electric power plant design

TM 5-811-6

TECHNICAL MANUAL

ELECTRIC POWER PLANT DESIGN

H E A D Q U A R T E R S , D E P A R T M E N T O F T H E A R M Y20 JANUARY 1984

TM 5-811-6

REPRODUCTION AUTHORIZATION/RESTRICTIONS

This manual has been prepared by or for the Government and, except to the extent indicated below, is publicproperty and not subject to copyright.Copyrighted material included in the manual has been used with the knowledge and permission of the proprie-tors and is acknowledged as such at point of use. Anyone wishing to make further use of any copyrighted ma-terial, by itself and apart from this text, should seek necessary permission directly from the proprietors.Reprints or republications of this manual should include a credit substantially as follows: “Department of theArmy, USA, Technical Manual TM 5-811-6, Electric Power Plant Design.If the reprint or republication includes copyrighted material, the credit should also state: “Anyone wishing tomake further use of copyrighted material, by itself and apart from this text, should seek necessary permissiondirectly from the proprietors. ”

A/(B blank)

TM 5-811-6

T ECHNICAL M A N U A L HEADQUARTERSDEPARTMENT OF THE ARMY

NO. 5-811-6 W ASHINGTON , DC 20 January 1984

ELECTRIC POWER PLANT DESIGN

CHAPTER 1. INTRODUCTIONPurpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design philosophy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Economic considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

CHAPTER 2. SITE AND CIVIL FACILITIES DESIGNSelection I. Site Selection

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Environmental considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Water supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fuel supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Physical characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Economic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section II. Civil Facilities, Buildings, Safety, and SecuritySoils investigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Site development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

CHAPTER 3. STEAM TURBINE POWER PLANT DESIGNSection I. Typical Plants and Cycles

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Plant function and purpose. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Steam power cycle economy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cogeneration cycles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Selection of cycle steam conditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cycle equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Steam power plant arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section II. Steam Generators and Auxiliary SystemsSteam generator convention types and characteristics . . . . . . . . . . . . . . . . . . . . . . . .Other steam generator characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Steam generator special types . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Major auxiliary systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Minor auxiliary systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section III. Fuel Handling and Storage SystemsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical fuel oil storage and handling system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Coal handling and storage systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section IV. Ash Handling SystemsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Description of major components.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section V. Turbines and Auxiliary SystemsTurbine prime movers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Turbine features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Governing and control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Turning gear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Lubrication systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Extraction features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Instruments and special tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section VI. Condenser and Circulating Water SystemIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Description of major components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Environmental concerns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section VII. Feedwater SystemFeedwater heaters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Boiler feed pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Feedwater supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section VIII. Service Water and Closed Cooling SystemsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Description of major components.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Paragraph

1-11-21-31-4

2-12-22-32-42-52-6

2-72-82-9

3-13-23-33-43-53-63-7

3-83-93-103-113-12

3-133-143-15

3-163-17

3-183-193-203-213-223-233-243-25

3-263-273-28

3-293-303-31

3-323-33

Page

1-11-11-11-5

2-12-12-12-12-12-1

2-22-22-2

3-13-13-13-33-63-63-6

3-93-113-123-123-25

3-263-263-27

3-293-30

3-303-323-323-333-333-333-343-34

3-343-353-40

3-403-413-43

3-433-44

i

TM 5-811-6

CHAPTER 3. STEAM TURBINE POWER PLANT DESIGN (Continued)Description of systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Reliability of systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section IX. Water Conditioning SystemsWater conditioning selection.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section X. Compressed Air SystemsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Description of major components.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Description of systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

CHAPTER 4. GENERATOR AND ELECTRICAL FACILITIES DESIGNSection I. Typical Voltage Ratings and Systems

Voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Station service power syetems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section II. GeneratorsGeneral types and standards.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Features and acceesories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Excitation systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section III. Generator Leads and SwitchyardGeneral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Generator leads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Switchyard . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section IV. TransformersGenerator stepup transformer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Auxiliary transformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Unit substation transformer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section V. Protective Relays and MeteringGenerator, stepup transformer and switchyard relaying . . . . . . . . . . . . . . . . . . . . . . .Switchgear and MCC protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Instrumentation and metering. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section VI. Station Service Power SystemsGeneral requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Auxiliary power transformers. . . . . . . . . . . . . . . . . . . . . . . . ...’. . . . . . . . . . . . . . . . .4160 volt switchgear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .480 volt unit substations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .480 volt motor control centers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Foundations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Grounding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Conduit and tray systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Distribution outside the power plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section VII. Emergency Power SystemBattery and charger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Emergency ac system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section VIII. MotorsGeneral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Horsepower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Grounding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Conduit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Motor details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section IX. Communication SystemsIntraplant communications.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Telephone communications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

CHAPTER 5. GENERAL POWER PLANT FACILITIES DESIGNSection I. Instruments and Control Systems

General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Control panels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Automatic control systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Monitoring instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Alarm and annunciator systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section II. Heating, Ventilating and Air Conditioning SystemsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Operations areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Service areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Paragraph

3-343-353-363-37

3-38

3-393-403-41

4-14-2

4-34-44-5

4-64-74-8

4-94-104-11

4-124-134-14

4-154-164-174-184-194-204-214-224-23

4-244-25

4-264-274-284-294-304-314-32

4-334-34

Page

3-44 3-453-453-45

3-45

3-463-463-50

-14-1

4-34-74-8

4-84-94-13

4-164-164-17

4-184-194-19

4-204-204-204-214-214-214-214-214-22

4-234-23

4-234-244-244-244-244-244-24

4-244-26

5-15-25-35-45-5

5-65-75-8

5-15-15-55-95-14

5-145-145-14

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TM 5-811-6

Paragraph Page

5-155-155-15

5-175-175-175-215-215-215-215-21

5-22

5-225-235-24

6-16-16-26-26-26-3

7-17-1

7-27-27-27-27-2

7-37-37-3

8-18-1

8-18-2

Page1-41-53-23-33-53-73-83-93-133-153-16

CHAPTER 5. GENERAL POWER PLANT FACILITIES DESIGN (Continued)Section 111. Power and Service Piping Systems

5-95-105-11

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Piping design fundamentals... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Specific system design considerations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section IV. Thermal Insulation and Freeze ProtectionIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-12

5-135-145-155-165-175-185-19

Insulation design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Insulation materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Control of useful heat losses.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Safety insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cold surface insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Economic thickness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Freeze protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section V. Corrosion Protection5-20General remarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section VI. Fire ProtectionIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

.

CHAPTER 6.

5-215-225-23Support facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

GASTURBINE POWER PLANT DESIGNGeneral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Turbine-generator selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

6-16-26-36-46-56-6

Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Plant arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Waste heat recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Equipment and auxiliary systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

DIESEL ENGINE POWER PLANT DESIGNSection I. Diesel Engine Generators

Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fuel selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section II. Balance of Plant Systems

CHAPTER 7.

L

7-17-2

7-37-47-57-67-7

General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cooling systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Combustion air intake and exhaust systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fuel storage and handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Engine room ventilation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section III. Foundations and BuildingGeneral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Engine foundation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

7-87-97-10Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

COMBINED CYCLE POWER PLANTSSection I. Typical Plants and Cycles

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Plant details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Section II. General Design ParametersBackground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

REFERENCES

.CHAPTRR 8.

8-18-2.

8-38-4

APPENDIX A:BIBLIOGRAPHY

LIST OF FiGURES

Figure No.

Figure 1-11-23-13-23-33-43-53-63-73-83-9

Typical Metropolitan Area Load Curves. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Annual Load Duration Curve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Straight Condensing Cycle. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Turbine Efficiencies Vs.Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Condensing–Controlled Extraction Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Smal1 2-Unit Power Plant "A” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Smal1 2-Unit Power Plant “B’’ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Critical Turbine Room Bay and Power Plant "B’’Dimensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fluidized Bed Combustion Boiler . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Theorectical Air and Combustion Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Minimum Metal Temperatures for Boiler Heat Recovery Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TM 5-811-6

Page

3-103-113-123-133-143-154-14-24-3

4-44-54-64-74-85-16-17-18-1

Table No.

Table 1-11-21-31-43-13-23-33-43-53-63-73-83-93-103-113-123-133-143-154-14-25-15-25-35-45-55-65-7

Coal Handling System Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Coal Handling System for Spreader Stoker Fired Boiler (with bucket elevator). . . . . . . . . . . . . . . . . . .Pneumatic Ash Handling Systems-Variations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Types of Circulating Water Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Compressed Air System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Arrangement of Air Compressor and Acceesories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Station Connections–Two Unit Station Common Bus Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Station Connections–Two Unit Station–Unit Arrangment–Generator at Distribution Voltage. . . . . . . . . .Station Connections–Two Unit Station–Unit Arrangement–Distribution Voltage Higher Than Genera-tion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .One Lone Diagram-TypicalStation Service Power System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Synchronizing Bus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Main and TransferBus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Ring Bus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Breaker and a Half Bus.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Economical Thickness of Heat Insulation (Typical Curves) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Indoor Simple Cycle Gas Turbine Generator PowerPlant.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Typical Diesel Generator Power Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Combined Cycle Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

LIST OF TABLES

General Description of Type of Plant.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Diesel Class and Operational Characteristics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Plant Sizes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Deeign Criteria Requirements.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Theoretical Steam Rates for Typical Steam Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fuel Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Indivdual Burner Turndown Ratios . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Emission Levels Allowable, National Ambient Air Quality Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Uncontrolled Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Characteristics of Cyclones for Particulate Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Characteristics of Scrubbers for Particulate Control. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Characterietics of Electrostatic Precipitators (ESP) for Particulate Control. . . . . . . . . . . . . . . . . . . . . . . . . . . .Characteristics of Baghouses for Particulate Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Characteristics of Flue-Gas Desulfurization Systems for Particulate Control. . . . . . . . . . . . . . . . . . . . . . . . . . .Techniques for Nitrogen Oxide Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Condenser Tube Design Velocities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .General Guide for Raw Water Treatment of Boiler Makeup . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Internal Chemical Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Effectiveness of Water Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Standard Motor Control Center Enclosures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Suggested Locations for Intraplant Communication System Devices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .List of Typical Instrumente and Devices for Boiler-Turbine Mechanical Panel. . . . . . . . . . . . . . . . . . . . . . . . . .List of Typical Instrument and Devices for Common Services Mechanical Panel. . . . . . . . . . . . . . . . . . . . . . .List of Typical Instruments and Devices for Electrical (Generator and Switchgear) Panel . . . . . . . . . . . . . . . .List of Typical Instrument and Devices for Diesel Mechanical Panel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Sensing Elements for Controls and Instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Piping Codes and Standards for Power Plants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Characteristics of Thermal Insulations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3-263-28 3-313-383-503-514-24-4

4-54-64-94-104-114-125-226-37-48-3

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1-21-31-31-33-43-103-143-173-183-19 3-203-213-223-233-243-363-473-483-494-224-255-15-45-65-85-105-165-18

iv

TM 5-811-6

CHAPTER 1

INTRODUCTION

1-1. Purposea. General: This manual provides engineering

data and criteria for designing electric power plantswhere the size and characteristics of the electricpower load and the economics of the particular facil-it y justify on-site generation. Maximum size ofplant considered in this manual is 30,000 kW.

b. References: A list of references used in thismanual is contained in Appendix A. Additionally, aBibliography is included identifying sources of ma-terial related to this document.

1-2. Design philosophya. General. Electric power plants fall into several

categories and classes depending on the type ofprime mover. Table 1-1 provides a general descrip-tion of plant type and related capacity require-ments. For purposes of this introduction Table 1-2defines, in more detail, the diesel plant classes andoperational characteristics; additional informationis provided in Chapter 7. No similar categories havebeen developed for gas turbines. Finally, for pur-poses of this manual and to provide a quick scale forthe plants under review here, several categorieshave been developed. These are shown in Table 1-3.

b. Reliability. Plant reliability standards will beequivalent to a l-day generation forced outage in 10years with equipment quality and redundancy se-lected during plant design to conform to this stand-ard.

c. Maintenance. Power plant arrangement willpermit reasonable access for operation and mainte-nance of equipment. Careful attention will be givento the arrangement of equipment, valves, mechan-ical specialties, and electrical devices so that rotors,tube bundles, inner valves, top works, strainers,contractors, relays, and like items can be maintainedor replaced. Adequate platforms, stairs, handrails,and kickplates will be provided so that operatorsand maintenance personnel can function conven-iently and safely.

d. Future expansion. The specific site selected forthe power plant and the physical arrangement of theplant equipment, building, and support facilitiessuch as coal and ash handling systems, coal storage,circulating water system, trackage, and accessroads will be arranged insofar as practicable to allowfor future expansion.

1-3. Design criteriaa. General requirements. The design will provide

for a power plant which has the capacity to providethe quantity and type of electric power, steam andcompressed air required. Many of the requirementsdiscussed here are not applicable to each of the plantcategories of Table 1-1. A general overview is pro-vided in Table 1-4.

b. Electric power loads. The following informa-tion, as applicable, is required for design:

(1) Forecast of annual diversified peak load tobe served by the project.

(2) Typical seasonal and daily load curves andload duration curves of the load to be served. Ex-ample curves are shown in Figures 1-1 and 1-2.

(3) If the plant is to operate interconnected withthe local utility company, the designer will need in-formation such as capacity, rates, metering, and in-terface switchgear requirements.

(4) If the plant is to operate in parallel withexisting generation on the base, the designer willalso need:

(a) An inventory of major existing generationequipment giving principal characteristics such ascapacities, voltages, steam characteristics, backpressures, and like parameters.

(b) Incremental heat rates of existing boiler-turbine units, diesel generators, and combustionturbine generator units.

(c) Historical operating data for each existinggenerating unit giving energy generated, fuel con-sumption, steam exported, and other related infor-mation.

(5) Existing or recommended distribution vol-tage, generator voltage, and interconnecting substa-tion voltages.

(6) If any of the above data as required for per-forming the detailed design is unavailable, the de-signer will develop this data.

c. Exports team loads.(1) General requirements. If the plant will ex-

port steam, information similar to that required forelectric power, as outlined in subparagraph c above,will be needed by the designer.

(2) Coordination of steam and electric powerloads. To the greatest extent possible, peak, season-al, and daily loads for steam will be coordinated withthe electric power loads according to time of use.

1-1

Category

Primary

Standby

Table 1-1. General Description of Type of Plant.

TYPE OF POWERCapacity No Export Steam

Adequate to meetrequirement .

Adequate withmobilization

all peacetime Purchased electric power to matchelectr ic load.

Continuous duty diesel plant,Class “A” diesel.

Straight condensing boilers andand turbines matched in capacityas units; enough units so plantwithout largest unit can carryemergency load.

prime source to match Purchased electric power.needs; or alone to supply

emergency electric load and exportsteam load in case of primary source Standby diesel plant, Class “B”out age. diesel .

Equal to primary source . . . . . . . . . . . . Retired straight condensing plant.

Emergency To supply that part of emergency load Fixed emergency diesel plant,that cannot be interrupted for m o r e Class “C” diesel.than 4 hours. Mobile utilities support equipment.

With Export Steam

Purchased electric power and steam tomatch electric load plus supplementaryboiler plant to match export steam load.

Automatic back pressure steam plant plusautomatic packaged firetube boiler tosupplement requirements of export steamload.

Automatic extraction steam plant boilersand turbines matched in capacity se unitsand enough units installed so that plantwithout largest unit can carry emergencyload.

Purchased electric power and steam tomatch electric power load plus supple-mentary boiler plant.

Standby diesel plant with supplementaryboiler plant.

Retired automatic extraction steam plant.

None.

None.

NAVFAC DM3

TM 5-811-6

Table 1-2. Diesel Class and Operational Characteristics.

Fu1l Load RatingCapabil i ty Expected Operating Hours

Minimum OperatingClass Usage Hours Period— — - — —

" "A . . . . . . . . . Continuous . . . . . . . 8,000 . . . . . Yearly . . . . . . . 4,000 hours plus . . . . .

“B” . . . . . . . . . Standby . . . . . . . . . . 8,000 . . . . . Yearly . . . . . . . 1,000 to 4,000 hours .

“c” . . . . . . . . . Emergency . . . . . . . . 650 . . . . . Monthly* . . . . . Under 1,000 hours . . . .

*Based on a 30-day month.

U . S . A r m y C o r p s o f E n g i n e e r s

C a t e g o r y

S m a l l

M e d i u m

L a r g e

Table-3. Plant Sizes.

S i z e

o to 2 , 5 0 0 k W

2 , 5 0 0 k W t o 1 0 , 0 0 0 k W

1 0 , 0 0 0 k W t o 3 0 , 0 0 0 k W

U . S . A r m y C o r p s o f E n g i n e e r s

Table-4. Design Criteria Requirements.

C l a s s( P l a n t C a t e g o r y )

A ( P r i m a r y )

B ( S t a n d b y )

C ( E m e r g e n c y )

E l e c t r i c

P o w e rL o a d s

A

A

c r i t i c a ll o a d s o n l y

A = A p p l i c a b l eN / A = N o t A p p l i c a b l e

First Ten Years

40,000 hours plus

20,000 to 40,000 hours

Under 10,000 hours

E x p o r t

St earnL o a d s

A

N / A

N / A

F u e lS o u r c e

a n d W a t e r S t a c k W a s t e

C o s t Supp ly E m i s s i o n D i s p o s a l

A A A A

A N / A N / AA

A N / A N / A N /A

C o u r t e s y o f P o p e , E v a n s a n d R o b b i n s ( N o n - C o p y r i g h t e d )

1-3

TM 5-811-6

This type of information is particularly important ifthe project involves cogeneration with the simul-taneous production of electric power and steam.

d. Fuel source, and cost. The type, availability,and cost of fuel will be determined in the earlystages of design; taking into account regulatory re-quirements that may affect fuel and fuel characteris-tics of the plant.

e. Water supply. Fresh water is required forthermal cycle makeup and for cooling tower or cool-ing pond makeup where once through water for heatrejection is unavailable or not usable because ofregulatory constraints. Quantity of makeup willvary with the type of thermal cycle, amount of con-densate return for any export steam, and the maxi-mum heat rejection from the cycle. This heat rejec-tion load usually will comprise the largest part ofthe makeup and will have the least stringent re-quirements for quality.

f. Stack emissions. A steam electric power plant

----- Sumner LoadWinter Load

Kw

1

will be designed for the type of stack gas cleanupequipment which meets federal, state, and munici-pal emission requirements. For a solid fuel fired boiler, this will involve an electrostatic precipitator orbag house for particulate, and a scrubber for sulfurcompounds unless fluidized bed combustion or com-pliance coal is employed. If design is based on com-pliance coal, the design will include space and otherrequired provision for the installation of scrubberequipment. Boiler design will be specified as re-quired for NOx control.

g. Waste disposal.(1) Internal combustion plants. Solid and liq-

uid wastes from a diesel or combustion turbine gen-erating station will be disposed of as follows: Mis-cellaneous oily wastes from storage tank areas andsumps will be directed to an API separator. Supple-mentary treating can be utilized if necessary to meetthe applicable requirements for waste water dis-charge. For plants of size less than 1,000 kW, liquid

.URBAN[NDUSTRIAL TRACTION

LOAD LOAD

1 2 6 1 2 6 1 2 6 1 2 6 1 2 6 1 2 6 1 2AM PM AM PM AM PM

FROM POWER STATION ENGINEERING AND ECONOMY BY SROTZKI AND LOPAT.COPYRIGHT © BY THE MC GRAW-HILL BOOK COMPANY, INC. USED WITH THEPERMISSION OF MC GRAW-HILL BOOK COMPANY.

Figure 1-1. Typical metropolitan area load curves.

1-4

TM 5-811-6

oily wastes will be accumulated in sumps or smalltanks for removal. Residues from filters and centri-fuges will be similarly handled.

(2) Steam electric stations. For steam electricgenerating stations utilizing solid fuel, both solidand liquid wastes will be handled and disposed of inan environmentally acceptable manner. The wastescan be categorized generally as follows:

(a) Solid wastes. These include both bottomash and fly ash from boilers.

(b) Liquid wastes. These include boiler blow-down, cooling tower blowdown, acid and causticwater treating wastes, coal pile runoff, and variouscontaminated wastes from chemical storage areas,sanitary sewage and yard areas.

h. Other environmental considerations. Other en-vironmental considerations include noise controland aesthetic treatment of the project. The final lo-cation of the project within the site area will be re-viewed in relation to its proximity to hospital andoffice areas and the civilian neighborhood, if appli-cable. Also, the general architectural design will bereviewed in terms of coordination and blending with

I

the style of surrounding buildings. Any anticipatednoise or aesthetics problem will be resolved prior tothe time that final site selection is approved.

1-4. Economic considerationsa. The selection of one particular type of design

for a given application, when two or more types ofdesign are known to be feasible, will be based on theresults of an economic study in accordance with therequirements of DOD 4270.1-M and the NationalEnergy Conservation Policy Act (Public Law95-619,9 NOV 1978).

b. Standards for economic studies are containedin AR 11-28 and AFR 178-1, respectively. Addi-tional standards for design applications dealingwith energy/fuel consuming elements of a facilityare contained in the US Code of Federal Regula-tions, 20 CFR 436A. Clarification of the basic stand-ards and guidelines for a particular application andsupplementary standards which may be required forspecial cases may be obtained through normal chan-nels from HQDA (DAEN-ECE-D), WASH DC20314.

I0 1000 2000 3000 4000 5000 6000 7000 8000 8760-

U.S. Army Corps of

Figure 1-2.

— HOURS

Engineers

Typical annual load duration curve.

1-5

TM 5-811-6

CHAPTER 2

SITE AND CIVIL FACILITIES DESIGN

Section 1. SITE SELECTION

2-1. IntroductionSince the selection of a plant site has a significantinfluence on the design, construction and operatingcosts of a power plant, each potential plant site willbe evaluated to determine which is the mosteconomically feasible for the type of power plant be-ing considered.

2-2. Environmental considerationsa. Rules and regulations. All power plant design,

regardless of the type of power plant, must be in ac-cordance with the rules and regulations which havebeen established by Federal, state and local govern-mental bodies.

b. Extraordinary design features. To meet var-ious environmental regulations, it is often necessaryto utilize design features that will greatly increasethe cost of the power plant without increasing its ef-ficiency. For example, the cost of the pollution con-trol equipment that will be required for each site un-der consideration is one such item which must becarefully evaluated.

2-3. Water supplya. General requirements. Water supply will be

adequate to meet present and future plant require-ments. The supply maybe available from a local mu-nicipal or privately owned system, or it may be nec-essary to utilize surface or subsurface sources.

b. Quality. Water quality and type of treatmentrequired will be compatible with the type of powerplant to be built.

c. Water rights. If water rights are required, it willbe necessary to insure that an agreement for waterrights provides sufficient quantity for present andfuture use.

d. Water wells. If the makeup to the closed sys-tem is from water wells, a study to determine watertable information and well drawdown will be re-quired. If this information is not available, test wellstudies must be made.

e. Once-through system. If the plant has a oncethrough cooling system, the following will be deter-mined:

(1) The limitations established by the appro-priate regulatory bodies which must be met to ob-

tain a permit required to discharge heated water tothe source.

(2) Maximum allowable temperature rise per-missible as compared to system design parameters.If system design temperature rise exceeds permissi-ble rise, a supplemental cooling system (coolingtower or spray pond) must be incorporated into thedesign.

(3) Maximum allowable temperature for riveror lake after mixing of cooling system effluent withsource. If mixed temperature is higher than allow-able temperature, a supplemental cooling systemmust be added. It is possible to meet the conditionsof (2) above and not meet the conditions in this sub-paragraph.

(4) If extensive or repetitive dredging of wat-erway will be necessary for plant operations.

(5) The historical maximum and minimumwater level and flow readings. Check to see that ade-quate water supply is available at minimum flowand if site will flood at high level.

2-4. Fuel supplySite selection will take into consideration fuel stor-age and the ingress and egress of fuel delivery equip-ment.

2-5. Physical characteristicsSelection of the site will be based on the availabilityof usable land for the plant, including yard struc-tures, fuel handling facilities, and any future expan-sion. Other considerations that will be taken into ac-count in site selection are:

-Soil information.-Site drainage.- Wind data.-Seismic zone.-Ingress and egress.

For economic purposes and operational efficiency,the plant site will be located as close to the load cen-ter as environmental conditions permit.

2-6. EconomicsWhere the choice of several sites exists, the final se-lection will be based on economics and engineeringstudies.

2-1

.

TM 5-811-6

Section Il. CIVIL FACILITIES, BUILDINGS, SAFETY, AND SECURITY

2-7. Soils investigationAn analysis of existing soils conditions will be madeto determine the proper type of foundation. Soilsdata will include elevation of each boring, watertable level, description of soil strata including thegroup symbol based on the Unified Soil Classifica-tion System, and penetration data (blow count). Thesoils report will include recommendations as to typeof foundations for various purposes; excavation, de-watering and fill procedures; and suitability of on-site material for fill and earthen dikes including dataon soft and organic materials, rock and other perti-nent information as applicable.

2-8. Site developmenta. Grading and drainage.

(1) Basic criteria. Determination of final grad-ing and drainage scheme for a new power plant willbe based on a number of considerations includingsize of property in relationship to the size of plantfacilities, desirable location on site, and plant accessbased on topography. If the power plant is part ofan overall complex, the grading and drainage will becompatible and integrated with the rest of the com-plex. To minimize cut and fill, plant facilities will belocated on high ground and storm water drainagewill be directed away from the plant. Assuming onsite soils are suitable, grading should be based onbalanced cut and fill volume to avoid hauling of ex-cess fill material to offsite disposal and replacementwith expensive new material.

(2) Drainage. Storm water drainage will beevaluated based on rainfall intensities, runoff char-acteristics of soil, facilities for receiving stormwater discharge, and local regulations. Storm waterdrains or systems will not be integrated with sani-tary drains and other contaminated water drainagesystems.

(3) Erosion prevention. All graded areas will bestabilized to control erosion by designing shallowslopes to the greatest extent possible and by meansof soil stabilization such as seeding, sod, stone, rip-rap and retaining walls.

b. Roadways.(1) Basic roadway requirements. Layout of

plant roadways will be based on volume and type oftraffic, speed, and traffic patterns. Type of traffic orvehicle functions for power plants can be catego-rized as follows:

-Passenger cars for plant personnel.-Passenger cars for visitors.-Trucks for maintenance material deliveries.-Trucks for fuel supply.

-Trucks for removal of ash, sludge and otherwaste materials.

(2) Roadway material and width. Aside fromtemporary construction roads, the last two catego-ries described above will govern most roadway de-sign, particularly if the plant is coal fired. Roadwaymaterial and thickness will be based on economicevaluations of feasible alternatives. Vehicular park-ing for plant personnel and visitors will be located inareas that will not interfere with the safe operationof the plant. Turning radii will be adequate to han-dle all vehicle categories. Refer to TM 5-803-5/ NAVPAC P-960/AFM 88-43; TM 5-818-2/AFM 88-6, Chap. 4; TM 5-822-2/AFM 88-7, Chap. 7; TM 5-822-4/AFM 88-7, Chap. 4; TM5-822 -5/AFM 88-7, Chap. 3; TM 5-822-6/AFM88-7, Chap. 1; TM 5-822-7/AFM 88-6, Chap. 8; andTM 5-822-8.

c. Railroads. If a railroad spur is selected to han-dle fuel supplies and material and equipment deliv-eries during construction or plant expansion, the de-sign will be in accordance with American RailwayEngineering Association standards. If coal is thefuel, spur layout will accommodate coal handling fa-cilities including a storage track for empty cars. Ifliquid fuel is to be handled, unloading pumps andsteam connections for tank car heaters may be re-quired in frigid climates.

2-9. Buildingsa. Size and arrangement.

(1) Steam plant. Main building size and ar-rangement depend on the selected plant equipmentand facilities including whether steam generatorsare indoor or outdoor type; coal bunker or silo ar-rangement; source of cooling water supply relativeto the plant; the relationship of the switchyard tothe plant; provisions for future expansion; and , aesthetic and environmental considerations. Gener-ally, the main building will consist of a turbine baywith traveling crane; an auxiliary bay for feedwaterheaters, pumps, and switchgear; a steam generatorbay (or firing aisle for semi-outdoor units); and gen-eral spaces as may be required for machine shop,locker room, laboratory and office facilities. Thegeneral spaces will be located in an area that will notinterfere with future plant expansion and isolatedfrom main plant facilities to control noise. For verymild climates the turbine generator sets and steamgenerators may be outdoor type (in a weather pro-tected, walk-in enclosure) although this arrange-ment presents special maintenance problems. If in-corporated, the elevator will have access to the high-

2-2

TM 5-811-6

est operating level of the steam generator (drum lev-els).

(2) Diesel plant. The requirements for a build-ing housing a diesel generator plant are the same asfor a steam turbine plant except that a steam gener-ator bay is not required.

b. Architectural treatment.(1) The architectural treatment will be de-

veloped to harmonize with the site conditions, bothnatural and manmade. Depending on location, theenvironmental compatibility y may be the determin-ing factor. In other cases the climate or user prefer-ence, tempered with aesthetic and economic factors,will dictate architectural treatment. Climate is acontrolling factor in whether or not a total or partialclosure is selected. Semi-outdoor construction withthe bulk of the steam generator not enclosed in aboiler room is an acceptable design.

(2) For special circumstances, such as areaswhere extended periods of very high humidity, fre-quently combined with desert conditions giving riseto heavy dust and sand blasting action, indoor con-struction with pressurized ventilation will be re-quired not only for the main building but also, gen-erally, for the switchyard. Gas enclosed switchyardinstallations may be considered for such circum-stances in lieu of that required above.

(3) Control rooms, offices, locker rooms, and some out-buildings will be enclosed regardless of en-

closure selected for main building. Circulating waterpumps may be installed in the open, except in themost severe climates. For semi-outdoor or outdoorstations, enclosures for switchgear and motor con-trols for the auxiliary power system will be enclosedin manufacturer supplied walk-in metal housings orsite fabricated closures.

c. Structural design.(1) Building framing and turbine pedestals.

Thermal stations will be designed utilizing conven-tional structural steel for the main power stationbuilding and support of boiler. The pedestal for sup-porting the turbine generator (and turbine drivenboiler feed pump if utilized) will be of reinforced con-crete. Reinforced concrete on masonry constructionmay be used for the building framing (not for boilerframing); special concrete inserts or other provisionmust be made in such event for support of piping,trays and conduits. An economic evaluation will bemade of these alternatives.

(2) Exterior walls. The exterior walls of mostthermal power stations are constructed of insulatedmetal panels. However, concrete blocks, bricks, orother material may be used depending on the aes-thetics and economics of the design.

(3) Interior walls. Concrete masonry blocks willbe used for interior walls; however, some specialized

areas, such as for the control room enclosure and foroffices, may utilize factory fabricated metal walls,fixed or moveable according to the application.

(4) Roof decks. Main building roof decks will beconstructed of reinforced concrete or ribbed metaldeck with built-up multi-ply roofing to provide wat-erproofing. Roofs will be sloped a minimum of 1/4,-inch per foot for drainage.

(5) Floors. Except where grating or checkeredplate is required for access or ventilation, all floorswill be designed for reinforced concrete with a non-slip finish.

(6) Live loads. Buildings, structures and allportions thereof will be designed and constructed tosupport all live and dead loads without exceedingthe allowable stresses of the selected materials inthe structural members and connections. Typicallive loads for power plant floors are as follows:

(a) Turbine generator floor 500 psf(b) Basement and operating floors except

turbine generator floor 200 psf(c) Mezzanine, deaerator, and

miscellaneous operating floors 200 psf(d) Offices, laboratories, instrument

shops, and other lightly loaded areas 100 psfLive loads for actual design will be carefully re-viewed for any special conditions and actual loadsapplicable.

(7) Other loads. In addition to the live and deadloads, the following loadings will be provided for:

(a) Wind loading. Building will be designed toresist the horizontal wind pressure available for thesite on all surfaces exposed to the wind.

(b) Seismic loading. Buildings and otherstructures will be designed to resist seismic loadingin accordance with the zone in which the building islocated.

(c) Equipment loading. Equipment loads arefurnished by the various manufacturers of eachequipment item. In addition to equipment deadloads, impact loads, short circuit forces for genera-tors, and other pertinent special loads prescribed bythe equipment function or requirements will be in-cluded.

d. Foundation design.(1) Foundations will be designed to safely sup-

port all structures, considering type of foundationand allowable bearing pressures. The two most com-mon types of foundations are spread footings andpile type foundations, although “raft” type of otherspecial approaches may be utilized for unusual cir-cumstances.

(2) Pile type foundations require reinforcedconcrete pile caps and a system of reinforced con-crete beams to tie the caps together. Pile load capa-bilities may be developed either in friction or point

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TM 5-811-6

bearing. The allowable load on piles will be deter-mined by an approved formula or by a load test.Piles can be timber, concrete, rolled structural steelshape, steel pipe, or steel pipe concrete filled.

(3) Design of the reinforced concrete turbinegenerator or diesel set foundation, both mat andpedestal, will be such that the foundation is isolatedfrom the main building foundations and structuresby expansion joint material placed around its perim-eter. The design will also insure that the resonanceof the foundation at operating speed is avoided inorder to prevent cracking of the foundation anddamage to machines caused by resonant vibration.The foundation will be designed on the basis of de-flection. The limits of deflection will be selected toavoid values of natural frequency by at least 30 per-cent above or 30 percent below operating speed.

(4) Vibration mounts or “floating floor” foun-dations where equipment or equipment foundationinertia blocks are separated from the main buildingfloor by springs or precompressed material will gen-erally not be used in power plants except for ventila-tion fans and other building service equipment. Inthese circumstances where such inertia blocks areconsidered necessary for equipment not normally somounted, written justification will be included inthe project design analysis supporting such a neces-sity.

(5) The location of turbine generators, diesel en-gine sets, boiler feed pumps, draft fans, compres-sors, and other high speed rotating equipment onelevated floors will be avoided because of the diffi-culty or impossibility of isolating equipment foun-dations from the building structure.

2-10. Safety.a. Introduction. The safety features described in

the following paragraphs will be incorporated intothe power plant design to assist in maintaining ahigh level of personnel safety.

b. Design safety features. In designing a powerplant, the following general recommendations onsafety will be given attention:

(1) Equipment will be arranged with adequateaccess space for operation and for maintenance.Wherever possible, auxiliary equipment will be ar-ranged for maintenance handling by the main tur-bine room crane. Where this is not feasible, mono-rails, wheeled trucks, or portable A-frames shouldbe provided if disassembly of heavy pieces is re-quired for maintenance.

(2) Safety guards will be provided on movingparts of all equipment.

(3) All valves, specialties, and devices needingmanipulation by operators will be accessible with-out ladders, and preferably without using chain

wheels. This can be achieved by careful piping de-sign, but some access platforms or remote mechani-cal operators may be necessary.

(4) Impact type handwheels will be used forhigh pressure valves and all large valves.

(5) Valve centers will be mounted approximate-ly 7 feet above floors and platforms so that risingstems and bottom rims of handwheels will not be ahazard.

(6) Stairs with conventional riser-tread propor-tions will be used. Vertical ladders, installed only asa last resort, must have a safety cage if required by .the Occupational Safety and Health Act (OSHA).

(7) All floors, gratings and checkered plates willhave non-slip surfaces.

(8) No platform or walkway will be less than 3 ‘feet wide.

(9) Toe plates, fitted closely to the edge of allfloor openings, platforms and stairways, will be pro-vided in all cases.

(10) Adequate piping and equipment drains towaste will be provided.

(11) All floors subject to washdown or leaks willbe sloped to floor drains.

(12) All areas subject to lube oil or chemicalspills will be provided with curbs and drains,

(13) If plant is of semi-outdoor or outdoor con-struction in a climate subject to freezing weather,weather protection will be provided for critical operating and maintenance areas such as the firingaisle, boiler steam drum ends and soot blower loca-tions.

(14) Adequate illumination will be providedthroughout the plant. Illumination will comply withrequirements of the Illuminating Engineers Society(IES) Lighting Handbook, as implemented by DOD 4270.1-M.

(15) Comfort air conditioning will be providedthroughout control rooms, laboratories, offices andsimilar spaces where operating and maintenancepersonnel spend considerable time.

(16) Mechanical supply and exhaust ventilationwill be provided for all of the power plant equipmentareas to alleviate operator fatigue and prevent accu-mulation of fumes and dust. Supply will be ductedto direct air to the lowest level of the power plantand to areas with large heat release such as the tur-bine or engine room and the boiler feed pump area.Evaporative cooling will be considered in low hu-midity areas. Ventilation air will be filtered andheated in the winter also, system air flow capacityshould be capable of being reduced in the winter.Battery room will have separate exhaust fans to re-move hydrogen emitted by batteries as covered inTM 5-811-2/AFM 88-9, Chap. 2.

(17) Noise level will be reduced to at least the

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TM 5-811-6

recommended maximum levels of OSHA. Use of fansilencers, compressor silencers, mufflers on internalcombustion engines, and acoustical material is re-quired as discussed in TM 5-805-4/AFM88-37/NAVFAC DM-3.1O and TM 5-805-9/AFM88-20/NAVFAC DM-3.14. Consideration should begiven to locating forced draft fans in acousticallytreated fan rooms since they are usually the largestnoise source in a power plant. Control valves will bedesigned to limit noise emissions.

(18) A central vacuum cleaning system shouldbe considered to permit easy maintenance of plant.

(19) Color schemes will be psychologically rest-ful except where danger must be highlighted withspecial bright primary colors.

(20) Each equipment item will be clearly la-belled in block letters identifying it both by equipment item number and name. A complete, coordi-nated system of pipe markers will be used for identi-fication of each separate cycle and power plant serv-ice system. All switches, controls, and devices on allcontrol panels will be labelled using the identicalnames shown on equipment or remote devices beingcontrolled.

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TM 5-811-6

CHAPTER 3

STEAM TURBINE POWER PLANT DESIGN

Section 1. TYPICAL PLANTS AND CYCLES

3-1. Introductiona. Definition. The cycle of a steam power plant is

the group of interconnected major equipment com-ponents selected for optimum thermodynamic char-acteristics, including pressure, temperatures and ca-pacities, and integrated into a practical arrange-ment to serve the electrical (and sometimes by-prod-uct steam) requirements of a particular project. Se-lection of the optimum cycle depends upon plantsize, cost of money, fuel costs, non-fuel operatingcosts, and maintenance costs.

b. Steam conditions. Typical cycles for the prob-able size and type of steam power plants at Army es-tablishments will be supplied by superheated steamgenerated at pressures and temperatures between600 psig (at 750 to 850°F) and 1450 psig (at 850 to950º F). Reheat is never offered for turbine genera-tors of less than 50 MW and, hence, is not applicablein this manual.

c. Steam turbine prime movers. The steam tur-bine prime mover, for rated capacity limits of 5000kW to 30,000 kW, will be a multi-stage, multi-valveunit, either back pressure or condensing. Smallerturbines, especially under 1000 kW rated capacity,may be single stage units because of lower first costand simplicity. Single stage turbines, either backpressure or condensing, are not equipped with ex-traction openings.

d. Back pressure turbines. Back pressure turbineunits usually exhaust at pressures between 250 psigand 15 psig with one or two controlled or uncon-trolled extractions. However, there is a significantprice difference between controlled and uncontrolledextraction turbines, the former being more expen-sive. Controlled extraction is normally appliedwhere the bleed steam is exported to process or dis-trict heat users.

e. Condensing turbines. Condensing units ex-haust at pressures between 1 inch of mercury abso-lute (Hga) and 5 inches Hga, with up to two con-trolled, or up to five uncontrolled, extractions.

