TECHNICAL MANUALELECTRIC POWER PLANT DESIGNREPRODUCTION AUTHORIZATION/RESTRICTIONSThis 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 proprietorsand is acknowledged as such at point of use. Anyone wishing to make further use of any copyrighted material,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 5-811-6T ECHNICAL M ANUAL HEADQUARTERSDEPARTMENT OF THE ARMYNO. 5-811-6 WASHINGTON, DC 20 January 1984ELECTRIC POWER PLANT DESIGNCHAPTER 1. INTRODUCTIONPurpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design philosophy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design criteria . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Economic considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .CHAPTER 2. SITE AND CIVIL FACILITIES DESIGNSelection I. Site SelectionIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .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 CyclesIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .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.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Paragraph1-11-21-31-42-12-22-32-42-52-62-72-82-93-13-23-33-43-53-63-73-83-93-103-113-123-133-143-153-163-173-183-193-203-21

3-223-233-243-253-263-273-283-293-303-313-323-33Page1-11-11-11-52-12-12-12-12-12-12-22-22-23-13-13-13-33-63-63-63-93-113-123-123-253-263-263-273-293-303-303-323-323-333-333-333-343-343-343-353-403-403-413-433-433-44iTM 5-811-6CHAPTER 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 SystemsVoltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .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 SystemsGeneral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Control panels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Automatic control systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Monitoring instruments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Alarm and annunciator systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Section II. Heating, Ventilating and Air Conditioning SystemsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Operations areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Service areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Paragraph3-343-353-363-37

3-383-393-403-414-14-24-34-44-54-64-74-84-94-104-114-124-134-144-154-164-174-184-194-204-214-224-234-244-254-264-274-284-294-304-314-324-334-34Page3-443-453-453-453-453-463-463-50-14-14-34-74-84-84-94-134-164-164-174-184-194-194-204-204-204-214-214-214-214-214-22

4-234-234-234-244-244-244-244-244-244-244-265-15-25-35-45-55-65-75-85-15-15-55-95-145-145-145-14i iTM 5-811-6Paragraph Page5-155-155-155-175-175-175-215-215-215-215-215-225-225-235-246-16-16-26-26-26-37-17-17-27-27-27-27-27-37-37-38-18-18-18-2

Page1-41-53-23-33-53-73-83-93-133-153-16CHAPTER 5. GENERAL POWER PLANT FACILITIES DESIGN (Continued)Section 111. Power and Service Piping Systems5-95-105-11Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Piping design fundamentals... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Specific system design considerations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Section IV. Thermal Insulation and Freeze ProtectionIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-125-135-145-155-165-175-185-19Insulation design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Insulation materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Control of useful heat losses.... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Safety insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cold surface insulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Economic thickness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Freeze protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Section V. Corrosion ProtectionGeneral remarks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-20Section VI. Fire ProtectionIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..CHAPTER 6.5-215-22Support facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-23GASTURBINE POWER PLANT DESIGNGeneral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Turbine-generator selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-16-26-36-46-56-6Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Plant arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Waste heat recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Equipment and auxiliary systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .DIESEL ENGINE POWER PLANT DESIGNSection I. Diesel Engine GeneratorsEngines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fuel selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Section II. Balance of Plant SystemsCHAPTER 7.L7-17-27-37-47-57-67-7General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Cooling systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Combustion air intake and exhaust systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fuel storage and handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Engine room ventilation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Section III. Foundations and BuildingGeneral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Engine foundation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-87-9Building . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-10COMBINED CYCLE POWER PLANTSSection I. Typical Plants and CyclesIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Plant details . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Section II. General Design ParametersBackground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Design approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .REFERENCES.CHAPTRR 8.8-1. 8-28-38-4APPENDIX A:BIBLIOGRAPHYLIST OF FiGURESFigure No.Figure 1-11-23-13-23-33-43-53-63-73-83-9Typical 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 5-811-6Page3-103-113-123-133-143-154-14-24-34-44-54-64-74-85-16-17-18-1Table No.Table 1-11-21-31-43-13-23-33-43-53-63-73-83-93-103-113-123-133-143-154-14-25-15-25-35-45-55-65-7Coal 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 Generation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .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 TABLESGeneral 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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-263-283-313-383-503-514-24-44-54-64-94-104-114-125-226-37-48-3Page1-2

1-31-31-33-43-103-143-173-183-193-203-213-223-233-243-363-473-483-494-224-255-15-45-65-85-105-165-18ivTM 5-811-6CHAPTER 1INTRODUCTION1-1. Purposea. General: This manual provides engineeringdata and criteria for designing electric power plantswhere the size and characteristics of the electricpower load and the economics of the particular facility 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 materialrelated to this document.1-2. Design philosophya. General. Electric power plants fall into severalcategories and classes depending on the type ofprime mover. Table 1-1 provides a general descriptionof plant type and related capacity requirements.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 purposesof this manual and to provide a quick scale for

the 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 selectedduring plant design to conform to this standard.c. Maintenance. Power plant arrangement willpermit reasonable access for operation and maintenanceof equipment. Careful attention will be givento the arrangement of equipment, valves, mechanicalspecialties, 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 convenientlyand 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 providefor 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 providedin Table 1-4.b. Electric power loads. The following information,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. Examplecurves 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 informationsuch as capacity, rates, metering, and interfaceswitchgear 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 boilerturbine

units, diesel generators, and combustionturbine generator units.(c) Historical operating data for each existinggenerating unit giving energy generated, fuel consumption,steam exported, and other related information.(5) Existing or recommended distribution voltage,generator voltage, and interconnecting substationvoltages.(6) If any of the above data as required for performingthe detailed design is unavailable, the designerwill develop this data.c. Exports team loads.(1) General requirements. If the plant will exportsteam, 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, seasonal,and daily loads for steam will be coordinated withthe electric power loads according to time of use.1-1CategoryPrimaryStandbyTable 1-1. General Description of Type of Plant.TYPE OF POWERCapacity No Export SteamAdequate to meetrequirement.Adequate withmobilizationall peacetime Purchased electric power to matchelectric 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 supplyemergency 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 more Class “C” diesel.than 4 hours. Mobile utilities support equipment.With Export SteamPurchased electric power and steam tomatch electric load plus supplementaryboiler plant to match export steam load.Automatic back pressure steam plant plus

automatic 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 supplementaryboiler plant.Standby diesel plant with supplementaryboiler plant.Retired automatic extraction steam plant.None.None.NAVFAC DM3TM 5-811-6Table 1-2. Diesel Class and Operational Characteristics.Fu1l Load RatingCapability Expected Operating HoursMinimum OperatingC—las s 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 sC a t e g o r yS m a l lM e d i u mL a r g eTable-3. Plant Sizes.S i z eo to 2 , 5 0 0 k W2 , 5 0 0 k W t o 1 0 , 0 0 0 k W1 0 , 0 0 0 k W t o 3 0 , 0 0 0 k WU . S . A r m y C o r p s o f E n g i n e e r sTable-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 (Emergency)E l e c t r i cP o w e rL o a d sAAc r i t i c a ll o a d s o n l yA = A p p l i c a b l eN / A = N o t A p p l i c a b l eFirst Ten Years40,000 hours plus20,000 to 40,000 hoursUnder 10,000 hoursE x p o r tSt earnL o a d s

AN/AN/AF u e lS o u r c ea n d W a t e r S t a c k W a s t eC o s t Supply E m i s s i o n D i s p o s a lA A A AA N/A N/AAA N/A N/A N /AC 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 )1-3TM 5-811-6This type of information is particularly important ifthe project involves cogeneration with the simultaneousproduction 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 requirementsthat may affect fuel and fuel characteristicsof the plant.e. Water supply. Fresh water is required forthermal cycle makeup and for cooling tower or coolingpond 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 condensatereturn for any export steam, and the maximumheat rejection from the cycle. This heat rejectionload usually will comprise the largest part ofthe makeup and will have the least stringent requirementsfor quality.f. Stack emissions. A steam electric power plant----- Sumner LoadWinter LoadKw1will be designed for the type of stack gas cleanupequipment which meets federal, state, and municipalemission 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 compliancecoal is employed. If design is based on compliancecoal, the design will include space and otherrequired provision for the installation of scrubberequipment. Boiler design will be specified as requiredfor NOx control.g. Waste disposal.(1) Internal combustion plants. Solid and liquidwastes from a diesel or combustion turbine generatingstation will be disposed of as follows: Miscellaneous

oily wastes from storage tank areas andsumps will be directed to an API separator. Supplementarytreating can be utilized if necessary to meetthe applicable requirements for waste water discharge.For plants of size less than 1,000 kW, liquid.URBAN[NDUSTRIAL TRACTIONLOAD LOAD1 2 6 1 2 6 1 2 6 1 2 6 1 2 6 1 2 6 1 2AM PM AM PM AM PMFROM 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.1-4TM 5-811-6oily wastes will be accumulated in sumps or smalltanks for removal. Residues from filters and centrifugeswill 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 blowdown,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 environmentalconsiderations include noise controland aesthetic treatment of the project. The final locationof the project within the site area will be reviewedin relation to its proximity to hospital andoffice areas and the civilian neighborhood, if applicable.Also, the general architectural design will bereviewed in terms of coordination and blending withIthe 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 designfor 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. Additionalstandards for design applications dealingwith energy/fuel consuming elements of a facilityare contained in the US Code of Federal Regulations,20 CFR 436A. Clarification of the basic standardsand guidelines for a particular application andsupplementary standards which may be required forspecial cases may be obtained through normal channelsfrom HQDA (DAEN-ECE-D), WASH DC20314.I0 1000 2000 3000 4000 5000 6000 7000 8000 8760-U.S. Army Corps ofFigure 1-2.— HOURSEngineersTypical annual load duration curve.1-5-TM 5-811-6CHAPTER 2SITE AND CIVIL FACILITIES DESIGNSection 1. SITE SELECTION2-1. 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 beingconsidered.2-2. Environmental considerationsa. Rules and regulations. All power plant design,regardless of the type of power plant, must be in accordancewith the rules and regulations which havebeen established by Federal, state and local governmentalbodies.b. Extraordinary design features. To meet variousenvironmental regulations, it is often necessaryto utilize design features that will greatly increasethe cost of the power plant without increasing its efficiency.For example, the cost of the pollution controlequipment that will be required for each site underconsideration is one such item which must becarefully evaluated.2-3. Water supplya. General requirements. Water supply will beadequate to meet present and future plant requirements.The supply maybe available from a local municipalor privately owned system, or it may be necessaryto 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 systemis from water wells, a study to determine watertable information and well drawdown will be required.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 determined:(1) The limitations established by the appropriateregulatory bodies which must be met to obtaina permit required to discharge heated water tothe source.(2) Maximum allowable temperature rise permissibleas compared to system design parameters.If system design temperature rise exceeds permissiblerise, 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 allowabletemperature, a supplemental cooling systemmust be added. It is possible to meet the conditionsof (2) above and not meet the conditions in this subparagraph.(4) If extensive or repetitive dredging of waterwaywill be necessary for plant operations.(5) The historical maximum and minimumwater level and flow readings. Check to see that adequatewater supply is available at minimum flowand if site will flood at high level.2-4. Fuel supplySite selection will take into consideration fuel storageand the ingress and egress of fuel delivery equipment.2-5. Physical characteristicsSelection of the site will be based on the availabilityof usable land for the plant, including yard structures,fuel handling facilities, and any future expansion.Other considerations that will be taken into accountin 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 centeras environmental conditions permit.2-6. EconomicsWhere the choice of several sites exists, the final selectionwill be based on economics and engineeringstudies.2-1.

TM 5-811-6Section Il. CIVIL FACILITIES, BUILDINGS, SAFETY, AND SECURITY2-7. 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 ClassificationSystem, and penetration data (blow count). Thesoils report will include recommendations as to typeof foundations for various purposes; excavation, dewateringand fill procedures; and suitability of onsitematerial for fill and earthen dikes including dataon soft and organic materials, rock and other pertinentinformation as applicable.2-8. Site developmenta. Grading and drainage.(1) Basic criteria. Determination of final gradingand 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 complex.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 excessfill material to offsite disposal and replacementwith expensive new material.(2) Drainage. Storm water drainage will beevaluated based on rainfall intensities, runoff characteristicsof soil, facilities for receiving stormwater discharge, and local regulations. Storm waterdrains or systems will not be integrated with sanitarydrains 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, riprapand retaining walls.

b. Roadways.(1) Basic roadway requirements. Layout ofplant roadways will be based on volume and type oftraffic, speed, and traffic patterns. Type of traffic orvehicle functions for power plants can be categorizedas 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 categoriesdescribed above will govern most roadway design,particularly if the plant is coal fired. Roadwaymaterial and thickness will be based on economicevaluations of feasible alternatives. Vehicular parkingfor plant personnel and visitors will be located inareas that will not interfere with the safe operationof the plant. Turning radii will be adequate to handleall 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 handlefuel supplies and material and equipment deliveriesduring construction or plant expansion, the designwill be in accordance with American RailwayEngineering Association standards. If coal is thefuel, spur layout will accommodate coal handling facilitiesincluding a storage track for empty cars. Ifliquid fuel is to be handled, unloading pumps andsteam connections for tank car heaters may be requiredin frigid climates.2-9. Buildingsa. Size and arrangement.(1) Steam plant. Main building size and arrangementdepend on the selected plant equipmentand facilities including whether steam generatorsare indoor or outdoor type; coal bunker or silo arrangement;source of cooling water supply relativeto the plant; the relationship of the switchyard tothe plant; provisions for future expansion; and ,aesthetic and environmental considerations. Generally,the main building will consist of a turbine baywith traveling crane; an auxiliary bay for feedwaterheaters, pumps, and switchgear; a steam generator

bay (or firing aisle for semi-outdoor units); and generalspaces 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 protected,walk-in enclosure) although this arrangementpresents special maintenance problems. If incorporated,the elevator will have access to the high-2-2TM 5-811-6est operating level of the steam generator (drum levels).(2) Diesel plant. The requirements for a buildinghousing a diesel generator plant are the same asfor a steam turbine plant except that a steam generatorbay is not required.b. Architectural treatment.(1) The architectural treatment will be developedto harmonize with the site conditions, bothnatural and manmade. Depending on location, theenvironmental compatibility y may be the determiningfactor. In other cases the climate or user preference,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, frequentlycombined with desert conditions giving riseto heavy dust and sand blasting action, indoor constructionwith pressurized ventilation will be requirednot only for the main building but also, generally,for the switchyard. Gas enclosed switchyardinstallations may be considered for such circumstancesin lieu of that required above.(3) Control rooms, offices, locker rooms, andsome out-buildings will be enclosed regardless of enclosureselected 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 controlsfor 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 conventional

structural steel for the main power stationbuilding and support of boiler. The pedestal for supportingthe turbine generator (and turbine drivenboiler feed pump if utilized) will be of reinforced concrete.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 aestheticsand economics of the design.(3) Interior walls. Concrete masonry blocks willbe used for interior walls; however, some specializedareas, 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 waterproofing.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 nonslipfinish.(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 exceptturbine generator floor 200 psf(c) Mezzanine, deaerator, andmiscellaneous operating floors 200 psf(d) Offices, laboratories, instrumentshops, and other lightly loaded areas 100 psfLive loads for actual design will be carefully reviewedfor 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 other

structures 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 generators,and other pertinent special loads prescribed bythe equipment function or requirements will be included.d. Foundation design.(1) Foundations will be designed to safely supportall structures, considering type of foundationand allowable bearing pressures. The two most commontypes of foundations are spread footings andpile type foundations, although “raft” type of otherspecial approaches may be utilized for unusual circumstances.(2) Pile type foundations require reinforcedconcrete pile caps and a system of reinforced concretebeams to tie the caps together. Pile load capabilitiesmay be developed either in friction or point2-3TM 5-811-6bearing. The allowable load on piles will be determinedby 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 perimeter.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 deflection.The limits of deflection will be selected toavoid values of natural frequency by at least 30 percentabove or 30 percent below operating speed.(4) Vibration mounts or “floating floor” foundationswhere equipment or equipment foundationinertia blocks are separated from the main buildingfloor by springs or precompressed material will generallynot be used in power plants except for ventilationfans 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 necessity.(5) The location of turbine generators, diesel enginesets, boiler feed pumps, draft fans, compressors,

and other high speed rotating equipment onelevated floors will be avoided because of the difficultyor impossibility of isolating equipment foundationsfrom the building structure.2-10. Safety.a. Introduction. The safety features described inthe 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 arrangedfor maintenance handling by the main turbineroom crane. Where this is not feasible, monorails,wheeled trucks, or portable A-frames shouldbe provided if disassembly of heavy pieces is requiredfor maintenance.(2) Safety guards will be provided on movingparts of all equipment.(3) All valves, specialties, and devices needingmanipulation by operators will be accessible withoutladders, and preferably without using chainwheels. This can be achieved by careful piping design,but some access platforms or remote mechanicaloperators may be necessary.(4) Impact type handwheels will be used forhigh pressure valves and all large valves.(5) Valve centers will be mounted approximately7 feet above floors and platforms so that risingstems and bottom rims of handwheels will not be ahazard.(6) Stairs with conventional riser-tread proportionswill 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 providedin 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 constructionin a climate subject to freezing weather,weather protection will be provided for criticaloperating and maintenance areas such as the firingaisle, boiler steam drum ends and soot blower locations.(14) Adequate illumination will be providedthroughout the plant. Illumination will comply withrequirements of the Illuminating Engineers Society(IES) Lighting Handbook, as implemented by DOD4270.1-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 accumulationof 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 turbineor engine room and the boiler feed pump area.Evaporative cooling will be considered in low humidityareas. 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 removehydrogen emitted by batteries as covered inTM 5-811-2/AFM 88-9, Chap. 2.(17) Noise level will be reduced to at least the2-4TM 5-811-6recommended maximum levels of OSHA. Use of fansilencers, compressor silencers, mufflers on internalcombustion engines, and acoustical material is requiredas 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 restfulexcept where danger must be highlighted withspecial bright primary colors.(20) Each equipment item will be clearly labelledin block letters identifying it both by equipment item number and name. A complete, coordinatedsystem of pipe markers will be used for identificationof each separate cycle and power plant service

system. All switches, controls, and devices on allcontrol panels will be labelled using the identicalnames shown on equipment or remote devices beingcontrolled.2-5

TM 5-811-6CHAPTER 3STEAM TURBINE POWER PLANT DESIGNSection 1. TYPICAL PLANTS AND CYCLES3-1. Introductiona. Definition. The cycle of a steam power plant isthe group of interconnected major equipment componentsselected for optimum thermodynamic characteristics,including pressure, temperatures and capacities,and integrated into a practical arrangementto serve the electrical (and sometimes by-productsteam) requirements of a particular project. Selectionof the optimum cycle depends upon plantsize, cost of money, fuel costs, non-fuel operatingcosts, and maintenance costs.b. Steam conditions. Typical cycles for the probablesize and type of steam power plants at Army establishmentswill 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 generatorsof less than 50 MW and, hence, is not applicablein this manual.c. Steam turbine prime movers. The steam turbineprime 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 extractionopenings.d. Back pressure turbines. Back pressure turbineunits usually exhaust at pressures between 250 psigand 15 psig with one or two controlled or uncontrolledextractions. However, there is a significantprice difference between controlled and uncontrolledextraction turbines, the former being more expensive.Controlled extraction is normally appliedwhere the bleed steam is exported to process or districtheat users.e. Condensing turbines. Condensing units exhaustat pressures between 1 inch of mercury absolute(Hga) and 5 inches Hga, with up to two controlled,or up to five uncontrolled, extractions.

