiliary equipment alarms, depending on
the plant arrangement. Generally, these alarm points are
transformer differential, transformer lockout trip, transformer overheat, transformer trouble, 480-V switchgear
trip, and trouble.
e. The generator excitation cubicle is provided with
an annunciator for excitation equipment alarm points for
AC regulator trip, bridge overtemperature, transformer
over temperature, regulator power supply, field overvoltage, maximum excitation limit, minimum excitation limit,
and volt per Hertz. Generator overvoltage, power system
stabilizer, and fan failure alarm points should be included
when required.
f. The switchboard annunciator for large power plants
should be provided with auxiliary or repeater contacts to
drive control room console remote annunciator wordindicating lights.
g. A control console window-indicating light annunciator is common to all units. One unit at a time can be
selected by use of the appropriate unit trouble status
lighted pushbutton. Visual indication is provided when
the unit switchboard annunciator is activated. The console window indicating lights are generally grouped by
switchboard annunciator points and provide essential
trouble status to the operator. Unit troubles are normally
categorized by shutdown, differential, overcurrent, cooling
water, bearing oil, unit trouble, breaker air, CO2 discharge, control power, and head cover high water. The
An SER should be provided to complement the plant
annunciation system if a SCADA system is not performing the sequence of events function. The SER provides a
time-tagged, sequenced, printed record of trouble events.
The documented record of a trouble event aids in diagnosing power plant forced outages. It is designed for operation on an ungrounded 125-V DC system. All inputs
should be optically isolated and filtered for 125-V DC dry
contact change-of-state scanning. The SER minimum
resolution should be coordinated with using agencies. A
value of 2 msec is typical. When an input signal status
change occurs, the SER should automatically initiate and
produce a tabulated printed record on the data logger
identifying the event and showing the time of status
change (to the nearest millisecond). The SER should be
provided with a system clock and time synchronization
features. Each SER system should be provided with an
adequate input point capacity to monitor each alarm trouble contact and provide plant breaker status necessary for
the plant operation. The alarm trouble contacts should
include IEEE 1010 requirements and project alarm points
9-5. Trouble Annunciator Points
All of the alarm points listed in Table 9-2 below are not
required in every plant, and, conversely, requirements for
an unlisted alarm point may arise. IEEE 1010 provides
types of alarm signals transmitted to the generator annunciator from the generator, excitation system, generator
terminal cabinet, generator breaker, step-up transformer,
turbine, and governor, which are listed in Table 9-2.
Table 9-2
Alarm Signals Transmitted to the Generator Annunciator
Generator Switchboard Annunciator Points
86GX & 86GT
Unit Emergency Shutdown
Generator Differential Shutdown
Generator Incomplete Start
Generator or 15-kV Bus Ground
Generator Overspeed
Generator Overcurrent
Generator Breaker Low Pressure
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Table 9-2. (Continued)
Generator Switchboard Annunciator Points
Control Power Loss
CO2 Discharge
CO2 Power Off
PT Fuse Fail or Undervoltage
Head Cover High Water
Generator Regulator Trip or Trouble
Turbine Bearing Oil Trouble
Generator Cooling Water Flow
Unit Bearing Oil Trouble
Generator Oil Level
Generator Stator High Temperature
Governor Oil Trouble
* See IEEE 1010
Step-Up Transformer Annunciation Points
Lockout Trip (Includes Transformer Ground)
Control Power Loss
* See IEEE 1010
Line Annunciation Points
Line Lockout
Line Relay or MW Power Off
Microwave Trouble
Station Service Transformer Annunciation Points
Transformer Lockout
Transformer Trouble
Transformer Breaker Tripped
CO2 Discharge
Station Annunciation Points
Station Service Switchgear Bus Differential
Station Service Switchgear DC Trouble
Station Annunciation Points
Station Service Switchgear Breaker Low Pressure
Station Service Feeder Breaker Tripped
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Table 9-2. (Concluded)
480-V AC Feeder Breaker Tripped
Bus Tie Breaker Tripped or Trouble
Battery Charger Failure
125-V DC Feeder Breaker Tripped
125-V DC System Tripped
48-V DC System Trouble
48-V DC Feeder Breaker Trip
Inverter Trouble
Unwatering Pump Trouble
Drainage Pump Trouble
Septic Tank High Level
Effluent High Level
Station Air Low Pressure
Oil or Paint Storage Room CO2 Discharge
Fire Pump Power Off
Fire Pump On
Engine Generator Trouble
Engine Generator Trip
Plant Intrusion Detector
Switchyard Annunciation Points
Power Circuit Breaker Loss of Tripping and Closing Energy
Power Circuit Breaker Energy Storage System Energy
Breaker Close Bus Failure
Breaker Trip Bus Failure
Breaker Failure Lockout Relay
Relay Potential Failure
Line Distance Relay Trip
Line Overcurrent Relay Trip
Line Ground Relay Trip
Microwave Transfer Trip
MWTT Trouble
Bus Failure Lockout Relay
Line Communication Trip
Transformer Cooling Fan Failure
Transformer Overheat
Transformer Gas Accumulator
Transformer Oil Level
Transformer Sudden Pressure Relay
Transformer Ground Detector
Transformer Inert Air Tank Pressure
Transformer Lockout Relay
Transformer Phase Differential
Transformer Phase Overcurrent
Switchyard Annunciation Points
Transformer Neutral Overcurrent
Transformer Fire
Battery Charger Trouble
Battery Trouble
Inverter Trouble
Engine Generator Running
Engine Generator Trouble
Yard Intrusion Detector
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Chapter 10
Communication System
10-1. General
a. Types of systems available. Reliable communication systems are vital to the operation of every power
plant. Voice communication is a necessity at all plants
and code-call signaling is generally required for accessing
personnel at large power plants. Additional dedicated
communication systems are required for telemetering,
SCADA, and for certain types of protective relaying.
Communications media available for power plant application include: metallic cable pairs; leased telephone lines;
power line carrier (PLC); radio frequency communications, including two-way land mobile (TWLM) radio and
terrestrial microwave (MW); fiber optics; and satellite
b. Regulatory requirements. The Federal Information
Resource Management Regulation (FIRMR), as administered by the General Services Administration (GSA),
requires GSA approval for all communication systems
(other than military) used by agencies of the Federal
Government. The GSA contract with common carriers
guarantees carriers access to Government long-distance
communication business. The service to provide longdistance communications is known as FTS 2000. The
GSA requires its use by Government agencies, unless the
agencies are able to prove, on a case-by-case basis, that
the FTS 2000 service will not meet its needs. For information on the FIRMR, and approval documentation
needed, contact the Corps of Engineers Information Management Office.
10-2. Voice Communication System
a. Telephone service. Normally, general internal and
external telephone communications are provided through
public switched telephone network services installed and
operated by the serving telephone company. The equipment (including telephones) is leased from the telephone
company. The communication circuits provided by a
commercial telephone operating company include connection to local exchange, long distance, WATS, and FTS
2000 telephone service. Telephone pay stations in visitor
areas should be provided for public convenience.
b. Plant equipment.
The distributing frame and
switching equipment for any commercial systems should
be installed in a location near the control room where it
can be included in the air conditioning zone for the
control room. A preferred AC circuit should be provided
for the commercial equipment.
c. Telephone locations. To ensure adequate telephone access, sufficient telephone outlets should be provided in the office area, the control room, the generator
floor at each unit, the switchgear area, the station service
area, and the plant’s repair shops. A telephone outlet
should be provided in each elevator cab. Circuits to
telephone outlets are provided by metallic cable pairs.
Telephone wiring inside the plant, from the telephone
company switching equipment location to the location of
the various instruments, is provided by the Government
and included in the powerhouse design. Embedded conduits dedicated to telephone use are provided for the
10-3. Dedicated Communications System
a. General. Dedicated communications systems are
provided in the plant for code call systems, SCADA systems, protective relay systems, and for voice communications to the dispatching centers and substations of the
power wheeling entity (either Federal Power Marketing
Agency (PMA) or non-Federal utility). Communications
media for performing these functions can be either leased
commercial circuits, power line carrier (PLC), radio frequency communications, fiber-optic cable, satellite communications, or a combination of these media.
b. Code call system. Generally, code-call facilities
are provided at all plants permitting paging of key personnel. A separate, Government-owned code-call system
should be provided when leased telephones are used, so
maintenance of the code call will not depend on outside
personnel. An automatic repeating type code-sending
station should be located on the control room operator’s
desk or console.
c. Utility telephone systems.
(1) Voice communications facilities for power plant
control and dispatch use are typically provided through a
utility or Federal PMA-owned telephone system. If it is a
Federally owned system, the FIRMR requires the use of
FTS2000 for inter-local access and transport area service,
unless an exception is granted. In some instances, the
major use of the communication channel has been the
determining factor in whether Government ownership of
the system is permitted. If the major use of the service is
technical; that is, plant operating and control information,
then Government ownership has been approved.
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(2) The telephone system should provide access to
dispatching voice channels of the utility. Generally, dial
automatic telephone switching facilities provide a systemwide network of voice circuits which are automatically
switched to permit calling between generating stations,
major substations, and control centers. Some plants have
used leased private line service for communications circuits which are provided by a commercial telephone company’s common carrier for the sole use of the plant.
These circuits are provided on the cable and other transmission facilities of the carrier, but should not be connected directly to the network switching systems of the
carrier or telephone operating company.
d. Leased circuits.
(1) Leased commercial circuits can be used for voice
communication circuits as described in paragraph 10-3c.
Voice grade communication channels are required and are
supplied either through a dial or a dedicated system, with
dedicated channels being the preferred alternative. The
basic voice-bandwidth private line channel is an AT&T
system “Type 3002 unconditioned” channel. Other commercially available private line data channel services are
Digital Data Service (DDS) and Basic Data Service
(BDS). These latter services offer digital interconnectivity through a wide range of data transmission speeds.
(2) Leased circuits have been used for plant protective relaying circuits with mixed results. Generally, it is
better to own the communication facility if it is used for
vital high-speed relaying service. Some of the past problems with leased channels have been loss of service
because of unannounced maintenance activity by the
leasing agency, failure of the system, rerouting of the
service because of maintenance or construction activity,
and accidental circuit interruption by personnel looking
for trouble on other circuits.
Typically, a leasing
agency’s operating and maintenance personnel do not
understand the level of reliability necessary for relaying
(3) Leased circuits have been used for SCADA system control of plants and substations. Here, too, the
results have been mixed. For short distances where the
leasing agency can provide a direct link between the local
and remote station, results have been good. Where the
circuit has been routed through a central office, the reliability of service has in a number of cases not been of the
level of reliability needed for data acquisition and control.
The lack of reliability is apt to be more of a problem if
the plant is in a remote location and served by a small
telephone company. Use of leased facilities has to be
considered on a case-by-case basis, and all of the influencing factors need to be considered, including the service
record of the proposed leasing agency.
e. Power line carrier.
(1) A “basic” PLC system consists of three distinct
(a) The terminal assemblies, consisting of the transmitters, receivers, and associated components.
(b) The coupling and tuning equipment, which provides a means of connecting the PLCs terminals to the
high-voltage transmission line.
(c) The high-voltage transmission line, which provides the path for transmission of the carrier energy.
High-voltage coupling capacitors are used to couple the
carrier energy to the transmission line, and simultaneously
block 60-Hz power from the carrier equipment.
(2) Most transmitter/receiver equipment is installed
in standard 19-in. radio racks inside cabinets located near
the plant control room. Carrier frequency energy is conducted out of the plant by coaxial cable to the high-voltage transmission line tuning and coupling equipment.
PLC equipment power requirements are supplied from
either 48-V or 125-V DC derived from the station battery
or a dedicated communications battery source. If a PLC
system is to be provided, routing provisions for the wire
and cables needed must be included in the plant design.
(3) Power line carrier communication systems have
found extensive use for relaying, control, and voice communications in Europe, and in some areas of the United
States. Their use is less popular in the United States,
apparently because of the availability of radio frequency
spectrum, and utility-owned communication systems apart
from the power transmission facilities. PLC bandwidth is
limited because of its operating frequencies and the transmission medium. Its transmission path is susceptible to
noise from arcing faults, interruption by ground faults and
other accidents to the line, and weather. If other reliable
communication means are available at a reasonable cost,
it would probably be advantageous to avoid the use of
f. TWLM radio.
(1) There is some very limited use of TWLM radio
in SCADA systems using the 150-MHz and 450-MHz
frequency bands. Mostly, it is used for data links with
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small distribution system remote terminal units (RTUs)
that are not critical to power system operation and not
economical to serve with a dedicated or dial phone line.
More common usage of TWLM media is Multiple
Address System (MAS) radio, which was developed
specifically for SCADA applications.
(2) MAS essentially emulates telephone leased line
circuits. The system consists of a transmitting master
station and multiple remote stations using frequencies in
the 900-MHz and above range. Its use is not practical for
hydro plant data acquisition and control, but it should be
considered if a hydrometeorological (hydromet) data system is to be built in the plant area, and hydromet data
gathering controlled from the plant. It could also be
considered for use in pumping plants that are under the
surveillance of the plant staff.
g. Microwave radio.
(1) Microwave radio consists of transceivers operating
at or above 1,000 MHz in either a point-to-point or pointmultipoint mode. Microwave radio systems have both
multiple voice channel and data channel capabilities.
Microwave systems use either analog (Frequency Division
Multiplex [FDM]) or digital (Time Division Multiplex
[TDM]) modulating techniques. The trend is towards
digital modulating systems because of increasing need for
high speed data circuits and the superior noise performance of TDM modulation. Analog radio is considered
to be obsolete technology, and it is likely that analog
radio will not be available in the future.
(2) Microwave radio energy is transmitted in a “line
of sight” to the receiving station, and the useful transmission path length varies depending on the frequency.
Whether a microwave system can be used at all depends
on factors beyond the scope of this manual, including the
terrain features between end points of the system. However, in general it can be said that useful systems of any
length will require one or more repeater stations located at
such points on the radio path that they can be seen from
the stations they receive from, and the stations they transmit to. Such repeater locations may be remote from any
utility services, and in fact may not even be near a road.
Site access, real estate acquisition, construction on the
site, environmental impacts, and maintenance of the station need to be carefully considered before a final decision is made to use microwave communications. FIRMR
requirements must also be considered.
(3) Microwave radio has found some short-range use
in providing communication between the powerhouse and
its switchyard, if the switchyard is located a mile or more
away from the plant and the plant ground mat is not
solidly connected to the substation ground mat. The
danger of voltage rise on control and communication
cables between plant and substation during fault conditions is well known. Microwave radio is particularly
useful here in providing isolation from noise and dangerous voltage levels on these circuits, since with the radio
there is no metallic connection between the terminals.
Note, however, that a fiber-optic carrier system will also
offer the advantages of a nonmetallic connection, and may
be more economical.
(4) Generally, microwave radio transceiver equipment accommodations in the plant are handled in the
same manner as PLC equipment accommodations. However, distance to the antenna, antenna location, and wave
guide routing must be considered. The effects of icing on
the antenna may require a power source for the antenna
location to provide antenna heating.
h. Fiber-optic cable.
(1) A fiber-optic cable system consists of a terminal
with multiplexing equipment, and a transmitter and
receiver coupled to fiber-optic light conductors that are
routed to the other terminal, which also has a receiver,
transmitter, and multiplexing equipment. Because the
transmission medium is nonmetallic, it offers the advantage of electrical isolation between terminals and immunity from electromagnetic interference.
(2) Because of the frequency of the transmitting
medium, light, the fiber-optic system offers a bandwidth
that can carry a great deal of data at very high speeds.
The glass fibers are small and delicate, so should be
enclosed in a protecting sheath. For communication systems external to the plant, right-of-way acquisition may be
a problem since the fiber-optic cable does require routing
just as a copper cable would.
(3) There are many possible ways of routing the
fiber. It is possible to obtain high-voltage transmission
line cable with fiber-optic light conductors incorporated in
its construction. The fiber-optic light conductor can also
be underbuilt on the transmission line to the plant. For
long transmission distances, the fiber-optic system
requires repeaters.
The transmission distance before
repeaters are needed has been steadily increasing because
of the development effort in this technology. It offers
great possibilities for external plant communication systems and should be considered in each case.