3-2. Plant function and purposea. Integration into general planning. General

plant design parameters will be in accordance withoverall criteria established in the feasibility study or

planning criteria on which the technical and econom-ic feasibility is based. The sizes and characteristicsof the loads to be supplied by the power plant, in-cluding peak loads, load factors, allowances for fu-ture growth, the requirements for reliability, andthe criteria for fuel, energy, and general economy,will be determined or verified by the designer andapproved by appropriate authority in advance of thefinal design for the project.

b. Selection of cycle conditions. Choice of steamconditions, types and sizes of steam generators andturbine prime movers, and extraction pressures de-pend on the function or purpose for which the plantis intended. Generally, these basic criteria shouldhave already been established in the technical andeconomic feasibility studies, but if all such criteriahave not been so established, the designer will selectthe parameters to suit the intended use.

c. Coeneration plants. Back pressure and con-trolled extraction/condensing cycles are attractiveand applicable to a cogeneration plant, which is de-fined as a power plant simultaneously supplyingeither electric power or mechanical energy and heatenergy (para. 3-4).

d. Simple condensing cycles. Straight condensingcycles, or condensing units with uncontrolled ex-tractions are applicable to plants or situationswhere security or isolation from public utility powersupply is more important than lowest power cost.Because of their higher heat rates and operatingcosts per unit output, it is not likely that simple con-densing cycles will be economically justified for amilitary power plant application as compared withthat associated with public utility ‘purchased powercosts. A schematic diagram of a simple condensingcycle is shown on Figure 3-1.

3-3. Steam power cycle economya. Introduction. Maximum overall efficiency and

economy of a steam power cycle are the principal de-sign criteria for plant selection and design. In gener-al, better efficiency, or lower heat rate, is accom-panied by higher costs for initial investment, opera-tion and maintenance. However, more efficientcycles are more complex and may be less reliable perunit of capacity or investment cost than simpler and

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TM 5-611-6

N A V F A C D M 3

Figure 3-1. Typical straight condensing cycle.

less efficient cycles. Efficiency characteristics canbe listed as follows:

(1) Higher steam pressures and temperaturescontribute to better, or lower, heat rates.

(2) For condensing cycles, lower back pressuresincrease efficiency except that for each particularturbine unit there is a crossover point where lower-ing back pressure further will commence to decreaseefficiency because the incremental exhaust loss ef-fect is greater than the incremental increase in avail-able energy.

(3) The use of stage or regenerative feedwatercycles improves heat rates, with greater improve-ment corresponding to larger numbers of such heat-ers. In a regenerative cycle, there is also a thermody-namic crossover point where lowering of an extrac-tion pressure causes less steam to flow through theextraction piping to the feedwater heaters, reducingthe feedwater temperature. There is also a limit tothe number of stages of extraction/feedwater heat-ing which may be economically added to the cycle.This occurs when additional cycle efficiency no long-er justifies the increased capital cost.

(4) Larger turbine generator units are generallymore efficient that smaller units.

(5) Multi-stage and multi-valve turbines aremore economical than single stage or single valvemachines.

(6) Steam generators of more elaborate design,or with heat saving accessory equipment are moreefficient.

b. Heat rate units and definitions. The economyor efficiency of a steam power plant cycle is ex-

3-2

pressed in terms of heat rate, which is total thermalinput to the cycle divided by the electrical output ofthe units. Units are Btu/kWh.

(1) Conversion to cycle efficiency, as the ratio ofoutput to input energy, may be made by dividingthe heat content of one kWh, equivalent to 3412.14Btu by the heat rate, as defined. Efficiencies are seldom used to express overall plant or cycle perform-ance, although efficiencies of individual compo-nents, such as pumps or steam generators, are com-monly used.

(2) Power cycle economy for particular plants orstations is sometimes expressed in terms of poundsof steam per kilowatt hour, but such a parameter isnot readily comparable to other plants or cycles andomits steam generator efficiency.

(3) For mechanical drive turbines, heat ratesare sometimes expressed in Btu per hp-hour, exclud-ing losses for the driven machine. One horsepowerhour is equivalent to 2544.43 Btu.

c. Heat rate applications. In relation to steampower plant cycles, several types or definitions ofheat rates are used:

(1) The turbine heat rate for a regenerative tur-bine is defined as the heat consumption of the tur-bine in terms of “heat energy in steam” supplied bythe steam generator, minus the “heat in the feedwa-ter” as warmed by turbine extraction, divided bythe electrical output at the generator terminals.This definition includes mechanical and electricallosses of the generator and turbine auxiliary sys-tems, but excludes boiler inefficiencies and pumpinglosses and loads. The turbine heat rate is useful for

TM 5-811-6

performing engineering and economic comparisonsof various turbine designs. Table 3-1 provides theo-retical turbine steam rates for typical steam throttle

conditions. Actual steam rates are obtained by di-viding the theoretical steam rate by the turbine effi-ciency. Typical turbine efficiencies are provided onFigure 3-2.

ASR =where: ASR = actual steam rate (lb/kWh)

TSR = theoretical steam rate (l/kWh)nt = turbine efficiency

Turbine heat rate can be obtained by multiplyingthe actual steam rate by the enthalpy change acrossthe turbine (throttle enthalpy - extraction or ex-haust enthalpy).

Ct = ASR(hl – h2)where = turbine heat rate (Btu/kWh)

ASR = actual steam rate lb/kWh)h1 = throttle enthalpyh1 = extraction or exhaust enthalpy

TSR

’

FROM STANDARD HANDBOOK FOR MECHANICALENGINEERS BY MARKS. COPYRIGHT © 1967,

. MCGRAW-HILL BOOK CO. USED WITH THEPERMISSION OF MCGRAW- HILL BOOK COMPANY.

Figure 3-2. Turbine efficiencies vs. capacity.m

(2) Plant heat rates include inefficiencies andlosses external to the turbine generator, principally

the inefficiencies of the steam generator and pipingsystems; cycle auxiliary losses inherent in power re-quired for pumps and fans; and related energy usessuch as for soot blowing, air compression, and simi-lar services.

(3) Both turbine and plant heat rates, as above,are usually based on calculations of cycle perform-ance at specified steady state loads and well defined,optimum operating conditions. Such heat rates areseldom achieved in practice except under controlledor test conditions.

(4) Plant operating heat rates are long termaverage actual heat rates and include other suchlosses and energy uses as non-cycle auxiliaries,

plant lighting, air conditioning and heating, generalwater supply, startup and shutdown losses, fuel de-terioration losses, and related items. The gradualand inevitable deterioration of equipment, and fail-ure to operate at optimum conditions, are reflectedin plant operating heat rate data.

d. Plant economy calculations. Calculations, esti-mates, and predictions of steam plant performancewill allow for all normal and expected losses andloads and should, therefore, reflect predictions ofmonthly or annual net operating heat rates andcosts. Electric and district heating distributionlosses are not usually charged to the power plantbut should be recognized and allowed for in capacityand cost analyses. The designer is required to devel-op and optimize a cycle heat balance during the con-ceptual or preliminary design phase of the project.The heat balance depicts, on a simplified flow dia-gram of the cycle, all significant fluid mass flowrates, fluid pressures and temperatures, fluid en-thalpies, electric power output, and calculated cycleheat rates based on these factors. A heat balance isusually developed for various increments of plantload (i.e., 25%, 50%, 75%, 100% and VWO (valveswide open)). Computer programs have been devel-oped which can quickly optimize a particular cycleheat rate using iterative heat balance calculations.Use of such a program should be considered.

e. Cogeneration performance. There is no gener-ally accepted method of defining the energy effi-ciency or heat rates of cogeneration cycles. Variousmethods are used, and any rational method is valid.The difference in value (per Btu) between prime en-ergy (i.e., electric power) and secondary or low levelenergy (heating steam) should be recognized. Referto discussion of cogeneration cycles below.

3-4. Cogeneration cyclesa. Definition. In steam power plant practice, co-

generation normally describes an arrangementwhereby high pressure steam is passed through aturbine prime mover to produce electrical power,and thence from the turbine exhaust (or extraction)opening to a lower pressure steam (or heat) distribu-tion system for general heating, refrigeration, orprocess use.

b. Common medium. Steam power cycles are par-ticularly applicable to cogeneration situations be-cause the actual cycle medium, steam, is also a con-venient medium for area distribution of heat.

(1) The choice of the steam distribution pres-sure will be a balance between the costs of distribu-tion which are slightly lower at high pressure, andthe gain in electrical power output by selection of alower turbine exhaust or extraction pressure.

(2) Often the early selection of a relatively low

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TM 5-811-6

3-4

steam distribution pressure is easily accommodatedin the design of distribution and utilization systems,whereas the hasty selection of a relatively highsteam distribution pressure may not be recognizedas a distinct economic penalty on the steam powerplant cycle.

(3) Hot water heat distribution may also be ap-plicable as a district heating medium with the hotwater being cooled in the utilization equipment andreturned to the power plant for reheating in a heatexchange with exhaust (or extraction) steam.

c. Relative economy. When the exhaust (or ex-traction) steam from a cogeneration plant can beutilized for heating, refrigeration, or process pur-poses in reasonable phase with the required electricpower load, there is a marked economy of fuel ener-gy because the major condensing loss of the conven-tional steam power plant (Rankine) cycle is avoided.If a good balance can be attained, up to 75 percent ofthe total fuel energy can be utilized as comparedwith about 40 percent for the best and largest Ran-kine cycle plants and about 25 to 30 percent forsmall Rankine cycle systems.

d. Cycle types. The two major steam power cogen-eration cycles, which may be combined in the sameplant or establishment, are:

TM 5-811-6

(1) Back pressure cycle. In this type of plant,the entire flow to the turbine is exhausted (or ex-tracted) for heating steam use. This cycle is themore effective for heat economy and for relativelylower cost of turbine equipment, because the primemover is smaller and simpler and requires no con-denser and circulating water system. Back pressureturbine generators are limited in electrical output bythe amount of exhaust steam required by the heatload and are often governed by the exhaust steamload. They, therefore, usually operate in electricalparallel with other generators.

(2) Extraction-condensing cycles. Where theelectrical demand does not correspond to the heatdemand, or where the electrical load must be carriedat times of very low (or zero) heat demand, then con-densing-controlled extraction steam turbine primemovers as shown in Figure 3-3 may be applicable.Such a turbine is arranged to carry a specified elec-trical capacity either by a simple condensing cycleor a combination of extraction and condensing.While very flexible, the extraction machine is rela-tively complicated, requires complete condensingand heat rejection equipment, and must always passa critical minimum flow of steam to its condenser tocool the low pressure buckets.

.

.

N A V F A C D M 3 Figure 3-3. Typical condensing-controlled extinction cycle.

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TM 5-811-6

e. Criteria for cogeneration. For minimum eco-nomic feasibility, cogeneration cycles will meet thefollowing criteria:

(1) Load balance. There should be a reasonablybalanced relationship between the peak and normalrequirements for electric power and heat. Thepeak/normal ratio should not exceed 2:1.

(2) Load coincidence. There should be a fairlyhigh coincidence, not less than 70%, of time andquantity demands for electrical power and heat.

(3) Size. While there is no absolute minimumsize of steam power plant which can be built for co-generation, a conventional steam (cogeneration)plant will be practical and economical only abovesome minimum size or capacity, below which othertypes of cogeneration, diesel or gas turbine becomemore economical and convenient.

(4) Distribution medium. Any cogenerationplant will be more effective and economical if theheat distribution medium is chosen at the lowestpossible steam pressure or lowest possible hot watertemperature. The power energy delivered by the tur-bine is highest when the exhaust steam pressure islowest. Substantial cycle improvement can be madeby selecting an exhaust steam pressure of 40 psigrather than 125 psig, for example. Hot water heatdistribution will also be considered where practicalor convenient, because hot water temperatures of200 to 240º F can be delivered with exhaust steampressure as low as 20 to 50 psig. The balance be-tween distribution system and heat exchangercosts, and power cycle effectiveness will be opti-mized.

3-5. Selection of cycle steam conditionsa. Balanced costs and economy. For a new or iso-

lated plant, the choice of initial steam conditionsshould be a balance between enhanced operatingeconomy at higher pressures and temperatures, andgenerally lower first costs and less difficult opera-tion at lower pressures and temperatures. Realisticprojections of future fuel costs may tend to justifyhigher pressures and temperatures, but such factorsas lower availability y, higher maintenance costs,more difficult operation, and more elaborate watertreatment will also be considered.

b. Extension of existing plant. Where a newsteam power plant is to be installed near an existingsteam power or steam generation plant, careful con-sideration will be given to extending or parallelingthe existing initial steam generating conditions. Ifexisting steam generators are simply not usable inthe new plant cycle, it may be appropriate to retirethem or to retain them for emergency or standbyservice only. If boilers are retained for standby serv-ice only, steps will be taken in the project design for

protection against internal corrosion.c. Special considerations. Where the special cir-

cumstances of the establishment to be served aresignificant factors in power cycle selection, the following considerations may apply:

(1) Electrical isolation. Where the proposedplant is not to be interconnected with any local elec-tric utility service, the selection of a simpler, lowerpressure plant may be indicated for easier operationand better reliability y.

(2) Geographic isolation. Plants to be installedat great distances from sources of spare parts, main-tenance services, and operating supplies may require special consideration of simplified cycles, re-dundant capacity and equipment, and highest prac-tical reliability. Special maintenance tools and facilities may be required, the cost of which would be af-fected by the basic cycle design.

(3) Weather conditions. Plants to be installedunder extreme weather conditions will require spe-cial consideration of weather protection, reliability,and redundancy. Heat rejection requires special de-sign consideration in either very hot or very coldweather conditions. For arctic weather conditions,circulating hot water for the heat distribution medi-um has many advantages over steam, and the use ofan antifreeze solution in lieu of pure water as a distribution medium should receive consideration.

3-6. Cycle equipmenta. General requirements. In addition to the prime

movers, alternators, and steam generators, a com-plete power plant cycle includes a number of second-ary elements which affect the economy and perform-ance of the plant.

b. Major equipment. Refer to other parts of this manual for detailed information on steam turbinedriven electric generators and steam generators.

c. Secondary cycle elements. Other equipmentitems affecting cycle performance, but subordinateto the steam generators and turbine generators, arealso described in other parts of this chapter.

3-7. Steam power plant arrangementa. General. Small units utilize the transverse ar-

rangement in the turbine generator bay while thelarger utility units are very long and require end-to-end arrangement of the turbine generators.

b. Typical small plants. Figures 3-4 and 3-6 showtypical transverse small plant arrangements. Smallunits less than 5000 kW may have the condensers atthe same level as the turbine generator for economyas shown in Figure 3-4. Figure 3-6 indicates thecritical turbine room bay dimensions and the basicoverall dimensions for the small power plants shownin Figure 3-5.

TM 5-811-6

U. S. Army Corps of Engineers

Figure 3-4. Typical small 2-unit powerplant “A”.

3-7

TM 5-811-6

a

3-8

TM 5-811-6

Section Il. STEAM GENERATORS AND AUXILIARY SYSTEMS.

tors for a steam power plant can be classified bytype of fuel, by unit size, and by final steam condi-tion. Units can also be classified by type of draft, bymethod of assembly, by degree of weather protec-tion and by load factor application.

(1) Fuel, general. Type of fuel has a major im-pact on the general plant design in addition to thesteam generator. Fuel selection may be dictated byconsiderations of policy and external circumstances

3-8. Steam generator conventionaltypes and characteristics

a. Introduction. Number, size, and outlet steam-ing conditions of the steam generators will be as de-termined in planning studies and confirmed in the fi-nal project criteria prior to plant design activities.Note general criteria given in Section I of this chapter under discussion of typical plants and cycles.

b. Types and classes. Conventional steam genera-.!

.

AND CONDENSER SUPPLIERS SELECTED.

36433116611.37 . 53 . 71.25 . 5517.55811

NOTE:

U S .

DIMENSIONS IN TABLE ARE APPLICABLE TO FIG. 3-5

Army Corps of Engineers

Figure 3-6. Critical turbine room bay and power plant “B” dimensions.

3-9

TM 5-811-6

unrelated to plant costs, convenience, or location.Units designed for solid fuels (coal, lignite, or solidwaste) or designed for combinations of solid, liquid,and gaseous fuel are larger and more complex thanunits designed for fuel oil or fuel gas only.

(2) Fuel coal. The qualities or characteristics ofparticular coal fuels having significant impact onsteam generator design and arrangement are: heat-ing value, ash content, ash fusion temperature, fri-ability, grindability, moisture, and volatile contentas shown in Table 3-2. For spreader stoker firing,the size, gradation, or mixture of particle sizes affect

Table 3-2.Characteristic

stoker and grate selection, performance, and main-tenance. For pulverized coal firing, grindability is amajor consideration, and moisture content before and after local preparation must be considered. Coalburning equipment and related parts of the steamgenerator will be specified to match the specificcharacteristics of a preselected coal fuel as well asthey can be determined at the time of design.

(3) Unit sizes. Larger numbers of smaller steamgenerators will tend to improve plant reliability andflexibility for maintenance. Smaller numbers of larg-er steam generators will result in lower first costs

Fuel Characteristcs.Effects

Coal

Heat balance.

Handling and efficiency loss.Ignition and theoretical air.Freight, storage, handling, air pollution.Slagging, allowable heat release,allowable furnace exit gas temperature.Heat balance, fuel cost.Handling and storage.Crushing and pulverizing.Crushing , segregation, and spreadingover fuel bed.Allowable temp. of metal contactingflue gas; removal from flue gas.

Oil

Heat balance.Fuel cost.Preheating, pumping, firing.Pumping and metering.Vapor locking of pump suction.Heat balance, fuel cost.Allowable temp. of metal contactingflue gas; removal from flue gas.

Gas

Heat balance.Pressure, f ir ing, fuel cost .Metering.Heat balance, fuel cost.Insignificant.

NAVFAC DM3

3-10

TM 5-811-6

per unit of capacity and may permit the use of de-sign features and arrangements not available onsmaller units. Larger units are inherently more effi-cient, and will normally have more efficient draftfans, better steam temperature control, and bettercontrol of steam solids.

(4) Final steam conditions. Desired pressureand temperature of the superheater outlet steam(and to a lesser extent feedwater temperature) willhave a marked effect on the design and cost of asteam generator. The higher the pressure the heav-ier the pressure parts, and the higher the steam tem-perature the greater the superheater surface areaand the more costly the tube material. In addition tothis, however, boiler natural circulation problems in-crease with higher pressures because the densitiesof the saturated water and steam approach each oth-er. In consequence, higher pressure boilers requiremore height and generally are of different designthan boilers of 200 psig and less as used for generalspace heating and process application.

(5) Type of draft.(a) Balanced draft. Steam generators for elec-

tric generating stations are usually of the so called“balanced draft” type with both forced and induceddraft fans. This type of draft system uses one ormore forced draft fans to supply combustion air un-

der pressure to the burners (or under the grate) andone or more induced draft fans to carry the hot com-bustion gases from the furnace to the atmosphere; aslightly negative pressure is maintained in the fur-nace by the induced draft fans so that any gas leak-age will be into rather than out of the furnace. Nat-ural draft will be utilized to take care of the chimneyor stack resistance while the remainder of the draftfriction from the furnace to the chimney entrance ishandled by the induced draft fans.

(b) Choice of draft. Except for special casessuch as for an overseas power plant in low cost fuelareas, balanced draft, steam generators will be spec-ified for steam electric generating stations.

(6) Method of assembly. A major division ofsteam generators is made between packaged or fac-tory assembled units and larger field erected units.Factory assembled units are usually designed forconvenient shipment by railroad or motor truck,complete with pressure parts, supporting structure,and enclosure in one or a few assemblies. Theseunits are characteristically bottom supported, whilethe larger and more complex power steam gener-ators are field erected, usually top supported.

(7) Degree of weather protection. For all typesand sizes of steam generators, a choice must bemade between indoor, outdoor and semi-outdoor in-stallation. An outdoor installation is usually less ex-pensive in first cost which permits a reduced general

building construction costs. Aesthetic, environmen-tal, or weather conditions may require indoor instal-lation, although outdoors units have been used SUC- cessfully in a variety of cold or otherwise hostile cli-mates. In climates subject to cold weather, 30 “F. for7 continuous days, outdoor units will require electri-cally or steam traced piping and appurtenances toprevent freezing. The firing aisle will be enclosedeither as part of the main power plant building or asa separate weather protected enclosure; and theends of the steam drum and retractable soot blowerswill be enclosed and heated for operator convenienceand maintenance.

(8) Load factor application. As with all parts ofthe plant cycle, the load factor on which the steamgenerator is to be operated affects design and costfactors. Units with load factors exceeding 50% willbe selected and designed for relatively higher effi-ciencies, and more conservative parameters for fur-nace volume, heat transfer surface, and numbersand types of auxiliaries. Plants with load factorsless than 50% will be served by relatively less ex-pensive, smaller and less durable equipment.

3-9. Other steam generator characteris-tics

a. Water tube and waterwell design. Power plantboilers will be of the water welled or water cooledfurnace types, in which the entire interior surface ofthe furnace is lined with steam generating heatingsurface in the form of closely spaced tubes usuallyall welded together in a gas tight enclosure.

b. Superheated steam. Depending on manufac-turer’s design some power boilers are designed todeliver superheated steam because of the require-ments of the steam power cycle. A certain portion ofthe total boiler heating surface is arranged to addsuperheat energy to the steam flow. In superheaterdesign, a balance of radiant and convective super-heat surfaces will provide a reasonable superheatcharacteristic. With high ‘pressure - high temper-ature turbine generators, it is usually desirable toprovide superheat controls to obtain a flat charac-teristic down to at least 50 to 60 percent of load.This is done by installing excess superheat surfaceand then attemperating by means of spray water atthe higher loads. In some instances, boilers are de-signed to obtain superheat control by means of tilt-ing burners which change the heat absorption pat-tern in the steam generator, although supplemen-tary attemperation is also provided with such a con-trol system.

c. Balanced heating surface and volumetric de-sign parameters. Steam generator design requiresadequate and reasonable amounts of heating surface

3-11

TM 5-811-6

and furnace volume for acceptable performance andlongevity.

(1) Evaporative heating surface. For its ratedcapacity output, an adequate total of evaporative orsteam generating heat transfer surface is required,which is usually a combination of furnace wall ra-diant surface and boiler convection surface. Bal-anced design will provide adequate but not exces-sive heat flux through such surfaces to insure effec-tive circulation, steam generation and efficiency.

(2) Superheater surface. For the required heattransfer, temperature control and protection of met-al parts, the superheater must be designed for a bal-ance between total surface, total steam flow area,and relative exposure to radiant convection heatsources. Superheaters may be of the drainable ornon-drainable types. Non-drainable types offer cer-tain advantages of cost, simplicity, and arrange-ment, but are vulnerable to damage on startup.Therefore, units requiring frequent cycles of shut-down and startup operations should be consideredfor fully drainable superheaters. With some boilerdesigns this may not be possible.

(3) Furnace volume. For a given steam gener-ator capacity rating, a larger furnace provides lowerfurnace temperatures, less probability of hot spots,and a lower heat flux through the larger furnace wallsurface. Flame impingement and slagging, partic-ularly with pulverized coal fuel, can be controlled orprevented with increased furnace size.

(4) General criteria. Steam generator designwill specify conservative lower limits of total heat-ing surface, furnace wall surface and furnace vol-ume, as well as the limits of superheat temperaturecontrol range. Furnace volume and surfaces will besized to insure trouble free operation.

(5) Specific criteria. Steam generator specifica-tions set minimum requirements for Btu heat re-lease per cubic foot of furnace volume, for Btu heatrelease per square foot of effective radiant heatingsurface and, in the case of spreader stokers, for Btuper square foot of grate. Such parameters are not setforth in this manual, however, because of the widerange of fuels which can affect these equipment de-sign considerations. The establishment of arbitrarylimitations which may handicap the geometry offurnace designs is inappropriate. Prior to settingfurnace geometry parameters, and after the typeand grade of fuel are established and the particularservice conditions are determined, the power plantdesigner will consult boiler manufacturers to insurethat steam generator specifications are capable ofbeing met.

d. Single unit versus steam header system. Forcogeneration plants, especially in isolated locationsor for units of 10,000 kW and less, a parallel boiler or

steam header system may be more reliable and moreeconomical than unit operation. Where a group ofsteam turbine prime movers of different types; i.e., one back pressure unit plus one condensing/extrac-tion unit are installed together, overall economy canbe enhanced by a header (or parallel) boiler arrange-ment.

3-10. Steam generator special typesa. Circulation. Water tube boilers will be specified

to be of natural circulation. The exception to thisrule is for wasteheat boilers which frequently are a . .special type of extended surface heat exchanger de-signed for forced circulation.

b. Fludized bed combustion. The fluidized bed boiler has the ability to produce steam in an environ-mentally accepted manner in controlling the stackemission of sulfur oxides by absorption of sulfur inthe fuel bed as well as nitrogen oxides because of itsrelatively low fire box temperature. The fluidizedbed boiler is a viable alternative to a spreader stokerunit. A fluidized bed steam generator consists of afluidized bed combustor with a more or less conven-tional steam generator which includes radiant andconvection boiler heat transfer surfaces plus heat re-covery equipment, draft fans, and the usual array ofsteam generator auxiliaries. A typical fluidized bed boiler is shown in Figure 3-7.

3-11. Major auxiliary systems.a. Burners.

(1) Oil burners. Fuel oil is introduced throughoil burners, which deliver finely divided or atomizedliquid fuel in a suitable pattern for mixing with com-bustion air at the burner opening. Atomizing meth-ods are classified as pressure or mechanical type, airatomizing and steam atomizing type. Pressureatomization is usually more economical but is alsomore complex and presents problems of control,poor turndown, operation and maintenance. Therange of fuel flows obtainable is more limited withpressure atomization. Steam atomization is simpleto operate, reliable, and has a wide range, but con-sumes a portion of the boiler steam output and addsmoisture to the furnace gases. Generally, steamatomization will be used when makeup water is rela-tively inexpensive, and for smaller, lower pressureplants. Air atomization will be used for plants burn-ing light liquid fuels, or when steam reacts ad-versely with the fuel, i.e., high sulfur oils.

(2) Gas and coal burners. Natural gas or pulver-ized coal will be delivered to the burner for mixingwith combustion air supply at the burner opening.Pulverized coal will be delivered by heated, pressurized primary air.

(3) Burner accessories. Oil, gas and pulverized

3-12

coal burners will be equipped with adjustable airguide registers designed to control and shape the airflow into the furnace, Some burner designs also pro-vide for automatic insertion and withdrawal of vary-ing size oil burner nozzles as load and operating con-ditions require.

(4) Number of burners. The number of burnersrequired is a function both of load requirements andboiler manufacturer design. For the former, the indi-vidual burner turndown ratios per burner are pro-vided in Table 3-3. Turndown ratios in excess ofthose listed can be achieved through the use of mul-tiple burners. Manufacturer design limits capacityof each burner to that compatible with furnace flameand gas flow patterns, exposure and damage to

STEAM OUTLET TOSUPERHEATER IN BED

TM 5-811-6

heating surfaces, and convenience of operation andcontrol.

(5) Burner managerment systems. Plant safetypractices require power plant fuel burners to beequipped with comprehensive burner control andsafety systems to prevent unsafe or dangerous con-ditions which may lead to furnace explosions. Theprimary purpose of a burner management system issafety which is provided by interlocks, furnacepurge cycles and fail safe devices.

b. Pulverizes. The pulverizers (mills) are an essen-tial part of powdered coal burning equipment, andare usually located adjacent to the steam generatorand burners, but in a position to receive coal bygravity from the coal silo. The coal pulverizers grind

k 1111111 rlu-SPREAOER

U.S. Army Corps of Engineers

Figure 3-7. Fluidized bed combustion boiler.

3-13

TM 5-811-6

and classify the coal fuel to specific particle sizes forrapid and efficient burning. Reliable and safe pulver-izing equipment is essential for steam generator op-eration. Pulverized coal burning will not be specifiedfor boilers smaller than 150,000 lb/hour.

c. Stokers and grates. For small and mediumsized coal burning steam generators, less than150,000 lb/hour, coal stokers or fluidized bed unitswill be used. For power boilers, spreader stokerswith traveling grates are used. Other types ofstokers (retort, underfeed, or overfeed types) aregenerally obsolete for power plant use except per-haps for special fuels such as anthracite.

(1) Spreader stokers typically deliver sized coal,with some proportion of fines, by throwing it intothe furnace where part of the fuel burns in suspen-sion and the balance falls to the traveling grate forburnout. Stoker fired units will have two or morespreader feeder units, each delivering fuel to its ownseparate grate area. Stoker fired units are less re-sponsive to load changes because a large proportionof the fuel burns on the grate for long time periods(minutes). Where the plant demand is expected to in-

clude sudden load changes, pulverized coal feedersare to be used.

(2) Grate operation requires close and skillfuloperator attention, and overall plant performance is sensitive to fuel sizing and operator experience.Grates for stoker fired units occupy a large part ofthe furnace floor and must be integrated with ash re-moval and handling systems. A high proportion ofstoker ash must be removed from the grates in awide range of particle sizes and characteristics al-though some unburned carbon and fly ash is carriedout of the furnace by the flue gas. In contrast, alarger proportion of pulverized coal ash leaves the .furnace with the gas flow as finely divided particu-late,

(3) Discharged ash is allowed to COOl in the ash hopper at the end of the grate and is then sometimesput through a clinker grinder prior to removal in thevacuum ash handling system described elsewhere inthis manual.

d. Draft fans, ducts and flues.(1) Draft fans.

(a) Air delivery to the furnace and flue gas re-

Table 3-3. Individual Burner Turndown Ratios.

Burner Type Turndown Ratio

NATURAL GM

Spud or Ring Type

HEAVY FUEL OIL

Steam Atomizing

Mechanical Atomizing

COAL

Pulverized

Spreader-Stoker

Fluidized Bed (single bed)

5:1 to 10:1

5:1 to 10:1

3:1 to 10:1

3:1

2 :1 to 3 :1

2 :1 to 3 :1


3-14

II

.

.

moval will be provided by power driven draft fansdesigned for adequate volumes and pressures of airand gas flow. Typical theoretical air requirementsare shown in Figure 3-8 to which must be added ex-cess air which varies with type of firing, plus fanmargins on both volumetric and pressure capacityfor reliable full load operation. Oxygen and carbondioxide in products of combustion for variousamounts of excess air are also shown in Figure 3-8.

(b) Calculations of air and gas quantities andpressure drops are necessary. Since fans are heavypower consumers, for larger fans considerationshould be given to the use of back pressure steamturbine drives for economy, reliability and their abil-it y to provide speed variation. Multiple fans on eachboiler unit will add to first costs but will providemore flexibility and reliability . Type of fan drivesand number of fans will be considered for cost effec-tiveness. Fan speed will be conservatively selected,and silencers will be provided in those cases wherenoise by fans exceeds 80 decibels.

(c) Power plant steam generator units de-signed for coal or oil will use balanced draft designwith both forced and induced draft fans arranged forclosely controlled negative furnace pressure.

(2) Ducts and flues. Air ducts and gas flues willbe adequate in size and structural strength and de-signed with provision for expansion, support, corro-

TM 5-811-6

sion resistance and overall gas tightness. Adequatespace and weight capacity will be allowed in overallplant arrangement to avoid awkward, noisy or mar-ginal fan, duct and flue systems. Final steam gener-ator design will insure that fan capacities (especiallypressure) are matched properly to realistic air andgas path losses considering operation with dirtyboilers and under abnormal operating conditions.Damper durability and control characteristics willbe carefully designed; dampers used for control pur-poses will be of opposed blade construction.

e. Heat recovery. Overall design criteria requirehighest fuel efficiency for a power boiler; therefore,steam generators will be provided with heat recov-ery equipment of two principal types: air pre-heater and economizers.

(1) Efficiency effects. Both principal types ofheat recovery equipment remove relatively low levelheat from the flue gases prior to flue gas dischargeto the atmosphere, using boiler fluid media (air orwater) which can effectively absorb such low levelenergy. Such equipment adds to the cost, complex-ity and operational skills required, which will be bal-anced by the plant designer against the life cyclefuel savings.

(2) Air preheater. Simple tubular surfaceheaters will be specified for smaller units and the re-generative type heater for larger boilers. To mini-

3-15

TM 5-811-6

mize corrosion and acid/moisture damage, especiallywith dirty and high sulphur fuels, special alloy steelwill be used in the low temperature heat transfersurface (replaceable tubes or “baskets”) of air pre-heater. Steam coil air heaters will be installed tomaintain certain minimum inlet air (and metal) tem-peratures and thus protect the main preheater fromcorrosion at low loads or low ambient air tempera-tures. Figure 3-9 illustrates the usual range of mini-mum metal temperatures for heat recovery equip-ment.

(3) Economizers. Either an economizer or an airheater or a balanced selection of both as is usual in apower boiler will be provided, allowing also for tur-bine cycle feedwater stage heating.

f. Stacks.(1) Delivery of flue gases to the atmosphere

through a flue gas stack or chimney will be pro-vided.

(2) Stacks and chimneys will be designed to dis-charge their gases without adverse local effects. Dis-persion patterns and considerations will be treatedduring design.

(3) Stacks and chimneys will be sized with dueregard to natural draft and stack friction with

290

NAVFAC DM3

Figure 3-9. Minimum metal temperatures for boiler heatrecovery equipment.

height sometimes limited by aesthetic or other non-economic considerations. Draft is a function of den-sit y difference between the hot stack gases and ambient air, and a number of formulas are available forcalculating draft and friction. Utilize draft of thestack or chimney only to overcome friction withinthe chimney with the induced draft fan(s) supplyingstack or chimney entrance. Maintain relatively highgas exit velocities (50 to 60 feet per second) to ejectgases as high above ground level as possible. Reheat(usually by steam) will be provided if the gases aretreated (and cooled) in a flue gas desulfurization scrubber prior to entering the stack to add buoy-ancy and prevent their settling to the ground afterejection to the atmosphere. Insure that downwashdue to wind and building effects does not drive the flue gas to the ground.

g. Flue gas cleanup. The requirements for flue gascleanup will be determined during design.

(1) Design considerations. The extent and na-ture of the air pollution problem will be analyzedprior to specifying the environmental control sys-tem for the steam generator. The system will meetall applicable requirements, and the application willbe the most economically feasible method of accom-plishment. All alternative solutions to the problemwill be considered which will satisfy the given loadand which will produce the least objectionablewastes. Plant design will be such as to accommodate future additions or modifications at minimum cost.Questions concerning unusual problems, unique ap-placations or marginal and future requirements willbe directed to the design agency having jurisdictionover the project. Table 3-4 shows the emission lev-els allowable under the National Ambient AirQuality Standards.

(2) Particulate control. Removal of flue gas particulate material is broadly divided into mechanicaldust collectors, electrostatic precipitators, bag fil-ters, and gas scrubbing systems. For power plantsof the size range here considered estimated uncon-trolled emission levels of various pollutants areshown in Table 3-5. Environmental regulations re-quire control of particulate, sulfur oxides and nitro-gen oxides. For reference purposes in this manual,typical control equipment performance is shown inTable 3-6, 3-7, 3-8, 3-9, 3-10 and 3-11. These onlyprovide general guidance. The designer will refer toTM 5-815-l/AFR 19-6/NAVFAC DM-3.15 for de-tails of this equipment and related computationalrequirements and design criteria.

(a) Mechanical collectors. For oil fired steam generators with output steaming capacities lessthan 200,000 pounds per hour, mechanical (centrifugal) type dust collectors may be effective and eco-nomical depending on the applicable emission stand-

3-16

ards. For a coal fired boiler with a spreader stoker, amechanical collector in series with an electrostaticprecipitator or baghouse also might be considered.Performance requirements and technical environ-mental standards must be carefully matched, andultimate performance warranties and tests requirecareful and explicit definitions. Collected dust froma mechanical collector containing a large proportionof combustibles may be reinfected into the furnacefor final burnout; this will increase steam generator

TM 5-811-6

efficiency slightly but also will increase collectordust loading and carryover. Ultimate collecteddust material must be handled and disposed of sys-tematically to avoid objectionable environmental ef-fects.

(b) Electrostatic precipitators. For pulverizedcoal firing, adequate particulate control will requireelectrostatic precipitators (ESP). ESP systems arewell developed and effective, but add substantialcapital and maintenance costs. Very high percent-

3-17

Pollutant

Part i cu la te

Sulfur Oxides

Nitrogen Oxides

COAL FIRED(Lb of Pollutant/Ton

Table3-5. Uncontrolled Emissions.

OIL FIREDof Coal) (Lb of Pollutant/1000 Gal)

Pulverized Stokers or

NATURAL GAS( L b o f P o l l u t a n t / 1 06 F t3 )

1. The letter A indicates that the weight percentage of ash in the coal should be multiplied bythe value given. Example: If the factor is 16 and the ash content is 10 percent, the particulateemissions before the control equipment would be 10 times 16, or 160 pounds of particulate per tonof coal.

2. Without fly ash reinfection. With fly ash reinfection use 20A.

3. S equals the sulfur content, use like the factor A (see Note 1 above) for estimate emissions.

U.S. Environmental Protection Agency

2-6

50-70

50

90-95 Industrial a n d

util i ty boilerParticulate control.


Table 3-2! Characteristics of Scrubbers for Particulate Control.

Partic leCollection Water UsageEff ic iency Per 1000 Gal/Min

80 3-5

InternalVelocity

Ft/SecPressure Drop

In. H O

3-8

Gas FlowFt /MinScrubber Type Energy Type

Low EnergyCentrifugalScrubber

1,000-20,000

50-150

Impingement &Entrainment

Low Energy 4-20 500-50,000

50-150 60-90 10-40

Venturi High Energy 4-200 200-150,000

200-600 95-99 5-7

Ejector Venturi High Energy 10-50 500- 200-500 90-98 70-14510,000


T y p e

Hot ESP

Cold ESP

Wet ESP

Table 3-8. Characteristics of Electrostatic Precipitators (ESP) for Particulate Control.

Operating , R e s i s t i v i t yTemperature at 300º F

°F ohm-cm

600+ Greater Than1 01 2

300 Less Than1 01 0

3 0 0 - Greater Than1 01 2 b e l o w1 04


P r e s s u r eGas DropFlow I n . o f

F t / M i n Water

100,000+ Less Than1"

Table 3-9. Characteristics of Baghouses for Particulate Control.

Pressure Loss Filter Ratio(Inches of (cfm/ft

System Type Water) Eff ic iency Cloth Type Cloth Area) Recommended Application

Shaker 3-6 99+% Woven 1-5 Dust with good filtercleaning properties,intermittent collection.

Reverse Flow 3-6 99+% Woven 1-5 Dust with good filter cleaningproperties, high temperaturecollection (incinerator fly-ash) with glass bags.

Pulse Jet

Reverse Jet

Envelope

3-6

3-8

3-6


99+% Felted

99+% Felted

99+% Woven

4-20

10-30

1-5

Efficient for coal and oil flyash collection.

Collection of fine dusts andfumes.

Collection of highly abrasivedust .

Table 3-10. Characteristics of Flue-Gas Desulfurization Systems for Particulate Control.

