text:
This action might not be possible to undo. Are you sure you want to continue?
UFC 3-540-02N 16 January 2004 UNIFIED FACILITIES CRITERIA (UFC) STEAM POWER PLANTS Any copyrighted material included in this UFC is identified at its point of use. Use of the copyrighted material apart from this UFC must have the permission of the copyright holder.
U.S. ARMY CORPS OF ENGINEERS NAVAL FACILITIES ENGINEERING COMMAND (Preparing Activity) AIR FORCE CIVIL ENGINEERING SUPPORT AGENCY Record of Changes (changes indicated by \1\ ... /1/ ) Change No. Date Location
Edited by Foxit PDF Editor Copyright (c) by Foxit Software Company, 2004 For Evaluation Only.
UFC 3-540-02N 16 January 2004
The Unified Facilities Criteria (UFC) system is prescribed by MIL-STD 3007 and provides planning, design, construction, sustainment, restoration, and modernization criteria, and applies to the Military Departments, the Defense Agencies, and the DoD Field Activities in accordance with USD(AT&L) Memorandum dated 29 May 2002. UFC will be used for all DoD projects and work for other customers where appropriate. All construction outside of the United States is also governed by Status of forces Agreements (SOFA), Host Nation Funded Construction Agreements (HNFA), and in some instances, Bilateral Infrastructure Agreements (BIA.) Therefore, the acquisition team must ensure compliance with the more stringent of the UFC, the SOFA, the HNFA, and the BIA, as applicable. UFC are living documents and will be periodically reviewed, updated, and made available to users as part of the Services' responsibility for providing technical criteria for military construction. Headquarters, U.S. Army Corps of Engineers (HQUSACE), Naval Facilities Engineering Command (NAVFAC), and Air Force Civil Engineer Support Agency (AFCESA) are responsible for administration of the UFC system. Defense agencies should contact the preparing service for document interpretation and improvements. Technical content of UFC is the responsibility of the cognizant DoD working group. Recommended changes with supporting rationale should be sent to the respective service proponent office by the following electronic form: Criteria Change Request (CCR). The form is also accessible from the Internet sites listed below.
Hard copies of UFC printed from electronic media should be checked against the current electronic version prior to use to ensure that they are current.
______________________________________ DONALD L. BASHAM, P.E. Chief, Engineering and Construction U.S. Army Corps of Engineers ______________________________________ DR. JAMES W WRIGHT, P.E. Chief Engineer Naval Facilities Engineering Command
______________________________________ KATHLEEN I. FERGUSON, P.E. The Deputy Civil Engineer DCS/Installations & Logistics Department of the Air Force
______________________________________ Dr. GET W. MOY, P.E. Director, Installations Requirements and Management Office of the Deputy Under Secretary of Defense (Installations and Environment)
Edited by Foxit PDF Editor Copyright (c) by Foxit Software Company, 2004 For Evaluation Only.
UFC 3-540-02N 16 January 2004
Edited by Foxit PDF Editor Copyright (c) by Foxit Software Company, 2004 For Evaluation Only.
UFC 3-540-02N 16 January 2004
CHAPTER 1 INTRODUCTION 1-1 PURPOSE AND SCOPE. This UFC is comprised of two sections. Chapter 1 introduces this UFC and provides a listing of references to other Tri-Service documents closely related to the subject. Appendix A contains the full text copy of the previously released Military Handbook (MIL-HDBK) on this subject. Appendix B contains the full text copy of Change 1 to the Military Handbook. This UFC serves as criteria until such time as the full text UFC is developed from the MIL-HDBK and other sources. This UFC provides general criteria for the design of steam and individual power plants. The primary purpose of these plants is to generate steam and/or high temperature water for process steam. Note that this document does not constitute a detailed technical design, maintenance or operations manual, and is issued as a general guide to the considerations associated with design of economical, efficient and environmentally acceptable heating plants. 1-2 APPLICABILITY. This UFC applies to all Navy service elements and Navy contractors; Army service elements should use the references cited in paragraph 1-3 below; all other DoD agencies may use either document unless explicitly directed otherwise. 1-2.1 GENERAL BUILDING REQUIREMENTS. All DoD facilities must comply with UFC 1-200-01, Design: General Building Requirements. If any conflict occurs between this UFC and UFC 1-200-01, the requirements of UFC 1-200-01 take precedence. 1-2.2 SAFETY. All DoD facilities must comply with DODINST 6055.1 and applicable Occupational Safety and Health Administration (OSHA) safety and health standards. NOTE: All NAVY projects, must comply with OPNAVINST 5100.23 (series), Navy Occupational Safety and Health Program Manual . If any conflict occurs between this UFC and OPNAVINST 5100.23, the requirements of OPNAVINST 5100.23 take precedence. 1-2.3 FIRE PROTECTION. All DoD facilities must comply with UFC 3-600-01, Design: Fire Protection Engineering for Facilities. If any conflict occurs between this UFC and UFC 3-600-01, the requirements of UFC 3-600-01 take precedence. 1-2.4 ANTITERRORISM/FORCE PROTECTION. All DoD facilities must comply with UFC 4-010-01, Design: DoD Minimum Antiterrorism Standards for Buildings. If any conflict occurs between this UFC and UFC 4-010-01, the requirements of UFC 4-010-01 take precedence. 1-1
UFC 3-540-02N 16 January 2004 1-3 REFERENCES. The following Tri-Service publications have valuable information on the subject of this UFC. When the full text UFC is developed for this subject, applicable portions of these documents will be incorporated into the text. The designer is encouraged to access and review these documents as well as the references cited in Appendix A and B. 1. US Army Corps of Engineers Commander USACE Publication Depot ATTN: CEIM-IM-PD 2803 52nd Avenue Hyattsville, MD 20781-1102 (301) 394-0081 fax: 0084 USACE TM 5-650, Central Boiler Plants 13 October 1989
Edited by Foxit PDF Editor Copyright (c) by Foxit Software Company, 2004 For Evaluation Only.
UFC 3-540-02N 16 January 2004 APPENDIX A MIL-HDBK 1003/7 STEAM POWER PLANTS A-1 .
water supply. pollution control. corrosion. environmental regulations and permitting. ABSTRACT Basic design guidance is presented for fossil-fueled.Edited by Foxit PDF Editor Copyright (c) by Foxit Software Company. load shedding. auxiliary equipment. controls and instrumentation. electric and steam generators. testing. steam condensers and cooling water systems. makeup and treatment. Criteria and design requirements are given for sizing plants. safety and fire protection. 2004 For Evaluation Only. steam-powered plants generating electricity or cogenerating electricity and steam. ii . and various miscellaneous items. use of cogeneration. coal and ash handling.
MIL-HDBK-1003/7 FOREWORD THIS HANDBOOK SHALL NOT BE USED AS A REFERENCE DOCUMENT FOR PROCUREMENT OF FACILITIES CONSTRUCTION. by using the self-addressed Standardization Document Improvement Proposal (DD Form 1426) appearing at the end of this document or by letter. Port Hueneme. iii . CA 93043. Naval Energy and Environmental Support Activity. deletions) and any pertinent data that may be of use in improving this document should be addressed to: Commanding Officer (Code 111C). SPECIFICATIONS. additions. IT IS TO BE USED IN THE PURCHASE OF FACILITIES ENGINEERING STUDIES AND DESIGN (FINAL PLANS. AND COST ESTIMATES). Beneficial comments (recommendations. DO NOT REFERENCE IT IN MILITARY OR FEDERAL SPECIFICATIONS OR OTHER PROCUREMENT DOCUMENTS.
iv . 2004 For Evaluation Only.Edited by Foxit PDF Editor Copyright (c) by Foxit Software Company.
.3 Economic Life...............6 2...3 Method of Satisfying Load Demands......3........................1..........17 Growth Curves.....3 2.5 Private Ownership..10 Plant Additions............2.......17 Section v .....5 2...1....14 Primary Power Plants..................................2 2..........7....... and Replacement of Existing Plants.....3 Guidelines..............7....................3 Uniform Annual Cost.........11 Environmental Regulations and Permitting.... Rehabilitation................9.............................................3 2..1...4 Choice of Individual Components.....7.........3 2 2.........4 2..............2..2 2...............................................2 Analysis Format.16 Steam Loads.........3.........1 2..9 2.................2 Present Value Analysis. and Other Services.............2 Discount Factor.............2 1..16 Typical Load Curves.......11 Codes and Regulations.............16 Electric Loads..1.............6...........10 Selection.1 2............................................12 Types of Power Plants.............5....FOSSIL FUELED CONTENTS Page Section 1 1.........14 ADMINISTRATIVE PROCEDURE TO DEVELOP A POWER PLANT Power Plant Loads....11 Conformance.....................................................2 2...1 3.........................2.................7...........3 2......................6..........2...1 2...........................2.6 2..7.........6............................4 Load Duration Curves............................2 2...2....4...11 Types.............12 Plant Location Factors...1........1 BASIC DATA Economic Analysis..10 Expansion.......................................................11 Page Safety Regulations and Requirements........2 2.........4 Comparative Owning and Operating Costs..........................2 2..10 Characteristics.............................1 2.............2 2....5 Private Versus Government Ownership..2.......2........1..2 Cost Elements.................1 2.......3 2.......................... Communications.....................5 Government Ownership..........................3 2..................................1 2..11 Pollution Control..................3 Factors to be Analyzed..........7 2....4 Source of Power.2 2........1 2.....3 2........2 Section 3 3................................2....1 2..................3 Economic Studies....10 Rehabilitation Versus Replacement.4 2...................2 3....8 2......................11 National Industry Codes........................2 2....................5 2...1 Cancellation......3 Objective........3..3 2..................4 Comparative Cost of Alternate Methods............1 INTRODUCTION Scope..........10 Fuel Selection...2.MIL-HDBK-1003/7 STEAM POWER PLANTS ...1 1.5 Hospitals..............2.4.............1 2....1.5 2..............14 Design.............4 2............................1 2..............2.............1 3...............3 2...............3 Plausible Methods......3 3.......................................9..1...................5..4......................1.......1 Policy..........3........................1...
.1........17 Steam Power Plant Design.2..........30 Furnace Volume......................17 Load Duration Curves.29 Natural Gas Firing............5............................2.1 4.................................1................3............2.............43 Steam Turbine Prime Movers.5.....30 Types of Stokers Used in Power Plants...............5..............37 Page Economizers........18 Plant Design Factors....................3.......13 4.11 4.....5.......................35 Coal Scales...2 4.9 4..........29 Normal Operating Pressure....37 Induced Draft Fans...18 Heat Balances................1 4......43 Controlled Extraction-Condensing Cycles and Back Pressure Cycles...........37 Forced Draft Fans...3........................1 4................17.......43 Larger Turbines..18 Section 5 5............1...............43 Selection of Cycle Conditions.38 Blowdown Equipment.........38 Steam Drive Auxiliaries.5 4.....2.......32 Coal Feeders........................5...........................2.......4 4.........................2 4.................37 Primary Air Fans.30 Definitions of Boiler and Stoker Criteria............................................................................................................................1 5....43 Definition...................4.......1....5...............38 Overfire Air Fans..................3 4...32 Pulverizers..1 4..44 Selection of Cycle Steam Conditions.12 4....1 4................43 Smaller Turbines.2 4.........18 POWER PLANT STEAM GENERATION Steam Generators (Boilers).3..............3 4....................1 5.....2 3........................1.............43 Topping Cycle.......15 4..............32 Pulverized Coal.....31 Overfeed Spreader Stoker with Traveling Grate.1.....1.................10 4........29 Steam Pressures and Temperatures.........2 3..................31 Front Gravity Feed Traveling Grate Stoker..........49 vi .........................5.......43 Simple Condensing Cycles...................1 4........1...............30 Fuel Oil Firing.1......5 Load Curves................30 Velocities in Convection Sections of Boilers..........29 Rated Pressure and Temperature........4 4....2......5.......2 5..............38 Equipment Selection..................1.........38 Essential Plant Equipment......................2 5..............MIL-HDBK-1003/7 3...7 4...........30 Coal Firing........3...........................................................................1..1..............1 5..................5..................1 4.......2......6..................38 Cinder Return Fans.....................3 4......1.................2 4.........14 4.. Stoker Coal Firing......2.2 5......................1 3...5.................5.........8 4.....18 Steam Conditions............5.........................5..............34 Pulverized Coal Firing vs............1..........1 4....38 STEAM TURBINE DESIGN Typical Plants and Cycles..29 Maximum Allowable Working Pressure..............2 3..........37 Soot Blowers...2...............4..1 5......44 General Economic Rules.3 5...............3 Section 4 4.....1.........................37 Wood Firing......5...2........2...........6 4........1 4..................................3 3.17 4....16 4.......4 5....37 Suspension Burning..5 4..37 Air Heaters.2 4.....38 Stacks..........2 4............30 Effective Radiant Heating Surface.32 Stoker Criteria........29 Safety Valves and Safety Relief Valves.3 5.......4 4........2 4.......6 4...1..........30 Stoker Grate Burning Rate.............2..
....2.......57 Definition..1......3 5...............49 Special Considerations..................55 Long Term Averages.....................................8..70 vii ......3......1 5.........55 Plant Economy Calculations......2 5..7.......................2 5....2 5........65 Lubricating Oil Systems..............59 Criteria For Cogeneration.5....1....5...........1.49 Extension of Existing Plant........3 5..........4 5...............2 5........6............................3 5.8 5...5.2....70 Air Cooled.................................9.......63 Economic Breakpoints...........7 5...............3.3 5......2....8................3.....1............5 5.50 Typical Small Plants..1 5..........2 5.........67 Lubricating Oil System Cleaning.9..........59 Cycle Types.......61 Back Pressure Type......57 Common Medium........5......7.......................1.....55 Theoretical Steam Rate................................60 Load Balance....6.........................60 Automatic Extraction Type...............1..3 5..3......2............61 Low Pressure Type.........................................55 Steam Rates....70 Generator Types....................4 5..2 5......60 Turbine Types.1 5...1 5.......3 5........4...61 Mixed Pressure or Induction Type....................4...2 5.........1...................60 High Pressure Extraction Type.2........................4...57 Cogeneration in Steam Power Plants........2...............................1 5.......6 5...............MIL-HDBK-1003/7 5....59 Page Relative Economy.1......................63 Turbine Generator Sizes.............................60 Size.67 Multistage Oil Conditioner..........1 5............................7 5...5.1 5..3 5...60 Load Coincidence..61 Noncondensing Types.1 5...60 High Pressure Non-Extraction Type...................3.2 5...9 5..1.....1.......2 5...........3.................70 Hydrogen Cooled......63 Geared Turbine Generator Units.67 Centrifuge With Bypass Particle Size Filter.....1 5................2 5.....................................1.............50 General...70 Generator Cooling......................63 Selection of Throttle Pressure and Temperature.............................1..............49 Steam Power Plant Arrangement..2..................7........8...2..1 5..........................1..........1..3..........2.1.61 Superposed or Topping Type.............2 5........1..........55 Turbine Generator Engine Efficiency.7.7......60 Condensing Types.......2..9....................3..............5 5.......3 5..................3.........4 5...1 5...........7.......................1..............3 5....1 5.....4 5....1........5..................................59 Extraction-Condensing Cycle.65 Turbine Exhaust Pressure..63 Noncondensing and Automatic Extraction Turbines............1........................................7.5 5...............66 Multistage Turbines...6 5..4 5.............4.1 5.7......59 Back Pressure Cycle.1.....................................2 5.......7........................2.................56 Actual Steam Rate.5..50 Heat Rates.66 Single Stage Turbines.......2 5..5 5...........50 Turbine Heat Rates..7.....3...........3...................7.....63 Turbine Throttle Pressure and Temperature..1 5...2 5..............................60 Distribution Medium..........70 Self Ventilation....1....................63 Atmospheric Exhaust......................2.................6 5.........................54 Cycle Performance...5..........2...........3 Balanced Costs and Economy..........1....5.....8 5.........4 5.....50 Heat Rate Units and Definitions.....2...............54 Plant Heat Rates...................7..7..............5 5.....1 5...2 5.66 Oil Purifiers......67 Lubricating Oil Storage Tanks.......2 5......3..