3-2. Plant function and purposea. Integration into general planning. Generalplant design parameters will be in accordance withoverall criteria established in the feasibility study orplanning criteria on which the technical and economicfeasibility is based. The sizes and characteristicsof the loads to be supplied by the power plant, includingpeak loads, load factors, allowances for futuregrowth, 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 dependon 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 controlledextraction/condensing cycles are attractiveand applicable to a cogeneration plant, which is definedas 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 extractionsare 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 condensingcycles 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 andeconomy of a steam power cycle are the principal designcriteria for plant selection and design. In general,better efficiency, or lower heat rate, is accompaniedby higher costs for initial investment, operationand maintenance. However, more efficientcycles are more complex and may be less reliable perunit of capacity or investment cost than simpler and3-1TM 5-611-6

NAVFAC DM3Figure 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 loweringback pressure further will commence to decreaseefficiency because the incremental exhaust loss effectis greater than the incremental increase in availableenergy.(3) The use of stage or regenerative feedwatercycles improves heat rates, with greater improvementcorresponding to larger numbers of such heaters.In a regenerative cycle, there is also a thermodynamiccrossover point where lowering of an extractionpressure 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 heatingwhich may be economically added to the cycle.This occurs when additional cycle efficiency no longerjustifies 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-3-2pressed 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 seldomused to express overall plant or cycle performance,although efficiencies of individual components,such as pumps or steam generators, are commonlyused.(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 and

omits steam generator efficiency.(3) For mechanical drive turbines, heat ratesare sometimes expressed in Btu per hp-hour, excludinglosses 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 turbineis defined as the heat consumption of the turbinein terms of “heat energy in steam” supplied bythe steam generator, minus the “heat in the feedwater”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 systems,but excludes boiler inefficiencies and pumpinglosses and loads. The turbine heat rate is useful forTM 5-811-6performing engineering and economic comparisonsof various turbine designs. Table 3-1 provides theoreticalturbine steam rates for typical steam throttleconditions. Actual steam rates are obtained by dividingthe theoretical steam rate by the turbine efficiency.Typical turbine efficiencies are provided onFigure 3-2.ASR =where: ASR = actual steam rate (lb/kWh)TSR = theoretical steam rate (l/kWh)nt = turbine efficiencyTurbine heat rate can be obtained by multiplyingthe actual steam rate by the enthalpy change acrossthe turbine (throttle enthalpy - extraction or exhaustenthalpy).Ct = ASR(hl – h2)where = turbine heat rate (Btu/kWh)ASR = actual steam rate lb/kWh)h1 = throttle enthalpyh1 = extraction or exhaust enthalpyTSR

’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, principallythe inefficiencies of the steam generator and pipingsystems; cycle auxiliary losses inherent in power requiredfor pumps and fans; and related energy uses

such as for soot blowing, air compression, and similarservices.(3) Both turbine and plant heat rates, as above,are usually based on calculations of cycle performanceat 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 deteriorationlosses, and related items. The gradualand inevitable deterioration of equipment, and failureto operate at optimum conditions, are reflectedin plant operating heat rate data.d. Plant economy calculations. Calculations, estimates,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 developand optimize a cycle heat balance during the conceptualor preliminary design phase of the project.The heat balance depicts, on a simplified flow diagramof the cycle, all significant fluid mass flowrates, fluid pressures and temperatures, fluid enthalpies,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 developedwhich 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 generallyaccepted method of defining the energy efficiencyor heat rates of cogeneration cycles. Variousmethods are used, and any rational method is valid.The difference in value (per Btu) between prime energy(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, cogenerationnormally describes an arrangementwhereby high pressure steam is passed through a

turbine prime mover to produce electrical power,and thence from the turbine exhaust (or extraction)opening to a lower pressure steam (or heat) distributionsystem for general heating, refrigeration, orprocess use.b. Common medium. Steam power cycles are particularlyapplicable to cogeneration situations becausethe actual cycle medium, steam, is also a convenientmedium for area distribution of heat.(1) The choice of the steam distribution pressurewill be a balance between the costs of distributionwhich 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 low3-3TM 5-811-63-4steam 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 applicableas 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 extraction)steam from a cogeneration plant can beutilized for heating, refrigeration, or process purposesin reasonable phase with the required electricpower load, there is a marked economy of fuel energybecause the major condensing loss of the conventionalsteam 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 Rankinecycle plants and about 25 to 30 percent forsmall Rankine cycle systems.d. Cycle types. The two major steam power cogenerationcycles, 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 extracted)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 condenser

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 condensing-controlled extraction steam turbine primemovers as shown in Figure 3-3 may be applicable.Such a turbine is arranged to carry a specified electricalcapacity either by a simple condensing cycleor a combination of extraction and condensing.While very flexible, the extraction machine is relativelycomplicated, requires complete condensingand heat rejection equipment, and must always passa critical minimum flow of steam to its condenser tocool the low pressure buckets...NAVFAC DM3 Figure 3-3. Typical condensing-controlled extinction cycle.3-5TM 5-811-6e. Criteria for cogeneration. For minimum economicfeasibility, 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 cogeneration,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 turbineis 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 heat

distribution 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 betweendistribution system and heat exchangercosts, and power cycle effectiveness will be optimized.3-5. Selection of cycle steam conditionsa. Balanced costs and economy. For a new or isolatedplant, the choice of initial steam conditionsshould be a balance between enhanced operatingeconomy at higher pressures and temperatures, andgenerally lower first costs and less difficult operationat 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 considerationwill 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 serviceonly, steps will be taken in the project design forprotection against internal corrosion.c. Special considerations. Where the special circumstancesof the establishment to be served aresignificant factors in power cycle selection, the followingconsiderations may apply:(1) Electrical isolation. Where the proposedplant is not to be interconnected with any local electricutility 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, maintenanceservices, and operating supplies may requirespecial consideration of simplified cycles, redundantcapacity and equipment, and highest practicalreliability. Special maintenance tools and facilitiesmay be required, the cost of which would be affectedby the basic cycle design.(3) Weather conditions. Plants to be installedunder extreme weather conditions will require specialconsideration of weather protection, reliability,and redundancy. Heat rejection requires special designconsideration in either very hot or very cold

weather conditions. For arctic weather conditions,circulating hot water for the heat distribution mediumhas many advantages over steam, and the use ofan antifreeze solution in lieu of pure water as a distributionmedium should receive consideration.3-6. Cycle equipmenta. General requirements. In addition to the primemovers, alternators, and steam generators, a completepower plant cycle includes a number of secondaryelements which affect the economy and performanceof the plant.b. Major equipment. Refer to other parts of thismanual 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 arrangementin the turbine generator bay while thelarger utility units are very long and require end-toendarrangement 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 5-811-6U. S. Army Corps of EngineersFigure 3-4. Typical small 2-unit powerplant “A”.3-7TM 5-811-6a

3-8TM 5-811-6Section 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 condition.Units can also be classified by type of draft, bymethod of assembly, by degree of weather protectionand by load factor application.(1) Fuel, general. Type of fuel has a major impacton the general plant design in addition to thesteam generator. Fuel selection may be dictated byconsiderations of policy and external circumstances3-8. Steam generator conventionaltypes and characteristicsa. Introduction. Number, size, and outlet steaming

conditions of the steam generators will be as determinedin planning studies and confirmed in the finalproject 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 . 5517.55811NOTE:US.DIMENSIONS IN TABLE ARE APPLICABLE TO FIG. 3-5Army Corps of EngineersFigure 3-6. Critical turbine room bay and power plant “B” dimensions.3-9TM 5-811-6unrelated 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: heatingvalue, ash content, ash fusion temperature, friability,grindability, moisture, and volatile contentas shown in Table 3-2. For spreader stoker firing,the size, gradation, or mixture of particle sizes affectTable 3-2.Characteristicstoker and grate selection, performance, and maintenance.For pulverized coal firing, grindability is amajor consideration, and moisture content beforeand 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 largersteam generators will result in lower first costs

Fuel Characteristcs.EffectsCoalHeat 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.OilHeat 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.GasHeat balance.Pressure, firing, fuel cost.Metering.Heat balance, fuel cost.Insignificant.NAVFAC DM33-10TM 5-811-6per unit of capacity and may permit the use of designfeatures and arrangements not available onsmaller units. Larger units are inherently more efficient,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 heavierthe pressure parts, and the higher the steam temperaturethe greater the superheater surface areaand the more costly the tube material. In addition tothis, however, boiler natural circulation problems increasewith higher pressures because the densitiesof the saturated water and steam approach each other.

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 electricgenerating 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 underpressure to the burners (or under the grate) andone or more induced draft fans to carry the hot combustiongases from the furnace to the atmosphere; aslightly negative pressure is maintained in the furnaceby the induced draft fans so that any gas leakagewill be into rather than out of the furnace. Naturaldraft 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 specifiedfor steam electric generating stations.(6) Method of assembly. A major division ofsteam generators is made between packaged or factoryassembled 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 generatorsare 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 installation.An outdoor installation is usually less expensivein first cost which permits a reduced generalbuilding construction costs. Aesthetic, environmental,or weather conditions may require indoor installation,although outdoors units have been used SUCcessfullyin a variety of cold or otherwise hostile climates.In climates subject to cold weather, 30 “F. for7 continuous days, outdoor units will require electricallyor 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 convenience

and 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 efficiencies,and more conservative parameters for furnacevolume, heat transfer surface, and numbersand types of auxiliaries. Plants with load factorsless than 50% will be served by relatively less expensive,smaller and less durable equipment.3-9. Other steam generator characteristicsa. 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 manufacturer’sdesign some power boilers are designed todeliver superheated steam because of the requirementsof 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 superheatsurfaces will provide a reasonable superheatcharacteristic. With high ‘pressure - high temperatureturbine generators, it is usually desirable toprovide superheat controls to obtain a flat characteristicdown 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 designedto obtain superheat control by means of tiltingburners which change the heat absorption patternin the steam generator, although supplementaryattemperation is also provided with such a controlsystem.c. Balanced heating surface and volumetric designparameters. Steam generator design requiresadequate and reasonable amounts of heating surface3-11TM 5-811-6and 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 radiantsurface and boiler convection surface. Balanceddesign will provide adequate but not excessive

heat flux through such surfaces to insure effectivecirculation, steam generation and efficiency.(2) Superheater surface. For the required heattransfer, temperature control and protection of metalparts, the superheater must be designed for a balancebetween 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 certainadvantages of cost, simplicity, and arrangement,but are vulnerable to damage on startup.Therefore, units requiring frequent cycles of shutdownand startup operations should be consideredfor fully drainable superheaters. With some boilerdesigns this may not be possible.(3) Furnace volume. For a given steam generatorcapacity 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, particularlywith pulverized coal fuel, can be controlled orprevented with increased furnace size.(4) General criteria. Steam generator designwill specify conservative lower limits of total heatingsurface, furnace wall surface and furnace volume,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 specificationsset minimum requirements for Btu heat releaseper 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 designconsiderations. 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 orsteam 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/extractionunit are installed together, overall economy canbe enhanced by a header (or parallel) boiler arrangement.3-10. Steam generator special typesa. Circulation. Water tube boilers will be specifiedto be of natural circulation. The exception to thisrule is for wasteheat boilers which frequently are a . .special type of extended surface heat exchanger designedfor forced circulation.b. Fludized bed combustion. The fluidized bedboiler has the ability to produce steam in an environmentallyaccepted 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 conventionalsteam generator which includes radiant andconvection boiler heat transfer surfaces plus heat recoveryequipment, draft fans, and the usual array ofsteam generator auxiliaries. A typical fluidized bedboiler 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 combustionair at the burner opening. Atomizing methodsare 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 consumesa portion of the boiler steam output and addsmoisture to the furnace gases. Generally, steamatomization will be used when makeup water is relativelyinexpensive, and for smaller, lower pressureplants. Air atomization will be used for plants burninglight liquid fuels, or when steam reacts adverselywith the fuel, i.e., high sulfur oils.(2) Gas and coal burners. Natural gas or pulverizedcoal will be delivered to the burner for mixingwith combustion air supply at the burner opening.Pulverized coal will be delivered by heated, pressurizedprimary air.(3) Burner accessories. Oil, gas and pulverized3-12

coal burners will be equipped with adjustable airguide registers designed to control and shape the airflow into the furnace, Some burner designs also providefor automatic insertion and withdrawal of varyingsize oil burner nozzles as load and operating conditionsrequire.(4) Number of burners. The number of burnersrequired is a function both of load requirements andboiler manufacturer design. For the former, the individualburner turndown ratios per burner are providedin Table 3-3. Turndown ratios in excess ofthose listed can be achieved through the use of multipleburners. Manufacturer design limits capacityof each burner to that compatible with furnace flameand gas flow patterns, exposure and damage toSTEAM OUTLET TOSUPERHEATER IN BEDTM 5-811-6heating 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 conditionswhich 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 essentialpart 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-SPREAOERU.S. Army Corps of EngineersFigure 3-7. Fluidized bed combustion boiler.3-13TM 5-811-6and classify the coal fuel to specific particle sizes forrapid and efficient burning. Reliable and safe pulverizingequipment is essential for steam generator operation.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 perhaps

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 suspensionand 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 responsiveto load changes because a large proportionof the fuel burns on the grate for long time periods(minutes). Where the plant demand is expected to includesudden load changes, pulverized coal feedersare to be used.(2) Grate operation requires close and skillfuloperator attention, and overall plant performance issensitive to fuel sizing and operator experience.Grates for stoker fired units occupy a large part ofthe furnace floor and must be integrated with ash removaland handling systems. A high proportion ofstoker ash must be removed from the grates in awide range of particle sizes and characteristics althoughsome 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 particulate,(3) Discharged ash is allowed to COOl in the ashhopper 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 RatioNATURAL GMSpud or Ring TypeHEAVY FUEL OILSteam AtomizingMechanical AtomizingCOALPulverizedSpreader-StokerFluidized Bed (single bed)5:1 to 10:15:1 to 10:13:1 to 10:13:12:1 to 3:12:1 to 3:1U.S. Army Corps of Engineers

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 excessair 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 ability 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 effectiveness.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 designedfor 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 designedwith provision for expansion, support, corro-TM 5-811-6sion resistance and overall gas tightness. Adequatespace and weight capacity will be allowed in overallplant arrangement to avoid awkward, noisy or marginalfan, duct and flue systems. Final steam generatordesign 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 purposeswill 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 recoveryequipment of two principal types: air preheaterand economizers.(1) Efficiency effects. Both principal types of

heat 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, complexityand operational skills required, which will be balancedby the plant designer against the life cyclefuel savings.(2) Air preheater. Simple tubular surfaceheaters will be specified for smaller units and the regenerativetype heater for larger boilers. To mini-3-15TM 5-811-6mize 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 preheater.Steam coil air heaters will be installed tomaintain certain minimum inlet air (and metal) temperaturesand thus protect the main preheater fromcorrosion at low loads or low ambient air temperatures.Figure 3-9 illustrates the usual range of minimummetal temperatures for heat recovery equipment.(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 turbinecycle feedwater stage heating.f. Stacks.(1) Delivery of flue gases to the atmospherethrough a flue gas stack or chimney will be provided.(2) Stacks and chimneys will be designed to dischargetheir gases without adverse local effects. Dispersionpatterns and considerations will be treatedduring design.(3) Stacks and chimneys will be sized with dueregard to natural draft and stack friction with290NAVFAC DM3Figure 3-9. Minimum metal temperatures for boiler heatrecovery equipment.height sometimes limited by aesthetic or other noneconomicconsiderations. Draft is a function of density difference between the hot stack gases and ambientair, 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 are

treated (and cooled) in a flue gas desulfurizationscrubber prior to entering the stack to add buoyancyand prevent their settling to the ground afterejection to the atmosphere. Insure that downwashdue to wind and building effects does not drive theflue gas to the ground.g. Flue gas cleanup. The requirements for flue gascleanup will be determined during design.(1) Design considerations. The extent and natureof the air pollution problem will be analyzedprior to specifying the environmental control systemfor the steam generator. The system will meetall applicable requirements, and the application willbe the most economically feasible method of accomplishment.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 accommodatefuture additions or modifications at minimum cost.Questions concerning unusual problems, unique applacationsor marginal and future requirements willbe directed to the design agency having jurisdictionover the project. Table 3-4 shows the emission levelsallowable under the National Ambient AirQuality Standards.(2) Particulate control. Removal of flue gas particulatematerial is broadly divided into mechanicaldust collectors, electrostatic precipitators, bag filters,and gas scrubbing systems. For power plantsof the size range here considered estimated uncontrolledemission levels of various pollutants areshown in Table 3-5. Environmental regulations requirecontrol of particulate, sulfur oxides and nitrogenoxides. 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 detailsof this equipment and related computationalrequirements and design criteria.(a) Mechanical collectors. For oil fired steamgenerators with output steaming capacities lessthan 200,000 pounds per hour, mechanical (centrifugal)type dust collectors may be effective and economicaldepending on the applicable emission stand-3-16ards. 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 environmentalstandards must be carefully matched, and

ultimate 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 generatorTM 5-811-6efficiency slightly but also will increase collectordust loading and carryover. Ultimate collecteddust material must be handled and disposed of systematicallyto avoid objectionable environmental effects.(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-3-17PollutantParticulateSulfur OxidesNitrogen OxidesCOAL FIRED(Lb of Pollutant/TonTable3-5. Uncontrolled Emissions.OIL FIREDof Coal) (Lb of Pollutant/1000 Gal)Pulverized Stokers orNATURAL 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 Agency2-650-705090-95 Industrial andutility boilerParticulate control.U.S. Army Corps of EngineersTable 3-2! Characteristics of Scrubbers for Particulate Control.ParticleCollection Water UsageEfficiency Per 1000 Gal/Min80 3-5InternalVelocityFt/SecPressure Drop

In. H O3-8Gas FlowScrubber Type Energy Type Ft /MinCentrifugal Low EnergyScrubber1,000-20,00050-150Impingement &EntrainmentLow Energy 4-20 500-50,00050-150 60-90 10-40Venturi High Energy 4-200 200-150,000200-600 95-99 5-7Ejector Venturi High Energy 10-50 500- 200-500 90-98 70-14510,000U.S. Army Corps of EngineersTypeHot ESPCold ESPWet ESPTable 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-cm600+ Greater Than1 01 2