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(4) Probably the most important application for fiberoptic technology is for a Local Area Network (LAN)
within the plant. Its large data capacity, high rate of data
transmission speed, and immunity from electromagnetic
interference make the LAN an ideal medium for communication among the elements of distributed control systems within the plant. The technology is developing at a
very rapid rate, and standards are coming into being, such
as the Fiber Distributed Data Interface (FDDI), allowing
its use with a variety of devices.
i. Satellite communications. Satellite communication
systems have not been applied to Corps plants because of
cost and convenience. The Corps has made use of a
satellite time signal to provide a uniform time signal to
plant control systems, but that signal is available to any
suitable receiver without charge. Though this alternative
appears to have many attractive advantages, the utility
industry in general has yet to implement widespread use
of private networks based on satellite technology.
10-4. Communication System Selection
a. Systems external to the plant. In most cases, the
choice of the communications media used for dispatching
and remote plant control and monitoring will not be a
responsibility of the plant designer. The power-wheeling
entity for the plant’s power production will use systems
and equipment compatible with the utility’s “backbone”
communications network.
It is the plant designer’s
responsibility to ensure that adequate provisions are made
for the communication system’s terminal equipment and
to ensure that plans and specifications prepared for powerhouse equipment and systems address special requirements for voice and data transmission as dictated by the
external communication system. Coordination with the
system owner will be required to ensure compatibility.
b. Design considerations. Other design considerations include interface requirements for data circuits, as
imposed by the communication utility due to FCC regulations, and ground potential rise protection requirements
for plant terminals of the metallic circuits used for voice,
data, and control. In cases where the project scope
includes development of a communications network, a
comprehensive study should be made of alternatives available including system life-cycle costs to determine the
most technically appropriate and cost-effective scheme to
achieve successful communications system integration.
EPRI EL-5036, Volume 13, provides guidance on criteria
to evaluate if the project scope includes development of a
communications network.
c. Internal plant communications. Internal data circuits (LANs) will be included with the data acquisition
and control equipment that uses them, but the designer
should consider that fiber-optic technology will probably
be used. Also, for large plants to be staffed with administrative and maintenance personnel, a network of microcomputers may be added after the plant is in operation.
The plant designer should provide facilities for routing
network data highways between offices, maintenance
shops, and the control room.
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Chapter 11
Direct-Current System
11-1. General
A direct-current system is used for the basic controls,
relaying, SCADA equipment, inverter, communication
equipment, generator exciter field flashing, alarm functions, and emergency lights. The system consists of a
storage battery with its associated eliminator-type chargers, providing the stored energy system required to ensure
adequate and uninterruptible power for critical power
plant equipment. The battery and battery circuits should
be properly designed, safeguarded and maintained, and the
emergency requirements should be carefully estimated to
ensure adequate battery performance during emergencies.
IEEE 946 and EPRI EL-5036, Volume 9, provide guidance about factors to consider and evaluate in planning
and designing direct current systems. IEEE 450 provides
guidelines and procedures for testing the capacity of the
battery system.
11-2. Batteries
a. Type. The battery or batteries should be of the
lead-acid type in vented cells or a sealed cell.
b. Battery room and mounting. A separate room or
an area enclosed with a chain link fence with lockable
doors provides adequate protection against accidental
contact or malicious tampering. The room or area should
be ventilated in such a manner that exhaust air from the
room does not enter any other room in the plant. If necessary, heat should be provided to obtain full rated performance out of the cells. The cells should be mounted in
rows on racks permitting viewing the edges of plates and
the bottom of the cells from one side of the battery. The
tops of all cells should preferably be of the same height
above the floor. The height should be convenient for
adding water to the cells. Tiered arrangements of cells
should be avoided. Aisles should be provided permitting
removal of a cell from its row onto a truck without reaching over any other cells. The lighting fixtures in the
room should be of the vapor-proof type, with the local
control switch mounted outside by the entrance to the
room. Battery charging equipment and controls should
not be located in the battery room. Thermostats for
heater control should be of the sealed type, and no contactors or other arc-producing devices should be located in
the battery room. A fountain eyewash-safety shower and
drain should be provided in the battery room.
c. Number and sizes. The number and sizes of
batteries depend upon the physical sizes of the initial and
ultimate stages of plant construction and the loads to be
carried by the battery system. A 58/60-cell battery
(129-V) is adequate for a plant with four to six main
units. Where a large plant has a considerable amount of
emergency lighting, long circuits, and a high number of
solenoid loads, a 116/120-cell battery may be warranted.
d. One- or two-battery systems. If the ultimate plant
will have a large number of generating units, studies
should be made to determine whether one control battery
for the ultimate plant will be more desirable and economically justifiable instead of two or more smaller batteries
installed as the plant grows. Selection of a one- or twobattery system will depend not only on comparative costs
of different battery sizes and combinations, including
circuits and charging facilities, but consideration of maximum dependability, performance, and flexibility during
periods of plant expansion.
e. DC load. The recommended procedure for determining the proper battery rating is outlined in IEEE 485.
The standard classifies the total DC system load into the
following categories:
(1) Momentary loads. Momentary loads consist of
switchgear operations, generator exciter field flashing,
voltage regulators, and similar devices. Momentary loads
are assumed to be applied for 1 min or less.
(2) Noncontinuous loads.
Noncontinuous loads
consist of emergency pump motors, fire protection systems, and similar systems. Noncontinuous loads are those
only energized for a portion of the duty cycle.
(3) Continuous loads. Continuous loads consist of
indicating lamps, inverters, contactor coils, and other
continuously energized devices. Continuous loads are
assumed to be applied throughout the duty cycle.
f. Emergency loads. In cases where emergency
lighting is excessive, the emergency load should be
broken down into two separate loads:
(1) Thirty-minute emergency load.
The 30-min
emergency load consists of emergency lights that can be
conveniently disconnected from the DC system when the
location of the trouble has been determined.
(2) Three-hour emergency load. The 3-hr emergency load consists of the emergency lights required after
the trouble area has been determined.
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g. Battery capacity. Using the above load classes and
durations and battery data obtained from manufacturer’s
literature, a station battery duty cycle is determined (see
IEEE 485). The battery capacity required is determined
as the sum of the requirements for each class and duration
of load comprising the duty cycle.
h. Battery and accessory purchase. The batteries,
with their accessories, indicating cell connectors, hydrometers, cell number, etc., are normally purchased through
the GSA Schedule. Standard battery racks for the battery
installation may also be obtained through GSA Schedules.
recharging the station battery at a normal rate. The
chargers should be of the “battery eliminator” type (additional filtering) allowing them to carry station DC loads
while the battery is disconnected for service. The batterycharger systems should be located near the battery room,
usually in a special room with the battery switchboard and
the inverter sets. Standard commercial features and
options available with station and communication battery
chargers are outlined in NEMA PE5 and PE7.
11-4. Inverter Sets
i. Safety considerations. Standard rack performance
criteria should be evaluated to ensure compliance with
plant requirements. Seismic considerations and other
factors may dictate the need for special racks and special
anchoring needs. The racks, anchors, and installation
practices, including seismic considerations, are discussed
in IEEE 484 and IEEE 344. Electrical safety considerations for battery installations are covered in Article 480
of the National Electrical Code (NFPA 70).
One inverter set should be provided in all plants where it
is necessary to maintain a continuous source of 120-V
AC. A separate supply bus for selected 120-V AC singlephase feeder circuits should be provided for SCADA,
recording instrument motors, selsyn circuits, and communication equipment. A transfer switch should be provided
to automatically transfer the load from the inverter output
to the station service AC system feeder in case of inverter
failure. Standard commercial features and options available with inverters used in uninterruptible power supplies
are outlined in NEMA PE1.
11-3. Battery-Charging Equipment
11-5. Battery Switchboard
Static charger sets are preferred for battery-charging service. Two sets should be provided so one will always be
available. The charger capacity should be sufficient for
supplying the continuous DC load normally carried while
Battery breaker, DC feeder breakers, ammeters, and
ground and undervoltage relays should be grouped and
mounted in a battery switchboard.
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Chapter 12
Lighting and Receptacle Systems
12-1. Design
a. General. For the purposes of design and plan
preparation, the lighting system is defined as beginning
with the lighting transformers and extending to the fixtures. This facilitates design coordination of various
features of the lighting system. For purposes of discussion, it also covers 480-V and 120-V convenience outlets
and corresponding circuits. After the design is complete,
the system may be broken down into separate categories
as determined by how the equipment will be obtained and
installed in the construction stage. One method of handling the division of work is outlined below. The lighting
systems, including fixtures and receptacles, are normally
furnished and installed by the powerhouse contractor.
b. Conduit and cable schedule. Supply cables and
conduit to transformers and lighting panels should be
listed in the conduit and cable schedule. Branch circuits
are normally not included on the schedule.
c. Panels. Lighting panels should be designed for the
job, using air circuit breakers to protect the branch circuits, and should be purchased and installed by the general contractor.
d. Distribution center. In designing the lighting distribution system, several schemes should be considered,
and a scheme adopted which gives the lowest overall cost
without sacrificing simplicity of design or efficiency of
operation. Two general schemes are:
(1) Small plant. A centrally located lighting transformer supplying the entire plant, which may be either:
(a) A 480-120/240-V, single-phase transformer with
120/240-V feeders and branch circuits.
(b) A 480-120/208-V, 3-phase, 4-wire transformer
with 120/208-V feeders and branch circuits.
(c) A 480-480Y/277-V, 3-phase, 4-wire transformer
with 480Y/277-V feeders and branch circuits.
(2) Large plant. Transformers located near the load
centers and fed by individual supply feeders from the
station service switchgear to supply lighting for a local
area, each transformer being either:
(a) A 480-120/240-V, single-phase transformer,
feeding panels with 120/240-V branch circuits.
(b) A 480-120/208-V, 3-phase, 4-wire transformer,
feeding panels with 120/208-V branch circuits.
(c) A 480-480Y/277-V, 3-phase, 4-wire transformer,
feeding panels with 480Y/277-V branch circuits.
12-2. Illumination Requirements
a. Intensity level. The lighting system should be
designed to give the maintained-in-service lighting intensities recommended by the IES Handbook (Kaufman 1984).
A maintenance factor of 0.75 is considered appropriate for
a well-maintained project.
b. Emergency lighting. Emergency lighting should
be designed to light important working areas within the
powerhouse and should be adequate to provide safe passage between such areas with a minimum load on the
station battery. NFPA 101 provides guidance on areas
requiring emergency lighting for personnel safety. Selfcontained, battery-operated, emergency lighting systems
should be considered to lower capacity requirements on
the station battery. Self-contained, battery-operated systems should be employed in areas with minimal occupancy or personnel access following an event initiating
use of the emergency lighting system. Emergency lighting for control rooms, unit control switchboard areas,
station service switchgear areas, the emergency generator
area, and interconnecting passageways between these
areas should be powered by the station battery.
c. Exterior lighting. Exterior lighting should be
provided for the switchyard, parking areas, passageways
near the powerhouse, the draft tube deck, and for the
upstream deck if there is one. Flood-lighting of the outside powerhouse walls should be included in the original
design, with provisions made for extension of lighting
circuits if the floodlights are not initially installed. Exterior doorways should be lighted either by flush soffit
lights or by bracket lights. If bracket lights are used, they
should be selected to enhance the architectural appearance
of the doorways.
d. Specific conditions. For general areas, the zonal
cavity method of illumination design (see IES Handbook)
is considered satisfactory. For special conditions such as
illumination (Kaufman 1984) of the vertical surfaces of
switchboards, a careful check by the point-by-point
method may be needed.
Care should be taken to
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minimize reflected glare from the faces of switchboard
instruments. To facilitate design review, the manufacturer’s candlepower distribution curves should accompany
the design drawings. If fixtures of unusual design are
being specified, their use must be justified, with complete
details of the fixtures submitted with the lighting design
e. Evaluation. Evaluation and choice of lighting
systems should consider both energy and maintenance
costs as well as initial cost of the fixtures.
12-3. Efficiency
a. General. Energy conservation is an important
concern when designing lighting systems. In the powerhouse, use of high efficiency lighting has the potential for
saving significant amounts of energy. An efficient lighting system is one in which the required amount of light
reaches the area to be illuminated at the proper level and
color, while using the minimum amount of energy. The
well-designed lighting system should make maximum use
of available natural light and consider the direction of
light and the desired dispersion or focus. Encouraging
efficient use requires provision of convenient control
points, use of proximity detectors in unoccupied interior
spaces, and consideration of two-level lighting in lowoccupancy machinery areas.
(b) HID metal halide lamps are a good source of
“white” light, covering about 70 percent of the visible
spectrum. They have good life and are very efficient.
Their disadvantages are relatively long start and restart
(c) HID high pressure sodium lamps are very efficient, but are a poor source of “white” light, covering
only about 21 percent of the available spectrum. They
need about 3 or 4 min of start time, and about 1 min of
restart time.
(4) Low-pressure sodium (LPS). LPS lamps are the
most efficient lamps available, but produce almost no
“white” light, so their use is extremely limited. They
have long lives, short start times, and very short restart
c. Evaluation. When designing the lighting system,
all of the above sources should be considered and the
most efficient combination of sources used, appropriate
with achieving design lighting levels and good lighting
quality. Evaluation and choice should consider both
energy and maintenance costs, as well as initial cost of
the fixtures. EPRI TR-101710 provides guidance on
achieving design lighting levels in an energy-efficient,
cost-effective manner.
12-4. Conductor Types and Sizes
b. Lighting source types.
Efficient light sources
should be considered. There are four common lighting
source categories, as follows:
(1) Incandescent.
In general, incandescent lamps
provide the “whitest” light, but at a higher energy cost
and relatively short life. Incandescent lamps are used
where fluorescent fixtures are not practical for reasons of
vapor, limited space, high lighting levels, or the need for
superior color rendition.
(2) Fluorescent. Triphosphor fluorescent lamps are a
good source of “white” light and are relatively long-lived,
with energy efficiencies better than incandescent lamps.
Most rooms and shops should be illuminated with energyefficient, fluorescent fixtures, using T-8 high-efficiency
lamps and electronic ballasts.
(3) High-intensity discharge (HID).
(a) HID mercury lamps are fairly efficient, have
relatively long lives, but are not a good source of “white”
light, covering only about 50 percent of the visible
The voltage drop in panel supply circuits should be
limited to 1 percent if possible, and the drop in branch
circuits should be limited to 2 percent. If it is not possible to limit the voltage drop to these figures, a limit of
3 percent for the total voltage drop should be observed.
In arriving at the voltage at the load, the impedance drop
through the transformer should be considered, although
this drop need not be considered in feeder or branch circuit design. Branch circuit and panel feeder design
should be based on the considerations outlined in Chapter
15. Minimum conduit size should be 3/4 in. and the
minimum conductor size should be No. 12 AWG.
12-5. Emergency Light Control
A system employing selected fixtures normally supplied
from the AC source through an automatic transfer switch
transferring the fixtures to the DC system on AC voltage
failure should be provided. Fixtures sourced from the
station battery should be minimized to reduce battery
drain (see paragraph 12-2b). Return to the AC source
should be automatic when the AC source is restored.
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12-6. Control Room Lighting
a. General. Many different schemes have been used
in attempting to develop “perfect” control room lighting.
This emphasis is due to the difficult and continuous visual
tasks that are performed in the control room. Task ambient lighting provides the most effective approach to
achieving desired results. IES-RP-24 provides guidance
on topics such as quality of illumination, luminance levels, and the visual comfort of room occupants, which
must be evaluated in developing a control room lighting
b. VDTs and instrument faces. Plant control systems
use visual display terminals (VDTs) which tend to “wash
out” in high ambient lighting, and the VDT face reflects
light from sources behind the operator that make the
screen image unreadable. Switchboard instrument faces
also reflect light, and such reflections obscure the instrument dial. Light fixtures or window areas should not be
reflected by the instrument glass and VDT screen.
c. Switchboard lighting.