5.10 5.11 5.12 5.13 5.14 5.15 5.15.1 126.96.36.199 220.127.116.11 126.96.36.199 188.8.131.52 220.127.116.11 184.108.40.206 5.15.2 184.108.40.206 188.8.131.52 5.15.3 5.16 5.16.1 5.16.2 5.16.3 Section 6 6.1 6.1.1 22.214.171.124 184.108.40.206 22.214.171.124 18.104.22.168 6.1.2 22.214.171.124 22.214.171.124 184.108.40.206 22.214.171.124 220.127.116.11 6.2 6.2.1 22.214.171.124 126.96.36.199 6.2.2 220.127.116.11 126.96.36.199 126.96.36.199 220.127.116.11 126.96.36.199 18.104.22.168 6.2.3 6.3 6.3.1 6.3.2 18.104.22.168
Turbine Generator Control...........................70 Turning Gear........................................70 Turbine Generator Foundations.......................71 Auxiliary Equipment.................................71 Installation........................................71 Cleanup, Startup, and Testing.......................71 Page Pipe Cleaning.......................................71 Boiler Chemical Boil out............................71 Main Steam Blowout..................................72 Installation of Temporary Strainers.................73 Condenser Cleaning..................................74 Condensate System Chemical Cleaning.................74 Turbine Lube Oil Flush and Recirculation............75 Equipment Startup...................................75 Preliminary Checks..................................75 Initial Plant Startup...............................76 Testing.............................................77 Operation...........................................77 Trial Operation.....................................77 Main System Operation...............................77 Operation Control...................................77 GENERATOR AND ELECTRICAL FACILITIES DESIGN Typical Voltage Ratings and Systems.................79 Voltages............................................79 General.............................................79 Generators..........................................79 Power Plant Station Service Power Systems...........79 Distribution System.................................79 Station Service Power Systems.......................79 General.............................................79 Common Bus System...................................80 Unit Type System....................................80 Station Service Switchgear..........................82 Startup Auxiliary Transformer.......................82 Generators..........................................86 General Types and Standards.........................86 Type................................................86 Standards...........................................86 Features and Accessories............................88 Voltage Variations..................................88 Thermal Variations..................................88 Mechanical Withstand................................88 Excitation Voltage..................................89 Wave Shape..........................................89 Telephone Influence Factor..........................89 Excitation Systems..................................89 Generator Leads and Switchyard......................89 General.............................................89 Generator Leads.....................................92 Cable...............................................92 Page
188.8.131.52 220.127.116.11 Section 7 7.1 7.1.1
Segregated Phase Bus................................96 Isolated Phase Bus..................................96 STEAM CONDENSERS Condenser Types.....................................97 Spray Type..........................................97
7.1.2 220.127.116.11 22.214.171.124 188.8.131.52 184.108.40.206 7.2 7.2.1 7.2.2 7.2.3 184.108.40.206 188.8.131.52 188.8.131.52 7.2.4 7.2.5 7.2.6 7.2.7 7.2.8 7.2.9 7.2.10 7.3 7.3.1 7.3.2 7.3.3 18.104.22.168 22.214.171.124 188.8.131.52 18.104.22.168 7.3.4 220.127.116.11 184.108.40.206 18.104.22.168 7.3.5 184.108.40.206 18.104.22.168 188.8.131.52 7.3.6 7.3.7 18.104.22.168 126.96.36.199 7.4 7.4.1 7.4.2 7.4.3 7.5 7.5.1 7.5.2 Section 8 8.1 8.1.1 8.1.2 8.1.3 8.1.4 8.1.5 8.1.6 188.8.131.52 188.8.131.52 8.2 8.2.1 8.2.2
Surface Type........................................97 Pass Configuration..................................97 Divided Water Box...................................97 Reheating Hotwell...................................97 Air Cooler Section..................................98 Condenser Sizes.....................................98 Condenser Heat Load.................................98 Condenser Vacuum....................................98 Cooling Water Temperatures..........................99 Inlet Temperature...................................99 Terminal Difference.................................99 Temperature Rise....................................99 Tube Water Velocity................................100 Tube Outside Diameter and Gauge....................100 Tube Length........................................100 Number of Water Passes.............................101 Tube Cleanliness Factor............................101 Surface............................................102 Cooling Water Flow.................................102 Condenser Materials................................102 Shell..............................................102 Tube Support Plates................................103 Tubes..............................................103 Freshwater Service.................................107 Brackish Water Service.............................108 Seawater Service...................................108 Polluted Water Service.............................109 Tubesheets.........................................109 Freshwater Service.................................109 Brackish and Seawater Service......................109 Polluted Water Service.............................111 Water Boxes........................................111 Freshwater Service.................................111 Brackish and Seawater Service......................111 Polluted Water.....................................112 Exhaust Neck.......................................112 Expansion Joints...................................112 Exhaust Neck.......................................112 Shell..............................................112 Condenser Support..................................112 Page Bottom Support.....................................112 Spring Support.....................................112 Rigid Support......................................112 Condenser Air Removal..............................113 Continuous Air Removal.............................113 Hogging Air Removal................................113 AUXILIARY EQUIPMENT Condensate Storage and Transfer....................114 Condensate Storage Tank............................114 Deionized or Demineralized Water Storage Tank......114 Condensate Receivers and Pumps Sizing..............114 Condensate Pumps...................................114 Condensate Transfer Pumps..........................116 Condensate Cleaning................................116 Wastage............................................116 Filtration.........................................116 Feedwater Heaters..................................116 Low Pressure Heater(s).............................116 High Pressure Heater(s)............................116
8.3 8.3.1 8.3.2 8.4 8.4.1 8.4.2 8.4.3 8.4.4 184.108.40.206 22.214.171.124 8.5 8.6 8.6.1 8.6.2 8.7 8.7.1 8.7.2 8.8 Section 9 9.1 9.1.1 220.127.116.11 22.214.171.124 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 Section 10 10.1 10.1.1 10.1.1.1 10.1.1.2 10.1.1.3 10.1.2 10.1.3 10.2 10.2.1 10.2.2 10.3 10.3.1 10.3.2 10.4 Section 11 11.1 11.1.1 11.1.2 11.1.3 11.1.4 11.1.5 11.1.6
Heater Drain Pumps.................................116 Low Pressure Heater Drain Pump.....................116 High Pressure Heater Drain Pumps...................117 Deaerators.........................................117 Deaerator Function.................................117 Deaerator Design Pressure..........................117 Deaerator Storage Volume...........................118 Deaerator Rating...................................120 Rated Capacity.....................................120 Oxygen Removal.....................................120 Boiler Feed Pumps..................................120 Pressure Reducing and Desuperheating Stations......120 Pressure Reducing Stations.........................120 Desuperheating Stations............................122 Compressed Air System..............................122 Applications.......................................122 Equipment Description, Design, and Arrangement.....122 Auxiliary Cooling Water System.....................122 COAL HANDLING Unloading Systems..................................125 Barge..............................................125 River Barge Unloader...............................125 Ocean Barge Unloader...............................125 Coal Crushing......................................127 Coal Storage.......................................127 Page Coal Reclaiming....................................127 Plant Bunker or Silo Storage.......................127 Bunker or Silo Filling Systems.....................128 Coal Scales........................................128 Magnetic Separators................................128 Coal Sampling......................................128 ASH HANDLING Ash Handling Systems...............................130 Pneumatic..........................................130 Vacuum System......................................130 Pressure System....................................131 Vacuum-Pressure System.............................131 Hydraulic..........................................131 Dense Phase........................................131 Bottom Ash Hoppers.................................132 Stoker Firing......................................132 Pulverized Coal Firing.............................132 Clinker Crushers...................................132 Page Stoker Coal Firing.................................132 Pulverized Coal Firing.............................132 Ash Storage........................................132 CONTROL AND INSTRUMENTATION Types of Controls and Control Systems..............133 Analog.............................................133 Microprocessor Based Control Stations..............133 Computer - Direct Digital Control (DDC) or Supervisory Control (SC)......................133 Pneumatic Control Systems..........................133 Types of Control Systems Available.................133 Maintenance and Calibration........................134
11.2 11.2.1 11.2.2 11.2.3 11.2.4 11.3 11.4 11.4.1 11.4.2 11.4.3 11.5 11.6 11.7 11.7.1 11.7.2 11.7.3 11.8 11.9 11.10 11.11 11.11.1 11.11.2 11.11.3 11.12 11.13 Section 12 12.1 12.2 12.2.1 12.2.2 12.3 12.4 12.4.1 12.4.2 188.8.131.52 18.104.22.168 18.104.22.168 12.5 12.5.1 12.5.2 12.5.3 12.5.4 12.5.5 126.96.36.199 18.104.22.168 184.108.40.206 12.5.6 18.104.22.168 126.96.36.199 12.5.7 12.6 12.6.1 12.6.2 12.7 12.7.1 188.8.131.52 22.214.171.124
Steam Power Plant Controls.........................134 Combustion Control.................................134 Steam Temperature Control..........................134 Feedwater Control..................................134 Steam Turbine Generator Control....................144 Safety Devices and Interlocks......................144 Control Loops......................................145 Pressure...........................................145 Temperature........................................145 Level..............................................145 Flow meters........................................145 Pressure Gauges....................................145 Page Temperature Sensors................................147 Thermometers.......................................147 Thermocouples......................................147 Resistance Temperature Detector....................147 Transmitters.......................................147 Recorders..........................................149 Controllers........................................149 Operators..........................................150 Pneumatic Operators................................150 Electric Operators.................................150 Electro-Hydraulic Operators........................153 Positioners........................................153 Control Room.......................................153 WATER SUPPLY, MAKEUP, AND TREATMENT Water Supply.......................................156 Water Makeup.......................................156 Cycle Makeup.......................................156 Cooling Tower Makeup...............................156 Water Treatment....................................157 Cooling Water Systems..............................157 Once-Through System................................157 Recirculating System...............................157 Evaporative Wet Cooling............................157 Non-evaporative Dry Cooling........................157 Combination Wet and Dry Cooling....................157 Intake Structures..................................158 Location...........................................158 Arrangement........................................158 Trash Racks........................................158 Traveling Water Screen.............................158 Pumps..............................................159 Vertical Pumps.....................................159 Horizontal Pumps...................................159 Backlash Pump......................................159 Water Treatment....................................160 Chlorination.......................................160 Cathodic Protection................................160 Housing............................................160 Outfall Structures.................................160 Location...........................................160 Seal Wells.........................................160 Cooling Towers.....................................165 Mechanical Draft Towers............................165 Induced Draft Wet Type.............................165 Induced Draft Wet/Dry Type.........................165 Page
188.8.131.52 12.7.2 12.8 12.8.1 12.8.2 Section 13 13.1 13.1.1 13.1.2 13.1.3 13.2 13.3 14 14.1 14.1.1 22.214.171.124 18.104.22.168 188.8.131.52 14.1.2 14.1.3 22.214.171.124 184.108.40.206 220.127.116.11 14.1.4 22.214.171.124 22.214.171.124 18.104.22.168 184.108.40.206 22.214.171.124 184.108.40.206 126.96.36.199 14.2 14.2.1 14.2.2 14.2.3 14.2.4 14.3 14.4 15 15.1 15.2 15.3 15.4 15.5 15.6 15.7 Section 16 16.1 16.2 16.2.1 16.2.2 16.2.3 16.3 16.4 16.5 16.5.1
Induced Draft Dry Type.............................165 Natural Draft Towers...............................165 Cooling Water System Chemical Treatment............165 Chemical Analysis..................................165 Selection Factors..................................166 CORROSION PROTECTION Justification......................................167 Economy............................................167 Operational Necessity..............................167 Hazards in Handling Materials......................167 Causes.............................................167 Corrosion Controls.................................167 SAFETY PROTECTION Personnel..........................................168 OSHA Standards.....................................168 Equipment Guards...................................168 Platforms and Stairs...............................168 Egress.............................................168 National Industrial Safety Codes...................168 Hearing Conservation...............................169 Permissible Noise Exposure.........................169 Equipment Design Sound Levels......................170 Space Design Sound Levels..........................170 Handling of Toxic and Hazardous Substances.........170 Hazard Communication Standard......................170 Local Exhaust......................................170 Storage............................................170 Dry Chemicals......................................170 Liquid Chemicals...................................170 Gaseous Chemicals..................................170 Emergency Shower and Eye Wash Fountain.............171 Piping and Equipment...............................171 Piping.............................................171 Boilers and Pressure Vessels.......................171 Air Compressors and Positive Displacement Pumps....171 Equipment Enclosures...............................171 Air Navigation.....................................171 Security...........................................171 FIRE PROTECTION....................................172 General Requirements...............................172 Fuel...............................................172 Transformers.......................................172 Lubricating and Hydrogen Seal Oil Equipment........172 Page Standpipe and Fire Hose Stations...................172 Portable Hand-Held Extinguishers...................172 Typical Fire Protection Systems for Power Plants...172 MISCELLANEOUS Piping.............................................176 Insulation, Lagging, and Jacketing.................176 Insulation.........................................176 Lagging............................................176 Jacketing..........................................176 Freeze Protection..................................176 Pipe Supports......................................176 Heating, Ventilating, and Air Conditioning.........177 Heating............................................177
16.5.2 16.5.3 16.6 16.6.1 16.6.2 16.6.3 16.7 16.8 16.9 16.9.1 16.9.2 16.9.3 16.9.4 16.10 16.10.1 16.10.2 16.10.3 16.11 16.11.1 16.11.2 16.11.3 220.127.116.11 220.127.116.11 16.11.4 16.12 16.13 16.13.1 188.8.131.52 220.127.116.11 220.127.116.11 22.214.171.124 220.127.116.11 22.214.171.124 16.13.2 Section 17 17.1 17.1.1 17.1.2 17.1.3 17.1.4 17.2 17.2.1 17.2.2 17.2.3 188.8.131.52 126.96.36.199 220.127.116.11 22.214.171.124 126.96.36.199 18.104.22.168 17.3 17.3.1 188.8.131.52 220.127.116.11 220.127.116.11 17.3.2 17.3.3 17.4
Ventilating........................................177 Air Conditioning...................................177 Cranes and Hoists..................................177 General............................................177 Cranes.............................................177 Hoists.............................................177 Metering...........................................178 Drainage...........................................178 Seismic Design Criteria............................178 Power Plant Buildings..............................178 Piping.............................................178 Equipment..........................................178 Controls...........................................178 Architectural Criteria.............................178 Outdoor and Semi-Outdoor Plants....................178 Arrangements.......................................179 Criteria Source....................................179 Structural Criteria................................179 Foundations........................................179 Platform and Ladders...............................180 Typhoon or Hurricane Considerations................180 Miscellaneous......................................180 Exterior Piping Systems............................180 Collateral Reading.................................180 Electrical Criteria................................180 Operation and Maintenance Manuals..................180 Plant Operation and Maintenance Manual.............180 System designation.................................180 Description of System and Associated Major Equipment..................................180 Operation..........................................181 Maintenance........................................181 Page Troubleshooting....................................181 Drawings...........................................181 Equipment Data Manual..............................181 POLLUTION CONTROL Air Quality Control................................183 Pollutant Production...............................183 Emission Limits....................................183 Equipment Selection................................183 Monitoring and Reporting...........................183 Water Quality Control..............................184 Waste Streams......................................184 Discharge Standards................................186 Treatment and Disposal Methods.....................186 Recycle Basin......................................186 Chemical Wastewater................................186 Sanitary Wastewater................................186 Storm Water Runoff.................................186 Leachate and Runoff From Coal Storage Areas........186 Oily Wastewater....................................186 Oil Spill Control..................................186 Possible Sources of Spills.........................186 Bulk Oil Storage Tanks.............................187 Lube Oil Tanks.....................................187 Oil-Filled Transformers............................187 Methods of Prevention..............................187 Methods of Cleanup.................................187 Solid Waste Disposal...............................188
.........201 Dumping........192 Page Water Quality Regulations.............1 18......208 Format....1.......198 Public Hearings and EPA Notification....5........1.197 Criteria.5......2.....................1.........1 18.2..............3 18....4................1.........199 Solid Waste Disposal.4.........3............197 Antidegradation Policy..5....196 Designation of Uses............4................2..3 18..................2 18..................6 18...3 18.........188 Fly Ash........202 Nonhazardous Waste............196 Water Quality Standards.........2.......210 New Source Permits......4..1 18........1.............188 Fly Ash..2........7 Solid Waste Production....5 18..4 18.........6 18............................................207 CEQ.....190 Prevention of Significant Deterioration Limits......213 Nonattainment Areas.....210 Purpose.....4........188 Bottom Ash..............................7 18...............5.................4 17.206 EPA Guidelines...2...1...................4 18.............2 18........4 18...........................1 17...189 ENVIRONMENTAL REGULATIONS AND PERMITTING Air Quality Regulations........209 Time Period.....................4........209 Coordination.4..............3 18..2..........198 Pretreatment Standards...5..201 Totally Enclosed Facilities.189 Bottom Ash......1........................................................5........210 De Minimis Amounts.....2................5.2......204 Harbor Lines..5 17.....188 FGD Scrubber Solids....3 18......2 18...............5................3 18.....1........1..8 18.1...............2 18...3 17...188 Requirements.2....5......209 Resolution............5 18...3 18.1 18....202 Dredge and Fill Regulations............201 Treatment..............2 18.............................................2.6 18...1....................208 Federal Register.........................................4...3 18.......................1.............2..................5...2..10 18....4.......4 17...................................3...........4......5.....5.........189 SO2 Scrubber Solids.1 17.....190 National Ambient Air Quality Standards................................5.......188 Methods of Treatment and Disposal..............1 18....1...........2 17........1.....1 18..............205 Regulatory Program.....................201 Hazardous Waste.1.3.........MIL-HDBK-1003/7 17.................. and Disposal.....5......................................206 Permits......2.........5 18.....2 18..........3....................2.2....2.............201 Guidelines.......................4................2 17.....................1.......198 Oil Spill Regulations.........3.....212 Class I Areas.207 NEPA.....207 Environmental Impact Statements...........2 18.189 Pulverizer Rejects......2................1 18...................4....................205 Discharge of Refuse.......3.1.......4 18.................3 17....................4...4.5............1 17........191 New Source Performance Standards...189 Hazardous Waste Considerations...4.1 18.....205 State Permit Program............213 xiv ........204 Obstruction or Alteration.......2...........2 18.............1..............5..5..1........5......212 Best Available Control Technology....213 Ambient Air Data.......................................3 Section 18 18.............1...........5 18......4 18.4.................................3...208 Draft EIS...2 18.......2 17......3.........3 18.......4.....209 Final Comment..1 18...2 18...............5...209 Air Permits...........................3...............1..................................... Storage..4.......1 18..........................9 18..........207 Environmental Impact Statements.............................188 Pulverizer Rejects.........