Retrofit toExisting

Installations

Yea

Pressure Drop(Inches of Water)

SO Removal Recovery andRegeneration

No Recoveryof Limestone

No Recoveryof Lime

No Recoveryof Lime

Recovery of MgOand Sulfuric Acid

Recovery of NaS03

OperationalReliabilityEfficiency (%)

30-40%

System Type

High

High

Low

Low

Unknown

Unknown

Unknown

Unknown

1) Limestone BoilerInjection Type

Less Than 6“

Greater Than 6“

Greater Than 6“

Greater Than 6“

Greater Than 6“

Yea2) Limestone, SrubberInjection Type

30-40%

Yea3) Lime, Scrubber,Injection Type

90%+

Yea4) Magnesium Oxide

90%+5) Wellman-Lordand Elemental Sulfur

6) Catalyticoxidation

Recovery of 80%H2S04

No85% May be as high as 24”

Tray Tower PressureDrop 1.6-2.0 in.H2O/tray, w/Venturiadd 10-14 in. H2O

Little Recoveryof Sodium Carbonate

Yea7) Single AlkaliSystems

90%+

Yea8) Dual Alkali 90-95%+ Regeneration ofSodium Hydroxideand Sodium Sulfites


g

Tabble 3-11. Techniques for Nitrogen Oxide Control.

Technique

Load Reduction

Low Excess Air Firing

Two Stage Conbustion

Coal

Oil

Gas

Potential

Off-Stoichiometric Combustion

Coal

Reduced Combustion AirPreheat

NO Reduction (%)

Flue Gas Recirculation

15 to 40

30

40

50

45

10-50

20-50


Advantages Disadvantages

Easily implemented; no additional Reduction in generating capacity;equipment required; reduced particu- possible reduction in boiler thermallate and SOX emissions. thermal efficiency.

Increased boiler thermal efficiency; A combustion control system whichpossible reduction in particulate closely monitors and controls fuel/emissions may be combined with a load air ratios is required.reduction to obtain additional NOx

emission decrease; reduction in hightemperature corrosion and ash deposition.

- - - Boiler windboxes must be designed forthis application.

- --

- - -

- - -

Possible improvement in combustionefficiency end reduction in particu-late emissions.

Furnace corrosion and particulateemissions may increase.

Control of alternate fuel rich/andfuel lean burners may be a problemduring transient load conditions.

Not applicable to coal or oil firedunits; reduction in boiler thermalefficiency; increase in exit gasvolume and temperature; reduction inboiler load.

Boiler windbox must be modified tohandle the additional gas volume;ductwork, fans and Controls required.

TM 5-811-6

ages of particulate removal can be attained (99 per-cent, plus) but precipitators are sensitive to ashcomposition, fuel additives, flue gas temperaturesand moisture content, and even weather conditions.ESP’s are frequently used with and ahead of fluegas washing and desulfurization systems. They maybe either hot precipitators ahead of the air preheaterin the gas path or cold precipitators after the air pre-heater. Hot precipitators are more expensive be-cause of the larger volume of gas to be handled andtemperature influence on materials. But they aresometimes necessary for low sulfur fuels where coldprecipitators are relatively inefficient.

(c) Bag filters. Effective particulate removalmay be obtained with bag filter systems or baghouses, which mechanically filter the gas by passagethrough specially designed filter fabric surfaces.Bag filters are especially effective on very fine parti-cles, and at relatively low flue gas temperatures.They may be used to improve or upgrade other par-ticulate collection systems such as centrifugal col-lectors. Also they are probably the most economicchoice for most medium and small size coal firedsteam generators.

(d) Flue gas desulfurization. While variousgaseous pollutants are subject to environmentalcontrol and limitation, the pollutants which must beremoved from the power plant flue gases are the ox-

ides of sulfur (SO2 and SO3). Many flue gas desulfuri-ztion (FGD) scrubbing systems to control SO2 andSO3stack emission have been installed and oper-ated, with wide variations in effectiveness, reliabil-ity, longevity and cost. For small or medium sizedpower plants, FGD systems should be avoided ifpossible by the use of low sulfur fuel. If the parame-ters of the project indicate that a FGD system is re-quired, adequate allowances for redundancy, capitalcost, operating costs, space, and environmental im-pact will be made. Alternatively, a fluidized bedboiler (para. 3-10 c) may be a better economic choicefor such a project.

(1) Wet scrubbers utilize either limestone,lime, or a combination of lime and soda ash as sor-bents for the SO2 and SO3 in the boiler flue gasstream. A mixed slurry of the sorbent material issprayed into the flue gas duct where it mixes withand wets the particulate in the gas stream. The S02

and S09 reacts with the calcium hydroxide of theslurry to form calcium sulfate. The gas then contin-ues to a separator tower where the solids and excesssolution settle and separate from the water vaporsaturated gas stream which vents to the atmospherethrough the boiler stack. Wet scrubbers permit theuse of coal with a sulfur content as high as 5 percent.

(2) Dry scrubbers generally utilize a dilutedsolution of slaked lime slurry which is atomized by

compressed air and injected into the boiler flue gasstream. SO2 and SO3 in the flue gas is absorbed bythe slurry droplets and reacts with the calcium hy-droxide of the slurry to form calcium sulfite. Evapo-ration of the water in the slurry droplets occurs si-multaneously with the reaction. The dry flue gasthen travels to a bag filter system and then to theboiler stack. The bag filter system collects the boilerexit solid particles and the dried reaction products.Additional remaining SO2 and SO3 are removed bythe flue gas filtering through the accumulation onthe surface of the bag filters, Dry scrubbers permitthe use of coal with a sulfur content as high as 3 per-cent.

(3) Induced draft fan requirements. Induceddraft fans will be designed with sufficient capacityto produce the required flow while overcoming thestatic pressure losses associated with the ductwork,economizer, air preheater, and air pollution controlequipment under all operating (clean and dirt y) con-ditions.

(4) Waste removal. Flue gas cleanup systemsusually produce substantial quantities of wasteproducts, often much greater in mass than the sub-stances actually removed from the exit gases. De-sign and arrangement must allow for dewateringand stabilization of FGD sludge, removal, storageand disposal of waste products with due regard forenvironmental impacts.

3-12. Minor auxiliary systemsVarious minor auxiliary systems and componentsare vital parts of the steam generator.

a. Piping and valves. Various piping systems aredefined as parts of the complete boiler (refer to theASME Boiler Code), and must be designed for safeand effective service; this includes steam and feed-water piping, fuel piping, blowdown piping, safetyand control valve piping, isolation valves, drips,drains and instrument connections.

b. Controls and instruments. Superheater and‘burner management controls are best purchasedalong with the steam generator so that there will beintegrated steam temperature and burner systems.

c. Soot blowers. Continuous or frequent on linecleaning of furnace, boiler economizer, and air pre-heater heating surfaces is required to maintain per-formance and efficiency. Soot blower systems,steam or air operated, will be provided for this pur-pose. The selection of steam or air for soot blowingis an economic choice and will be evaluated in termsof steam and makeup water vs. compressed air costswith due allowance for capital and operating costcomponents.

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Section Ill. FUEL HANDLING AND STORAGE SYSTEMS

3-13. Introductiona. Purpose. Figure 3-10 is a block diagram illus-

trating the various steps and equipment requiredfor a solid fuel storage and handling system.

b. Fuels for consideration. Equipment requiredfor a system depends on the type of fuel or fuelsburned. The three major types of fuels utilized forsteam raising are gaseous, liquid and solid.

3-14. Typical fuel oil storage and han-dling system

The usual power plant fuel oil storage and handlingsystem includes:

a. Unloading and storage.(1) Unloading pumps will be supplied, as re-

quired for the type of delivery system used, as part

of the power plant facilities. Time for unloading willbe analyzed and unloading pump(s) optimized for the circumstances and oil quantities involved.Heavier fuel oils are loaded into transport tanks hotand cool during delivery. Steam supply for tank carheaters will be provided at the plant if it is expectedthat the temperature of the oil delivered will be be-low the 120 to 150ºF. range.

(2) Storage of the fuel oil will be in two tanks soas to provide more versatility for tank cleanout in-spection and repair. A minimum of 30 days storagecapacity at maximum expected power plant load(maximum steaming capacity of all boilers withmaximum expected turbine generator output andmaximum export steam, if any) will be provided.Factors such as reliability of supply and whether

Figure 3-10. Coal handling system diagram.

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backup power is available from other sources mayresult in additional storage requirements. Space forfuture tanks will be allocated where additional boil-ers are planned, but storage capacity will not be pro-vided initially.

(3) Storage tank(s) for heavy oils will be heatedwith a suction type heater, a continuous coil extend-ing over the bottom of the tank, or a combination ofboth types of surfaces. Steam is usually the mosteconomical heating medium although hot water canbe considered depending on the temperatures atwhich low level heat is available in the power plant.Tank exterior insulation will be provided.

b. Fuelpumps and heaters.(1) Fuel oil forwarding pumps to transfer oil

from bulk storage to the burner pumps will be pro-vided. Both forwarding and burner pumps should beselected with at least 10 percent excess capacityover maximum burning rate in the boilers. Sizingwill consider additional pumps for future boilers andpressure requirements will be selected for pipe fric-tion, control valves, heater pressure drops, andburners. A reasonable selection would be one pumpper boiler with a common spare if the system is de-signed for a common supply to all boilers. For highpressure mechanical atomizing burners, each boilermay also have its own metering pump with spare.

(2) Pumps may be either centrifugal or positivedisplacement. Positive displacement pumps will bespecified for the heavier fuel oils. Centrifugal pumpswill be specified for crude oils. Where absolute relia-ability is required, a spare pump driven by a steamturbine with gear reducer will be used. For “blackstarts, ” or where a steam turbine may be inconven-ient, a dc motor driver may be selected for use forrelatively short periods.

(3) At least two fuel oil heaters will be used forreliability and to facilitate maintenance. Typicalheater design for Bunker C! fuel oil will provide fortemperature increases from 100 to 230° F usingsteam or hot water for heating medium.

c. Piping system.(1) The piping system will be designed to main-

tain pressure by recirculating excess oil to the bulkstorage tank. The burner pumps also will circulateback to the storage tank. A recirculation connectionwill be provided at each burner for startup. It will bemanually valved and shut off after burner is suc-cessfully lit off and operating smoothly.

(2) Piping systems will be adapted to the typeof burner utilized. Steam atomizing burners willhave “blowback” connections to cleanse burners offuel with steam on shutdown. Mechanical atomizingburner piping will be designed to suit the require-ments of the burner.

d. Instruments and control. Instruments and

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controls include combustion controls, burner man-agement system, control valves and shut off valves.

3-15. Coal handling and storage systemsa. Available systems. The following principal sys-

tems will be used as appropriate for handling, stor-ing and reclaiming coal:

(1) Relatively small to intermediate system;coal purchases sized and washed. A system with atrack or truck (or combined track/truck) hopper,bucket elevator with feeder, coal silo, spouts andchutes, and a dust collecting system will be used.Elevator will be arranged to discharge via closedchute into one or two silos, or spouted to a groundpile for moving into dead storage by bulldozer. Re-claim from dead storage will be by means of bulldoz-er to track/truck hopper.

(2) Intermediate system; coal purchased sizedand washed. This will be similar to the system de-scribed in (1) above but will use an enclosed skiphoist instead of a bucket elevator for conveying coalto top of silo.

(3) Intermediate system alternatives. For morethan two boilers, an overbunker flight or belt con-veyor will be used. If mine run, uncrushed coalproves economical, a crusher with feeder will be in-stalled in association with the track/truck hopper.

(4) Larger systems, usually with mine run coal.A larger system will include track or truck (or com-bined track/truck) unloading hopper, separate deadstorage reclaim hoppers, inclined belt conveyorswith appropriate feeders, transfer towers, vibratingscreens, magnetic separators, crusher(s), overbunk-er conveyor(s) with automatic tripper, weighingequipment, sampling equipment, silos, dust collect-ing system(s), fire protection, and like items. Wheretwo or more types of coal are burned (e.g., high andlow sulphur), blending facilities will be required.

(5) For cold climates. All systems, regardless ofsize, which receive coal by railroad will require carthawing facilities and car shakeouts for looseningfrozen coal. These facilities will not be provided fortruck unloading because truck runs are usuallyshort.

b. Selection of handling capacity. Coal handlingsystem capacity will be selected so that ultimateplanned 24-hour coal consumption of the plant atmaximum expected power plant load can be unload-ed or reclaimed in not more than 7-1/2 hours, or withinthe time span of one shift after allowance of a 1/2-hourmargin for preparation and cleanup time. The hand-ling capacity should be calculated using the worst(lowest heating value) coal which may be burned inthe future and a maximum steam capacity boiler ef-ficiency at least 3 percent less than guaranteed byboiler manufacturer.

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c. Outdoor storage pile. The size of the outdoorstorage pile will be based on not less than 90 days ofthe ultimate planned 24-hour coal consumption ofthe plant at maximum expected power plant load.Some power plants, particularly existing plantswhich are being rehabilitated or expanded, will haveoutdoor space limitations or are situated so that it isenvironmentally inadvisable to have a substantialoutdoor coal pile.

d. Plant Storage.(1) For small or medium sized spreader stoker

fired plants, grade mounted silo storage will be spe-cified with a live storage shelf above and a reservestorage space below. Usually arranged with one siloper boiler and the silo located on the outside of thefiring aisle opposite the boiler, the live storage shelfwill be placed high enough so that the spout to thestoker hopper or coal scale above the hopperemerges at a point high enough for the spout angleto be not less than 60 degrees from the horizontal.The reserve storage below the live storage shelf willbe arranged to recirculate back to the loading pointof the elevator so that coal can be raised to the top ofthe live storage shelf as needed. Figure 3-11 shows a

typical bucket elevator grade mounted silo arrange-ment for a small or medium sized steam generatingfacility.

(2) For large sized spreader stoker fired plants,silo type overhead construction will be specified. Itwill be fabricated of structural steel or reinforcedconcrete with stainless steel lined conical bottoms.

(3) For small or medium sized plants combinedlive and reserve storage in the silo will be not lessthan 3 days at 60 percent of maximum expectedload of the boiler(s) being supplied from the silo sothat reserves from the outside storage pile need notbe drawn upon during weekends when operatingstaff is reduced. For large sized plants this storagerequirement will be 1 day.

e. Equipment and systems.(1) Bucket elevators. Bucket elevators will be

chain and bucket type. For relatively small installa-tions the belt and bucket type is feasible althoughnot as rugged as the chain and bucket type. Typicalbucket elevator system is shown in Figure 3-11.

(2) Skip hoists. Because of the requirement fordust suppression and equipment closure dictated by

environmental considerations, skip hoists will notbe specified.

(3) Belt conveyors. Belt conveyors will be selected for speeds not in excess of 500 to 550 feet per

minute. They will be specified with roller bearingsfor pulleys and idlers, with heavy duty belts, andwith rugged helical or herringbone gear drive units.

(4) Feeders. Feeders are required to transfercoal at a uniform rate from each unloading and inter-mediate hopper to the conveyor. Such feeders will beof the reciprocating plate or vibrating pan type withsingle or variable speed drive. Reciprocating typefeeders will be used for smaller installations; the vi-brating type will be used for larger systems.

(5) Miscellaneous. The following items are re-quired as noted

(a) Magnetic separators for removal of trampiron from mine run coal.

(b) Weigh scale at each boiler and, for largerinstallations, for weighing in coal as received. Scaleswill be of the belt type with temperature compensat-ed load cell. For very small installations, a low costdisplacement type scale for each boiler will be used.

(c) Coal crusher for mine run coal; for large in-stallations the crusher will be preceded by vibrating(scalping) screens for separating out and by-passingfines around the crusher.

(d) Traveling tripper for overbunker conveyor serving a number of bunkers in series.

(e) One or more coal samplers to check “as re-

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ceived” and’ ‘as fired” samples for large systems.(f) Chutes, hoppers and skirts, as required,

fabricated of continuously welded steel for dusttightness and with wearing surfaces lined withstainless steel. Vibrators and poke holes will be pro-vided at all points subject to coal stoppage or hang-up.

(g) Car shakeout and a thaw shed for loosen-ing frozen coal from railroad cars.

(h) Dust control systems as required through-out the coal handling areas. All handling equip-ment—hoppers, conveyors and galleries-will be en-closed in dust tight casings or building shells andprovided with negative pressure ventilation com-plete with heated air supply, exhaust blowers, sepa-rators, and bag filters for removing dust from ex-hausted air. In addition, high dust concentrationareas located outside which cannot be enclosed, suchas unloading and reclaim hoppers, will be providedwith spray type dust suppression equipment.

(i) Fire protection system of the sprinklertype.

(j) Freeze protection for any water piping lo-cated outdoors or in unheated closures as providedfor dust suppression or fire protection systems.

(k) A vacuum cleaning system for mainte-nance of coal handling systems having galleries andequipment enclosures.

(l) System of controls for sequencing andmonitoring entire coal handling system.

Section IV. ASH HANDLING SYSTEMS3-16. Introduction

a. Background.(1) Most gaseous fuels burn cleanly, and the

amount of incombustible material is so small that itcan be safely ignored. When liquid or solid fuel isfired in a boiler, however, the incombustible materi-al, or ash, together with a small amount of unburnedcarbon chiefly in the form of soot or cinders, collectsin the bottom of the furnace or is carried out in alightweight, finely divided form usually knownloosely as “fly ash.” Collection of the bottom ashfrom combustion of coal has never been a problem asthe ash is heavy and easily directed into hopperswhich may be dry or filled with water,

(2) Current ash collection technology is capableof removing up to 99 percent or more of all fly ashfrom the furnace gases by utilizing a precipitator orbaghouse, often in combination with a mechanicalcollector. Heavier fly ash particles collected fromthe boiler gas passages and mechanical collectors of-ten have a high percentage of unburned carbon con-

tent, particularly in the case of spreader stoker firedboilers; this heavier material may be reinfected intothe furnace to reduce unburned carbon losses and in-

crease efficiency, although this procedure does in-crease the dust loading on the collection equipmentdownstream of the last hopper from which such ma-terial is reinfected.

(3) It is mandatory to install precipitators orbaghouses on all new coal fired boilers for finalcleanup of the flue gases prior to their ejection to at-mosphere. But in most regions of the United States,mechanical collectors alone are adequate for heavyoil fired boilers because of the conventionally lowash content of this type of fuel. An investigation isrequired, however, for each particular oil fired unitbeing considered.

b. Purpose. It is the purpose of the ash handlingsystem to:

(1) Collect the bottom ash from coal-firedspreader stoker or AFBC boilers and to convey itdry by vacuum or hydraulically by liquid pressureto a temporary or permanent storage terminal. Thelatter may be a storage bin or silo for ultimate trans-fer to rail or truck for transport to a remote disposalarea, or it maybe an on-site fill area or storage pondfor the larger systems where the power plant site is

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adequate and environmentally acceptable for thispurpose.

(2) Collect fly ash and to convey it dry to tem-porary or permanent storage as described above forbottom ash. Fly ash, being very light, will be wettedand is mixed with bottom ash prior to disposal toprevent a severe dust problem.

3-17. Description of major componentsa. Typical oil fired system. Oil fired boilers do not

require any bottom ash removal facilities, since ashand unburned carbon are light and carried out withthe furnace exit gas. A mechanical collector may berequired for small or intermediate sized boilers hav-ing steaming rates of 200,000 pounds per hour orless. The fly ash from the gas passage and mechani-cal collector hoppers can usually be handled manu-ally because of the small amount of fly ash (soot) col-lected. The soot from the fuel oil is greasy and cancoagulate at atmospheric temperatures making itdifficult to handle. To overcome this, hoppersshould be heated with steam, hot water, or electricpower. Hoppers will be equipped with an outletvalve having an air lock and a means of attachingdisposable paper bags sized to permit manual hand-ling. Each hopper will be selected so that it need notbe evacuated more than once every few days. If boil-er size and estimated soot/ash loading is such thatmanual handling becomes burdensome, a vacuum orhydraulic system as described below should be con-sidered.

b. Typical ash handling system for small or intermediate sized coal fired boilers;

(1) Plant fuel burning rates and ash content ofcoal are critical in sizing the ash handling system.Sizing criteria will provide for selecting hoppers andhandling equipment so that ash does not have to beremoved more frequently than once each 8-hourshift using the highest ash content coal anticipatedand with boiler at maximum continuous steamingcapacity. For the smaller, non-automatic system itmay be cost effective to select hoppers and equipment which will permit operating at 60 percent ofmaximum steam capacity for 3 days without remov-ing ash to facilitate operating with a minimumweekend crew.

(2) For a typical military power plant, the mosteconomical selection for both bottom and fly ash dis-posal is a vacuum type dry system with a steam jet

or mechanical(Figure 3-12).

exhauster for creating the vacuumThis typical plant would probably

have a traveling grate spreader stoker, a mechanical collector, and a baghouse; in all likelihood, no on-siteash disposal area would be available.

(3) The ash system for the typical plant will in-clude the following for each boiler:

(a) A refractory lined bottom ash hopper toreceive the discharge from the traveling grate. Aclinker grinder is not required for a spreader stokeralthough adequate poke holes should be incorpor-ated into the outlet sections of the hopper.

(b) Gas passage fly ash hoppers as required by the boiler design for boiler proper, economizer,and air heater.

(c) Collector fly ash hoppers for the mechanical collector and baghouse.

(d) Air lock valves, one at each hopper outlet,manually or automatically operated as selected bythe design engineer.

(4) And the following items are common to allboilers in the plant:

(a) Ash collecting piping fabricated of specialhardened ferro-alloy to transfer bottom and fly ashto Storage.

(b) Vacuum producing equipment, steam ormechanical exhauster as may prove economical. Forplants with substantial export steam and with lowquality, relatively inexpensive makeup requirements, steam will be the choice. For plants withhigh quality, expensive makeup requirements,consideration should be given to the higher cost me-chanical exhauster.

(c) Primary and secondary mechanical (centri-fugal) separators and baghouse filter are used toclean the dust out of the ash handling system ex-haust prior to discharge to the atmosphere. This equipment is mounted on top of the silo.

(d) Reinforced concrete or vitrified tile over-head silo with separator and air lock for loading silo with a “dustless” unloader designed to dampenashes as they are unloaded into a truck or railroadcar for transport to remote disposal.

(e) Automatic control system for sequencingoperation of the system. Usually the manual initia-tion of such a system starts the exhauster and thenremoves bottom and fly ash from each separator col-lection point in a predetermined sequence. Ash un-loading to vehicles is separately controlled.

Section V. TURBINES AND AUXILIARY SYSTEMS

3-18. Turbine prime movers generator and its associated electrical accessories,The following paragraphs on turbine generators dis- refer to Chapter 4.cuss size and other overall characteristics of the tur- a. Size and type ranges. Steam turbine gener-bine generator set. For detailed discussion of the ators for military installations will fall into the fol-

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Figure 3-12. Pneumatic ash handling systems—variations.

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lowing size ranges:(1) Small turbine generators. From 500 to about

2500 kW rated capacity, turbine generators willusually be single stage, geared units without extrac-tion openings for either back pressure or condensingservice. Rated condensing pressures for single stageturbines range from 3 to 6 inches Hga. Exhaustpressures for back pressure units in cogenerationservice typically range from 15 psig to 250 psig.

(2) Intermediate turbine generators. Fromabout 2500 to 10,000 kW rated capacity, turbinegenerators will be either multi-stage, multi-valvemachines with two pole direct drive generators turn-ing at 3600 rpm, or high speed turbines with gear re-ducers may also be used in this size range. Units areequipped with either uncontrolled or controlled (au-tomatic) extraction openings. Below 4000 kW, therewill be one or two openings with steam pressures upto 600 psig and 750°F. From 4000 kW to 10,000kW, turbines will be provided with two to four un-controlled extraction openings, or one or two auto-matic extraction openings. These turbines wouldhave initial steam conditions from 600 psig to 1250psig, and 750°F to 900°F. Typical initial steam con-ditions would be 600 psig, 825º For 850 psig, 900°F.

(3) Large turbine generators. In the capacityrange 10,000 to 30,000 kW, turbine generators willbe direct drive, multi-stage, multi-valve units. Forelectric power generator applications, from two tofive uncontrolled extraction openings will be re-quired for feedwater heating. In cogeneration appli-cations which include the provision of process orheating steam along with power generation, one au-tomatic extraction opening will be required for eachlevel of processor heating steam pressure specified,along with uncontrolled extraction openings forfeedwater heating. Initial steam conditions range upto 1450 psig and 950 “F with condensing pressuresfrom 1 1/2 to 4 inches Hga.

b. Turbine features and accessories. In all sizeranges, turbine generator sets are supplied by themanufacturer with basic accessories as follows:

(1) Generator with cooling system, excitationand voltage regulator, coupling, and speed reduc-tion gear, if used.

(2) Turbine and generator (and gear) lubricationsystem including tank, pumps, piping, and controls.

(3) Load speed governor, emergency overspeedgovernor, and emergency inlet steam trip valve withrelated hydraulic piping.

(4) Full rigid base plate in small sizes or sepa-rate mounting sole plates for installation in concretepedestal for larger units.

(5) Insulation and jacketing, instruments, turn-ing gear and special tools.

3-19. GeneratorsFor purposes of this section, it is noted that the gen-erator must be mechanically compatible with the driving turbine, coupling, lubrication system, andvibration characteristics (see Chapter 4 for gener-ator details).

3-20. Turbine featuresa. General. Turbine construction may be general-

ly classified as high or low pressure, single or multi-stage, back pressure on condensing, direct drive orgear reducer drive, and for electric generator or formechanical drive service.

(1) Shell pressures. High or low pressure con-struction refers generally to the internal pressuresto be contained by the main shell or casing parts.

(2) Single us. multi-stage. Single or multi-stagedesigns are selected to suit the general size,enthalpy drops and performance requirements ofthe turbine. Multi-stage machines are much moreexpensive but are also considerably more efficient.Single stage machines are always less expensive,simpler and less efficient. They may have up tothree velocity wheels of blading with reentry sta-tionary vanes between wheels to improve efficiency.As casing pressure of single stage turbines are equalto exhaust pressures, the design of seals and bear-ings is relatively simple.

(3) Back pressure vs. condensing. Selection of a back pressure or a condensing turbine is dependenton the plant function and cycle parameters. (SeeChapter 3, Section I for discussion of cycles.) Con-densing machines are larger and more complex withhigh pressure and vacuum sealing provisions, steamcondensers, stage feedwater heating, extensive lubeoil systems and valve gear, and related auxiliary fea-tures.

(4) Direct drive vs. geared sets. Direct drive tur-bines generators turn the turbine shaft at generatorspeed. Units 2500 kW and larger are normally directconnected. Small, and especially single stage, tur-bines may be gear driven for compactness and forsingle stage economy. Gear reducers add complex-ity and energy losses to the turbine and should beused only after careful consideration of overall econ-omy and reliability.

(5) Mechanical drive. Main turbine units inpower plants drive electrical generators, althoughlarge pumps or air compressors may also be drivenby large turbines. In this event, the turbines arecalled “mechanical drive” turbines. Mechanicaldrive turbines are usually variable speed units withspecial governing equipment to adapt to best econ-omy balance between driver (turbine) and driven ma-chine. Small auxiliary turbines for cycle pumps,

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fans, or air compressor drives are usually singlestage, back pressure, direct drive type designed formechanical simplicity and reliability. Both constantspeed and variable speed governors are used de-pending on the application.

b. Arrangement. Turbine generators are horizon-tal shaft type with horizontally split casings. Rela-tively small mechanical drive turbines may be builtwith vertical shafts. Turbine rotor shaft is usuallysupported in two sleeve type, self aligning bearings,sealed and protected from internal casing steamconditions. Output shaft is coupled to the shaft ofthe generator which is provided with its own enclo-sure but is always mounted on the same foundationas the turbine.

(1) Balance. Balanced and integrated design ofthe turbine, coupling and generator moving parts isimportant to successful operation, and freedomfrom torsional or lateral vibrations as well as pre-vention of expansion damage are essential.

(2) Foundations. Foundations and pedestals forturbine generators will be carefully designed to ac-commodate and protect the turbine generator, con-denser, and associated equipment. Strength, mass,stiffness, and vibration characteristics must be con-sidered. Most turbine generator pedestals in theUnited States are constructed of massive concrete.

3-21. Governing and controla. Turbine generators speed/load control. Electri-

cal generator output is in the form of synchronizedac electrical power, causing the generator and driv-ing turbine to rotate at exactly the same speed (orfrequency) as other synchronized generators con-nected into the common network. Basic speed/loadgoverning equipment is designed to allow each unitto hold its own load steady at constant frequency, orto accept its share of load variations, as the commonfrequency rises and falls. Very small machines mayuse direct mechanical governors, but the bulk of theunits will use either mechanical-hydraulic governingsystems or electrohydraulic systems. Non-reheatcondensing units 5000 kW and larger and back pres-sure units without automatic extraction will beequipped with mechanical-hydraulic governing. Forautomatic extraction units larger than 20,000 kW,governing will be specified either with a mechanical-hydraulic or an electro-hydraulic system.

b. Overspeed governors. All turbines require sep-arate safety or overspeed governing systems to in-sure inlet steam interruption if the machine exceedsa safe speed for any reason. The emergency gover-nor closes a specially designed stop valve which notonly shuts off steam flow but also trips various safe-ty devices to prevent overspeed by flash steam in-

TM 5-811-6

duction through the turbine bleed (extraction)points.

c. Single and multi-valve arrangements. What-ever type of governor is used, it will modulate theturbine inlet valves to regulate steam flow and tur-bine output. For machines expected to operate ex-tensively at low or partial loads, multi-valve ar-rangements improve economy. Single valve tur-bines, in general, have equal economy and efficiencyat rated load, but lower part load efficiencies.

3-22. Turning geara. General. For turbines sized 10,000 kW and

larger, a motor operated turning gear is required toprevent the bowing of the turbine rotor created bythe temperature differential existing between theupper and lower turbine casings during the long pe-riod after shutdown in which the turbine cools down.The turbine cannot be restarted until it has com-pletely cooled down without risk of damage to inter-state packing and decrease of turbine efficiency,causing delays in restarting. The turning gear ismounted at the exhaust end of the turbine and isused to turn the rotor at a speed of 1 to 4 rpm whenthe turbine is shut down in order to permit uniformcooling of the rotor. Turning gear is also used duringstartup to evenly warm up the rotor before rollingthe turbine with steam and as a jacking device forturning the rotor as required for inspection andmaintenance when the turbine is shut down.

b. Arrangement and controls. The turning gearwill consist of a horizontal electric motor with a setof gear chains and a clutching arrangement whichengages a gear ring on the shaft of the turbine. Itscontrols are arranged for local and/or remote start-ing and to automatically disengage when the tur-bine reaches a predetermined speed during startupwith steam. It is also arranged to automatically en-gage when the turbine has been shut down and de-celerated to a sufficiently slow speed. Indicatinglights will be provided to indicate the disengaged orengaged status of the turning gear and an interlockprovided to prevent the operation of the turning gear if the pressure in the turbine lubrication oil sys-tem is below a predetermined safe setting.

3-23. Lubrication systemsa. General. Every turbine and its driven machine

or generator requires adequate lubricating oil supply including pressurization, filtration, oil cooling,and emergency provisions to insure lubrication inthe event of a failure of main oil supply. For a typ-ical turbine generator, an integrated lube oil storagetank with built in normal and emergency pumps isusually provided. Oil cooling may be by means of an

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external or internal water cooled heat exchanger. Oiltemperatures should be monitored and controlled,and heating may be required for startup.

b. Oil Pumps. Two full capacity main lube oilpumps will be provided. One will be directly drivenfrom the turbine shaft for multi-stage machines.The second full size pump will be ac electric motordriven. An emergency dc motor driven or turbine-driven backup pump will be specified to allow or-derly shutdown during normal startup and shut-down when the shaft driven pump cannot maintainpressure, or after main pump failure, or in the eventof failure of the power supply to the ac electric mo-tor driven pumps.

c. Filtration. Strainers and filters are necessaryfor the protection and longevity of lubricated parts.Filters and strainers should be arranged in pairs foron line cleaning, inspection, and maintenance. Larg-er turbine generator units are sometimes equippedwith special off base lubrication systems to provideseparate, high quality filtering.

3-24. Extraction featuresa. Uncontrolled extraction systems. Uncontrolled

bleed or extraction openings are merely nozzles inthe turbine shell between stages through which rela-tively limited amounts of steam may be extractedfor stage feedwater heating. Such openings addlittle to the turbine cost as compared with the costof feedwater heaters, piping, and controls. Turbinesso equipped are usually rated and will have efficien-cies and performance based on normal extractionpressures and regenerative feedwater heating calcu-lations. Uncontrolled extraction opening pressureswill vary in proportion to turbine steam flow, and

extracted steam will not be used or routed to anysubstantial uses except for feedwater heating.

b. Automatic extraction. Controlled or automaticextraction turbines are more elaborate and equipped with variable internal orifices or valves to modulateinternal steam flows so as to maintain extractionpressures within specified ranges. Automatic ex-traction machine governors provide automatic self-contained modulation of the internal flow orifices orvalves, using hydraulic operators. Automatic ex-traction governing systems can also be adapted torespond to external controls or cycle parameters topermit extraction pressures to adjust to changingcycle conditions.

c. Extraction turbine selection. Any automaticextraction turbine is more expensive than itsstraight uncontrolled extraction counterpart of sim-ilar size, capacity and type; its selection and use re-quire comprehensive planning studies and economicanalysis for justification. Sometimes the same ob-jective can be achieved by selecting two units, one ofwhich is an uncontrolled extraction-condensing ma-chine and the other a back pressure machine.

3-25. Instruments and special toolsa. Operating instruments. Each turbine will be

equipped with appropriate instruments and alarmsto monitor normal and abnormal operating condi-tions including speed, vibration, shell and rotor ex-pansions, steam and metal temperatures, rotorstraightness, turning gear operation, and varioussteam, oil and hydraulic system pressures.

b. Special took. Particularly for larger machines,complete sets of special tools, lifting bars, and re-lated special items are required for organized and ef-fective erection and maintenance.

Section VI. CONDENSER AND CIRCULATING WATERSYSTEM

3-26. Introductiona. Purpose.

(1) The primary purpose of a condenser and cir-culating water system is to remove the latent heatfrom the steam exhausted from the exhaust end ofthe steam turbine prime mover, and to transfer thelatent heat so removed to the circulating waterwhich is the medium for dissipating this heat to theatmosphere. A secondary purpose is to recover thecondensate resulting from the phase change in theexhaust steam and to recirculate it as the workingfluid in the cycle.

(2) Practically, these purposes are accom-plished in two steps. In the first step, the condenseris supplied with circulating water which serves as amedium for absorbing the latent heat in the con-densing exhaust steam. The source of this circulat-

ing water can be a natural body of water such as anocean, a river, or a lake, or it can be from a recircu-lated source such as a cooling tower or cooling pond.In the second step, the heated circulating water isrejected to the natural body of water or recirculatedsource which, in turn, transfers the heat to the at-mosphere, principally by evaporative cooling effect.

b. Equipment required—general. Equipment re-quired for a system depends on the type of systemutilized. There are two basic types of con-densers: surface and direct contact.

There are also two basic types of cooling sys-tems:

Once through; andRecirculating type, including cooling ponds, me-

chanical draft cooling towers, natural draft coolingtowers, or a combination of a pond and tower.

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TM 5-811-6

3-27. Description of major componentsa. Surface condensers.

(1) General description. These units are de-signed as shell and tube heat exchangers. A surfacecondenser consists of a casing or shell with a cham-ber at each end called a “water box. ” Tube sheetsseparate the two water boxes from the center steamspace. Banks of tubes connect the water boxes bypiercing the tube sheets; the tubes essentially fillthe shell or steam space. Circulating water pumpsforce the cooling (circulating] water through the wa-ter boxes and the connecting tubes. Uncontami-.nated condensate is recovered in surface condenserssince the cooling water does not mix with the con-densing steam. Steam pressure in a condenser (or

* vacuum) depends mainly on the flow rate and tem-perature of the cooling water and on the effective-ness of air removal equipment.

(2) Passes and water boxes.(a) Tubing and water boxes may be arranged

for single pass or two pass flow of water through theshell. In single pass units, water enters the waterbox at one end of the tubes, flows once through allthe tubes in parallel, and leaves through the outletwater box at the opposite end of the tubes. In twopass units, water flows through the bottom half ofthe tubes (sometimes the top half) in one direction,

Lreverses in the far end water box, and returnsthrough the upper or lower half of the tubes to thenear water box. Water enters and leaves through thenear water box which is divided into two chambersby a horizontal plate. The far end water box is undi-vided to permit reversal of flow.

(b) For a relatively large cooling water sourceand low circulating water pump heads (hence lowunit pumping energy costs), single pass units will be.used. For limited cooling water supplies and highcirculating water pump heads (hence high unitpumping energy costs), two pass condensers will be

< specified. In all cases, the overall condenser-circulat-ing water system must be optimized by the designerto arrive at the best combination of condenser sur-face, temperature, vacuum, circulating waterpumps, piping, and ultimate heat rejection equip-ment.

(c) Most large condensers, in addition to theinlet waterbox horizontal division, have vertical par-titions to give two separate parallel flow pathsthrough the shell. This permits taking half the con-densing surface our of service for cleaning while wa-ter flows through the other half to keep the unit run-ning at reduced load.

(3) Hot well. The hot well stores the condensate‘L and keeps a net positive suction head on the conden-

sate pumps. Hot well will have a capacity of at least3 minutes maximum condensing load for surges and

to permit variations in level for the condensate con-trol system.

(4) Air removal offtakes. One or more air off-takes in the steam space lead accumulating air tothe air removal pump.

(5) Tubes.(a) The tubes provide the heat transfer sur-

face in the condenser are fastened into tube sheets,usually made of Muntz metal. Modern designs havetubes rolled into both tube sheets; for ultra-tight-ness, alloy steel tubes may be welded into tubesheets of appropriate material. Admiralty is themost common tube material and frequently is satis-factory for once through systems using fresh waterand for recirculating systems. Tube material in the“off gas” section of the condenser should be stain-less steel because of the highly corrosive effects ofcarbon dioxide and ammonia in the presence ofmoisture and oxygen. These gases are most concen-trated in this section. Other typical condenser tubematerials include:

(1) Cupronickel(2) Aluminum bronze(3) Aluminim brass(4) Various grades of stainless steel

(b) Condenser tube water velocities rangefrom 6 to 9 feet per second (Table 3- 12). Higher flowrates raise pumping power requirements and erodetubes at their entrances, thus shortening their lifeexpectancy. Lower velocities are inefficient from aheat transfer point of view. Tubes are generally in-stalled with an upwardly bowed arc. This providesfor thermal expansion, aids drainage in a shutdowncondenser, and helps prevent tube vibration.

b. Direct contact condensers. Direct contact con-densers will not be specified.

c. Condenser auxiliaries.(1) General. A condenser needs equipment and

conduits to move cooling water through the tubes,remove air from the steam space, and extract con-densate from the hotwell. Such equipment and con-duits will include:

(a) Circulating water pumps.(b) Condensate or hotwell pumps.(c) Air removal equipment and piping.(d) Priming ejectors.(e) Atmospheric relief valve.(f) Inlet water tunnel, piping, canal, or com-

bination of these conduits.(g) Discharge water tunnel, piping or canal,

or combination of these conduits.(2) Circulating water pumps. A condenser uses

75 to 100 pounds of circulating water per pound ofsteam condensed. Hence, large units need substan-tial water flows; to keep pump work to a minimum,top of condenser water boxes in a closed system will

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TM 5-811-6

Table 3-12. Condenser Tube Design Velocities.