Switchboards should be
lighted so that the instrument major scale markings and
pointers can be readily seen from the control console even
though the actual numbers opposite these markings cannot
be read. Sufficient vertical illumination on the fronts of
the boards is only part of the answer. Illumination must
be provided in a manner that does not produce glare from
the instrument glass, or objectionable shadows on the
instrument face from the instrument rims and control
switches. It is also important that no light source be
visible in the line of the operator’s vision when viewing
the boards.
d. Lighting criteria. Extreme contrasts in lighted
areas, such as a bright ceiling or wall visible above the
switchboard, must be avoided, as they produce eye strain.
The modern practice of using light-colored switchboards,
and the latest design of indicating instrument dials have
both helped to improve control room lighting. Good
control room lighting will be obtained if the following
criteria are observed:
(1) Adequate vertical illumination on vertical board
(2) Brightness contrasts preferably within a ratio of
1 to 3. (No light sources in line of vision).
(3) No specular reflection from instrument, VDT
screen, or other surfaces.
(4) No objectionable shadows on working surfaces.
e. Heat. The amount of heat from the lamps (of any
type) in the control room must be given special consideration in designing the air-conditioning layout for the control room and adjacent areas.
12-7. Hazardous Area Lighting
Battery room and oil room fixtures should be vapor- and
explosion-proof type, and local control switches should be
mounted outside the door. Lighting switches of the standard variety may be used by placing them outside the
room door. Convenience receptacles in the rooms should
be avoided, or where necessary, be of the explosion-proof
12-8. Receptacles
The types and ratings of receptacles for convenience
outlets should be clearly indicated on the fixture and
device schedule sheet in the drawings, or in the bill of
materials. Standardization of receptacles allows use of
portable equipment throughout the project. The following
receptacles are suggested as the appropriate quality and
a. 480-V receptacles.
3-wire, 4-pole, 30 A,
grounded through extra pole and shell of plug type receptacles are recommended. The receptacles and plugs
should meet the requirements of ANSI/UL 498 and should
be weather resistant for use in wet and dry locations. For
welding machines and other portable 480-V equipment,
use two-gang-type cast boxes to ensure adequate room for
No. 6 AWG feeders, except for the placement of 480-V
receptacles at the end of conduit runs, which may be
single-gang receptacles.
b. 120-/208-V receptacles. 4-wire, 5-pole, 30 A,
grounded type receptacles, plugs, and fixtures meeting the
requirements of ANSI/UL 498 and 514 are recommended.
Typically, these fixtures are used to service supplemental
lighting in work areas during overhauls.
c. 120-V receptacles. The choice between using a
twist-lock receptacle or using a parallel-blade receptacle
has never been standardized nationwide. There is a trend
to employ parallel-blade receptacles on new construction
Parallel-blade receptacles are recommended
unless there is a strong local preference for twist-lock
receptacles based on existing local standardization.
Ground fault protection should be provided for 120-V
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outlets in all wet locations or outdoors. Use appropriate
ground fault interrupter circuit breakers in these locations.
(1) Twist-lock receptacles. For projects using twistlock receptacles, 3-pole, 15-A, 125-V, grounding, duplex,
twist-lock, NEMA L5-15R configuration for use with
compatible twist-lock caps are recommended for dry
locations within all powerhouse areas. For wet locations
or outdoors, a similar single-gang receptacle in a cast box
with twist-lock caps or plugs is recommended. For lunch
rooms, office areas, lounges and restrooms, duplex combination, twist-lock, straight-blade receptacles, NEMA
L5-15R configuration, are recommended.
(2) Straight-blade receptacles.
For projects using
straight-blade receptacles, 3-pole, 20-A, 120-277-V grounding, duplex, hospital grade, NEMA 5-20R configuration,
are recommended for dry locations. For wet locations or
outdoor use, single, hospital-grade receptacles in the same
configuration, with weatherproof single-receptacle cover
plates are recommended.
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Chapter 13
Grounding Systems
e. Duration of the fault and body contact for a sufficient time to cause harm.
13-3. Field Exploration
13-1. General
a. Purpose. A safe grounding design has two objectives: to carry electric currents into earth under normal
and fault conditions without exceeding operating and
equipment limits or adversely affecting continuity of
service and to assure that a person in the vicinity of
grounded facilities is not exposed to the danger of electric
b. Reference. IEEE 142, known as “The Green
Book,” covers practical aspects of grounding in more
detail, such as equipment grounding, indoor installations,
cable sheath grounding, etc. This standard provides guidance in addressing specific grounding concerns. Additional guidance for powerhouse-specific grounding issues
is provided in EPRI EL-5036, Volume 5.
13-2. Safety Hazards
The existence of a low station ground resistance is not, in
itself, a guarantee of safety. During fault conditions, the
flow of current to earth will produce potential gradients
that may be of sufficient magnitude to endanger a person
in the area. Also, dangerous potential differences may
develop between grounded equipment or structures and
nearby earth. IEEE 80 provides detailed coverage of
design issues relating to effective ground system design. It
provides a detailed discussion of permissible body current
limits and should be reviewed prior to developing a
grounding design. It is essential that the grid design limit
step and touch voltages to levels below the tolerable levels identified in the standard. The conditions that make
electric shock accidents possible are summarized in Chapter 2 of the guide and include:
a. High fault current to ground in relation to the area
of ground system and its resistance to remote earth.
b. Soil resistivity and distribution of ground currents
such that high potential gradients may occur at the earth
c. Presence of an individual such that the individual’s
body is bridging two points of high potential difference.
d. Absence of sufficient contact resistance to limit
current through the body to a safe value.
After preliminary layouts of the dam, powerhouse, and
switchyard have been made, desirable locations for two or
more ground mats can be determined. Grounding conditions in these areas should be investigated, and the soil
resistance measured. IEEE 81 outlines methods for field
tests and formulas for computing ground electrode resistances. Sufficient prospecting should be done to develop
a suitable location for the ground mat coupled with a
determination of average soil resistivity at the proposed
location. IEEE 81 describes and endorses use of “the
Wenner four-pin method” as being the most accurate
procedure for making the soil resistivity determination. It
also provides information on other recognized field measurement techniques.
13-4. Ground Mats
a. General requirements. The measured soil resistivity obtained by field exploration is used to determine
the amount of ground grid necessary to develop the
desired ground mat resistance. The resistance to ground
of all power plant, dam, and switchyard mats when connected in parallel should not exceed, if practicable,
0.5 ohm for large installations. For small (1500 kW)
plants, a resistance of 1 ohm is generally acceptable.
Practical electrode drive depth should be determined in
the field. A depth reaching permanent moisture is desirable. The effective resistance of, and the step and touch
potentials for, an entire ground mat with a number of
electrodes in parallel can be determined from IEEE 80.
The diameter of the electrode is determined by driving
requirements. Copper-weld ground rods of 3/4 in. diam
are usually satisfactory where driving depths do not
exceed 10 ft. For greater depths or difficult soil conditions, 1-in.-diam rods are preferred. Galvanized pipe is
not suitable for permanent installations.
b. Location. The depth and condition of the soil
upstream from the dam on the flood plain is frequently
favorable for placement of one or two ground mats.
These can be used for the grounding of the equipment in
the dam and leads extended to the grounding network in
the powerhouse. At least one ground mat should be provided under or near the switchyard.
c. Leads. Leads from ground mats should be sufficiently large to be mechanically durable, and those which
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may carry large fault currents should be designed to minimize IR drop. Two leads, preferably at opposite ends of
the mat, should be run to the structure or yard, and the
entire layout designed to function correctly with one lead
disconnected. The design and location of connecting
leads should account for construction problems involved
in preserving the continuity of the conductor during earth
moving, concrete placement, and form removal
d. Types of ground mats. Topography of the site, soil
conditions, and depth of soil above bedrock are factors
influencing not only the location, but type of ground mat
used. Some common types (in addition to forebay location) are:
(1) Ground rods driven to permanent moisture and
interconnected by a grid system of bare, soft annealed
copper conductors. This type of mat is preferable.
(2) A grid of interconnected conductors laid in
trenches dug to permanent moisture below the frost line.
(3) Ground wells with steel casings used as electrodes, or holes in rock with inserted copper electrodes
and the hole backfilled with bentonite clays. The wells or
holes should penetrate to permanent moisture.
(4) Plate electrodes or grids laid in the powerhouse
tailrace, suitably covered or anchored to remain in place.
e. Ground resistance test. A test of the overall project ground resistance should be made soon after construction. Construction contract specifications should contain
provisions for adding ground electrodes if tests indicate
that this is necessary to obtain the design resistance.
Proper measurement of the resistance to ground of a large
mat or group of mats requires placement of the test electrodes at a considerable distance (refer to IEEE 81).
Transmission line conductors or telephone wires are occasionally used for test circuits before the lines are put into
13-5. Powerhouse Grounding
a. Main grounding network.
(1) This network should consist of at least two major
runs of grounding conductors in the powerhouse. Major
items of equipment such as generators, turbines, transformers, and primary switchgear should be connected to
these grounding “buses” so there are two paths to ground
from each item of equipment.
(2) Copper bar rather than cable is preferred for
exposed runs of bus. Generator leads of the metalenclosed type will be equipped by the manufacturer with
a grounding bar interconnecting all bus supports. Properly connected, this forms a link in the powerhouse
ground bus.
(3) In selecting conductor sizes for the main grounding network, three considerations should be borne in
(a) The conductors should be large enough so that
they will not be broken during construction.
(b) Current-carrying capacity of the conductors
should be sufficient to carry the maximum current for a
fault to ground for a minimum period of 5 sec without
damage to the conductor (fusing) from overheating.
(c) The total resistance of the loads from major
items of equipment should be such that the voltage drop
in the cable under fault conditions will not exceed 50 V.
b. Equipment. Miscellaneous electrically operated
equipment in the powerhouse should be grounded with
taps from the main ground network. For mechanical
strength, these conductors should be not less than No. 6
AWG. The resistance of these taps should keep the voltage drop in the leads to the ground mat to less than 50 V.
They should carry the current from a fault to ground
without damage to the conductor before the circuit protective device trips. Provisions should be made in the design
of the powerhouse grounding system for bare copper
cable taps of sufficient length to allow connection to
equipment installed after installation of the grounding
system. Generally, the tap connection cable is coiled in a
concrete blockout for easy accessibility later when attaching the tap to the housing of the equipment with pressure
connectors. Items of minor equipment may be grounded
by a bare wire run in the conduit from the distribution
center to the equipment. The neutrals and enclosures of
lighting and station service power transformers should be
grounded. Distribution center and lighting panel enclosures as well as isolated conduit runs should be grounded.
c. Conductor size selection. Ground conductor sizes
should be limited to Nos. 6, 2, 2/0, 250 kCM and
500 kCM, or larger, to limit ordering inventories and
access normally stocked conductor sizes. Subject to
short-circuit studies, usage, in general, is as follows:
(1) No. 6: Control cabinets, special outlets, machinery, lighting standards, power distribution equipment with
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main feeders #2 or less, and motor frames of 60 hp or
(2) No. 2: Switchboards, governor cabinets, large
tanks, power distribution equipment with primary or secondary feeders 250 kCM or less, and motor frames
between 60 and 125 hp.
(3) No. 2/0: Roof steel, crane rails, generator neutral
equipment, gate guides, power distribution equipment with
primary or secondary feeders larger than 250 kCM, and
motor frames larger than 125 hp.
(4) 250 kCM: Turbine stay-rings, turbine pit liners,
generator housings and/or cover plates, large station
service transformers, transmission tower steel, and interconnecting powerhouse buses.
(5) 500 kCM: Main powerhouse buses, leads to the
ground mat, generator step-up transformer grounds, and
surge arrester grounds.
(6) 750-1,000 kCM: Main powerhouse buses or leads
to the ground mat when larger sizes are needed.
d. Miscellaneous metal and piping.
crane rails should be bonded at the joints with both rails
being connected to ground. Roof trusses; draft tube gate
guides; and miscellaneous structural steel, which may be
exposed to dangerous potentials from energized circuits,
should be connected to the ground network. All piping
systems should be grounded at one point if the electrical
path is continuous, or at more points if the piping system’s electrical path is noncontinuous.
surfacing or a grounding mesh buried 12-18 in. below
grade should be provided at each disconnecting switch
handle. The platform or mesh should be grounded to the
steel tower and to the ground network in two places.
d. Grounded equipment.
Grounded switchyard
equipment includes tanks of circuit breakers, operating
mechanisms of disconnecting switches, hinged ends of
disconnect grounding blades, transformer tanks and neutrals, surge arresters, cases of instrument transformers and
coupling capacitors, and high-voltage potheads. Isolated
conduit runs, power and lighting cabinet enclosures, and
frames of electrically operated auxiliary equipment should
also be grounded. Separate conductors are used for
grounding surge arresters to the ground network. Fences,
including both sides of any gates, and other metal structures in the switchyard, should be grounded to the switchyard grid at intervals of about 30 ft. If the fence gates
open outward, a ground conductor shall be provided
approximately 3 ft outside the gate swing radius. Each
switchyard tower should be grounded through one leg.
All structures supporting buses or equipment should be
grounded. If the network does not extend at least 3 ft
outside the fence line, separate buried conductors should
be installed to prevent a dangerous potential difference
between the ground surface and the fence. These conductors should be connected to both the fence posts and the
ground network in several places.
e. Overhead ground wires. Overhead ground wires
should be bonded securely to the steel structure on one
end only and insulated on the other to prevent circulating
current paths.
13-7. Grounding Devices
13-6. Switchyard Grounding
a. Copper conductors. A grid of copper conductors
should be installed beneath the surface of the switchyard
to prevent dangerous potential gradients at the surface.
The cables should be large enough and be buried deep
enough for protection from mechanical damage. The
cables’ current-carrying capacity under fault conditions
and during lightning discharges should be checked.
Under all conditions, the grid serves to some extent as an
electrode for dissipating fault current to ground.
b. Ground rods. If warranted by soil conditions, a
system of ground rods should be installed with the grid to
provide maximum conductance to ground.
c. Grounding platform. A grounding platform consisting of a galvanized steel grating set flush in the gravel
a. Cables. Grounding cable used for direct burial or
embedding in concrete should be soft-drawn bare copper.
Sizes larger than No. 6 AWG should be stranded.
b. Electrodes. Electrodes for driving should be
copper-weld rods of appropriate diameter and length.
Desired lengths can be obtained on factory orders.
c. Exterior connections. Ground cable connections
to driven ground rods, any buried or embedded connections, or any exposed ground grid connections should be
made either with an appropriate molded powdered metal
weld or by a copper alloy brazed pressure connector.
d. Interior connections. Pressure clamp (bolted)
type terminal lugs should be used for interior work. For
neatness of appearance of interior connections, embedded
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grounding cables may terminate on or pass through
grounding inserts installed with the face of the insert flush
with the finished surface. Connection to the apparatus is
made by bolting an exposed strap between a tapped hole
on the insert and the equipment frame.
e. Test stations. Test stations should be provided for
measuring resistance of individual mats and checking
continuity of interconnecting leads. Where measurements
are contemplated, the design of the grounding systems
should avoid interconnection of ground mats through
grounded equipment, overhead lines, and reinforcing steel.
f. Embedded cable installation. Embedded ground
cables must be installed so movement of structures will
not sever or stretch the cables where they cross contraction joints. Suitable provision should be made where
embedded cables pass through concrete walls below grade
or water level to prevent percolation of water through the
cable strands.
g. Conduit. Grounding conductors run in steel conduit for mechanical protection should be bonded to the
conduit. Control cable sheaths should be grounded at
both ends. Signal cable shields are grounded at one end
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Chapter 14
Conduit and Tray Systems
14-1. General
The conduit and tray system is intended to form a permanent pathway and to provide maximum protection for the
conductors. The system design should allow for reasonable expansion of the number of leads and circuits.
14-2. Conduit
a. Design. Where practicable, all conduits should be
concealed. In cases in which allowance must be made for
circuits to future equipment, the conduit extension may be
exposed. Connections to equipment should not be made
with flexible conduit if suitable connections can be made
with rigid conduit.
(1) Conduit size is determined by the type of wire
and number of circuits in the run, the length of run and
the number and degree of bends in the run.
(2) Where conduits cross building contraction joints,
the conduit runs should be perpendicular to the joint and
expansion fittings, such as dresser couplings with grounding straps, installed to provide for movement of the
conduit and to maintain an unbroken ground path. The
fitting, installed on one side of the contraction joint,
should be protected with a suitable neoprene sleeve to
accommodate differential movement of the concrete.