300 Less Than1 01 0

300- Greater Than1 012 b e l o w1 04

U.S. Army Corps of EngineersPressureGas DropFlow I n . o fF t / M i n Water100,000+ Less Than1"Table 3-9. Characteristics of Baghouses for Particulate Control.Pressure Loss Filter Ratio(Inches of (cfm/ftSystem Type Water) Efficiency Cloth Type Cloth Area) Recommended ApplicationShaker 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 temperature

collection (incinerator flyash)with glass bags.Pulse JetReverse JetEnvelope3-63-83-6U.S. Army Corps of Engineers99+% Felted99+% Felted99+% Woven4-2010-301-5Efficient 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 toExistingInstallationsYeaPressure Drop(Inches of Water)SO Removal Recovery andRegenerationNo Recoveryof LimestoneNo Recoveryof LimeNo Recoveryof LimeRecovery of MgOand Sulfuric AcidRecovery of NaS03

OperationalEfficiency (%) Reliability30-40%System TypeHighHighLowLowUnknownUnknownUnknownUnknown

1) Limestone BoilerInjection TypeLess Than 6“Greater Than 6“Greater Than 6“Greater Than 6“Greater Than 6“2) Limestone, Srubber YeaInjection Type30-40%3) Lime, Scrubber, YeaInjection Type90%+4) Magnesium Oxide Yea5) Wellman-Lord 90%+and Elemental Sulfur6) CatalyticoxidationRecovery of 80%H2S04

85% May be as high as 24” NoTray Tower PressureDrop 1.6-2.0 in.H2O/tray, w/Venturiadd 10-14 in. H2OLittle Recoveryof Sodium Carbonate7) Single Alkali YeaSystems90%+8) Dual Alkali 90-95%+ Regeneration of YeaSodium Hydroxideand Sodium SulfitesU.S. Army Corps of EngineersgTabble 3-11. Techniques for Nitrogen Oxide Control.TechniqueLoad ReductionLow Excess Air FiringTwo Stage ConbustionCoalOilGasPotentialOff-Stoichiometric CombustionCoalReduced Combustion AirPreheatNO Reduction (%)Flue Gas Recirculation15 to 40

3040504510-5020-50U.S. Army Corps of EngineersAdvantages DisadvantagesEasily 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 particulateemissions.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 5-811-6ages of particulate removal can be attained (99 percent,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 preheater.Hot precipitators are more expensive becauseof the larger volume of gas to be handled andtemperature influence on materials. But they aresometimes necessary for low sulfur fuels where cold

precipitators 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 particles,and at relatively low flue gas temperatures.They may be used to improve or upgrade other particulatecollection systems such as centrifugal collectors.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 oxidesof sulfur (SO2 and SO3). Many flue gas desulfuriztion(FGD) scrubbing systems to control SO2 andSO3stack emission have been installed and operated,with wide variations in effectiveness, reliability,longevity and cost. For small or medium sizedpower plants, FGD systems should be avoided ifpossible by the use of low sulfur fuel. If the parametersof the project indicate that a FGD system is required,adequate allowances for redundancy, capitalcost, operating costs, space, and environmental impactwill 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 sorbentsfor 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 continuesto 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 bycompressed 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 hydroxideof the slurry to form calcium sulfite. Evaporationof the water in the slurry droplets occurs simultaneouslywith the reaction. The dry flue gasthen travels to a bag filter system and then to the

boiler 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 percent.(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) conditions.(4) Waste removal. Flue gas cleanup systemsusually produce substantial quantities of wasteproducts, often much greater in mass than the substancesactually removed from the exit gases. Designand 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 feedwaterpiping, 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 preheaterheating surfaces is required to maintain performanceand efficiency. Soot blower systems,steam or air operated, will be provided for this purpose.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.3-25k

TM 5-811-6Section Ill. FUEL HANDLING AND STORAGE SYSTEMS3-13. Introductiona. Purpose. Figure 3-10 is a block diagram illustratingthe various steps and equipment required

for 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 handlingsystemThe usual power plant fuel oil storage and handlingsystem includes:a. Unloading and storage.(1) Unloading pumps will be supplied, as requiredfor the type of delivery system used, as partof the power plant facilities. Time for unloading willbe analyzed and unloading pump(s) optimized forthe 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 belowthe 120 to 150ºF. range.(2) Storage of the fuel oil will be in two tanks soas to provide more versatility for tank cleanout inspectionand 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 whetherFigure 3-10. Coal handling system diagram.3-26backup power is available from other sources mayresult in additional storage requirements. Space forfuture tanks will be allocated where additional boilersare planned, but storage capacity will not be providedinitially.(3) Storage tank(s) for heavy oils will be heatedwith a suction type heater, a continuous coil extendingover 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 oilfrom bulk storage to the burner pumps will be provided.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 friction,

control valves, heater pressure drops, andburners. A reasonable selection would be one pumpper boiler with a common spare if the system is designedfor 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 reliaabilityis required, a spare pump driven by a steamturbine with gear reducer will be used. For “blackstarts, ” or where a steam turbine may be inconvenient,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 maintainpressure 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 successfullylit 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 requirementsof the burner.d. Instruments and control. Instruments andTM 5-811-6controls include combustion controls, burner managementsystem, control valves and shut off valves.3-15. Coal handling and storage systemsa. Available systems. The following principal systemswill be used as appropriate for handling, storingand 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. Reclaimfrom dead storage will be by means of bulldozer

to track/truck hopper.(2) Intermediate system; coal purchased sizedand washed. This will be similar to the system describedin (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 conveyorwill be used. If mine run, uncrushed coalproves economical, a crusher with feeder will be installedin association with the track/truck hopper.(4) Larger systems, usually with mine run coal.A larger system will include track or truck (or combinedtrack/truck) unloading hopper, separate deadstorage reclaim hoppers, inclined belt conveyorswith appropriate feeders, transfer towers, vibratingscreens, magnetic separators, crusher(s), overbunkerconveyor(s) with automatic tripper, weighingequipment, sampling equipment, silos, dust collectingsystem(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 unloadedor 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 handlingcapacity should be calculated using the worst(lowest heating value) coal which may be burned inthe future and a maximum steam capacity boiler efficiencyat least 3 percent less than guaranteed byboiler manufacturer.3-27TM 5-811-6c. 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 stokerfired plants, grade mounted silo storage will be specifiedwith 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 atypical bucket elevator grade mounted silo arrangementfor 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 bechain and bucket type. For relatively small installationsthe 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 byenvironmental considerations, skip hoists will notbe specified.(3) Belt conveyors. Belt conveyors will be selectedfor speeds not in excess of 500 to 550 feet perminute. 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 intermediatehopper 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 vibrating

type will be used for larger systems.(5) Miscellaneous. The following items are requiredas 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 compensatedload 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 installationsthe crusher will be preceded by vibrating(scalping) screens for separating out and by-passingfines around the crusher.(d) Traveling tripper for overbunker conveyorserving a number of bunkers in series.(e) One or more coal samplers to check “as re-TM 5-811-6ceived” 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 providedat all points subject to coal stoppage or hangup.(g) Car shakeout and a thaw shed for looseningfrozen coal from railroad cars.(h) Dust control systems as required throughoutthe coal handling areas. All handling equipment—hoppers, conveyors and galleries-will be enclosedin dust tight casings or building shells andprovided with negative pressure ventilation completewith heated air supply, exhaust blowers, separators,and bag filters for removing dust from exhaustedair. 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 locatedoutdoors or in unheated closures as providedfor dust suppression or fire protection systems.(k) A vacuum cleaning system for maintenanceof coal handling systems having galleries andequipment enclosures.(l) System of controls for sequencing andmonitoring entire coal handling system.Section IV. ASH HANDLING SYSTEMS3-16. Introductiona. 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 material,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 oftenhave a high percentage of unburned carbon content,particularly in the case of spreader stoker firedboilers; this heavier material may be reinfected intothe furnace to reduce unburned carbon losses and increaseefficiency, although this procedure does increasethe dust loading on the collection equipmentdownstream of the last hopper from which such materialis 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 atmosphere.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 transferto 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 is3-29TM 5-811-6adequate and environmentally acceptable for thispurpose.(2) Collect fly ash and to convey it dry to temporaryor permanent storage as described above forbottom ash. Fly ash, being very light, will be wetted

and 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 notrequire 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 havingsteaming rates of 200,000 pounds per hour orless. The fly ash from the gas passage and mechanicalcollector hoppers can usually be handled manuallybecause of the small amount of fly ash (soot) collected.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 handling.Each hopper will be selected so that it need notbe evacuated more than once every few days. If boilersize and estimated soot/ash loading is such thatmanual handling becomes burdensome, a vacuum orhydraulic system as described below should be considered.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 removingash to facilitate operating with a minimumweekend crew.(2) For a typical military power plant, the mosteconomical selection for both bottom and fly ash disposalis a vacuum type dry system with a steam jetor mechanical(Figure 3-12).exhauster for creating the vacuumThis typical plant would probablyhave a traveling grate spreader stoker, a mechanicalcollector, and a baghouse; in all likelihood, no on-siteash disposal area would be available.(3) The ash system for the typical plant will includethe 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 incorporatedinto the outlet sections of the hopper.(b) Gas passage fly ash hoppers as requiredby the boiler design for boiler proper, economizer,and air heater.(c) Collector fly ash hoppers for the mechanicalcollector 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 mechanicalexhauster.(c) Primary and secondary mechanical (centrifugal)separators and baghouse filter are used toclean the dust out of the ash handling system exhaustprior to discharge to the atmosphere. Thisequipment is mounted on top of the silo.(d) Reinforced concrete or vitrified tile overheadsilo with separator and air lock for loading silowith 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 initiationof such a system starts the exhauster and thenremoves bottom and fly ash from each separator collectionpoint in a predetermined sequence. Ash unloadingto vehicles is separately controlled.Section V. TURBINES AND AUXILIARY SYSTEMS3-18. 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 generbinegenerator set. For detailed discussion of the ators for military installations will fall into the fol-3-30Figure 3-12. Pneumatic ash handling systems—variations.TM 5-811-6lowing size ranges:

(1) Small turbine generators. From 500 to about2500 kW rated capacity, turbine generators willusually be single stage, geared units without extractionopenings 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 turningat 3600 rpm, or high speed turbines with gear reducersmay also be used in this size range. Units areequipped with either uncontrolled or controlled (automatic)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 uncontrolledextraction openings, or one or two automaticextraction openings. These turbines wouldhave initial steam conditions from 600 psig to 1250psig, and 750°F to 900°F. Typical initial steam conditionswould 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 requiredfor feedwater heating. In cogeneration applicationswhich include the provision of process orheating steam along with power generation, one automaticextraction 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 reductiongear, 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 separatemounting sole plates for installation in concrete

pedestal for larger units.(5) Insulation and jacketing, instruments, turninggear and special tools.3-19. GeneratorsFor purposes of this section, it is noted that the generatormust be mechanically compatible with thedriving turbine, coupling, lubrication system, andvibration characteristics (see Chapter 4 for generatordetails).3-20. Turbine featuresa. General. Turbine construction may be generallyclassified as high or low pressure, single or multistage,back pressure on condensing, direct drive orgear reducer drive, and for electric generator or formechanical drive service.(1) Shell pressures. High or low pressure constructionrefers 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 stationaryvanes between wheels to improve efficiency.As casing pressure of single stage turbines are equalto exhaust pressures, the design of seals and bearingsis relatively simple.(3) Back pressure vs. condensing. Selection of aback pressure or a condensing turbine is dependenton the plant function and cycle parameters. (SeeChapter 3, Section I for discussion of cycles.) Condensingmachines are larger and more complex withhigh pressure and vacuum sealing provisions, steamcondensers, stage feedwater heating, extensive lubeoil systems and valve gear, and related auxiliary features.(4) Direct drive vs. geared sets. Direct drive turbinesgenerators turn the turbine shaft at generatorspeed. Units 2500 kW and larger are normally directconnected. Small, and especially single stage, turbinesmay be gear driven for compactness and forsingle stage economy. Gear reducers add complexityand energy losses to the turbine and should beused only after careful consideration of overall economyand 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 are

called “mechanical drive” turbines. Mechanicaldrive turbines are usually variable speed units withspecial governing equipment to adapt to best economybalance between driver (turbine) and driven machine.Small auxiliary turbines for cycle pumps,3-32fans, 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 dependingon the application.b. Arrangement. Turbine generators are horizontalshaft type with horizontally split casings. Relativelysmall 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 enclosurebut 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 preventionof expansion damage are essential.(2) Foundations. Foundations and pedestals forturbine generators will be carefully designed to accommodateand protect the turbine generator, condenser,and associated equipment. Strength, mass,stiffness, and vibration characteristics must be considered.Most turbine generator pedestals in theUnited States are constructed of massive concrete.3-21. Governing and controla. Turbine generators speed/load control. Electricalgenerator output is in the form of synchronizedac electrical power, causing the generator and drivingturbine to rotate at exactly the same speed (orfrequency) as other synchronized generators connectedinto 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 pressureunits without automatic extraction will beequipped with mechanical-hydraulic governing. Forautomatic extraction units larger than 20,000 kW,

governing will be specified either with a mechanicalhydraulicor an electro-hydraulic system.b. Overspeed governors. All turbines require separatesafety or overspeed governing systems to insureinlet steam interruption if the machine exceedsa safe speed for any reason. The emergency governorcloses a specially designed stop valve which notonly shuts off steam flow but also trips various safetydevices to prevent overspeed by flash steam in-TM 5-811-6duction through the turbine bleed (extraction)points.c. Single and multi-valve arrangements. Whatevertype of governor is used, it will modulate theturbine inlet valves to regulate steam flow and turbineoutput. For machines expected to operate extensivelyat low or partial loads, multi-valve arrangementsimprove economy. Single valve turbines,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 andlarger, 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 periodafter shutdown in which the turbine cools down.The turbine cannot be restarted until it has completelycooled down without risk of damage to interstatepacking 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 startingand to automatically disengage when the turbinereaches a predetermined speed during startupwith steam. It is also arranged to automatically engagewhen the turbine has been shut down and deceleratedto a sufficiently slow speed. Indicatinglights will be provided to indicate the disengaged orengaged status of the turning gear and an interlock

provided to prevent the operation of the turninggear if the pressure in the turbine lubrication oil systemis below a predetermined safe setting.3-23. Lubrication systemsa. General. Every turbine and its driven machineor 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 typicalturbine generator, an integrated lube oil storagetank with built in normal and emergency pumps isusually provided. Oil cooling may be by means of an3-33TM 5-811-6external 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 turbinedrivenbackup pump will be specified to allow orderlyshutdown during normal startup and shutdownwhen the shaft driven pump cannot maintainpressure, or after main pump failure, or in the eventof failure of the power supply to the ac electric motordriven 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. Largerturbine generator units are sometimes equippedwith special off base lubrication systems to provideseparate, high quality filtering.3-24. Extraction featuresa. Uncontrolled extraction systems. Uncontrolledbleed or extraction openings are merely nozzles inthe turbine shell between stages through which relativelylimited 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 efficienciesand performance based on normal extractionpressures and regenerative feedwater heating calculations.Uncontrolled extraction opening pressureswill vary in proportion to turbine steam flow, andextracted steam will not be used or routed to anysubstantial uses except for feedwater heating.b. Automatic extraction. Controlled or automatic

extraction turbines are more elaborate and equippedwith variable internal orifices or valves to modulateinternal steam flows so as to maintain extractionpressures within specified ranges. Automatic extractionmachine governors provide automatic selfcontainedmodulation of the internal flow orifices orvalves, using hydraulic operators. Automatic extractiongoverning 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 similarsize, capacity and type; its selection and use requirecomprehensive planning studies and economicanalysis for justification. Sometimes the same objectivecan be achieved by selecting two units, one ofwhich is an uncontrolled extraction-condensing machineand the other a back pressure machine.3-25. Instruments and special toolsa. Operating instruments. Each turbine will beequipped with appropriate instruments and alarmsto monitor normal and abnormal operating conditionsincluding speed, vibration, shell and rotor expansions,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 relatedspecial items are required for organized and effectiveerection and maintenance.Section VI. CONDENSER AND CIRCULATING WATERSYSTEM3-26. Introductiona. Purpose.(1) The primary purpose of a condenser and circulatingwater 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 accomplishedin two steps. In the first step, the condenseris supplied with circulating water which serves as amedium for absorbing the latent heat in the condensingexhaust steam. The source of this circulatingwater can be a natural body of water such as an

ocean, a river, or a lake, or it can be from a recirculatedsource 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 atmosphere,principally by evaporative cooling effect.b. Equipment required—general. Equipment requiredfor a system depends on the type of systemutilized. There are two basic types of condensers:surface and direct contact.There are also two basic types of cooling systems:Once through; andRecirculating type, including cooling ponds, mechanicaldraft cooling towers, natural draft coolingtowers, or a combination of a pond and tower.3-34TM 5-811-63-27. Description of major componentsa. Surface condensers.(1) General description. These units are designedas shell and tube heat exchangers. A surfacecondenser consists of a casing or shell with a chamberat 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. Uncontaminatedcondensate is recovered in surface condenserssince the cooling water does not mix with the condensingsteam. Steam pressure in a condenser (or* vacuum) depends mainly on the flow rate and temperatureof the cooling water and on the effectivenessof air removal equipment.(2) Passes and water boxes.(a) Tubing and water boxes may be arrangedfor 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 undividedto permit reversal of flow.