.................5..........4 18.5.........5.......1..........5...2 18..1...2......2....................6....13 19......218 Oil Spill Plan...............1......................................................5....1 20....215 Page New Source............1 19..3 20.3 19.....................251 Preparations for Tests..................3........5....230 FAA Permit....216 Filling Date.................10 19...............14 19..........254 Rate of Load Reduction.......5........246 Heat Exchangers..1.1.5...........2..2....244 Fans........................238 Turbine Generators...........................229 Regional Permits..7 18.1 Local Permits..........2.....3.....................254 Reduced Plant Capability......2..5.........2.......................2...................241 Condensers..1..................................................228 Management Practices......3.217 NPDES Permit Conditions.................253 Purpose......2......5............4 19.......................6 18..226 Activity-Specific Conditions............1 20.........1 18.12 19...........................2..............................7...........1.....1 19.6.............242 Cooling Towers..................253 Turbine Blade Fatigue.......2 20.11 19.....254 Section xv ..9 18.................................229 Individual Permits..................236 TESTING Equipment Testing....1 20...253 Generating Unit Sizes.MIL-HDBK-1003/7 18.2......215 State Permit Program..5.........1.245 Compressors...................3 18................2.............6...........9 19.2 19.............216 Violation of Regulations.8 18................2 20...................................5........220 Solid Waste Disposal Permit...5 18.................244 Deaerators.....5.............3......................2 19......2...216 Storm Sewers and Conveyances.....................5......215 Environmental Impact Statement.............253 Requirements for Load Reduction..1 18.253 Page Stable Operation and Overload Capability..............5 18.................1 20...............1.............2..............225 Activities Authorized by a Nationwide Permit...5.......5 19...5.....................239 Heat Loss Method...2 20...............5.....2....1.1..6............5.......1..............1 19....6...250 Precipitators................................5....................215 Federal License or Permit.2 18.......2................1..4 18....................3 18................................3..1..5..3........253 Motor speed.....244 Pumps.............235 Forms.2.................1..6 18..........8 19.1..2....3 20 20...254 Number of Generating Units.........3........................2......1........4 20.........5..............7 19....................6.....5.....251 LOAD SHEDDING Objectives of Load Shedding Program..............3..221 Dredge and Fill Permit..6 19..........5 20........6 18.8 18..........236 Supplemental Notice........251 Flue Gas Scrubbers................................2 Section 19 19......1......5 18.1.........239 Input/Output Method.............2 20......243 Evaporators.....247 Air Heaters.............2 19...........................2.7 18..........5...215 Wastewater Discharge Permit.2....249 Dust Collectors....5.......1 18..........1............251 Test Equipment and Materials..3................254 Load Reduction Requirements.........2.............7.2..............253 Definition...........217 NPDES Permit.................223 Nationwide Permits..........4 18.............238 Steam Generators...3 18.....
.........4 21...259 Cost of Power Outage...265 Line and Equipment Protection..........3 20........4.......2 20.....................3 21.......4........4.....................4.............266 Energy Charge....4..............263 Base Load Thermal.....................................4 20....2 20....1........4..................264 Operation Requirements......2 20................................3 20.....257 Transfer Trip Load Shedding....................................2 20..................261 Reasons for Paralleling.....6..2.........................2 20.......4.256 Incremental Load Reduction.............................1.....266 Purchase of Electricity..........1 20...2 20.4..2.....2 20.5 21.......258 Local Application...4.........258 Critical Loads..........261 Parallel Operation...............................257 Incremental Load Reduction.....259 Life Support Loads.............2.....2 21.............261 Methods of Operation...4...4.....6......3 20..........4...................3...264 Electric Tracking....5.............3 20.........3.1.4..................1 21................1 21....5..................................2 Total Load Reduction.............2 21....4.......................261 Efficiency...268 Fuel Savings...265 Utility Power Rates.......1 21...........2 21....1.......2...............1........5...1.....5.2.......3 21..............1 21....................268 Competitive Systems......5.........................1 20.....264 Interconnection with Utility......257 Manual Load Shedding...259 Standby Power.......259 Interruptible Loads.....260 POWER PLANT COGENERATION..264 Thermal Tracking........................256 Automatic Operation.........5 21.............268 xvi .............259 Political Implications...6 21....259 Mission Critical Loads.............................2..............1 20...........256 Critical Frequencies...263 Base Load Electric.........3....3 20.........5..6...............266 Demand Charge.............2 21....3 21..........259 Diurnal Variations........3.............4.................5...........263 Page Electric Utility Crosstie........2........4 20......4.......5.3...2 21.1 20.................1 21...2 21.....3.........3...............................1 21....6...1 20.....4 21.3..4........4.........2...........263 Electric Peak Shaving......................5 21.266 Other Factors for Sale of Electricity...........................263 Electric and Thermal Tracking..................2.5..4............1 21...................................4 21.................5.............267 Economics...1 20..........263 Reasons for Isolation...1 21.........MIL-HDBK-1003/7 20....259 Seasonal Variations.......................3.............4..........1 21.........5........4............3 20.....5...........261 Combined Cycle....................2 21.....................261 Definition.4 Section 21 21..1..........................4....256 Minimum Power Supply....3...265 Utility Standby Service............4 20.259 Time-Critical Loads.........................3 21............5..............258 Remote Application.....4..................264 Interconnection Equipment..261 Cycles...1 20...............261 Basic Cycle..............2....2 20.......258 Point of Application.3..........................260 Non-Critical Loads....258 Electrical Usage and Critcality...........4 21........................1..............261 Isolated Operation......................256 Methods of Load Shedding.........265 Parallel Operation.........4..............1 21........257 Load Shedding Plan...............4...4...3 20.256 Underfrequency Relaying.................................4.........4....3...3.................6 21.2 21..........4......................2.........266 Total Electric Billing........
................... 2-Unit Stations.......6 Typical Load Duration Curve--All Export Steam from Power Plant...............95 Heat Transfer Through Condenser Tubes........22 Typical Extraction Condensing Cycle Heat Balance................................8 Typical Load Duration Curve--Load Priority ....... 2-Unit Stations Common Bus Arrangement...............269 FIGURES Figure 1 2 3 4 5 6 7 8 9 10 11 12 13 14 Typical Steam and Electric Load Curves............ 2-Unit Stations........................48 Page 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 Typical Small 2-Unit Power Plant (Less than 5 MW) Condenser on Same Level as Turbine.....45 Typical Controlled Extraction ..........................................................104 Galvanic Series of Metals and Alloys in Flowing Seawater....................53 Turbine Efficiency vs....58 Typical Automatic Extraction Cycle...................................... Capacities.....85 Typical Synchronizing Bus......81 Station Connections......................................20 Typical Back Pressure Cycle. Unit Arrangement Distribution Voltage Higher than Generation..........36 Typical Uncontrolled Extraction ..62 Oil Purification System with Centrifuge.....119 Typical Pressure Reducing and Desuperheating Stations........23 Pulverizer ........143 Typical Control Loops.115 Deaerator Functions......123 Arrangement of Continuous Bucket Ladder for Unloading Barges...........68 Oil Purification System with Multistage Conditioner.............91 Typical Main and Transfer Bus...........126 Typical Combustion Control System.....................................7 Typical Load Duration Curve--Portion of Export Steam on Central Heating Plant.46 Typical Back Pressure Cycle.......Burner Coordination Curves........................9 Typical Load Duration Curve--All Power Purchased..................94 Typical Breaker and a Half Bus...... Unit Arrangement Generation at Distribution Voltage..................135 Electro-Hydraulic Control System........................................................................151 xvii ..................Condensing Cycle..........................110 Typical Steam Plant Flow Diagram........19 Typical Extraction Condensing Cycle.................................Condensing Cycle...........21 Typical Automatic Extraction Condensing Cycle...........269 Economic Evaluation....................6...........5 Power to Heat Ratio..146 Typical Controls..............................6....................................51 Typical 2-Unit Power Plant Condenser Below Turbine...................................268 Economic Variables.....................MIL-HDBK-1003/7 21..........69 Station Connections................6.......93 Typical Ring Bus.........4 21............121 Typical Auxiliary Cooling Water Station..83 Station Connections...................................3 21...52 Critical Turbine Room Bay Clearances................47 Typical Topping Cycle..84 One-Line Diagram Typical Station Service Power Systems.......
......................193 xviii .........................................56 Direct Connected Condensing Steam Turbine Generator Units...............................................12 Power Plant Loads for Design................... Tube Sheet.......99 Typical Condenser Tube Length VS Surface..................152 Hysteresis Caused by Friction in a Valve..................... Water Velocity........33 Equipment Selection for Boiler Plants............148 Cooling Water Treatments......................... Wood........................107 Venting Equipment Capacities for Single Shell Condenser.......................54 Theoretical Steam Rates LB/KWH....65 Typical Turbine Throttle Steam Pressure Temperature Conditions..............................................100 Typical Condenser Size and Cooling Water Flow....163 Sump Dimensions Elevation View..64 Turbine Throttle Steam Pressures and Temperatures....................113 Typical Distribution of Boiler Ash.....................MIL-HDBK-1003/7 41 42 43 44 45 46 47 48 Types of Automatic Controller Action......................173 EPA Emission Sampling Techniques.262 TABLES Page 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Plant Location Factors.................169 Typical Fixed Fire Detection and Suppression Systems....31 Stoker Selection Criteria.....184 Primary and Secondary Ambient Air Quality Standards..........................................16 Information Required for Design of Power Plants................................101 Recommended Tube........105 Recommended Tube Gauge..........39 Typical Gross Turbine Heat Rates.130 List of Instruments on Control Panels..........................................................162 Sump Dimensions Plan View.....66 Typical Design Conditions for Steam Condensers..................................................................65 Typical Turbine Exhaust Pressure............113 Hogger Capacities.....161 Sump Dimensions Versus Flow....142 Flowmeter Selection Table.............................211 Combined Cycle....................138 Locally Mounted Instrumentation............ and Water Box Materials..136 Sensing Elements for Controls and Instruments.24 Maximum Velocities (FPS) in Convection Sections for Coal......... or Solid Waste Boilers.................................154 Multiple Pump Pits..........................................191 New Source Performance Standards for IndustrialCommercial-Institutional Steam Generating Units Larger than 100 MBTU/HR Input Rate.........................166 Permissible Noise Exposures............164 Principal Steps in the New Source Review Process..... and Application........106 Relative Resistance of Most Widely Used Tube Materials to Failure..................
.......................270 .......................................195 Significance Levels (In ug/m3).................214 Typical Performance of Cogeneration Systems Power to Heat Ratio........................................269 .....MIL-HDBK-1003/7 Page 32 33 34 New Source Performance Standards for FossilFuel Fired Steam Generating Units Larger than 250 MBTU/HR Heat Release Input Rate...................271 BIBLIOGRAPHY REFERENCES xix .........................
MIL-HDBK-1003/7 THIS PAGE INTENTIONALLY LEFT BLANK xx .
.... 2-Unit Stations Common Bus Arrangement......262 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 xxi ....151 Types of Automatic Controller Action..................................154 Multiple Pump Pits.......................................................123 Arrangement of Continuous Bucket Ladder for Unloading Barges..........................................121 Typical Auxiliary Cooling Water Station............ 69 Station Connections.....................................211 Combined Cycle......................................................84 One-Line Diagram Typical Station Service Power Systems...........................53 Turbine Efficiency vs........ 2-Unit Stations......110 Typical Steam Plant Flow Diagram................68 Oil Purification System with Multistage Conditioner.....81 Station Connections...................................104 Galvanic Series of Metals and Alloys in Flowing Seawater...........................................................................94 Typical Breaker and a Half Bus..163 Sump Dimensions Elevation View...............58 Typical Automatic Extraction Cycle................................135 Electra-Hydraulic Control System...161 Sump Dimensions Versus Flow.........126 Typical Combustion Control System........ Unit Arrangement Distribution Voltage Higher than Generation... Capacities...................146 Typical Controls.............................................152 Hysteresis Caused by Friction in a Valve...............................85 Typical Synchronizing Bus..............115 Deaerator Functions.............91 Typical Main and Transfer Bus..52 Critical Turbine Room Bay Clearances................143 Typical Control Loops.....119 Typical Pressure Reducing and Desuperheating Stations..95 Heat Transfer Through Condenser Tubes..........51 Typical 2-Unit Power Plant Condenser Below Turbine.....83 Station Connections..............162 Sump Dimensions Plan View.....................164 Principal Steps in the New Source Review Process............62 Oil Purification System with Centrifuge.............. Unit Arrangement Generation at Distribution Voltage..................................MIL-HDBK-1003/7 Page 15 16 17 18 19 20 21 22 23 24 Typical Small 2-Unit Power Plant (Less than 5 MW) Condenser on Same Level as Turbine...................... 2-Unit Stations..................................93 Typical Ring Bus.........................
.......12 Power Plant Loads for Design.................................................................. and Application...............................39 Typical Gross Turbine Heat Rates........................54 Theoretical Steam Rates LB/KWH......................... Tube Sheet......MIL-HDBK-1003/7 TABLES Page 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Plant Location Factors.166 Permissible Noise Exposures....148 Cooling Water Treatments...............................................130 List of Instruments on Control Panels... and Water Box Materials.....184 Primary and Secondary Ambient Air Quality Standards............................ Wood............................100 Typical Condenser Size and Cooling Water Flow..................................138 Locally Mounted Instrumentation...........................64 Turbine Throttle Steam Pressures and Temperatures....... Water Velocity................6 5 Typical Turbine Throttle Steam Pressure Temperature Conditions.........113 Typical Distribution of Boiler Ash....................31 Stoker Selection Criteria...193 xxii .............................................24 Maximum Velocities (FPS) in Convection Sections for Coal........101 Recommended Tube....33 Equipment Selection for Boiler Plants............136 Sensing Elements for Controls and Instruments...............56 Direct Connected Condensing Steam Turbine Generator Units..............169 Typical Fixed Fire Detection and Suppression Systems..........65 Typical Turbine Exhaust Pressure......................16 Information Required for Design of Power Plants............l91 New Source Performance Standards for IndustrialCommercial-Institutional Steam Generating Units Larger than 100 MBTU/HR Input Rate...........173 EPA Emission Sampling Techniques................................66 Typical Design Conditions for Steam Condensers...........................................142 Flowmeter Selection Table.........l05 Recommended Tube Gauge....................................107 Venting Equipment Capacities for Single Shell Condenser..... or Solid Waste Boilers..........113 Hogger Capacities.....99 Typical Condenser Tube Length VS Surface...........l06 Relative Resistance of Most Widely Used Tube Materials to Failure.......
..... . ... . .. .. . . . . . . . . .. . . . . ... ..214 Typical Performance of Cogeneration Systems Power to Heat Ratio. . 271 BIBLIOGRAPHY REFERENCES xxiii .. . . .... .. . .. . . . ... .. .. ... .... . . . . .. .... .. . . ..195 3 Significance Levels (In ug/m ). .. . . . . .269 .. . . . . ....... ... . .. .. . .. ... . . .. ... . . . ... . . . ..MIL-HDBK-1003/7 Page 32 33 34 New Source Performance Standards for FossilFuel Fired Steam Generating Units Larger than 250 MBTU/HR Heat Release Input Rate... . . . .. . . . . . . . 270 . .. .. .. .. . .. . .. . ....... . .. ..
MIL-HDBK-1003/7 Section 1.Fossil Fueled. Power plants shall be provided when a crucial need exists which cannot be satisfied economically or reliably with purchased power. When a power plant is required. This handbook. This handbook contains data and information as criteria that shall govern the design of fossil fueled steam power plants that are used to generate electricity or cogenerate electricity and steam. that is. 1.1 Scope. 1. operation. and fuel consumption during its life span. 1 .3 Policy. maintenance. it shall be designed and constructed with the lowest overall cost to own and operate. Steam Power Plants . does not cancel or supersede any existing design handbooks. INTRODUCTION 1. the lowest overall life cycle costs for ownership.2 Cancellation.