(3) Conduit should be installed in a manner to permit
condensed water to drain whenever possible. When selfdraining is not possible, a suitable drain should be
installed in the low point of the run. Threaded joints in
metal conduit and terminations in cast boxes should be
coated with an approved joint compound to make the
joints watertight and provide electrical continuity of the
conduit system.
(4) The conduit should provide a ground for the
frames or housings of equipment to which it is connected,
thereby providing a backup for the ground wire connection to the main grounding system. All conduits except
lighting branch circuit conduits should be listed in the
conduit and cable schedule.
b. Conduit types.
(1) Rigid steel conduit should be hot-dip galvanized
on inside and outside surfaces, conforming to ANSI
(2) For powerhouse substructure work, if conditions
are such that embedded galvanized conduit might rust out,
consideration should be given to installing exposed runs
which can be replaced. Galvanized conduit buried in the
switchyard should be protected with a coat of bituminous
paint or similar material, unless experience at the particular site has demonstrated that no special protection is
needed on the galvanized conduit.
(3) Unjacketed type MC or type MV cables, meeting
the requirements of UL 1569 or UL 1072, may be used to
avoid installing a cable tray carrying only a few conductors or where the installed cost would be substantially less
than installing rigid steel conduit. Compatible connectors
should be used to bond the sheath to the ground system
and to the equipment served. The copper sheath version
is preferable for corrosive environments. MC or MV
cables with PVC insulation or jacketing should not be
c. Boxes and cabinets.
(1) The materials used for boxes and cabinets should
conform to those used for the conduit system. Cast iron
boxes should be used with galvanized conduit in embedded and exposed locations at and below the generator
room floor level. Galvanized sheet steel boxes are
acceptable in locations above the generator room floor.
Suitable extension rings should be specified for outlet
boxes in walls finished with plaster or tile. Large cabinets used for pull boxes, distribution centers, and terminal
cabinets are usually constructed of heavy-gauge, galvanized sheet steel. Because it is impracticable to galvanize
large sheet metal boxes and fronts after fabrication without severe warping, galvanized steel sheets should be used
in the fabrication. Box corners should be closed by welds
after bending, and the galvanizing repaired by metallized
zinc spray.
(2) If a cabinet is embedded in a wall finished with
plaster or tile, special precautions should be observed to
ensure that the face of the installed cabinet is flush with
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the finished wall. Front covers are generally mounted
with machine screws through a box flange drilled and
tapped in the field to facilitate proper alignment. The
requirements of UL 50 should be considered as minimum
in the design of such cabinets. Provision should be made
for internal bracing of large cabinets to prevent distortion
during concreting operations.
b. Fabrication. Cable trays are fabricated from
extruded aluminum, formed sheet metal, or expanded
metal. Material costs for the expanded metal trays may
be slightly higher, but a greater selection of joining
devices, greater distance between supports, and special
sections and fittings minimize field labor costs and generally result in lowest installed cost.
(3) Pull boxes for telephone circuits should be large
enough to provide adequate space for fanning-out and
connecting cables to the terminal blocks.
c. Tray supports. The trays are installed on fabricated galvanized steel supports designed and anchored to
the powerhouse walls and/or ceiling to provide a rigid
structure throughout. In the cable spreading room, the
tray supports may extend from the floor to the ceiling to
give the necessary rigidity. Supports similar to cable
racks and hooks are suitable for supporting cable trays on
cable tunnel walls. If trays run through the center of a
tunnel, they should be supported on structural members
such as channel with angle cross-pieces. Metal tray sections 8 ft long require supports on 8-ft centers. Splices
should be made at supports to provide proper anchorage
for the tray sections.
14-3. Cable Trays
a. General. Cable trays are commonly used to carry
groups of cables from generating units, the switchyard,
and accessory equipment that terminates in the control
room. Trays in place of conduit provide flexibility, accessibility, and space economy. Trays are also used for the
interconnecting cables between switchboards in the control room, and from switchboards to the terminations of
embedded conduits running to equipment. Short runs of
trays may be used to connect two groups of conduit runs
where it is not practicable to make the conduit runs continuous. The designed tray system should provide the
maximum practicable segregation between control circuits
and power and lighting circuits. Appropriate guidelines
for cable tray design considerations are contained in
IEEE 422.
d. Cable supports. Split hardwood blocks drilled to
fit cables or accessories for the metal trays should be
provided as necessary to support cables entering and
leaving the trays. The tray system should be designed to
avoid long steep runs requiring anchoring of the cables to
prevent movement.
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Chapter 15
Wire and Cable
15-1. General
Wire and cable systems should be designed for long life
with a minimum of service interruptions. The materials
and construction described in Guide Specification CW16120 provide construction materials consistent with these
service requirements. IEEE 422 provides overall guidance in planning, designing, and installing wire and cable
systems in a power plant. Topics covered in the IEEE
guide include cable performance, conductor sizing, cable
segregation systems, installation and handling, acceptance
testing, and other related subjects. Additional guidance is
provided in EPRI EL-5036, Volume 4.
15-2. Cable Size
The minimum size of conductor for current-carrying
capacity should be based on the National Electrical Code
(NEC) requirements for 60 °C insulated wire. NEMA
WC50 and WC51 provide ampacities for high-voltage
cables and for multiconductor cables not covered in the
NEC. Circuit voltage drop should be checked to ensure
the total drop from the source to the equipment does not
exceed requirements of Articles 210 and 430 of the NEC.
15-3. Cable System Classification
All cables or conductors, except lighting system branch
circuits, should be listed in the conduit and cable schedule
under the appropriate heading as either power or control
cable. Design of the cable systems is divided into three
classifications according to functions, as follows:
a. Interior distribution.
(1) Power and lighting conductors include circuits
from the station service switchgear to distribution centers
or to station auxiliary equipment; branch circuits and
control circuits from distribution centers to auxiliary
equipment; feeders to lighting panels; and lighting branch
circuits. No conductor size smaller than No. 12 AWG
should be used, except for control circuits associated with
heating and air-conditioning equipment where No. 14 is
(2) Multiconductor power cables should be used for
the larger and more important circuits such as feeders to
distribution centers in the dam, the powerhouse, and the
switchyard; lighting panels; and any other major project
loads. Single-conductor wires can be used for branch
circuits and control circuits from distribution centers to
equipment when installed in conduit. For cable tray
installations, Article 318 of the National Electric Code
(NFPA 70-1993) dictates the use of multi-conductor tray
rated cable for all circuits requiring No. 1 cable or
b. Control and communication.
(1) Control cables include station control and annunciator circuits from the control room switchboards, unit
instrument boards, exciter cubicles, and secondary control
centers. Such circuits are generally identified with the
DC control system, the instrument bus, or the annunciator
system. All control cables, except those for the communication system and special circuits noted in paragraph 15-3b(6), should comply with the requirements of
Guide Specification CW-16120.
(2) The cables should be adequately supported in
long vertical runs and where they enter or leave the cable
trays. Multi-conductor cables are usually No. 19/25 or
19/22 for control, metering, and relaying circuits and
No. 16 stranded for annunciator circuits. All current
transformer secondary circuits should be No. 19/22 or
larger. Larger conductor sizes may be required to take
care of voltage drop, or to decrease the burden on instrument transformers.
(3) No splices should be made between the terminal
points of the cable.
(4) In selecting cables, consideration should be given
to minimizing the number of different cable items ordered
for installation or stocked for maintenance. For example,
the 4-, 6-, and 8-conductor cables might be omitted and
5-, 7-, and 9-conductor cables substituted, leaving one
spare conductor. The practice of including one or more
spare conductors in each cable of more than four conductors is considered desirable. Selection of sizes and numbers of conductors per control cable should be limited, if
possible, to combinations that have 50 ft or more in each
item of a lot ordered.
(5) All wiring for the telephone system, including
circuits from the main cabinet to the local telephone jacks,
should be listed under “Telephone” cables in the schedule.
Selection of telephone system conductors will be dictated
by the application.
(6) Special circuits such as calibrated ammeter leads,
and coaxial cable circuits to carrier-current capacitors,
computer networks, microwave, and video, should be
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scheduled under control cables or telephone cables,
whichever is applicable. Clarifying remarks concerning
the type of the conductor and the supplier should be
included. Where fiber-optic cables are used, installation
and application should follow the manufacturer’s recommendations. Two-conductor No. 19/25 control cables
may be used where the circuit lengths make it impractical
to obtain calibrated leads with the instruments.
(7) Analog and digital signal cables. There is no
standard specification for these cables. There are general
guidelines that should be followed in selecting the general
characteristics of the signal cable to be used. Some of
these guidelines are:
(a) PVC insulation or jacketing may not be used.
(b) Insulation and jacket material should pass UL
flame tests.
b. Power circuits.
(1) Each cable and conduit should be identified with
an individual designation. The cable and conduit are
tagged with a designation at each end and at intermediate
points as necessary to facilitate identification. The designation is also shown on equipment wiring diagrams, tray
loading diagrams, on conduit plans and details, on cabinet
layouts, and on junction and pull box layouts.
(2) The scheduling of cables should always include
(opposite the cable designation) the following information:
(a) Number and size of conductor.
(b) Function or equipment served.
(c) Origin and destination.
(d) Routing via conduits and trays.
(c) Analog signal conductors must be paired and
twisted together with a shield, signal conductor, and
return conductor in the same pair.
(e) Special conditions.
(f) Estimated length.
(d) Conductor pairs should be twisted, variable lay,
pairs individually shielded.
(e) Multipair cables should have an overall shield and
an outer jacket.
(f) Shields should be grounded at one end only to
prevent shield current.
(3) The scheduling of conduit should include (opposite the conduit designation) the following:
(a) Size and type of conduit.
(b) Function or equipment serviced.
(c) Origin and destination.
(g) Conductor size should be not less than No. 18
(h) Minimum insulation level should be 150 V.
c. Grounding conductors.
Embedded grounding
system conductors should be stranded, soft-drawn, bare
copper wire following the recommendations of Chapter 13. The cables need not be scheduled, but if brought
out in test stations, should be suitably tagged for future
15-4. Conduit and Cable Schedules
a. General. The intent of the conduit and cable
schedule is to provide all pertinent information to assist in
installing, connecting, identifying, and maintaining control
and power cables. When not included with the plans for
construction bids, the specifications indicate cable schedules will be furnished to the contractor.
(d) Special conditions.
(e) Length.
(4) Conduit and cable should have the same designation if possible. The number assigned should give information about the service rendered by the cable, the
termination points of the cable, and the approximate voltage or power classification.
(5) Generally, each cable between major units of
equipment or from major units of equipment in the powerhouse to structures external to the powerhouse is
assigned a number made up of three parts, as follows:
(a) The first part of the cable number shows the
beginning of each cable run and is composed of uppercase letters and numerals assembled into a code to represent the various major units of equipment, switchgear,
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switchboards, cabinets, etc., located throughout the
(b) The second part of the cable number is composed
of a single lower-case letter and number. The letter indicates the type of service rendered by the cable, i.e.,
power, alarm, etc., while the number serves to differentiate between cables of a particular type running between
two points.
(c) The third part of the cable number shows the
termination of each cable run and is composed in the
same manner as the first part of the cable number.
Example: Cable Number
Cable ID: SC-u3-G1
Breakdown: SC = Start of cable run (Main control
u = Type of service (Annunciator
3 = Number of such cable (3rd
annunciator lead cable to Generator No. 1; there might be 6 or 9
cables, for example, each with its
own number)
G1 = Termination of cable (Generator
No. 1)
(6) Cables between low-voltage equipment (such as
motor control centers) and minor units of equipment (such
as station auxiliaries) have no code letter and numeral to
show the termination of the cable run. The cable numbers in these cases are made of only two parts. The first
part indicates the start of the cable run, while the second
part indicates the type of service rendered by the cable.
Example: Cable Number
Cable ID: CQ5-c12
Breakdown: CQ5 = Start of cable run (480-V load
center No. 5)
c = Type of service (Control circuit)
12 = Circuit number
(7) Numbers are assigned to the power and control
cables so the power circuit of a given number is
controlled by a control circuit having the same number,
the differentiation being only in the code letter designation of the circuit duty. As an example, cable “CQ5-c12”
would be the control for power circuit “CQ5-q12.”
(8) There are cases where a circuit terminates at
several duplicate devices. For instance, an annunciator
circuit runs to a junction box and is spliced at this point
with branches running to a thermostat in each tank of a
transformer bank. In such a case, the cable from the
switchboard may have a designation such as S1-u2-T1
and the branch designations are S1-u2.1-T1, S1-u2.2-T1,
and S1-u2.3-T1.
(9) Spare conduits are numbered by using a threepart number where possible. In cases where the spare
conduits leave a certain switchboard or distribution center
and are stubbed at the end of the building, only a two-part
number can be used, e.g., CQ01-s1 is a spare conduit
leaving motor control center CQ01.
c. Lighting circuits.
(1) Numbering of the circuits and conduits for lighting circuits is similar to the power circuit numbering
scheme. Each cable is assigned a three-part number such
as SR1-r3-CR4. Full information for these conduits and
circuits is given on lighting drawings. Circuits from the
lighting cabinets receive numbers corresponding to the
switch numbers in the lighting cabinets.
(2) The lighting drawings indicate, between each
outlet, the conduit size, number of conductors, and the
size of the conductors. The number of conductors is
indicated by drawing small lines across the conduit, one
line for each conductor. At the side of each outlet, there
is a small number indicating the circuit to which the outlet is connected, another number at the side of the outlet
indicating the size of the lamp to be installed if not covered elsewhere. Where the conduit leaves the first outlet
to run to the lighting cabinet, the circuit numbers of the
conductors in the conduit are indicated.
d. Code letter identification.
(1) General. Code letters are broken down into three
classes: terminal equipment, modifying terms for terminal
equipment, and cable service classification. Code letters
and explanations are given in Table 15-1 below.
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Table 15-1
Code Letters for Conduit and Cable
Terminal Equipment
• Operator’s desk, switchboards, and switchgear
Fishwater Generator Switchboard
Satellite Digital Processor
Generator Switchboard (Add No.)
Battery Switchboard
Main Control Switchboard
Main Control Console
Graphic Instrument Switchboard
Load Control Switchboard
Station Service Switchboard
System Operations Controller
13.8 kV Switchgear (Add No.)
4160 V (or 2400 V) Switchgear
480 V Switchgear (Add No.)
Heating Switchgear
Status Board
Motor Control Center (Add No.)
Lighting Switchgear
Excitation System Equipment (Add No.)
Generator Neutral
Operator’s Desk
Carrier Current Equipment
Electrical Equipment Room Cabinets
Microwave Terminals
Fishway Switchboard
Digital Operations Controller
Remote Operations Controller
4160 V Fishway Switchgear
4160 V Fishway Controller
480 V Fishway Switchgear
Fishway Unit Switchgear
Telephone Frame
• Load centers
4160 V (or 2400 V)
480 V
120/240 V (120/208 V)
48 V DC
125 V DC
250 V DC
Emergency Lighting
Preferred AC
(CO2) Cabinet
480 V (Dam)
4160 V (or 2400 V) Fishway
480 V (Fishway)
480 V (Project)
• Apparatus
Actuator (Governor)
Fishwater Generator
Breaker (Add Voltage Letter)
Transformer (power)
Disconnecting Switch (Add Voltage Letter)
Current Transformer
Voltage Transformer
Engine Generator
Motor Generator
Motor Control Cabinet
Potential Transformer (Separate Apparatus modified by
voltage as PTW)
- Crane
- Fishway Transformer
• Miscellaneous terminal equipment, boxes, or structures. Some
items in this list are used for cable and conduit terminals, but a
majority are used only as modifying suffixes for devices on schematic diagrams:
Governor Air Compressor
Air Horn
Governor Oil Pump
Annunciator Reset
Ammeter Switch
Battery Charger
Break Glass Station
Bubbler System
Bypass Valve or Butterfly Valve
Central Air Conditioner
Junction Box, Master Control Circuits (Modify by Unit No.)