Material Design Velocities fps

Fresh Water Brackish Water Salt Water

Admiralty Metal 7.0 (1) (1)

Aluminum Brass(2) 8.0 7.0 7.0

Copper-Nickel Alloys:

90-10 8.0 8.0 7.0 to 7.5

80-20 8.0 8.0 7.0 to 7.5

70-30 9.0 9.0 8.0 to 8.5

Stainless Steel 9.0 to 9.5 8 . 0( 3 ) 8 . 0( 3 )

Aluminum (4) 8.0 7.0 6.8

NOTES :

(1) Not normally used, but if used, velocity shall not exceed 6.0 fps.

(2) For salt and brackish water , velocities in excess of 6.8 fps arenot recommended.

(3) Minimum velocity of 5.5 fps to prevent chloride attack.

(4) Not recommended for circulating water containing high concentrationof heavy metal salts.


not be higher than approximately 27 feet above min-imum water source level which permits siphon oper-ation without imposing static head. With a siphonsystem, air bubbles tend to migrate to the top of thesystem and must be removed with vacuum-produc-ing equipment. The circulating pumps then need todevelop only enough head to overcome the flow re-sistance of the circulating water circuit. Circulatingpumps for condensers are generally of the centrif-ugal type for horizontal pumps, and either mixedflow or propeller type for vertical pumps. Verticalpumps will be specified because of their adaptabilityfor intake structures and their ability to handle highcapacities at relatively low heads. Pump materialwill be selected for long life.

(3) Condensate pumps. Condensate (or hotwell)

pumps handle much smaller flows than the circulat-ing water pumps. They must develop heads to pushwater through atmospheric pressure, pipe and con-trol valve friction, closed heater water circuit fric-tion, and the elevation of the deaerator storage tank.These pumps take suction at low pressure of twoinches Hg absolute or less and handle water at sat-uration temperature; to prevent flashing of the con-densate, they are mounted below the hotwell to re-ceive a net positive suction head. Modern vertical“can” type pumps will be used. Specially designedpump glands prevent air leakage into the conden-sate, and vents from the pump connecting to the va-por space in the condenser prevent vapor binding.

(4) Spare pumps. Two 100 percent pumps for both circulating water and condensate service will

be specified. If the circulating water system servesmore than one condenser, there will be one circulat-

ing pump per condenser with an extra pump as acommon spare. Condensate pump capacity will besized to handle the maximum condenser load underany condition of operation (e.g., with automatic ex-traction to heating or process shutoff and includingall feedwater heater drains and miscellaneous dripsreceived by the condenser.)

(5) Air removal.(a) Non-condensable gases such as air, carbon

dioxide, and hydrogen migrate continuously intothe steam space of a condenser inasmuch as it is thelowest pressure region in the cycle. These gases mayenter through leakage at glands, valve bonnets, por-ous walls, or may be in the throttle steam. Thosegases not dissolved by the condensate diffusethroughout the steam space of the condenser. Asthese gases accumulate, their partial pressure raisesthe condenser total pressure and hence decreases ef-ficiency of the turbine because of loss of availableenergy. The total condenser pressure is:

Pc = PS+ Pa

where Ps = steam saturation pressure cor-responding to steam tempera-ture

Pa = air pressure (moisture free)

LThis equation shows that air leakage must be re-moved constantly to maintain lowest possible vac-uum for the equipment selected and the particularexhaust steam loading. In removing this air, it willalways have some entrained vapor. Because of itssubatmospheric pressure, the mixture must be com-pressed for discharge to atmosphere.

(b) Although the mass of air leakage to thecondenser may be relatively small because of its.very low pressure, its removal requires handling of alarge volume by the air removal equipment. The airofftakes withdraw the air-vapor moisture from the. steam space over a cold section of the condensertubes or through an external cooler, which con-denses part of the moisture and increases the air-to-steam ratio. Steam jets or mechanical vacuumpumps receive the mixture and compress it to at-mosphere pressure.

(6) Condenser cleanliness. Surface condenserperformance depends greatly on the cleanliness ofthe tube water side heat transfer surface. Whendirty fresh water or sea water is used in the circulat-ing water system, automatic backflush or mechan-ical cleaning systems will be specified for on linecleaning of the interior condenser tube surfaces.

d. Circulating water system–once through(1) System components. A typical once through

circulating water system, shown in figure 3-13, con-sists of the following components:

(a)(b)(c)(d)(e)(f)

TM 5-811-6

Intake structure.Discharge, or outfall.Trash racks.Traveling screens.Circulating water pumps.Circulating water pump structure (indoor

or outdoor).(g) Circulating water canals, tunnels, and

pipework.(2) System operation.

(a) The circulating water system functions asfollows. Water from an ocean, river, lake, or pondflows either directly from the source to the circulat-ing water structure or through conduits which bringwater from offshore; the inlet conduits dischargeinto a common plenum which is part of the circulat-ing water pump structure. Water flows through bartrash racks which protect the traveling screens fromdamage by heavy debris and then through travelingscreens where smaller debris is removed. For largesystems, a motor operated trash rake can be in-stalled to clear the bar trash racks of heavy debris.In case the traveling screens become clogged, or toprevent clogging, they are periodically backwashesby a high pressure water jet system. The backwashis returned to the ocean or other body of water. Eachseparate screen well is provided with stop logs andsluice gates to allow dewatering for maintenancepurposes.

(b) The water for each screen flows to the suc-tion of the circulating water pumps. For small sys-tems, two 100-percent capacity pumps will be se-lected while for larger systems, three 50-percentpumps will be used. At least one pump is requiredfor standby. Each pump will be equipped with a mo-torized butterfly valve for isolation purposes. Thepumps discharge into a common circulating watertunnel or supply pipe which may feed one or morecondensers. Also, a branch line delivers water to thebooster pumps serving the closed cooling water ex-changers.

(c) Both inlet and outlet water boxes of themain condensers will be equipped with butterflyvalves for isolation purposes and expansion joints.As mentioned above, the system may have the capa-bility to reverse flow in each of the condenser halvesfor cleaning the tubes. The frequency and durationof the condenser reverse flow or back wash opera-tion is dictated by operating experience.

(d) The warmed circulating water from thecondensers and closed cooling water exchangers isdischarged to the ocean, river, lake, or pond via acommon discharge tunnel.

(3) Circulating water pump setting. The circu-lating water pumps are designed to remain operablewith the water level at the lowest anticipated eleva-

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TM 5-811-6I

NAVFAC DM3

Figure 3-13. Types of circulating water systems.

tion of the selected source. This level is a function ofthe neap tide for an ocean source and seasonal levelvariations for a natural lake or river. Cooling pondsare usually man-made with the level controlled with-in modest limits. The pump motors and valve motoroperators will be located so that no electrical partswill be immersed in water at the highest anticipatedelevation of the water source.

(4) System pressure control. On shutdown of acirculating water pump, water hammer is avoidedby ensuring that the pumps coast down as the pumpisolation valves close. System hydraulics, circulat-ing pump coastdown times, and system isolationvalve closing times must be analyzed to precludedamage to the system due to water hammer. Thecondenser tubes and water boxes are to be designedfor a pressure of approximately 25 psig which is wellabove the ordinary maximum discharge pressure ofthe circulating water pumps, but all equipmentmust be protected against surge pressures causedby sudden collapse of system pressure.

(5) Inspection and testing. All active compo-nents of the circulating water system will be accessi-ble for inspection during station operation.

e. Circulating water system—recirculating type(1) General discussion.

(a) With a once-through system, the evapora-tive losses responsible for rejecting heat to the at-mosphere occur in the natural body of water as thewarmed circulating water is mixed with the residualwater and is cooled over a period of time by evapora-tion and conduction heat transfer. With a recircula-tion system, the same water constantly circulates;evaporative losses responsible for rejecting heat tothe atmosphere occur in the cooling equipment andmust be replenished at the power plant site. Recircu-lating systems can utilize one of the following forheat rejection:

(1) A natural draft, hyperbolic cooling tow-er.

(2) A mechanical draft cooling tower, us-ually induced draft.

(3) A spray pond with a network of pipingserving banks of spray nozzles.

(b) Very large, man-made ponds which takeadvantage of natural evaporative cooling may beconsidered as “recirculating” systems, although fordesign purposes of the circulating water system

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TM 5-811-6

they are once through and hence considered as suchin paragraph d above.

(c) To avoid fogging and plumes which arecharacteristic of cooling towers under certain at-mospheric conditions in humid climates, so calledwet-dry cooling towers may be used. These towersuse a combination of finned heat transfer surfaceand evaporative cooling to eliminate the fog and vis-ible plume. The wet-dry types of towers are expen-sive and not considered in this manual. Hyperbolictowers also are expensive and are not applicable tounits less than 300-500 M W; while spray pondshave limited application (for smaller units) becauseof the large ground area required and the problem ofexcessive drift. Therefore, the following descriptivematerial applies only to conventional induced draftcooling towers which, except for very special cir-cumstances, will be the choice for a military powerplant requiring a recirculating type system.

(2) System components. A typical recirculatingsystem with a mechanical draft cooling tower con-sists of the following components:

(a) Intake structure which is usually an ex-tension of the cooling tower basin.

(b) Circulating water pumps.(c) Circulating water piping or tunnels to con-

densers and from condensers to top of cooling tower.(d) Cooling tower with makeup and blowdown

systems.(3) System operation.

(a) The recirculating system functions as fol-lows. Cooled water from the tower basin is directedto the circulating water pump pit. The pit is similarto the intake structure for a once through system ex-cept it is much simpler because trash racks or trav-eling screens are not required, and the pit settingcan be designed without reference to levels of a nat-ural body of water. The circulating water pumpspressure the water and direct it to the condensersthrough the circulating water discharge piping. Astream of circulating water is taken off from themain condenser supply and by means of boosterpumps further pressurized as required for bearingcooling, generator cooling, and turbine generator oilcooling. From the outlet of the condensers and mis-cellaneous cooling services, the warmed circulatingwater is directed to the top of the cooling tower forrejection of heat to the atmosphere.

(b) Circulating water pump and condenservalving is similar to that described for a typicalonce-through system, but no automatic back flush-ing or mechanical cleaning system is required forthe condenser. Also, due to the higher pumping

heads commonly required for elevating water to thetop of the tower and the break in water pressure atthat point which precludes a siphon, higher pressure

ratings for the pumps and condensers will be speci-fied.

(4) Cooling tower design.(a) In an induced draft mechanical cooling

tower, atmospheric air enters the louvers at the bot-tom perimeter of the tower, flows up through thefill, usually counterflow to the falling water droplets, and is ejected to the atmosphere in saturatedcondition thus carrying off the operating load ofheat picked up in the condenser. Placement and ar-rangement of the tower or towers on the power sta-tion site will be carefully planned to avoid recircula-tion of saturated air back into the tower intake andto prevent drift from the tower depositing on elec-trical buses and equipment in the switchyard, road-ways and other areas where the drift could be detri-mental.

(b) Hot circulating water from the condenserenters the distribution header at the top of the tow-er. In conventional towers about 75 percent of thecooling takes place be evaporation and the re-mainder by heat conduction; the ratio depends onthe humidity of the entering air and various factors.

(5) Cooling tower performance. The principalperformance factor of a cooling tower is its approachto the wet bulb temperature; this is the differencebetween the cold water temperature leaving the tow-er and the wet bulb temperature of the entering air.The smaller the approach, the more efficient and ex-pensive the tower. Another critical factor is the cool-ing range. This is the difference between the hot wa-ter temperature entering the tower and the cold wa-ter temperature leaving it is essentially the same asthe circulating water temperature rise in the conden-ser. Practically, tower approaches are 8 to 15°F withranges of 18 to 22°F. Selection of approach andrange for a tower is the subject for an economic opti-mization which should include simultaneous selec-tion of the condensers as these two major items ofequipment are interdependent.

(6) Cooling tower makeup.(a) Makeup must be continuously added to

the tower collecting basin to replace water lost byevaporation and drift. In many cases, the makeupwater must be softened to prevent scaling of heattransfer surfaces; this will be accomplished bymeans of cold lime softening. Also the circulatingwater must be treated with bioxides and inhibitorswhile in use to kill algae, preserve the fill, and pre-vent metal corrosion and fouling. Algae control isaccomplished by means of chlorine injection; acidand phosphate feeds are used for pH control and tokeep heat surfaces clean.

(b) The circulating water system must beblown down periodically to remove the accumulatedsolid concentrated by evaporation.

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TM 5-811-6

3-28. Environmental concernsa. Possible problems. Some of the environmental

concerns which have an impact on various types ofpower plant waste heat rejection systems are as fol-lows:

(1) Compatibility of circulating water systemwith type of land use allocated to the surroundingarea of the power plant.

(2) Atmospheric ground level fogging fromcooling tower.

(3) Cooling tower plumes.(4) Ice formation on adjacent roads, buildings

and structures in the winter.(5) Noise from cooling tower fans and circulat-

ing water pumps.(6) Salts deposition on the contiguous country-

side as the evaporated water from the tower is ab-sorbed in the atmosphere and the entrained chemi-cals injected in the circulating water system fallout.

(7) Effect on aquatic life for once though sys-tems:

(a) Entrapment or fish kill.(b) Migration of aquatic life.(c) Thermal discharge.(d) Chemical discharge.(e) Effect of plankton.

(8) Effect on animal and bird life.(9) Possible obstruction to aircraft (usually only

a problem for tall hyperbolic towers).(10) Obstruction to ship and boat navigation

(for once through system intakes or navigablestreams or bodies of water).

b. Solutions to problems. Judicious selection of the type of circulating water system and optimumorientation of the power plant at the site can mini-mize these problems. However, many military proj-ects will involve cogeneration facilities which mayrequire use of existing areas where construction ofcooling towers may present serious on base prob-lems and, hence, will require innovative design solu-tions.

Section VII. FEEDWATER SYSTEM

3-29. Feedwater heatersa. Open type—deaerators.

(1) Purpose. Open type feedwater heaters areused primarily to reduce feedwater oxygen and oth-er noncondensable gases to essentially zero and thusdecrease corrosion in the boiler and boiler feed sys-tem. Secondarily, they are used to increase thermalefficiency as part of the regenerative feedwater heat-ing cycle.

(2) Types.(a) There are two basic types of open deaerat-

ing heaters used in steam power plants—tray typeand spray type. The tray or combination spray/traytype unit will be used. In plants where heater traymaintenance could be a problem, or where the feed-water has a high solids content or is corrosive, aspray type deaerator will be considered.

(b) All types of deaerators will have internalor external vent condensers, the internal parts ofwhich will be protected from corrosive gases andoxidation by chloride stress resistant stainless steel.

(c) In cogeneration plants where largeamounts of raw water makeup are required, a deaer-ating hot process softener will be selected dependingon the steam conditions and the type of raw waterbeing treated (Section IX, paragraph 3-38 and3-39).

(3) Location. The deaerating heater should belocated to maintain a pressure higher than theNPSH required by the boiler feed pumps under allconditions of operation. This means providing amargin of static head to compensate for sudden fall

off in deaerator pressure under an upset condition.Access will be provided for heater maintenance andfor reading and maintaining heater instrumenta-tion.

(4) Design criteria.(a) Deaerating heaters and storage tanks will

comply with the latest revisions of the followingstandards:

(1) ASME Unified Pressure Vessel Code.(2) ASME Power Test Code for Deaerators.(3) Heat Exchanger Institute (HE I).(4) American National Standards Institute

(ANSI).(b) Steam pressure to the deaerating heater

will not be less than three psig.(c) Feedwater leaving the deaerator will con-

tain no more than 0.005 cc/liter of oxygen and zeroresidual carbon dioxide. Residual content of the dis-solved gases will be consistent with their relativevolubility and ionization.

(d) Deaerator storage capacity will be not lessthan ten minutes in terms of maximum design flowthrough the unit.

(e) Deaerator will have an internal or externaloil separator if the steam supply may contain oil,such as from a reciprocating steam engine.

(f) Deaerating heater will be provided withthe following minimum instrumentation: reliefvalve, thermometer, thermocouple and test well atfeedwater inlet and outlet, and steam inlet; pressure gauge at feedwater and steam inlets; and a level con-trol system (paragraph c).

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TM 5-811-6

b. Closed type.(1) Purpose. along with the deaerating heater,

closed feedwater heaters are used in a regenerativefeedwater cycle to increase thermal efficiency andthus provide fuel savings. An economic evaluationwill be made to determine the number of stages offeedwater heating to be incorporated into the cycle.Condensing type steam turbine units often haveboth low pressure heaters (suction side of the boilerfeed pumps) and high pressure heaters (on the dis-charge side of the feed pumps). The economic anal-ysis of the heaters should consider a desuperheatersection when there is a high degree of superheat inthe steam to the heater and an internal or externaldrain cooler (using entering condensate or boilerfeedwater) to reduce drains below steam saturationtemperature.

(2) Type. The feedwater heaters will be of the U-tube type.

(3) Location. Heaters will be located to alloweasy access for reading and maintaining heater in-strumentation and for pulling the tube bundle orheater shell. High pressure heaters will be located toprovide the best economic balance of high pressurefeedwater piping, steam piping and heater drain piping.

(4) Design criteria(a) Heaters will comply with the latest revi-

sions of the following standards:(1) ASME Unfired Pressure Vessel Code.(2) ASME Power Test Code for Feedwater

Heaters.(3) Tubular Exchanger Manufacturers As-

sociation (TEMA).(4) Heat Exchanger Institute (HE I).(5) American National Standards Institute

(ANSI).(b) Each feedwater heater will be provided

with the following minimum instrumentation: shelland tube relief valves; thermometer, thermocoupleand test well at feedwater inlet and outlet; steam in-let and drain outlet; pressure gauge at feedwater in-let and outlet, and steam inlet; and level control sys-tem.

c. Level control systems.(1) Purpose. Level control systems are required

for all open and closed feedwater heaters to assureefficient operation of each heater and provide forprotection of other related power plant equipment.The level control system for the feedwater heaters isan integrated part of a plant cycle level control sys-tem which includes the condenser hotwell and theboiler level controls, and must be designed with thisin mind. This paragraph sets forth design criteriawhich are essential to a feedwater heater level con-trol system. Modifications may be required to fit the

actual plant cycle.(2) Closed feedwater heaters.

(a) Closed feedwater heater drains are usuallycascaded to the next lowest stage feedwater heateror to the condenser, A normal and emergency drainline from each heater will be provided. At high loadswith high extraction steam pressure, the normalheater drain valve cascades drain to the next loweststage heater to control its own heater level. At lowloads with lower extraction steam pressure and low-er pressure differential between successive heaters,sufficient pressure may not be available to allow thedrains to flow to the next lowest stage heater. Inthis case, an emergency drain valve will be providedto cascade to a lower stage heater or to the conden-ser to hold the predetermined level.

(b) The following minimum instrumentationwill be supplied to provide adequate level control ateach heater: gauge glass; level controller to modu-late normal drain line control valve (if emergencydrain line control valve is used, controller musthave a split range); and high water level alarmswitch.

(3) Open feedwater heaters-deaerators. The fol-lowing minimum instrumentation will be suppliedto provide adequate level control at theheater: gauge glass, level controller to control feed-water inlet control waive (if more than one feedwaterinlet source, controller must have a split range); lowwater level alarm switch; “low-low” water levelalarm switch to sound alarm and trip boiler feedpumps, or other pumps taking suction from heater;high water level alarm switch; and “high-high” wa-ter level controller to remove water from the deaer-ator to the condenser or flash tank, or to divert feed-water away from the deaerator by opening a divert-ing valve to dump water from the feedwater line tothe condenser or condensate storage tank.

(4) Reference. The following papers should beconsulted in designing feedwater level control sys-tems, particularly in regard to the prevention of wa-ter induction through extraction piping

(a) ASMD Standard TWDPS-1, July 1972,“Recommended Practices for the Prevention of Wa-ter Damage to Steam Turbines Used for ElectricPower Generation (Part 1- Fossil Fueled Plants).”

(b) General Electric Company StandardGEK-25504, Revision D, “Design and OperatingRecommendations to Minimize Water Induction inLarge Steam Turbines.”

(c) Westinghouse Standard, “Recommenda-tion to Minimize Water Damage to Steam Tur-bines.”

3-30. Boiler feed pumps.a. General. Boiler feed pumps are used to pressur-

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TM 5-811-6

ize water from the deaerating feedwater heater ordeaerating hot process softener and feed it throughany high pressure closed feedwater heaters to theboiler inlet. Discharge from the boiler superheatedsteam in order to maintain proper main steam tern-perature to the steam turbine generator.

b. Types. There are two types of centrifugalmulti-stage boiler feed pumps commonly used insteam power plants—horizontally split case and bar-rel type with horizontal or vertical (segmented) splitinner case. The horizontal split case type will beused on boilers with rated outlet pressures up to 900psig. Barrel type pumps will be used on boilers withrated outlet pressure in excess of 900 psig.

c. Number of pumps. In all cases, at least onespare feed pump will be provided.

(1) For power plants where one battery of boilerfeed pumps feeds one boiler.

(a) If the boiler is base loaded most of thetime at a high load factor, then use two pumps eachat 110-125 percent of boiler maximum steaming ca-pacity.

(b) If the boiler is subject to daily wide rangeload swings, use three pumps at 55-62.5 percent ofboiler maximum steaming capacity. With this ar-

rangement, two pumps are operated in parallel be-tween 50 and 100 percent boiler output, but only onepump is operated below 50 percent capacity. This ar-rangement allows for pump operation in its most ef-ficient range and also permits a greater degree offlexibility.

(2) For power plants where one battery of pumpfeeds more than one boiler through a header system,the number of pumps and rating will be chosen toprovide optimum operating efficiency and capitalcosts. At least three 55-62.5 percent pumps shouldbe selected based on maximum steaming capacity ofall boilers served by the battery to provide the flexi-bility required for a wide range of total feedwaterflows.

d. Location. The boiler feed pumps will be locatedat the lowest plant level with the deaerating heateror softener elevated sufficiently to maintain pumpsuction pressure higher than the required NPSH ofthe pump under all operating conditions. Thismeans a substantial margin over the theoreticallycalculated requirements to provide for pressures col-lapses in the dearator under abnormal operatingconditions. Deaerator level will never be decreasedfor structural or aesthetic reasons, and suction pipeconnecting deaerator to boiler feed pumps should besized so that friction loss is negligible.

e. Recirculation control system.(1) To prevent overheating and pump damage,

each boiler feed pump will have its own recirculationcontrol system to maintain minimum pump flow

whenever the pump is in operation. The control sys-tem will consist off

(a) Flow element to be installed in the pump suction line.

(b) Flow controller.(c) Flow control valve.(d) Breakdown orifice.

(2) Whenever the pump flow decreases to mini-mum required flow, as measured by the flow ele-ment in the suction line, the flow controller will bedesigned to open the flow control valve to maintainminimum pump flow. The recirculation line will be discharge to the deaerator. A breakdown orifice willbe installed in the recirculation line just before it en-ters the deaerator to reduce the pressure from boilerfeed pump discharge level to deaerator operatingpressure.

f. Design criteria.(1) Boiler feed pumps will comply with the lat-

est revisions of the following standards:(a) Hydraulics Institute (HI).(b) American National Standards Institute

(ANSI).(2) Pump head characteristics will be maximum

at zero flow with continuously decreasing head asflow increases to insure stable operation of onepump, or multiple pumps in parallel, at all loads.

(3) Pumps will operate quietly at all loads with-out internal flashing and operate continuously without overheating or objectionable noises at minimumrecirculation flow.

(4) Provision will be made in pump design forexpansion of

(a) Casing and rotor relative to one another.(b) Casing relative to the base.(c) Pump rotor relative to the shaft of the

driver.(d) Inner and outer casing for double casing

pumps.(5) All rotating parts will be balanced statically -

and dynamically for all speeds.(6) Pump design will provide axial as well as ra-

dial balance of the rotor at all outputs.(7) One end of the pump shaft will be accessible

for portable tachometer measurements.(8) Each pump will be provided with a pump

warmup system so that when it is used as a standbyit can be hot, ready for quick startup. This is doneby connecting a small bleed line and orifice from thecommon discharge header to the pump discharge in-side of the stop and check valve. Hot water can thenflow back through the pump and open suction valveto the common suction header, thus keeping thepump at operating temperature.

(9) Pump will be designed so that it will startsafely from a cold start to full load in 60 seconds in

TM 5-811-6

an emergency, although it will normally be warmedbefore starting as described above.

(10) Other design criteria should be as forth inMilitary Specification MIL-P-17552D.

g. Pump drives. For military plants, one steamturbine driven pump may be justified under certainconditions; e.g., if the plant is isolated, or if it is a co-generation plant or there is otherwise a need for sub-stantial quantities of exhaust steam. Usually, how-ever, adequate reliability can be incorporated intothe feed pumps by other means, and from a plant ef-ficiency point of view it is always better to bleedsteam ‘from the prime mover(s) rather than to usesteam from an inefficient mechanical drive turbine.

3-31. Feedwater supplya. General description.

(1) In general terms, the feedwater supply in-cludes the condensate system as well as the boilerfeed system.

(2) The condensate system includes the conden-sate pumps, condensate piping, low pressure closedheaters, deaerator, and condensate system level andmakeup controls. Cycle makeup may be introducedeither into the condenser hotwell or the deaerator.For large quantities of makeup as in cogenerationplants, the deaerator maybe preferred as it containsa larger surge volume. The condenser, however, isbetter for this purpose when makeup is of high pur-ity and corrosive (demineralized and undeaerated).With this arrangement, corrosive demineralized wa-ter can be deaerated in the condenser hotwell; theexcess not immediately required for cycle makeup isextracted and pumped to an atmospheric storagetank where it will be passive in its deaerated state.As hotwell condensate is at a much lower tempera-ture than deaerator condensate, the heat loss in theatmospheric storage tank is much less with this ar-rangement.

(3) The feedwater system includes the boilerfeed pumps, high pressure closed heaters, boiler feedsuction and discharge piping, feedwater level con-trols for the boiler, and boiler desuperheater watersupply with its piping and controls.

b. Unit vs. common system. Multiple unit cogen-eration plants producing export steam as well aselectric will always have ties for the high pressure

Section Vlll. SERVICE WATER

3-32. Introduction

a. Definitions and purposes. Service water supplysystems and subsystems can be categorized as fol-lows:

(1) For stations with salt circulating water or

steam, the extraction steam, and the high pressurefeedwater system. If there are low pressure closedheaters incorporated into the prime movers, the con-densate system usually remains independent foreach such prime mover; however, the deaerator andboiler feed pumps are frequently common for allboilers although paralleling of independent highpressure heater trains (if part of the cycle) on thefeedwater side maybe incorporated if high pressurebleeds on the primer movers are uncontrolled. Eachcogeneration feedwater system must carefully be de-signed to suit the basic parameters of the cycle. Lev-el control problems can become complex, particu-larly if the cycle includes multiple deaerators operat-ing in parallel.

c. Feedwater controls. Condensate pumps, boilerfeed pumps, deaerator, and closed feedwater heatersare described as equipment items under other head-ings in this manual. Feedwater system controls willconsist of the following

(1) Condenser hotwell level controls which con-trol hotwell level by recirculating condensate fromthe condensate pump discharge to the hotwell, byextracting excess fluid from the cycle and pumpingit to atmospheric condensate storage (surge) tanks,and by introducing makeup (usually from the samecondensate storage tanks) into the hotwell to replen-ish cycle fluid.

(2) Condensate pump minimum flow controls torecirculate sufficient condensate back to the con-denser hotwell to prevent condensate pumps fromoverheating.

(3) Deaerator level controls to regulate amountof condensate transferred from condenser hotwell todeaerator and, in an emergency, to overflow excesswater in the deaerator storage tank to the conden-sate storage tank(s).

(4) Numerous different control systems are pos-sible for all three of the above categories. Regardlessof the method selected, the hotwell and the deaer-ator level controls must be closely coordinated andintegrated because the hotwell and deaerator tankare both surge vessels in the same fluid system.

(5) Other details on instruments and controlsfor the feedwater supply are described under Section1 of Chapter 5, Instruments and Controls.

heavily contaminated or sedimented fresh circulat-ing water.

(a) Most power stations, other than thosewith cooling towers, fall into this category. Circulat-ing water booster pumps increase the pressure of a(small) part of the circulating water to a level ade-

3-43

TM 5-811-6

quate to circulate through closed cooling water ex-changers. If the source is fresh water, these pumpsmay also supply water to the water treating system.Supplementary sources of water such as the areapublic water supply or well water may be used forpotable use and/or as a supply to the water treatingsystem. In some cases, particularly for larger sta-tions, the service water system may have its pumpsdivorced from the circulating water pumps to pro-vide more flexibility y and reliability.

(b) The closed cooling water exchangerstransfer rejected heat from the turbine generatorlube oil and generator air (or hydrogen) coolers, bear-ings and incidental use to the circulating water side-stream pressurized by the booster pumps. The medi-um used for this transfer is cycle condensate whichrecirculates between the closed cooling exchangersand the ultimate equipment where heat is removed.This closed cooling cycle has its own circulating(closed cooling water) pumps, expansion tank andtemperature controls.

(2) For stations with cooling towers. Circulat-ing water booster pumps (or separate service waterpumps). may also be used for this type of powerplant. In the case of cooling tower systems, how-ever, the treated cooling tower circulating water canbe used directly in the turbine generator lube oil andgenerator air (or hydrogen) coolers and various otherservices where a condensate quality cooling mediumis unnecessary. This substantially reduces the sizeof a closed cooling system because the turbine gen-erator auxiliary cooling requirements are the largestheat rejection load other than that required for themain condenser. If a closed cooling system is usedfor a station with a cooling tower, it should be de-signed to serve equipment such as air compressorcylinder jackets and after coolers, excitation systemcoolers, hydraulic system fluid coolers, boiler TVcameras, and other similar more or less delicateservice. If available, city water, high quality wellwater, or other clean water source might be used forthis delicate equipment cooling service and thuseliminate the closed cooling water system.

b. Equipment required—general. Equipment re-quired for each system is as follows:

(1) Service water system(a) Circulating water booster pumps (or sepa-

rate service water pumps).(b) Piping components, valves, specialities

and instrumentation.(2) Closed cooling water system.

(a) Cosed cooling water circulating pumps.(b) Closed cooling water heat exchangers.(c) Expansion tank.(d) Piping components, valves, specialities

and instrumentation. Adequate instrumentation

(thermometers, pressure gages, and flow indicators)should be incorporated into the system to allowmonitoring of equipment cooling.

3-33. Description of major componentsa. Service water systerm.

(1) Circulating water booster (or service water)pumps. These pumps are motor driven, horizontal(or vertical) centrifugal type. Either two 100-per-cent or three 50-percent pumps will be selected forthis duty. Three pumps provide more flexibility; de-pending upon heat rejection load and desired watertemperature, one pump or two pumps can be oper-

.

ated with the third pump standing by as a spare. Apressure switch on the common discharge linealarms high pressure, and in the case of the boosterpumps a pressure switch on the suction header or in-terlocks with the circulating water pumps providespermissive to prevent starting the pumps unlessthe circulating water system is in operation.

(2) Temperature control. In the event the sys-tem serves heat rejection loads directly, temper-ature control for each equipment where heat is re-moved will be by means of either automatic or man-ually controlled valves installed on the cooling wa-ter discharge line from each piece of equiment, or byusing a by-pass arrangement to pass variableamounts of water through the equipment withoutupsetting system hydraulic balance.

b. Closed cooling water system.(1) Closed cooling water pumps. The closed

cooling water pumps will be motor driven, horizon-tal, end suction, centrifugal type with two 100-per-cent or three 50-percent pumps as recommended forthe pumps described in a above.

(2) Closed cooling water heat exchangers. Theclosed cooling water exchangers will be horizontalshell and tube test exchangers with the treatedplant cycle condensate on the shell side and circulat-ing (service) water on the tube side. Two 100-per-cent capacity exchangers will be selected for thisservice, although three 50-percent units may be se-lected for large systems.

(3) Temperature control. Temperature controlfor each equipment item rejecting heat will be simi-lar to that described above for the service water sys-tem.

3-34. Description of systemsa. Service water system.

(1) The service water system heat load is thesum of the heat loads for the closed cooling watersystem and any other station auxiliary systemswhich may be included. The system is designed to maintain the closed cooling water system supplytemperature at 950 For less during normal operation

TM 5-811-6

with maximum heat rejection load. The system willalso be capable of being controlled or manually ad-

justed so that a minimum closed cooling water supply temperature of approximately 55 ‘F can bemaintained with the ultimate heat sink at its lowesttemperature and minimum head load on the closedcooling water system. The service water system willbe designed with adequate backup and other reli-ability features to provide the required cooling tocomponents as necessary for emergency shutdownof the plant. In the case of a system with circulatingwater booster pumps, this may mean a crossoverfrom a city or well water system or a special smallcirculating water pump.

(2) Where cooling towers are utilized, meanswill be provided at the cooling tower basin to permitthe service water system to remain in operationwhile the cooling tower is down for maintenance orrepairs.

(3) The system will be designed such that opera-tional transients (e.g., pump startup or water ham-mer due to power failure) do not cause adverse ef-fects in the system. Where necessary, suitable valv-ing or surge control devices will be provided.

b. Closed cooling water system.(1) The closed cooling water coolant tempera-

ture is maintained at a constant value by automaticcontrol of the service water flow through the heatexchanger. This is achieved by control valve modu-lation of the heat exchanger by-pass flow. All equip-ment cooled by the cooling system is individuallytemperature controlled by either manual or auto-matic valves on the coolant discharge from, or byby-pass control around each piece of equipment. Thequantity of coolant in the system is automaticallymaintained at a predetermined level in the expan-sion tank by means of a level controller which oper-ates a control valve supplying makeup from thecycle condensate system. The head tank is providedwith an emergency overflow. On a failure of a run-ning closed cooling water pump, it is usual to pro-

vide means to start a standby pump automatically.(2) The system will be designed to ensure ade-

quate heat removal based on the assumption that allservice equipment will be operating at maximum de-sign conditions.

3-35. Arrangementa. Service water system. The circulating water

booster pumps will be located as close as possible tothe cooling load center which generally will be nearthe turbine generator units. All service water pipinglocated in the yard will be buried below the frostline.

b. Closed cooling water system. The closed cool-ing water system exchangers will be located nearthe turbine generators.

3-36. Reliability of systemsIt is of utmost importance that the service andclosed cooling water systems be maintained in serv-ice during emergency conditions. In the event powerfrom the normal auxiliary source is lost, the motordriven pumps and electrically actuated devices willbe automatically supplied by the emergency powersource (Chapter 4, Section VII). Each standby pumpwill be designed for manual or automatic startupupon loss of an operating pump with suitable alarmsincorporated to warn operators of loss of pressure ineither system.

3-37. TestingThe systems will be designed to allow appropriateinitial and periodic testing to:

u. Permit initial hydrostatic testing as required inthe ASME Boiler and Pressure Vessel Code.

b. Assure the operability and the performance ofthe active components of the system.

c. Permit testing of individual components orsubsystems such that plant safety is not impairedand that undesirable transients are not present.

Section IX. WATER CONDITIONING SYSTEMS

3-38. Water Conditioning Selection sure boiler used in power generation.a. Purpose. (2) The purpose of the water conditioning sys-

(1) All naturally occuring waters, whether sur- tems is to purify or condition raw water to the re-face water or well water, contain dissolved and pos- quired quality for all phases of power plant opera-sibly suspended impurities (solids) which may be in- tion. Today, most high pressure boilers (600 psig orjurious to steam boiler operation and cooling water above) require high quality makeup water which isservice. Fresh water makeup to a cooling tower, de- usually produced by ion exchange techniques. Tore-pending on its quality, usually requires little or no duce the undesirable concentrations of turbidity andpretreatment. Fresh water makeup to a boiler sys-

tem ranges from possibly no pretreatment (in theorganic matter found in most surface waters, theraw water will normally be clarifed by coagulation

case of soft well water used in low pressure boiler) to and filtration for pretreatment prior to passing toultra-purification required for a typical high pres- the ion exchangers (demineralizers). Such pretreat-

3-45

TM 5-811-6

ment, which may also include some degree of soften-ing, will normally be adequate without further treat-ment for cooling tower makeup and other generalplant use.

b. Methods of conditioning.(1) Water conditioning can be generally cate-

gorized as’ ‘external” treatment or’ ‘internal” treat-ment. External treatment clarifies, softens, or puri-fies raw water prior to introducing it into the powerplant fluid streams (the boiler feed water, coolingtower system, and process water) or prior to utiliz-ing it for potable or general washup purposes. Inter-nal treatment methods introduce chemicals directlyinto the power plant fluid stream where they coun-teract or moderate the undesirable effects of waterimpurities. Blowdown is used in the evaporativeprocesses to control the increased concentration ofdissolved and suspended solids at manageable lev-els.

(2) Some of the methods of water conditioningare as follows:

(a) Removal of suspended matter by sedimen-tation, coagulation, and filtration (clarification).

(b)of gases.

(c)(d)(f)(g)(h)

Deaeration and degasification for removal

Cold or hot lime softening.Sodium zeolite ion exchange.Choride cycle dealkalization.Demineralization (ultimate ion exchange).Internal chemical treatment.

(i) Blowdown to remove sludge and concen-tration buildups.

c. Treatment Selection. Tables 3-13, 3-14, and3-15 provide general guidelines for selection oftreatment methodologies. The choice among these isan economic one depending vitally on the actual con-stituents of the incoming water. The designer willmake a thorough life cycle of these techniques inconjunction with the plant data. Water treatmentexperts and manufacturer experience data willcalled upon.

Section X. COMPRESSED AIR SYSTEMS

3-39. Introductiona. Purpose. The purpose of the compressed air

systems is to provide all the compressed air require-ments throughout the power plant. The compressedair systems will include service air and instrumentair systems.

b. Equipment required-general. Equipment re-quired for a compressed air system is shown in Fig-ures 3-14 and 3-15. Each system will include

(1) Air compressors. (2) Air aftercoolers.

(3) Air receiver.(4) Air dryer (usually for instrument air system

only).(5) Piping, valves and instrumentation.c. Equipment served by the compressed air sys-

tems.(1) Service (or plant) air system for operation of

tools, blowing and cleaning.(2) Instrument air system for instrument and

control purposes.(3) Soot blower air system for boiler soot blow-

ing operations.

3-40. Description of major componentsa. Air compressors. Typical service and instru-

ment air compressor? for power plant service aresingle or two stage, reciprocating piston type withelectric motor drive, usually rated for 90 to 125 psigdischarge pressure. They may be vertical or horizon-tal and, for instrument air service, always have oil-less pistons and cylinders to eliminate oil carryover.