(b) For a relatively large cooling water sourceand low circulating water pump heads (hence low. unit pumping energy costs), single pass units will beused. 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-circulatingwater system must be optimized by the designerto arrive at the best combination of condenser surface,temperature, vacuum, circulating waterpumps, piping, and ultimate heat rejection equipment.(c) Most large condensers, in addition to theinlet waterbox horizontal division, have vertical partitionsto give two separate parallel flow pathsthrough the shell. This permits taking half the condensingsurface our of service for cleaning while waterflows through the other half to keep the unit runningat reduced load.(3) Hot well. The hot well stores the condensate‘L and keeps a net positive suction head on the condensatepumps. Hot well will have a capacity of at least3 minutes maximum condensing load for surges andto permit variations in level for the condensate controlsystem.(4) Air removal offtakes. One or more air offtakesin the steam space lead accumulating air tothe air removal pump.(5) Tubes.(a) The tubes provide the heat transfer surfacein the condenser are fastened into tube sheets,usually made of Muntz metal. Modern designs havetubes rolled into both tube sheets; for ultra-tightness,alloy steel tubes may be welded into tubesheets of appropriate material. Admiralty is themost common tube material and frequently is satisfactoryfor once through systems using fresh waterand for recirculating systems. Tube material in the“off gas” section of the condenser should be stainlesssteel because of the highly corrosive effects ofcarbon dioxide and ammonia in the presence ofmoisture and oxygen. These gases are most concentratedin 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 life

expectancy. Lower velocities are inefficient from aheat transfer point of view. Tubes are generally installedwith an upwardly bowed arc. This providesfor thermal expansion, aids drainage in a shutdowncondenser, and helps prevent tube vibration.b. Direct contact condensers. Direct contact condenserswill not be specified.c. Condenser auxiliaries.(1) General. A condenser needs equipment andconduits to move cooling water through the tubes,remove air from the steam space, and extract condensatefrom the hotwell. Such equipment and conduitswill 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 combinationof these conduits.(g) Discharge water tunnel, piping or canal,or combination of these conduits.(2) Circulating water pumps. A condenser uses75 to 100 pounds of circulating water per pound ofsteam condensed. Hence, large units need substantialwater flows; to keep pump work to a minimum,top of condenser water boxes in a closed system will3-35TM 5-811-6Table 3-12. Condenser Tube Design Velocities.Material Design Velocities fpsFresh Water Brackish Water Salt WaterAdmiralty Metal 7.0 (1) (1)Aluminum Brass(2) 8.0 7.0 7.0Copper-Nickel Alloys:90-10 8.0 8.0 7.0 to 7.580-20 8.0 8.0 7.0 to 7.570-30 9.0 9.0 8.0 to 8.5Stainless Steel 9.0 to 9.5 8 . 0( 3 ) 8 . 0( 3 )

Aluminum(4) 8.0 7.0 6.8NOTES :(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.U.S. Army Corps of Engineersnot be higher than approximately 27 feet above minimumwater source level which permits siphon operationwithout imposing static head. With a siphon

system, air bubbles tend to migrate to the top of thesystem and must be removed with vacuum-producingequipment. The circulating pumps then need todevelop only enough head to overcome the flow resistanceof the circulating water circuit. Circulatingpumps for condensers are generally of the centrifugaltype 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 circulatingwater pumps. They must develop heads to pushwater through atmospheric pressure, pipe and controlvalve friction, closed heater water circuit friction,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 saturationtemperature; to prevent flashing of the condensate,they are mounted below the hotwell to receivea net positive suction head. Modern vertical“can” type pumps will be used. Specially designedpump glands prevent air leakage into the condensate,and vents from the pump connecting to the vaporspace in the condenser prevent vapor binding.(4) Spare pumps. Two 100 percent pumps forboth circulating water and condensate service willbe specified. If the circulating water system servesmore than one condenser, there will be one circulatingpump 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 extractionto 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, carbondioxide, 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, porouswalls, 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 efficiencyof the turbine because of loss of availableenergy. The total condenser pressure is:

Pc = PS+ Pa

where Ps = steam saturation pressure correspondingto steam temperaturePa = air pressure (moisture free)LThis equation shows that air leakage must be removedconstantly to maintain lowest possible vacuumfor 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 compressedfor discharge to atmosphere.(b) Although the mass of air leakage to the. condenser may be relatively small because of itsvery low pressure, its removal requires handling of alarge volume by the air removal equipment. The air. osftfetaamke ss pwaicteh dorvaewr ath ec oaldir -sveacptoiorn m oofi stthuer ec ofnrodmen tsheertubes or through an external cooler, which condensespart of the moisture and increases the air-tosteamratio. Steam jets or mechanical vacuumpumps receive the mixture and compress it to atmospherepressure.(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 circulatingwater system, automatic backflush or mechanicalcleaning 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 throughcirculating water system, shown in figure 3-13, consistsof the following components:(a)(b)(c)(d)(e)(f)TM 5-811-6Intake structure.Discharge, or outfall.Trash racks.Traveling screens.Circulating water pumps.Circulating water pump structure (indooror outdoor).(g) Circulating water canals, tunnels, andpipework.(2) System operation.(a) The circulating water system functions as

follows. Water from an ocean, river, lake, or pondflows either directly from the source to the circulatingwater structure or through conduits which bringwater from offshore; the inlet conduits dischargeinto a common plenum which is part of the circulatingwater 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 installedto 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 suctionof the circulating water pumps. For small systems,two 100-percent capacity pumps will be selectedwhile for larger systems, three 50-percentpumps will be used. At least one pump is requiredfor standby. Each pump will be equipped with a motorizedbutterfly 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 exchangers.(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 capabilityto reverse flow in each of the condenser halvesfor cleaning the tubes. The frequency and durationof the condenser reverse flow or back wash operationis 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 circulatingwater pumps are designed to remain operablewith the water level at the lowest anticipated eleva-3-37TM 5-811-6INAVFAC DM3Figure 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 level

variations for a natural lake or river. Cooling pondsare usually man-made with the level controlled withinmodest 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, circulatingpump 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 componentsof the circulating water system will be accessiblefor inspection during station operation.e. Circulating water system—recirculating type(1) General discussion.(a) With a once-through system, the evaporativelosses responsible for rejecting heat to the atmosphereoccur in the natural body of water as thewarmed circulating water is mixed with the residualwater and is cooled over a period of time by evaporationand conduction heat transfer. With a recirculationsystem, 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. Recirculatingsystems can utilize one of the following forheat rejection:(1) A natural draft, hyperbolic cooling tower.(2) A mechanical draft cooling tower, usuallyinduced 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 system3-38TM 5-811-6they are once through and hence considered as suchin paragraph d above.(c) To avoid fogging and plumes which arecharacteristic of cooling towers under certain atmospheric

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 visibleplume. The wet-dry types of towers are expensiveand 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 circumstances,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 consistsof the following components:(a) Intake structure which is usually an extensionof the cooling tower basin.(b) Circulating water pumps.(c) Circulating water piping or tunnels to condensersand from condensers to top of cooling tower.(d) Cooling tower with makeup and blowdownsystems.(3) System operation.(a) The recirculating system functions as follows.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 exceptit is much simpler because trash racks or travelingscreens are not required, and the pit settingcan be designed without reference to levels of a naturalbody 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 miscellaneouscooling 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 flushingor mechanical cleaning system is required forthe condenser. Also, due to the higher pumpingheads commonly required for elevating water to thetop of the tower and the break in water pressure at

that point which precludes a siphon, higher pressureratings for the pumps and condensers will be specified.(4) Cooling tower design.(a) In an induced draft mechanical coolingtower, atmospheric air enters the louvers at the bottomperimeter 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 arrangementof the tower or towers on the power stationsite will be carefully planned to avoid recirculationof saturated air back into the tower intake andto prevent drift from the tower depositing on electricalbuses and equipment in the switchyard, roadwaysand other areas where the drift could be detrimental.(b) Hot circulating water from the condenserenters the distribution header at the top of the tower.In conventional towers about 75 percent of thecooling takes place be evaporation and the remainderby 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 towerand the wet bulb temperature of the entering air.The smaller the approach, the more efficient and expensivethe tower. Another critical factor is the coolingrange. This is the difference between the hot watertemperature entering the tower and the cold watertemperature leaving it is essentially the same asthe circulating water temperature rise in the condenser.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 optimizationwhich should include simultaneous selectionof the condensers as these two major items ofequipment are interdependent.(6) Cooling tower makeup.(a) Makeup must be continuously added tothe 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 preventmetal corrosion and fouling. Algae control isaccomplished by means of chlorine injection; acidand phosphate feeds are used for pH control and to

keep heat surfaces clean.(b) The circulating water system must beblown down periodically to remove the accumulatedsolid concentrated by evaporation.3-39TM 5-811-63-28. Environmental concernsa. Possible problems. Some of the environmentalconcerns which have an impact on various types ofpower plant waste heat rejection systems are as follows:(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, buildingsand structures in the winter.(5) Noise from cooling tower fans and circulatingwater pumps.(6) Salts deposition on the contiguous countrysideas the evaporated water from the tower is absorbedin the atmosphere and the entrained chemicalsinjected in the circulating water system fallout.(7) Effect on aquatic life for once though systems:(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 onlya 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 ofthe type of circulating water system and optimumorientation of the power plant at the site can minimizethese problems. However, many military projectswill involve cogeneration facilities which mayrequire use of existing areas where construction ofcooling towers may present serious on base problemsand, hence, will require innovative design solutions.Section VII. FEEDWATER SYSTEM3-29. Feedwater heatersa. Open type—deaerators.(1) Purpose. Open type feedwater heaters areused primarily to reduce feedwater oxygen and othernoncondensable gases to essentially zero and thusdecrease corrosion in the boiler and boiler feed system.

Secondarily, they are used to increase thermalefficiency as part of the regenerative feedwater heatingcycle.(2) Types.(a) There are two basic types of open deaeratingheaters 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 feedwaterhas 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 deaeratinghot 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 falloff in deaerator pressure under an upset condition.Access will be provided for heater maintenance andfor reading and maintaining heater instrumentation.(4) Design criteria.(a) Deaerating heaters and storage tanks willcomply 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 heaterwill not be less than three psig.(c) Feedwater leaving the deaerator will containno more than 0.005 cc/liter of oxygen and zeroresidual carbon dioxide. Residual content of the dissolvedgases 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; pressuregauge at feedwater and steam inlets; and a level controlsystem (paragraph c).3-40TM 5-811-6b. 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 dischargeside of the feed pumps). The economic analysisof 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 Utubetype.(3) Location. Heaters will be located to alloweasy access for reading and maintaining heater instrumentationand 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 revisionsof the following standards:(1) ASME Unfired Pressure Vessel Code.(2) ASME Power Test Code for FeedwaterHeaters.(3) Tubular Exchanger Manufacturers Association(TEMA).(4) Heat Exchanger Institute (HE I).(5) American National Standards Institute(ANSI).(b) Each feedwater heater will be providedwith the following minimum instrumentation: shelland tube relief valves; thermometer, thermocoupleand test well at feedwater inlet and outlet; steam inletand drain outlet; pressure gauge at feedwater inletand outlet, and steam inlet; and level control system.

c. Level control systems.(1) Purpose. Level control systems are requiredfor 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 systemwhich 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 controlsystem. Modifications may be required to fit theactual 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 lowerpressure 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 condenserto hold the predetermined level.(b) The following minimum instrumentationwill be supplied to provide adequate level control ateach heater: gauge glass; level controller to modulatenormal 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 followingminimum instrumentation will be suppliedto provide adequate level control at theheater: gauge glass, level controller to control feedwaterinlet 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” waterlevel controller to remove water from the deaeratorto the condenser or flash tank, or to divert feedwateraway from the deaerator by opening a divertingvalve to dump water from the feedwater line tothe condenser or condensate storage tank.(4) Reference. The following papers should be

consulted in designing feedwater level control systems,particularly in regard to the prevention of waterinduction through extraction piping(a) ASMD Standard TWDPS-1, July 1972,“Recommended Practices for the Prevention of WaterDamage 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, “Recommendationto Minimize Water Damage to Steam Turbines.”3-30. Boiler feed pumps.a. General. Boiler feed pumps are used to pressur-3-41TM 5-811-6ize 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 ternperatureto 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 barreltype 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 capacity.(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 arrangement,two pumps are operated in parallel between50 and 100 percent boiler output, but only onepump is operated below 50 percent capacity. This arrangementallows for pump operation in its most efficientrange 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 capital

costs. At least three 55-62.5 percent pumps shouldbe selected based on maximum steaming capacity ofall boilers served by the battery to provide the flexibilityrequired 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 collapsesin 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 flowwhenever the pump is in operation. The control systemwill consist off(a) Flow element to be installed in the pumpsuction line.(b) Flow controller.(c) Flow control valve.(d) Breakdown orifice.(2) Whenever the pump flow decreases to minimumrequired flow, as measured by the flow elementin the suction line, the flow controller will bedesigned to open the flow control valve to maintainminimum pump flow. The recirculation line will bedischarge to the deaerator. A breakdown orifice willbe installed in the recirculation line just before it entersthe deaerator to reduce the pressure from boilerfeed pump discharge level to deaerator operatingpressure.f. Design criteria.(1) Boiler feed pumps will comply with the latestrevisions of the following standards:(a) Hydraulics Institute (HI).(b) American National Standards Institute(ANSI).(2) Pump head characteristics will be maximumat 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 withoutinternal flashing and operate continuously withoutoverheating or objectionable noises at minimum

recirculation 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 thedriver.(d) Inner and outer casing for double casingpumps.(5) All rotating parts will be balanced statically -

and dynamically for all speeds.(6) Pump design will provide axial as well as radialbalance of the rotor at all outputs.(7) One end of the pump shaft will be accessiblefor portable tachometer measurements.(8) Each pump will be provided with a pumpwarmup 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 insideof 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 inTM 5-811-6an 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 cogenerationplant or there is otherwise a need for substantialquantities of exhaust steam. Usually, however,adequate reliability can be incorporated intothe feed pumps by other means, and from a plant efficiencypoint 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 includesthe condensate system as well as the boilerfeed system.(2) The condensate system includes the condensatepumps, 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 purityand corrosive (demineralized and undeaerated).With this arrangement, corrosive demineralized watercan 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 temperaturethan deaerator condensate, the heat loss in theatmospheric storage tank is much less with this arrangement.(3) The feedwater system includes the boilerfeed pumps, high pressure closed heaters, boiler feedsuction and discharge piping, feedwater level controlsfor the boiler, and boiler desuperheater watersupply with its piping and controls.b. Unit vs. common system. Multiple unit cogenerationplants producing export steam as well aselectric will always have ties for the high pressureSection Vlll. SERVICE WATER3-32. Introductiona. Definitions and purposes. Service water supplysystems and subsystems can be categorized as follows:(1) For stations with salt circulating water orsteam, the extraction steam, and the high pressurefeedwater system. If there are low pressure closedheaters incorporated into the prime movers, the condensatesystem 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 designedto suit the basic parameters of the cycle. Levelcontrol problems can become complex, particularlyif the cycle includes multiple deaerators operatingin parallel.c. Feedwater controls. Condensate pumps, boilerfeed pumps, deaerator, and closed feedwater heatersare described as equipment items under other headingsin this manual. Feedwater system controls willconsist of the following(1) Condenser hotwell level controls which controlhotwell 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 replenishcycle fluid.(2) Condensate pump minimum flow controls torecirculate sufficient condensate back to the condenserhotwell 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 condensatestorage tank(s).(4) Numerous different control systems are possiblefor all three of the above categories. Regardlessof the method selected, the hotwell and the deaeratorlevel 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 circulatingwater.(a) Most power stations, other than thosewith cooling towers, fall into this category. Circulatingwater booster pumps increase the pressure of a(small) part of the circulating water to a level ade-3-43TM 5-811-6quate to circulate through closed cooling water exchangers.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 stations,the service water system may have its pumpsdivorced from the circulating water pumps to providemore flexibility y and reliability.(b) The closed cooling water exchangerstransfer rejected heat from the turbine generatorlube oil and generator air (or hydrogen) coolers, bearingsand incidental use to the circulating water sidestreampressurized by the booster pumps. The mediumused 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. Circulating

water booster pumps (or separate service waterpumps). may also be used for this type of powerplant. In the case of cooling tower systems, however,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 generatorauxiliary 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 designedto 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 requiredfor each system is as follows:(1) Service water system(a) Circulating water booster pumps (or separateservice water pumps).(b) Piping components, valves, specialitiesand 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, specialitiesand 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-percentor three 50-percent pumps will be selected forthis duty. Three pumps provide more flexibility; dependingupon 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 interlocks

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 systemserves heat rejection loads directly, temperaturecontrol for each equipment where heat is removedwill be by means of either automatic or manuallycontrolled valves installed on the cooling waterdischarge 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 closedcooling water pumps will be motor driven, horizontal,end suction, centrifugal type with two 100-percentor 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 circulating(service) water on the tube side. Two 100-percentcapacity exchangers will be selected for thisservice, although three 50-percent units may be selectedfor large systems.(3) Temperature control. Temperature controlfor each equipment item rejecting heat will be similarto that described above for the service water system.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 tomaintain the closed cooling water system supplytemperature at 950 For less during normal operationTM 5-811-6with maximum heat rejection load. The system willalso be capable of being controlled or manually adjustedso 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 reliabilityfeatures 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 small

circulating 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 operationaltransients (e.g., pump startup or water hammerdue to power failure) do not cause adverse effectsin the system. Where necessary, suitable valvingor surge control devices will be provided.b. Closed cooling water system.(1) The closed cooling water coolant temperatureis maintained at a constant value by automaticcontrol of the service water flow through the heatexchanger. This is achieved by control valve modulationof the heat exchanger by-pass flow. All equipmentcooled by the cooling system is individuallytemperature controlled by either manual or automaticvalves 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 expansiontank by means of a level controller which operatesa control valve supplying makeup from thecycle condensate system. The head tank is providedwith an emergency overflow. On a failure of a runningclosed cooling water pump, it is usual to providemeans to start a standby pump automatically.(2) The system will be designed to ensure adequateheat removal based on the assumption that allservice equipment will be operating at maximum designconditions.3-35. Arrangementa. Service water system. The circulating waterbooster 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 coolingwater 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 serviceduring 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 pump

will 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 SYSTEMS3-38. 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 refacewater or well water, contain dissolved and pos- quired quality for all phases of power plant operasiblysuspended 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. Torependingon its quality, usually requires little or no duce the undesirable concentrations of turbidity andpretreatment. Fresh water makeup to a boiler systemranges from possibly no pretreatment (in theorganic matter found in most surface waters, theraw water will normally be clarifed by coagulationcase 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-3-45TM 5-811-6ment, which may also include some degree of softening,will normally be adequate without further treatmentfor cooling tower makeup and other generalplant use.b. Methods of conditioning.(1) Water conditioning can be generally categorizedas’ ‘external” treatment or’ ‘internal” treatment.External treatment clarifies, softens, or purifiesraw water prior to introducing it into the powerplant fluid streams (the boiler feed water, coolingtower system, and process water) or prior to utilizingit for potable or general washup purposes. Internaltreatment methods introduce chemicals directlyinto the power plant fluid stream where they counteractor moderate the undesirable effects of waterimpurities. Blowdown is used in the evaporativeprocesses to control the increased concentration ofdissolved and suspended solids at manageable levels.(2) Some of the methods of water conditioning

are as follows:(a) Removal of suspended matter by sedimentation,coagulation, and filtration (clarification).(b)of gases.(c)(d)(f)(g)(h)Deaeration and degasification for removalCold or hot lime softening.Sodium zeolite ion exchange.Choride cycle dealkalization.Demineralization (ultimate ion exchange).Internal chemical treatment.(i) Blowdown to remove sludge and concentrationbuildups.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 constituentsof 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 SYSTEMS3-39. Introductiona. Purpose. The purpose of the compressed airsystems is to provide all the compressed air requirementsthroughout the power plant. The compressedair systems will include service air and instrumentair systems.b. Equipment required-general. Equipment requiredfor a compressed air system is shown in Figures3-14 and 3-15. Each system will include(1) Air compressors.(2) Air aftercoolers.(3) Air receiver.(4) Air dryer (usually for instrument air systemonly).(5) Piping, valves and instrumentation.c. Equipment served by the compressed air systems.(1) Service (or plant) air system for operation oftools, blowing and cleaning.(2) Instrument air system for instrument andcontrol purposes.(3) Soot blower air system for boiler soot blowingoperations.3-40. Description of major components

a. Air compressors. Typical service and instrumentair 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 horizontaland, for instrument air service, always have oillesspistons and cylinders to eliminate oil carryover.3-46Non-lubricated design for service air as well as instrumentair will be specified so that when the formeris used for backup of the latter, oil carryoverwill not be a problem. Slow speed horizontal unitsfor service and instrument air will be used. Sootblower service requirements call for pressures whichrequire multi-stage design. The inlet air filter-silencerwill be a replaceable dry felt cartridge type. Eachcompressor will have completely separate and independentcontrols. The compressor controls will permiteither constant speed-unloaded cylinder controlor automatic start-stop control. Means will be providedin 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, designedto 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 coolingsystem which is routed counter-flow to the airthrough the aftercooler, and then through the cylinderjackets. Standard aftercoolers are rated for95 “F. maximum inlet cooling water. Permissivecan be installed to prevent compressor startup unlesscooling water is available and to shut compressordown 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 removalof water.d. Instrument air dryer. The instrument air dryerTM5-811-6Table 3-13. General Guide for Raw Water Treatment of BoilerMakeupSt earnPressure Silica Alkalinity- (psig) reg./l. reg./l. (as CaCO3) Water Treatmentup 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 15450 to 600 Under 5Over 50Under 50Over 50Hot 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 limezeoliteor hot lime-hotzeolite.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 theAmerican 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 DM33-47TM 5-811-6Table 3-14. Internal Chemical Treatment.Corrosive Treatment RequiredMaintenance 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.U.S. Army Corps of EngineersChemicalCaustic SodaSoda Ash