Channel Manometer
Capacitance Potential Device
Control Terminal Cabinet
Drainage Pump
Deck Station
Differential Transmitter (Transducer)
Domestic Water Pump
Sewage Aerator
Effluent Comminutor
Exhaust Fan
Electric Heater
Electric Oil Heater
Sewage (Effluent) Pump
Elapsed Time Meter
Electrically Operated Valve
Flow Meter
Fire Pump
Float Switch (Device 71 preferred)
Fishway Terminal Cabinet
Float Well
Forebay Water Level Gage
Generator Heater
Ground Insert
Grease Pump
Generator Cooling Water (Pump or Valve)
Head Cover Sump Pump
Air Conditioning Damper
Air Conditioning Air Filtration Equipment
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Table 15-1. (Concluded)
Air Conditioning System Humidifier
High Pressure Thrust Bearing Oil Pump
Conditioning System Oil Pump
Air Conditioning System Refrigeration Pump
Air Conditioning System, Master Devices
Air Conditioning System Water Pump
Intake Gate
Intake Manometer
Intruder Detector System
Intake Gate Oil Pump
Junction Box
Load Control Cabinet
Outside Lighting (480 V)
High Bay Lighting
Line Tuning Unit
Load Control Master
Motor Operated Disconnect
Operations Recorder
Load Control Station Operation Selector
Station (Plant) Air Compressor
Pull Box or Pushbutton
Program Controller
Penstock Gate
Powerhouse (Add No.)
Project Building
Potential Selector or Pressure Switch (Device 63
preferred for pressure switch)
Pressure Tank
Penstock Valve
Oil Transfer Pump (Dirty)
Oil Transfer Pump (Lube)
Oil Transfer Pump (Transil)
Code Call Relay Box
Recirculating Fan
Raw Water Pump
Servo or Shaft Oil Catcher Drain Pump
Supply Fan
Stop Nut
Load Control System Selector
Transformer Cooling Equipment Air System
Telephone Box or Test Block
Turbine Bearing Oil Pump - AC
Turbine Bearing Oil Pump - DC
Terminal Cabinet
Transformer Deluge
Thermostat (Heating & Ventilation Equipment Drawings)
Preferred AC Transformer
Tailrace Manometer
Turbine Pit
Transformer Cooling Equipment Oil Pump
Test Station
Tailwater Level Gage
Unit Air Conditioner
Unit Load Control Selector
Unit Selector
Unloader Valve
Unwatering Pump
Valve Oil Pump
Circuit Breaker Air Compressor
Circuit Breaker Cooling Fan
Voltmeter Switch
Water Gate (Sluice, Weir, etc.)
Water Heater (Hot Water Tank or Boiler)
Gate Wash Pump - Deck Wash Pump
Water Valve
Modifying terms for terminal equipment
• As an aid to further identification of voltage class and location of
the equipment, the following letters are applied to separately
mounted breakers, disconnecting switches, current transformers,
and voltage transformers:
500 kV
230 kV
115 kV
13.8 kV or 7.2 kV
4160 V (or 2400 V)
480 V
120/240 V (120/208 V)
250 V DC
125 V DC
48 V DC
120 V Preferred AC
• Other modifying terms
- (as GO, TO) - Station Service
- (as GN1, TN1) - Neutral
- (as CY for CO2 Cabinet) - CO2
Service classification
- Current Transformer - Shunt Leads
- Control Circuits, (Circuit Breaker Control Circuits, Excitation System Control Circuits, and Governor Control
- 0 - 48 V DC
- Power Circuit, 125 V DC
- Power Circuit, 250 V DC
- 120V Preferred AC
- Power Circuit, 13.8 kV AC
- Power Circuit, 230 kV AC
- Power Circuit, 4160 V or 2400 V AC
- Power Circuit 480 V AC
- Power Circuit (Lighting) 120/240 V or 120/208 V AC
- Spare Conduit
- Radio Circuits
- Telephone Circuits, Intercommunication Circuits
- Sound Power Circuit
- Alarm Circuits; Annunciator Circuits; Water Flow Level;
Pressure; and Temperature Indicating and Recording
Circuits; Telemetry, Analog, Operations Recorder, etc.
- Code Call Circuits
- Voltage (Potential) Transformer Secondaries and DC
Voltage Leads
- Carrier or Pilot Wire Circuit
- Excitation Circuits
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e. Code identification notes.
(1) The list of letters in paragraph 15-4d(1) is used
for separately mounted apparatus only. Instrument transformers and disconnecting switches are given individual
designations only if they are mounted by themselves, as in
an outdoor structure or in a similar indoor arrangement.
(2) Instrument transformers and disconnecting
switches mounted on a circuit breaker or circuit breaker
structure have the cable and conduit designations of the
breaker. For example, bushing-type current transformers
and potential devices mounted on oil circuit breaker XJ3
have cable and conduit designations such as “S3-a1-XJ3”
and “S3-v1-XJ3”
(3) Cable terminal designations are used to designate
major assemblies such as a switchgear assembly and not
an individual breaker within the switchgear. Individual
breaker designation is desirable, but including it in the
terminal designation (first term of cable code) would
complicate the system impairing its usefulness. Thus,
instrument transformers, breakers, and disconnecting
switches mounted in a switchgear or switchboard take the
terminal designation of the switchgear or switchboard.
For example, a breaker mounted in a 480-V switchboard
has a cable and conduit designation of “SQ” for the first
term and even though the breaker may have a number,
this number is disregarded in the first term of the cable
code. Where there are only a few breakers, the lack of a
more positive identification is not objectionable.
(4) When a switchboard has a large number of
breakers, considerable time may be consumed in locating
the cable. To overcome this objection, the second term of
the cable code is numbered to correspond with the breaker
number. For example, CQ2-q8 and CQ2-q25 are 480-V
power circuits connected to breaker No. 8 and No. 25,
respectively, in 480-V cabinet No. 2. No difficulty is
encountered because the number in the second term serves
to differentiate one cable from another and doesn’t indicate the total number of cables from a point.
(5) The order of terminal designation follows the
order given in the code. For example, a cable between a
lighting switchboard and a lighting cabinet is designated
as “SR2-r4-CR5.” The switchboard table precedes the
load center table, the switchboard designation being the
first term and the load center the last term. Other examples would be SJ-j2-G1 and CP-p1-K2. This order of
designation is maintained for items of the same table;
e.g., SC-a1-SP or A2-c1-G2.
(6) Because of the complicated code, the designation’s primary application is in the powerhouse. The
same designation may be used with a prefix to signify
location at a different feature of the project. For example,
DCR can represent a lighting cabinet in the dam.
(7) Similarly, FCQ represents a fish facility 480-V
control center. This system is maintained at the powerhouse for terminal equipment, cables, and conduits servicing the fishway next to the powerhouse and also is
maintained partially at the fishway. However, on portions
of the fishway including collection channels, diffusion
chambers, and the various gates, it is desirable to use
designations employed in the structural and mechanical
design and having name familiarity. Designations and
locations of these elements of fish facilities are projectspecific.
(8) Cable running from one part of the project to
another should be clearly identified. For instance, the
4160-V cables originating at the powerhouse and used to
supply power for the fishway, dam, and lock may have a
designation SP - p1 to the first point of connection, SP p1.1 between the first and second points of connection,
and SP - p1.2, and so on, for the subsequent points.
(9) Powerhouse drawings showing the cable running
to the fishway should indicate the cable number and give
reference to the fishway drawing in which the other terminal of the cable is shown. Similarly, the fishway drawings should indicate the cable numbers for the cable in
both directions and references given to both powerhouse
and dam drawings.
(10) Wiring diagrams for a large switchboard or
switchgear assembly are on several drawings, so considerable time is consumed in locating the proper drawing
and the proper panel. To avoid this difficulty, each
switchboard has its front panels numbered in order from
left to right. The panel designation is the switchboard
designation followed by the panel number, and the cable
number then designates the panel at which it terminates.
For example, on Generator Switchboard No. 1, the third
panel from the left would be designated “S13” and a
cable running from this panel has a designation such as,
(11) In duplex switchboards, a rear panel is designated by the letter “R” followed by a number corresponding to its front panel. For example, on Generator
Switchboard No. 1, the third rear panel from the right
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(facing the front of the rear panels) is designated “S1R3”
and a cable running from this panel has a designation
such as “S1R3-c1-TO.”
(12) Some vertical sections of a motor control center
assembly may include two or more lighting panels, in one
instance with the same voltage classification (e.g., CR-r
and CA-r). The lighting panel designation is used in lieu
of the vertical section number in these instances. A
motor control center could include lighting panels of the
following designations:
SU1 - - - CR11, CE11, CF11, CA11, CB11
SU2 - - - CR21, CE21, CF21, CA21, CB21
SU3 - - - CR31, CE31, CF31 CA31, CB31
SU4 - - - CR41, etc.
f. Lighting circuits. With lighting circuits, it is desirable to deviate from the general plan of providing a relationship between the conduit and its contained circuits.
Branch circuits from lighting cabinets are numbered to
comply with the power circuit guide. The numbering of
branch conduits from lighting cabinets complies with the
guide, except the conduit number bears no relationship to
the numbers of the circuits running through it. The conduit number is initially determined by sequence numbering in a clockwise direction from the upper right-hand
corner when facing the lighting cabinet and is not affected
by circuits and conduits feeding the lighting cabinet.
Where more than one row of knockouts is involved, the
sequence of numbering is from front to back and
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Chapter 16
Procedure for Powerhouse Design
16-1. Design Initiation
Design for a powerhouse is initiated during engineering
and design activities supporting preconstruction planning
studies. The planning studies accompany reports to Congress seeking initial authorization for a project. The
accompanying studies are either reconnaissance reports or
feasibility studies with an engineering appendix. If favorable congressional action is received as a result of initial
authorization activities, further engineering and design
activities are conducted including preparation of a General
Design Memorandum (GDM). The GDM is incorporated
into documentation submitted to higher authority seeking
a construction start. ER 1105-2-100 provides further
information on the contents of these reports. Chapter 17
describes requirements for the GDM. At each stage of
the process, powerhouse design is further refined.
16-2. Design Process
After a project has been authorized and funds appropriated or allotted for design of the power plant, criteria
outlined in Guide Specification CE 4000, Appendix A,
should be followed regardless of the organization performing the design. The criteria outline a process of
preparation of Feature Design Memorandums covering the
design features of the power plant, preparation of plans
and specifications, and other engineering activities
involved in implementing design, construction, and commissioning of the power plant. The field operating activity (FOA) can utilize either the Hydroelectric Design
Center (HDC) or an architect engineer (A-E) to provide
the engineering and design services for developing powerhouse design, preparing plans and specifications, reviewing vendor drawings, assisting in preparation of operation
and maintenance manuals, and providing record drawing
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Chapter 17
General Design Memorandum
17-1. Requirements
Format and content requirements for the General Design
Memorandum (GDM) are described in ER 1105-2-100.
The general features of the selected power plant design
are presented and analyzed by means of sketches, diagrams, and cost comparisons. Sketches, diagrams, and
cost comparisons are used to explain plan formulation and
the plan selection process.
The electrical drawings
required for the memorandum, in addition to equipment
locations shown on general floor plans, consist chiefly of
one-line diagrams. Approximately six to eight drawings
are sufficient to show main unit and switchyard connections, the station service scheme, the control and protective relaying schemes, the communications system, and a
lighting feeder scheme. Major equipment information,
obtained from vendors, should be included in the appendixes. If the report is approved, it becomes a guide for
subsequent detailed engineering developed in Feature
Design Memorandums and design drawings (covered in
Chapter 18).
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Chapter 18
Feature Design Memorandums and
18-4. Design Drawings
18-1. Design Memorandum Topics and Coverage
a. Generators. No design drawings are necessary
for generators, unless needed to depict unusual generator
lead arrangements, or illustrate connections to and location of excitation equipment.
Following approval of the General Design Memorandum,
engineering, design, and drawing preparation for the
power plant proceed using Feature Design Memorandums
(FDM) and accompanying drawings. A completion schedule for each of the planned memorandums and a
sequence of submission is developed for the concurrence
and approval of the field operating activity (FOA) and
higher authority early in the process. Design memorandum sequence and submission dates should be coordinated
with the power plant construction schedule and equipment
procurement schedules. Timing and sequence of submission are scheduled to maximize review time and allow
effective use of engineering resources of the review
Design drawings accompanying an FDM will conform in
general to the requirements mentioned in the following
b. Transformers. Design drawings for either generator step-up or station service transformers are not required
with FDM submission.
c. High-voltage system.
Drawings locating the
switchyard with respect to the powerhouse, depicting
cable tunnel or cable duct locations, and providing details
on bay widths, types of structures, and phase-to-phase and
phase-to-ground clearances should be furnished. A plan
of the switchyard, including line bay and transformer bay
sections and a switchyard one-line diagram, will adequately convey the design intent.
18-2. Feature Design Memorandums
FDMs are normally prepared for electrical equipment and
systems purchased by the Government. They are also
prepared for electrical systems having a significant content of Government-furnished equipment. The plans and
specifications required for purchased equipment are based
on the design parameters and information contained in the
FDM. Typical equipment and systems requiring FDMs
include generators, step-up and station service transformers, generator bus and breakers, station service switchgear,
power plant energy management systems (SCADA),
480-V station service and distribution systems, station
battery systems, and station lighting and distribution
18-3. Engineering Documentation
The engineering documentation in FDMs should include
the methods, formulas, detailed computations, and results
(if results are obtained from engineering software programs) used to determine equipment and system ratings
and technical design parameters. Design alternatives
investigated during the equipment or system selection
process should be discussed together with the rationale for
choosing the selected alternative. FDMs should contain
sufficient detail not only to facilitate the checking and
review process, but to allow preparation of plans and
specifications accurately conveying the design intent.
d. Generator-voltage system. A plan of the arrangement of the generator bus and breaker system, together
with locating and limiting dimensions, equipment ratings,
generator surge protection equipment, and excitation system power potential system taps, should be provided with
the FDM. In addition, a plant one-line diagram should be
e. Station service systems. Drawings with arrangements, locations, limiting dimensions and one-line diagrams for medium-voltage switchgear, low-voltage
switchgear, and low-voltage motor control centers of the
station service system should be included with the FDM.
f. Control system. Drawings included with the control system FDM should define the design of the plant
energy management (SCADA) system, the plant control
and relay scheme, the control and protective relay switchboards, and associated equipment. The plans should
provide sufficient information regarding control and protective relay functions to convey the intended operations
of the plant’s control and protective relaying systems.
Typically, unit one-line diagrams, unit and plant control
and protective relaying schematics, station service control
and protective relaying schematics, and block diagrams of
the plant’s energy management system adequately provide
this information. In addition, a control room layout, and
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a layout with control equipment locations, together with
locating and limiting (if necessary) dimensions, is
g. Communications systems. A drawing of the extent
and composition of leased commercial telephone facilities,
the code call system, and dedicated communications systems for utility communications, telemetry, and plant
energy management systems (SCADA) should be provided. Drawings with locations of the commercial telephone main distribution frame, code call stations, and
dedicated communication system components of either the
power line carrier, microwave system, or the fiber-optic
system should be provided.
provided. Information regarding connected lighting system loads, intended feeder sizes, and location of lighting
distribution panels and transformers should be included.
In addition, information on intended lighting intensities
throughout the plant and proposed types of luminaires
should be provided.
j. Grounding systems. A plan of the power plant
ground mat, including taps to major equipment, should be
provided. A similar plan should be provided if a separate
switchyard ground mat is included in the project
h. Direct current system. In addition to the one-line
and schematics described in paragraph 18-4f, a preliminary layout should be provided of the DC system equipment. The drawing should include the rating of battery
chargers, inverters, and batteries; any limiting dimensions
of equipment; and the arrangement of the battery cells.
k. Conduit and cable tray systems. Design layouts
with locations and preferred methods of routing major
conduit runs (including number and size of conduit)
should be provided. Similar layouts should be provided
for the plant’s cable tray systems. These preliminary
layouts form the basis for detailed drawings of these
systems prepared for the powerhouse construction
i. Lighting and receptacle systems. Drawings of the
plant normal and emergency lighting systems should be
l. Wire and cable. Design drawings are not prepared
for this phase of the work.