3-46

Non-lubricated design for service air as well as in-strument air will be specified so that when the for-mer is used for backup of the latter, oil carryoverwill not be a problem. Slow speed horizontal unitsfor service and instrument air will be used. Soot blower service requirements call for pressures whichrequire multi-stage design. The inlet air filter-silenc-er will be a replaceable dry felt cartridge type. Eachcompressor will have completely separate and inde-pendent controls. The compressor controls will per-mit either constant speed-unloaded cylinder controlor automatic start-stop control. Means will be pro-vided in a multi-compressor system for selection ofthe’ ‘lead” compressor.

b. Air aftercooler. The air aftercooler for eachcompressor will be of the shell and tube type, de-signed to handle the maximum rated output of thecompressor. Water cooling is provided except forrelatively small units which may be air cooled.Water for cooling is condensate from the closed cool-ing system which is routed counter-flow to the airthrough the aftercooler, and then through the cylin-der jackets. Standard aftercoolers are rated for95 “F. maximum inlet cooling water. Permissivecan be installed to prevent compressor startup un-less cooling water is available and to shut compress-or down or sound an alarm (or both) on failure ofwater when unit is in operation.

c. Air receiver. Each compressor will have its ownreceiver equipped with an automatic drainer for re-moval of water.

d. Instrument air dryer. The instrument air dryer

TM5-811-6

Table 3-13. General Guide for Raw Water Treatment of BoilerMakeup

St earnPressure Sil ica Alkalinity- (ps ig ) reg./l. reg./l. (as CaCO3) Water Treatment

up to 450 Under 15 Under 50 Sodium ion exchange.Over 50 Hot lime-hot zeolite,

or cold lime zeolite,or hot lime soda, orsodium ion exchange pluschloride anion exchange.

Over 15

450 t o 600 Under 5

Over 50

Under 50

Over 50

Hot lime-hot zeolite,or cold lime-zeolite,or hot lime soda.

Sodium ion exchange pluschloride anion exchange,or hot lime-hot zeolite.

Sodium plus hydrogen ionexchange, or cold lime-zeolite or hot lime-hotzeol i te .

Above 5 Demineralizer, or hotlime-hot zeolite.

600 to 1000 ------- ‘Any Water - - - - - - - Demineralizer.

1000 & Higher ------- Any Water - - - - - - - Demineralizer.

NOTES : (1) Guide is based on boiler water concentrations recommended in the

American Boiler and Affiliated Industries “Manual of IndustryStandards and Engineering Information.”

(2) Add filters when turbidity exceeds 10mg./l.(3) See Table 3-15 for effectiveness of treatments.(4) reg./l. = p.p.m.

Source: Adapted from NAVFAC DM3

3-47

TM 5-811-6

Table 3-14. Internal Chemical Treatment.

Corrosive Treatment Required

Maintenance of feedwater pH and boiler wateralkalinity for scale and corrosion control.

.

Prevention of boiler scale by internal softeningof the boiler water.

Conditioning of boiler sludge to prevent adherenceto internal boiler surfaces.

Prevention of scale from hot water in pipelines,stage heaters, and economizers.

Prevention of oxygen corrosion by chemicaldeaeration of boiler feedwater.

Prevention of corrosion by protective filmformation.

Prevention of corrosion by condensate.

Prevention of foam in boiler water.

Inhibition of caustic embrittlement.


Chemical

Caustic SodaSoda AshSulfuric Acid

PhosphatesSoda AshSodium AluminateAlginatesSodium Silicate

TanninsLignin DerivativesStarchGlucose Derivatives

PolyphosphatesTanninsLignin DerivativesGlucose Derivatives

Sulf itesTanninsFerrus hydroxideGlucose DerivativesHydrazineAmmonia

TanninsLignin DerivativesGlucose Derivatives

Amine CompoundsAmmonia

PolyamidesPolyalkylene Glycols

Sodium SulfatePhosphatesTanninsNitrates

3-48

Treatment

Cold Lime-Zeolite

TM 5-811-6

Table 3-15. Effectiveness of Water Treatment

Average Analysis of EffluentHardness Alkalinity co Dissolved

(as CaCO )

Hot Lime Soda

Hot Lime-Hot Zeolite

Sodium Zeolite

Sodium PlusHydrogen Zeolite

Sodium ZeolitePlus ChlorideAnion Exchanger

Demineralizer

Evaporator

o to 2

17 to 25

o to 2

o to 2

o to 2

o to 2

o to 2

o to 2

(as CaCO )mg./1.

75

35 to 50

20 to 25

Unchanged

10 to 30

15 to 35

o to 2

o to 2

Medium High

Low

Low to High

Low

Low

o to 5

o to 5

Solids

Reduced

Reduced

Reduced

Unchanged

Reduced

Unchanged

o t o 5

o t o 5

Sil ica

8

3

3

Unchanged

Unchanged

Unchanged

Below 0.15

Below 0.15

NOTE : (1) reg./l. = p.p.m.

Source: NAWFAC DM3

3-49

WET AIR

ENTRAINMENTSEPARATOR

Courtesy of Pope, Evans and Robbins (Non-Copyrighted)

Figure 3-14. Typical compressed airsystem.

will be of the automatic heat reactivating, dualchamber, chemical desiccant, downflow type. It willcontain a prefilter and afterfilter to limit particulatesize in the outlet dried air. Reactivating heat will beprovided by steam heaters.

3-41. Description of systemsa. General. The service (or plant) air and the in-

strument air systems may have separate or commoncompressors. Regardless of compressor arrange-ment, service and instrument air systems will eachhave their own air receivers. There will be isolationin the piping system to prevent upsets in the serviceair system from carrying over into the vital instru-ment air system.

b. Service air system. The service air systemcapacity will meet normal system usage with onecompressor out of service. System capacity will in-clude emergency instrument air requirements aswell as service air requirements for maintenanceduring plant operation. Service air supply will in-

3-50

elude work shops, laboratory, air hose stations formaintenance use, and like items. Air hose stationsshould be spaced so that air is available at eachpiece of equipment by using an air hose no longerthan 75 feet. Exceptions to this will be as follows:

(1) The turbine operating floor will have serviceair stations every 50 feet to handle air wrenchesused to tension the turbine hood bolts.

(2) No service air stations are required in thecontrol room and in areas devoted solely to switch-gear and motor control centers.

(3) Service air stations will be provided insidebuildings at doors where equipment or supplies maybe brought in or out.

c. Instrument air sys tern. A detailed analysis willbe performed to determine system requirements.The analysis will be based on:

(1) The number of air operated valves anddampers included in the mechanical systems.

(2) The number of air transmitters, controllersand converters.

TM 5-811-6


Figure 3-15. Typical arrangement of air compressor and accessories.

(3) A list of another estimated air usage not in- (2) Instrument air reserve. In instances whereeluded in the above items. short term, large volume air flow is required, local

d. Piping system. air receivers can be considered to meet such needs(1) Headers. Each separate system will have a and thereby eliminate installation of excessive com-

looped header to distribute the compressed air, and pressor capacity. However, compressor must befor large stations a looped header will be provided at sized to recharge the receivers while continuing toeach of the floor levels. supply normal air demands.

3-51

TM 5-811-6

CHAPTER 4

GENERATOR AND ELECTRICAL FACILITIES DESIGN

Section 1. TYPICAL VOLTAGE RATINGS AND SYSTEMS “

4-1. Voltagesa. General. Refer to ANSI Standard C84. 1 for

voltage ratings for 60 Hz electric power systemsand equipment. In addition, the standard lists appli-cable motor and motor control nameplate voltageranges up to nominal system voltages of 13.8 kV.

b. Generators. Terminal voltage ratings for powerplant generators depend on the size of the genera-tors and their application. Generally, the larger thegenerator, the higher the voltage. Generators for apower plant serving an Army installation will be inthe range from 4160 volts to 13.8 kV to suit the sizeof the unit and primary distribution system voltage.Generators in this size range will be offered by themanufacturer in accordance with its design, and itwould be difficult and expensive to get a differentvoltage rating. Insofar as possible, the generatorvoltage should match the distribution voltage toavoid the installation of a transformer between thegenerator and the distribution system.

c. Power plant station service power systems.(1) Voltages for station service power supply

within steam electric generating stations are relatedto motor size and, to a lesser extent, distances of ca-ble runs. Motor sizes for draft fans and boiler feedpumps usually control the selection of the higheststation service power voltage level. Rules for select-ing motor voltage are not rigid but are based on rela-tive costs. For instance, if there is only one motorlarger than 200 hp and it is, say, only 300 hp, itmight be a good choice to select this one larger mo-tor for 460 volts so that the entire auxiliary powersystem can be designed at the lower voltage.

(2) Station service power requirements for com-bustion turbine and internal combustion engine gen-erating plants are such that 208 or 480 volts will beused.

d. Distribution system. The primary distributionsystem for an Army installation with central in-house generation should be selected in accordancewith TM 5-811 -l/AFM 88-9.

4-2. Station service power systems.a. General. Two types of station service power

systems are generally in use in steam electric plantsand are discussed herein. They are designated as a

common bus system and a unit system. The distinc-tion is based on the relationship between the gener-ating unit and the auxiliary transformer supplyingpower for its auxiliary equipment.

(1) In the common bus system the auxiliarytransformer will be connected through a circuitbreaker to a bus supplied by a number of units andother sources so that the supply has no relationshipto the generating unit whose auxiliary equipment isbeing served. In the unit system the auxiliary trans-former will be connected solidly to the generatorleads and is switched with the generator. In eithercase, the auxiliary equipment for each generatingunit usually will be supplied by a separate transfor-mer with appropriate interconnections between thesecondary side of the transformers.

(2) The unit type system has the disadvantagethat its station service power requirements must besupplied by a startup transformer until the generat-ing unit is synchronized with the system. This start-up transformer also serves as the backup supply incase of transformer failure. This arrangement re-quires that the station service power supply betransferred from the startup source to the unitsource with the auxiliary equipment in operation asapart of the procedure of starting the unit.

(3) The advantages of the unit system are thatit reduces the number of breakers required and thatits source of energy is the rotating generating unitso that, in case of system trouble, the generatingunit and its auxiliaries can easily be isolated fromthe rest of the system. For application to Army in-stallations, the advantage of switching the gener-ator and its auxiliary transformer as a unit is notvery important, so the common bus system will nor-mally be used.

b. Common bus system. In this system, gener-ators will be connected to a common bus and theauxiliary transformers for all generating units willbe fed from that common bus. This bus may haveone or more other power sources to serve for stationstartup.

(1) Figure 4-1 is a typical one-line diagram forsuch a system. This type system will be used fordiesel generating plants with all station service sup-plied by two station service transformers with no

4-1

TM 5-811-6

4-2

TM 5-811-6

isolation between auxiliaries for different generat-ing units. It also will be used for steam turbine andgas turbine generating plants. For steam turbinegenerating plants the auxiliary loads for each unit inthe plant will be isolated on a separate bus fed by aseparate transformer. A standby transformer is in-cluded and it serves the loads common to all unitssuch as building services.

(2) The buses supplying the auxiliaries for theseveral units will be operated isolated to minimizefault current and permit use of lower interruptingrating on the feeder breakers. Provision will be madefor the standby transformer to supply any auxiliarybus.

c. Unit type system.(1) The unit type station service power system

will be used for a steam electric or combustion tur-bine generating station serving a utility transmis-sion network. It will not be, as a rule, used for adiesel generating station of any kind since the sta-tion service power requirements are minimal.

(2) The distinguishing feature of a unit type sta-tion power system is that the generator and unitauxiliary transformer are permanently connected to-gether at generator voltage and the station servicepower requirements for that generating unit, includ-ing boiler and turbine requirements, are normally

supplied by the auxiliary transformer connected tothe generator leads. This is shown in Figure 4-2. Ifthe unit is to be connected to a system voltage that ishigher than the generator voltage, the unit conceptcan be extended to include the step-up transformerby tying its low side solidly to the generator leadsand using the high side breaker for synchronizingthe generator to the system. This arrangement isshown in Figure 4-3.

d. Station service switchgear. A station serviceswitchgear lineup will be connected to the low sideof the auxiliary transformer; air circuit breakers willbe used for control of large auxiliary motors such asboiler feed pumps, fans and circulating water pumpswhich use the highest station service voltage, andfor distribution of power to various unit substationsand motor control centers to serve the remainingstation service requirements. Figure 4–4 is a typical

one-line diagram of this arrangement. If the highestlevel of auxiliary voltage required is more than 480volts, say 4.16 kV, the auxiliary switchgear air cir-cuit breakers will only serve motors 250 hp and larg-er and feeders to unit substations. Each unit substa-tion will include a transformer to reduce voltagefrom the highest auxiliary power level to 480 voltstogether with air circuit breakers in a lineup forstarting of motors 100 to 200 hp and for’ serving480-volt motor control centers. The motor controlcenters will include combination starters and feed-ers breakers to serve motors less than 100 hp andother small auxiliary circuits such as power panels.

e. Startup auxiliary transformer. In addition tothe above items, the unit auxiliary type system willincorporate a “common” or “startup” arrangementwhich will consist of a startup and standby auxil-iary transformer connected to the switchyard bus orother reliable source, plus a low voltage switchgearand motor control center arrangement similar tothat described above for the unit auxiliary system.The common bus system may have a similar ar-rangement for the standby transformer.

(1) This common system has three principalfunctions:

(a) To provide a source of normal power forpower plant equipment and services which are com-mon to all units; e.g., water treating system, coaland ash handling equipment, air compressors, light-ing, shops and similar items.

(b) To provide backup to each auxiliary powersystem segment if the transformer supplying thatsegment fails or is being maintained.

(c) In the case of the unit system, to providestartup power to each unit auxiliary power systemuntil the generator is up to speed and voltage and issynchronized with the distribution system.

(2) The startup and standby transformer andswitchgear will be sized to accomplish the abovethree functions and, in addition, to allow for possiblefuture additions to the plant. Interconnections willbe provided between the common and unit switch-gear. Appropriate interlocks will be included so thatno more than one auxiliary transformer can feed anyswitchgear bus at one time.

4-3. General types and standards

Section Il. GENERATORS

a. Type. Generators for power plant service canbe generally grouped according to service and size.

(1) Generators for steam turbine service rated5000-32,000 kVA, are revolving field, non-salient,two-pole, totally enclosed, air cooled with watercooling for air coolers, direct connected, 3600 rpmfor 60 Hz frequency (sometimes connected through

a gear reducer up to 10,000 kVA or more). Self-ven-tilation is provided for generators larger than 5000kVA by some manufacturers, but this is not recom-mended for steam power plant service.

(2) Similar generators rated 5000 kVA and be-low are revolving field, non-salient or salient pole,self-ventilated, open drip-proof type, sometimesconnected through a gear reducer to the turbine

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LEGEND


Figure 4-3. Station connections, two unit station unit arrangement-distribution voltage higher than generation.

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with the number of poles dependent on the speed se-lected which is the result of an economic evaluationby the manufacturer to optimize the best combina-tion of turbine, gear and generator.

(3) Generators for gas turbine service are re-volving field, non-salient or salient pole, self-venti-lated, open drip-proof type, sometimes connectedthrough a gear reducer, depending on manufactur-er’s gas turbine design speed, to the gas turbinepower takeoff shaft. Non-salient pole generators aretwo-pole, 3600 rpm for 60 Hz, although manufactur-ers of machines smaller than 1500 kVA may utilize1800 rpm, four-pole, or 1200 rpm, six-pole, salient

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pole generators. Generators may be obtained totallyenclosed with water cooling if desired because ofhigh ambient temperatures or polluted atmosphere.

(4) Generators for diesel service are revolvingfield, salient pole, air cooled, open type, direct con-nected, and with amortisseur windings to dampenpulsating engine torque. Number of poles is six ormore to match low speeds typical of diesels,

b. Standards. Generators will meet the require-ments of ANSI C50. 10, C50. 13 and C50.14 is applic-able as well as the requirements of NEMA SM 12 and SM 13.

(1) ANSI C84.1 designates standard voltages

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as discussed in section I.(2) Generator kVA rating for steam turbine

generating units is standardized as a multiplier ofthe turbine kW rating. Turbine rating for a condens-ing steam turbine with controlled extraction forfeedwater heating is the kW output at design initialsteam conditions, 3.5-inches hg absolute exhaustpressure, three percent cycle makeup, and all feed-water heaters in service. Turbine rating for a non-condensing turbine without controlled or uncon-trolled extraction is based on output at design ini-tial steam conditions and design exhaust pressure.Turbine standard ratings for automatic extractionunits are based on design initial steam conditionsand exhaust pressure with zero extraction whilemaintaining rated extraction pressure. However,automatic extraction turbine ratings are complicat-ed by the unique steam extraction requirements foreach machine specified. For air cooled generators upto 15,625 kVA, the multiplier is 1.25 times the tur-bine rating, and for 18,750 kVA air cooled and hy-drogen cooled generators, 1.20. These ratings are forwater cooled generators with 95 “F maximum inletwater to the generator air or hydrogen coolers.Open, self-ventilated generator rating varies withambient air temperature; standard rating usually isat 104° F ambient.

(3) Generator ratings for gas turbine generat-ing units are selected in accordance with ANSIStandards which require the generator rating to bethe base capacity which, in turn, must be equal to orgreater than the base rating of the turbine over aspecified range of inlet temperatures. Non-standardgenerator ratings can be obtained at an additionalprice.

(4) Power factor ratings of steam turbine drivengenerators are 0.80 for ratings up to 15,625 kVAand 0.85 for 17,650 kVA air cooled and 25,600 kVAto 32,000 kVA air/water cooled units. Standard pow-er factor ratings for gas turbine driven air cooledgenerators usually are 0.80 for machines up to 9375kVA and 0.90 for 12,500 to 32,000 kVA. Changes inair density, however, do not affect the capability ofthe turbine and generator to the same extent so thatkW based on standard conditions and generatorkVA ratings show various relationships. Power fac-tors of large hydrogen cooled machines are stand-ardized at 0.90. Power factor for salient pole gener-ators is usually 0.80. Power factor lower than stand-ard, with increased kVA rating, can be obtained atan extra price.

(5) Generator short circuit ratio is a rough indi-cation of generator stability; the higher the shortcircuit ratio, the more stable the generator undertransient system load changes or faults. However,fast acting voltage regulation can also assist in

achieving generator stability without the heavy ex-pense associated with the high cost of building highshort circuit ratios into the generator. Generatorshave standard short circuit ratios of 0.58 at ratedkVA and power factor. If a generator has a fast act-ing voltage regulator and a high ceiling voltagestatic excitation system, this standard short circuitratio should be adequate even under severe systemdisturbance conditions. Higher short circuit ratiosare available at extra cost to provide more stabilityfor unduly fluctuating loads which may be anticipat-ed in the system to be served.

(6) Maximum winding temperature, at ratedload for standard generators, is predicated on oper-ation at or below a maximum elevation of 3300 feet;this may be upgraded for higher altitudes at an ad-ditional price.

4-4. Features and accessoriesThe following features and accessories are availablein accordance with NEMA standards SM 12 andSM 13 and will be specified as applicable for eachgenerator.

a. Voltage variations. Unit will operate with volt-age variations of plus or minus 5 percent of ratedvoltage at rated kVA, power factor and frequency,but not necessarily in accordance with the stand-ards of performance established for operation at rat-ed voltage; i.e., losses and temperature rises may ex-ceed standard values when operation is not at ratedvoltage.

b. Thermal variations.(1) Starting from stabilized temperatures and

rated conditions, the armature will be capable ofoperating, with balanced current, at 130 percent ofits rated current for 1 minute not more than twice ayear; and the field winding will be capable of operat-ing at 125 percent of rated load field voltage for 1minute not more than twice a year.

(2) The generator will be capable of withstand-ing, without injury, the thermal effects of unbal-anced faults at the machine terminals, including thedecaying effects of field current and dc componentof stator current for times up to 120 seconds, provid-ed the integrated product of generator negativephase sequence current squared and time (12

2t) doesnot exceed 30. Negative phase sequence current isexpressed in per unit of rated stator current, andtime in seconds. The thermal effect of unbalancedfaults at the machine terminals includes the decay-ing effects of field current where protection is pro-vided by reducing field current (such as with an ex-citer field breaker or equivalent) and dc componentof the stator current.

c. Mechanical withstand. Generator will be cap-able of withstanding without mechanical injury any

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type of short circuit at its terminals for times not ex-ceeding its short time thermal capabilities at ratedkVA and power factor with 5 percent over ratedvoltage, provided that maximum phase current islimited externally to the maximum current obtainedfrom the three-phase fault. Stator windings mustwithstand a normal high potential test and show noabnormal deformation or damage to the coils andconnections.

d. Excitation voltage. Excitation system will bewide range stabilized to permit stable operationdown to 25 percent of rated excitation voltage onmanual control. Excitation ceiling voltage on man-ual control will not be less than 120 percent of ratedexciter voltage when operating with a load resist-ance equal to the generator field resistance, and ex-citation system will be capable of supplying thisceiling voltage for not less than 1 minute. These cri-teria, as set for manual control, will permit oper-ation when on automatic control. Exciter responseratio as defined in ANSI/IEEE 100 will not be lessthan 0.50.

e. Wave shape. Deviation factor of the open cir-cuit terminal voltage wave will not exceed 10 per-cent.

f. Telephone influence factor. The balanced tele-phone influence factor (TIF) and the residual compo-nent TIF will meet the applicable requirements ofANSI C50.13.

4-5. Excitation systemsRotating commutator exciters as a source of dc pow-er for the ac generator field generally have been replaced by silicon diode power rectifier systems ofthe static or brushless type.

a. A typical brushless system includes a rotatingpermanent magnet pilot exciter with the stator con-nected through the excitation switchgear to the sta-tionary field of an ac exciter with rotating armatureand a rotating silicon diode rectifier assembly,which in turn is connected to the rotating field of thegenerator. This arrangement eliminates both the .commutator and the collector rings. Also, part ofthe system is a solid state automatic voltage regula-tor, a means of manual voltage regulation, and nec-essary control devices for mounting on a remotepanel. The exciter rotating parts and the diodes aremounted on the generator shaft; viewing duringoperation must utilize a strobe light.

b. A typical static system includes a three-phaseexcitation potential transformer, three single-phasecurrent transformers, an excitation cubicle withfield breaker and discharge resistor, one automaticand one manual static thyristor type voltage regula-tors, a full wave static rectifier, necessary devicesfor mounting on a remote panel, and a collector as-sembly for connection to the generator field.

Section Ill. GENERATOR LEADS AND SWITCHYARD

4-6. GeneralThe connection of the generating units to the distri-bution system can take one of the following pat-terns:

a. With the common bus system, the generatorsare all connected to the same bus with the distribu-tion feeders. If this bus operates at a voltage of 4.16kV, this arrangement is suitable up to approximate-ly 10,000 kVA. If the bus operates at a voltage of13.8 kV, this arrangement is the best for stations upto about 25,000 or 32,000 kVA. For larger stations,the fault duty on the common bus reaches a levelthat requires more expensive feeder breakers andthe bus should be split.

b. The bus and switchgear will be in the form of afactory fabricated metal clad switchgear as shownin Figure 4-1. For plants with multiple generatorsand outgoing circuits, the bus will be split for reli-ability y using a bus tie breaker to permit separationof approximately one-half of the generators andlines on each side of the split.

c. A limiting factor of the common type bus sys-tem is the interrupting capacity of the switchgear.The switchgear breakers will be capable of inter-

rupting the maximum possible fault current thatwill flow through them to a fault. In the event thatthe possible fault current exceeds the interruptingcapacity of the available breakers, a synchronizingbus with current limiting reactors will be required.Switching arrangement selected will be adequate tohandle the maximum calculated short circuit cur-rents which can be developed under any operatingroutine that can occur. All possible sources of faultcurrent; i.e., generators, motors and outside utilitysources, will be considered when calculating shortcircuit currents. In order to clear a fault, all sourceswill be disconnected. Figure 4-5 shows, in simplifiedsingle line format, a typical synchronizing bus ar-rangement. The interrupting capacity of the break-ers in the switchgear for each set of generators islimited to the contribution to a fault from the gener-ators connected to that bus section plus the contri-bution from the synchronizing bus and large (load)motors. Since the contribution from generators con-nected to other bus sections must flow through tworeactors in series fault current will be reduced ma-terially.

d. If the plant is 20,000 kVA or larger and the

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Figure 4-5. Typical synchronizing bus.

.

area covered by the distribution system requiresdistribution feeders in excess of 2 miles, it may beadvantageous to connect the generators to a highervoltage bus and feed several distribution substa-tions from that bus with step-down substationtransformers at each distribution substation asshown in Figure 4-3.

e. The configuration of the high voltage bus willbe selected for reliability and economy. Alternativebus arrangements include main and transfer bus,ring bus and breaker and a half schemes. The mainand transfer arrangement, shown in Figure 4-6, isthe lowest cost alternative but is subject to loss ofall circuits due to a bus fault. The ring bus arrange-ment, shown in Figure 4-7, costs only slightly morethan the main and transfer bus arrangement and

L eliminates the possibility of losing all circuits from abus fault since each bus section is included in theprotected area of its circuit. Normally it will not be

used with more than eight bus sections because ofthe possibility of simultaneous outages resulting inthe bus being split into two parts. The breaker and ahalf arrangement, shown in Figure 4-8, is the high-est cost alternative and provides the highest relia-bility without limitation on the number of circuits.

4-7. Generator leadsa. Cable.

(1) Connections between the generator andswitchgear bus where distribution is at generatorvoltage, and between generator and stepup trans-former where distribution is at 34.5 kV and higher,will be by means of cable or bus duct. In most in-stances more than one cable per phase will be neces-sary to handle the current up to a practical maxi-mum of four conductors per phase. Generally, cableinstallations will be provided for generator capac-ities up to 25 MVA. For larger units, bus ducts will

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TM 5-811-6

LOAD LOAD

be evaluated as an alternative.(2) The power cables will be run in a cable tray,

separate from the control cable tray; in steel con-duit; suspended from ceiling or on wall hangers; orin ducts depending on the installation requirements.

(3) Cable terminations will be made by means ofpotheads where lead covered cable is applied, or bycompression lugs where neoprene or similarly jack-eted cables are used. Stress cones will be used at4.16 kV and above.

(4) For most applications utilitizing conduit,cross-linked polyethylene with approved type filleror ethylene-propylene cables will be used. For appli-cations where cables will be suspended from hangersor placed in tray, armored cable will be used to pro-vide physical protection. If the cable current ratingdoes not exceed 400 amperes, the three phases will

4-10

be tri-plexed; i.e., all run in one steel armored enclo-sure. In the event that single phase cables are re-quired, the armor will be nonmagnetic.

(5) In no event should the current carrying ca-pacity of the power cables emanating from the gen-erator be a limiting factor on turbine generator out-put. As a rule of thumb, the cable current carryingcapacity will be at least 1.25 times the current asso-ciated with kVA capacity of the generator (not thekW rating of the turbine).

b. Segregated phase bus.(1) For gas turbine generator installations the

connections from the generator to the side wall orroof of the gas turbine generator enclosure will havebeen made by the manufacturer in segregated phase bus configuration. The three phase conductors willbe flat copper bus, either in single or multiple con-

TM 5-811-6

ductor per phase pattern. External connection toswitchgear or transformer will be by means of segre-gated phase bus or cable. In the segregated phasebus, the three bare bus-phases will be physically sep-arated by non-magnetic barriers with a single enclo-sure around the three buses.

(2) For applications involving an outdoor gasturbine generator for which a relatively small lineupof outdoor metal clad switchgear is required to han-dle the distribution system, segregated phase buswill be used. For multiple gas turbine generator in-stallations, the switchgear will be of indoor con-struction and installed in a control/switchgear build-ing. For these installations, the several generatorswill be connected to the switchgear via cables.

(3) Segregated bus current ratings may followthe rule of thumb set forth above for generator ca-

Typical ring bus.

bles but final selection will be based on expectedfield conditions. c. Isolated phase bus.

(1) For steam turbine generator ratings of 25MVA and above, the use of isolated phase bus forconnection from generator to stepup transformerwill be used. At such generator ratings, distributionseldom is made at generator voltage. An isolatedphase bus system, utilizing individual phase copperor aluminum, hollow square or round bus on insula-tors in individual non-magnetic bus enclosures, pro-vides maximum reliability by minimizing the possi-bility of phase-to-ground or phase-to-phase faults.

(2) Isolated phase bus current ratings shouldfollow the rule of thumb set forth above for gener-ator cables.

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4-8. Switchyarda. Outdoor vs. indoor. With normal atmospheric

conditions, switchyards will be of the outdoor typeas described below. It is possible that a plant will belocated on a tropical desert area where alternatesand blasting and corrosion or contamination is aproblem or in an arctic area where icing is a problem.In such an event, an indoor switchyard or installa-tion employing totally enclosed metal clad switch-gear with SF6 insulation will be provided.

b. Structures and buses.(1) In the event distribution for a large installa-

tion is at higher than generator voltage; e.g., 34.5kV, or in the event an interconnection with a localutility is necessary, a switchyard will be required.The switching structure will be erected to supportthe bus insulators, disconnecting switches, poten-tial and current transformers, and the terminationsfor the generator stepup transformer and transmis-sion lines.

(2) Structures of galvanized steel or aluminumare most often used. Where the switchyard is lo-cated close to an ocean, the salt laden atmospheremay be extremely corrosive to aluminum requiringthe use of galvanized steel.

(3) Either copper or aluminum, tubular buseswill be employed depending upon the atmosphere,

with aluminum generally being less expensive. Cop-per bus connections will be bolted; aluminum con-nections must be welded. Special procedures are re-quired for aluminum welding, and care should betaken to assure that welders certified for this type ofwelding are available. For isolated or overseas es-tablishments, only copper buses should be used. Acorrosive atmosphere will preclude the use of alumi-num.

c. Disconnect switches; insulators(1) Two three-phase disconnect switches will be

used for each oil circuit breaker, one on each side ofthe breaker. If the ring bus arrangement is used, adisconnect switch will also be used in the circuittake-off so the ring can be reclosed with the circuitout for maintenance. If only one bus is used, a dis-connect switch will be installed as a by-pass aroundthe circuit breaker so it can be maintained.

(2) Line disconnect switches at all voltage rat-ings will have arcing horns. Above 69 kV, all discon-nect switches will have arcing horns.

(3) Current carrying capacity of each discon-nect switch will be at least 25 percent above that ofthe line or transformer to which it is connected. Theswitches are available in 600, 1200 and 2000 ampereratings.

(4) Voltage ratings of switches and bus supportinsulators will match the system voltage. In par-

titularly polluted atmospheres, the next higher volt-age rating than that of the system will be used. Insome instances, the manufacturer can furnish cur-rent carrying parts designed for the system voltageand will increase phase spacing and insulator stacklength to the next higher voltage rating in order toincrease the leakage paths in the polluted atmos-phere. In such installations, the normal relationshipbetween flashover across the open switch and flash-over to ground must be maintained.

(5) All disconnect switches will be operablefrom ground level by means of either a lever or rotat-ing crank mechanism. The crank type mechanism ispreferred because it is more positive and takes lessstrength to operate. Operating mechanisms will becapable of being locked by padlock in both the openand closed positions. A switchplate will be providedat each operating mechanism for the operator tostand on when operating the switch. Each plate willbe approximately 2 feet, 6 inches wide by 4 feetlong, made of galvanized steel, and with two groundlugs permanently attached to the underside of eachplate on the side next to the operating mechanism.The switchplates will be connected to the operatinghandle and to the switchyard ground grid at twoseparate points by means of a 2/0 stranded bare cop-per wire.

d. Oil circuit breakers.(1) For outdoor service, from nominal 13.8 kV

through 69 kV, single tank oil circuit breakers(ocb’s) having one operating mechanism attached tothe tank will be used. Above 69 kV, three tanks areused, all permanently mounted on a single channelbase, with ‘a single operating mechanism attached toone of the end tanks.

(2) Operating mechanisms can be springcharged using a motor to charge the spring, pneu-matic employing a motor driven compressor in eachoperating mechanism; or pneudraulic, a combina-tion pneumatic and hydraulic mechanism. The 69kV and below applications utilize the spring chargedmechanism because of lower cost while above 69 kV,either of the other two work satisfactorily. Both anac and a dc auxiliary source must be made availableto each breaker operating mechanism.

(3) Up to two doughnut type multi-ratio currenttransformers (600:5, with taps; or 1200:5, with taps)can be obtained on each bushing. These are mountedinside the tanks with all leads brought to terminalblocks in the mechanism cabinets. Since it is a majortask to add current transformers, the two will bepurchased initially for each bushing.

(4) A considerable range of both current carry-ing and current interrupting capacity is availablefor each system operating voltage level. Carefulstudy must be made of the continuous load current

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TM 5-811-6

and fault current requirements before selecting oilcircuit breakers. Short circuit calculations must bemade for any power system, but for extensive powersystems operating in parallel with a utility, a sys-tem study will be performed prior to selecting the oilcircuit breakers. Power networks analyzers or com-puter programs will be utilized in such work.

e. Potential and current transformers.(1) For power systems through 69 kV, potential

transformers are generally used to provide voltagesin the 69- and 120-volt ranges for voltmeters, watt-meters, varmeters, watt-hour meters, power factormeters, synchroscopes, various recorders, and forcertain protective relays and controls. Above 69 kV,the cost becomes prohibitive and capacitor potentialdevices are used. The latter do not have as muchvolt-ampere capacity as potential transformers socare must be taken not to overload the potential de-vices by placing too many instruments or devices inthe circuit.

(2) Both the potential transformers (pt’s) andcapacitor potential devices (cpd’s) will be purchasedwith dual 120 volt secondaries, each tapped at 69volts for circuit flexibility y. All should be for singlephase-to-ground application on the high voltageside.

(3) Three line-to-ground pt’s or cpd’s will be em-ployed on each main high voltage bus. Generally,only one pt or cpd is needed on each feeder for syn-chronizing or hot line indication; but for ties to theoutside utility or for special energy metering for bill-ing purposes or other energy accounting, or for re-laying, three devices will be necessary.

(4) Current transformers (et’s) of the throughtype, where the primary winding is connected in thecircuit, will seldom be used. In the usual case, thereare sufficient bushing type ct’s in the oil circuitbreakers and power transformers. Multi-ratio unitswill be employed, as described under d above, for

control, indication and protective relaying. Shouldbilling metering be needed, more accurate meteringtype bushing type ct’s will be used.

(5) Current transformer ratios do not necessar-ily have a direct relationship with the continuouscurrent capacity of the circuit breaker or transform-er bushing on which they are mounted. The high cur-rent portion of the ratio shoul be selected so thatthe circuit full load current ‘wall beat approximately70-80 percent of instrument full scale for best accu-racy. Ratios for protective relaying will be speciallyselected to fill the particular relays being applied.

(6) Joint use of a particular set of et’s for bothinstrumentation and protective relaying will beavoided because the two ratio requirements may bedifferent and testing or repair of instrument circuitsmay require those circuits to be out of service for a

time. Power circuits can be operated for extended,periods with a part of the instrumentation and me-tering out of service; they should not be operated forextended periods without the protective devices.

f. Duct system.(1) Except as otherwise described herein, duct

systems will be in accordance with TM 5-811-1/AFM 88-9.

(2) Power and control cables will be run in un-derground conduit in a concrete duct system be-tween the generating station and switchyard; thetwo types of cable maybe run in the same duct bankbut in separate conduits. If in the same duct bank,the manholes will be divided with a concrete barrierbetween the power and control cable sections. Themain power cables will be run in their own ductsystem and will terminate at the power transform-ers which are usually placed in a single row.

(3) At the point of entrance into the switchyard,the control cable duct system will empty into a con-crete cable trench system, either poured in place orassembled from prefabricated runs. The U-shapedtrench will be of sufficient size in width and depth toaccommodate control and auxiliary power cables forpresent transformers, breakers, disconnectswitches, pt’s and ct ‘s, ac and dc auxiliary power ca-bles and lighting circuits, plus provision of at least25 percent for expansion of the switchyard.

(4) Checkered plate or sectionalized prefabricated concrete covers will be placed on the trench,complete with holes or tilt-up recessed handles forassistance in removal of each cover section.

(5) Control cables will be run through sleevesfrom the trench then through galvanized steel con-duit buried 18 inches deep to the point of rising tothe circuit breaker mechanism housing or other ter-mination. Risers will be attached securely to the ter-minating device.

g. Ac and dc distribution. One or more 120/208Vat, 24 or 40 circuit distribution panlboards andone 125 Vdc, 24-circuit distribution panel will beprovided in weatherproof enclosures in a central lo-cation in the switchyard. Oil circuit breakers require125 Vdc for closing, tripping and indication. Com-pressor motors or spring winding motors for the oilcircuit breakers will require 120 or 208 volts ac, aswill the radiator cooling fans for the power trans-formers. Strip heaters for the ocb transformermechanism housings will operate at 208 Vat. Light-ing circuits will require 120 Vat. Weatherproof,grounding type convenience outlets at 120 volts and208 volts will be provided for electrically operatedtools and maintenance equipment needed to main-tain the switchyard.

h. Grading and fencing.(1) The entire switchyard area will be at the

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TM 5-811-6

same grade except for enough slope to providedrainage. The concrete pads and foundations for allocb’s and transformers; for all bus, pt and ct sup-porting structures; and for the switchyard struc-tures will be designed for the same top elevation,and final rough grade will set some 9 inches belowtop of concrete.

(2) Three inches of coarse gravel and 3 inches offine gravel will be provided on the rough gradewhich will allow the top of the concrete to be ex-posed 3 inches above the final crushed rock grade.The rough grade will be sloped at 1 inch per hundredfeet to provide drainage, but the final crushed rockcourse will be dead level. Crushed rock will extend 3feet outside the fence line.

(3) All concrete foundations will have a l-inch,45-degree chamfer so the edges will not chip.

(4) An 8-foot galvanized steel chain link fencewith round line and corner posts will enclose the en-tire substation. The fence will be angle braced inboth directions. End posts for personnel and vehiclegates will be similarly braced. Posts will be mountedin poured concrete footings, having the top caprounded for drainage.

(5) Two 36-inch wide personnel gates will beplaced in diagonally opposite locations; one locatedfor convenience for operator and maintenance regu-lar access, and the other to provide an emergencyexit. The gate for regular access will be padlockable.The emergency exit gate will not be padlocked butwill be openable only from inside the switchyard bymeans of removing a drop-in pin; the pin will be sobarriered that it cannot be removed from outside thefence. This panic hardware will be designed for in-stant, easy removal in the event use of the emergen-cy exit is necessary.

(6) A double hung, padlockable vehicle gate willbe installed; each section will be 8 feet in width toprovide adequate room for transformer removal andline truck entrance and egress.

(7) If local codes will permit, a three-strandbarbed wire security extension, facing outward at45 degrees, will be mounted on top of the fence andgates.

i. Grounding.(1) A grounding grid, buried approximately 2

feet below rough grade level will be installed prior toinstallation of cable ducts, cable trenches andcrushed rock, but simultaneously with the installa-tion of switchyard structure, ocb, and transformerfootings.

(2) The main rectangular grid will be loopedaround the perimeter of the yard and composed of500 MCM bare stranded tinned copper cable. From

the perimeter, cross-connections from side to sideand end to end will be 250 MCM stranded tinnedcopper cable on 10- to 12-foot spacing in accord-ance with TM 5-811-l/AFM 88-9. Taps will bemade to each vertical bay column of the switchyardstructure, to every pt and ct and bus support struc-ture, to every ocb and transformer, and to every dis-connect switch structure with 4/0 stranded tinnedcopper conductor. Two taps will be run to each cir-cuit breaker and power transformer from different250 MCM cross-connections.

(3) Taps will extend outward from the 500MCM perimeter cable to a fence rectangular loopwith taps at no more than 40-foot centers. This loopwill be run parallel to the fence, 2 feet outside thefence line, and the fence loop will be tapped every 20-feet via 2/0 stranded tinned copper taps securelybolted to the fence fabric near the top rail. Flexibletinned copper ground straps will be installed acrossthe hinge point at each swinging gate.