Sulfuric AcidPhosphatesSoda AshSodium AluminateAlginatesSodium SilicateTanninsLignin DerivativesStarchGlucose DerivativesPolyphosphatesTanninsLignin DerivativesGlucose DerivativesSulfitesTanninsFerrus hydroxideGlucose DerivativesHydrazineAmmoniaTanninsLignin DerivativesGlucose DerivativesAmine CompoundsAmmoniaPolyamidesPolyalkylene GlycolsSodium SulfatePhosphatesTanninsNitrates3-48TreatmentCold Lime-ZeoliteTM 5-811-6Table 3-15. Effectiveness of Water TreatmentAverage Analysis of EffluentHardness Alkalinity co Dissolved(as CaCO )Hot Lime SodaHot Lime-Hot ZeoliteSodium ZeoliteSodium PlusHydrogen ZeoliteSodium ZeolitePlus ChlorideAnion ExchangerDemineralizerEvaporator

o to 217 to 25o to 2o to 2o to 2o to 2o to 2o to 2(as CaCO )mg./1.7535 to 5020 to 25Unchanged10 to 3015 to 35o to 2o to 2Medium HighLowLow to HighLowLowo to 5o to 5SolidsReducedReducedReducedUnchangedReducedUnchangedo t o 5o t o 5Silica833UnchangedUnchangedUnchangedBelow 0.15Below 0.15NOTE : (1) reg./l. = p.p.m.Source: NAWFAC DM33-49WET AIRENTRAINMENTSEPARATORCourtesy of Pope, Evans and Robbins (Non-Copyrighted)Figure 3-14. Typical compressed airsystem.will be of the automatic heat reactivating, dual

chamber, 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 instrumentair systems may have separate or commoncompressors. Regardless of compressor arrangement,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 instrumentair system.b. Service air system. The service air systemcapacity will meet normal system usage with onecompressor out of service. System capacity will includeemergency instrument air requirements aswell as service air requirements for maintenanceduring plant operation. Service air supply will in-3-50elude 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 switchgearand 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 5-811-6Courtesy of Pope, Evans and Robbins (Non-Copyrighted)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, locald. 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 comloopedheader 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 5-811-6CHAPTER 4GENERATOR AND ELECTRICAL FACILITIES DESIGNSection 1. TYPICAL VOLTAGE RATINGS AND SYSTEMS “4-1. Voltagesa. General. Refer to ANSI Standard C84. 1 forvoltage ratings for 60 Hz electric power systemsand equipment. In addition, the standard lists applicablemotor 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 generatorsand 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 supplywithin steam electric generating stations are relatedto motor size and, to a lesser extent, distances of cableruns. Motor sizes for draft fans and boiler feedpumps usually control the selection of the higheststation service power voltage level. Rules for selectingmotor voltage are not rigid but are based on relativecosts. 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 motorfor 460 volts so that the entire auxiliary powersystem can be designed at the lower voltage.(2) Station service power requirements for combustionturbine and internal combustion engine generatingplants are such that 208 or 480 volts will beused.d. Distribution system. The primary distributionsystem for an Army installation with central inhousegeneration 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 powersystems are generally in use in steam electric plantsand are discussed herein. They are designated as a

common bus system and a unit system. The distinctionis based on the relationship between the generatingunit 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 transformerwill 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 transformerwith 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 generatingunit is synchronized with the system. This startuptransformer also serves as the backup supply incase of transformer failure. This arrangement requiresthat 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 installations,the advantage of switching the generatorand its auxiliary transformer as a unit is notvery important, so the common bus system will normallybe used.b. Common bus system. In this system, generatorswill 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 suppliedby two station service transformers with no4-1TM 5-811-64-2TM 5-811-6isolation between auxiliaries for different generating

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 includedand 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 systemwill be used for a steam electric or combustion turbinegenerating station serving a utility transmissionnetwork. It will not be, as a rule, used for adiesel generating station of any kind since the stationservice power requirements are minimal.(2) The distinguishing feature of a unit type stationpower system is that the generator and unitauxiliary transformer are permanently connected togetherat generator voltage and the station servicepower requirements for that generating unit, includingboiler and turbine requirements, are normallysupplied 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 typicalone-line diagram of this arrangement. If the highestlevel of auxiliary voltage required is more than 480volts, say 4.16 kV, the auxiliary switchgear air circuitbreakers will only serve motors 250 hp and largerand feeders to unit substations. Each unit substationwill include a transformer to reduce voltagefrom the highest auxiliary power level to 480 volts

together 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 feedersbreakers 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 auxiliarytransformer 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 arrangementfor 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 commonto all units; e.g., water treating system, coaland ash handling equipment, air compressors, lighting,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 switchgear.Appropriate interlocks will be included so thatno more than one auxiliary transformer can feed anyswitchgear bus at one time.4-3. General types and standardsSection Il. GENERATORSa. 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 througha gear reducer up to 10,000 kVA or more). Self-ventilationis provided for generators larger than 5000kVA by some manufacturers, but this is not recommendedfor steam power plant service.

(2) Similar generators rated 5000 kVA and beloware revolving field, non-salient or salient pole,self-ventilated, open drip-proof type, sometimesconnected through a gear reducer to the turbine4-3TM 5-811-6wLEGENDCourtesy of Pope, Evans and Robbins (Non-Copyrighted)Figure 4-3. Station connections, two unit station unit arrangement-distribution voltage higher than generation.TM 5-811-6with the number of poles dependent on the speed selectedwhich is the result of an economic evaluationby the manufacturer to optimize the best combinationof turbine, gear and generator.(3) Generators for gas turbine service are revolvingfield, non-salient or salient pole, self-ventilated,open drip-proof type, sometimes connectedthrough a gear reducer, depending on manufacturer’sgas turbine design speed, to the gas turbinepower takeoff shaft. Non-salient pole generators aretwo-pole, 3600 rpm for 60 Hz, although manufacturersof machines smaller than 1500 kVA may utilize1800 rpm, four-pole, or 1200 rpm, six-pole, salient4-6pole 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 connected,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 requirementsof ANSI C50. 10, C50. 13 and C50.14 is applicableas well as the requirements of NEMA SM 12and SM 13.(1) ANSI C84.1 designates standard voltagesTM 5-811-6as discussed in section I.(2) Generator kVA rating for steam turbinegenerating units is standardized as a multiplier ofthe turbine kW rating. Turbine rating for a condensingsteam 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 feedwaterheaters in service. Turbine rating for a noncondensingturbine without controlled or uncontrolledextraction is based on output at design initialsteam conditions and design exhaust pressure.Turbine standard ratings for automatic extraction

units are based on design initial steam conditionsand exhaust pressure with zero extraction whilemaintaining rated extraction pressure. However,automatic extraction turbine ratings are complicatedby the unique steam extraction requirements foreach machine specified. For air cooled generators upto 15,625 kVA, the multiplier is 1.25 times the turbinerating, and for 18,750 kVA air cooled and hydrogencooled 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 generatingunits 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 powerfactor 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 factorsof large hydrogen cooled machines are standardizedat 0.90. Power factor for salient pole generatorsis usually 0.80. Power factor lower than standard,with increased kVA rating, can be obtained atan extra price.(5) Generator short circuit ratio is a rough indicationof 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 inachieving generator stability without the heavy expenseassociated 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 actingvoltage regulator and a high ceiling voltagestatic excitation system, this standard short circuitratio should be adequate even under severe system

disturbance conditions. Higher short circuit ratiosare available at extra cost to provide more stabilityfor unduly fluctuating loads which may be anticipatedin the system to be served.(6) Maximum winding temperature, at ratedload for standard generators, is predicated on operationat or below a maximum elevation of 3300 feet;this may be upgraded for higher altitudes at an additionalprice.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 voltagevariations of plus or minus 5 percent of ratedvoltage at rated kVA, power factor and frequency,but not necessarily in accordance with the standardsof performance established for operation at ratedvoltage; i.e., losses and temperature rises may exceedstandard values when operation is not at ratedvoltage.b. Thermal variations.(1) Starting from stabilized temperatures andrated 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 operatingat 125 percent of rated load field voltage for 1minute not more than twice a year.(2) The generator will be capable of withstanding,without injury, the thermal effects of unbalancedfaults at the machine terminals, including thedecaying effects of field current and dc componentof stator current for times up to 120 seconds, providedthe 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 decayingeffects of field current where protection is providedby reducing field current (such as with an exciterfield breaker or equivalent) and dc componentof the stator current.c. Mechanical withstand. Generator will be capableof withstanding without mechanical injury any4-7TM 5-811-6type of short circuit at its terminals for times not exceeding

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 manualcontrol will not be less than 120 percent of ratedexciter voltage when operating with a load resistanceequal to the generator field resistance, and excitationsystem will be capable of supplying thisceiling voltage for not less than 1 minute. These criteria,as set for manual control, will permit operationwhen 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 circuitterminal voltage wave will not exceed 10 percent.f. Telephone influence factor. The balanced telephoneinfluence factor (TIF) and the residual componentTIF will meet the applicable requirements ofANSI C50.13.4-5. Excitation systemsRotating commutator exciters as a source of dc powerfor the ac generator field generally have been replacedby silicon diode power rectifier systems ofthe static or brushless type.a. A typical brushless system includes a rotatingpermanent magnet pilot exciter with the stator connectedthrough the excitation switchgear to the stationaryfield 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 regulator,a means of manual voltage regulation, and necessarycontrol 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 regulators,

a full wave static rectifier, necessary devicesfor mounting on a remote panel, and a collector assemblyfor connection to the generator field.Section Ill. GENERATOR LEADS AND SWITCHYARD4-6. GeneralThe connection of the generating units to the distributionsystem can take one of the following patterns:a. With the common bus system, the generatorsare all connected to the same bus with the distributionfeeders. If this bus operates at a voltage of 4.16kV, this arrangement is suitable up to approximately10,000 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 reliabilityy 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 systemis the interrupting capacity of the switchgear.The switchgear breakers will be capable of interruptingthe 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 currentswhich 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 arrangement.The interrupting capacity of the breakersin the switchgear for each set of generators islimited to the contribution to a fault from the generatorsconnected to that bus section plus the contributionfrom the synchronizing bus and large (load)motors. Since the contribution from generators connectedto other bus sections must flow through tworeactors in series fault current will be reduced materially.d. If the plant is 20,000 kVA or larger and the4-8

ITM 5-811-6Figure 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 substationsfrom 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 arrangement,shown in Figure 4-7, costs only slightly morethan the main and transfer bus arrangement andL 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 beused 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 highestcost alternative and provides the highest reliabilitywithout 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 transformerwhere distribution is at 34.5 kV and higher,will be by means of cable or bus duct. In most instancesmore than one cable per phase will be necessaryto handle the current up to a practical maximumof four conductors per phase. Generally, cableinstallations will be provided for generator capacitiesup to 25 MVA. For larger units, bus ducts will4-9TM 5-811-6LOAD LOADbe evaluated as an alternative.(2) The power cables will be run in a cable tray,separate from the control cable tray; in steel conduit;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 by

compression lugs where neoprene or similarly jacketedcables 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 applicationswhere cables will be suspended from hangersor placed in tray, armored cable will be used to providephysical protection. If the cable current ratingdoes not exceed 400 amperes, the three phases will4-10be tri-plexed; i.e., all run in one steel armored enclosure.In the event that single phase cables are required,the armor will be nonmagnetic.(5) In no event should the current carrying capacityof the power cables emanating from the generatorbe a limiting factor on turbine generator output.As a rule of thumb, the cable current carryingcapacity will be at least 1.25 times the current associatedwith kVA capacity of the generator (not thekW rating of the turbine).b. Segregated phase bus.(1) For gas turbine generator installations theconnections from the generator to the side wall orroof of the gas turbine generator enclosure will havebeen made by the manufacturer in segregated phasebus configuration. The three phase conductors willbe flat copper bus, either in single or multiple conTM5-811-6ductor per phase pattern. External connection toswitchgear or transformer will be by means of segregatedphase bus or cable. In the segregated phasebus, the three bare bus-phases will be physically separatedby non-magnetic barriers with a single enclosurearound the three buses.(2) For applications involving an outdoor gasturbine generator for which a relatively small lineupof outdoor metal clad switchgear is required to handlethe distribution system, segregated phase buswill be used. For multiple gas turbine generator installations,the switchgear will be of indoor constructionand installed in a control/switchgear building.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 25

MVA 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 insulatorsin individual non-magnetic bus enclosures, providesmaximum reliability by minimizing the possibilityof phase-to-ground or phase-to-phase faults.(2) Isolated phase bus current ratings shouldfollow the rule of thumb set forth above for generatorcables.4-11TM 5-811-64-12ADbDTM 5-811-6I4-8. Switchyarda. Outdoor vs. indoor. With normal atmosphericconditions, 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 installationemploying totally enclosed metal clad switchgearwith SF6 insulation will be provided.b. Structures and buses.(1) In the event distribution for a large installationis 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, potentialand current transformers, and the terminationsfor the generator stepup transformer and transmissionlines.(2) Structures of galvanized steel or aluminumare most often used. Where the switchyard is locatedclose 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. Copperbus connections will be bolted; aluminum connectionsmust be welded. Special procedures are requiredfor aluminum welding, and care should betaken to assure that welders certified for this type of

welding are available. For isolated or overseas establishments,only copper buses should be used. Acorrosive atmosphere will preclude the use of aluminum.c. Disconnect switches; insulators(1) Two three-phase disconnect switches will beused 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 disconnectswitch will be installed as a by-pass aroundthe circuit breaker so it can be maintained.(2) Line disconnect switches at all voltage ratingswill have arcing horns. Above 69 kV, all disconnectswitches will have arcing horns.(3) Current carrying capacity of each disconnectswitch 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 partitularlypolluted atmospheres, the next higher voltagerating than that of the system will be used. Insome instances, the manufacturer can furnish currentcarrying 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 atmosphere.In such installations, the normal relationshipbetween flashover across the open switch and flashoverto ground must be maintained.(5) All disconnect switches will be operablefrom ground level by means of either a lever or rotatingcrank 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 copperwire.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, pneumaticemploying a motor driven compressor in eachoperating mechanism; or pneudraulic, a combinationpneumatic 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 carryingand current interrupting capacity is availablefor each system operating voltage level. Carefulstudy must be made of the continuous load current4-13TM 5-811-6and 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 systemstudy will be performed prior to selecting the oilcircuit breakers. Power networks analyzers or computerprograms will be utilized in such work.e. Potential and current transformers.(1) For power systems through 69 kV, potentialtransformers are generally used to provide voltagesin the 69- and 120-volt ranges for voltmeters, wattmeters,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 devicesby placing too many instruments or devices inthe circuit.(2) Both the potential transformers (pt’s) andcapacitor potential devices (cpd’s) will be purchased

with 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 employedon each main high voltage bus. Generally,only one pt or cpd is needed on each feeder for synchronizingor hot line indication; but for ties to theoutside utility or for special energy metering for billingpurposes or other energy accounting, or for relaying,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, forcontrol, indication and protective relaying. Shouldbilling metering be needed, more accurate meteringtype bushing type ct’s will be used.(5) Current transformer ratios do not necessarilyhave a direct relationship with the continuouscurrent capacity of the circuit breaker or transformerbushing on which they are mounted. The high currentportion of the ratio shoul be selected so thatthe circuit full load current ‘wall beat approximately70-80 percent of instrument full scale for best accuracy.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 atime. Power circuits can be operated for extended,periods with a part of the instrumentation and meteringout of service; they should not be operated forextended periods without the protective devices.f. Duct system.(1) Except as otherwise described herein, ductsystems will be in accordance with TM 5-811-1/AFM 88-9.(2) Power and control cables will be run in undergroundconduit in a concrete duct system betweenthe 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 transformers

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 concretecable 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 cablesand lighting circuits, plus provision of at least25 percent for expansion of the switchyard.(4) Checkered plate or sectionalized prefabricatedconcrete 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 conduitburied 18 inches deep to the point of rising tothe circuit breaker mechanism housing or other termination.Risers will be attached securely to the terminatingdevice.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 locationin the switchyard. Oil circuit breakers require125 Vdc for closing, tripping and indication. Compressormotors or spring winding motors for the oilcircuit breakers will require 120 or 208 volts ac, aswill the radiator cooling fans for the power transformers.Strip heaters for the ocb transformermechanism housings will operate at 208 Vat. Lightingcircuits 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 maintainthe switchyard.h. Grading and fencing.(1) The entire switchyard area will be at the4-14TM 5-811-6same grade except for enough slope to providedrainage. The concrete pads and foundations for allocb’s and transformers; for all bus, pt and ct supportingstructures; and for the switchyard structureswill 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 exposed

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 entiresubstation. 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 regularaccess, 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 instant,easy removal in the event use of the emergencyexit 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 2feet below rough grade level will be installed prior toinstallation of cable ducts, cable trenches andcrushed rock, but simultaneously with the installationof 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. Fromthe perimeter, cross-connections from side to sideand end to end will be 250 MCM stranded tinnedcopper cable on 10- to 12-foot spacing in accordancewith 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 structure,to every ocb and transformer, and to every disconnect

switch structure with 4/0 stranded tinnedcopper conductor. Two taps will be run to each circuitbreaker 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. Connectionwill be made to opposite ends of the switchyard500 MCM loop and to widely separated pointsat the generating station grid.(5) Ground rods, at least 8 feet long, 3/4-inch diameter,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 particularlyrocky 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 grading,fencing and grounding system in considerabledetail for station and substation applications wherepower is purchased from a utility or small generatorsare 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” system.TM 5-811-UAFM 88-9 will be followed for detailnot described herein.4-15TM 5-811-6Section IV. TRANSFORMERS4-9. Generator stepup transformer