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Chapter 19
Construction Specifications and
19-1. Specifications
a. Types of contracts. Construction specifications and
drawings for hydroelectric power plant work are used for
two different classes of contracts: supply contracts for the
purchase of built-to-order equipment from manufacturers;
and construction contracts for the building of the powerhouse, switchyard, and related structures. When construction begins before engineering and design of all features
are completed, second- and third-stage construction contracts are used to cover the superstructure and/or wiring
and installation of machinery and equipment.
b. Selection of contract type. The choice of whether
to include electrical equipment procurement within the
powerhouse construction scope of responsibility, to
directly purchase the required equipment for installation
by the contractor (installation only), or to procure design,
fabrication, and installation of equipment (“turn-key”) is
dependent upon a number of factors. These factors
include equipment procurement lead times, the complexity
of the fabricated equipment, and the need for specialized
installation skills. Generally, supply contracts are used to
procure equipment with long lead times, equipment with a
high degree of complexity, or equipment requiring
specialized installation skills and techniques. Typical
equipment procured with supply contracts includes generators (turn-key procurement), SCADA systems, highvoltage bus and breakers, generation step-up transformers,
and generator- and high-voltage power circuit breakers.
Low-voltage switchgear, motor control centers, lighting
panels, and cable tray systems are typical of equipment
included in a construction scope of supply.
c. Specification preparation. General criteria and
policies to be observed in preparing specifications are
found in Appendix A of Guide Specification CE-4000.
Specifications and plans should be carefully coordinated,
and various sections in a given specification (sometimes
prepared by different writers) checked to ensure consistency, eliminate conflicts, clearly define limits of payment
items, and avoid overlapping payments for any item.
Specifications are prepared to accommodate three classes
of users of the specifications: the construction and/or
manufacturing contractor, the resident engineer, and the
field or shop inspector. Specifications for Corps of Engineers civil works projects differ from private sector
practices because the specifications and plans must be
self-explanatory without amplification about details of the
construction or equipment fabrication. Typically, private
sector specifications depend on interpretations of the
engineering organization designing the project. Private
sector specifications are unsuited to the Corps of Engineers’ competitive open bidding methods of awarding
contracts and performing the work.
19-2. Construction Drawings
a. General. Construction drawings should be complete and based on commercially available equipment and
industry-recognized construction and installation techniques. Details of equipment design and installation,
wiring, and conduit should be complete to minimize the
need for field revision. Discussions in the following
paragraphs indicate the type and scope of information that
should be included on construction drawings for the various phases of work covered by this chapter.
b. Generators.
(1) Selected or modified drawings from the general
arrangement drawings of the powerhouse are generally
used to accompany the specifications for purchase of
generators. Drawings prepared to accompany guide specifications should indicate various mechanical and electrical
interfaces including main leads, piping terminations (e.g.,
lube oil, cooling water, CO2, brake air), neutral equipment
locations, and excitation system equipment locations.
(2) A plant or main unit one-line diagram should
also be included in the procurement drawing set. Equipment centerline should be dimensioned from structure
lines. Powerhouse crane hook coverage should be shown
on the appropriate procurement drawing set. Other governing or limiting dimensions should be established.
Locations and dimensions of openings, sleeves, and interfering equipment should be shown where possible. In
cases where dimensions cannot be determined until later,
the dimension lines should be drawn in and indication
made that the dimension will be added at a later date.
Generator procurement drawings may be included in the
construction contract set to show the extent of generator
erection performed by the generator supplier.
c. Transformers.
(1) Suitable drawings showing the location and
general arrangement of the transformers and connecting
bus structures and limits of work under the contract
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should be included with the transformer procurement
(2) The drawings should include all features not
adequately covered in the specifications affecting the
design of the transformers or powerhouse, such as limiting transformer dimensions, rails and other provisions for
lifting and moving the transformers, locations of terminal
cabinets, surge arresters, chilling sumps and walls
between transformers, bushing enclosures for connection
to metal-enclosed bus, and location of heat exchangers.
Other details include size of oil pipes for Class FOW
transformers where the heat exchangers will be installed
remotely from the transformers, types and sizes of bushing terminal connectors, and provisions for grounding the
neutrals of the high-voltage windings and the transformer
d. High-voltage system. Construction drawings for
this system should show all necessary layouts and details
for installation of equipment from the high-voltage bushings of the transformers to the outgoing transmission line
interface in the switchyard. These plans should include
drawings of the high-voltage leads with details of termination points; switchyard equipment arrangement drawings,
including plans, sections, elevations, and details; structure
loading diagrams; conduit and grounding plans; and
details of lighting and power panels and other miscellaneous equipment. A one-line diagram of the high-voltage
system should be prepared, together with control schematics of controlled equipment. Manufacturers’ shop drawings are used to a great extent in the actual installation of
e. Generator-voltage system. Drawings for the generator-voltage system should show sufficient details for
purchase of the generator main and neutral leads and
associated equipment, and the generator switchgear if
included in the supply scope. The drawings should show
the general layout, details of arrangement and ratings of
equipment, limiting dimensions, termination methods, and
a one-line diagram showing items of equipment. If the
supply scope includes generator switchgear, control schematics of the controlled equipment should be provided.
These drawings are also included with the drawings for
the construction contract to show the extent of the installation work. Manufacturers’ detail drawings are used for
installation of this equipment.
f. Station service systems.
(1) General. Construction drawings for the station
service system should consist of the station service
one-line diagram and drawings used for purchase of the
switchgear and motor control centers, if supply of this
equipment is not included in the construction scope of
(2) Station service switchgear.
(a) The station service switchgear drawings should
show all information necessary for design of the switchgear and, insofar as possible, the information needed for
(b) The switchgear drawings should indicate the
frame size and ampere rating of each breaker, as well as
the nameplate designation of each circuit. Wire sizes of
outgoing feeders should be provided for correct sizing of
circuit breaker lugs. The number and rating of current
and potential transformers should be indicated. The preferred layout of indicating and control equipment should
be shown.
(c) A one-line diagram should be prepared of the
switchgear line-up. Centerline dimensions and preferred
routing of any bus included in the switchgear scope of
supply should be provided.
(d) Drawings showing the switchgear installation
should be prepared with sufficient arrangement flexibility
to accommodate variations in dimensions among equipment suppliers. Drawings prepared for the purchase of
the switchgear are also included in the contract construction drawings to indicate the scope and complexity of
installation and connection. Manufacturers’ shop drawings are used for installation of the switchgear.
(3) Motor control centers.
(a) Drawings for motor control centers are similar in
scope to the drawings of the switchgear. Motor control
centers consist of free-standing cubicles containing combinations of standardized factory subassemblies. The standardized units described in Chapter 7 are preferred.
(b) Outside dimensions of embedded cabinets and
locations of conduits for supply and branch circuits should
be shown. Motor control center elevations indicating
preferred location of starters, control switches, and nameplates should be shown. A one-line diagram with the
relative positions of equipment enclosed within the control
center, direction of bus runs, the location of bus lugs, and
the ratings of all equipment should be provided.
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(c) The drawings should contain tabulations of the
circuit number, the nameplate designation of the circuit,
the expected load, the breaker frame size, the starter size,
and the number and size of conductors.
(4) Lighting and power panelboards.
(a) The purchase and installation of lighting and
power panels are included in the powerhouse construction
contract. Drawings are prepared showing the size of the
embedded cabinets, the size of the front covers, bus diagrams, and any pertinent details such as space allocation
and wiring diagrams for throw-over switches or remote
control switches located in the panels. Tabulations of
main bus current ratings, main breaker ratings, location
and sizes of main and neutral lugs, and the number and
ratings of branch-circuit breakers should be included on
the drawings.
(b) Lighting plan circuit designations should be provided on the panel bus diagrams. Panel layouts should
provide space for spare and future circuit breakers.
(c) Doors, locks, and details of door openings should
be shown. Front covers should overlap the embedded
cabinet approximately 1 in. all around. All contactors
should be completely separated by barriers from other
equipment and from wire gutters.
(d) Buses should also be completely enclosed except
at the ends of runs. The necessity for the removable
cover over the bus lugs should be considered in locating
equipment within the cabinet.
g. Control system. Drawings issued for purchase of
switchboards, control panels, and the operator’s control
console (if required), comprising the plant control system,
should include plant and unit one-line diagrams, plant and
unit control and protective relay schematics, station service control and protective relay schematics, and associated equipment. Other drawings that should be in the
drawing package include switchboard and control console
arrangements showing preferred locations of relays,
instruments, and control switches. Preparation of wiring
diagrams for this equipment should be included in the
manufacturer’s scope of supply, together with the preparation of terminal connection diagrams to which external
plant interconnection details can be added during the shop
drawing review process. If a plant energy management
system (SCADA) is incorporated in the control system
procurement, block diagrams of the system should be
incorporated with the procurement drawing set. Control
system drawings are also incorporated in the construction
drawing set for information as to the extent of the installation work. Actual installation of the control system
should be performed in accordance with the manufacturer’s approved drawings. Included in the construction
set should be drawings providing locating dimensions for
control system equipment.
h. Annunciation system. Generally, annunciators are
included in the scope of supply for the control switchboards. A drawing of the incoming trouble and alarm
points to the annunciators, together with preferred window
arrangements and window legends, should be provided.
Incoming trouble, alarm, and event points to the plant
sequence-of-event recorder (SER), together with a preferred format for printout of recorded events, should be
provided on the drawings.
i. Communications system. Drawings that define the
scope of facilities that will permit the installation of communication termination equipment should be included in
the construction drawing set. The construction contractor
will provide the facilities. The communication termination equipment will be furnished and installed by others
(see Chapter 10). In addition, a drawing with locations of
the plant’s code call system should be prepared.
j. Direct current system. The drawing for the purchase of the battery switchboard is similar in scope to
those for the equipment discussed in paragraph 19-2g.
The battery switchboard is generally purchased with the
control switchboard. The battery switchboard drawing is
included with the construction contract drawings to depict
the extent of the work and provide explanatory material.
k. Lighting and receptacle systems.
(1) Lighting drawings on the lighting plan for an
area should show all fixture, switch, and receptacle outlets, and all conduits in the walls and ceiling.
(2) Conduits in the ceiling and walls of an area are
shown on a floor plan of that area. Conduit in the floor
slab for the same area, even though used to feed outlets in
the area, should be shown on another plan as in the ceiling for the area below.
(3) Building and room outlines, beams, and openings, should be shown. Rooms should be identified.
Normally, it is not necessary to show equipment on lighting drawings. Sections and details should be shown
where necessary for clarification. Wiring diagrams and
equipment should be detailed in accordance with the
drawing legend. All outlets, junction boxes, and conduit
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terminations should be located by dimensions and, if
necessary, by elevations.
(4) The conduit system should be detailed completely
and all sizes and materials noted. Embedded conduit for
branch circuits should be limited to ¾- and 1-in. sizes if
possible. Conduits serving ceiling fixtures in areas with
suspended ceilings should be stubbed out of the concrete.
The conduit will be extended to fixture outlet boxes
before placing the ceiling suspension system.
(5) Boxes, extension rings, and covers should be
suited to the finish of the space in which they are used
with appropriate notations or details made on the drawings to ensure the use of the proper materials and fittings.
Wall outlet boxes should be sheet metal boxes with suitable extension rings when located above the generator
room floor. On turbine room walls, boxes should be cast
boxes meeting the requirements of UL 514A.
(6) Complete details should be given for lighting fixture mountings, wiring devices, and device plates. Circuits
should be designated by lighting panel number and circuit
number and balanced across the lighting panel buses and
transformer. The number and sizes of wires in each conduit are indicated by standard hash marks and notes. The
system should be color-coded as noted on the typical
(7) To avoid confusion, local switches and their controlled fixtures should have an individual letter designation to indicate their relation.
Fixture, switch, and
receptacle types should be designated on the drawings and
referred to a schedule giving the fixture type by reference
to a catalog product or to a detail drawing. The schedule
should also show all mounting fittings.
l. Grounding systems. Grounding system drawings
should include all plans, information, and details necessary for the installation of the power plant ground mat,
the main powerhouse grounding network, and taps and
connections to equipment. The taps from the main
ground network to equipment may be shown conveniently
on the power and control conduit plans. Details should
include test stations if used, water seals, exposed ground
bus supports, and typical connections to the frame or
housing of plant equipment and metal structures.
m. Conduit and cable tray systems.
(1) Conduit plans for station service power and for all
control circuits, including the communication system,
should show the conduits in the floor and walls of the
designated area. Obstructions, structural features, and
locations of equipment influencing conduit location should
be shown on the drawings.
(2) Conduits should be in accordance with the legend. Each conduit should be labeled with the size and
conduit number shown in the conduit and cable schedule.
Conduit termination locations should be dimensioned to
building control lines wherever possible.
(3) All outlet boxes and cabinets should be shown
on the drawings with size, location, and, if applicable,
designation numbers given. Any required boxes should
be located and detailed.
(4) Where a number of conduits stub out of a wall
or floor within a small area, a structural steel terminal
plate should be detailed for use in holding the conduits
rigidly in place during concrete placement operations. If
conduit locations are not known when the drawings are
prepared, indication should be made that dimensions will
be furnished at a later date.
(5) Sufficient elevations and details of conduits
entering junction boxes, pull boxes, or cabinets should be
provided showing the complexity of the work and the
quality and size of allowable electrical construction materials. Where stubs are left in concrete walls or ceilings
for exposed runs to equipment, the conduit should be
stubbed flush with a coupling and closed with a pipe plug.
(6) One or two spare conduits should be run from
each motor control center or lighting panel wall location
to 6 in. below the ceiling of the room in which the installation is located and terminated in a flush coupling. One
or more spare conduits should be similarly terminated in
the room below the installation.
(7) Pull boxes, embedded power cabinets, and junction boxes should be completely detailed to show size,
material, flange width, front covers, and conduit drilling.
For cast iron boxes, a standard catalog product with
drilled and tapped conduit entrances is specified.
(8) Drawings should show the arrangement and
location of the complete tray system. Details of tray
hangers, supports and splices, and supporting blocks for
cables entering or leaving the trays, should be shown on
the drawings. The trays should be suitably identified for
listing in cable schedule references. Construction details
of all fabricated components should be provided on the
drawing. Component totals should be included on a bill
of materials.
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n. Wire and cable. The cable and conduit schedule
should be prepared as outlined in Chapter 15. It is convenient to list the multiconductor control cables separately
from power cables. Computer-generated spreadsheets are
generally used for listing all power plant power, control,
and communications cables. The locations of wire and
cable in trays should be shown on tray diagrams. These
diagrams will expedite construction and provide “as constructed” engineering documentation useful for plant
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Chapter 20
Analysis of Design
20-1. Permanent Record
The “Analysis of Design” memorandum should be a
permanent record for future reference. It should consolidate into one document engineering information and
computations from previously approved design memorandums pertinent to the executed plans and specifications.
20-2. Up-To-Date Values
Original computations based on assumed values for
machine or equipment characteristics are revised to reflect
up-to-date values based either on the manufacturers’
design calculations or on field or factory test
20-3. Expansion
If provisions are made in the powerhouse or switchyard
design for future addition of units, transmission lines, or
auxiliary equipment, the Analysis of Design memorandum
should detail the provisions for the expansion.