(4) At least two 500 MCM bare-stranded,tinned copper cables will be connected via directburial to the generating station ground grid. Con-nection will be made to opposite ends of the switch-yard 500 MCM loop and to widely separated pointsat the generating station grid.

(5) Ground rods, at least 8 feet long, 3/4-inch di-ameter, will be driven at each main grid intersectionpoint and at 20-foot centers along the fence loop toa depth of 13 inches above the intersection about 17inches below rough grade.

(6) Every grid intersection and every groundrod connection to both grids will be exothermicwelded using appropriate molds.

(7) The ground grid system described above willsuffice for most Army establishments except in par-ticularly rocky areas or in the Southwest desertstates. Target is to obtain not greater than fiveohms ground resistance. In rocky or desert areas,special connections of the switchyard grid to remotegrounding pits via drilled holes perhaps 200 feetdeep or grids buried in remote stream beds may benecessary. NOTE: TM 5-811-1 describes a grad-ing, fencing and grounding system in considerabledetail for station and substation applications wherepower is purchased from a utility or small genera-tors are installed. The intent herein is to provide forthe additional requirements for a larger (5000-30,000 kW) generating station stepup switchyardwhich permits connection to a distribution systemand interconnection with an outside utility system.The system herein described is a “heavy duty” sys-tem. TM 5-811-UAFM 88-9 will be followed for de-tail not described herein.

4-15

TM 5-811-6

Section IV. TRANSFORMERS

4-9. Generator stepup transformerThe stepup transformer will be in accordance withANSI Standard C 57.12.10 and will include the fol-lowing optional features.

a. Rating.(1) The generator stepup transformer kVA rat-

ing for boiler-turbine-generator “unit type” powerplants will depend upon the generator kVA ratingwhich, in turn, is dependent upon the prime moverratings. In any event, the transformer kVA ratingwill be selected so that it is not the limiting factorfor station output.

(2) As a rule of thumb, the top kVA rating willbe selected to be approximately 115-120 percent ofthe KVA rating of the generator. Since the genera-tor unit auxiliary transformer load is tapped off be-tween the generator and stepup transformer andwill amount to about 6 percent of the generator rat-ing, the operating margin for the stepup transform-er will be on the order of 20-25 percent. This will per-mit making full use of the margin the turbine gener-ator manufacturer must build in, in order to meethis guarantees.

(3) If the load served is expected to be quiteconstant and the generator will be operating at ahigh load factor, it should be cost effective to obtainan FOA (forced oil/air cooled) transformer. Pumpsand fans are on whenever the transformer is ener-gized. If, on the other hand, a widely varying load isexpected, it may be cost effective to obtain a dualrated transformer OA/FA, or even triple ratedOA/FA/FA having two increments of fan cooling aswell as a self-cooled rating. The top rating would co-ordinate with the generator rating but fans wouldshut down when the unit is operating at partial load.The resulting rating of the turbine, generator andstepup transformer for typical unit might be:

Turbine 25,000 kWG e n e r a t o r 31,250 kVA at 0.8 PFTransformer 35,000 kVA at OA/FA/FA rat-

ing(4) Voltage of the high side will match the nomi-

nal operating voltage desired for the distributionsystem, such as 34.5 kV; and for the low side willmatch the generator voltage, such as 13.8 kV. Highvoltage side will have two 2 1/2 percent full capacitytaps above and “below rated voltage.

b. Control.(1) Both the fan and pump systems will operate

on 208 volts, 60 Hz, single phase. The control sys-tem will provide automatic throwover from dual 208volt sources with one being preferred and the otheralternate; either may be selected as preferred via aselector switch. Sources will be run from separate

auxiliary power sources within the plant.(2) The transformer alarms will be connected to

the plant annunciator system and will require 125Vdc for the alarm system auxiliary relays. Protec-tive devices, which will be mounted in the trans-former with control and indication leads run by thetransformer manufacturer to the control cabinet,are as follows:

(a) Oil low level gauge with alarm contacts.(b) Top oil temperature indicator with alarm

contacts.(c) Winding hot spot oil temperature indica-

tor with two or more sets of electrically independentcontrol and alarm contacts, the number dependingon whether unit is FOA, O/FA, or OA/FA/FA.

(d) Sudden gas pressure Buchholz type relaywith alarm contacts and external reset button.

(e) Pressure relief device with alarm contactsand with operation indicator clearly visible fromground level.

(f) Pressure/vacuum gauge with electricallyindependent high and low alarm contacts; gauge tobe visible from ground level.

(g) Full set of thermally protected moldedcase circuit breakers and auxiliary control andalarm relays for denoting-Loss of preferred fan pump power source.-Automatic throwover of fan and pump sources oneor two.-Loss of control power.

(3) The control compartment will have a dualhinged door readily accessible from finished gradelevel; bottom of compartment will be about 3 feetabove grade. Thermostat and heaters will be provided,

c. Miscellaneous. Miscellaneous items that will beincluded are as follows:

(1) Control of the fixed high side winding tapswill be accessible to a person standing on theground. The control device will permit padlockingwith the selected tap position clearly visible.

(2) Base of transformer will be on I-beams suit-able for skidding the transformer in any direction.

(3) Two 600-5 or 1200-5 multi-ratio bushingct’s will be provided on each of the high side and lowside bushings with all leads brought to terminalblocks in the control cabinet.

(4) One 600-5, or lesser high current rating,bushing ct will be provided on the high side neutralbushing with leads brought to a terminal block inthe control compartment.

4-10. Auxiliary transformersa. Rating.

4-16

TM 5-811-6

(1) As a rule of thumb, the unit auxiliary trans-former for a steam electric station will have a kVArating on the order of 6 to 10 percent of the genera-tor maximum kVA rating. The percent goes downslightly as generator kVA goes up and coal firedplants have highest auxiliary power requirementswhile gas fired plants have the least. The actual rat-ing specified for an installation will be determinedfrom the expected station service loads developedby the design. The station startup and standby aux-iliary transformer for plants having a unit systemwill have a kVA rating on the order of 150 percent ofa unit auxiliary transformer— say 10 to 12 percent ofthe maximum generator kVA. The additional capac-it y is required because the transformer acts as 100percent spare for the unit auxiliary transformer foreach of one or more generators, while also serving anumber of common plant loads normally fed fromthis source. If the auxiliary power system is not onthe unit basis; i.e., if two or more auxiliary trans-formers are fed from the station bus, sizing of theauxiliary transformer will take into account the aux-iliary power loads for all units in the station plus allcommon plant loads. The sizing of auxiliary trans-formers, in any case, will be subject to an analysis ofall loads served under any set of startup, operating,or shutdown conditions with reasonable assumed

transformer outages and will include a minimum of10 percent for future load additions.

(2) Auxiliary transformer voltage ratings willbe compatible with the switchyard voltage and theauxiliary switchgear voltages. Two 2 1/2 percent tapsabove and below rated voltage on the high voltageside will be included f or each transformer.

b. Control.(1) One step of fan control is commonly pro-

vided, resulting in an OA/FA rating. Fan control forauxiliary transformers will be similar to that de-scribed for the generator stepup transformer, exceptthat it is not necessary to provide for dual powersources to the fans. Since the unit auxiliary and thestation auxiliary transformers can essentially fur-nish power for the same services, each transformerserves as a spare for the other. Also, if a fan sourcefails, the transformer it serves can still be operatedcontinuously at the base self-cooled rating.

(2) The protective devices and alarms will beidentical to those of the generator stepup trans-former.

(3) The control compartment will be similar tothat of the generator stepup transformer.

c. Miscellaneous. The miscellaneous items will besimilar to those for the generator stepup transform-er, except that only one set of multi-ratio bushingct’s need be provided on each of the high and lowside bushings.

4-11. Unit substation transformera. Definition. The phrase “unit substation” is

used to denote a unit of equipment comprising atransformer and low-side switchgear designed andfactory assembled as a single piece of equipment. Itis used herein to denote an intermediate voltage re-ducing station fed by one or two circuits from theauxiliary switchgear and, in turn, serving a numberof large motors or motor control centers. The break-ers will have lower ratings than those in the auxiliary switchgear but higher ratings than those in themotor control centers. The transformer in the “unitsubstation” is referred to as a “unit substationtransformer.”

(1) The term “unit auxiliary transformer” isused to denote the transformer connected to thegenerator leads that provides power for the auxilia-ries of the unit to which it is connected. It feeds the“auxiliary switchgear” for that unit.

(2) The “unit stepup transformer” designatesthe stepup transformer that is connected perma-nently to the generator terminals and connects thatgenerator to the distribution system.

b. Rating. For steam electric stations there willbe a minimum of two unit substations per turbineinstallation so that each can be located near an areaload center to minimize the lengths of cables servingthe various low voltage loads. The kVA rating of thetransformer in each unit substation will be suffi-cient to handle the full kVA of the connected load,including the starting kVA of the largest motor fedfrom the center, plus approximately 15 percent forfuture load additions. For diesel engine or gas tur-bine installations, these unit substations may not berequired or one such unit substation may serve morethan one generating unit.

c. Control. No fans or pumps are required andthus no control voltage need be brought to thetransformer.

d. Alarms. Protective devices will be mounted onthe transformer with alarm leads run to an easily ac-cessible terminal board. Devices will include a wind-ing hot spot temperature indicator having twoalarm stages for two temperature levels with elec-trically independent alarm contacts. On occasion, itwill be found that design and construction of theunit substation transformer and its physically at-tached 480-volt switchgear may require the groundindication pt’s and their ground indicating lamps tobe mounted within and on the transformer venti-lated enclosure. In this event, the ground alarm re-lays will be mounted in a readily accessible portionof the enclosure with leads brought to terminalblocks for external connection to the control roomannunicator.

4-17

TM 5-811-6

Section V. Protective RELAYS AND METERING

4-12. Generator, stepup transformerand switchyard relaying

a. General. Selection of relays and coordination oftheir settings so that the correct circuit breakertrips when it is supposed to, and does not trip whenit is not supposed to is a subject too broad to be cov-ered herein. For the purpose of this document thelistings below will set forth those protective relaytypes which will be considered.

b. Generator relaying. Each generator will be pro-vided with the following protective relays:–Three – Generator differential relays (ANSI De-vice 87)–One – Lockout relay, electrical trip, hand reset(ANSI Device 86)–One – Loss of field relay (ANSI Device 40)–One – Negative sequence relay (ANSI Device 46)–One – Reverse power relay (ANSI Device 32)–One – Generator field ground relay (ANSI Device64)–Three – Phase time overcurrent relays, voltagerestrained (ANSI Device 51V)—One – Ground overcurrent relay in the generatorneutral (ANSI Device 5 lG)Although not a part of the ANSI device identifica-tion system, generator relay numbers are frequentlysuffixed with a letter-number sequence such as‘(G1”. For instance, differential relays for generator1 would be 87G 1 and for generator 2 would be 87G2.

c. Relay functions.(1) It is usual practice in relay. application to

provide two separate relays that will be activated bya fault at any point on the system. In the case of agenerating unit with an extended zone of differentialprotection including generator, feeder, auxiliarytransformer, stepup transformer and circuit break-er, it is also common practice to use a dedicated zoneof differential protection for the generator as back-up protection.

(2) The lockout relay (ANSI device 86) is a handreset device to control equipment when it is desiredto have the operator take some positive action be-fore returning the controlled equipment to its nor-mal position.

(3) If a unit operating in parallel with otherunits or a utility system loses its excitation, it willdraw excessive reactive kVA from the system,which may cause other difficulties in the system ormay cause overloads in the generator. The loss offield relays (ANSI device 40) will sense this situa-tion and initiate a safe shutdown.

(4) Negative sequence currents flowing in a gen-erator armature will cause double frequency mag-netic flux linkages in the rotor and may cause sur-

face heating of the rotor. The generator is designed to accept a specified amount of this current con-tinually and higher amounts for short periods with-in a specified integrated time-current square (I2

2t)limit. The negative sequence relay (ANSI device 46) is to remove the unit from service if these limits areexceeded..

(5) The reverse power relay (ANSI device 32) isused to trip the generator from the system in case itstarts drawing power from the system and drivingits primemover.

(6) A ground on the generator field circuits isnot serious as long as only one ground exists. How-ever, a second ground could cause destructive vibra-tions in the unit due to unbalanced magnetic forces.The generator field ground relay (ANSI device 64) isused to detect the first ground so the unit can beshut down or the condition corrected before a secondground occurs.

(7) The phase time-overcurrent relays (ANSIdevice 51) are used for overload protection to pro-tect the generator from faults occurring on the sys-tem.

(8) The ground overcurrent relay (ANSI 51G) inthe generator neutral is used to confirm that aground fault exists before other ground relays canoperate, thus preventing false trips due to unbal- antes in circuit transformer circuits.

d. Power transformer relaying. Each stepuptransformer will be provided with the following pro-tective relays:

(1) Three – Transformer differential relays(ANSI Device 87).

(2) One–Transformer neutral time over-current -relay to be used as a ground fault detector relay(ANSI Device 51G)

(3) One–Transformer sudden gas pressure relay. This device is specified and furnished as part ofthe transformer (ANSI Device 63).

(4) For application in a “unit system” wherethe generator, the stepup transformer, and the aux-iliary transformer are connected together perma-nently, an additional differential relay zone is estab-lished comprising the three items of equipment andthe connections between them. This requires threeadditional differential relays, one for each phase,shown as Zone 1 in Figure 4-3.

e. Auxiliary transformer relaying. These transfor-mers will each be provided with the following pro-tective relays:

(1) Three–Transformer differential relays(ANSI Device 87)

(2) One–Lockout relay (ANSI Device 86)(3) One–Transformer netural time overcurrent

4-18

.

relay to be used as a fault detector relay (ANSI De-vice 51G)

(4) One–Transformer sudden gas pressure re-lay (ANSI Device 63).

f. Switchyard bus relaying. Each section of theswitchyard bus will be provided with bus differen-tial relaying if the size of the installation, say 25,000kW or more, requires high speed clearing of busfaults.

g. Distribution feeder relaying. Whether feedersemanate from the switchyard bus at, say 34.5kV, orfrom the generator bus at 13.8 kV, the following re-lays will be provided for each circuit:

(1) Three–Phase time overcurrent relays withinstantaneous element (ANSI Device 50/5 1).

(2) One–Residual ground time overcurrent re-lay with instantaneous element (ANSI Device50/51 N).

h. Ties to utility. Relaying of tie lines to the util-ity company must be coordinated with that utilityand the utility will have its own standards whichmust be met. For short connections, less than 10miles, pilot wire relaying is often used (ANSI device87PW). For longer connections, phase directionaldistance and ground distance relays are often used(ANSI device 21 and 21 G). Various auxiliary relayswill also be required. Refer to the utility for these tieline protective relaying requirements.

4-13. Switchgear and MCC protectiona. Medium voltage switchgear (4160 volt system).

(1) The incoming line breaker will be providedwith: Three-Phase time overcurrent relays sethigh enough to provide protection against bus faultson the switchgear bus and not to cause tripping onfeeder faults (ANSI Device 50/51).

(2) Each transformer feeder will be providedwith:

(a) Three-Phase time overcurrent relayswith instantaneous trip attachments (ANSI Device50/51).

(b) One–Residual ground time overcurrentrelay with instantaneous trip attachment (ANSIDevice 50N/51N).

(3) Each motor feeder will be provided with:(a) Three–Phase time overcurrent relay

(ANSI Device 50/51).(b) One–Replica type overcurrent relay

(ANSI Device 49) (to match motor characteristicheating curves).

(4) Each bus tie will be provided with: Three–Phase time overcurrent relays (ANSI Device 50).

b. Unit substation switchgear protection (480 voltsystem). Breakers in the 480-volt substations uti-lize direct acting trip devices. These devices will beprovided as follows:

(1) Incomingtime elements.

TM 5-811-6

line: three–long time and short

(2) Motor control center feeders: three–longtime and short time elements.

(3) Motor feeders: three–long time and instan-taneous elements.

c. Motor control center protection (480-volt sys-tem). Because of the lower rating, breakers will bemolded case type employing thermal/magnetic ele-ments for protection on direct feeders. Combinationstarters will employ three thermal protective heatertype elements in conjunction with the starter.

4-14. Instrumentation and meteringThe following instruments will be mounted on thecontrol board in the operating room to provide theoperator with information needed for operations:

a. Generator.(1)(2)(3)(4)(5)(6)(7)

Ammeter with phase selector switchVoltmeter with phase selector switchWattmeterVarmeterPower factor meterFrequency meterTemperature meter with selector switch for

stator temperature detectors(8) D.C. volmeter for excitation voltage(9) D.C. ammeter for field current

b. Stepup transformer.(1) Voltmeter on high voltage side with selector

switch(2) Ammeter with selector switch(3) Wattmeter(4) Varmeter(5) Power factor meter

c. Auxiliary transformer.(1)

switch(2)(3)(4)(5)

Voltmeter on low voltage side with selector

Ammeter with selector switchWattmeterVarmeterPower factor meter

d. Common.(1) Voltmeter with selector switch for each bus(2) Synchroscope

e. Integrating meters. The following integratingmeters will be provided but need not be mounted onthe control board:

(1) Generator output watthour meter(2) Auxiliary transformer watthour meter for

each auxiliary transformer.f. Miscellaneous. For units rated 20,000 kW or

larger, a turbine-generator trip recorder will be pro-vided but not necessarily mounted on the controlboard. This is for use in analyzing equipment fail-ures and shutdowns.

4-19

TM 5-811-6

Section Vl. STATlON SERVlCE POWER SYSTEMS

4-15. General requirementsa. Scope. The power plant station service electric-

al system will consist of the following(1) For steam turbine plants of about 20,000

kW or larger, a medium voltage (4.16 kV) distribu-tion system utilizing outdoor oil filled auxiliarypower transformers and indoor metal clad drawouttype switchgear assemblies. Usually a medium vol-tage level of 4.16 kV is not required until generatorunit sizes reach approximately 20 MW. A 4.16 kVsystem may be grounded permitting the use ofphase and ground protective relays.

(2) A low voltage (480-volt and 208/120-volt)distribution system, unit substation assemblies,and also motor control centers containing combina-tion starters and feeder breakers.

(3) Station power requirements are smaller forcombustion gas turbine units and diesel engine driv-en generators. For the combustion gas turbineplant, a starting transformer capable of supplyingthe starting motors is required if the turbine is mo-tor started, but may serve more than one unit. Fordiesel plants a single 480-volt power supply withappropriate standby provisions is adequate for allunits.

b. Operating conditions and redundancy. The sta-tion service system will be designed to be operation-al during station startup, normal operation and nor-mal shutdown. Redundancy will be provided to per-mit operation of the plant at full or reduced outputduring a component failure of those portions of thesystem having two or more similar equipments.

c. Switchgear and motor control center location.Switchgear inside the power plant will be located soas to minimize the requirements for conduit to beembedded in the grade floor slab. In steam electricplants it will generally be convenient to have one ormore motor control centers at grade with top en-trance of control and power cables. The 4160-voltswitchgear and 480-volt unit substation will prefer-ably be located on upper floor levels for maximumconvenience in routing power cables; control andpower cables can thus enter from either above or be-low. The 480-volt switchgear in combustion gas tur-bine or diesel plants will be at ground level.

4-16. Auxiliary power transformersa. Type. The auxiliary power transformers will be

oil filled, outdoor type, having both natural andforced air cooled ratings.

b. Taps. Four full capacity taps for deenergizedtap changing will be provided on the high voltageside, in two 2 1/2 percent increments above and belowrated voltage.

4-20

c. Impedance.(1) Impedance should be selected so that the

voltage drop during starting of the largest motor onan otherwise fully loaded bus will not reduce motorterminal voltage below 85 percent of the nominalbus voltage to assure successful motor startingunder adverse conditions and so that the symmetri-cal short circuit current on the low voltage side willnot exceed 48 kA using 4160 volt rated switchgearor 41 kA for 4.16 kV system where 2400 volt switch-gear is to be used. This permits using breakers having an interrupting rating of 350 MVA for 4160volts swichgear or 300 MVA for 2400 volt switch-gear.

(2) Meeting these criteria is possible for units of the size contemplated herein. If the voltage dropwhen starting the largest motor exceeds the criteri-on with the fault current limited as indicated, al-ternative motor designs and reduced voltage start-ing for the largest motor or alternative drives forthat load, will be investigated.

d. Transformer connections.(1) With the unit system, the turbine generator

unit auxiliary transformers will be 13.8 kV delta to4.16 kV wye. If the startup and standby auxiliarytransformer is fed from a bus to which the generatoris connected through a delta-wye transformation, it must be wye-wye with a delta tertiary. The wye-wyeconnection is necessary to get the correct phase rela-tionship for the two possible sources to the 4160volt buses. Voltage phase relationships must be con-sidered whenever different voltage sources are inparallel. For wye-wye or delta-delta transformer con-nections, there is no phase shift between theprimary and secondary voltages. However, for delta-wye or wye-delta transformer connections, theprimary and secondary voltage will be 30 degreesout of phase in either a leading or lagging relation-ship. With the correct arrangement of transformersit will be possible to establish correct phase anglesfor paralleling voltages from different sources. Figures 4– 1, 4-2 and 4-3 illustrate the typical phase re-lationships for power station generators and trans-formers.

(2) Where more than one generator is installed,a single startup and standby auxiliary transformeris sufficient. The low side will be connected throughsuitable switches to each of the sections of mediumvoltage switchgear,

4-17. 4160 volt switchgeara. Type. The 4160 volt assemblies will be indoor

metal clad, drawout type employing breakers hav-ing a symmetrical interrupting rating of 48 kA and

TM 5-811-6

with copper or aluminum buses braced to withstandthe corresponding 350 MVA short circuit. Quantityof breakers will be determined to handle incomingtransformer, large motors above 200 hp and trans-former feeds to the 480 volt unit substations.

b. Cable entrance. Power and control cable en-trance from above or below the gear will depend onfinal locations in the power plant.

c. Relaying. Appropriate protective relaying willbe applied to each incoming and outgoing circuit asdiscussed in paragraph 4- 13a above.

4-18. 480 volt unit substationsa. General arrangement. The unit substation as

defined in subparagraph 4-1 la, or power centers,employ a 4160-480 volt transformer close coupledto a section of 480 volt switchgear. Switchgear por-tion will utilize drawout breakers and have breakersand buses braced to interrupt and withstand, re-spectively, a short circuit of 42 kA, symmetrical.Buses may be of aluminum or copper.

b. Loads served. The unit substations will serveas sources for 480-volt auxiliary motor loads be-tween 75 and 200 horsepower, and also serve as sup-ply to the 480-volt motor control centers.

c. Cable entrance. Power and control cable en-trance from above or below will depend on final loca-tion in the station.

d. Trip devices. Direct acting trip devices will beapplied to match the appropriate transformer ormotor feeder load and fault characteristics as dis-cussed in paragraph 4- 13b above.

4-19. 480-volt motor control centersa. General arrangement. Motor control centers

(MCC’S) will utilize plug-in type circuit breakers andcombination starters in either a front only or a back-to-back free standing construction, depending onspace limitations. Main bus, starters and breakerswill be braced to withstand a short circuit of 22 kA,symmetrical. A power panel transformer and feederbreaker, complete with a 120/208 volt power paneland its own main breaker, may be built into theMCC.

b. Current limiting reactors. Dry type three phasereactors, when necessary, will be located in a verti-cal section of the MCC’s to reduce the availableshort circuit at the 480-volt unit substations to 22kA at the MCC’s. Each system will be investigatedto determine the necessity for these current limitingreactors; cable reactance will play an important partin determining the necessity for reactors.

c. Location. The several motor control centerswill be strategically located in the power plant toserve most of the plant auxiliary motor loads, light-ing transformers, motor operated devices, welding

receptacle system and the like. Loads should begrouped in such a manner as to result in relativelyshort feeder runs from the centers, and also to facili-tate alternate power sources to vital services.

d. Cable space. Connection to the MCC’s will bevia overhead cable tray, and thus the top horizontalsection of the MCC will incorporate ample cabletraining space. Control and power leads will termi-nate in each compartment. The MCC’s can be de-signed with all external connections brought by themanufacturer to terminal blocks in the top or bot-tom horizontal compartments, at added expense.

e. Enclosures. Table 4-1 lists standard MCC en-closures. Type 2, drip tight, will be specified for allindoor power plant applicants; Type 3, weather re-sistant, for outdoor service. The other types listed inTable 4-1 should be used when applicable.

4-20. Foundationsa. Transformers. The outdoor auxiliary power

transformers will be placed on individual reinforcedconcrete pads.

b. Medium voltages switchgear. The medium volt-age switchgear assemblies will be mounted on flushembedded floor channels furnished by the switch-gear manufacturer prior to shipment of the gear.

c. Unit substations and motor control centers.480-volt unit substation transformers and switch-gear, and all MCC's will be mounted on chamferedconcrete pads at least 3 inches above finished floorgrade. Foundations will be drilled for clinch anchorsafter the foundation has been poured and set; theanchor placement will be in accordance with theswitchgear manufacturer’s recommendation.

4-21. GroundingA minimum 1/4-inch by 2-inch copper ground buswill be incorporated within the lower rear of eachsection of switchgear and MCC. Each ground bus .will be connected to the station ground grid withtwo 4/0 stranded copper cables.

4-22. Conduit and tray systemsa. Power cables. Power cables will generally be

run in galvanized rigid steel conduit to the motorand switchgear terminations, although a laddertype galvanized steel cable tray system having ade-quate support may be used with conduit runoutsfrom trays to terminations.

b. Control cables. Control cables will be run in anexpanded metal galvanized steel overhead tray sys-tem wherever possible. Adequate support will beprovided to avoid sagging. Exit from the tray willbe via rigid steel conduit.

c. Grounding. Every cable tray length (i.e., eachconstruction section) will be grounded by bolting to

4-21

TM 5-811-6

Table 4-1. Standard Motor Control Center Enclosures.NEMA Classification

Type 1:General purpose . . . . . . . . . . . . . .

Type 1:Gasketed . . . . . . . . . . . . . . . . . . . . .

Type 2:Drip tight . . . . . . . . . . . . . . . . . . .

Type 3:Weather-resistant . . . . . . . . . . . .

Type 4:Watertight . . . . . . . . . . . . . . . . . . .

Type 7:Hazardous locations, Class 1,Air break . . . . . . . . . . . . . . . . . . . .Type 9:Hazardous locations, Class 2,Groups F & G. . . . . . . . . . . . . . . . .Type 9-C:Hazardous locations, Class 2,Group E. . . . . . . . . . . . . . . . . . . . .

Type 12:Industrial use . . . . . . . . . . . . . . .

Source: NAVFAC DM3

Comments

A sheet metal case designed primarilyto protect against accidental contactwith the control mechanism.

The general purpose enclosure withgasketed door or cover.

Similar to Type 1 with the addition ofdrip shields or the equivalent.

Designed to provide protection againstweather hazards such as rain and sleet.

Designed to meet the hose test describedin NEMA Definition lC-1.2.6B.

Enclosures designedrequirements of thespecific classes of

to meet the applicationNEC for the indicatedhazardous locations.

A sheet metal case designed with weldedcorners and no knockouts to meet theJoint Industry Conference standards foruse where it is desired to exclude dust,l i n t , fibers and fillings, and oil orcoolant seepage.

a stranded bare copper ground cable which will be 4-23. Distribution outside the powerrun throughout the tray system. The tray cable it- plantself will be tapped to the plant ground grid at eachbuilding column. Basic tray cable will be 4/0 bare

Electrical distribution system for the installation

stranded copper with connections to station taps ofoutside of the power plant is covered in TM5-811-11AFM88-9.

minimum 2/0 copper.

4-22

4-24. Battery and charger

TM 5-811-6

Section Vll. EMERGENCY POWER SYSTEM

a. General requirements. The dc system, consist-ing of a station battery, chargers and dc distributionpanels, provides a continuous and reliable source ofdc control voltage for system protection during nor-mal operation and for emergency shutdown of thepower plant. Battery will be nominal 125 volts,mounted on wooden racks or metal racks with PVCcovers on the metal supporting surfaces. Lead calci-urn cells having pasted plates Plante or other suit-able cells will be considered for use.

b. Duty cycle. Required capacity will be calcu-lated on an 8-hour duty cycle basis taking into ac-count all normal and emergency loads. The dutycycle will meet the requirements of the steam gen-erator burner control system, emergency coolingsystems, control benchboard, relays and instrumentpanels, emergency lighting system, and all close/tripfunctions of the medium voltage and 480-volt cir-cuit breaker systems. In addition, the followingemergency functions shall be included in the dutycycle:

(1) Simultaneously close all normally openbreakers and trip 40 percent of all normally closedbreakers during the first minute of the duty cycle;during the last minute, simultaneously trip all mainand tie breakers on the medium voltage system.

(2) One hour (first hour) running of the turbinegenerator emergency lube oil pump motor and, forhydrogen cooled units, 3-hour running of the emer-gency seal oil pump motor.

(3) One hour (first hour) running of the backupturning gear motor, if applicable.

c. Battery chargers.(1) Two chargers capable of maintaining a 2.17

the proper float and equalizing voltage on the bat-tery will be provided. Each charger will be capableof restoring the station battery to full charge in 12hours after emergency service discharge. Also, eachunit will be capable of meeting 50 percent of the to-tal dc demand including charging current taken bythe discharged battery during normal conditions.Note: Equalizing voltage application will subjectcoils and indicating lamps to voltages above thenominal 125-volt dc system level. These devices,however, will accept 20 percent overvoltage continu-

Section Vlll.

4-26. GeneralMotors inside the power plant require drip proof en-closures, while outside the plant totally enclosed fancooled motors are used. For induced draft and forceddraft, and outdoor fan motors in the larger sizes, a

ously. To assure, however, that the manufacturer ofall dc operated devices is aware of the source of dcsystem voltage, the various equipment specifica-tions will advise that the nominal system voltagewill be 125 volts but will have an equalizing chargeapplied periodically.

(2) Appurtenances. The following instrumentsand devices will be supplied for each charger:

(a) Relay to recognize loss of ac supply.(b) Ac voltage with selector switch.(c) Dc ground detection system with test de-

vice.(d) Relay to recognize loss of dc output.(e) Relay to alarm on high dc voltage.(f) Relay to alarm on low dc voltage.(g) Dc voltmeter.(h) Dc ammeter with shunt.

d. Battery room. Only the battery will be locatedin a ventilated battery room, which will be in accord-ance with TM 5-811-2. The chargers maybe wall orfloor mounted, together with the main dc distribu-tion panel, immediately outside the battery room.

e. DC distribution panel. The distribution panelwill utilize molded case circuit breakers or fuses se-lected to coordinate with dc breakers furnished incontrol panels and switchgear. The breakers will beequipped with thermal magnetic trip devices, andfor 20 kA dc interrupting rating.

4-25. Emergency ac systemThose portions of the station service load that mustbe operable for a safe shutdown of the unit, or thatare required for protection of the unit during shut-down, will be fed from a separate 480-volt unitemergency power bus. A suitable emergency dieselengine driven generator will be installed and ar-ranged to start automatically and carry these loadsif the normal source of power to this bus is lost. Theloads fed from this bus might include such things asemergency lighting, communication system, bat-tery charger, boiler control system, burner controlsystem, control boards, annunciator, recorders andinstrumentation. Design of these systems will pro-vide for them to return to operation after a briefpower outage.

MOTORS

weatherproof construction employing labyrinthtype enclosures for air circulation will be applied.All motors will be capable of starting at 85 percentnameplate voltage.

4-23

TM 5-811-6

4-27. Insulationa. 4000-volt motors. Motors at this voltage will

be three phase, 60 Hz, have Class B insulation for 80C. rise above 40 C. ambient, and with 1.0 servicefactor.

b. 460-volt motors. These motors will be threephase, 60 Hz, have Class B insulation for 80 C. rise,or Class F for 95 C. rise, above 40 C. ambient, andwith 1.0 service factor.

c. 115-volt motors. These motors will be onephase, 60 Hz, with Class B insulation for 80 C. riseabove 40 C. ambient, and with 1.25 service factor.

4-28. HorsepowerIt is seldom necessary to specify motor horsepowerif the motor is purchased with the driven equipmentas is the usual case with military projects. In almostevery instance, the load required by the pump, fan,or other driven equipment sets the motor horse-power and characteristics-thus the specification iswritten to require manufacturer of the driven ma-chine to furnish a motor of proper horsepower andcharacteristics to perform the intended function.

4-29. GroundingEvery motor will be connected to the station groundgrid via a bolted connection to a stranded coppertap. Single phase motors may be grounded with #6AWG bare wire; to 75 horsepower, three phase with#2 AWG bare stranded copper cable; and to 200 hp,three phase, with 2/0 bare stranded copper wire.

Above 200 horsepower, three phase, 4/0 barestranded copper wire will be used for the groundconnection.

4-30. ConduitMotor power cables will be run in rigid steel galvan-ized conduit to a point approximately 18 inchesfrom the motor termination or pull box. The last 18inches, approximately, will be flexible conduit withPVC weatherproof jacket. Firm support will be giv-en the rigid conduit at the point of transition to theflexible conduit.

4-31. CableIn selecting motor cable for small motors on a highcapacity station service power system, the cable sizeis seldom set by the motor full load current. Manu-facturer’s curves showing copper temperature melt-ing values for high short circuit currents for a spe-cific time duration must be consulted; the cable mayneed to be appreciably larger than required bymotor full load current.

4-32. Motor detailsIt is important to specify enclosure type, specialhigh temperature or other ambient conditions andsimilar data which is unique to the particular application. Also the type of motor, whether squirrelcage, wound rotor or synchronous, and power supply characteristics including voltage, frequency,and phases must be specified.

Section IX. COMMUNICATION SYSTEMS

4-33. Intraplant communicationsa. General requirements. Installation of a high

quality voice communication system in a power‘ plant and in the immediate vicinity of the plant is

vital to successful and efficient startup, operationand maintenance. The communications system se-lected will be designed for operation in a noisy en-vironment.

b. Functional description. A description of thefeatures of an intraplant communication system isgiven below.

(1) A page-talk party line system will be re-quired.

(2) If a conversation is in process on the partyline when a page is initiated, the paging party willinstruct the party paged to respond on the “page”system. This second conversation will be carried onover the page system—that is, both parties will beheard on all speakers, except that the speakers near-est the four or more handsets in use will be muted.

(3) If a party wishes to break into a private con-versation, all he will do is lift his handset and break

4-24

into the private conversation already taking place.Any number of parties will be able to participate in the “private conversation” because the private sys-tem is a party line system.

(4) Additional handsets and speakers can beadded to the basic system as the power plant or outdoor areas are expanded.

c. Handsets.(1) Except for handsets at desks in offices or

operating rooms, the indoor handsets in the powerplant will be hook switch mounted in a metal enclos-ure having a hinged door. They will be mounted onbuilding columns approximately 5 feet above thefloor. In particularly noisy areas, e.g., in the boilerfeed pump and draft fan areas, the handsets will beof the noise canceling types.

(2) Desk type handsets will be furnished eitherfor table top use or in “wall-mounting” hook switchtype for mounting on the side of a desk. The hookswitch wall mounting will also be used at various control boards for ease of use by the plant controlroom operators.

TM 5-811-6

(3) Outdoor handsets will be hook switch area configuration but a handset will be readilymounted in a weatherproof enclosure having a available to any operator performing an operatinghinged door. They will be mounted on the switch- function.yard structure or other structure five feet above d. Speakers.final grade. (1) Speakers for general indoor use will be of

(4) Flexible coil spring type cords will be sup- relatively small trumpet type and will be weather-plied with each handset to permit freedom of move- proof for durability. They will be mounted on build-ment by the caller. In the control room provide extra ing columns about 10 feet above floor level withlong cords. The spacing depends upon the operating spacing as indicated in Table 4-2.

Table 4-2. Suggested Locations for Intraplant Communication Systems Devices.

For Speakers

Two ceiling speakers.

Handsets

Control Room Desk set on operator’s desk;handsets spaced about 10-feet apart on controlbenchboards and on eachisolated control panel.

Offices Ceiling speaker inSup’t. and AssistantSup’t. o f f i c e s .

Desk set in each office.

Locker Room

Plant

Wall speaker in lockerroom.

Wall handset in locker room.

Column mounted speakersas necessary to providecoverage of work areas.The required spacingwill depend upon plantlayout, equipment loca-tion and noise levels.

Column mounted handsets,as necessary to provideconvenient access.

Switchyard

Cooling tower area

Fuel oil unloadingarea (or coal handl-ing area)

Gate house (if power

Minimum two structuremounted speakers atdiagonally oppositecorner of structure.

Mininum two structuremounted handsets at quarterpoints on longitudinalcenterline of structure.

Speaker mounted oncooling tower auiliarybuilding facing tower.

Two handsets; one insideauxiliary building; onemounted on outside wall.

Minimum two speakers onstructures (one insidecrusher house).

One handset near pump area(one handset inside gradedoor or crusher house).

Speaker on outside ofgate house.

One handset outside fence,at personnel or vehicleplant area is fenced)gate.

Note: Speakers and handsets for inside-the-power plant coverage willbe provided at every floor and mezzanine level from basement touppermost boiler platform.


4-25

TM 5-811-6

(2) Speakers for outdoor use will be largetrumpet type, weatherproof. They will be mountedon the switchyard structure or other structureabout 15 feet above final finished grade.

(3) In the control room, two flush mountedspeakers will be installed in the ceiling. A wallmounted speaker in wooden enclosure will be pro-vided for the plant superintendent’s office, trainingroom or other similar location.

e. Power supply.(1) Power supply will be 120 Vat, 60 Hz, single

phase as supplied from the emergency power sup-ply. The single phase conductors will be run in theirown conduit system. It is vital to have the plantcommunication system operable under all normaland emergency conditions.

(2) The manufacturer will be consulted regard-ing type of power supply cable, as well as type,shielding, and routing of the communication pairconductors.

f. Device locations, general. Proper selection andplanning for location of components is necessary toensure adequate coverage. Alignment of speakers isimportant so as to avoid interference and feedback.

It is not necessary to have a speaker and a handsetmounted near to one another. Speakers will be posi-tioned to provide “page” coverage; handsets will beplaced for convenience of access. For example, a speaker may be mounted outdoors to cover a tankarea, while the nearest handset may be convenientlylocated immediately inside the plant or auxiliarybuilding adjacent to the door giving access to thetanks.

g. Suggested device locations. Table 4-2 showssuggested locations for the various intraplant com-munication systems devices.

4-34. Telephone communicationsAt least one normal telephone desk set will be pro-vided in the central control room for contact by the operators with the outside world and for contactwith the utility company in the event of paralleloperation. For those instances when the power plantis connected into a power pool grid, a direct tele-phone connection between the control room and thepool or connected utility dispatcher will also be pro-vided.

TM 5-811-6

●

✎

✎ ✎

.

‘

CHAPTER 5

GENERAL POWER PLANT FACILITIES DESIGN

Section l. lNSTRUMENTS AND CONTROL SYSTEMS

5-1. GeneralInput adjustments will be designed to be delegatedto automatic control systems except during startup,shutdown, and abnormal operating conditions whenthe operator. displaces or overrides automatic con-trol functions.

5-2. Control panelsa. Types and selection.

(1) General types. Control panels used in powerplants may be free standing or mounted on a wall orcolumn, as appropriate.