The stepup transformer will be in accordance withANSI Standard C 57.12.10 and will include the followingoptional features.a. Rating.(1) The generator stepup transformer kVA ratingfor 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 generatorunit auxiliary transformer load is tapped off betweenthe generator and stepup transformer andwill amount to about 6 percent of the generator rating,the operating margin for the stepup transformerwill be on the order of 20-25 percent. This will permitmaking full use of the margin the turbine generatormanufacturer 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 energized.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 coordinatewith 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 kWGenerator 31,250 kVA at 0.8 PFTransformer 35,000 kVA at OA/FA/FA rating(4) Voltage of the high side will match the nominaloperating 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 operateon 208 volts, 60 Hz, single phase. The control systemwill provide automatic throwover from dual 208volt sources with one being preferred and the otheralternate; either may be selected as preferred via a

selector switch. Sources will be run from separateauxiliary power sources within the plant.(2) The transformer alarms will be connected tothe plant annunciator system and will require 125Vdc for the alarm system auxiliary relays. Protectivedevices, which will be mounted in the transformerwith 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 alarmcontacts.(c) Winding hot spot oil temperature indicatorwith 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 suitablefor 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.4-16TM 5-811-6(1) As a rule of thumb, the unit auxiliary transformerfor a steam electric station will have a kVArating on the order of 6 to 10 percent of the generatormaximum 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 ratingspecified for an installation will be determinedfrom the expected station service loads developedby the design. The station startup and standby auxiliarytransformer 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 capacity 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 transformersare fed from the station bus, sizing of theauxiliary transformer will take into account the auxiliarypower loads for all units in the station plus allcommon plant loads. The sizing of auxiliary transformers,in any case, will be subject to an analysis ofall loads served under any set of startup, operating,or shutdown conditions with reasonable assumedtransformer 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 provided,resulting in an OA/FA rating. Fan control forauxiliary transformers will be similar to that describedfor 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 furnishpower 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 be

identical to those of the generator stepup transformer.(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 transformer,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” isused 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 reducingstation fed by one or two circuits from theauxiliary switchgear and, in turn, serving a numberof large motors or motor control centers. The breakerswill have lower ratings than those in the auxiliaryswitchgear 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 auxiliariesof 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 permanentlyto 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 sufficientto 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 turbineinstallations, 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 accessibleterminal board. Devices will include a windinghot spot temperature indicator having two

alarm stages for two temperature levels with electricallyindependent alarm contacts. On occasion, itwill be found that design and construction of theunit substation transformer and its physically attached480-volt switchgear may require the groundindication pt’s and their ground indicating lamps tobe mounted within and on the transformer ventilatedenclosure. In this event, the ground alarm relayswill be mounted in a readily accessible portionof the enclosure with leads brought to terminalblocks for external connection to the control roomannunicator.4-17TM 5-811-6Section V. Protective RELAYS AND METERING4-12. Generator, stepup transformerand switchyard relayinga. 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 coveredherein. 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 providedwith the following protective relays:–Three – Generator differential relays (ANSI Device87)–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 identificationsystem, 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 toprovide 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 breaker,

it is also common practice to use a dedicated zoneof differential protection for the generator as backupprotection.(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 beforereturning the controlled equipment to its normalposition.(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 situationand initiate a safe shutdown.(4) Negative sequence currents flowing in a generatorarmature will cause double frequency magneticflux linkages in the rotor and may cause surfaceheating of the rotor. The generator is designedto accept a specified amount of this current continuallyand higher amounts for short periods withina 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. However,a second ground could cause destructive vibrationsin 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 protectthe generator from faults occurring on the system.(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 unbalantesin circuit transformer circuits.d. Power transformer relaying. Each stepuptransformer will be provided with the following protectiverelays:(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 auxiliarytransformer are connected together permanently,an additional differential relay zone is establishedcomprising 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 transformerswill each be provided with the following protectiverelays:(1) Three–Transformer differential relays(ANSI Device 87)(2) One–Lockout relay (ANSI Device 86)(3) One–Transformer netural time overcurrent4-18.relay to be used as a fault detector relay (ANSI Device51G)(4) One–Transformer sudden gas pressure relay(ANSI Device 63).f. Switchyard bus relaying. Each section of theswitchyard bus will be provided with bus differentialrelaying 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 relayswill be provided for each circuit:(1) Three–Phase time overcurrent relays withinstantaneous element (ANSI Device 50/5 1).(2) One–Residual ground time overcurrent relaywith instantaneous element (ANSI Device50/51 N).h. Ties to utility. Relaying of tie lines to the utilitycompany 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 utilizedirect acting trip devices. These devices will beprovided as follows:(1) Incomingtime elements.TM 5-811-6line: three–long time and short(2) Motor control center feeders: three–longtime and short time elements.(3) Motor feeders: three–long time and instantaneouselements.c. Motor control center protection (480-volt system).Because of the lower rating, breakers will bemolded case type employing thermal/magnetic elementsfor 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 forstator temperature detectors(8) D.C. volmeter for excitation voltage(9) D.C. ammeter for field currentb. Stepup transformer.(1) Voltmeter on high voltage side with selectorswitch(2) Ammeter with selector switch(3) Wattmeter(4) Varmeter(5) Power factor meterc. Auxiliary transformer.(1)switch(2)(3)(4)(5)Voltmeter on low voltage side with selectorAmmeter with selector switchWattmeterVarmeterPower factor meterd. Common.(1) Voltmeter with selector switch for each bus(2) Synchroscopee. 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 foreach auxiliary transformer.f. Miscellaneous. For units rated 20,000 kW orlarger, a turbine-generator trip recorder will be providedbut not necessarily mounted on the controlboard. This is for use in analyzing equipment failuresand shutdowns.4-19TM 5-811-6Section Vl. STATlON SERVlCE POWER SYSTEMS4-15. General requirementsa. Scope. The power plant station service electricalsystem will consist of the following

(1) For steam turbine plants of about 20,000kW or larger, a medium voltage (4.16 kV) distributionsystem utilizing outdoor oil filled auxiliarypower transformers and indoor metal clad drawouttype switchgear assemblies. Usually a medium voltagelevel 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 combinationstarters and feeder breakers.(3) Station power requirements are smaller forcombustion gas turbine units and diesel engine drivengenerators. For the combustion gas turbineplant, a starting transformer capable of supplyingthe starting motors is required if the turbine is motorstarted, 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 stationservice system will be designed to be operationalduring station startup, normal operation and normalshutdown. Redundancy will be provided to permitoperation 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 entranceof control and power cables. The 4160-voltswitchgear and 480-volt unit substation will preferablybe located on upper floor levels for maximumconvenience in routing power cables; control andpower cables can thus enter from either above or below.The 480-volt switchgear in combustion gas turbineor diesel plants will be at ground level.4-16. Auxiliary power transformersa. Type. The auxiliary power transformers will beoil 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 thevoltage 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 symmetricalshort 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 switchgearis to be used. This permits using breakers havingan interrupting rating of 350 MVA for 4160volts swichgear or 300 MVA for 2400 volt switchgear.(2) Meeting these criteria is possible for units ofthe size contemplated herein. If the voltage dropwhen starting the largest motor exceeds the criterionwith the fault current limited as indicated, alternativemotor designs and reduced voltage startingfor the largest motor or alternative drives forthat load, will be investigated.d. Transformer connections.(1) With the unit system, the turbine generatorunit 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, itmust be wye-wye with a delta tertiary. The wye-wyeconnection is necessary to get the correct phase relationshipfor the two possible sources to the 4160volt buses. Voltage phase relationships must be consideredwhenever different voltage sources are inparallel. For wye-wye or delta-delta transformer connections,there is no phase shift between theprimary and secondary voltages. However, fordelta-wye or wye-delta transformer connections, theprimary and secondary voltage will be 30 degreesout of phase in either a leading or lagging relationship.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 relationshipsfor power station generators and transformers.(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 indoormetal clad, drawout type employing breakers havinga symmetrical interrupting rating of 48 kA and

TM 5-811-6with 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 transformerfeeds to the 480 volt unit substations.b. Cable entrance. Power and control cable entrancefrom 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 asdefined in subparagraph 4-1 la, or power centers,employ a 4160-480 volt transformer close coupledto a section of 480 volt switchgear. Switchgear portionwill utilize drawout breakers and have breakersand buses braced to interrupt and withstand, respectively,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 between75 and 200 horsepower, and also serve as supplyto the 480-volt motor control centers.c. Cable entrance. Power and control cable entrancefrom above or below will depend on final locationin the station.d. Trip devices. Direct acting trip devices will beapplied to match the appropriate transformer ormotor feeder load and fault characteristics as discussedin 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 backto-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 verticalsection 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, lightingtransformers, motor operated devices, weldingreceptacle system and the like. Loads should begrouped in such a manner as to result in relativelyshort feeder runs from the centers, and also to facilitatealternate 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 terminatein each compartment. The MCC’s can be designedwith all external connections brought by themanufacturer to terminal blocks in the top or bottomhorizontal compartments, at added expense.e. Enclosures. Table 4-1 lists standard MCC enclosures.Type 2, drip tight, will be specified for allindoor power plant applicants; Type 3, weather resistant,for outdoor service. The other types listed inTable 4-1 should be used when applicable.4-20. Foundationsa. Transformers. The outdoor auxiliary powertransformers will be placed on individual reinforcedconcrete pads.b. Medium voltages switchgear. The medium voltageswitchgear assemblies will be mounted on flushembedded floor channels furnished by the switchgearmanufacturer prior to shipment of the gear.c. Unit substations and motor control centers.480-volt unit substation transformers and switchgear,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 berun in galvanized rigid steel conduit to the motorand switchgear terminations, although a laddertype galvanized steel cable tray system having adequatesupport may be used with conduit runoutsfrom trays to terminations.b. Control cables. Control cables will be run in an

expanded metal galvanized steel overhead tray systemwherever 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 to4-21TM 5-811-6Table 4-1. Standard Motor Control Center Enclosures.NEMA ClassificationType 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 DM3CommentsA 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 ofto meet the applicationNEC for the indicatedhazardous locations.A sheet metal case designed with welded

corners 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 bareElectrical distribution system for the installationstranded copper with connections to station taps ofoutside of the power plant is covered in TM5-811-11AFM88-9.minimum 2/0 copper.4-224-24. Battery and chargerTM 5-811-6Section Vll. EMERGENCY POWER SYSTEMa. General requirements. The dc system, consistingof a station battery, chargers and dc distributionpanels, provides a continuous and reliable source ofdc control voltage for system protection during normaloperation 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 calciurncells having pasted plates Plante or other suitablecells will be considered for use.b. Duty cycle. Required capacity will be calculatedon an 8-hour duty cycle basis taking into accountall normal and emergency loads. The dutycycle will meet the requirements of the steam generatorburner control system, emergency coolingsystems, control benchboard, relays and instrumentpanels, emergency lighting system, and all close/tripfunctions of the medium voltage and 480-volt circuitbreaker 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 emergencyseal 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 2.17the proper float and equalizing voltage on the batterywill 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 totaldc 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 enclosures,while outside the plant totally enclosed fancooled motors are used. For induced draft and forceddraft, and outdoor fan motors in the larger sizes, aously. To assure, however, that the manufacturer ofall dc operated devices is aware of the source of dcsystem voltage, the various equipment specificationswill 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 device.(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 accordancewith TM 5-811-2. The chargers maybe wall orfloor mounted, together with the main dc distributionpanel, immediately outside the battery room.e. DC distribution panel. The distribution panelwill utilize molded case circuit breakers or fuses selectedto 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 shutdown,will be fed from a separate 480-volt unitemergency power bus. A suitable emergency diesel

engine driven generator will be installed and arrangedto 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, batterycharger, boiler control system, burner controlsystem, control boards, annunciator, recorders andinstrumentation. Design of these systems will providefor them to return to operation after a briefpower outage.MOTORSweatherproof construction employing labyrinthtype enclosures for air circulation will be applied.All motors will be capable of starting at 85 percentnameplate voltage.4-23TM 5-811-64-27. Insulationa. 4000-volt motors. Motors at this voltage willbe 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 horsepowerand characteristics-thus the specification iswritten to require manufacturer of the driven machineto 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 galvanized

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 giventhe 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. Manufacturer’scurves showing copper temperature meltingvalues for high short circuit currents for a specifictime 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 supplycharacteristics including voltage, frequency,and phases must be specified.Section IX. COMMUNICATION SYSTEMS4-33. Intraplant communicationsa. General requirements. Installation of a highquality voice communication system in a power‘ plant and in the immediate vicinity of the plant isvital to successful and efficient startup, operationand maintenance. The communications system selectedwill be designed for operation in a noisy environment.b. Functional description. A description of thefeatures of an intraplant communication system isgiven below.(1) A page-talk party line system will be required.(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 nearestthe four or more handsets in use will be muted.(3) If a party wishes to break into a private conversation,all he will do is lift his handset and break4-24into the private conversation already taking place.Any number of parties will be able to participate inthe “private conversation” because the private systemis 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 oroperating rooms, the indoor handsets in the powerplant will be hook switch mounted in a metal enclosurehaving 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 variouscontrol 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 weatherpliedwith each handset to permit freedom of move- proof for durability. They will be mounted on buildmentby 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 SpeakersTwo ceiling speakers.HandsetsControl 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 RoomPlantWall speaker in lockerroom.Wall handset in locker room.Column mounted speakersas necessary to providecoverage of work areas.The required spacingwill depend upon plantlayout, equipment locationand noise levels.

Column mounted handsets,as necessary to provideconvenient access.SwitchyardCooling tower areaFuel oil unloadingarea (or coal handlingarea)Gate house (if powerMinimum 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,plant area is fenced) at personnel or vehiclegate.Note: Speakers and handsets for inside-the-power plant coverage willbe provided at every floor and mezzanine level from basement touppermost boiler platform.Courtesy of Pope, Evans and Robbins (Non-Copyrighted)4-25TM 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 providedfor 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 supply.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 regardingtype 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 positionedto provide “page” coverage; handsets will beplaced for convenience of access. For example, aspeaker 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 communicationsystems devices.4-34. Telephone communicationsAt least one normal telephone desk set will be providedin the central control room for contact by theoperators 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 telephoneconnection between the control room and thepool or connected utility dispatcher will also be provided.TM 5-811-6l.. .

.‘CHAPTER 5GENERAL POWER PLANT FACILITIES DESIGNSection l. lNSTRUMENTS AND CONTROL SYSTEMS5-1. 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 controlfunctions.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 enclosedand of the dual switchboard, duplex switchboard,dual benchboard, control benchboard, or controldesk type depending upon the size of the plantand complexity of the instruments and controls tobe mounted. When control panels have complex wiring(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 simplifycable 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 selectedusing the following criteria:(a) Space availability in the control room.(b) Number of controls and instruments to bemounted.(c) Visibility of the controls and instrumentsby the plant operators.(d) Grouping and interrelationship of the controlsand instruments for ease of operation andavoidance of operating error.b. Location of panels.(1) Control room. The various panels located inthe central control room will be arranged to minimizeoperator 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 oneunit. 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 instrumentsinto a boiler panel for all boilers and a turbinegenerator panel for all turbines whenever practicable.Usually, a separate electrical panel with mimicbus for the generators and switchgear and switchyard,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 close

to 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, feedwater,circulating water, service water and like systems),Burner management controls will be obtainedas an “insert” or subpanel which can be incorporatedinto the boiler grouping of controls and instruments.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 controls,switches and other devices which requiremanipulation by the operators will be easily accessibleand 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 permanentrecord of plant parameters is desired for eco-5-1TM 5-811-6Table 5-1. List of Typical Instruments and Devices to be Provided for Boiler Turbine Mechanical PanelMeasurementor DevicePressureTemperatureFlowNotes: (1)(2)(3)(4)Primary ElementFluid LocationSteamSteamSteamSteamFeedwater

CondensateFuel gasFuel gasFuel gasFlue gasLube OilVacuumSteamSteamSteamAir-flue gasLube OilSteamAirC02 FeedwaterFeedwaterFuel gasFuel oilBoiler drumBoiler atomizing steamTurbine ThrottleDeaerator steam spaceBFP dischargeCond. pump dischargeBoiler burnersIgniterBoiler burne sTurbine generatorCondenserTurbine throttleBoiler superheater outletTurbine extraction steamBoiler draft systemTurbine generatorBoiler main steamBoiler FD f n dischargeBoiler main supplyBoiler AttemperatorBoiler burner supplyBoiler burner supplyIncluding FD fan discharge, air inlet & outletInstrument orDevice on PanelIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicator

IndicatorIndicatorIndicatorIndicatorRecorder &totalizerRecorderRecorderRecorderRecorderRecorder &totalizerRecorder &totalizerto 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.5-2TM 5-311-6Table 5-1. List of Typical Instruments and Devices to be Provided for Boiler Turbine Mechanical Panel. (Continued)Measurement Primary Elementor Device Fluid LocationInstrument orDevice on PanelLevel FeedwaterCondensateCoalBoiler drumDeaerator, Condenser HotwellBunkerRecorderRecorderIndicator orpilot lightsCells as requiredConductivity Condensate (4) RecorderManual- - -automaticstationsCombustion control system,condensate and feedwatercontrol systems, steamattemperator, and as requiredEach station

M o t o r c o n t r o l - -switchesStarters for draft fans,BF pumps, condensate pumps,vacuum pumps, fuel pumps,lube oil pumps, turninggear, turbine governor andlike itemsEach switchAmmeters - - Major motors (high voltage): draft fans, BF pumpsIndicatorAlarms - - Points as selected forsafe operationAnnunciatorsection forboiler turbinepanelBoiler burner system Insert on boilerturbinepanelBurner - -ManagementIndicating - As required to start upand monitor boiler andturbine.Each lightNotes: See firstCourtesy of Pope,page of Table.5-3TM 5-811-6Table 5-2. List of Typical Instruments and Devices to be Provided for Common Services Mechanical PanelPrimary ElementFluid LocationInstrument orDevice on PanelMeasurementor DeviceMain steam header(l)

Extraction steam header(l)Supply to plantsupplyBurner pump dischargeDischarge headerService waterClosed cooling waterFire systemInstrument airService airAtmosphere

RecorderIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorBarometerPressure SteamSteamFuel gasFuel oilFuel oilCirc. waterWaterWaterWaterAirAirAir.Extraction steam header(l)supplyAs requiredTemperature SteamFuel OilVariousViscosityFlowFuel oilSteamSteamPump and heater setsExtraction to processRecorderRecorder &totalizerRecorder &totalizerFuel gas Supply to plantFuel oilCondensateTank(s)Tank(s)IndicatorIndicatorLevel