MIL-HDBK-1003/7 Section 2. Taxes are Insurance is not charged because the Government is self-insured.1 Present Value Analysis.3 Analysis Format. Economic Analysis and Program Evaluation for Navy Resource Management. The annual costs shall then be summarized to determine the total project cost for each alternative proposal. 2. 2 . For information. Operating and maintenance material costs (other than fuel). formatting. Water Costs. Chemical Costs. Life-Cycle Cost Manual for the Federal Energy Management Programs. The cost elements of an economic analysis will include non-recurring (capital cost of construction) and recurring operational and maintenance costs. 2. In this method all benefits and costs accruing throughout the life of the facility are compared on a present value basis. 2. BASIC DATA 2.1 Economic Analysis. Economic Analysis Handbook or National Bureau of Standards Handbook 135.1. All cost analyses for power plant investments shall be computed by using the present value (discounting) technique. All economic analyses shall follow the policy and procedures as outlined in SECNAVINST 7000. Operating and maintenance labor.14. Consider various fuels and fuel combinations. The recurring costs which are tabulated for each year of the facility useful life will include the sum of the following items: a) b) c) d) e) f) g) Fuel Costs.1. Any other costs related to the facility.2 Cost Elements.1. The economic analysis for all new or modified plant construction projects shall consider all suitable alternative methods to determine the most cost-effective method of accomplishment. The cost elements described above shall be summarized and tabulated for each year of the economic life of the facility and should be prepared for each alternative proposal under consideration. Electrical Costs. not charged because the Government does not pay taxes. The cost investments for each year of the economic life of the facility are converted to present values by applying a discount factor. and guidance in performing a detailed cost analyses refer to NAVFAC P-442.
Principles of Engineering Economy. 2. heat. c) d) Continuous integrity of utility service. In determining the present value of future expenditures the appropriate discount factor (interest rate) is applied to each annual tabulated expenditure. which must be ignored as having nothing to do with a choice between two alternatives for the future. 2. Discount factors are based on a 10 percent interest rate. E.2.2. for the end year of the project. Consider all plausible. at lowest overall owning and operating cost. the load demands. The uniform cost is determined by dividing the total project cost by the factor in NAVFAC P-442. Table B. 2. Future expansion. New York. L. The method of project accomplishment shall be the alternative which has the lowest uniform annual cost.3 Plausible Methods.2.6 Uniform Annual Cost. Past experiences with other power plants. Sensitivity of the establishment to hazards. Consider the following. Permanence of the power plant." Grant. etc. and compressed air. 2.MIL-HDBK-1003/7 2.1 Economic Studies Factors to be Analyzed a) b) c) d) e) f) g) h) i) 2. 3 .2. A maximum economic life of 25 years shall be used in cost analyses of utility investments. Emergency requirements. with sufficient standby to preclude irreparable loss to personnel or national security.1 Objective.2.2 Guidelines. Standby requirements.5 Economic Life. Provide the necessary utilities such as electricity.2 Actual loads. steam. a) Interservice possibilities.1. Duration of loads.2 2. NY. New installation. or large financial loss.1.4 Discount Factor. Modernization. Wiley & Sons.2. "A sunk cost is a past expenditure or an obligation already incurred. Method of Satisfying Load Demands 2. Replacement. one power plant to service more than one installation. refrigeration. Fuel selection. including: a) b) c) d) e) Rehabilitation. for example. Mobilization requirements. Consolidation.2. b) Only new or future costs of a project.1. alternate methods of satisfying 2. such as electric.2.
3. and apply discount factor for discounted annual cost. and 4 for a particular job. 2. The same economic analysis can be applied to individual components within a utility system. The example is for a plant generating electricity and exporting steam at three different conditions: 135 pounds per square inch (psig) (930 kPa gage). Tabulate total annual costs for each project year in Format A or Format A-1 of SECNAVINST 7000. and 6 psig (41 kPa gage). 2. block out each method of satisfying electric and export steam demands on a load duration graph (with a curve for electricity and each export steam condition). back pressure turbines. 35 psig (241 kPa gage).1 Load Duration Curves. 2.3. extraction condensing turbines.3 Comparative Cost of Alternate Methods 2. Since the only variables will be initial cost and energy.2 Comparative Owning and Operating Costs.2.3.MIL-HDBK-1003/7 f) Cogeneration. For electric generating plants. 4 .2. such as steam condensing turbines. as shown in Figures 1.14. gas turbines.2. only these factors need be considered in the analysis.3 Choice of Individual Components. 2.3. Estimate and tabulate the owning and operating costs for the alternate methods. g) Types and combinations of drivers.2. and diesel engines.
see MIL-HDBK-1004/1. prior to final disposal. e) A demand for complete command control. regardless of whether the services were owned or purchased. in order to avoid compromise of highly classified security information. Private or commercial facilities shall be utilized unless it can be demonstrated that it is necessary. 2.4 Private Versus Government Ownership 2. Only those costs which would remain unchanged. 2. may be neglected. d) The need for training military personnel for advanced base or overseas operations where nonmilitary personnel are not available for the particular work or service. for the Government to perform the services. c) The necessity for meeting current and mobilization requirements at any emergency. The Government shall operate utility services only if justified by any of the following factors: a) A lack of reliable.4. Each naval activity shall normally be provided with three sources of electric power: primary. and emergency. g) The need for a complete demilitarization. of certain types of military equipment. b) Substantial savings to the Government resulting from owning and operating a plant.1 Private Ownership. see Section 2. provided the true cost basis (including all allocable items of overhead and personnel) is used in evaluating government ownership. For further information on power sources. particularly where an abnormal or fluctuating military demand discourages private investment. or more economical. Electrical Engineering Preliminary Design Considerations.3 Source of Power. This factor shall apply to the essential load only. First.MIL-HDBK-1003/7 2. f) The necessity for protecting the plant and personnel in areas of unusually hazardous operations.4. the possibility of inducing private industry to undertake the operation or to provide the facility must be examined. available private facilities with sufficient capacity to meet the load demand. however. 5 . h) Any other items clearly demonstrating a particular Government owned operation to be in the public interest. For additional data.2 Government Ownership. standby.
2.4.3 Hospitals, Communications, and Other Services. Activities which cannot withstand an outage of more than four hours must be protected. Where normal electric connections between hospitals, for instance, and the normal source of power may be broken by a catastrophe, provide an emergency power plant of sufficient capacity to handle the essential load, arranged to operate automatically with the failure or restoration of normal current. 2.5 Expansion, Rehabilitation, and Replacement of Existing Plants
2.5.1 Plant Additions. Expansion of an existing power plant should be considered when additional electric generating capacity, including reserve capacity, is needed to provide for future loads. An economic study must show that modifications and additions to an existing plant, to serve additional loads, will be more economical than the construction of another power plant. Compliance pollution control and elimination of safety deficiencies shall be included for any significant plant modifications. 2.5.2 Rehabilitation Versus Replacement. If an existing plant has deteriorated to the point where numerous outages occur, does not perform in compliance with air pollution regulations, or is becoming a safety hazard, its rehabilitation or replacement should be considered. The choice between rehabilitation of the existing plant or replacement with a new modern plant shall be determined by a life cycle economic analysis. New capacity as needed to handle additional projected load shall be included in the considerations. Necessary equipment and systems for air pollution regulation compliance and elimination of other operating, safety, or maintenance deficiency must be included in either the rehabilitated or replacement plant. 2.6 Fuel Selection
2.6.1 Selection. Refer to Department of Defense MIL-HDBK-1190, Facility Planning and Design Guide, NAVFACINST 10343.1A, On-Shore Use of Navy Special, Navy Distillate and Marine Diesel Fuel Oils, NAVFACINST 10340.4C, Coal Requirements and requisitions, OPNAVINST 4100.6, Energy Financing and Source selection Criteria for Shore Facilities, and Navy policy on selection of fuels. Select fuels that are within the national guidelines and that produce the required performance at lowest life cycle costs, consistent with availability and pollution control. The fuel policy has been to use a solid domestically produced fuel as a primary fuel for power plants of medium size and above except where use of a solid fuel is not feasible because of geographic considerations. Existing plants burning fuel oil or gas may continue to burn fuel oil or gas, but new or replacement boilers in plants with design input over the threshold minimum established by government policy are required to burn solid fuel. Capability of burning another fuel shall be provided to be used when the primary fuel is not available and where it is critical to keep the power plant in operation on an emergency basis. Interruptible gas service will require a secondary oil fuel backup.
2.6.2 Characteristics. For properties of various fuels, handling equipment, firing equipment, and controls, refer to MIL-HDBK-1003/6, Central Heating Plants, Section 5, "Fuel and Combustion Systems". When oil is to be used, the plant shall be capable of pumping and burning grades No. 2 through No. 6 oil. 2.6.3 Types. Type of fuels to be considered are coal/oil, oil, gas/oil, wood, waste, and other combinations. 2.7 Codes and Regulations
2.7.1 Conformance. It is mandatory for the Federal Government to conform to Federal, state, and local air and water pollution abatement codes. 2.7.2 2.7.3 Environmental Regulations and Permitting. Pollution Control. See Section 17. See Section 18.
2.7.4 National Industry Codes. Where applicable, design shall conform to the industry codes including the following: a) Vessel Code. b) c) d) American National Standards Institute (ANSI) Standards. American Petroleum Institute (API). National Board of Boiler and Pressure Vessels (NBBPV), Inspection Code. American Society of Mechanical Engineers (ASME), Boiler and Pressure
e) American Society of Heating, Refrigerating and Air Conditioning Engineers (ASHRAE). f) g) h) i) j) k) American Society for Testing and Materials (ASTM). American Welding Society (AWS). American Institute of Plant Engineers (AIPE). National Association of Power Engineers (NAPE). National Association of Corrosion Engineers (NACE). National Fire Protection Association (NFPA).
l) m) n) o)
Air and Waste Management Association (AWMA). American Institute of Chemical Engineers (AICHE). Institute of Electrical and Electronics Engineers (IEEE). American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME). See Section 14, "Safety
2.7.5 Safety Regulations and Requirements. Protection" and Section 15, "Fire Protection". 2.8 Plant Location Factors. factors listed in Table 1. Plant Location Factors
Power plant location should be determined after evaluating the Table 1
+)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), Subitem Comment * Item * * * * * *
* * * * * * * * Topography * * *
Will determine type of * * architecture of * * building, wall and * * roof U factors, heating, * * and ventilating * * Max. and min. dry bulb; * * max. wet bulb temperature load heating heating and cooling degree days Max. and min. wind velocities Grades Affects heating load and structural loading Affects * architecture and floor levels, fuel handling, fuel storage, and drainage
Affects export
* * * * * * ** * * *
* Soil - Bearing value Determines structural * Water table foundations, drainage, * * * and underground pipe * distribution * * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))-
Table 1 (Cont.) Plant Location Factors
+)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), * Item Subitem Comment * * * * Max. high water Affects floor levels, * * level pumps, suction lifts, * * and foundations * * * Frost line Determines depth of * * * water and sewer lines * * * Cathodic analysis Determines cathodic * * * protection * * * * Seismic zone Determines structural * * reinforcement * * * * Future Expansion Affects allocation of * * space in plant for expansion * * * * Altitude Height above sea level Affects air density and * * stack height * * * * Orientation Load Center --------------* * * * Air Field Determines maximum * stack heights and hazards * * * * * Docks, railroads, and Affects transportation * * roads of fuel and materials * * * * Water supply Condenser cooling, jacket Affects plant location, * * cooling, makeup water, water treatment, filtering * * domestic water * * * --------------May determine materials of * * Local * material construction * * * * Local rules Air pollution Obtain permits * * and Water * Sewers * * regulations * Landfill * Fuel storage Allot space, note fire * * * protection requirements * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))-
MIL-HDBK-1003/7 Table 1 (Cont. as required to suit plant steam usage. * Item Subitem Comment * * * * Skills and --------------Determine construction * * availability and operating manpower * * of local labor * * * --------------Make sure plant is * * Master plan * consistent with Master Plan * * for activity development * * * * Architectural Must be compatible with * surrounding buildings * * requirements .1 Design.) Plant Location Factors +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).2 Primary Power Plants. c) Steam boilers with turbine generators of matched capacity.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 2. Types of plants for installations requiring export steam: a) Purchased electric power and steam plus steam heating boiler. Primary power plants must have adequate capacity to meet all peacetime requirements. Types of plants for installations not requiring export steam or heat: a) b) Purchased electric power.9. Power plant design varies to suit the various combination of electrical power generation and export heat requirements. 2. 14 . or combination condensing and back pressure. Steam heating boilers can be used to supplement the requirements of the export steam load. Diesel engine-generator rated for continuous duty. b) High pressure steam boilers with back pressure steam turbines of matched capacity.9. Turbines can be straight condensing. Steam heating boilers can be used to supplement the requirements of the export steam load.9 Types of Power Plants 2. c) High pressure steam boilers with automatic extraction condensing turbines.
15 .MIL-HDBK-1003/7 d) Diesel generator with heat recovery boilers for low pressure steam distribution and supplementary boilers as required for steam export.
Section 3. 3.1
Power Plant Loads
3.1.1 Electric Loads. To determine plant capacity, the data shown in Table 2 must be obtained using the demand coincidence and load factors discussed in MIL-HDBK-1004/1. 3.1.2 Steam Loads. Determine steam loads as indicated in Table 2. Table 2 Power Plant Loads for Design
+)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), Loads to be determined in kW * * * (Determine winter and summer * * Types of Electric Load loads separately) * * * * Export . . . . . . . . . . . . . . . . . See MIL-HDBK-1004/1 * * Plant . . . . . . . . . . . . . . . . . See MIL-HDBK-1004/1 * * * Switchgear . . . . . . . . . . . . . . . See MIL-HDBK-1004/1 * Line losses . . . . . . . . . . . . . . 12% of subtotal (unless more * * accurate data is available). * * * Total present load . . . . . . . . . . . Total of above. * Total ultimate load . . . . . . . . . . See MIL-HDBK-1004/1 (may be * * estimated by extending current * * load trend). * * * Minimum continuous . . . . . . . . . . . See MIL-HDBK-1004/1 (as for a * summer night). * * Emergency load . . . . . . . . . . . . . See MIL-HDBK-1004/1 (demand of * * services that cannot tolerate * a 4 hour interruption). * * * * * Loads to be Determined in KBtu/hr * * (Determine winter and summer * * Types of Steam Load and winter loads separately) * * * * Condensing turbine . . . . . . . . . . . Rated kW x Heat Rate * * * Auto-extraction turbine . . . . . . . . .Rated kW x Heat Rate * Plant auxiliaries . . . . . . . . . . . Steam jet air ejector * * Feedwater heating. * Fuel oil heating. * * * Export . . . . . . . . . . . . . . . . . Space heating (radiation) * Use diversity factor of 1.0. * * * Space heating (ventilation). * Use diversity factor of 0.8. * * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))-
Table 2 (Cont.) Power Plant Loads for Design
+)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), * Export (Cont.). . . . . . . . . . . . . .Utilities (hot water and laundry).* * Use diversity factor of 0.65. * * For kitchen use factor of 1.0. * * Refrigeration (turbine drive). * * Refrigeration (absorption type). * Process. * * * Distribution loss. * * Total present load . . . . . . . . . . . Total of above steam loads. * * * Total ultimate load . . . . . . . . . . .Maximum expected steam load for * (including projected present and additional future * electrical power generation * * future load) * plant steam requirements and * * export * steam loads. * * * Minimum continuous Same as distribution loss. * * Emergency load . . . . . . . . . . . . . Demand of services that cannot * tolerate a 4-hour interruption. * * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))-
Typical Load Curves.
For an example of a typical load curve, see Figure 1.
22.214.171.124 Growth Curves. In (a) of Figure 1, note the normal trend growth of total steam and electric demands and the additional loads when new buildings or processes are added. This curve is useful in timing power plant additions of equipment. 188.8.131.52 Load Curves. The average of daily steam and electric demands, (b) of Figure 1, for the season or year under consideration for each hour of a 24 hour day is also important. Such curves are useful in determining load factors and duration of certain demands, and in dividing the total load among the plant units. Refer also to Appendix B, Load Shedding. 220.127.116.11 Load Duration Curves. Plot the number of hours duration of each load during a year for present and future load conditions of steam and electricity usage for the Naval activity. See (c) of Figure 1. This type of curve is useful in determining load factors and in sizing units of power plant equipment. Load duration curves for various conditions are shown on Figures 2, 3, 4, and 5.