(2) Central control panel selection. Controlpanels for use in central control rooms will be en-closed and of the dual switchboard, duplex switch-board, dual benchboard, control benchboard, or con-trol desk type depending upon the size of the plantand complexity of the instruments and controls tobe mounted. When control panels have complex wir-ing (piping and devices mounted in the interior) thevertical panel section will be provided with rear orwalk-in access for ease in erection and maintenance.Frequently the floor of the walk-in space is dropped

.2 or 3 feet below the raised control room floor to sim-plify cable and tubing entrance to the panel interiorand to increase space for terminals. A dropped floorwill be provided for proper access to any benchboardsection of a panel. The shape of the panel will be se-lected using the following criteria:

(a) Space availability in the control room.(b) Number of controls and instruments to be

mounted.(c) Visibility of the controls and instruments

by the plant operators.(d) Grouping and interrelationship of the con-

trols and instruments for ease of operation andavoidance of operating error.

b. Location of panels.(1) Control room. The various panels located in

the central control room will be arranged to mini-mize operator wasted motion. In a unitized powerplant (one without a header system), provide aboiler-turbine mechanical panel (or section) for eachunit with separate common panel(s) to accommodatecompressed air, circulating water, service water andlike system which may pertain to more than one

unit. Coal handling, ash handling and water treatingpanels will not be located in the central control roomunless the plant is small and the operating crew maybe reduced by such additional centralizing. If theplant has a header system which is not conducive toboiler-turbine panels, group controls and instru-ments into a boiler panel for all boilers and a turbinegenerator panel for all turbines whenever practic-able. Usually, a separate electrical panel with mimicbus for the generators and switchgear and switch-yard, if applicable, will be provided regardless ofwhether the mechanical instruments are grouped ona unit basis or a header basis.

(2) Local panels. These will be mounted as closeto the equipment (or process) they are controlling asis practical.

c. Instrument selection and arrangement onpanels. Selection and arrangement of the variouscontrols, instruments and devices on the panels willbe generally in accordance with the guidelines ofTables 5-1,5 -2,5-3 and 5-4, and the following

(1) Items. Mechanical items will be grouped bybasic function (i.e., turbine, boiler, condensate, feed-water, circulating water, service water and like sys-tems), Burner management controls will be obtainedas an “insert” or subpanel which can be incorporat-ed into the boiler grouping of controls and instru-ments. Such an insert may include remote lightoffand startup of burners if desired. Electrical itemswill be grouped by generator, voltage regulator,switchgear and like equipment items in a mannerwhich is easily incorporated into a mimic bus.

(2) Readability. Instruments which requireoperator observation will be located not higher than6 1/2 feet nor lower than 3 feet above the floor foreasy readability.

(3) Controls, switches and devices. Those con-trols, switches and other devices which requiremanipulation by the operators will be easily access-ible and will be located on a bench or desk whereverpracticable.

(4) Indicators versus recorders. Indicators willbe provided where an instantaneous reading of cyclethermodynamic or physical parameters suffices as acheck of proper system operation. When a perma-nent record of plant parameters is desired for eco-

5-1

TM 5-811-6

Table 5-1. List of Typical Instruments and Devices to be Provided for Boiler Turbine Mechanical Panel

Measurementor Device

Pressure

Temperature

Flow

Notes: (1)

(2)

(3)

(4)

Primary ElementFluid Location

SteamSteamSteamSteamFeedwaterCondensateFuel gasFuel gasFuel gasFlue gasLube OilVacuum

SteamSteamSteamAir-flue gasLube Oil

Steam

AirC02

FeedwaterFeedwaterFuel gas

Fuel oil

Boiler drumBoiler atomizing steamTurbine ThrottleDeaerator steam spaceBFP dischargeCond. pump dischargeBoiler burnersIgniterBoiler burne s

Turbine generatorCondenser

Turbine throttleBoiler superheater outletTurbine extraction steamBoiler draft systemTurbine generator

Boiler main steam

Boiler FD f n discharge

Boiler main supplyBoiler AttemperatorBoiler burner supply

Boiler burner supply

Including FD fan discharge, air inlet & outlet

Instrument orDevice on Panel

IndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicator

Recorder &total izer

RecorderRecorderRecorderRecorderRecorder &

total izerRecorder &

total izer

to air preheater,windbox, furnace draft, inlet & outlet to economizer, gas inletand outlet to air preheater, overfire or primary air pressure,and ID fan discharge.Multi-point electronic type to track air and gas temperaturesthrough the unit.May be used for combustion controls instead of steam flow-airflow.Usually in condensate system, boiler feed system and processreturns.

5-2

TM 5-311-6

List of Typical Instruments and Devices to be Provided for Boiler Turbine Mechanical Panel. (Continued)Table 5-1.

Measurement Primary Elementor Device Fluid Location


Level FeedwaterCondensateCoal

Boiler drumDeaerator, Condenser HotwellBunker

RecorderRecorderIndicator or

pilot lights

Cells as required (4)Conductivity Condensate Recorder

Manual- - -automaticstations

Combustion control system,condensate and feedwatercontrol systems, steamattemperator, and as re-quired

Each station

M o t o r c o n t r o l - -switches

Starters for draft fans,BF pumps, condensate pumps,vacuum pumps, fuel pumps,lube oil pumps, turninggear, turbine governor andlike items

Each switch

Ammeters - - Major motors (high volt-age) : draft fans, BF pumps

Indicator

Alarms - - Points as selected forsafe operation

Annunciatorsection forboiler turbinepanel

Boiler burner system Insert on boiler-turbine panel

Burner - -Management

Indicating - As required to start upand monitor boiler andturbine.

Each light

Notes: See first

Courtesy of Pope,

page of Table.

5-3

TM 5-811-6

Table 5-2. List of Typical Instruments and Devices to be Provided for Common Services Mechanical Panel

Primary ElementFluid Location


Measurementor Device

Main steam header(l)

Extraction steam header(l)Supply to plantsupplyBurner pump dischargeDischarge headerService waterClosed cooling waterFire systemInstrument airService airAtmosphere

RecorderIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorBarometer

Pressure SteamSteamFuel gasFuel oilFuel oilCirc. waterWaterWaterWaterAirAirAir

.

Extraction steam header(l)supplyAs required

Temperature SteamFuel OilVarious

ViscosityFlow

Fuel oilSteamSteam

Pump and heater sets

Extraction to processRecorderRecorder &

total izerRecorder &

total izerFuel gas Supply to plant

Fuel oilCondensate

Tank(s)Tank(s)

IndicatorIndicator

Level

Manual-automaticstations

Pressure reducing station,misc. air operated devices

Each station--

CW pumps, cooling tower Each switchMotorcontrolswitches

- -fans, air compressors,condensate transfer pumps,service water pumps, fueltransfer pumps, and likei t ems

:(2)

For header systems onlyMulti-point electronic type

5-4

Table 6-2,

TM 5-811-6

List of Typical Instruments and Devices to be provided for Common Services Mechanical Panel. (Continued)


Ammeter - Major (high voltage)motors; CW pumps, coolingtower fans

Alarms - - Points as selectedfor safe operation

Indicating - -.

‘

As required to start-upand monitor principalcommon systems


nomic or engineering accountability purposes, re-corders will be provided.

d. Ventilation. All panels which house heat pro-ducing instruments will be ventilated or air condi-tioned to prevent overheating of the instruments.For panel~in the central control room, this will be.accomplished by having a filtered air intake and me-chanical exhaust arrangement to circulate cool airfrom the air conditioned control room through eachenclosed panel wherever practicable. Local panels,as a rule, have only gages and other devices whichemit little heat and do not require special ventila-tion.

e. Illumination. In a central control room, thebest illumination is a “light ceiling” with diffusertype suspended panels to give a shadowless, evenlevel of lighting throughout the control room. Levelsof illumination at bench tops of 75-foot candles,plus or minus 10-foot candles, will be provided.However, caution must be used when designinglighting for control rooms utilizing electronic digitalcontrols with cathode ray tube (CRT) display as ex-cessive illumination tends to wash out displays. Inareas with electronic digital controls with CRT dis-plays, the level of general illumination will be main-tained at 15- to 25-foot candles. Local panel illumi-nation will be accomplished by means of a canopybuilt into the top of the panel. Local switch controlwill be provided at each canopy light.

5-3. Automatic control systemsa. Types. Control systems and instruments may

be pneumatic, ac or dc electronic, electronic digital,combination pneumatic and electronic, or hydraulic.


Indicator

Annunciatorsection forcommon panel

Each light

Mechanical-hydraulic and electro-hydraulic systemswill be utilized in connection with turbine generatorspeed governing control systems. Pneumatic con-trols will be used for power plant units of 30 MW orless. Applications include: combustion control,feedwater regulation, desuperheating and pressurereducing station control, heater drain control, andboiler feed recirculation control. Pneumatic systemsare economical, reliable, and provide smooth, modu-lating type of operation. For plants where the ar-rangement is dispersed and precision is required,electronic controls and instruments will be providedin lieu of the pneumatic type because of the slug-gishness of pneumatic response where long dis-tances are involved. Electronic digital controls haverecently become economically competitive withanalog pneumatic and electronic controls and offerthe advantage of’ ‘soft-wired” control logic and pro-grammable versatility. With electronic controls it isrequired to use pneumatically operated valves withtransducers to convert the electronic signals topneumatic at the pneumatic valve operator.

b. Combustion controls. Combustion controls forsteam generators will be based on the conventionalindirect method of maintaining steam pressure.Systems will be of the fully metering type, designedto hold steam pressure within plus or minus 1 per-cent of the controller setting with load changes of 5percent per minute; under the same rate of loadchange, excess air will be maintained at plus orminus 2 percent of the control setting. (Note: Withstoker fired boilers having limited heat inputs fromsuspension heat release, the tolerances on steampressure will be greater than 1 percent.)

5-5

TM 5-811-6

Table 5-3. List of Typical Instruments and Devices to be Provided for Electrical (Generator and Switchgear) Panel

Measurement Instrument oror Device Device on Panel

For Each Generator

Generator gross outputPower FactorGenerator ac currentGenerator ac voltsGenerator dc currentGenerator dc voltsGenerator ac current(for individual phases)Generator ac volts(for individual phases)GeneratorsynchronizingGeneratorsynchronizing

Oil circuit breakert r ipGenerator fieldbreakerVoltage regulator

Voltage regulator

Voltage regulator

Voltage regulator

Unit governor

Unit tripUnit resetUnit speedUnit temperatures

Generator alarmsMiscellaneous

Supervisory

WattmeterP.F. MeterAC ammeterAC voltmeterDC ammeterDC voltmeterAC ammetercontrol switchAC voltmetercontrol switchSynchronizingcontrol switchSeparate panelsection

OCB controlswitchField breakercontrol switchVoltage reg.

Notes

- -- -- -- -

For phase measurement selection- -

For phase measurement selection- -

Incl . synch. lamps and metersfor incoming and runningindicationIf step-up transformationincluded

- -

transfer voltmeterManual voltageregulator - -Auto. voltagereg. adjuster - -Voltage reg.transfer switch - -Governor controlswitch, raise-lower - -Trip pushbutton - -Reset pushbutton - -Speed indicator - -Electronic For turbine and generatorrecorder temperaturesAnnunciator With test and reset pushbuttonsIndicating For switches and as requiredlightsRecorders Vibration, eccentric i ty

5-6

Table 5-3.

TM 5-811-6

List of Typical Instruments and Devices to be Provided for Electrical (Generator and Switchgear) Panel. (Continued)

Measurement Instrument oror Device Device on Panel

For Switchgear

2.4 or 4.16 kV unitswitchgear2.4 or 4.16 kVcommon switchgear2.4 or 4.16 kVfeeders

480 V unit switchgear

480 V commonswitchgear480 V feeders

Swithgear ac current

Switchgear ac volts

Switchgear alarms

Miscellaneous

Intraplantcommunication

Breaker controlswitchBreaker controlswitchBreaker controlswitches

Breaker controlswitchBreaker controlswitchBreaker controlswitchesAC ammeters

AC voltmeters

Annunciator

Notes: (1) If a highbe required.

IndicatinglightsTelephone handset

Notes

If higher plant auxiliaryvoltage requiredIf required

For plant auxiliariesand/or for outside distri-bution circuits as re-quired.

For plant auxiliaries asrequiredOne for each switchgearwith switchOne for each switchgearwith switchWith test and reset push-buttonsFor switches and as re-quired

voltage switchyard is required a separate panel may

(2) For relays see Chapter 4, Section V; generator and auxiliarypower relays may be mounted on the back of the generatorwalk-in benchboard or on a separate panel.


5-7

TM 5-811-6

Table 5-4. List of Typical Instruments and Devices to be Provided for Diesel Mechanical Panel


Pressure Fuel gasFuel oilLube oilLube oilComb. airComb. airCooling waterStarting air

Temperature Exhaust

Cooling waterCooling water

Level Jacket waterLube OilFuelFuel

Motor -controlswitches(or pushbuttons)

Alarms - -

Supply to engineSupply to engineSupply to enginesupply to turbochargerTurbocharger dischargeFilter downstreamPump dischargeAir receiver

Each cylinder andcombined exhaustSupply to engineReturn from engine

Surge tankSump tankBulk storage tankDay Tank

Jacket water pumps,radiator (or coolingtower) fans, fuel oilpumps, centrifuges,and like auxiliaries

Low lube oil pressure,low jacket water pressure,high lube oil temperature,high jacket watertemperature, high and lowday tank levels

Notes: (1) With selector switch.

Courtesy of Pope, Evans and Robbins

5-8

(Non-Copyrighted)


IndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicator

Indicator(l)

IndicatorIndicator

IndicatorIndicatorIndicatorIndicator

Each switch

Annunciator

TM 5-811-6

.

c. Feedwater regulation. A three element feed-water regulator system will be provided for steampower plant service. Such a system balances feed-water input to steam output subject to correctionfor drum level deviations caused by operating pres-sure variations (drum swell).

d. Attemperator control system. Each powerplant steam generator will have superheat (attem-perator) controls to maintain superheat within thelimits required for protection of the turbine metalparts against thermal stress and for preventingexcessive reduction in part load turbine efficiency.Injection of desuperheating water (which must behigh purity water, such as condensate) will be donebetween stages of the boiler superheater to reducechances of water carryover to the turbine. An at-temperator system having a controller with a fastresponse, derivative feature will be provided. Thistype of controller anticipates the magnitude of sys-tem deviations from the control set point in accord-ance with the rate of change of superheat temperat-ure. Automatic positive shutoff valve(s) will be pro-vided in the desuperheating water supply line up-stream of the desuperheater control valve to preventdribbling of water to the desuperheater when thecontrols are not calling for spray water.

e. Closed heater drain controls. Although it isthermodynamically preferable to pump the drainsfrom each feedwater heater forward into the conden-sate or feedwater stream exiting from the heater,the expense and general unreliability of the lowNPSH pumps required for this type of drain servicewill normally preclude such a design. Accordingly,the drains from each heater will normally be cas-caded to the next lower pressure heater through alevel control valve. The valve will be located asclosely as possible to the lower pressure heater dueto the flashing which occurs because of the pressurereduction at the outlet of the level control valve.Each heater will be provided with two level controlvalves. The secondary valve only functions onstartup, on malfunction of the normal valve, orsometimes during light loads when pressure differ-ential between heaters being cascaded becomes verysmall. The secondary valve frequently dischargesdirectly to the condenser. Such a complexity of con-trols for heater drains is necessary to assist in pre-venting problems and turbine damage caused byturbine water induction. Water induction occurswhen feedwater header tubes or level control valvesfail, causing water to backup into the turbinethrough the extraction steam piping. Refer toChapter 3, Section VII.

f. Boiler feed recirculation controls. An automaticrecirculation system will be installed for each pumpto bypass a minimum amount of feedwater back to

the deaerator at low loads for protection againstboiler feed pump overheating. A flow signal fromthe suction of each pump will be used to sense thepreset minimum safe pump flow. This low flow sig-nal will open an automatic recirculation valve lo-cated in the piping run from the pump discharge tothe deaerator. This recirculation line poses mini-mum flow through a breakdown orifice for pressurereduction to the deaerator. The breakdown orificewill be located as closely as possible to the deaeratorbecause flashing occurs downstream. When pumpsuction flow increases to a preselected amount in ex-cess of pump minimum flow, the recirculation valvecloses. The operator will be able to open the recir-culation valve manually with a selector switch onthe control panel. Designs will be such as to pre-clude accidental closing of the valve manually. Suchan operator error could cause flow to drop below thesafe level quickly, destroying high pressure pumps.

g. Other control systems. Desuperheating, pres-sure reducing, fuel oil heating, and other miscellane-ous power plant control systems will be provided asappropriate. Direct acting valves will not be used.Control valves will be equipped with a matchingvalve operator for positive opening and closing ac-tion. Deaerator and hotwell level control systemsare described in Chapter 3, Section VII.

5-4. Monitoring instrumentsa. Types.

(1) Control system components will includesensing devices for primary fluids plus transmitters,transducers, relays, controllers, manual-automaticstations, and various special devices. Table 5-5 listssensing elements for controls and instruments. In-struments generally fall into two classifications—di-rect reading and remote reading.

(2) Direct reading instruments (e.g., thermome-ters, pressure gages, and manometers) will bemounted on local panels, or directly on the processpiping or equipment if at an accessible location.Locally mounted thermometers will be of the con-ventional mercury type or of the more easily read(but less accurate) dial type. Type selected will de-pend on accuracy required. Pressure gages for steamor water service will be of the Bourdon tube type.

(3) Remote reading instruments (recorders, in-tegrators, indicators and electrical meters) will bemounted on panels in the central control room.These instruments will have pneumatic or electronictransmission circuits. Sometimes the same trans-mitters utilized for control system service can beutilized for the pertinent remote reading instru-ment, although for vital services, such as drumlevel, an independent level transmitter will be usedfor the remote level indicator.

5-9

Table 5-5. Sensing Elements for Controls and Instruments. (Continued)

Common ApplicationsControl InstrumentElement Type

Motion

Chemical

CentrifugalVibrating reedRelative motionPhoto-electric cell

Flue gas analysis

Water analysis

Speed governs TachometerSpeed governs Tachometer

- - StroboscopeLimit control Counter

- .- -- -- -

- -

- -

Combustion OrsatcontrolWater - -treatment

Fuel analysis - - - -

- - Hydrometer for liquids- - Scales for solids- - Hygrometer- - Ringelman chart

Combustion C02 meterCombustion Btu meter

Physical Specific gravityWeightHumiditySmoke densityGas densityHeat

- -- -

- -

Combination ofwater flow andtemperaturedif ferential

Electricandelectronic

Photo-conductivity Flame safe-guard

Photo-electric cellSmoke density

Electricconductivity

Probes Alarm pH of waterOil in condensate

Source: NAVFAC DM3


Common ApplicationsElement Type Control Instrument

Pressure Mechanical

Variable electricresistance due tostrain

Variable electricresistance due tovacuum

Variableelectronicresistance due tovacuum

Level Visual

Float

Dif ferentialpressureHydrostatic

Bourdon tubeBellows ordiaphragmManometers

Pressure transducer

Thermocouple

Vacuum tube

- -

Buoyant float

Displacement

Manometer

Diaphragm in tankbottom

Pressure, draftand vacuumregulators

Process pressureregulator

Vacuumregulator

Vacuumregulator

- -

Mechanicallevel regulatorPneumatic floatregulator

Level regulator

Level regulator

Pressure gageLow pressure,vacuum gagesBarometer

Po tent i om.

draft and

100 to 50,000 psi

High vacuum 1-7000microns Hg

High-vacuum down to0.1 micron Hg

Gage stickTransparent tube

Tape connected to float

Torque

Remote level gage

Tank levels withviscous fluids


Element Type

Temperature Solid expansion

Fluid expansion

Thermocouple

Elec. resistanceof metals

OpticalPyrometer

Radiationpyrometer

Fusion

Bimetal

Mercury or alcohol

Mercury in coilOrganic liquid

Organic vaporliquidGas

Copper-constantanIron-constantanChromel-alumelPlat.-plat. rhodium

CopperNickelPlatinum

Comparative radiantenergy

Radiant energy onthermocouples

- -

Common ApplicationsControl Instrument

On-offthermostats

- -

Temperatureregulators



- -

Dial therm. - 100 to 1000 F

Glass therm.- 38 to 750 F

Dial therm. - 38 to 1000 F125 to 500 F

- 40 to 600 F

- 400 to 1000 F

Low voltage - 300 to 600 FO to 1400 F

600 to 2100 F1300 to 3000 F

Potentiom. - 40 to 250 F- 300 to 600 F- 300 to 1800 F

Potentiom. - 800 to 5200 F

Flame safeguard Potentiom. - 200 to 7000 FSurfacetemperatureregulation

- - Pyrom.cones -1600 to 3600 F

Crayons - 100 to 800 F

TM 5-811-6

(4) Panel mounted receiver gages for pressure,temperature, level and draft will be of the miniature,vertical indicating type which can be arranged inconvenient lineups lineups on the panel and are easyto read.

(5) Recorders will be of the miniature type, ex-cept for multi-point electronic dot printing recorderswhich will be full size.

b. Selection. The monitoring instruments for anycontrol system will be selected to provide the neces-sary information required for the control roomoperator to be informed at all times on how the con-trolled system is functioning, on vital processtrends, and on other essential information so thatcorrective action can be taken as required.

5-5. Alarm and annunciator systemsa. Purpose. The annunciator system supplements

the operator’s physical senses and notifies him both

audibly and visually when trouble occurs so thatproper steps can be taken to correct the problem.

b. General. The alarm system will be both audible and visual. The sounding of the alarm will alert theoperators that a problem exists and the visual lightin the pertinent annunciator window will identifythe problem. Annunciator systems shall provide forthe visual display to be distinguishable betweennew alarms and previous alarms already acknowl-edged by the operator pushing a button provided forthis purpose. New alarms will be signified by a flash-ing light, whereas acknowledged alarms will be signified by a steady light. Alarm windows will be ar-ranged and grouped on vertical, upper panel sec-tions with corresponding control stations andoperating switches within easy reach of the operatorat all times. Critical or potentially dangerous alarmswill be a different color from standard alarms forrapid operator identification and response.

Section Il. HEATlNG; VENTILATING AND AlR CONDITIONING SYSTEMS

5-6. introductionThis section sets forth general criteria for design ofspace conditioning systems for a power plant.

5-7. Operations areasa. Enclosed general operating areas.

(1) Ventilation supply. Provide mechanical ven-tilation for fresh air supply to, as well as exhaustfrom, the main operating areas, A filtered outsideair supply, with heating coils and recirculation op-tion for winter use, will be provided. Supply fanswill be selected so that indoor temperature does notrise more than 15oF. above the ambient outdoor airdesign temperature, and to maintain a slight posi-tive inside pressure with all exhaust fans operatingat maximum speed. Ventilation system design willtake into account any indoor air intakes for boilerforced draft fans, which can be designed to drawwarm air from near the roof of the plant. Supply airwill be directed through a duct system to the lowestlevels of the plant with particular emphasis on fur-nishing large air quantities to “hot spots. ” Theturbine room will receive a substantial quantity offresh air, supplemented by air from lower levels ris-ing through operating floor gratings. For hot, dryclimates, evaporative cooling of ventilation air sup-ply will be provided.

(2) Ventilation exhaust. Exhaust fans with atleast two speeds are switched so that individual fanand fan speed can be selected according to air quan-tity desired will be provided. Battery rooms willhave separate exhaust systems designed in accord-ance with TM 5-811-21AFM 88-9/2. It may beeconomical to remove heat from hot spots with local

5-14

ducted exhaust systems to prevent heat from beingcarried into other areas. All exhaust and supplyopenings will be provided with power operateddampers, bird screens, and means for preventing en-trance of rain, sleet and snow.

(3) Heating. As much heating as practicablewill be supplied via the central ventilation supply system, which will be designed so that maximum de-sign air flow can be reduced to a minimum requiredfor winter operation. Heat supplied by the ventila-tion system will be supplemented as required byunit heaters and radiation. Heating system designfor ventilation and other space heating equipmentwill be selected to maintain a minimum plant indoortemperature of 55OF. and an office, control roomand laboratory area temperature of 68OF.

b. Control room.(1) The central control room is the operating

center of a power plant and will be air conditioned(i.e., temperature control, humidity control and airfiltration) for the purpose of human comfort and toprotect equipment such as relays, meters and com-puters. Unattended control rooms may not requirecomfort conditions but have temperature limits asrequired by the equipment housed in the room. Con-trol system component manufacturers will be con-sulted to determine the operating environment re-quired for equipment reliability.

(2) Intermediate season cooling using 100 per-cent outside air for an economizer cycle or enthalpycontrol will be life cycle cost analyzed.

5-8. Service areasa. Toilets, locker rooms and lunch rooms.

TM 5-811-6

(1) Toilets will be exhausted to maintain a nega-tive pressure relative to adjacent areas. All exhaustoutlets from a toilet will be a minimum of 15 feetfrom any supply inlet to prevent short circuiting ofair. Toilet exhaust will be combined with a lockerroom exhaust but not with any other exhaust.

(2) Locker rooms will be exhausted according tothe applicable codes and supplied by a heated airsupply.

(3) Lunch rooms will be furnished with recircu-lation heating systems to meet applicable codes; ex-haust will be installed. System will be independent

of other systems to prevent recirculation of foododors to other spaces.

b. Shops and maintenance rooms. All shops andmaintenance rooms will be ventilated according toapplicable codes. Welding and painting areas will beexhausted. Heating will be provided by means ofunit heaters sized to maintain a maximum of 68 “F.on the coldest winter design day.

c. Offices and laboratories. All offices and labora-tories will be air conditioned for human comfort inaccordance with TM 5-810-l/AFM 88-8/1. Ex-haust will be provided where required for laboratoryhoods or other special purposes.

Section lll. POWER AND SERViCE PlPlNG SYSTEMS

5-9. introductiona. General. Power plant piping systems, designed

to transfer a variety of fluids (steam, water, com-pressed air, fuel oil, lube oil, natural gas) at pres-sures ranging from full vacuum to thousands of psi,will be engineered for structural integrity and econo-my of fluid system construction and operation.

b. Design considerations. Piping systems will bedesigned to conform to the standards listed in Table5-6. ASME Boiler Pressure Vessel Code Section Igoverns the design of boiler piping, usually up to thesecond isolation valve. ANSI B31.1, Code for Pres-sure Power Piping governs the pressure boundaryrequirements of most other plant piping (excludingplumbing and drainage piping). Each of these codesprovides a detailed description of its scope and lim-itations.

5-10. Piping design fundamentalsDesign of piping system will conform to the follow-ing procedure:1

I a. Select pipe sizes, materials and wall thickness(pipe schedule). Design for the maximum pressureand temperature the piping will experience duringeither operation or upset conditions. Follow appro-priate sections of ASME Section I and ANSI B31.1.Other requirements for welding qualification andpressure vessel design are set forth in ASME Sec-tions VIII and IX. Specify hydrostatic pressuretesting requirements in accordance with the codes.Select flow velocities for overall economy.

b. Select piping components and end connectionsfor equipment.

c. Route piping. Make runs as simple and directas possible. Allow for maintenance space and accessto equipment. Do not allow piping to encroach onaisles and walkways. Inspect for interferences with

structures, ductwork, equipment and electric serv-ices.

d. Include provisions for drainage and venting ofall pipe lines.

e. Design pipe supports, restraints and anchors,using accepted procedures for thermal expansionstress analysis. The stress analysis will consider si-multaneous application of seismic loads, where ap-plicable. Computer analysis will be used for majorthree plane piping systems with multiple anchors.

5-11. Specific system design considera-tions

a. Steam piping. In all steam systems, provisionswill be made for draining of condensate before start-up, during operation and after shutdown. Steamtraps will be connected to low points of the pipe-lines. Small bore bypass piping will be providedaround block valves on large, high pressure lines topermit warming before startup.

b. Circulating water piping. Reinforced plasticpiping will be used for salt or brackish water servicewhenever practicable.

c. Fuel oil piping. Fuel oil piping will be designedwith relief valves between all block valves to protectagainst pipe rupture due to thermal expansion of theoil. Fuel oil piping will be designed in accordancewith National Fire Protection Association (NFPA)standards and ANSI B31. Piping subject to vibra-tion (such as engine service) will be socket or buttwelded, although flared tubing may be used forsmall lines under 1/2 inch.

d. Insulation. Insulate all lines containing fluidsabove 120oF. so that insulation surface tempera-tures remain below 1200F. at 80oF. still air ambient.Provide anti-sweat insulation for all lines which op-erate below ambient temperatures. Protect all insu-lation against weather (or wash down water if in-doors) and mechanical abuse.

I5-15

TM 5-811-6

Table 5-6. Piping Codes and Standards for Power Plants. (Continued)

Sponsor Identi f icat ion Tit le

ANSI B36 series Iron and steelpipe

B16 series Pipe, flangesand G37.1 and fittings

ASTM

B18 series Bolts and nuts

- - Testing materials

Major - -equipmentmanufacturers(turbines, pumps,heat exhangers, etc.)

- -

Coverage

Materials and dimensions.

Materials, dimensions,stresses and temperature-pressure ratings.

Bolted connections.

Physical properties ofmaterials specified inabove ASME and ANSIstandards.

Allowable reactions andmovements on nozzles frompiping.


Section IV. THERMAL INSULATION AND FREEZE PROTECTION

5-12. IntroductionApplications. Thermal insulations are used for thefollowing purposes:

a. Limit useful heat losses.b. Personnel burn protection.c. Limit heat gains where cold is desired.d. Prevent icing and condensation.e. Freeze protection.

5-13. Insulation designThe principal elements of insulation system designand specification areas follows:

a. Selection of surfaces. Define and list the vari-ous surfaces, piping, vessels, ductwork, and machin-ery for which insulation is needed including lengths,areas and temperatures.

b. Insulation systems. For each class or type ofsurface select an appropriate insulation system:bulk insulation material and miscellaneous materi-als,coverings, and like items.

c. Economical thickness. Based on the abovedata, select the economical or necessary thickness ofinsulation for each class or type of surface.

5-14. lnsulation materialsa. Bulk material. Refer to Table 5-7 for nomencla-

ture and characteristics of conventional thermal in-sulations.

b. Restrictions on asbestos. Asbestos insulation,or insulations containing loose, fibrous, or free as-bestos are not to be used.

c. Maximum temperatures. Each type of insula-tion is suitable for use at a specified maximum tem-perature. Design will be such that those maximumswill not be approached closely in ordinary applica-tions. All high temperature insulations are more ex-pensive and more fragile than lower temperatureproducts and, in general, the least expensive materi-al which is suitable for the temperature exposurewill be selected. Where substantial total insulationthicknesses of 6 inches or more are required, eco-nomics may be realized by using two layers of differ-ent materials using high temperature material closeto the hot surface with cheaper low temperature ma-terial on the cold side.

d. Prefabricated insulation. A major part of totalinsulation cost is field labor for cutting, fitting and

5-17

0.64 0.68-- ---- --

200 6-18 0.28 0.29 0.30 -- -- -- -- --

600 6-10 -- -- 0.28 0.35 0.43 -- -- --

1600 16-24 -- -- 0.34 0.39 0.44 0.54 0.64 --175 1.6 0.26 0.28 0.30 -- -- -- -- --150 5 0.23 0.24 0.25 -- -- -- -- --

Corrugated and laminatedasbes tos paper :

4 p ly pe r in .6 p ly pe r in .8 p ly pe r in .

300300300

1200

800200

15001900

600

11-1315-1718-20

-- 0.54 0 .57— 0.49 0 .51- - 0 .47 0 .49

0.620.590.57

------

-- --- ---- --

C a l c i u m s i l i c a t e 11 -- -- 0.36 0.40 0.55 -- --

C e l l u l a r g l a s sCork (without addedb i n d e r )Dia tomaceous s i l i ca

97-10

0 .37 0 .39 0 .410 .27 0 .28 0 .29

0.480.30

----

-- ---- --

2225

0.640.70

0.66 0 .710 .75 0 .80

. - -- —-- -- --

----

- .--

85% magnesia 11-14 -- -- 0.39 0.42 0.51 -- --

Mineral wool (rock,slag or glass):

Low temp. (asphaltor resin bonded)Low temp. (finef ibe r r e s in bonded)High temp. blanket-type (metal reinforced)

200

450

1200

15 0 .28 0 .30 0 .33 0.39 -- -- -- --.

3 0 .22 0 .23 0 .24 0.27 0.31 — -- --

TM 5-811-6

. .

,

installation. For large areas or long piping runs, sub-stantial savings may be realized by factory forming,cutting or covering. Valves and pipe fittings, espe-cially large ones, may be economically insulatedwith factory made prefabricated shapes. Equipmentrequiring periodic servicing will be equipped with re-movable, reusable insulation.

e. Miscellaneous materials. Complete insulationsystems include accessory materials such as fasten-ers, adhesives, reinforcing wire meshes and screens,bandings and binder wires, coverings or laggings,and finishes. All insulations will be sealed or closedat joints and should be arranged to accommodatedifferential expansions between piping or metalstructures and insulations.

f. Cold surface materials. Cold surface insulationmaterials will be selected primarily for high resis-tance to moisture penetration and damage, and foravoidance of corrosion where wet insulation materi-als may contact metal surfaces. Foamed plastics orrubber and cellular (or foamed) glass materials willbe used wherever practicable.

5-15. Control of useful heat lossesa. General. Control of losses of useful heat is the

most important function of insulations. Substantialinvestments for thermal insulation warrants carefulselection and design.

b. Durability and deterioration. Most convention-al insulating materials are relatively soft and fragileand are subject to progressive deterioration and lossof effectiveness with the passage of time. Insulationassemblies which must be removed for maintenanceor which are subject to frequent contact with tools,operating equipment and personnel, or are subjectto shock or vibration, will be designed for maximumresistance to these forces.

5-16. Safety insulationa. General Insulation for personnel protection or

safety purposes will be used to cover dangerouslyhot surfaces to avoid accidental contact, where heatloss is not itself an important criteria.

b. General safety criteria. Safety or burn protec-tion insulations will be selected to insure that out-side insulation surfaces do not exceed a reasonablysafe maximum, such as 140 “F.

c. Other criteria Close fitting or sealing of safetyinsulation is not required. Metal jacketing will beavoided due to its high conductivity in contact withthe human body.

5-17. Cold surface insulationa. Applications. Insulations for cold surfaces will

be applied to refrigeration equipment, piping andductwork, cold water piping, and to air ducts bring-

ing outside air into power plants and HVAC sys-tems.

b. Criteria. In most cases, cold surface insulationswill be selected to prevent icing or condensation. Ex-tra insulation thickness is not normally economicalfor heat absorption control.

5-18. Economic thicknessa. General. Economic thickness of an insulation

material (ETI) is a calculated parameter in whichthe owning costs of greater or lesser thicknesses arecompared with the relative values of heat energywhich might be saved by such various thicknesses.The method is applicable only to systems which areinstalled to save useful heat (or refrigeration) anddoes not apply to safety insulation or anti-sweat(condensation) materials.

b. Economic criteria. The general principle of ETIcalculations is that the most economical thicknessof a group or set of thicknesses is that one for whichthe annual sum of owning costs and heat loss costsis a minimum. Generally, thicker insulations willrepresent higher owning costs and lower heat losscosts. The range of thicknesses selected for calcula-tion will indicate at least one uneconomical thick-ness on each side of the indicated ETI. Refer to Figure 5-1 for a generalized plot of an ETI solution.

c. Required data. The calculations of ETI for aparticular insulation application involves routinecalculations of costs for a group of different thick-nesses. While calculations are readily performed bycomputers, the required input data are relativelycomplex and will include energy or fuel prices withallowance for future changes, relative values of par-ticular heat sources or losses, depreciation andmoney cost rates, costs of complete installed insula-tion systems, conductivities, temperatures, airvelocities and operating hours. Standard programsare available for routine calculations but must beused with care. The most uncertain data will be theinstalled costs of alternative insulation systems andthicknesses. Assumptions and estimates of suchcosts will be as accurate as possible. Refer to thepublications and program systems of the ThermalInsulation Manufacturers Association (TIMA) andof leading insulation manufacturers.

5-19. Freeze protectiona. Application. Freeze protection systems are

combinations of insulation and heat source materi-als arranged to supply heat to exposed piping orequipment to prevent freezing in cold weather.

b. Insulaztion materials. Conventional insulationmaterials will be used and selected for general heatloss control purposes in addition to freeze protec-tion. Insulation will be such as not to be damaged by

5-21

TM 5-811-6


Figure 5-1. Economical thickness for heat insulation (typical curves).

the heat source or by extended exposure to weather erally be used to supply the correct heat flow to theand moisture. protected surface. Steam and ho water tracing may

c. Design criteria. In general, the insulation for a also be used with provisions to avoid loss of steamfreeze protection system will be selected for maxi- or water. In either case, the required heat supplymum overall coldest ambient temperatures. Allow- will be sufficient to meet the heat loss of the insula-ance for wind conditions will be made. tion under the combination of design ambient and

d. Heat sources. Electrical heating tape will gen- pipe line surface temperature.

Section V. CORROSION PROTECTION

5-20. General remarks cycle is generally accomplished by more convention-The need for corrosion protection will be investigat- al methods such as:ed. Cycle fluids will be analyzed to determine treat- U. Selection of corrosion resistant materials.ment or if addition of corrosion inhibitors is re- b. Protective coatings.quired. Corrosion protection of items external to the c. Cathodic protection.

Section Vl. FIRE PROTECTION

5-21. Introduction lar type of fire which can occur in the station. ThisFire protection will be provided in order to safe- manual discusses various fire protection systems guard the equipment and personnel. Various sys- and their general application in power plants. Refer-tems will be installed as required to suit the particu- ence will be made to TM 5-812-1 for specific re-

5-22

TM 5-811-6

quirements for military installations. Further de-tails may be found in the National Fire Protection

Association (NFPA) Codes and Standards.

5-22. Design considerationsa. Areas and equipment to be protected. The fol-

lowing are some of the major areas which will be in-vestigated to determine the need for installing fireprotection facilities.

(1) Main and auxiliary transformers.(2) Turbine lubricating oil system including the

oil reservoir, oil, cooler, storage tanks, pumps andthe turbine and generator bearings.

(3) Generator hydrogen cooling system includ-ing control panels, seal oil unit, hydrogen bottlesand the purification unit.

(4) Coal storage bunkers, fuel oil storage tanksand the burner front of the steam generator.

(5) Emergency diesel generator and its oil stor-age tank.

(6) Office and records rooms.(7) Control room.(8) Relay, computer, switchgear and battery

rooms.(9) Shops, warehouses, garages and laborato-

ries.(10) Personnel locker rooms, lunch rooms and

toilets.b. Types of systems. The following is a brief de-

scription of the various types of systems and theirgeneral application.

(1) Water spray and deluge system. This type ofsystem consists of open type sprinkler heads at-tached to a network of dry (not water filled) pipingwhich is automatically controlled by a fully super-vised fire detection system which also serves as afire alarm system. When a fire is detected, an auto-matic deluge valve is tripped open, admitting waterto the system to discharge through all of the sprink-ler heads. The system may be subdivided into sepa-rately controlled headers, depending on the area tobe covered and the number of sprinkler heads re-quired. The usual pressure required at the sprinklerheads is about 175 psi and the piping should beproperly sized accordingly. A water spray delugesprinkler system will be provided where required inopen areas and areas requiring the protection of thepiping from freezing, such as the steam generatorburner fronts; the generator hydrogen system; themain and auxiliary transformers; and unheatedshops, garages, warehouses and laboratories.