ManualautomaticstationsPressure reducing station,misc. air operated devices- - Each stationMotor CW pumps, cooling tower Each switchcontrolswitches- -fans, air compressors,condensate transfer pumps,service water pumps, fueltransfer pumps, and likei t ems:(2)For header systems onlyMulti-point electronic type5-4Table 6-2,TM 5-811-6List of Typical Instruments and Devices to be provided for Common Services Mechanical Panel. (Continued)Measurement Primary Elementor Device Fluid LocationAmmeter - Major (high voltage)motors; CW pumps, coolingtower fansAlarms - - Points as selectedfor safe operationIndicating - -.‘As required to start-upand monitor principalcommon systemsCourtesy of Pope, Evans and Robbins (Non-Copyrighted)nomic or engineering accountability purposes, recorderswill be provided.d. Ventilation. All panels which house heat producinginstruments will be ventilated or air conditionedto prevent overheating of the instruments.For .panel~in the central control room, this will beaccomplished by having a filtered air intake and mechanicalexhaust 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 ventilation.e. Illumination. In a central control room, thebest illumination is a “light ceiling” with diffuser

type 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 excessiveillumination tends to wash out displays. Inareas with electronic digital controls with CRT displays,the level of general illumination will be maintainedat 15- to 25-foot candles. Local panel illuminationwill 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 maybe pneumatic, ac or dc electronic, electronic digital,combination pneumatic and electronic, or hydraulic.Instrument orDevice on PanelIndicatorAnnunciatorsection forcommon panelEach lightMechanical-hydraulic and electro-hydraulic systemswill be utilized in connection with turbine generatorspeed governing control systems. Pneumatic controlswill 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, modulatingtype of operation. For plants where the arrangementis dispersed and precision is required,electronic controls and instruments will be providedin lieu of the pneumatic type because of the sluggishnessof pneumatic response where long distancesare involved. Electronic digital controls haverecently become economically competitive withanalog pneumatic and electronic controls and offerthe advantage of’ ‘soft-wired” control logic and programmableversatility. 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, designed

to hold steam pressure within plus or minus 1 percentof 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.)5-5TM 5-811-6Table 5-3. List of Typical Instruments and Devices to be Provided for Electrical (Generator and Switchgear) PanelMeasurement Instrument oror Device Device on PanelFor Each GeneratorGenerator gross outputPower FactorGenerator ac currentGenerator ac voltsGenerator dc currentGenerator dc voltsGenerator ac current(for individual phases)Generator ac volts(for individual phases)GeneratorsynchronizingGeneratorsynchronizingOil circuit breakert r ipGenerator fieldbreakerVoltage regulatorVoltage regulatorVoltage regulatorVoltage regulatorUnit governorUnit tripUnit resetUnit speedUnit temperaturesGenerator alarmsMiscellaneousSupervisoryWattmeterP.F. MeterAC ammeterAC voltmeterDC ammeterDC voltmeter

AC ammetercontrol switchAC voltmetercontrol switchSynchronizingcontrol switchSeparate panelsectionOCB 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, eccentricity5-6Table 5-3.TM 5-811-6List of Typical Instruments and Devices to be Provided for Electrical (Generator and Switchgear) Panel. (Continued)

Measurement Instrument oror Device Device on PanelFor Switchgear2.4 or 4.16 kV unitswitchgear2.4 or 4.16 kVcommon switchgear2.4 or 4.16 kVfeeders480 V unit switchgear480 V commonswitchgear480 V feedersSwithgear ac currentSwitchgear ac voltsSwitchgear alarmsMiscellaneousIntraplantcommunicationBreaker controlswitchBreaker controlswitchBreaker controlswitchesBreaker controlswitchBreaker controlswitchBreaker controlswitchesAC ammetersAC voltmetersAnnunciatorNotes: (1) If a highbe required.IndicatinglightsTelephone handsetNotesIf higher plant auxiliaryvoltage requiredIf requiredFor plant auxiliariesand/or for outside distributioncircuits as required.For plant auxiliaries asrequiredOne for each switchgearwith switchOne for each switchgear

with switchWith test and reset pushbuttonsFor switches and as requiredvoltage 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 bench- board or on a separate panel.Courtesy of Pope, Evans and Robbins (Non-Copyrighted)5-7TM 5-811-6Table 5-4. List of Typical Instruments and Devices to be Provided for Diesel Mechanical PanelMeasurement Primary Elementor Device Fluid LocationPressure Fuel gasFuel oilLube oilLube oilComb. airComb. airCooling waterStarting airTemperature ExhaustCooling waterCooling waterLevel Jacket waterLube OilFuelFuelMotor -controlswitches(or pushbuttons)Alarms - -Supply to engineSupply to engineSupply to enginesupply to turbochargerTurbocharger dischargeFilter downstreamPump dischargeAir receiverEach cylinder andcombined exhaustSupply to engineReturn from engineSurge tankSump tankBulk storage tankDay TankJacket water pumps,radiator (or cooling

tower) fans, fuel oilpumps, centrifuges,and like auxiliariesLow lube oil pressure,low jacket water pressure,high lube oil temperature,high jacket watertemperature, high and lowday tank levelsNotes: (1) With selector switch.Courtesy of Pope, Evans and Robbins5-8(Non-Copyrighted)Instrument orDevice on PanelIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicatorIndicator(l)IndicatorIndicatorIndicatorIndicatorIndicatorIndicatorEach switchAnnunciatorTM 5-811-6.

c. Feedwater regulation. A three element feedwaterregulator system will be provided for steampower plant service. Such a system balances feedwaterinput to steam output subject to correctionfor drum level deviations caused by operating pressurevariations (drum swell).d. Attemperator control system. Each powerplant steam generator will have superheat (attemperator)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 attemperatorsystem having a controller with a fast

response, derivative feature will be provided. Thistype of controller anticipates the magnitude of systemdeviations from the control set point in accordancewith the rate of change of superheat temperature.Automatic positive shutoff valve(s) will be providedin the desuperheating water supply line upstreamof 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 condensateor 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 cascadedto 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 differentialbetween heaters being cascaded becomes verysmall. The secondary valve frequently dischargesdirectly to the condenser. Such a complexity of controlsfor heater drains is necessary to assist in preventingproblems 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 tothe 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 signalwill open an automatic recirculation valve locatedin the piping run from the pump discharge tothe deaerator. This recirculation line poses minimumflow 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 excess

of pump minimum flow, the recirculation valvecloses. The operator will be able to open the recirculationvalve manually with a selector switch onthe control panel. Designs will be such as to precludeaccidental 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, pressurereducing, fuel oil heating, and other miscellaneouspower 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 action.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. Instrumentsgenerally fall into two classifications—directreading and remote reading.(2) Direct reading instruments (e.g., thermometers,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 conventionalmercury type or of the more easily read(but less accurate) dial type. Type selected will dependon accuracy required. Pressure gages for steamor water service will be of the Bourdon tube type.(3) Remote reading instruments (recorders, integrators,indicators and electrical meters) will bemounted on panels in the central control room.These instruments will have pneumatic or electronictransmission circuits. Sometimes the same transmittersutilized for control system service can beutilized for the pertinent remote reading instrument,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 ApplicationsElement Type Control InstrumentMotionChemicalCentrifugal

Vibrating reedRelative motionPhoto-electric cellFlue gas analysisWater analysisSpeed governs TachometerSpeed governs Tachometer- - StroboscopeLimit control Counter- .- -- -- -- -- -Combustion OrsatcontrolWater - -treatmentFuel analysis - - - -- - Hydrometer for liquids- - Scales for solids- - Hygrometer- - Ringelman chartCombustion C02 meterCombustion Btu meterPhysical Specific gravityWeightHumiditySmoke densityGas densityHeat- -- -- -Combination ofwater flow andtemperaturedifferentialElectricandelectronicPhoto-conductivity Flame safeguardPhoto-electric cellSmoke densityElectricconductivityProbes Alarm pH of waterOil in condensateSource: NAVFAC DM3Table 5-5. Sensing Elements for Controls and Instruments. (Continued)

Common ApplicationsElement Type Control InstrumentPressure MechanicalVariable electricresistance due tostrainVariable electricresistance due tovacuumVariableelectronicresistance due tovacuumLevel VisualFloatDifferentialpressureHydrostaticBourdon tubeBellows ordiaphragmManometersPressure transducerThermocoupleVacuum tube- -Buoyant floatDisplacementManometerDiaphragm in tankbottomPressure, draftand vacuumregulatorsProcess pressureregulatorVacuumregulatorVacuumregulator- -Mechanicallevel regulatorPneumatic floatregulatorLevel regulatorLevel regulatorPressure gageLow pressure,vacuum gagesBarometer

Potentiom.draft and100 to 50,000 psiHigh vacuum 1-7000microns HgHigh-vacuum down to0.1 micron HgGage stickTransparent tubeTape connected to floatTorqueRemote level gageTank levels withviscous fluidsTable 5-5. Sensing Elements for Controls and Instruments. (Continued)Element TypeTemperature Solid expansionFluid expansionThermocoupleElec. resistanceof metalsOpticalPyrometerRadiationpyrometerFusionBimetalMercury or alcoholMercury in coilOrganic liquidOrganic vaporliquidGasCopper-constantanIron-constantanChromel-alumelPlat.-plat. rhodiumCopperNickelPlatinumComparative radiantenergyRadiant energy onthermocouples- -Common ApplicationsControl InstrumentOn-offthermostats- -Temperature

regulatorsTemperatureregulatorsTemperatureregulators- -Dial therm. - 100 to 1000 FGlass therm.- 38 to 750 FDial therm. - 38 to 1000 F125 to 500 F- 40 to 600 F- 400 to 1000 FLow voltage - 300 to 600 FO to 1400 F600 to 2100 F1300 to 3000 FPotentiom. - 40 to 250 F- 300 to 600 F- 300 to 1800 FPotentiom. - 800 to 5200 FFlame safeguard Potentiom. - 200 to 7000 FSurfacetemperatureregulation- - Pyrom.cones -1600 to 3600 FCrayons - 100 to 800 FTM 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, exceptfor multi-point electronic dot printing recorderswhich will be full size.b. Selection. The monitoring instruments for anycontrol system will be selected to provide the necessaryinformation required for the control roomoperator to be informed at all times on how the controlledsystem 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 supplementsthe operator’s physical senses and notifies him bothaudibly and visually when trouble occurs so thatproper steps can be taken to correct the problem.b. General. The alarm system will be both audibleand visual. The sounding of the alarm will alert theoperators that a problem exists and the visual lightin the pertinent annunciator window will identify

the problem. Annunciator systems shall provide forthe visual display to be distinguishable betweennew alarms and previous alarms already acknowledgedby the operator pushing a button provided forthis purpose. New alarms will be signified by a flashinglight, whereas acknowledged alarms will be signifiedby a steady light. Alarm windows will be arrangedand grouped on vertical, upper panel sectionswith 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 SYSTEMS5-6. 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 ventilationfor fresh air supply to, as well as exhaustfrom, the main operating areas, A filtered outsideair supply, with heating coils and recirculation optionfor 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 positiveinside 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 furnishinglarge air quantities to “hot spots. ” Theturbine room will receive a substantial quantity offresh air, supplemented by air from lower levels risingthrough operating floor gratings. For hot, dryclimates, evaporative cooling of ventilation air supplywill 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 quantitydesired will be provided. Battery rooms willhave separate exhaust systems designed in accordancewith TM 5-811-21AFM 88-9/2. It may beeconomical to remove heat from hot spots with local5-14ducted exhaust systems to prevent heat from beingcarried into other areas. All exhaust and supplyopenings will be provided with power operated

dampers, bird screens, and means for preventing entranceof rain, sleet and snow.(3) Heating. As much heating as practicablewill be supplied via the central ventilation supplysystem, which will be designed so that maximum designair flow can be reduced to a minimum requiredfor winter operation. Heat supplied by the ventilationsystem 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 operatingcenter 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 computers.Unattended control rooms may not requirecomfort conditions but have temperature limits asrequired by the equipment housed in the room. Controlsystem component manufacturers will be consultedto determine the operating environment requiredfor equipment reliability.(2) Intermediate season cooling using 100 percentoutside 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 negativepressure 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 recirculationheating systems to meet applicable codes; exhaustwill be installed. System will be independentof 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 laboratorieswill be air conditioned for human comfort inaccordance with TM 5-810-l/AFM 88-8/1. Exhaustwill be provided where required for laboratoryhoods or other special purposes.Section lll. POWER AND SERViCE PlPlNG SYSTEMS5-9. introductiona. General. Power plant piping systems, designedto transfer a variety of fluids (steam, water, compressedair, fuel oil, lube oil, natural gas) at pressuresranging from full vacuum to thousands of psi,will be engineered for structural integrity and economyof 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 PressurePower 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 limitations.5-10. Piping design fundamentalsDesign of piping system will conform to the followingprocedure: 1Ia. 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 appropriatesections of ASME Section I and ANSI B31.1.Other requirements for welding qualification andpressure vessel design are set forth in ASME SectionsVIII 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 withstructures, ductwork, equipment and electric services.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 simultaneousapplication of seismic loads, where applicable.Computer analysis will be used for majorthree plane piping systems with multiple anchors.5-11. Specific system design considerations

a. Steam piping. In all steam systems, provisionswill be made for draining of condensate before startup,during operation and after shutdown. Steamtraps will be connected to low points of the pipelines.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 vibration(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 temperaturesremain below 1200F. at 80oF. still air ambient.Provide anti-sweat insulation for all lines which operatebelow ambient temperatures. Protect all insulationagainst weather (or wash down water if indoors)and mechanical abuse.I

5-1524-30TM 5-811-6Table 5-6. Piping Codes and Standards for Power Plants. (Continued)Sponsor Identification TitleANSI B36 series Iron and steelpipeB16 series Pipe, flangesand G37.1 and fittingsASTMB18 series Bolts and nuts- - Testing materialsMajor - -equipmentmanufacturers(turbines, pumps,heat exhangers, etc.)- -CoverageMaterials and dimensions.Materials, dimensions,stresses and temperaturepressureratings.Bolted connections.Physical properties of

materials specified inabove ASME and ANSIstandards.Allowable reactions andmovements on nozzles frompiping.Courtesy of Pope, Evans and Robbins (Non-Copyrighted)Section IV. THERMAL INSULATION AND FREEZE PROTECTION5-12. 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 varioussurfaces, piping, vessels, ductwork, and machineryfor 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 materials,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 nomenclatureand characteristics of conventional thermal insulations.b. Restrictions on asbestos. Asbestos insulation,or insulations containing loose, fibrous, or free asbestosare not to be used.c. Maximum temperatures. Each type of insulationis suitable for use at a specified maximum temperature.Design will be such that those maximumswill not be approached closely in ordinary applications.All high temperature insulations are more expensiveand more fragile than lower temperatureproducts and, in general, the least expensive materialwhich is suitable for the temperature exposurewill be selected. Where substantial total insulationthicknesses of 6 inches or more are required, economicsmay be realized by using two layers of differentmaterials using high temperature material closeto the hot surface with cheaper low temperature materialon the cold side.d. Prefabricated insulation. A major part of total

insulation cost is field labor for cutting, fitting and5-170.64 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 laminatedasbestos paper:4 ply per in.6 ply per in.8 ply per in.30030030012008002001500190060011-1315-1718-20-- 0.54 0.57— 0.49 0.51- - 0.47 0.490.620.590.57-------- --- ---- --Calcium silicate 11 -- -- 0.36 0.40 0.55 -- --Cellular glassCork (without addedbinder)Diatomaceous silica97-100.37 0.39 0.410.27 0.28 0.290.480.30--

---- ---- --22250.640.700.66 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. (finefiber resin bonded)High temp. blankettype(metal reinforced)200450120015 0.28 0.30 0.33 0.39 -- -- -- --.3 0.22 0.23 0.24 0.27 0.31 — -- --24-30TM 5-811-6. .,

installation. For large areas or long piping runs, substantialsavings may be realized by factory forming,cutting or covering. Valves and pipe fittings, especiallylarge ones, may be economically insulatedwith factory made prefabricated shapes. Equipmentrequiring periodic servicing will be equipped with removable,reusable insulation.e. Miscellaneous materials. Complete insulationsystems include accessory materials such as fasteners,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 resistanceto moisture penetration and damage, and for

avoidance of corrosion where wet insulation materialsmay 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 themost important function of insulations. Substantialinvestments for thermal insulation warrants carefulselection and design.b. Durability and deterioration. Most conventionalinsulating 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 orsafety 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 protectioninsulations will be selected to insure that outsideinsulation 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 willbe applied to refrigeration equipment, piping andductwork, cold water piping, and to air ducts bringingoutside air into power plants and HVAC systems.b. Criteria. In most cases, cold surface insulationswill be selected to prevent icing or condensation. Extrainsulation thickness is not normally economicalfor heat absorption control.5-18. Economic thicknessa. General. Economic thickness of an insulationmaterial (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 ETI

calculations 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 calculationwill indicate at least one uneconomical thicknesson 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 thicknesses.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 particularheat sources or losses, depreciation andmoney cost rates, costs of complete installed insulationsystems, 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 arecombinations of insulation and heat source materialsarranged 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 protection.Insulation will be such as not to be damaged by5-21TM 5-811-6Courtesy of Pope, Evans and Robbins (Non-Copyrighted)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 mayc. 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 insulaancefor wind conditions will be made. tion under the combination of design ambient andd. Heat sources. Electrical heating tape will gen- pipe line surface temperature.Section V. CORROSION PROTECTION5-20. 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 PROTECTION5-21. 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 systemsguard the equipment and personnel. Various sys- and their general application in power plants. Refertemswill be installed as required to suit the particu- ence will be made to TM 5-812-1 for specific re-5-22TM 5-811-6quirements for military installations. Further detailsmay be found in the National Fire ProtectionAssociation (NFPA) Codes and Standards.5-22. Design considerationsa. Areas and equipment to be protected. The followingare some of the major areas which will be investigatedto determine the need for installing fireprotection facilities.(1) Main and auxiliary transformers.(2) Turbine lubricating oil system including theoil reservoir, oil, cooler, storage tanks, pumps andthe turbine and generator bearings.(3) Generator hydrogen cooling system includingcontrol 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 storagetank.(6) Office and records rooms.(7) Control room.(8) Relay, computer, switchgear and batteryrooms.(9) Shops, warehouses, garages and laboratories.(10) Personnel locker rooms, lunch rooms andtoilets.b. Types of systems. The following is a brief descriptionof the various types of systems and theirgeneral application.(1) Water spray and deluge system. This type ofsystem consists of open type sprinkler heads attachedto a network of dry (not water filled) pipingwhich is automatically controlled by a fully supervisedfire detection system which also serves as afire alarm system. When a fire is detected, an automaticdeluge valve is tripped open, admitting waterto the system to discharge through all of the sprinklerheads. The system may be subdivided into separatelycontrolled headers, depending on the area tobe covered and the number of sprinkler heads required.