Steam Power Plant Design
3.2.1 Steam Conditions. For selection of steam pressures and temperatures for inlet conditions to the turbine, see Section 5, Steam Turbine Design. Going slightly beyond a range bracket (as above 400 psig (2758 kPa gage) and 750 degrees F (399 degrees C)) will result in price increases and a less economical design. For boiler outlet conditions, see Section 4, Power Plant Steam Generation. The export steam conditions depend on the distribution system and the consuming equipment. 3.2.2 Heat Balances. Typical extraction condensing, back pressure and automatic extraction cycles are shown in Figures 6, 7, and 8. For collateral reading on steam cycles and heat balances, see Steam Turbines and Their Cycles, Salisbury 1974, Modern Turbines, L. E. Newman 1944, Mechanical Engineers Handbook, Marks 1978, and Power Plant Engineering, Morse 1943. A typical heat balance for an extraction condensing cycle is shown on Figure 9. 3.3 Plant Design Factors. factors listed in Table 3. Power plant design should consider and evaluate the
))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 24 . * Steam Maximum pressure See criteria in * * Export * fluid required by consumer. * * Maximum Add future load to * ultimate present load.7-0. buildings where no cutback * Essential can be tolerated. Distribution loss and * * Minimum night utility load. load. Minimum permissible * heating and ventilating * * * load where cutback can * * be tolerated. Determine * * * diurnal loads diversity 0. * Minimum heating load to * * * avoid freeze-up. * * * load. * * * * * * Process.MIL-HDBK-1003/7 Table 3 Information Required for Design of Power Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).8-0.9. * * * Total summer load. * Maximum allowable Exterior * * conditions . * * continuous Diversified load in all * * load.7. * * * load. NAVFAC DM-3. "Heating Loads" * * * Utilities hot water.8 Heating loads by * * and hourly criteria in * loads.5 . winter. diversity Determine ratio of * varies. MIL-HDBK-1003/8.0. * * * Distribution loss. summer and * Consider Heating (auto control). sum of utility and * * * process loads to * * total load. * * Total winter load. control) separately for * * load load. Use factors to * * * kitchen laundry. * Principal * * Item Subitem Required Data Comments * * * * Plant Maximum Export load: Heating Obtain loads * * steam continuous (not auto.03 and * * * ASHRAE Handbook * Fundamentals Chapter * * * 25. diversity 0. obtain diversified * * diversity 0.
heating Ascertain supply. valving arrangement * pressure at meter. * million Btu * * * * Fuel oils Grade. * * * through distribution * * system. Determine who * * ultimate analysis. * * * * Natural gas Heating value. * * * return tank * * * * Ratio of condensate * return to steam * * * * * Fuels Availability Reserves for life See Section 2 for * * of plant policy. * * . Determine if gas * petroleum ultimate analysis. Add simultaneous * * * return pressure. for * * other criteria. and pumping rates of * * temperature at all condensate * condensate storage/ return pumps. HTW.) Information Required for Design of Power Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). * * consumer equipment. * * * Condensate Condensate flow. * million Btu * * * * * Liquid Heating value. * * moisture content. supplies meter. * * * * Purity for ship Use demineralized * usage water for makeup. * * * See MIL-HDBK-1025/2. and gas piping * * * delivered cost per on site. Gas. * * Dockside Utilities for * Ship Service. * * specific gravity.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 25 . meter house.MIL-HDBK-1003/7 Table 3 (Cont. supply is firm or * * * gas delivered cost per interruptible. and * Maximum pressure drop Compressed Air. CHW. * Principal * * Item Subitem Required Data Comments * * * * pressure in distribution Distribution of * * system and in Utility Steam.
heating Determine how * * * value. delivered * * * cost per million Btu. heating Determine how * * (municipal) value.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 26 . * * * * Ash Cost of disposal Determine disposal * * by fill on site or * by trucking away. * * analysis. delivered is not available * cost per million for burner ignition. composition delivered by * municipality or * * * private haulers and * * how stored and * * handled. unloaded. heating Determine how * * * value. * * * Btu Determine how * * delivered. * * * * Water Availability Domestic use. ultimate delivered. * and stored. * cost per million Btu.) Information Required for Design of Power Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). unloaded. * * * * * Refuse Source. * * * * Coal Source. unloaded * * analysis. and handled. proximate stored.MIL-HDBK-1003/7 Table 3 (Cont. * * * Wood Source. * * * Determine pollution * abatement. delivered stored. Condensing * . * Determine pollution * * * abatement. and handled. ultimate if other gas fuel * * analysis. * Principal * * Item Subitem Required Data Comments * * * * value. ultimate delivered. Determine * * * if secure landfill * * area is necessary to * prevent contamination * * * of ground water. * analysis. Cooling * and tempering pumps and * * * coolers.
* construction purposes. * Environmental restraints. * * * Normal Substation capacity * * Electric * service service and voltage available. * Principal * * Item Subitem Required Data Comments * * * * water. Determine if * * service size of electric continuous. * * * Inlet temperature. * * * * * Composition Chemical analysis Determine type * and Source of water treatment * * * * Discharge Determine discharge * * * temperature and * * composition. makeup water * * for heating plant. * partial load * * * generation * * * .) Information Required for Design of Power Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 27 .MIL-HDBK-1003/7 Table 3 (Cont. Use most * * studies * types of including utility economical system * * generating costs in accord with * equipment for National energy * * * full and policy. * * and required) * * * Alternate Alternate source in * * service case of normal * service failure. * * * * * Emergency Power required. * * fire protection. * generator * * * * * Plant See Table 1 * * location * * factors * * * * Economic Comparison Capital costs and See Section 2 for * of various operating expense policy. * * (available Energy and demand * charges.
* Principal * * Item Subitem Required Data Comments * * * * Choice of Electrical demand loads. determine most * * * and Heating loads. Make life cycle * * operating Reliability and cost of cost analysis to * pressure purchased power. * * temperature production requirements.) Information Required for Design of Power Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). costs including * distribution * * * energy loss costs.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 28 .MIL-HDBK-1003/7 Table 3 (Cont. * . Consider first * lines losses energy cost and operating * * * costs. economical system.
In order to avoid excessive use and wear of safety or safety relief valves. The specified operating pressure is the maximum operating pressure at the turbine throttle valve inlet plus the main steam line pressure drop (between the superheater outlet and turbine throttle valve inlet at the maximum continuous rating of the boiler) rounded to the next higher unit of 5 psi (34 kPa gage). 4. which is usually 3 to 4 percent of the set pressure. For characteristics. Burning rate is the higher heating value (in Btu) of the type of coal used. see MIL-HDBK-1003/6. multiplied by the number of pounds of coal burned per hour to obtain the rated boiler capacity.4 Fuel Oil Firing.2 Maximum Allowable Working Pressure. The maximum values shown are based on the assumption that furnace walls are water cooled. 4. 4. values 29 . 4. and burning. 4. The boiler shall be specified for the maximum steam temperature required at the superheater outlet for operation of the turbine generator. one or more safety valves on the boiler shall be set at or below the MAWP. For fuel oil characteristics.2. Sections 5 and 9. 1978 and (2) Combustion/Fossil Power Systems.1 Definitions of Boiler and Stoker Criteria. 4. and that the most desirable type of coal for the unit is used. see (1) Steam/Its Generation and Use. POWER PLANT STEAM GENERATION 4.1 Safety Valves and Safety Relief Valves. 4.2. divided by the total active burning area. and coal.2.1 Stoker Grate Burning Rate. that there is adequate furnace volume. handling. application. Inc. If additional safety valves are used. The capacity of all safety valves or safety relief valves for each boiler shall be such that the valves will discharge all the steam that can be generated without allowing the pressure to rise more than 6 percent above the highest pressure at which any valve is set and in no case higher than 6 percent above the MAWP. The ASME Boiler and Pressure Vessel Code states that no boiler shall be operated at a pressure higher than the MAWP except when the safety valve or valves are discharging (blowing). by Babcock & Wilcox.1 Steam Generators (Boilers).3 Natural Gas Firing. Based on the specified operating pressure.2. This allows operation of the boiler below the blowdown range of the safety valves. by Combustion Engineering. 1981. The specified temperature is equal to the sum of the operating temperature at the turbine throttle valve inlet plus the main steam temperature drop (between the superheater outlet and turbine throttle valve inlet) with the sum rounded out to the next higher unit of 5 degrees F. the maximum boiler operating pressure in the boiler steam drum or at the superheater outlet is usually not greater than 95 percent of the lowest set pressure of the relief valves at these points.2 Steam Pressures and Temperatures 4. the boiler manufacturers will design the boiler parts and safety valve pressure settings in accordance with the ASME Boiler and Pressure Vessel Code. The boiler shall be specified for the maximum operating steam pressure required at the superheater outlet for operation of the turbine generator. Section 1.5.2 Normal Operating Pressure. application. For collateral reading and further detailed information. the highest pressure setting shall not exceed the MAWP by more than 3 percent.5 Coal Firing. 4.2. Power Boilers. The maximum allowable working pressure (MAWP) of a boiler is an absolute limit of pressure in psig at which a boiler is permitted to operate.1. of the stoker grate. Sections 5 and 9. handling. in square feet. in the absence of these conditions. storage of 4.MIL-HDBK-1003/7 Section 4.1 Rated Pressure and Temperature. see MIL-HDBK-1003/6.5. storage.2. see NAVFAC MIL-HDBK-1003/6. For natural gas characteristics and application. In accordance with the rules of the ASME Boiler and Pressure Vessel Code.
1. oil) and the first plane of entry into or between the tubes. 4.1. above the grate surface that is directly exposed to radiant heat of the flame on one side and to the medium being heated on the other. furnace volume is defined as the cubical volume between the top grate surface (coal) or the floor (gas.MIL-HDBK-1003/7 should be reduced to ensure satisfactory combustion.2 Velocities in Convection Sections of Boilers. 4. which may be bare. This surface consists of plain or finned tubes and headers and plain surfaces. or metallic-ore-covered tubes and headers: projected area (external diameter times length of tube) of the tubes or header. Refractory-covered surfaces should not be counted. metal-covered.4 Effective Radiant Heating Surface. For water-tube boilers. metal-covered. they constitute the plane of entry. The surface shall be measured on the side receiving heat.5. Computations of effective radiant heating surface for water tube boilers shall be based on the following: a) Bare.1. stoker. Effective radiant heating surface is defined as the heat-exchange surface within the furnace boundaries and. 30 .3 Furnace Volume. and fuel combination.5. the gas velocities through the convection section shall not exceed velocities shown in Table 4 for the specific boiler. 4. or metallic-ore-covered. If screen tubes are utilized. in solid-fuel furnaces. To prevent undue erosion of boiler convection tubes.5.
MIL-HDBK-1003/7 Table 4 Maximum Velocities (ft/sec) in Convection Sections for Coal. Front arches are used with 31 . or Solid Waste Boilers +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).35 mm) thick or more than 1-1/4 inches (31. except that metal blocks not integral with tubes or headers.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- b) Extended surface (metal and metallic surfaces extending from the tubes or headers): sixty percent of the flat projected area. coke breeze to high and medium volatile bituminous. It will handle fuels that have widely varying characteristics.75 mm) in length. such as anthracite or coke breeze. are important when using the traveling grate stoker to burn very low volatile fuels. from low volatile anthracite.5.2 Types of Stokers Used in Power Plants 4. Wood. the traveling grate stoker method of firing can be used for moderately changing wide load swings. It is particularly efficient with free-burning type coals in the Mid-West producing areas and can handle lignite and subbituminous coals.5. c) Furnace exit tubes: the projected areas of those portions of the first two rows of exit tubes receiving radiant heat from the fire.2.1 Front Gravity Feed Traveling Grate Stoker.000 pph (7260 Kg/hr) range. * Single Pass Multi-Pass * * Stoker Type Water Tube Water Tube * * * * Solid * Coal Wood Waste Coal * * * * * Underfeed stoker 75 60 * * * * Spreader stoker 60 50 50 * * * Traveling grate * (with reinjection) * * * 60 50 50 * * Spreader stoker * Traveling grate * * (without reinjection) * * * * Traveling grate 75 60 * * (front gravity feed) * * * * Solid waste 30 * . and the part of the extended surface which is more than one tube or header radius from the tube of header from which it extends are not included. The type of furnace configuration. extended surfaces less than 1/4 inch (6. For plant capacities in the 25. including long rear arches. 4.000 pounds of steam per hour (pph) (11400 kg/hr) to 160.
Section 5. Information included in the table are average criteria gathered from several boiler-stoker manufacturers' recommendations. For use with each pulverizer. 4. Front discharge traveling grates are commonly used with spreader stokers. This means that the traveling grate stoker has a low particulate pollution characteristic as compared to other fuel burning stokers. and good efficiency. Suspension burning gives rapid response to load changes which is an important characteristic for many industrial process steam plants that need rapid changes in steam production.1 Coal Feeders. therefore.6.4.MIL-HDBK-1003/7 the high volatile and free-burning Mid-Western type coals. the spreader stoker requires the use of electrostatic precipitator or baghouse collectors to prevent particulate pollution. See Table 5. may operate with either a negative or positive internal pressure and will also contain hot circulating air. The spreader stoker has high availability.5.2.6 mm) to 6 inches (152. The spreader stoker is characterized by a thin bed and partial burning of coal particles in suspension. Since the fuel bed on the traveling grate stoker is not agitated by vibration as the bed usually 4 inches (101.5. 4. The suspension burning causes a high particulate loading of the burning gases within the furnace which. This characteristic. would result in a high carbon loss in the fly ash. depending on type. and oscillating grates are also available). a height (head) of coal must be provided and maintained above the feeder inlet to prevent pulverizer air backflow. (Dump. With a high particulate loading. 4. provides a unit capable of firing a wide range of coal grades and types. Pulverizers.5. 4. Stoker Selection Criteria. 32 .4 mm) depth is moving from the feed end toward the discharge end. These units normally have from five to nine individual air zones which can control the amount of air admitted to the fuel bed as it travels from the free end of the stoker to the discharge. The feature of the traveling grate stoker that provides for the utilization of such a wide variety of fuel types is the undergrate air zoning. the coal feeding function can be accomplished by the use of a separate rotary feeder or combined with the weighing function (see para. without fly ash reinjection. for information necessary for proper selection of a stoker type. This provides the stoker operation with tremendous flexibility to obtain complete combustion with the various sizes and types of fuel. the amount of particulate fluidization is very low. reciprocating. together with a nonclinkering thin bed on the grate. vibrating. Coal feeders cannot act as a seal for the pulverizer air.4 Pulverized Coal 4.5. Chain grate stokers are not recommended except to burn low fusion coals with high clinkering tendencies. ease of operation. using a volumetric or gravimetric feeder.5. Coal Scales). See also MILHDBK-1003/6.3 Stoker Criteria.2 Overfeed Spreader Stoker with Traveling Grate.
000 6 to 1 * * 160. process type loads which may vary in capacity more than 50% during any 30 minute period. 33 .MIL-HDBK-1003/7 Table 5 Stoker Selection Criteria +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).000* 160.000. use spreader stoker.000 35.000 spreader .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- Notes: 1.500 * * * * * * * Maximum * Stoker * * * Grate Btu/Hr ft2 * 3 * Type of Stoker Burning Btu/Hr ft of Radiant Combustion * * Unit Size Type of Type of Rates of furnace Heating limited * Feed Grate Btu/ft2/Hr Volume Surface (turndown) * * Range PPH * * * 25.000Front Traveling 450. Where availability of proper coal suitable for a particular type stoker is indeterminate.000 100.000Front Traveling 1" to 0" top Free burning to medium * Gravity size with caking (free swelling * * 160.e. For applications of swing loads with less than the 30 minute period..8 to 1 * 3. Ash fusion * * * screen (reducing atmosphere H = * 1/2W) minimum 2750 deg.000 * maximum 60% index less than 6) ash 6 * * though 1/4" to 15% volatile matter 28 * round hole to 40%. 2.000 2.000 Gravity * * * * * * 25. F * minimum Btu/lb 11.5 to 1 * * 160. i. consideration should be given to the spreader type stoker. F * * * minimum Btu/lb 11. * Type of Stoker Fuel Requirements * * Unit Size Type of Type of * * Range PPH Feed Grate Size Characteristics * * * * 25.Overfeed Traveling 700.00 300. The underfeeds and chain grate stokers are not generally applicable to widely fluctuating loads.000 spreader 3/4" X 0" subbituminous or lignite * * with maximum volatile matter 25% to 40% * 40% through ash 6 to 15% ash fusion * * * 1/4" round (reducing atmosphere H = * * hole screen 1/2W) minimum 2750 deg.500 * * * Overfeed Traveling 1-1/4" to Bituminous A & B * * 25.000 100.