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Appendix A
ANSI C2-1993
National Electrical Safety Code
ANSI C37.06-1987
American National Standard for Switchgear - AC HighVoltage Circuit Breakers Rated on a Symmetrical Current
Basis - Preferred Ratings and Related Required
Required Publications
TM 5-810-1
Mechanical Design, HVAC
ER 1105-2-100
Guidance for Conducting Civil Works Planning Studies
ER 1110-2-103
Strong Motion Instrument for Recording Earthquake
Motions on Dams
EM 1110-2-3001
Planning and Design of Hydroelectric Power Plant
EM 1110-2-4205
Hydroelectric Power Plant Mechanical Design
CE 4000
Civil Works Guide Specification for Lump Sum Contract
for Engineering Services for Design of Hydroelectric
Power Plant
Civil Works Guide Specification for Supervisory Control
and Data Acquisition Equipment
ANSI C37.16-1980
American National Standard Preferred Ratings, Related
Requirements, and Application Recommendations for
Low-Voltage Power Circuit Breakers and AC Power
Circuit Protectors
ANSI C37.90.1-1989
IEEE Standard Surge Withstand Capability (SWC) Test
for Protective Relays and Relay Systems (ANSI)
ANSI C80.1-1983
Rigid Steel Conduit-Zinc Coated
ANSI C84.1-1989
American National Standard Voltage Ratings for Electric
Power Systems and Equipment (60 Hz)
ANSI/IEEE 242-1986
IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems
ANSI/ISA S18.1-1981
Annunciator Sequence and Specifications
Civil Works Guide Specification for Insulated Wire and
EPRI EL-5036
Power Plant Electrical Reference Series, Vol. 2, “Power
Civil Works Guide Specification for Rewind of
Hydraulic-Turbine-Driven Alternating Current Generators
EPRI EL-5036
Power Plant Electrical Reference Series, Vol. 4, “Wire
and Cable”
Civil Works Guide Specification for Governors for
Hydraulic Turbines and Pump Turbines
EPRI EL-5036
Power Plant Electrical Reference Series, Vol. 5, “Grounding and Lightning Protection”
Civil Works Guide Specification for Power Transformers
EPRI EL-5036
Power Plant Electrical
“DC Distribution”
AIEE Transactions on Power Apparatus and Systems,
1953 (Oct)
Characteristics of Split-Phase Currents as a Source of
Generator Protection, Paper 53-314.
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EPRI EL-5036
Power Plant Electrical Reference Series, Vol. 10, “Electrical and Instrumentation”
EPRI EL-5036
Power Plant Electrical Reference Series, Vol. 13,
EPRI TR-101710, 1993
EPRI Lighting Fundamentals Handbook
IEEE Transactions on Power Apparatus and Systems,
IEEE Transactions on Power Apparatus and Systems,
1983, Vol PAS-102, No. 9 (September).
IEEE Transactions on Power Apparatus and Systems,
IEEE Transactions on Power Apparatus and Systems,
1983, Vol PAS-102, No. 10 (October).
IEEE 484-1987
IEEE Recommended Practice for Installation Design and
Installation of Large Lead Storage Batteries for Generating Stations and Substations (ANSI)
IEEE 485-1983
IEEE Recommended Practice for Sizing of Large Lead
Storage Batteries for Generating Stations and Substations
IEEE 605-1987
IEEE Guide for
Structures (ANSI)
IEEE 946-1992
IEEE Recommended Practice for the Design of DC Auxiliary Power Systems for Generating Stations
IEEE 979-1984 (Reaffirmed 1988)
IEEE Guide for Substation Fire Protection (ANSI)
IEEE 43-1974
IEEE Recommended Practice for Testing Insulation Resistance of Rotating Machinery (ANSI)
IEEE 980-1987
IEEE Guide for Containment and Control of Oil Spills in
Substations (ANSI)
IEEE 80-1986
IEEE Guide for Safety in AC Substation Grounding
IEEE 1010-1987
IEEE Guide for Control of Hydroelectric Power Plants
IEEE 81-1983
IEEE Guide for Measuring Earth Resistivity, Ground
Impedance, and Earth Surface Potentials of a Ground
IEEE C37.013-1988
IEEE Standard for AC High-Voltage Generator Circuit
Breakers Rated on a Symmetrical Current Basis (ANSI)
IEEE 115-1983
IEEE Test Procedures for Synchronous Machines (ANSI)
IEEE 142-1991
IEEE Recommended Practice for Grounding of Industrial
and Commercial Power Systems (ANSI)
IEEE 399-1990
IEEE Recommended Practice for Power Systems Analysis
IEEE 422-1986
IEEE Guide for Design and Installation of Cable Systems
in Power Generating Stations (ANSI)
IEEE 450-1987
IEEE Recommended Practice for Maintenance, Testing,
and Replacement of Large Lead Storage Batteries for
Generating Stations and Substations (ANSI)
IEEE C37.122 (with Supplement .122a)-1983
IEEE Standard for Gas Insulated Substations (ANSI)
IEEE C37.123-1991
IEEE Guide to Specification for Gas-Insulated Substation
Equipment (ANSI)
IEEE C37.2
Electrical Power System Device Function Numbers
IEEE C37.20.2-1987
IEEE Standard for Metal-Clad and Station-Type Cubicle
Switchgear (ANSI)
IEEE C37.23-1987
IEEE Standard for Metal-Enclosed Bus and Calculating
Losses in Isolated-Phase Bus (ANSI)
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IEEE C37.91-1985 (Reaffirmed 1990)
IEEE Guide for Protective Relay Applications to Power
Transformers (ANSI)
IEEE C57.104-1991
IEEE Guide for the Interpretation of Gases Generated in
Oil-Immersed Transformers
IEEE C37.95-1989
Guide for Protective Relaying of Utility Customer Interconnections (ANSI)
IEEE C57.116-1989
IEEE Guide for Transformers Directly Connected to Generators (ANSI)
IEEE C37.96-1988
IEEE Guide for AC Motor Protection (ANSI)
IEEE C57.120-1991
IEEE Standard Loss Evaluation Guide for Power Transformers and Reactors (ANSI)
IEEE C37.97-1979 (Reaffirmed 1990)
IEEE Guide for Protective Relay Applications to Power
Systems Buses (ANSI)
IEEE C37.101-1985 (Reaffirmed 1990)
IEEE Guide for Generator Ground Protection (ANSI)
IEEE C37.102-1987 (Reaffirmed 1991)
IEEE Guide for AC Generator Protection
IEEE C62.1-1989
IEEE Standard for Gapped Silicon-Carbide
Arresters for AC Power Circuits (ANSI)
IEEE C62.11-1987
IEEE Standard for Metal-Oxide Surge Arresters for
AC Power Circuits (ANSI)
IEEE C37.106-1987
IEEE Guide for Abnormal Frequency Protection for
Power Generating Plants (ANSI)
IEEE C62.2-1987
IEEE Guide for the Application of Gapped SiliconCarbide Surge Arresters for Alternating Current Systems
IEEE C57.12.00-1987
IEEE Standard General Requirements for LiquidImmersed Distribution, Power, and Regulating Transformers (ANSI)
IEEE C62.92.2-1989
IEEE Guide for Grounding in Electrical Utility Systems,
Part II - Grounding of Synchronous Generator Systems
IEEE C57.12.11-1980
IEEE Guide for Installation of Oil-Immersed Transformers (10MVA and Larger, 69 kV - 287 kV Rating)
VDT Lighting
IEEE C57.12.14-1982
IEEE Trial Use Standard for Dielectric Test Requirement
for Power Transformers for Operation at System Voltage
from 115 kV through 230 kV
IEEE C57.12.90-1987
IEEE Standard Test Code for Liquid-Immersed Distribution. Power, and Regulating Transformers; and Guide for
Short-Circuit Testing of Distribution and Power Transformers (ANSI)
NEMA PE 1-1983
Uninterruptible Power Systems
NEMA PE 5-1985
Utility Type Battery Chargers
NEMA PE 7-1985
Communication Type Battery Chargers
NEMA WC 50-1976
Ampacities, Including Effect of Shield Losses for SingleConductor Solid-Dielectric Power Cable 15 kV through
69 kV
IEEE C57.19.01-1991
IEEE Standard Performance Characteristics and Dimensions for Outdoor Apparatus Bushings (ANSI)
NEMA WC 51-1986
Ampacities of Cables in Open-Top Cable Trays
IEEE C57.98-1986
IEEE Guide for Transformer Impulse Tests (ANSI)
NFPA 70-1993
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American National Standard Schedules of Preferred Ratings, Manufacturing Specifications and Application Guide
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EM 1110-2-3006
30 Jun 94
Appendix B
Power Transformer Studies and
(3) Transformer data:
B-1. Recommended Studies
a. The following studies should be performed during
the preliminary design phase for generator step-up power
46,000 kVA
13.2 kV/115 kV
FOA type cooling
B-3. Sample Study B1, BIL / Surge Arrester
(1) Transformer kVA Rating Study.
The objective of this study is to determine the following:
(2) Transformer Cooling Study.
(3) Basic Impulse Insulation Level (BIL) / Surge
Arrester Coordination Study.
(1) Transformer high-voltage basic impulse insulation
levels (BIL’s).
(2) Transformer impulse curves.
(4) Transformer Bushings Rating Study.
(3) Surge arrester type and sizing.
(5) Transformer Efficiency Study.
(4) Surge arrester impulse curves.
(6) Transformer Loss Evaluation Study.
(7) System Fault Study for Transformer Impedance
(5) Transformer high-voltage BIL / surge arrester
b. This appendix outlines samples of these studies
and calculations as listed above. Sample studies for items
(a) and (b) are not included due to their lesser degree of
complexity and site-specific nature (a discussion concerning transformer ratings and cooling considerations is
included in Chapter 4). A system fault study should be
performed prior to determining transformer impedances.
A sample system fault study is not included in this appendix due to its expanded scope and site-specific nature.
The following references were used in the performance of
this study. Complete citations can be found in Appendix A of this document, “References.”
(1) ANSI C62.1-1984.
(2) ANSI C62.2-1987.
(3) ANSI C62.11-1987.
B-2. Data Used for Sample Studies
(4) ANSI/IEEE C57.12.00-1987.
a. The sample studies shall be based upon the following assumed data:
(1) Transmission line data:
- 230 kVL-L
- 750 kV BIL rating
(2) Generator data:
- 69,000 kVA
- 110 kV winding BIL
(5) ANSI/IEEE C57.12.14-1982.
(6) ANSI/IEEE C57.12.90-1987.
(7) ANSI/IEEE C57.98-1986.
c. Procedure. The proposed transformer replacement will be two winding, single-phase, 60-Hz, FOA
cooled units, 65 °C rise, connected delta/wye, with the
following ratings:
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30 Jun 94
Transformer bank: Three-1φ, 46,000 kVA,
13.2 kV/230 kV.
These transformers are considered to be a “replacementin-kind.”
(1) Transformer high-voltage basic impulse insulation
levels (BIL’s).
(a) Line BIL characteristics. The Power Marketing
Authority’s (PMA’s) transmission line, transformer highvoltage insulation, high-voltage bushing BIL characteristics, and surge arrester duty-cycle ratings are as follows:
Chopped-wave withstand voltage levels for different transformer high-voltage BIL ratings are listed in Table 5 of
ANSI/IEEE C57.12.00.
These levels correspond to
1.1 × BIL, and the time-to-chop occurs at 3.0 µs.
Table B-2
CWW Withstand Voltage
Line Voltage,
BIL Rating,
CWW Strength,
230-kV System:
(c) Full-wave (BIL) withstand voltage.
Transmission line: approximately 750 kV BIL
• Transformer high-voltage insulation:
650 kV BIL
(d) Switching impulse level (BSL) withstand voltage.
High-voltage bushings: typically 750 kV BIL
• Surge arrester rating: typically 180 kV duty-cycle
(b) This study will analyze transformer high-voltage
BIL levels of 650 kV, 750 kV, and 825 kV, for the 230-kV
transmission line, and determine the correct level of
(2) Transformer impulse curves.
(a) Front-Of-Wave (FOW) withstand voltage.
As indicated by ANSI C62.2, the FOW strength range
should be between 1.3 and 1.5 times the BIL rating, with
time-to-chop occurring at 0.5 µs. For the purposes of this
coordination study, an FOW strength of 1.4 times BIL
shall be used.
Table B-1
FOW Withstand Voltage
Line Voltage,
BIL Rating,
FOW Strength,
(b) Chopped-wave (CWW) withstand voltage.
The full-wave withstand voltage is equivalent to the highvoltage BIL rating of the transformer. This withstand
voltage occurs as a straight line from 8 to 50 µsec.
Switching impulse withstand voltage levels for different
transformer high-voltage BIL ratings are listed in Table 5
of ANSI/IEEE C57.12.00. These levels correspond to
0.83 × BIL, and extend from 50 to 2,000 µsec.
Table B-3
BSL Withstand Voltage
Line Voltage,
BIL Rating,
BSL Strength,
(e) Applied voltage test level.
Applied voltage test levels for different transformer highvoltage BIL ratings are listed in Table 5 of ANSI/IEEE
Table B-4
APP Voltage
Line Voltage,
BIL Rating,
APP Strength,
EM 1110-2-3006
30 Jun 94
(f) Transformer impulse curve generation. The transformer impulse curve is generated as indicated in Figure 3
of ANSI C62.2. As discussed in Figure 3:
It is not possible to interpolate exactly between
points on the curve. Good experience has been
obtained with the assumptions implicit in the preceding rules: (a) The full BIL strength will apply
for front times between 8 and 50 µs. (b) Minimum
switching surge withstand occurs between 50 and
2,000 µs. Refer to the attached plot of the transformer impulse curves located at the end of this
(3) Surge arrester type and sizing.
(a) General. The objective for surge protection of a
power system is to achieve at a minimum cost an acceptably low level of service interruptions and an acceptably
low level of transformer failures due to surge-related
(b) Arrester type. Surge arresters utilizing metaloxide (such as zinc-oxide) valve (MOV) elements will be
used due to the extreme improvement in nonlinearity as
compared to arresters with silicon-carbide valve elements.
This nonlinear characteristic of the voltage-current curve
provides better transformer protection and improves the
arrester’s thermal stability.
(c) Arrester class. Station class arresters shall be
utilized, based on system line voltage of 230 kV.
(d) Arrester sizing. It is desirable to select the minimum-sized arrester that will adequately protect the transformer insulation from damaging overvoltages, while not
self-destructing under any reasonably possible series of
events at the location in the system. Since the metaloxide valve in MOV arresters carries all or a substantial
portion of total arrester continuous operating voltage, the
most important criterion for selection of the minimum
arrester size is the continuous operating voltage. Selection of a size for an arrester to be installed on grounded
neutral systems is based upon:
• The maximum continuous operating voltage
(MCOV), line-to-neutral, at the arrester location computed
as the maximum system voltages divided by root-three.
• The assumption that the system is effectively
grounded where a fault is expected to initiate circuit
breaker operation within a few cycles.
Minimum arrester sizing for system line
voltage. Based upon ANSI C57.12.00, the relationship of
nominal system voltage to maximum system voltage is as
Nominal System Voltage
Maximum System Voltage
230 kV
242 kV
(4) The minimum arrester sizing in MCOV for the
system line voltage shall, therefore, be as follows:
• Arrester MCOV rating = 242 kV / √3 =
139.7 kV1-n
• This calculated arrester rating of 139.7 kV1-n
MCOV for the 230-kV line voltage corresponds to a standard arrester voltage rating of 140 kV1-n MCOV and a
duty-cycle voltage of 172 kV1-n, as outlined in Table 1 of
ANSI C62.11.
(5) Line voltages at the powerhouse are commonly
operated between the nominal and maximum system voltages. Based on this, the surge arrester should be sized
somewhat higher than the maximum system line-to-neutral
voltage rating of the line to avoid overheating of the
arrester during normal operating conditions. The arrester
rating chosen shall be one MCOV step higher than the
recommended MCOV for grounded neutral circuits. The
following arrester MCOV values have been chosen:
• Arrester MCOV rating = 144 kV
• Arrester duty-cycle rating = 180 kV
B-4. Surge Arrester Impulse Curves
For the purposes of this coordination study, surge arrester
voltage withstand levels shall be assumed to correspond to
typical manufacturer’s data. These voltage withstand
voltage levels shall be used for the generation of the
arrester curves and the coordination study. Gapped design
MOV surge arresters are typically used for distribution
class transformers. The gapless design surge arrester shall
be addressed in this study, since it represents a typical
MOV type arrester suitable for these applications.
a. Maximum 0.5 µs discharge voltage (FOW). The
discharge voltage for an impulse current wave which produces a voltage wave cresting in 0.5 µs is correlative to
the front-of-wave sparkover point. The discharge currents
used for station class arresters are 10 kA for arrester
EM 1110-2-3006
30 Jun 94
MCOV from 2.6 through 245 kV. As taken from the
manufacturer’s protective characteristics,
230 kV line voltage (144 kV arrester MCOV)
Maximum 0.5 µs discharge voltage = 458 kV
b. Maximum 8 × 20 µs current discharge voltage
Discharge voltages resulting when ANSI
8 × 20 µs current impulses are discharged through the
arrester are listed in the manufacturer’s data from 1.5 kA
through 40 kA.