(2) Water spray pre-action and deluge system.This type of system is similar to the above water

spray deluge system, except that it contains closedtype sprinkler heads which only discharges waterthrough those sprinklers whose fixed temperature

elements have been opened by the heat from a fire.This system will be utilized for the turbine and gen-erator bearings and for the above water spray de-luge sprinkler system areas where more localizedcontrol is desired.

(3) Wet pipe sprinkler systems. This wet pipesystem utilizes a water filled piping system connect-ed to a water supply and is equipped with sprinklershaving fixed temperature elements which each openindividually when exposed to a high temperaturedue to a fire. The areas where wet pipe sprinkler sys-tems will be used are heated shops, garages, ware-houses, laboratories, offices, record rooms, lockerrooms, lunch rooms and toilets.

(4) Foam extinguishing systems. Foam fire ex-tinguishing systems utilize a foam producing solu-tion which is distributed by pipes equipped withspray nozzles or a fuel tank foam entry chamber fordischarging the foam and spreading it over the areato be protected. It is principally used to form a co-herent floating blanket over flammable and com-bustible liquids which extinguish (or prevent) a fire by excluding air and cooling the fuel. The foam isusually generated by mixing proportionate amountsof 3% double strength, low expansion standardfoam concentrate using either a suitably arrangedinduction device with (or without) a foam storage-proportioning tank to mix the foam concentratewith a water stream from a fire water header. A spe-cially designed hand play pipe, tank foam chamberor open sprinklers aspirate the air to form the foamto blanket the area to be protected. The deluge wa-ter entry valve to the system may be manually orautomatically opened. Foam systems will be in-stalled in power plants to protect fuel oil areas,lubricating oil systems, and hydrogen seal oil sys-tems.

(5) Carbon dioxide extinguishing systems. Thistype of system usually consists of a truck filled lowpressure refrigerated liquid carbon dioxide storagetank with temperature sensing controls to permitthe automatic injection of permanently pipe carbondioxide into areas to be protected. The systemusually includes warning alarms to alert personnelwhenever carbon dioxide is being injected into an ac-tuated area. Carbon dioxide extinguishing systemsof this total flooding type will be utilized to extin-guish coal bunker fires and for electrical hazardareas such as in battery rooms, electrical relayrooms, switchgear rooms, computer rooms and with-in electrical cabinets.

(6) Halogenated fire extinguishing systems.This type of system utilizes specially designed re-movable and rechargeable storage containers con-taining liquid HaIon at ambient temperature whichis superpressurized with dry nitrogen up to 600 psig

5-23

TM 5-811-6

pressure. These manifolded containers are locatedas closely as possible to the hazards they protectand include connecting piping and discharge noz-zles. There are two types of systems. The total flood-ing system is arranged to discharge into, and fill tothe proper concentration, an enclosed space or an en-closure about the hazard. The local application sys-tem is arranged to discharge directly onto the burn-ing material. Either system may be arranged to pro-tect one or more hazards or groups of hazards by soarranging the piping and valves and may be manual-ly or automatically actuated. Halon is a colorlessand odorless gas with a density of approximatelyfive times that of air, and these systems must in-clude warning alarms to alert personnel wheneverthe gas is being ejected. However, personnel maybeexposed to Halon vapors in low concentrations forbrief periods without serious risk. The principal ap-plication of Halon extinguishing systems is wherean electrically nonconductive medium is essential ordesired or where the cleanup of other media presentsa problem, such as in control rooms, computerrooms, chemical laboratories and within electricalpanels.

c. Automatic fire detectors. All fire protectionsystems will normally be automatically alarmed and

actuated; however, some special conditions may re-quire manual actuation on an alarm indication. Amanual actuation will be included to provide foremergencies arising from the malfunction of an au-tomatic system. The primary element of any fireprotection system is the fire detection sensing de-vice which is actuated by heat detectors which de-tect abnormally high temperature or rate-of-tem-perature rise, or smoke detectors which are sensitiveto the visible or invisible particles of combustion.The ionization type of smoke detector belongs inthis category.

5-23. Support facilitiesTo support the fire protection water systems, an as-sured supply of water at an appropriate pressure isnecessary. This water supply will be provided froman underground fire water hydrant system main ifone is available in the area and/or by means of an ele-vated head storage tank or by fire pumps which taketheir suction from a low level storage tank. Forcases where the water supply pressure is inadequateto fill the tank, fill pumps will be provided. Firepumps will be electric motor driven, except that atleast one should be of the engine driven or of thedual drive type.

5-24

TM5-811-6

CHAPTER 6

GAS TURBINE POWER PLANT DESIGN

6-1. GeneralGas turbines find only limited application as primemovers for power generation at military facilities.This is because gas turbine generators typicallyhave significantly higher heat rates than steam tur-bine or diesel power plants; their higher fuel costsquickly outweigh their initial advantages in mostapplications. Applications to be evaluated include:

a. Supplying relatively large power requirementsin a facility where space is at a significant pre-mium—such as hardened structure.

b. Mobile, temporary or difficult access site—such as a troop support or lie of sight station.

c. Peak shaving, in conjunction with a more effi-cient generating station.

d. Emergency power, where a gas turbine’s lightweight and relatively vibration-free operation are ofgreater importance than fuel consumption overshort periods of operation. However, the startingtime of gas turbines may not be suitable for a givenapplication.

e. Combined cycle or cogeneration power plantswhere turbine exhaust waste heat can be econom-ically used to generate additional power and thermalenergy for process or space heating.

6-2. Turbine-generator selectiona. Packaged plants. Gas turbines are normally

purchased as complete, packaged power plants.With few exceptions, only simple cycle turbines areapplicable to military installations. Therefore, theremainder of this chapter focuses on the simplecycle configuration. The packaged gas turbine pow-er plant will include the prime mover, combustionsystem, starting system, generator, auxiliaryswitchgear and all turbine support equipment re-quired for operation. This equipment is usually“skid” or base mounted. The only “off base” oradditional auxiliaries normally required to supple-ment the package are the fuel oil storage tanks,transfer pumps and oil receiving station, distribu-tion switchgear, step up transformer and switch-yard, as required.

(1) Selection of unit size requires establishmentof plant loading and the number of units required forreliability y and turndown. Wide gaps in the standardequipment capacity ratings available may force re-

consideration of the number of units or the totalplant capacity,

(2) Initial selection of the gas turbine unit be-gins using the International Standards Organiza-tion (ISO) rating provided on the manufacturer’sdata sheets. This is a power rating at design speedand at sea level with an ambient temperature of590F (150C). The ISO rating considers inlet and out-let losses to be zero. Initially, ISO ratings will be re-duced 15 percent for typical applications, which willfurther be refined to reflect actual site and installa-tion conditions. The four variables which will be con-sidered in unit rating are:

(a) Elevation.(b) Ambient temperature.(c) Inlet losses.(d) Exhaust losses.

The following subsections define the impact of eachof these variables.

b. Elevation. For a specific site, the ISO rating re-duction due to site altitude is read directly from analtitude correction curve published by the variousmanufacturers. There is little difference in suchcurves. For mobile units, the effect of possible sitealtitudes will be evaluated. The operating altitudewill be used to determine the unit rating.

c. Temperature. Site temperature data will be ob-tained from TM 5-785. The design temperature se-lected is normally the 2 1/2 percent dry bulb tempera-ture, although the timing of the load curve peak willalso be considered. Unless the choice of equipment istight, there is usually sufficient overload capabilityto carry the unit during the 2 1/2 percent time of high-er temperature. Another temperature related selec-tion parameter is icing. Icing is caused when theright combination of temperature and humidity lev-els occurs, and is manifested by ice formation on thedownstream side of the inlet filters or at the com-pressors bell mouth intake. Chunks of ice can besucked in the compressor with possible blade dam-age resulting. Icing occurs when ambient tempera-tures are in the 350 to 420F. range and relative hu-midity is high. This problem will be avoided by recir-culating hot air from the compressor discharge tothe filter inlet, either manually or automatically.This causes some loss of turbine efficiency.

d. Inlet losses. Inlet losses are a critical perform-ance variable, and one over which the designer has

6-1

TM 5-811-6

considerable control. Increases in the inlet air fric-tion cause a significant reduction in power output.The total inlet pressure loss will not exceed 2 inchesof water and will be as close to zero as space limita-tions and economics will permit. Additional duct-work costs will be quickly amortized by operatingfuel savings. Dust, rain, sand and snow will be pre-vented from entering the combustion air inlet of theengine. Inlet air filter design will preclude entranceof these contaminants with minimal pressure loss.The air inlet will be located to preclude ingestion ofcombustion products from other turbines or a near-by boiler plant, or hot, humid discharge from anycooling towers.

e. Outlet losses. Outlet friction losses also resultin a decrease of turbine-generator output and will beaccounted for in the unit design. The major factor inoutlet losses is the requirement to attenuate noise.More effective silencers typically have higher pres-sure losses. Exhaust back pressure has a smalleroverall effect on performance than inlet losses butwill be kept as low as possible, and will be less than6 inches of water. Since increasing exhaust silencersize costs considerably more than ductwork designimprovements, the return on investment for a lowpressure loss exhaust is significantly longer.

6-3. FuelsEach manufacturer has his own specification on fuelacceptable for his turbine. The high grade liquidfuels such as Diesel No. 1 or 2 and JP-4 or JP-5 willlikely be acceptable to all manufacturers. Use ofheavier oils is possible with a specially designed tur-bine. The heavy oil will have to be cleaned up to re-duce corrosive salts of sodium, potassium, vana-dium, and sulfur–all of which will elevate the costof the fuel. Storage and handling at the site will alsobe more costly, particularly if a heavy oil such asNo. 6 was involved because of the heating require-ment. No. 4 oil will increase transfer pumping costsa bit but, except in extremely cold regions, wouldnot require heating.

6-4. Plant arrangementa. General. Turbine generator units are frequent-

ly sold as complete packages which include all com-ponents necessary to operate, ready for connectionto the fuel supply and electrical distribution system.This presents the advantages of faster lead time,well matched components and single point of perfor-mance responsibility y.

b. Outdoor vs. indoor.(1) Outdoor. Outdoor units can be divided into

two sub-types.(a) The package power plant unit is supplied

with the principal components of the unit factory as-

sembled into three or more skid mounted modules,each with its own weatherproof housing the sepa-rate modules have wiring splits, piping connections, and housing flanges arranged so that the modulesmay be quickly assembled into a unit on a reinforcedconcrete pad in the field. Supplementing these mainmodules are the inlet and exhaust ducts, inlet si-lencer and filters, exhaust silencer, fuel tanks, unitfuel skid, and unit auxiliary transformer which areconnected by piping and cables to the main as-sembly after placing on separate foundation asmay be required.

(b) The other outdoor sub-type is a similarpackage unit except that the weatherproof housingis shipped knocked down and is, in effect, a prefabri-cated building for quick field assembly into a clo-sure for the main power plant components.

(c) Outdoor units to be provided with all com-ponents, auxiliaries and controls assembled in all-weather metal enclosures and furnished completefor operation will be specified for Class “B” and “C”power plants having a 5-year anticipated life and re-quiring not more than four generating units.

(2) Indoor. An indoor type unit will have thecompressor-turbine-generator mounted at gradefloor level of the building on a pad, or possiblyraised above or lowered below grade floor level to provide space for installation of ducts, piping andcabling. Inlet and exhaust ducts will be routed to the outside through the side wall or the roof; the sidewall is usually preferable for this so that the turbineroom crane can have full longitudinal travel in theturbine generator bay. Filters and silencers may beinside or outside. All heat rejection equipment willbe mounted outside while fuel oil skids may be in-side or outside. Unit and distribution switchgearand motor control centers will be indoors as in a con-ventional steam power plant. Figure 6-1 shows atypical indoor unit installation with the prime mov-er mounted below grade floor level.

6-5. Waste heat recoveryWaste heat recovery will be used wherever cost ef-fective. If the turbine unit is to be used only inter-mittently, the capital cost of heat recovery must bekept down in order to be considered at all. Add-on orsidestream coils might provide a temporary hotwater supply for the period of operation—for one ex-ample. Care must be exercised due to the high ex-haust gas temperature. It may prove feasible toflash steam through the jacket of a small heat ex-changer. In the event that a long term operation isindicated, the cost trade off for heat recovery equipment is enchanced, but still must be considered as an auxiliary system. It will take a sizable yearlyload to justify an exhaust gas heat recovery boiler.

6-2

TM 5-811-6,

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Figure 6-1. T:ppical indoor simple cycle gas turbine generatorpowerpkznt.

Turbine efficiency loss due to back pressure is also afactor to be considered.

6-6. Equipment and auxiliary systemsa. GeneraL The gas turbine package is a complete

power plant requiring only adequate site prepara-tion, foundations, and support facilities includingfuel storage and forwarding system, distributionswitchgear, stepup transformer, and switchyard. Ifthe fuel to be fired is a residual oil, a fuel washingand treating plant is also required.

b. References. Chapter 4 sets forth guidelines forthe design of the electrical facilities required for a

gas turbine power plant, including the generator,switchgear, switchyard, transformers, relays andcontrols. Chapter 2 describes the pertinent civil fa-cilities.

c. Scope. The scope of a package gas turbine gen-erator for purchase from the manufacturer will in-clude the following

(1) Compressor and turbine with fuel and com-bustion system, lube oil system, turning gear, gov-ernor, and other auxiliaries and accessories.

(2) Reduction gear.(3) Generator and excitation system.

6 - 3

TM 5-811-6

(4) AC auxiliary power system includingswitchgear and motor controls.

(5) DC power system including battery, charg-er, and inverter if required.

(6) External heat rejection equipment if re-quired.

(7) All mechanical and electrical controls.(8) Diesel engine or electric motor starting sys-

tem.

(9) Unit fuel skid (may be purchased separatelyif desired).

(10) Intake and exhaust ducts.(11) Intake air filters.(12) Acoustical treatment for intake and ex-

haust ducts and for machinery.(13) Weatherproof housing option with appro-

priate lighting, heating, ventilating, air condition-ing and fire protection systems.

6 - 4

CHAPTER 7

DIESEL ENGINE POWER PLANT DESIGN

7-1. Enginesa. Diesel engines have higher thermal efficiencies

than other commercial prime movers of comparablesize. Diesel engine-generators are applicable to elec-tric loads. from about 10 to 5000 kilowatts. Diesel-engine-driven electric generator sets are divided intothree general categories based on application as fol-lows:

(1) Class A: Diesel-electric generator sets forstationary power plants generating prime powercontinuously at full nameplate kW rating as the solesource of electric power.

(2) Class B: Diesel-electric generators sets forstationary power plants generating power on astandby basis for extended periods of time wheremonths of continuous operation at full nameplatekW rating are anticipated.

(3) Class C: Diesel-electric generator sets forstationary power plants generating power on anemergency basis for short periods of time at fullnameplate kW rating where days of continuousoperation are anticipated.

b. Diesel engines normally will be supplied asskid mounted packaged systems. For multiple-unitprocurement, matched engine-generator sets will beprovided for units of 2500kW electrical output orless. For larger units, investigate the overall eco-nomics and practicality of purchasing the gener-ators separately, recognizing that the capability forreliable operation and performance of the units aresacrificed if engine and generator are bought fromtwo sources.

c. Engines and engine-generator sets are normal-ly provided with the primary subsystems necessaryfor engine operation, such as:

(1) Starting system.(2) Fuel supply and injection system.(3) Lubrication system and oil cooling.(4) Primary (engine) cooling system.(5) Speed control (governor) system.(6) Required instrumentation.

d. The designer must provide for the following(1) Intake air.

(2) Exhaust and exhaust silencng.(3) Source of secondary cooling (heat sink).(4) Engine foundation and vibration isolation.(5) Fuel storage, transfer and supply to the en-

gine.(6) Electrical switchgear, stepup transformer, if

required, and connection to distribution wiring.(7) Facilities for engine maintenance, such as

cranes, hoists and disassembly space.(8) Compressed air system for starting, if re-

quired.e. Generator design criteria are provided in

Chapter 4.

7-2. Fuel selectionA fuel selection is normally made according to avail-ability and economic criteria during the conceptualdesign. Fuels are specified according to ASTM, Fed-eral and military specifications and include:

a. ASTM Grades l-D, 2-D, and 4-D as specifiedby ASTM D 975. These fuels are similar to No. 1,No. 2 and No. 4 heating oils.

b. Federal Specification Grades DF-A and DF-2(see Federal Specification VV-F-800). These specifi-cations parallel ASTM Grades 1-D and 2-D, respec-tively.

c. Jet Fuel Grade JP-5 (Military SpecificationMIL-T-5624).

d. Marine Diesel (Military Specification MIL-F-16884). Marine Diesel is close to ASTM No. 2-D,although requirements differ somewhat.

e. ASTM No. 6, or its Federal equivalent, or Navyspecial may be specified for engines in excess of2000 kW if economics permit. Fuel selection mustbe closely coordinated with the requirements of theengine manufacturer. The No. 2-D or DF- 2 fuels aremost common. If fuel is stored at ambient tempera-tures below 200F,, No. 1-D or DF-A (arctic fuel)should be considered. ASTM No. 4-D or No. 6 areresidual oil blends which require preheating prior toburning. Fuel oil storage and handling equipmentand the engine itself will be specifically designed forburning these viscous fuel oils.

7-1

TM 5-811-6

Section ll. BALANCE OF PLANT SYSTEMS

7-3. GeneralBalance of plant systems are those which must beprovided and interfaced with a packaged diesel ordiesel-generator set to provide an operational gener-ating unit.

7-4. Cooling systemsa. Water-to-water systems. Jacket water and lube

oil cooling heat exchangers are cooled by a sec-ondary circulating water system. Normally, a recir-culating system will be used. Heat is dissipated tothe atmosphere through an evaporative, mechan-ical-draft cooling tower. If the plant is located on ornear a body of water, once-through circulating waterwill be evaluated. Bidders will be informed of thetype and source of secondary water used so heat ex-changers can be designed for their intended service.

b. Water-to-air systems. Water-to-air systemswill be restricted to small engines. If an integral(skid mounted) radiator is used, sufficient coolingair will be provided. Outside air may be ducted tothe radiator air inlet. Ductwork will be designed forminimum pressure loss. The cooling fan(s) will bechecked for adequate flow (cfm) and static pressureunder the intended service. Air leaving the radiatornormally goes to the engine room and is exhausted.Cooling air inlets will be equipped with automaticdampers and bird screens.

7-5. Combustion air intake and exhaustsystems

a. Purpose. The functions of the intake and ex-haust systems are to deliver clean combustion air tothe engine and dispose of the exhaust quietly withthe minimum loss of performance.

b. Intake. The air intake system usually consistsof air intake duct or pipe appropriately supported, asilencer, an air cleaner, and flexible connections asrequired. This arrangement permits location of areaof air intake beyond the immediate vicinity of theengine, provides for the reduction of noise from in-take air flow, and protects vital engine parts againstairborne impurities. The air intake will be designedto be short and direct and economically sized forminimum friction loss. The air filter will be designedfor the expected dust loading, simple maintenance,and low pressure drop. Oil bath or dry filter elementair cleaners will be provided. The air filter and si-lencer may be combined.

c. Exhaust. The exhaust system consists of amuffler and connecting piping to the atmospherewith suitable expansion joints, insulation, and sup-ports. In cogeneration plants, it also provides forutilization of exhaust heat energy by incorporating

7-2

a waste heat boiler which can be used for space heat-ing, absorption refrigeration, or other useful purpose. This boiler produces steam in parallel with thevapor phase cooling system. The exhaust silencerattenuates exhaust gas pulsations (noise), arrestssparks, and in some cases recovers waste heat. Themuffler design will provide the required sound at-tenuation with minimum pressure loss.

7-6. Fuel storage and handlinga. Storage requirements.

(1) Aboveground fuel storage tanks with a mini-mum capacity for 30 days continuous operation willbe provided for continuous and standby duty plants. Fuel storage shall be designed to the require-ments of NFPA 30. A tank with 3 day storage ca-pacity will be provided for emergency duty plants.

(2) For continuous duty plants, provide a daytank for each engine. The tank will provide a 4-hourstorage capacity at maximum load. The tank will befilled by automatic level controls and transferpumps. Standby plants will be provided with daytanks of sufficient capacity to permit manual fillingonce per shift (10-hour capacity). No separate daytank is required for emergency plants.

b. Fuel handling. Provide unloading pumps if fuelis to be delivered by rail car or barge. Most fuel tanktrucks are equipped with pumps. Provide transfer pumps capable of filling the day tank in less than 1/2hour when the engine is operating at maximum load.Duplex pumps, valved so that one can operate whilethe other is on standby, will be provided for reliabil-ity. Pipeline strainers and filters will be provided toprotect the fuel pumps and engine injectors fromdirt. Strainers and filters will not pass particles larg-er than half the injector nozzle opening.

7-7. Engine room ventilationAbout 8 percent of the heating value of the fuel con-sumed by the engine is radiated to the surroundingair. It is essential that provision be made for re-moval of this heat. Engine room temperature riseshould be limited to 150F. For engines with wallmounted or ducted radiators, radiator fans may besufficient if adequate exhaust or air relief is pro-vided. If engines are equipped with water cooledheat exchangers, a separate ventilation system willbe provided. The approximate ventilation rate maybe determined by the following formula:

1,000 x HPC F M = T

where:HP =

T =maximum engine horsepowerallowable temperature rise, ‘F.

TM 5-811-6

Provision will be made to allow for reducing the air the engine room; however, jacket water cooling willflow during the cooler months so as not to over-cool remain within recommended limits at all times.

Section Ill. FOUNDATIONS AND BUILDING

7-8. GeneralChapter 2 should be consulted for the civil facilitiesdesign criteria associated with a diesel power plant.This section amplifies the civil engineering aspectsdirectly applicable to the diesel plant.

7-9. Engine foundation

a. Design considerations.(1) The foundation will have the required mass

’ and base area, assuming installation on firm soil andthe use of high quality concrete. Before final detailsof the foundation design are established by the de-signer, the bearing capacity and suitability of thesoil on which the foundation will rest will be deter-mined. Modification of the manufacturer’s recom-mended foundation may be required to meet specialrequirements of local conditions. Modifications re-quired may include:

(a) Adjustment of the mass.(b) Additional reinforcing steel.(c) Use of a reinforced mat under the regular

foundation.(d) Support of the foundation on piles. Piling

may require bracing against horizontal displace-ment.‘ (2) The engine foundation will extend below the

footings of the building and the foundation will becompletely isolated from the walls and floors of thebuilding. The foundation block will be cast in a sin-gle, continuous pour. If a base mat is used, it will becast in a separate continuous pour and be providedwith vertical re-bars extending up into the founda-tion block.

b. Vibration mounts.(1) For small engine installations where there is

a possibility y of transmission of vibration to adjacentareas, the engine foundations will be adequately in-sulated by gravel, or the engine mounted on vibra-tion insulating material or devices. Vibrationmounts for larger engines become impractical andfoundation mass must be provided accordingly.

(2) Skid mounted generating units will be sup-plied with skids of sufficient strength and rigidity tomaintain proper alignment between the engine andthe generator. Vibration isolators, either of the ad-justable spring or rubber pad type, will be placed be-tween the unit skid and the foundation block to min-imize the transmission of vibrations.

7-10. Buildinga. Location.

(1) A diesel engine power plant has few limita-tions regarding location. Aesthetically, an architec-turally attractive building can enclose the equip-ment if required. Fuel can be stored underground ifappearance so dictates. Proper exhaust and intakeair silencing can eliminate all objectionable noise.Air and water pollution problems are minimal withmost recommended fuels.

(2) Consider the relative importance of the fol-lowing when selecting a plant site:

(a) Proximity to the center of power demand.(b) Economical delivery of fuel.(c) Cost of property.(d) Suitability of soil for building and machin-

ery foundations.(e) Space available for future expansion.(f) Proximity to potential users of engine

waste heat.(g) Availability of water supply for cooling

systems.b. Arrangement.

(1) In designing the power plant building, a gen-eral arrangement or plant layout will be designed forthe major components. The arrangement will facili-tate installation, maintenance and future plant ex-pansion. Ample space shall be provided around eachunit to create an attractive overall appearance andsimplify maintenance for engines and auxiliaryequipment.

(2) In addition to the basic equipment arrange-ment, provide for the location of the following, as re-quired by the project scope:

(a) Office space.(b) Lunchroom and toilet facilities.(c) Engine panels, plant and distribution

switchgear, and a central control board (Chapter 5,Section I).

(d) Cooling system including pumps and heatexchangers.

(e) Lube oil filters and, for heavier fuels,oil processing equipment such as centrifuges.

(f) Tools and operating supplies storage.(g) Facilities for maintenance.(h) Heat recovery equipment, if included.

fuel

(3) The main units should usually be lined up inparallel, perpendicular to the long axis of the engineroom thus making unlimited future expansion easy

7-3

TM 5-811-6

and economical. The engine bay will be high enoughfor a motorized, overheat traveling crane. The crane,if economically feasible, will be sized for mainte-nance only. The switchgear will be located at thegenerator end of each unit, permitting the shortest

possible wiring between the switchgear and gener-ators. The switchgear may be enclosed in a separateroom or maybe a part of the main engine bay.

(4) A typical small two-unit diesel power plant -

arrangement is shown in Figure 7-1.


Figure 7-1. Typical diesel generator power plant.

7-4

TM 5-811-6

CHAPTER 8

COMBINED CYCLE POWER PLANTS

Section 1. TYPlCAL PLANTS AND CYCLES

8-1. Introductiona. Definition. In general usage the term ‘ ‘com-

bined cycle power plant” describes the combinationof gas turbine generator(s) (Brayton cycle) with tur-bine exhaust waste heat boiler(s) and steam turbinegenerator(s) (Rankine cycle) for the production Ofelectric power. If the steam from the waste heat boil-er is used for process or space heating, the term "co-generation” is the more correct terminology (simul-taneous production of electric and heat energy).

b. General description.(1) Simple cycle gas turbine generators, when

operated as independent electric power producers,are relatively inefficient with net heat rates at fullload of over 15,000 Btu per kilowatt-hour. Conse-quently, simple cycle gas turbine generators will beused only for peaking or standby service when fueleconomy is of small importance.

(2) Condensing steam turbine generators havefull load heat rates of over 13,000 Btu per kilowatt-hour and are relatively expensive to install and oper-ate. The efficiency of such units is poor compared tothe 8500 to 9000 Btu per kilowatt-hour heat ratestypical of a large, fossil fuel fired utility generatingstation.

(3) The gas turbine exhausts relatively largequantities of gases at temperatures over 900 “F, Incombined cycle operation, then, the exhaust gasesfrom each gas turbine will be ducted to a waste heatboiler. The heat in these gases, ordinarily exhaustedto the atmosphere, generates high pressure super-heated steam. This steam will be piped to a steamturbine generator. The resulting “combined cycle”heat rate is in the 8500 to 10,500 Btu per net kilo-watt-hour range, or roughly one-third less than asimple cycle gas turbine generator.

(4) The disadvantage of the combined cycle isthat natural gas and light distillate fuels requiredfor low maintenance operation of a gas turbine are

expensive. Heavier distillates and residual oils arealso expensive as compared to coal.

8-2. Plant detailsa. Unfired boiler operation. For turbines burning

natural gas or light distillate oil, the boiler will be ofthe compact, extended surface design with eithernatural or forced circulation with steam generatedat approximately 650 psig and 8250F. The additionof the waste heat boiler-steam turbine generatorcombinations increases power output over the sim-ple gas turbine.

b. Fired boiler operation. The exhaust from a gasturbine contains large amounts of excess air. Thisexhaust has an oxygen content close to fresh air,and will be utilized as preheated combustion air forsupplementary fuel firing. Supplementary fuel fir-ing permits increasing steaming of the waste heatboiler. Burners will be installed between the gas turbine exhaust and the waste boiler to elevate the ex-haust gases to the heat absorption limitations of thewaste heat boiler. Supplementary burners also per-mit generation when the gas turbine is out ofservice.

c. Other types of combined cycle plants. Varia-tions of combined cycle plants areas follows:

(1) Back pressure operation of the steam tur-bine. This may include either unfired or fired boileroperation. The steam turbine used is a non-condens-ing machine with all of the exhaust steam utilizedfor heating or process at a lower pressure level.

(2) Controlled (automatic) extraction operationof the steam turbine. This may also include eitherunfired or fired boiler operation. A controlled extrac-tion steam turbine permits extraction steam flow tobe matched to the steam demand. Varying amountsof steam can be used for heating or process pur-poses. Steam not extracted is condensed. This typeof steam turbine will only be used when electrical re-quirements are very large (see Chapter 1).

Section Il. GENERAL DESIGN PARAMETERS

8-3. Background turbine and steam turbine power plants. The wasteA combined cycle power plant is essentially com- heat boiler is different in design, however, from a

prised of standard equipment derived from both gas normal fossil fueled boiler. Feedwater heating is

8-1

TM 5-811-6

usually less complex. Power plant controls musttake into account the simultaneous operation of gasturbine, boiler and steam turbine.

8-4. Design approach

a. Operating differences. The following itemsshould be given consideration:

(1) Turndown. Gas turbine mass flows are fairlyconstant, but exhaust temperature falls off rapidlyas load is reduced. Therefore, decreasing amounts ofsteam are generated in the waste heat boiler. Varia-tions in gas turbine generator output affect the out-put from the steam turbine generator unless supple-mentary fuel is fired to adjust the temperature. Sup-plementary fuel firing, however, decreases combinedcycle efficiency because of the increased boiler stackgas losses associated with the constant mass flow ofthe turbine.

(2) Exhaust gas flows. For the same amount ofsteam produced, gas flows through a combined cycleboiler are always much higher than for a fuel firedboiler.

(3) Feedwater temperatures. With a combinedcycle plan, no air preheater is needed for the boiler.Hence, the only way to reduce final stack gas exittemperature to a sufficiently low (efficient) level isto absorb the heat in the feedwater with economizerrecovery equipment. Inlet feedwater temperaturemust be limited (usually to about 2500F) to do this.

b. Approaches to specialized problems:(1) Load following. Methods of varying loads

for a combined cycle include:(a) Varying amount of fuel to a gas turbine

will decrease efficiency quickly as output is reducedfrom full load because of the steep heat rate curve ofthe gas turbine and the multiplying effect on thesteam turbine. Also, steam temperature can rapidlyfall below the recommended limit for the steam tur-bine.

(b) Some supplementary firing may be usedfor a combined cycle power plant full load. Supple-mentary firing is cut back as the load decreases; ifload decreases below combined output when supple-mentary firing is zero, fuel to the gas turbine is alsocut back. This will give somewhat less efficiency atcombined cycle full load and a best efficiency pointat less than full load; i.e., at 100 percent waste heatoperation with full load on the gas turbine.

(c) Use of a multiple gas turbine coupled witha waste heat boiler will give the widest load rangewith minimum efficiency penalty. Individual gasturbine-waste heat units can be shut down as the

load decreases with load-following between shut-down steps by any or both of the above methods.

(d) Installation of gas dampers to bypass variable amounts of gas from turbine exhaust di-rectly to atmosphere. With this method, gas turbineexhaust and steam temperatures can be maintainedwhile steam flow to steam turbine generator is de-creased as is the load. This has the added advantagethat if both atmospheric bypass and boiler dampersare installed, the gas turbine can operate while thesteam turbine is down for maintenance. Also, if fullfuel firing for the boiler is installed along with a standby forced draft fan, steam can be producedfrom the boiler while the gas turbine is out for main-tenance. This plan allows the greatest flexibilitywhen there is only one gas turbine-boiler-steam tur-bine train. It does introduce equipment and controlcomplication and is more costly; and efficiency de-creases as greater quantities of exhaust gas are bypassed to atmosphere.

(2) Boiler design.(a) Waste heat boilers must be designed for

the greater gas flows and lower temperature differ-entials inherent in combined cycle operation. If astandby forced draft fan is installed, the fan must becarefully sized. Gas turbine full load flow rates neednot be maintained,

(b) If the fuel to be fired, either in the gas tur-bine or as supplementary fuel, is residual oil, bare tubes should be used in the boiler with extended sur-face tubes used in the economizer only. This in-creases the boiler cost substantially but will pre-clude tube pass blockages. Soot blowers are requiredfor heavy oil fired units.

(3) Feedwater heating and affect on steam gen-erator design.

(a) Because of the requirement for relativelylow temperature feedwater to the combined cycleboiler, usually only one or two stages of feedwater heating are needed. In some cycles, separate econo-mizer circuits in the steam generator are used toheat and deaerate feewater while reducing boilerexit gas to an efficient low level.

(b) For use in military installations, only co-generation combined cycles will be installed. A typi-cal cycle diagram is shown in Figure 8-1.

(4) Combined cycle controls. There is a widevariation in the controls required for a combined cy-cle unit which, of course, are dependent on the typeof unit installed. Many manufacturers have de-veloped their own automated control systems tosuit the standardized equipment array which theyhave developed.

8-2

TM 5-811-6

.

*

8-3

TM 5-811-6

APPENDIX A

REFERENCES

Government PublicationsCode of Federal Register

10 CFR 436A

Federal SpecificationsVV-F-800

●✝ Department of DefenseDOD 4270.1-M

Army RegulationsAR 11-28

Air Force RegulationsAFR 178-1

Military SpecificationsMIL-T-5624LMIL-F-16884CMIL-P-17552D

Part 436: Federal Energy Management and Planning Program.Subpart A: Methodology and Procedures for Life Cycle Cost Analysis.

Fuel Oil, Diesel.

Department of Defense Construction Manual Guide.

Economic Analysis and Program Evaluation for Resource Management.

Economic Analysis and Program Evaluation for Resources Manage-ment.

Turbine Fuel, Aviation, Grades JP-4 and JP-5.Fuel Oil, Diesel, Marine.Pump Units, Centrifugal, Water, Horizontal; General Service and Boiler

Feed: Electric Motor or Steam Turbine Driven.

Departments of the Army, Air Force and NavyTM 5-803-5/NAVPAC P-960 Installation Design.

AFM 88-43TM 5-805-41AFM 88-371 Noise Control for Mechanical Equipment.

NAVFAC DM-3.1OTM 5-805-91AFM 88-201 Power Plant Acoustics.

NAVFAC DM-3.14TM 5-815-l/AFR 19-6/ Air Pollution Control Systems for Boilers and Incinerators.

NAVFAC DM-3.15

Departments of the Army and Air ForceTM 5-810-l/AFM 88-8, Mechanical Design - Heating, Ventilating and Air Conditioning.

Chap. 1TM 5-811 -l/AFM 88-9, Electrical Power Supply and Distribution.

Chap, 1TM 5-811-2/AFM 88-9, Electrical Design, Interior Electrical System.

Chap. 2TM 5-818-2/AFM 88-6, Pavement Design for Frost Conditions.

Chap. 4TM 5-822-2/AFM 88-7, General Provisions and Geometric Design for Roads, Streets, Walks, and

Chap. 5 Open Storage Areas.TM 5-822-41AFM 88-7, Soil Stabilization for Roads and Streets.

Chap. 4TM 5-822-5/AFM 88-7, Flexible Pavements for Roads, Streets, Walks and Open Storage Areas.

Chap, 3

A-1

TM 5-811-6

TM 5-822-6/AFM 88-7,Chap. 1

TM 5-822-7/AFM 88-7,Chap. 8

Rigid Pavements for Roads, Streets, Walks and Open Storage Areas.

Standard Practice for Concrete Pavements.

Department of the ArmyTM 5-785 Engineering Weather Data.TM 5-822-8 Bituminous Pavements - Standard Practice.

Non-Government PublicationsAmerican National Standards Institute (ANSI), 1430 Broadway, New York, N.Y. 10018B31.1 Code for Pressure Piping - Power Piping.C5O.1O General Requirements for Synchronous Machines.C50.13 Requirements for Cylindrical Rotor Synchronous Generators.C50.14 Requirements for Combustion Gas Turbine Cylindrical Rotor Syn-

chronous Generators.C57.12.1O Requirements for Transformers, 230,000 Volts and Below, 833/958

Through 8,333/10,417 kVA, Single-Phase, and 750/862 Through60,000/80,000/100,000 kVA, Three-Phase.

C84.1 Voltage Ratings for Electrical Power Systems and Equipment.

American Society of Mechanical Engineers, 345 East 47th Street, New York, N.Y. 10017ASME Code ASME Boiler and Pressure Code: Section I, Power Boilers; Section II,

Material Specifications; Section VIII, Pressure Vessels; SectionIX, Welding and Brazing Qualifications.

ASME TWDPS-1 Recommended Practices of Water Damage to Steam Turbines Used forElectric Power Generation (Part 1- Fossil Fueled Plants).

Institute of Electrical and Electronic Engineers, (NEMA) IEEE Service Center, 445 Hoes Lane, Piscataway,N.J. 08854

100 Standard Dictionary of Electrical and Electronic Terms.112 Test Procedure for Polyphase Indicator Motors and Generators.114 Test Procedure for Single Phase Induction Motors.115 Test Procedure for Synchronous Machines.

National Electrical Manufacturer’s Association, 155 East 44th Street, New York, N.Y. 10017SM 12 Direct-Connected Steam Turbine Synchronous Generator Units, Air

Cooled.SM 13 Direct-Connected Steam Turbine Synchronous Generator Units, Hydro- -

gen Cooled (20,000 to 30,000 kW, Inclusive).

National Fire Protection Association, Publication Sales Department, 470 Atlantic Avenue, Boston, MA.02210

30 Flammable and Combustible Liquids Code.70 National Electric Code.

General Electric Company, Lynn, MA. 0910GEK 22504 Standard Design and Operating Recommendations to Minimize Water

Rev. D. Induction in Large Steam Turbines.

Westinghouse Electric Corporation, Lester, PA. 19113— Recommendation to Minimize Water Damage to Steam Turbines.

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BIBLIOGRAPHY

American Institute of Architecture, Life Cycle Cost Analysis - A Guide for Architects, AIA, 1735 New YorkAvenue, Washington, DC 20006

Fink and Beatty, Standard Handbook for Electrical Engineers, McGraw Hill Book Company, New York, N.Y.10020

Grant, Ireson and Leavenworth, Principals of Engineering Economy, John Wiley & Sons, Inc., New York,N.Y. 10036

Kent, R. T., Kents Mechanical Engineers Handbook Power Volume, John Wiley& Sons, Inc., New York, N.Y.10036

Marks Standurd Handbook for Mechanical Engineers, McGraw Hill Book Company, New York, N.Y. 10020

Mason, The Art and Science of Protective Relaying, General Electric Engineering Practice Series, John Wiley& Sons, Inc., New York, N.Y. 10036

Morse, Frederick T., Power Plant Engineering and Design, D. Van Nostrand Company, Inc., New York, N.Y.

Naval Facilities Engineering Command, Economic Analysis Handbook, NAVFAC P442, U.S. Naval Publica-tions and Forms Center, 5801 Tabor Avenue, Philadelphia, PA. 19120.

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Changes to Publications and Blank Forms) directly to HQDA (DAEN-ECE-E), WASH DC 20314.

By Order of the Secretary of the Army:

Official:ROBERT M. JOYCE

Major General United States ArmyThe Adjutant General

JOHN A. WICKHAM, JR.General United States Army

Chief of Staff

* U . S . GOVERNMENT PRINTING OFFICE: 1983-424-688

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