with a tube and tile (spaced tubes backed by refractory) or refractory furnace. Further turndown beyond that indicated under Note 4 may be obtainable dependent upon allowable emission requirements and/or pollution abatement equipment applied. All grate heat release rates are based on maximum continuous rating (MCR) with allowance for 110% rating for 2 hour emergency peak per 24 hours. Pulverizers are used to reduce crushed coal to a powder-like fineness usually in the order of 70 percent passing through a 200 mesh screen. 8.MIL-HDBK-1003/7 3. one pulverizer will usually furnish coal directly to several burners. For excess air requirements at the boiler outlet over the boiler/stoker limits operating range. To facilitate the pulverizing and pneumatic circulation of the coal fuel within the pulverizer. 10. see MIL-HDBK-1003/6. 9. 6. a) follows: (1) Ball and race Types of Pulverizers. 4.4. 7. For smokeless condition. a distributor located beyond the fan discharge is used to distribute the coalair mixture to several burners.5 .5. furnace volume and radiant heating surface. If a blower is used. the minimum burning rate for tangent tube or membrane furnace wall construction is 250. consult NAVFAC headquarters Code 04 for direction. as loss of ignition could result. A pulverizer fan is used either as a blower or exhauster which either forces or draws hot primary air through the pulverizer and through the discharge coal-air piping to the burners.1 maximum boiler turndown. The principal types of pulverizers are as 34 . hot air (up to 650 degrees F (343 degrees C)) is introduced into the pulverizer for the purpose of drying the coal.2 Pulverizers. 4. Consult boiler and stoker manufacturers for predicted excess air requirements at various loads.000 Btu/ft2/hr which equates to 3. If an exhauster is used.000 Btu/ft2/hr active stoker grate area which equates to 2/3 .1 maximum boiler turndown 5. Some chain grate designs are applicable for anthracite coal firing. In cases where coal quality is less than in above tables. Coal with volatile content less than indicated should not be applied. This release rate can be reduced to 200. see the section. For definitions of stoker grate burning rates.
and need highly trained personnel. the firing rate may be further reduced by reducing the number of pulverizers and number of burners per pulverizer in service. These factors must also be taken into account in selecting number and size of pulverizers. (2) Combustion Engineering. Coal feed size ranges from 3/4" (19. The larger the pulverizer size. The minimum boiler load will depend on the number of pulverizers and burners installed and primary air velocities in the coal-air piping and coal burners.1 mm) x 0" with 3/4" x 0" being a size which is commonly used. The operating range of all types of pulverizers.5 Pulverized Coal Firing vs. Base pulverizer selection on coal feed is required at maximum boiler load plus 10 percent for load pickup and continuous boiler output at maximum steam load. high power costs to drive mills. For many years. c) Pulverizer Sizing. Emergency loss of one pulverizer must be considered and the remaining pulverizer capacity must be sufficient to carry maximum boiler steam load. During boiler startup.MIL-HDBK-1003/7 (2) (3) (4) Roll and race Ball tube Attrition The various types are described in detail in the following boiler manufacturers' literature: (1) Babcock & Wilcox. 4.5. electrical demand. Stoker Coal Firing.05 mm) x 0" to 1-1/2" (38. This is usually stated as not more than 3 to 1 turndown range or ratio. 1981. The choice between the use of pulverizers or stokers can only be determined by making an economical evaluation of life cycle costs which include cost of equipment and installation. Sizing of pulverizers must be coordinated with the boiler manufacturer and usually requires the development of a set of coordination curves of the various factors involved such as shown on Figure 10. d) Coal Feed Size. the larger is the coal size which can be accommodated. b) Turndown Ratio. Inc. and supplies. It is desirable to have at least a 3 to 1 turndown on automatic control with all burners and pulverizers in service. Pulverizer output varies with coal grindability index and fineness (percent through 200 mesh) of grind. electrical energy. more rigid coal specifications. 35 . the boiler size breakpoint was approximately 300. Pulverized coal systems are of high installation costs. Crushed coal is used as the feed stock for pulverizers. The maximum coal feed size is dependent upon pulverizer size. maintenance labor and parts.000 pph (113 000 kg/hr). for industrial power applications. operating labor. Presently there is a downward trend and the breakpoint for boiler size is approximately 250. without reducing the number of burners fed from the pulverizer(s) is approximately 35 percent to 100 percent of the maximum pulverizer coal capacity. fuel. 1978.000 pph (136 000 kg/hr) with pulverizers predominantly used at this boiler load and above.
In wood burning applications. The result is an increase in boiler efficiency. drives and general requirements.7 Soot Blowers. Dry wood may have a heating value of 8. regarding the use of rail car scales and the use of truck scales for coal delivery.6 Coal Scales.9 Air Heaters.6 Wood Firing. 37 . drives. 4. methods should be researched thoroughly and their successful operation.6. refer to MIL-HDBK-1003/6. and general requirements. For burning wood as a fuel to produce steam or high temperature water (HTW). The ash or unburned particles are collected on traveling grate and transported to ash pit. coal. Air heaters should be used to burn bark and wood chips and may be used for other fuels if economically justified or required for combustion. along with preheated air. Combustion systems for wood are usually designed specifically for the material and mixture of fuels to be burned. For forced draft fan size. 4. 4. volumetric (volume rate of flow measurement) belt. In addition. Spreader stokers and cyclone burners work well for this application. with the purpose of inducing high turbulence in the boiler. adequate source of fuel.750 Btu/lb (4071 kJ/kg). or gas can be used or the wood must be mixed with low-moisture fuels so that enough energy enters the boiler to support combustion. See MIL-HDBK-1003/6.MIL-HDBK-1003/7 4. Additional information regarding soot blowers and blowing mediums are presented in MIL-HDBK-1003/6. 4. heat releases have been as high as 1.000 Btu/ft2/hr. types. allowances must be made for leakage and pressure requirements for air pollution control equipment. supplemental firing of coal. (11 357 373 kJ/m2/hr) of active grate area. For application and design considerations. These are located at the in-plant bunker outlet and may be of the batch weigh bucket.1 Suspension Burning. 6 fuel oil. the induced draft fans must be able to accommodate the boiler full test steam load when the scrubbers are not in operation. but at 80 percent moisture. Coal scales are also used to measure coal feed to stokers or pulverizers. 4. 4.5.000. see MIL-HDBK-1003/6. over 60 to 65 percent. When the moisture content is high. Small wood chips or saw dust are blown into the furnace chamber and burned in suspension. For induced draft fan size. and all but the largest particles are burned before they reach the grate at the bottom of the furnace.750 Btu/lb (20 353 kJ/kg). The usual practice when burning wood is to propel the wood particles into the furnace through injectors. and wood and may or may not be required for No. a pound of wet wood has a heating value of only 1. When flue gas scrubbers are used. refer to MIL-HDBK-1003/6. The wood is injected high enough in the combustion chamber so that it is dried. 4. Economizers are located in the boiler flue gas outlet duct and are used to heat the incoming feedwater by reducing the flue gas temperature.10 Forced Draft Fans. oil.11 Induced Draft Fans. types. or gravimetric (weight rate of flow measurement) belt type. 2 fuel oil. and economics evaluated. Soot blowers are required for No. For additional information see MIL-HDBK-1003/6.8 Economizers.
On coal stoker-fired installations. steam driven boiler feed pumps. 4. 4.16 Blowdown Equipment.1 Steam Drive Auxiliaries. with total pumping capacity to suit the ultimate plant capacity. Paragraph PG61) requirement of two means of feeding water. Part of the fan discharge goes through a section of the air heater or separate air heater which in turn raises the temperature to 500 degrees F (260 degrees C) or 600 degrees F (315 degrees C). Overfire air fans are used on stoker fed coal fired boilers to reduce smoke and to improve combustion efficiency by mixing with unburned gases and smoke. Primary air fans may be used on large pulverized coal fired boilers in lieu of pulverizer blowers or exhausters. "Water Treatment". see Table 6. The pressure and volume of overfire air must be sufficient to produce the proper turbulence for efficient burnup of the unburned gases and suspended fuel particles. Fan size is determined by the boiler manufacturer and furnished with the boiler. Section 7. 4.MIL-HDBK-1003/7 4. The quantity of overfire air is usually between 5 and 15 percent of the total air needed for combustion of the coal fuel. 4. Fan size is determined by the boiler manufacturer and furnished with the boiler.18 Equipment Selection. Primary air fans usually provide both hot and cold air which can be tempered before being introduced into the pulverizers. are required to satisfy the ASME Boiler and Pressure Vessel Code (Section 1.15 Stacks. The hot air is then ducted and tempered with the cold air to provide the motive and drying air to the pulverizers at the proper temperature. refer to MIL-HDBK-1003/6. These pumps shall be primarily connected to the boiler feed header from the deaerator and also to the treated water line for an emergency water source for the boilers.13 Overfire Air Fans. 4.17 Essential Plant Equipment 4. see MIL-HDBK-1003/6. Cinder return fans are used on some stoker fed coal fired boilers for reinjection of fly ash from last pass hoppers and mechanical dust collectors. For information relative to boiler blowdown and blowdown equipment. The cold air is atmospheric air supplied from the fan discharge.17. 4. For design information and requirements needed to design 38 . boiler plants.12 Primary Air Fans. For description and sizing of stacks.14 Cinder Return Fans.
000 to 160. * Casing to withstand not * * * less than 20 inches W.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 39 . gas. * Maximum casing surface * * * temperature not to exceed * * 150 degrees F.MIL-HDBK-1003/7 Table 6 Equipment Selection For Boiler Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). * * * * Air heater Tubular or regenerative Use for wood firing. temperature above dew point.G.000 pph Coal/oil or coal/oil/gas * * (shop assembled) or coal fired * * * Coal/oil or coal fired. Maximum * * * temperature of combustion * * air shall not exceed 350 deg F * * for coal stoker or wood chip * firing.000 pph * (field erected) Gas can be used if allowed * * by current energy policy. temperature from 230 deg F * * * to 250 degrees F depending * * on sulfur content of fuel. Keep * * outlet gas temperature * above dew point. pulverized coal firing * * * may use temperatures up to * * 600 deg F. * * * * * Economizer Bare tube or cast iron Use where economically * * (part of boiler covered tube for coal justified. * * * * Finned tubes for No.000 to 25. * * * * Superheater Drainable * * * (part of boiler) * * . some * * coal firing where required * for proper combustion or when * * * economically justified. 2 Keep water inlet * fuel oil. Minimum flue gas * * temperature range is 300 to * 350 degrees F. * Equipment Size or Type Pertinent Information * * * * Water tube boiler 10. * * Water tube boiler 30. Keep outlet gas * * unit) or high sulfur oil.
air pollution regulation * or with a dry scrubber. * * Draft Forced and * * * Induced * * * Induced draft fan Straight radial with Safety factor for test * shrouds or radial tip block ratings. Use * * * jet or reverse air with fuel with sulfur * * between 50. * * * * .000 and content in compliance with * * 100. 20 to 25% excess * * pressure.) Equipment Selection For Boiler Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). Coal.000 actual cubic gas. Use * * * upstream of baghouse. 10 to 15% excess * * * volume. Add 25 deg F to * temperature of gas. Centrifugal thickness blade for ID fans. * * * * * Wet scrubber Flue gas desulfurization for * fuel sulfur content up to 4. Do not use for oil * * * cubic feet per minute firing because of bag * * (ACFM). Reverse air blinding or for wood chip * * cleaning over 100. * Equipment Size or Type Pertinent Information * * * * Forced draft fan Backward inclined or Safety factor for test * * MIL-F-18523. oil and * backward inclined) gas.MIL-HDBK-1003/7 Table 6 (Cont.000 ACFM. high Flue gas large particulate * * cyclone dust efficiency removal.000 or solid waste firing be * ACFM. 60 to 80% * * collector efficiency is common minimum * protection for ID fan. * * * * * Mechanical Multiple tube. Use with fuel * which is in compliance with * * * air pollution control * regulations for sulfur. Either pulse cause of fire hazard. * * * * Electrostatic Rigid frame Particulate removal from * * precipitator flue gas. backward curved single block ratings same as * * Fan.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 40 .5% * * * * * Baghouse Pulse jet cleaning up Particle removal from flue * to 50. 20% * * MIL-F-18523 * (forward curvedexcess pressure.
* Deaerating * * * * Boiler feed pumps Coal fired plants For adequate minimum pump * and oil or gas flow. system for each pump. Horizontal split case or * * Condenser * condensate Size each for 1. * Equipment Size or Type Pertinent Information * * * * Soot blowers Compressed air Required for burning No. use automatic flow * * (centrifugal) * MIL-P-17552 fired boilers: control valve or automatically * * horizontally one motor driven controlled discharge * * split. to permit instantaneous * changeover from one drive * * * to the other.MIL-HDBK-1003/7 Table 6 (Cont. Use * * Deaerating * heater and tank storage capacity at with multiport back * * MIL-H-1766OC. * capacity * * Heater. 2 fuel oil. Consider dual * * 1.) Equipment Selection For Boiler Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). Fluid. * Not required for gas firing. high * alloy pumps boiler steaming storage tank. * Pump to be 1. For * straight condensing plant * * * use 60 to 90 minutes. plus two variable speed drive if * * steam driven pumps over 10 HP.6 * * or steam operated fuel oil and coal and * * possibly for No. * * * * * Condensate 60 to 180 minute Steel plate tank with * storage capacity at corrosion resistant liner * * receiver * ultimate plant suitable for 250 degrees F.25 x half of motor drive and steam * ultimate plant turbine drive with clutch * * * capacity. * * * 15 to 20 minutes Tray type to be used. ultimate plant pressure relief valve.25 x Discharge water to deaerator * * multistage. Consider * * capacity. * capacity. * * * For automatic extraction * * plant use 180 minutes.25 x vertical can type pumps. * * * Two per condenser. * condenser maximum flow * * pumps * rate. * * * * * . pump per boiler.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 41 .
Discharge of * * pumps to be 1. * .) Equipment Selection For Boiler Plants +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). tank. * * * * Steam Turbines Size for maximum Can be used for condensate * * for Mechanical horsepower required transfer pump. under all possible pump. steam flow. over * * Steam Turbines * for Mechanical fire fan. * operating conditions induced draft fan. * * * the motor driven * pumps. * * turbine driven pump Horizontal split case or * in lieu of one of vertical can type pumps. loads. Each pump each pump. * * Consider both motor drive * and steam turbine drive * * * with overrunning clutch * or units to permit * * instantaneous changeover * * from one drive to the other.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 42 . boiler feed * * Drive MIL-T-18246. * Equipment Size or Type Pertinent Information * * * * Condensate Two motor driven pumps Provide bypass orifice at * * transfer per boiler. forced draft fan. Use to reduce * * Drive electric consumption of * * heating plant.MIL-HDBK-1003/7 Table 6 (Cont. Assure * sufficient electric * * * auxiliaries to preclude * * atmospheric exhaust * * during low-load periods.25 x boiler bypass to go to condensate * steaming capacity. * * * * * Feedwater Two element (steam Use three element pump * flow/drum level) control where boilers are * * regulators * pump control or operated simultaneously or * * three element (drum have severely fluctuating * level. * * * water-flow) * * pump control. Consider variable * * MIL-P-17552 * Consider one steam speed drive if over 10 HP.
1. Condensing units exhaust at pressures between 1 inch of mercury absolute (Hga) and 5 inches Hga.000 kW to 30. 5. and sizes of steam generators and turbine drives and extraction pressures. temperatures. types. b) Condensing Turbines. which is defined as a power plant simultaneously supplying either electric power or mechanical energy and heat energy. including pressures. Back pressure turbine units usually exhaust at pressures between 5 psig (34 kPa gage) and 300 psig (2068 kPa gage) with one or two controlled or uncontrolled extractions.2.1 Smaller Turbines. non-fuel operating costs.1. Turbines for 5. or up to five uncontrolled extractions. 5. 5.3. Single stage turbines. The cycle of a steam power plant is the group of interconnected major equipment components selected for optimum thermodynamic characteristics. either back pressure or condensing.000 kW shall be multi-stage.2 Controlled Extraction-Condensing Cycles and Back Pressure Cycles. either back pressure or condensing types.MIL-HDBK-1003/7 Section 5. A schematic diagram of an uncontrolled extraction-cycle is shown in Figure 11.1. Controlled extraction is normally applied where the bleed steam is exported to process or district heat users. cost of money. 5.3. Straight condensing cycles or condensing units with uncontrolled extractions are applicable to plants or situations where security or isolation from public utility power supply is more important than lowest power cost. a) Back Pressure Turbines. A schematic diagram of a controlled extraction-condensing cycle is shown in Figure 12. 5. Because of their higher heat rates and operating costs per unit output. fuel costs. and capacities. The function or purpose for which the plant is intended determines the conditions. Turbines under 1.2 Larger Turbines.1 Definition.2. Selection of the optimum cycle depends upon plant size. there is a significant price difference between controlled and uncontrolled extraction turbines. A schematic diagram of a back pressure cycle is shown in Figure 13. with up to two controlled. However. 43 .1.1.000 kW may be single stage units because of lower first cost and simplicity. and maintenance costs. are not equipped with extraction openings. the former being more expensive.1 Typical Plants and Cycles STEAM TURBINE DESIGN 5.2 Steam Turbine Prime Movers 5. Back pressure and controlled extraction-condensing cycles are attractive and applicable to a cogeneration plant.1. it is not likely that simple condensing cycles will be economically justified for a military power plant application as compared with that associated with public utility purchased power costs.3 Selection of Cycle Conditions. and integrated into a practical arrangement to serve the electrical (and sometimes by-product steam) requirements of a particular project. multi-valve units.1. 5.1 Simple Condensing Cycles.