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 waterspray deluge system, except that it contains closedtype sprinkler heads which only discharges waterthrough those sprinklers whose fixed temperatureelements have been opened by the heat from a fire.This system will be utilized for the turbine and generatorbearings and for the above water spray delugesprinkler system areas where more localizedcontrol is desired.(3) Wet pipe sprinkler systems. This wet pipesystem utilizes a water filled piping system connectedto 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 systemswill be used are heated shops, garages, warehouses,laboratories, offices, record rooms, lockerrooms, lunch rooms and toilets.(4) Foam extinguishing systems. Foam fire extinguishingsystems utilize a foam producing solutionwhich 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 coherentfloating blanket over flammable and combustibleliquids which extinguish (or prevent) a fireby 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 storageproportioningtank to mix the foam concentratewith a water stream from a fire water header. A speciallydesigned hand play pipe, tank foam chamberor open sprinklers aspirate the air to form the foamto blanket the area to be protected. The deluge waterentry valve to the system may be manually orautomatically opened. Foam systems will be installedin power plants to protect fuel oil areas,lubricating oil systems, and hydrogen seal oil systems.(5) Carbon dioxide extinguishing systems. This

type 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 actuatedarea. Carbon dioxide extinguishing systemsof this total flooding type will be utilized to extinguishcoal bunker fires and for electrical hazardareas such as in battery rooms, electrical relayrooms, switchgear rooms, computer rooms and withinelectrical cabinets.(6) Halogenated fire extinguishing systems.This type of system utilizes specially designed removableand rechargeable storage containers containingliquid HaIon at ambient temperature whichis superpressurized with dry nitrogen up to 600 psig5-23TM 5-811-6pressure. These manifolded containers are locatedas closely as possible to the hazards they protectand include connecting piping and discharge nozzles.There are two types of systems. The total floodingsystem is arranged to discharge into, and fill tothe proper concentration, an enclosed space or an enclosureabout the hazard. The local application systemis arranged to discharge directly onto the burningmaterial. Either system may be arranged to protectone or more hazards or groups of hazards by soarranging the piping and valves and may be manuallyor automatically actuated. Halon is a colorlessand odorless gas with a density of approximatelyfive times that of air, and these systems must includewarning 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 applicationof 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 andactuated; however, some special conditions may requiremanual actuation on an alarm indication. Amanual actuation will be included to provide foremergencies arising from the malfunction of an automaticsystem. The primary element of any fire

protection system is the fire detection sensing devicewhich is actuated by heat detectors which detectabnormally high temperature or rate-of-temperaturerise, 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 assuredsupply 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 elevatedhead 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.5-24TM5-811-6CHAPTER 6GAS TURBINE POWER PLANT DESIGN6-1. 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 turbineor 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 premium—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 efficientgenerating 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 economicallyused to generate additional power and thermalenergy for process or space heating.6-2. Turbine-generator selection

a. Packaged plants. Gas turbines are normallypurchased 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 powerplant will include the prime mover, combustionsystem, starting system, generator, auxiliaryswitchgear and all turbine support equipment requiredfor operation. This equipment is usually“skid” or base mounted. The only “off base” oradditional auxiliaries normally required to supplementthe package are the fuel oil storage tanks,transfer pumps and oil receiving station, distributionswitchgear, step up transformer and switchyard,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 reconsiderationof the number of units or the totalplant capacity,(2) Initial selection of the gas turbine unit beginsusing the International Standards Organization(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 outletlosses to be zero. Initially, ISO ratings will be reduced15 percent for typical applications, which willfurther be refined to reflect actual site and installationconditions. The four variables which will be consideredin 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 reductiondue 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 obtainedfrom TM 5-785. The design temperature selectedis normally the 2 1/2 percent dry bulb temperature,although the timing of the load curve peak willalso be considered. Unless the choice of equipment is

tight, there is usually sufficient overload capabilityto carry the unit during the 2 1/2 percent time of highertemperature. Another temperature related selectionparameter is icing. Icing is caused when theright combination of temperature and humidity levelsoccurs, and is manifested by ice formation on thedownstream side of the inlet filters or at the compressorsbell mouth intake. Chunks of ice can besucked in the compressor with possible blade damageresulting. Icing occurs when ambient temperaturesare in the 350 to 420F. range and relative humidityis high. This problem will be avoided by recirculatinghot 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 performancevariable, and one over which the designer has6-1TM 5-811-6considerable control. Increases in the inlet air frictioncause 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 limitationsand economics will permit. Additional ductworkcosts will be quickly amortized by operatingfuel savings. Dust, rain, sand and snow will be preventedfrom 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 nearbyboiler 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 pressurelosses. 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 turbine.

The heavy oil will have to be cleaned up to reducecorrosive salts of sodium, potassium, vanadium,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 requirement.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 frequentlysold as complete packages which include all componentsnecessary 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 performanceresponsibility y.b. Outdoor vs. indoor.(1) Outdoor. Outdoor units can be divided intotwo sub-types.(a) The package power plant unit is suppliedwith the principal components of the unit factory assembledinto three or more skid mounted modules,each with its own weatherproof housing the separatemodules 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 silencerand filters, exhaust silencer, fuel tanks, unitfuel skid, and unit auxiliary transformer which areconnected by piping and cables to the main assemblyafter 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 prefabricatedbuilding for quick field assembly into a closurefor the main power plant components.(c) Outdoor units to be provided with all components,auxiliaries and controls assembled in allweathermetal enclosures and furnished completefor operation will be specified for Class “B” and “C”power plants having a 5-year anticipated life and requiringnot 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 toprovide 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 insideor outside. Unit and distribution switchgearand motor control centers will be indoors as in a conventionalsteam power plant. Figure 6-1 shows atypical indoor unit installation with the prime movermounted below grade floor level.6-5. Waste heat recoveryWaste heat recovery will be used wherever cost effective.If the turbine unit is to be used only intermittently,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 example.Care must be exercised due to the high exhaustgas temperature. It may prove feasible toflash steam through the jacket of a small heat exchanger.In the event that a long term operation isindicated, the cost trade off for heat recovery equipment is enchanced, but still must be considered asan auxiliary system. It will take a sizable yearlyload to justify an exhaust gas heat recovery boiler.6-2, TM 5-811-6

rAIR INTAKE WET CELL

WASHER OR FILTER I L.1.

.

L.,

‘Lw wTA

TRsI2s’-0’

I

STACKExHAuST\ A

I Q~ n 1 n Ii,1 ,

,! r l?$dLEJ%/ l-w

1 I &~‘ a\:. ;r .-. . ,.

... . ,------ “’-’”A’&?yBA.s.E. .M. ENTk~;fllNTi4KE FLOOR.7. -...LONGITUDINAL SECTION “A” -“A”NAVFAC DM3Figure 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 completepower plant requiring only adequate site preparation,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 agas turbine power plant, including the generator,switchgear, switchyard, transformers, relays andcontrols. Chapter 2 describes the pertinent civil facilities.c. Scope. The scope of a package gas turbine generatorfor purchase from the manufacturer will includethe following(1) Compressor and turbine with fuel and combustionsystem, lube oil system, turning gear, governor,and other auxiliaries and accessories.(2) Reduction gear.

(3) Generator and excitation system.6-3TM 5-811-6(4) AC auxiliary power system includingswitchgear and motor controls.(5) DC power system including battery, charger,and inverter if required.(6) External heat rejection equipment if required.(7) All mechanical and electrical controls.(8) Diesel engine or electric motor starting system.(9) Unit fuel skid (may be purchased separatelyif desired).(10) Intake and exhaust ducts.(11) Intake air filters.(12) Acoustical treatment for intake and exhaustducts and for machinery.(13) Weatherproof housing option with appropriatelighting, heating, ventilating, air conditioningand fire protection systems.6 - 4CHAPTER 7DIESEL ENGINE POWER PLANT DESIGN7-1. Enginesa. Diesel engines have higher thermal efficienciesthan other commercial prime movers of comparablesize. Diesel engine-generators are applicable to electricloads. from about 10 to 5000 kilowatts. Dieselengine-driven electric generator sets are divided intothree general categories based on application as follows:(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 economicsand practicality of purchasing the generatorsseparately, recognizing that the capability forreliable operation and performance of the units are

sacrificed if engine and generator are bought fromtwo sources.c. Engines and engine-generator sets are normallyprovided 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 engine.(6) Electrical switchgear, stepup transformer, ifrequired, and connection to distribution wiring.(7) Facilities for engine maintenance, such ascranes, hoists and disassembly space.(8) Compressed air system for starting, if required.e. Generator design criteria are provided inChapter 4.7-2. Fuel selectionA fuel selection is normally made according to availabilityand economic criteria during the conceptualdesign. Fuels are specified according to ASTM, Federaland 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 specificationsparallel ASTM Grades 1-D and 2-D, respectively.c. Jet Fuel Grade JP-5 (Military SpecificationMIL-T-5624).d. Marine Diesel (Military Specification MILF-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 temperaturesbelow 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 for

burning these viscous fuel oils.7-1TM 5-811-6Section ll. BALANCE OF PLANT SYSTEMS7-3. GeneralBalance of plant systems are those which must beprovided and interfaced with a packaged diesel ordiesel-generator set to provide an operational generatingunit.7-4. Cooling systemsa. Water-to-water systems. Jacket water and lubeoil cooling heat exchangers are cooled by a secondarycirculating water system. Normally, a recirculatingsystem will be used. Heat is dissipated tothe atmosphere through an evaporative, mechanical-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 exchangerscan 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 exhaustsystemsa. Purpose. The functions of the intake and exhaustsystems 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 intakeair 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 silencermay be combined.

c. Exhaust. The exhaust system consists of amuffler and connecting piping to the atmospherewith suitable expansion joints, insulation, and supports.In cogeneration plants, it also provides forutilization of exhaust heat energy by incorporating7-2a waste heat boiler which can be used for space heating,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 attenuationwith minimum pressure loss.7-6. Fuel storage and handlinga. Storage requirements.(1) Aboveground fuel storage tanks with a minimumcapacity for 30 days continuous operation willbe provided for continuous and standby dutyplants. Fuel storage shall be designed to the requirementsof NFPA 30. A tank with 3 day storage capacitywill 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 transferpumps 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 reliability.Pipeline strainers and filters will be provided toprotect the fuel pumps and engine injectors fromdirt. Strainers and filters will not pass particles largerthan half the injector nozzle opening.7-7. Engine room ventilationAbout 8 percent of the heating value of the fuel consumedby the engine is radiated to the surroundingair. It is essential that provision be made for removalof 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 provided.If engines are equipped with water cooledheat exchangers, a separate ventilation system will

be provided. The approximate ventilation rate maybe determined by the following formula:1,000 x HPCFM = Twhere:HP =T =maximum engine horsepowerallowable temperature rise, ‘F.TM 5-811-6Provision 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 BUILDING7-8. 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 foundationa. 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 designer,the bearing capacity and suitability of thesoil on which the foundation will rest will be determined.Modification of the manufacturer’s recommendedfoundation may be required to meet specialrequirements of local conditions. Modifications requiredmay include:(a) Adjustment of the mass.(b) Additional reinforcing steel.(c) Use of a reinforced mat under the regularfoundation.(d) Support of the foundation on piles. Pilingmay require bracing against horizontal displacement.‘ (2) The engine foundation will extend below thefootings of the building and the foundation will becompletely isolated from the walls and floors of thebuilding. The foundation block will be cast in a single,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 foundationblock.b. Vibration mounts.(1) For small engine installations where there isa possibility y of transmission of vibration to adjacentareas, the engine foundations will be adequately insulatedby gravel, or the engine mounted on vibrationinsulating material or devices. Vibrationmounts for larger engines become impractical and

foundation mass must be provided accordingly.(2) Skid mounted generating units will be suppliedwith skids of sufficient strength and rigidity tomaintain proper alignment between the engine andthe generator. Vibration isolators, either of the adjustablespring or rubber pad type, will be placed betweenthe unit skid and the foundation block to minimizethe transmission of vibrations.7-10. Buildinga. Location.(1) A diesel engine power plant has few limitationsregarding location. Aesthetically, an architecturallyattractive building can enclose the equipmentif 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 followingwhen 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 machineryfoundations.(e) Space available for future expansion.(f) Proximity to potential users of enginewaste heat.(g) Availability of water supply for coolingsystems.b. Arrangement.(1) In designing the power plant building, a generalarrangement or plant layout will be designed forthe major components. The arrangement will facilitateinstallation, maintenance and future plant expansion.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 arrangement,provide for the location of the following, as requiredby the project scope:(a) Office space.(b) Lunchroom and toilet facilities.(c) Engine panels, plant and distributionswitchgear, 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 easy7-3TM 5-811-6and economical. The engine bay will be high enoughfor a motorized, overheat traveling crane. The crane,if economically feasible, will be sized for maintenanceonly. The switchgear will be located at thegenerator end of each unit, permitting the shortestpossible wiring between the switchgear and generators.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.U.S. Army Corps of EngineersFigure 7-1. Typical diesel generator power plant.7-4TM 5-811-6CHAPTER 8COMBINED CYCLE POWER PLANTSSection 1. TYPlCAL PLANTS AND CYCLES8-1. Introductiona. Definition. In general usage the term ‘ ‘combinedcycle power plant” describes the combinationof gas turbine generator(s) (Brayton cycle) with turbineexhaust waste heat boiler(s) and steam turbinegenerator(s) (Rankine cycle) for the production Ofelectric power. If the steam from the waste heat boileris used for process or space heating, the term "cogeneration”is the more correct terminology (simultaneousproduction of electric and heat energy).b. General description.(1) Simple cycle gas turbine generators, whenoperated as independent electric power producers,are relatively inefficient with net heat rates at fullload of over 15,000 Btu per kilowatt-hour. Consequently,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 kilowatthourand are relatively expensive to install and operate.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 superheatedsteam. 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 kilowatt-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 areexpensive. Heavier distillates and residual oils arealso expensive as compared to coal.8-2. Plant detailsa. Unfired boiler operation. For turbines burningnatural 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 simplegas 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 firingpermits increasing steaming of the waste heatboiler. Burners will be installed between the gas turbineexhaust and the waste boiler to elevate the exhaustgases to the heat absorption limitations of thewaste heat boiler. Supplementary burners also permitgeneration when the gas turbine is out ofservice.c. Other types of combined cycle plants. Variationsof combined cycle plants areas follows:(1) Back pressure operation of the steam turbine.This may include either unfired or fired boileroperation. The steam turbine used is a non-condensingmachine 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 extractionsteam turbine permits extraction steam flow tobe matched to the steam demand. Varying amountsof steam can be used for heating or process purposes.Steam not extracted is condensed. This type

of steam turbine will only be used when electrical requirementsare very large (see Chapter 1).Section Il. GENERAL DESIGN PARAMETERS8-3. Background turbine and steam turbine power plants. The wasteA combined cycle power plant is essentially com- heat boiler is different in design, however, from aprised of standard equipment derived from both gas normal fossil fueled boiler. Feedwater heating is8-1TM 5-811-6usually less complex. Power plant controls musttake into account the simultaneous operation of gasturbine, boiler and steam turbine.8-4. Design approacha. 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. Variationsin gas turbine generator output affect the outputfrom the steam turbine generator unless supplementaryfuel is fired to adjust the temperature. Supplementaryfuel 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 loadsfor a combined cycle include:(a) Varying amount of fuel to a gas turbinewill 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 turbine.(b) Some supplementary firing may be usedfor a combined cycle power plant full load. Supplementaryfiring is cut back as the load decreases; ifload decreases below combined output when supplementaryfiring is zero, fuel to the gas turbine is alsocut back. This will give somewhat less efficiency at

combined 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 theload decreases with load-following between shutdownsteps by any or both of the above methods.(d) Installation of gas dampers to bypassvariable amounts of gas from turbine exhaust directlyto atmosphere. With this method, gas turbineexhaust and steam temperatures can be maintainedwhile steam flow to steam turbine generator is decreasedas 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 astandby forced draft fan, steam can be producedfrom the boiler while the gas turbine is out for maintenance.This plan allows the greatest flexibilitywhen there is only one gas turbine-boiler-steam turbinetrain. It does introduce equipment and controlcomplication and is more costly; and efficiency decreasesas greater quantities of exhaust gas are bypassed to atmosphere.(2) Boiler design.(a) Waste heat boilers must be designed forthe greater gas flows and lower temperature differentialsinherent 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 turbineor as supplementary fuel, is residual oil, baretubes should be used in the boiler with extended surfacetubes used in the economizer only. This increasesthe boiler cost substantially but will precludetube pass blockages. Soot blowers are requiredfor heavy oil fired units.(3) Feedwater heating and affect on steam generatordesign.(a) Because of the requirement for relativelylow temperature feedwater to the combined cycleboiler, usually only one or two stages of feedwaterheating are needed. In some cycles, separate economizercircuits 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 cogeneration

combined cycles will be installed. A typicalcycle diagram is shown in Figure 8-1.(4) Combined cycle controls. There is a widevariation in the controls required for a combined cycleunit which, of course, are dependent on the typeof unit installed. Many manufacturers have developedtheir own automated control systems tosuit the standardized equipment array which theyhave developed.8-2TM 5-811-6.*8-3TM 5-811-6APPENDIX AREFERENCESGovernment PublicationsCode of Federal Register10 CFR 436AFederal SpecificationsVV-F-800l= Department of DefenseDOD 4270.1-MArmy RegulationsAR 11-28Air Force RegulationsAFR 178-1Military SpecificationsMIL-T-5624LMIL-F-16884CMIL-P-17552DPart 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 Management.Turbine Fuel, Aviation, Grades JP-4 and JP-5.Fuel Oil, Diesel, Marine.Pump Units, Centrifugal, Water, Horizontal; General Service and BoilerFeed: 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, andChap. 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, 3A-1TM 5-811-6TM 5-822-6/AFM 88-7,Chap. 1TM 5-822-7/AFM 88-7,Chap. 8Rigid 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 SynchronousGenerators.C57.12.1O Requirements for Transformers, 230,000 Volts and Below, 833/958Through 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. 08854100 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. 10017

SM 12 Direct-Connected Steam Turbine Synchronous Generator Units, AirCooled.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.0221030 Flammable and Combustible Liquids Code.70 National Electric Code.General Electric Company, Lynn, MA. 0910GEK 22504 Standard Design and Operating Recommendations to Minimize WaterRev. D. Induction in Large Steam Turbines.Westinghouse Electric Corporation, Lester, PA. 19113— Recommendation to Minimize Water Damage to Steam Turbines.A-2TM 5-811-6BIBLIOGRAPHYAmerican Institute of Architecture, Life Cycle Cost Analysis - A Guide for Architects, AIA, 1735 New YorkAvenue, Washington, DC 20006Fink and Beatty, Standard Handbook for Electrical Engineers, McGraw Hill Book Company, New York, N.Y.10020Grant, Ireson and Leavenworth, Principals of Engineering Economy, John Wiley & Sons, Inc., New York,N.Y. 10036Kent, R. T., Kents Mechanical Engineers Handbook Power Volume, John Wiley& Sons, Inc., New York, N.Y.10036Marks Standurd Handbook for Mechanical Engineers, McGraw Hill Book Company, New York, N.Y. 10020Mason, The Art and Science of Protective Relaying, General Electric Engineering Practice Series, John Wiley& Sons, Inc., New York, N.Y. 10036Morse, 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 Publicationsand Forms Center, 5801 Tabor Avenue, Philadelphia, PA. 19120.TM 5-811-6Changes 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. JOYCEMajor General United States ArmyThe Adjutant GeneralJOHN A. WICKHAM, JR.General United States ArmyChief of Staff* U . S . GOVERNMENT PRINTING OFFICE: 1983-424-688