For coordination of the 8 × 20 µs
current-wave discharge voltage with full-wave transformer
withstand voltage, a value of coordination current must be
selected. To accurately determine the maximum discharge currents, the PMA was contacted and the following
line fault currents were obtained:
Transmission Line (230 kV):
3φ fault................17010 Amperes
line-ground fault..15910 Amperes
c. Maximum switching surge protective level (SSP).
The fast switching surge (45 × 90 µs) discharge voltage
defines the arresters’ switching surge protective level. As
taken from the manufacturer’s protective characteristics,
d. 60-Hz temporary overvoltage capability. Surge
arresters may infrequently be required to withstand a
60-Hz voltage in excess of MCOV. The most common
cause is a voltage rise on unfaulted phases during a lineto-ground fault. For the arrester being addressed for the
purposes of this coordination, the arrester could be energized at 1.37 × MCOV for a period of 1 min.
230-kV line voltage (144-kV arrester MCOV)
60-Hz temporary overvoltage capability:
144 kV × 1.37 = 197.3 kV
B-5. Transformer High-Voltage BIL/Surge
Arrester Coordination
a. Coordination between MOV arresters and transformer insulation is checked by comparing the following
points of transformer withstand and arrester protective
levels on the impulse curve plot:
MOV Arrester Protective
Transformer Withstand
Maximum 0.5 µs discharge
voltage - “FOW”
Chopped-wave withstand “CWW”
Maximum 8 × 20 µs current
discharge voltage - “LPL”
Full-wave withstand “BIL”
Maximum switching surge
45 × 90 µs discharge
voltage - “SSP”
Switching surge withstand “BSL”
b. At each of the above three points on the transformer withstand curve, a protective margin with respect
to the surge arrester protective curves is calculated as:
% PM
 (Transformer Withstand)
 (Protective Level)
1 × 100
c. The protective margin limits for coordination, as
specified in ANSI C62.2, are as follows:
(1) % PM (CWW/FOW) ≥ 20
(2) % PM (BIL/LPL) ≥ 20
230 kV line voltage (144 kV arrester MCOV)
Maximum switching surge protective level
classifying 1,000 ampere current level = 339 kV.
Table B-5
Surge Arrester Coordination
(3) % PM (BSL/SSP) ≥ 15
d. The protective margins for the MOV arresters
selected yield protective margins of:
(1) Transformer BIL = 650 kV.
(a) % PM (CWW/FOW) = (715 kV/458 kV - 1)
× 100 = 56%
(b) % PM (BIL/LPL) = (650 kV/455 kV - 1) × 100 =
(c) % PM (BSL/SSP) = (540 kV/339 kV - 1) × 100 =
(2) Transformer BIL = 750 kV.
(a) % PM (CWW/FOW) = (825 kV/458 kV - 1)
× 100 = 80%
(b) % PM (BIL/LPL) = (750 kV/455 kV - 1) × 100 =
EM 1110-2-3006
30 Jun 94
(c) % PM (BSL/SSP) = (620 kV/339 kV - 1) × 100 =
(3) Transformer BIL = 825 kV.
(a) % PM (CWW/FOW) = (905 kV/458 kV - 1)
× 100 = 98%
(b) % PM (BIL/LPL) = (825 kV/455 kV - 1) × 100 =
(c) % PM (BSL/SSP) = (685 kV/339 kV - 1) × 100 =
(5) Main Unit Generator Step-up Transformer
Replacement, BIL / Surge Arrester Coordination Study.
c. Procedure. As summarized in the referenced
studies, the transformers shall be rated as follows:
46,000 kVA
13.2 kV /230 kV Y
750 kV High-Voltage Winding BIL
110 kV Low-Voltage Winding BIL
d. Bushing ratings and characteristics. As outlined
in IEEE Std. 21-1976, performance characteristics based
upon definite conditions shall include the following:
• Rated maximum line-to-ground voltage
(1) As noted from the transformer BIL / surge
arrester coordination plots (Figure B-1), the minimum
protective margins are much greater than the design
standards, due to the better protective characteristics of
MOV surge arresters.
• Rated frequency
• Rated dielectric strengths
• Rated continuous currents
(2) A high-voltage winding BIL rating of 750 kV BIL
for the 230-kV nominal system voltage shall be selected
for the transformers. These BIL selections will provide
the following advantages: (a) reduction in transformer
procurement costs, (b) reduction in transformer losses,
(c) better coordination with the BIL rating structure of the
system, and (d) reduction in the physical size of the transformer. Item (d) is due consideration because of vault
size limitations.
B-6. Sample Study B2, Transformer Bushings
a. Objective. The objective of this study is to determine the proper ratings for the bushings and bushing
current transformers on the replacement generator step-up
(GSU) transformers.
b. References. The following references were used
in the performance of this study. Complete citations can
be found in Appendix A of this document, “References.”
(1) ANSI C76.1-1976 / IEEE Std. 21-1976.
(2) ANSI C76.2-1977 / IEEE Std. 24-1977.
(3) ANSI C57.13-1978.
The bushings will not be subject to any unusual service
(1) Rated maximum line-to-ground voltage.
(a) Based upon ANSI C57.12.00, the relationship of
nominal system voltage to maximum system voltage is as
Nominal System Voltage
230 kV
Maximum System Voltage
242 kV
(b) The maximum line-to-ground voltage is therefore:
Maximum System Voltage
242 kV
Line-To-Ground Voltage
139.7 kV
(c) Line voltages are commonly operated between
the nominal and maximum system voltages. Based on
this, the selection of maximum line-to-ground voltages
will be chosen as 5 percent higher than the ANSI suggested values to avoid overheating of the bushings during
normal operating conditions. This leads to bushing selections with the following Rated Maximum Line-To-Ground
Voltage, Insulation Class, and BIL characteristics:
(4) Main Unit Generator Step-up Transformer
Replacement, Transformer kVA Rating Study.
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Line Voltage: 230 kV
Bushing Insulation Class: 196 kV
Bushing BIL: 900 kV
Rated Maximum Line-to-Ground Voltage: 146 kV
(d) The low-voltage terminal bushings shall be insulated at the same BIL as the generator windings, i.e.,
110 kV BIL. This corresponds to an insulation class of
15 kV.
• Chopped Wave Impulse - kV Crest, 2µsec
Withstand: 142 kV
• Chopped Wave Impulse - kV Crest, 3µsec
Withstand: 126 kV
(c) Neutral bushings.
• 60 Hz, 1-min Dry Voltage Withstand Test:
60 kV rms
• 60 Hz, 10-sec Wet Voltage Withstand Test:
50 kV rms
(e) The neutral terminal bushings shall be insulated at
150 kV BIL, corresponding to an insulation class of
25 kV.
• Full Wave Impulse Voltage Withstand Test:
150 kV
(2) Rated frequency. The frequency at which the
bushings shall be designed to operate is 60 Hz.
• Chopped Wave Impulse - kV Crest, 2µsec
Withstand: 194 kV
(3) Rated dielectric strengths. The rated dielectric
strengths for the transformer bushings, expressed in terms
of specific values of voltage withstand tests, shall be as
• Chopped Wave Impulse - kV Crest, 3µsec
Withstand: 172 kV
(a) 230 kV system high-voltage bushings.
• 60 Hz, 1-min Dry Voltage Withstand Test:
425 kV rms
• 60 Hz, 10-sec Wet Voltage Withstand Test:
350 kV rms
• Full Wave Impulse Voltage Withstand Test:
900 kV
(4) Rated continuous currents.
(a) The following are the rated currents for the transformer bank, based upon the maximum kVA generating
capacity of each generating unit:
• Two generators shall be connected to the transformer bank. The maximum kVA rating of each generator is 69,000 kVA. The total of the generator rated
currents for these units is, therefore:
• Chopped Wave Impulse - kV Crest, 2µsec
Withstand: 1160 kV
• Chopped Wave Impulse - kV Crest, 3µsec
Withstand: 1040 kV
(b) 13.2 kV low-voltage bushings.
• 60 Hz, 10-sec Wet Voltage Withstand Test:
45 kV rms
• Full Wave Impulse Voltage Withstand Test:
110 kV
(2) 69,000 kVA
3 VL
3 (13.8 kV)
5,774 Amps
• Total rated low-voltage terminal current for delta
connected transformers:
• 60 Hz, 1-min Dry Voltage Withstand Test:
50 kV rms
5,774 Amps
3,334 Amps
• Rated line current:
5,774 Amps ×
13.2 kV
230 kV
331 Amps
(b) Based on the above data, the suggested minimum
bushing rated current requirements shall be as follows:
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• High-Voltage Bushing Minimum Current Rating:
400 Amperes
(6) Determine the losses.
(7) Determine transformer estimated efficiency.
• Neutral
400 Amperes
• Low-Voltage Bushing Minimum Current Rating:
3,500 Amperes
e. Bushing current transformer (CT) ratings and
characteristics. Two standard multi-ratio bushing-type
CT’s for relaying service shall be installed in each of the
230-kV transformer high-voltage bushings for the bank,
conforming to accuracy classification ’C’, rated 400/5.
These CT’s shall be used for transformer differential
relaying and line protective relaying.
B-7. Sample Study B3, Transformer Efficiency
a. Objective. The objective of this study is to estimate the transformer efficiencies for the proposed replacement generator step-up (GSU) transformers.
b. References. The following references were used
in the performance of this study. Complete citations can
be found in Appendix A of this document, “References.”
(1) Main Unit Generator Step-up Transformer
Replacement, Transformer kVA Rating Study.
(2) Main Unit Generator Step-up Transformer
Replacement, BIL/Surge Arrester Coordination Study.
(3) Westinghouse Electric Corporation. 1964 (located
at end of study).
c. Procedure. The calculations for estimating the
transformer losses and efficiency calculations shall be
based on the Westinghouse Technical Data Bulletin
No. 48-500. The following steps will be used in determining this data:
(1) Determine the insulation level of the transformer.
(2) Determine the equivalent two winding 65 °C
reference product factors.
(3) Determine the basic product factor from the
Table A: 65 °C reference product factors.
(4) Adjust for special features.
(5) Determine the ratio of losses.
d. Transformer bank: 46,000 kVA, 1φ, 13.2 kV
/230 kV Y, FOA cooled transformers.
(1) Transformer BIL rating.
(a) Low-voltage windings: 110 kV BIL.
(b) High-voltage windings: 750 kV BIL.
(2) Equivalent two-winding 65 °C self-cooled MVA.
For FOA type cooling rated at 65 °C, the specified MVA
is for self-cooling.
(3) Basic product factor determination (Pe).
reference product factor:
(a) As taken from Table A, A = .0001590, B = .2564
(b) Conversion of the MVA(1φ) to MVA(3φ) is
required to calculate the product factor.
MVA(3φ) = 2 × MVA(1φ) = 2 × 46 MVA = 92 MVA
(c) Therefore, the base product factor (Pe) is:
.0001590 92
(4) Adjust Pe for % adders (Pr). The base product
factor calculated in (c) should be adjusted further for
special features. The adjusted base product factor, Pr, is
calculated as follows:
) × Pe
(a) From Table B, on page 12 of the Westinghouse
document, the percent additions are:
Front of Wave Impulse Test: 5%
(b) Final adjusted base product factor:
Pr = .028257 × (1+.05) = .029669
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(5) Loss ratio (R). The ratio of losses (NL kW/L
kW), applying to the reference product factors, for
transformers with the high-voltage winding BIL between
550 and 750 kV, is calculated as follows:
R = 2.75 - .182 1n MVA
R = 2.75 - .182 ln 46 = 2.053
(6) Determination of losses.
(a) The percent no-load loss is given by:
a. Objective. The objective of this study is to establish the loss evaluation and penalty factors, and determine
an auxiliary cooling loss evaluation factor, for use in the
construction specifications for the new main unit generator step-up replacement transformers.
b. References. The following reference was used in
the performance of this study. A complete citation can be
found in Appendix A of this document, “References.”
(1) “Main Unit Generator Step-Up Transformer
Replacement, Transformer Efficiency Study.”
(2) Guide
(b) No-load loss is given by:
No Load Loss
B-8. Sample Study B4, Transformer Loss
× %Fe
× .120214
.055299 MW
(1) Pertinent values for computations. The following
sample values will be used in the computations for loss
No-Load Loss = 55.30 kW
(a) Value of replacement energy: 15.94 mills/KW-hr
(c) Total loss is given by:
(b) Value of replacement capacity: $267,800/MW-yr
= $30.57/KW-yr
Total Loss = (R+1) × No-Load Loss
Total Loss = (2.053 + 1) × 55.30 kW = 168.83 kW
(d) Plant capacity factor: 54%
(d) Load loss is given by:
Load Loss = Total Loss - No-Load Loss
= 168.83 kW - 55.30 kW
Load Loss = 113.53 kW
(7) Estimated efficiency (η).
mated efficiency is given by:
The transformer esti-
× 100%
Total Losses
× 100%
(c) Alternative cost of Federal financing interest rate:
(2) Determination of rates of evaluation. The evaluation of transformer efficiency for use in determining
award of the contract should be based on the same value
per kW of loss used in determining the evaluation of
efficiency of the associated main generators. This value
of one kilowatt of loss is the capitalized value of the
annual capacity and energy losses based on the average
annual number of hours of operation. The transformer
load used for efficiency evaluation should correspond
approximately to the generator load used for evaluation of
generator efficiency. For class FOA transformers, 87 percent of rated load at 1.0 power factor shall be used.
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(a) The rate of evaluation for efficiency is calculated
as present worth, as follows:
Transformer loss is therefore
40,020 kW
39,872 kW
148 kW
R = rate of evaluation
EV = energy value
CV = capacity value
CF = capacity factor
(c) Rate of evaluation for each 1/100% of transformer efficiency. Transformer losses per 1/100% of
transformer efficiency is:
Loss per 1/100%
PWF = present worth factor
148 kW
99.63) × (100)
The rate of evaluation per 1/100 percent of efficiency is:
Rate of evaluation
R = (PWF) ((365) (24) (EV) (CF) + CV)
The present worth factor (PWF) for 35 years at 8.5% is:
( , 8.5%, 35)
(1 .085)35 1
.085(1 .085)35
(11.088YR) × ((365
× (.01594
) × (24
) × (.54)
(b) Transformer efficiency and losses. Transformer
input shall be based upon 87 percent of rated load at 1.0
power factor of the connected generators. The transformer bank has two generators connected, each rated at
69,000 kVA at 1.0 power factor. The total input to each
single-phase transformer under these conditions is
(2) × (69,000 kVA) × (1.0 pf) × (0.87)
3 transformers
40,020 kW
Transformer output shall be based upon the specified
efficiency of 99.63 percent:
4.00 kW
40,020 kW × (99.63%)
39,872 kW
) × (4.00
1/100% eff
1/100% eff
(3) Application of rates of evaluation to contract bid
and penalty for failure to meet guaranteed efficiency. The
calculated rate of evaluation per 1/100 percent of transformer efficiency shall be used during the bid evaluation
to credit the bid price for each 1/100 percent of efficiency
that the guaranteed value exceeds the specified minimum
value of 99.63 percent. After final testing of the transformer, twice the rate of evaluation shall be applied as a
penalty for each 1/100 percent of efficiency less than the
guaranteed value.
(4) Auxiliary cooling loss.
(a) Guide Specification CE-2203 states the following:
In the evaluation of Transformer Auxiliary Power,
the power required for motor-driven fans and oilcirculating pumps should be evaluated on the basis
that each horsepower of motor rating in excess of
the number of horsepower excluded from evaluation is equal in value to approximately 40 percent
of the capitalized value of one kW of loss used in
the transformer efficiency evaluation.
(b) The rate of evaluation for transformer auxiliary
power for FOA cooled transformers is given by:
Rate of evaluation
$1,175 × 40%
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(c) The total horsepower of motor-driven fans and oil
pumps excluded from evaluation for each size of transformer is given by:
Total losses based on 99.6% estimated efficiency:
46,000 kVA
46,000 kVA
184.74 kW
Total auxiliary loss in hp excluded from evaluation:
184.74 kW ×
.05 hp
9.24 hp
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