There is also a limit to the number of stages of extraction/feedwater heating. f) Steam generators of more elaborate design and with heat saving accessory equipment are more efficient. because the costs of lowering the exhaust pressure is more than the savings from the more efficient turbine operation. d) smaller units. High pressure topping turbines are usually installed as an addition to an existing lower pressure steam electric plant. which may be economically added to the cycle. a) Higher steam pressures and temperatures increase the turbine efficiencies. General rules to consider to improve the plant efficiency are listed hereinafter. The topping cycle consists of a high pressure steam boiler and turbine generator with the high pressure turbine exhausting steam to one or more low pressure steam turbine generators. reducing the feedwater temperature. 5. c) The use of stage or regenerative feedwater cycles improves heat rates. However.4 General Economic Rules. with greater improvement corresponding to larger numbers of such heaters. Larger turbine generator units are generally more efficient than e) Multi-stage and multi-valve turbines are more economical than single stage or single valve machines.MIL-HDBK-1003/7 5. In a regenerative cycle. Higher efficiency and a lower heat rate require more complex cycles which are accompanied with higher initial investment costs and higher operational and maintenance costs but lower fuel costs.1.1. 44 .3. there is also a thermodynamic crossover point where lowering of an extraction pressure causes less steam to flow through the extraction piping to the feed water heaters. A schematic diagram of a topping cycle is shown in Figure 14. b) Lower condensing pressures increase turbine efficiency. there is a limit where lowering condensing (back) pressure will no longer be economical.3 Topping Cycle. but temperatures above 750 degrees F (399 degrees C) usually require more expensive alloy piping in the high pressure steam system. This occurs when additional cycle efficiency no longer justifies the increased capital cost. Maximum overall efficiency and economy of the steam turbine power cycle are the objectives of a satisfactory design.
45 .
46 .
48 .
Selection of Cycle Steam Conditions
18.104.22.168 Balanced Costs and Economy. For a new or isolated plant, the choice of initial steam conditions should be a balance between enhanced operating economy at higher pressures and temperatures, and generally lower first costs and less difficult operation at lower pressures and temperatures. Realistic projections of future fuel costs may tend to justify higher pressures and temperatures, but such factors as lower availability, higher maintenance costs, more difficult operation, and more elaborate water treatment shall also be considered. 22.214.171.124 Extension of Existing Plant. Where a new steam power plant is to be installed near an existing steam power or steam generation plant, careful consideration shall be given to extending or paralleling the existing initial steam generating conditions. If existing steam generators are simply not usable in the new plant cycle, it may be appropriate to retire them or to retain them for emergency or standby service only. If boilers are retained for standby service only, steps shall be taken in the project design for protection against internal corrosion. 18.104.22.168 Special Considerations. Where the special circumstances of the establishment to be served are significant factors in power cycle selection, the following considerations may apply: a) Electrical Isolation. Where the proposed plant is not to be interconnected with any local electric utility service, the selection of a simpler, lower pressure plant may be indicated for easier operation and better reliability. b) Geographic Isolation. Plants to be installed at great distances from sources of spare parts, maintenance services, and operating supplies may require special consideration of simplified cycles, redundant capacity and equipment, and highest practical reliability. Special maintenance tools and facilities may be required, the cost of which would be affected by the basic cycle design. c) Weather Conditions. Plants to be installed under extreme weather conditions require special consideration of weather protection, reliability, and redundancy. Heat rejection requires special design consideration in either very hot or very cold weather conditions. For arctic weather conditions, circulating hot water for the heat distribution medium has many advantages over steam, and the use of an antifreeze solution in lieu of pure water as a distribution medium should receive consideration.
Steam Power Plant Arrangement
22.214.171.124 General. Small units utilize the transverse arrangement in the turbine generator bay, while the larger utility units are very long and require end-to-end arrangement of the turbine generators. 126.96.36.199 Typical Small Plants. Figures 15 and 16 show typical transverse small plant arrangements. Small units less than 5,000 kW may have the condensers at the same level as the turbine generator for economy, as shown in Figure 15. Figure 17 indicates the critical turbine room bay clearances. 5.1.7 Heat Rates. The final measure of turbine cycle efficiency is represented by the turbine heat rate. It is determined from a heat balance of the cycle, which accounts for all flow rates, pressures, temperatures, and enthalpies of steam, condensate, or feedwater at all points of change in these thermodynamic properties. Heat rate is an excellent measure of the fuel economy of power generation. 126.96.36.199 Heat Rate Units and Definitions. The economy or efficiency of a steam power plant cycle is expressed in terms of heat rate, which is total thermal input to the cycle divided by the electrical output of the units. Units are Btu/kWh. a) Conversion to cycle efficiency, as the ratio of output to input energy, may be made by dividing the heat content of one kWh, equivalent to 3412.14 Btu by the heat rate, as defined. Efficiencies are seldom used to express overall plant or cycle performance, although efficiencies of individual components, such as pumps or steam generators, are commonly used. b) Power cycle economy for particular plants or stations is sometimes expressed in terms of pounds of steam per kilowatt hour, but such a parameter is not readily comparable to other plants or cycles and omits steam generator efficiency. c) For mechanical drive turbines, heat rates are some times expressed in Btu per hp-hour, excluding losses for the driven machine. One horsepower hour is equivalent to 2544.43 Btu.
Turbine Heat Rates
a) Gross Turbine Heat Rate. The gross heat rate is determined by dividing the heat added in the boiler between feedwater inlet and steam outlet by the kilowatt output of the generator at the generator terminals. The gross heat rate is expressed in Btu per kWh. For reheat cycles, the heat rate is expressed in Btu per kWh. For reheat cycles, the heat added in the boiler includes the heat added to the steam through the reheater. For typical values of gross heat rate, see Table 7. Table 7 Typical Gross Turbine Heat Rates
+)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))), Throttle Throttle Reheat Cond. * * * Turbine Generator Pressure Temp. Temp. Pressure HeatRate * psig F F in. Hg Abs. Btu/kWh * * Rating, kW * * * 11,500 600 825 1 1/2 10,423 * 850 900 1 1/2 9,462 * * 30,000 * 60,000 1,250 950 1 1/2 8,956 * * 75,000 1,450 1,000 1,000 1 1/2 8,334 * 1,800 1,000 1,000 1 1/2 7,904 * *125,000 .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))-
b) Net Turbine Heat Rate. The net heat rate is determined the same as for gross heat rate, except that the boiler feed pump power input is subtracted from the generator power output before dividing into the heat added in the boiler. c) Turbine Heat Rate Application. The turbine heat rate for a regenerative turbine is defined as the heat consumption of the turbine in terms of "heat energy in steam" supplied by the steam generator, minus the "heat in the feedwater" as warmed by turbine extraction, divided by the electrical output at the generator terminals. This definition includes mechanical and electrical losses of the generator and turbine auxiliary systems, but excludes boiler inefficiencies and pumping losses and loads. The turbine heat rate is useful for performing engineering and economic comparisons of various turbine designs. 184.108.40.206 Plant Heat Rates. Plant heat rates include inefficiencies and losses external to the turbine generator, principally the inefficiencies of the steam generator and piping systems; cycle auxiliary losses inherent in power required for pumps and fans; and related energy uses such as for soot blowing, air compression, and similar services. a) Gross Plant Heat Rate. This heat rate (Btu/kWh) is determined by dividing the total heat energy (Btu/hour) in fuel added to the boiler by the kilowatt output of the generator.
1. are usually based on calculations of cycle performance at specified steady state loads and well defined. on a simplified flow diagram of the cycle. and predictions of steam plant performance shall allow for all normal and expected losses and loads and should. are reflected in plant operating heat rate data. and calculated cycle heat rates based on these factors. and failure to operate at optimum conditions. The gradual and inevitable deterioration of equipment. Computer programs have been developed which can quickly optimize a particular cycle heat rate using iterative heat balance calculations. fluid pressures and temperatures. The designer is required to develop and optimize a cycle heat balance during the conceptual or preliminary design phase of the project. When the turbine throttle pressure and temperature and the turbine exhaust pressure (or condensing pressure) are known. 55 .7. fluid enthalpies.1. wide open).1. Both turbine and plant heat rates.7. plant lighting. This heat rate is determined by dividing the total fuel energy (Btu/hour) added to the boiler by the difference between power (kilowatts/hour) generated and plant auxiliary electrical power consumed.1. 75. electric power output. Calculations.8. startup and shutdown losses.8 Steam Rates 5. estimates. A heat balance is usually developed for various increments of plant load such as 25. 5. 5. fuel deterioration losses. 1969. general water supply. 50. optimum operating conditions. and related items.6 Plant Economy Calculations. 100 percent and VWO (valves. 5. the theoretical steam rate can be calculated based on a constant entropy expansion or can be determined from published tables.7. See Theoretical Steam Rate Tables. See Table 8 for typical theoretical steam rates. 5. therefore. Use of such a program should be considered. reflect predictions of monthly or annual net operating heat rates and costs. Plant operating heat rates are actual long term average heat rates and include other such losses and energy uses as non-cycle auxiliaries.1 Theoretical Steam Rate. The American Society of Mechanical Engineers. air conditioning and heating.5 Long Term Averages. all significant fluid mass flow rates. Electric and district heating distribution losses are not usually charged to the power plant but should be recognized and allowed for in capacity and cost analyses.1. The heat balance depicts. as above.4 Cycle Performance.MIL-HDBK-1003/7 b) Net Plant Heat Rate. Such heat rates are seldom achieved in practice except under controlled or test conditions.
17 24. = 3413/(h1 . lb/kWh h1 = throttle enthalpy at the throttle pressure and temperature.35 13.78 7.46 * 71.53 19.56 19.68 9.1 35.52 * * 20 PSIG 37.78 11.89 * 22.76 * 41.40 23.43 5.33 14.72 7.12 10.74 16.65 26.56 26.94 5.31 12.79 * *150 PSIG *200 PSIG 43. The engine efficiency can be calculated using the following equation: EQUATION: ne = (h1 . * Pin.8.83 8.75 17.31 10.56 14.80 10.34 5. = theoretical steam rate of the turbine.8 31.28 5.82 21. P * 10.42 8.05 6.93 22.63 12.36 6.65 11.71 10.22 10.14 8.MIL-HDBK-1003/7 Table 8 Theoretical Steam Rates LB/KWH +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).40 * * 1" HGA * 2" HGA 11.07 14.08 9.02 8.26 12.44 10.S.76 9.66 8.he)ntng/(h1 .35 13.79 26.15 17.R.93 5.08 * *300 PSIG 40.92 5.09 6. Sat.6 42.62 5.96 20.96 * 29.57 11.10 7. Btu/lb h2 = extraction or exhaust enthalpy at the exhaust pressure based on isentropic expansion.38 11.3 35.03 22.27 7.90 10.77 12.30 29.43 23.85 6.70 * 78.69 * *600 PSIG 73.43 9.15 9.81 8.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- The equation for the theoretical steam rate is as follows: EQUATION: where: T.86 18.35 * .26 * * 10 PSIG * 15 PSIG 33.51 26.53 14.99 26.8 35.2 Turbine Generator Engine Efficiency.96 9.87 25.69 * * 3" HGA 12.S.07 19.76 6.82 8.h2) (1) 56 .73 17.10 17.20 22.05 16. 550 750 825 900 950 1000 1000 * * * * Exhaust.05 14.98 * * 25 PSIG * 50 PSIG 74.62 9.52 * *400 PSIG *500 PSIG 49.53 6.PSIG 100 200 250 400 600 850 1250 1450 1600 * * Tin.52 21.h2) (2) T.17 8.72 14.91 8.R.F Sat.71 8.31 20.66 17.38 8. The engine efficiency is an overall efficiency and includes the entire performance and mechanical and electrical losses of the turbine and generator.70 14.20 9. Btu/1b.14 8.99 10.49 8.19 9.94 * *100 PSIG 66.34 10.90 11.29 8.07 7. 5.42 9.16 5.10 19.1.52 14.71 7.62 * * 0 PSIG * 5 PSIG 26.73 5.02 11.15 12.03 28.35 15.83 18.
and the size of the steam turbine. the loading of the steam turbine.S.R. The resulting steam rate is expressed in pounds of steam per kWh. produced by that amount of steam.2. lb/kWh.S. The actual steam rate can also be determined by dividing the theoretical steam rate by the engine efficiency of the turbine generator.1 Definition. 5.S. Cogeneration in a steam power plant affects the design of the steam turbine relative to the type of cycle used.8.3 Actual Steam Rate. Btu/lb nt = Turbine mechanical efficiency ng = Generator efficiency Engine efficiency is usually obtained from turbine generator manufacturers or their literature. = T. and thence from the turbine exhaust (or extraction) opening to a lower pressure steam (or heat) distribution system for general heating. Appendix C presents a further discussion on steam plant cogeneration.MIL-HDBK-1003/7 where: ne = Turbine generator engine efficiency h1 and h2 = (see Equation 1) he = Actual extraction or exhaust enthalpy. at the generator terminals. EQUATION: where: A. refrigeration. Therefore. 5. = actual steam rate of the turbine.R. 5. or process use. the exhaust or extraction pressures required. Typical turbine generator engine efficiencies are provided in Figure 18. In steam power plant practice.R.2 Cogeneration in Steam Power Plants. cogeneration normally describes an arrangement whereby high pressure steam is passed through a turbine prime mover to produce electrical power./ne (3) 57 . A. it is not usually necessary to calculate engine efficiency.1. The actual steam rate of a turbine can be determined by dividing the actual throttle steam flow rate in pounds per hour by the actual corresponding kilowatts.
or where the electrical load must be carried at times of very low (or zero) heat demand. When the exhaust (or extraction) steam from a cogeneration plant can be utilized for heating.2 Extraction-Condensing Cycle. then condensing-controlled extraction steam turbine prime movers. which are slightly lower at high pressure. up to 75 per cent of the total fuel energy can be utilized. steam. Where the electrical demand does not correspond to the heat demand. They.4. requires complete condensing and heat rejection equipment. is also a convenient medium for area distribution of heat.2. the early selection of a relatively low steam distribution pressure is easily accommodated in the design of distribution and utilization systems. may be applicable. b) Often.2. If a good balance can be attained. the entire flow to the turbine is exhausted (or extracted) for heating steam use. Steam power cycles are particularly applicable to cogeneration situations because the actual cycle medium. 59 . 5. or process purposes in reasonable phase with the required electric power load. While very flexible.2.2. In a back pressure turbine. 5. Back pressure turbine generators are limited in electrical output by the amount of exhaust steam required by the heat load and are often governed by the exhaust steam load. a) The choice of the steam distribution pressure should be a balance between the costs of distribution. This cycle is more effective for heat economy and for relatively lower cost of turbine equipment. Such a turbine is arranged to carry a specified electrical capacity either by a simple condensing cycle or a combination of extraction and condensing. refrigeration.2. as compared with about 40 percent for the best and largest Rankine cycle plants and about 25 to 30 percent for small Rankine cycle systems. c) Hot water heat distribution may also be applicable as a district heating medium with the hot water being cooled in the utilization equipment and returned to the power plant for reheating in a heat exchange with exhaust (or extraction) steam. 5. there is a marked economy of fuel energy because the major condensing loss of the conventional steam power plant (Rankine) cycle is avoided. usually operate in electrical parallel with other generators.4. because the prime mover is smaller and simpler and requires no condenser and circulating water system. whereas the hasty selection of a relatively high steam distribution pressure may not be recognized as a distinct economic penalty on the steam power plant cycle. 5.4 Cycle Types.3 Relative Economy. and must always pass a critical minimum flow of steam to its condenser to cool the low pressure buckets. are the back pressure and extraction-condensing cycles. as shown in Figure 12.MIL-HDBK-1003/7 5.2 Common Medium. therefore.1 Back Pressure Cycle. which may be combined in the same plant or establishment. and the gain in electrical power output by selection of a lower turbine exhaust or extraction pressure. The two major steam power cogeneration cycles. the extraction machine is relatively complicated.
intermediate.2 High Pressure Non-Extraction Type.3. The condenser pressure is comparable to that with high pressure extraction machines. High pressure steam enters the turbine throttle and expands through the turbine to the condenser. Any cogeneration plant will be more effective and economical if the heat distribution medium is chosen at the lowest possible steam pressure or lowest possible hot water temperature. There should be a fairly high coincidence.2. 60 .1. and power cycle effectiveness should be optimized. 5.5.3. Hot water heat distribution should also be considered where practical or convenient. diesel. because hot water temperatures of 200 to 240 degrees F (93 to 116 degrees C) can be delivered with exhaust steam pressure as low as 20 to 50 psig (138 to 345 kPa gage).1 Load Balance. of time and quantity demands for electrical power and heat. a conventional steam (cogeneration) plant will be practical and economical only above some minimum size or capacity. and environmental heating. 5. The high pressure non-extraction type of turbine is basically the same as the extraction type described in 5.1 Turbine Types Condensing Types 5. A typical cycle using a high pressure extraction type turbine is shown in Figure 12.5.1 above.3 Size. While there is no absolute minimum size of steam power plant which can be built for cogeneration.2. cogeneration cycles will meet the following criteria: 5.3. There should be a reasonably balanced relationship between the peak and normal requirements for electric power and heat. The peak/normal ratio should not exceed 2:1. and low pressure turbines is not definite.3. For minimum economic feasibility. Turbines with throttle pressures generally above 400 psig (2758 kPa gage) are considered high pressure machines.1 High Pressure Extraction Type.4 Distribution Medium. the exact demarcation between high. or gas turbine become more economical and convenient. Turbines built with provisions for extraction of steam from the turbine at intermediate pressure points below the throttle pressure are called extraction turbines. except no steam is extracted from the turbine.2. 5. 5. The power energy delivered by the turbine is highest when the exhaust steam pressure is lowest. feed water heating. not less than 70 percent.3 5.MIL-HDBK-1003/7 188.8.131.52.1. The extracted steam may be used for process systems. The balance between distribution system and heat exchanger costs. however.2 Load Coincidence. for example.5.5 Criteria For Cogeneration. 5. Substantial cycle improvement can be made by selecting an exhaust steam pressure of 40 psig (276 kPa gage) rather than 125 psig (862 kPa gage). below which other types of cogeneration.2.
Double automatic extraction turbines consist of a high.MIL-HDBK-1003/7 5.2 Noncondensing Types 5.1. and 5.3. or it may be the excess from auxiliary equipment or processes.1. The exhaust pressure of the high pressure turbine is held constant by means of automatic extraction gear (valve) that regulates the amount of steam passing to the low pressure turbine.) or noncondensing (usually 5 to 15 psig (34 to 103 kPa gage) back pressure).3.3 above. This type of machine is also called an admission type. and Figure 14 in this handbook for a description of topping turbine and cycle.2.1 Superposed or Topping Type.22.214.171.124 Low Pressure Type.1.3. the pressure dividing point varies.) The variations as described in 5. intermediate. Automatic extraction turbine generators operating automatically meet both automatic extraction steam and electrical demands by adjusting the flow of steam through the low pressure turbine. Low pressure turbines are those with throttle pressures generally below 400 psig (2758 kPa gage). except steam is admitted instead of extracted at the automatic controlled opening.0 inches of Hg Abs. 5. and low pressure turbine section and provide steam in the range of 50 to 150 psig (345 to 1034 kPa gage) at one automatic extraction opening and 10 to 15 psig (69 to 103 kPa gage) at the other automatic extraction opening.3.3.3 Automatic Extraction Type. The mixed pressure or induction type turbine is supplied with steam to the throttle and also to other stages or sections at a pressure lower than throttle pressure.184.108.40.206. high temperature throttle steam supply to a high pressure turbine section. Single automatic extraction turbines provide steam at a constant pressure from the automatic extraction opening. depending on the manufacturer and type of turbine (industrial. usually in the range of 50 to 150 psig (345 to 1034 kPa gage). Refer to para 5. Automatic extraction turbines may be either condensing (condenser pressure 1. 5.1.1. 5.3 above are also applicable to low pressure turbines.3.1.0 to 4.3. The steam admitted into the lower pressure openings may come from old low pressure boilers. Automatic extraction turbines usually operate with high pressure. etc. However. 61 . 5.4 Mixed Pressure or Induction Type.3. mechanical drive. The mixed pressure turbine is the same as an automatic extraction turbine described in 5. A typical automatic extraction cycle is shown in Figure 19.
Single stage geared units are available in sizes from 100 kW to 3.3.2. generate as much electricity as possible from the steam passing through the turbine. therefore. The other method of control allows the turbine steam flow to be such as to provide whatever power is required from the turbine by driven equipment. 5. in the process. 5.2 Geared Turbine Generator Units. single stage turbines utilize throttle steam at pressures from less than 100 psig (689 kPa gage) and saturated temperatures up to 300 psig and 150 (66 degrees C) to 200 degrees F (93 degrees C) of superheat. and exhaust at steam pressures in the range of 5 to 300 psig (34 to 2068 kPa gage). Multistage units are also available as single valve or multi-valve.5 Turbine Throttle Pressure and Temperature.1 Noncondensing and Automatic Extraction Turbines.4. These turbines are used in power plants to drive equipment such as pumps and fans. See Table 9 for nominal size and other characteristic data for turbine generator units. One of the methods modulates the turbine steam flow to be such as to maintain the turbine exhaust pressure constant and. Un-controlled steam extraction openings can be provided depending on throttle pressure and exhaust pressures. The turbine exhaust steam must then be used. must be vented to the atmosphere. 5.3 Atmospheric Exhaust.3. The selection of turbine throttle pressure and temperature is a matter of economic evaluation involving performance of the turbine generator and cost of the unit including boiler. 5. The amount of electricity generated. A typical back pressure cycle is shown in Figure 13. Geared turbine generator units utilizing multistage mechanical drive turbines are available in sizes ranging generally from 500 to 10.2. the alternative turbine valve and stage arrangements should be considered and economically evaluated within the limits of their capabilities. high temperature throttle steam supply.4.2 Back Pressure Type. Because of overlapping size range. at the rate flowing through the turbine. 5.1 Selection of Throttle Pressure and Temperature. piping. if any. The sizes of turbine generators and types of generator cooling as shown in Table 9 generally apply also to these types of turbines. 63 .4 Turbine Generator Sizes. and fittings.000 kW. Two methods of control are possible. 5.MIL-HDBK-1003/7 5. valves.5. Atmospheric exhaust is the term applied to mechanical drive turbines which exhaust steam at pressures near atmospheric. which allows further division of size range. Small.000 kW. Back pressure turbines usually operate with high pressure. changes upward or downward with like changes in steam demand from the turbine exhaust. by other steam consuming equipment or excess steam. Steam pressures and temperatures applicable to larger multistage turbines are shown in Table 10.
MIL-HDBK-1003/7 Table 9 Direct Connected Condensing Steam Turbine Generator Units +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).000 Hydrogen * * SCSF 23 40.Tandem Compound Double Flow Exhaust 64 .Tandem Compound Single Flow Exhaust TCDF .000 Air * SCSF 14 20.000 Hydrogen * * * * Utility-Sized * * * * TCDF 16.5 7.000 Hydrogen * * TCDF 20 75.000 Hydrogen * * SCSF 25-26 50.000 Air * * SCSF 11.000 Hydrogen * TCDF 16.750 Air * * * SCSF 7 5.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 1.500 Air * * * SCSF 10 10.000 Hydrogen * * * * * * Reheat Units (Reheat is never offered for turbine-generators of * less than 50 MW). In. kW Cooling * * and Exh.000 Hydrogen * * TCSF 25-26 75. SCSF . * * * * TCSF 23 60.000 Air * * * SCSF 17-18 25. * Nominal Nominal Typical * * Turbine Type Last Stage Turbine Generator * Blade Length.5-18 100.000 Hydrogen * TCDF 23 100.500 Air * SCSF 6 3.5 12.250 Air * SCSF 8.Single Case Single Flow Exhaust TCSF .000 Hydrogen * * * * .000 Air * * SCSF 20 30.5-18 60. Size.000 Air * * SCSF 7 6. Flow1 * * * * Non-Reheat Units * * * Industrial Sized * * * * SCSF 6 2.500 Air * * SCSF 13 15.
this handbook. Table 11 Typical Turbine Throttle Steam Pressure-Temperature Conditions +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).000 Reheat * .000 to 50. 850 degrees F (454 degrees C) for carbon molybdenum steel.000 to 30.1. and 1.250 .000 1. * Pressure.1.000 * * .600 1.5.000 degrees F (538 degrees C) for 2-1/4 percent chromium .250 900 or 950 * * 1.000 1.825 * 20.1/2 percent molybdenum steel.1. See Section 7. Typical turbine exhaust pressure is as shown in Table 12.825 * * 7.6 Turbine Exhaust Pressure. Throttle steam temperature is also dependent on moisture content of steam existing at the final stages of the turbine.500 to 6.1.000 500 . degrees F * * * * 250 500 or 550 * * 400 650 or 750 * 600 750 or 825 * * * 850 825 or 900 * * 1. 5.600 750 . * Unit Size.250 300 .1 percent molybdenum. psig Temperature.000 750 .900 * * * 40.400 650 .450 950 . Traditional throttle steam conditions which have evolved and are in present use are shown in Table 11.450 950 or 1.000 * 1.000 * 60. Steam Condenser.500 to 15. 900 degrees F (482 degrees C) for 1/2 to 1 percent chromium .250 . psig Temperature Range.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 5. kW Pressure Range.2 Economic Breakpoints.000 and * * * 1. Economic breakpoints exist primarily because of pressure classes and temperature limits of piping material that includes valves and fittings.MIL-HDBK-1003/7 Table 10 Turbine Throttle Steam Pressures and Temperatures +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 65 . General limits of steam temperature are 750 F (399 degrees C) for carbon steel. The exhaust pressure of condensing turbines is dependent on available condenser cooling water inlet temperature. 950 degrees F (510 degrees C) for 1-1/4 percent chromium .850 825 .1/2 percent molybdenum steel. deg F * * * * 2.450 825 . Moisture content must be limited to not more than 10 percent to avoid excessive erosion of turbine blades.000 to 125.
and stainless steel. b) Bearing oil pump types and arrangement are determined from turbine generator manufacturers' requirements. and accessories.4.300 * * * Atmospheric pressure -0 . At least one of the auxiliary oil pumps shall be separately steam turbine driven or DC motor driven. if necessary.4. aluminum-brass.300 * * Superposed (topping) -200 . rotating ring-oiled bearings.50 * .0 1 .5 .7 Lubricating Oil Systems 5. Hg Abs. oil coolers.MIL-HDBK-1003/7 Table 12 Typical Turbine Exhaust Pressure +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).100 * Back pressure -5 . arsenical copper. psig * * * * Multivalve multistage 0.2 Multistage Turbines.5 0 . This arrangement is provided with one or more separate auxiliary oil pumps for startup and emergency backup service. Standard tube material is usually inhibited admiralty or 90-10 copper-nickel. For some hydrogen cooled generators. water cooled oil coolers shall be used. two full capacity.3.5 . bearing oil pumps. the bearing oil and hydrogen seal oil are served from the same pumps.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 5. 66 . Turbine generators should be supplied with a main oil pump integral on the turbine shaft.5 . c) Where separate oil coolers are necessary. water-cooled.7. Turbine generator manufacturers' standard design for oil coolers is usually based on a supply of fresh cooling water at 95 degrees F (35 degrees C) at 125 psig (862 kPa gage).1 Single Stage Turbines. The lubricating oil system for small. single stage turbines is self-contained. Multistage turbines require a separate pressure lubricating oil system consisting of oil reservoir. 5. Other tube materials are available. including 70-30 copper-nickel. These design conditions shall be modified.600 * Single valve multistage 1.0 0 . usually consisting of water jacketed. a) The oil reservoir's capacity shall provide a 5 to 10 minute oil retention time based on the time for a complete circuit of all the oil through the bearings. Condensing Non-Condensing * * * Turbine Type In. to accommodate actual cooling water supply conditions. pressure controls.7.300 * * * Single valve single stage 2.
provide one storage tank and one oil transfer pump. is used continuously except during times the centrifuge is used. and Purification of Steam and Gas Turbine Lubricating Systems.7. Two storage tanks can be provided when separate tanks are desired for separate storage of clean and used oil. Flushing. and a storage compartment which contains a polishing filter consisting of multiple cellulose cartridge filter elements. However. Particle filters are generally sized for not less than 5 microns to avoid removal of silicone foam inhibitors if present in the turbine oil used. Refer to ASME Standard LOS-1M. The purification system shall be either one of the following types. The particle filter.7. The storage tank capacity should be equal to. Both centrifuge and particle size filters are suitable for turbine oil purification. 67 .2 Multistage Oil Conditioner. The circulating pump receives oil from the storage compartment and pumps the oil through the polishing filter and back to the turbine oil reservoir. 5. a gravity filtration compartment containing a number of clothcovered filter elements. See Figure 21 for arrangement of equipment. careful selection of the purification equipment is required to avoid the possibility of additive removal by use of certain types of purification equipment such as clay filters or heat and vacuum units. The transfer pump is used to transfer oil between the turbine oil reservoir and the storage tank. a continuous bypass purification system with a minimum flow rate per hour equal to 10 percent of the turbine oil capacity shall be used. or greater than the largest turbine oil reservoir. The typical multistage conditioner consists of three stages: a precipitation compartment where gross free water is removed by detention time and smaller droplets are coalesced on hydrophobic screens.3. it may be necessary to provide an additional oil transfer pump by each turbine oil reservoir.3. 5.4 Lubricating Oil Storage Tanks. usually of the cellulose cartridge type. Because of the additives contained in turbine oils.MIL-HDBK-1003/7 5. The centrifuge is used periodically for water removal from the turbine oil. Usually a separate portable oil filter press is used for oil purification of used oil held in the storage tank. depending on plant arrangement. 5. As a minimum. ASTM-ASME-NEMA Recommended Practices for the Cleaning. See Figure 20 for arrangement of equipment.3 Oil Purifiers.7.1 Centrifuge With Bypass Particle Size Filter. Where a separate turbine oil reservoir and oil coolers are used. This latter arrangement can also be satisfied by use of a twocompartment single tank. The oil conditioner in this type of purification system operates continuously. or return oil to the turbine oil reservoir. The storage compartment must be sized to contain the flowback oil quantity contained in the turbine generator bearings and oil supply piping. The single tank can be used to receive oil from. Only one set of storage tanks and associated transfer pump is needed per plant.7.
Hydrogen pressure in the generator casing is typically 30 psig (207 kPa gage). 70 . Design pressure of 300 psig (2068 kPa gage) can be obtained as an alternate. 70-30 copper-nickel.000 kVA and smaller. approximately 2. should a turbine be selected for operation at higher than usual throttle steam temperature.S. 5. Coolers of standard design are typically rated for 95 degrees F (35 degrees C) cooling water at a maximum pressure of 125 psig (862 kPa gage) and supplied with 5/8-inch minimum 18 Birmingham wire gage (BWG) inhibited admiralty or 90-10 copper-nickel tubes. are hydrogen cooled by means of hydrogen to air heat exchangers. Refer to ASME Standard LOS-1M.000 kVA. are air cooled by drawing air through the generator by means of a shaft-mounted propeller fan. Synchronous generators are available for either 60 cycles (usually used in U. However.7. are air cooled with water cooling of air coolers (water-to-air heat exchangers) located either horizontally or vertically within the generator casing.2 Air Cooled. approximately 2. In order to thermally stabilize turbine rotors and avoid rotor warpage. 5. Generators are classified as either synchronous (AC) or direct current (DC) machines. since the normal throttle steam temperature is such that a turning gear is not necessary. a turning gear would be supplied. depending on the turbine size. the turbine generator rotor is again stabilized by turning gear rotation for several hours to several days. until the turbine shaft is stabilized. Generators. Before being placed in service."Controls and Instrumentation" of this handbook.8 Generator Types.11 Turning Gear.10 Turbine Generator Control.A. 5.9. Generators. or stainless steel are available.MIL-HDBK-1003/7 5. 5. Also. Direct current generators are used for special applications requiring DC current in small quantities and not for electric power production.500 kVA to 25. 5. The rotation of the turbine generator rotor by the turning gear is continued through a period of several hours to several days. see Section 11.500 kW are not normally supplied with a turning gear. The turning gear and turbine generator rotor are then stopped until the turbine generator is about to be again placed in service.000 kVA and larger.9.1 Self Ventilation.500 kW and larger are rotated by a motor-driven turning gear at a speed of approximately 5 rpm immediately upon taking the turbine off the line. alternate tube materials such as aluminumbrass.5 Lubricating Oil System Cleaning.) or 50 cycles (frequently used abroad). the rotors of turbine generators size 12.9 Generator Cooling 5. Turbine generators smaller than 12. For turbine generator control description. approximately 30.9. Generators. depending on the size of the turbine and the initial throttle temperature. The heat exchangers are similar in location and design to those for air-cooled generators. 5.3 Hydrogen Cooled.
2. depending on size and manufacturer of the turbine generator. Chemical or acid cleaning is the quickest and most satisfactory method for the removal of water side deposits.15. 71 . the turbine generator bearings are lubricated by use of either the main bearing oil pump or a separate turning gear oil pump. The passivation treatment produces a passive surface or forms a very thin protective film on ferrous surfaces so that formation of "after-rust" on freshly cleaned surfaces is prevented.12 Turbine Generator Foundations. Loads. start-up. Turbine generator foundations shall be designed in accordance with MIL-HDBK-1002/2.15. 5. 5. b) Clean water is used to flush out loose deposits. mechanical air exhausters.500 kW and larger.1. and Testing Pipe Cleaning 5. see Section 7. Any corrosive or explosive gases that may have formed in the unit are displaced. In general. c) The unit is treated to neutralize and "passivate" the heating surfaces. 5. and steam operated hogging ejectors. four steps are required in a complete chemical cleaning process for a boiler. and test supervision furnished by the manufacturer at the site of installation. these instructions shall be specially prepared for each machine by the turbine generator manufacturer and copies (usually up to 25 copies) shall be issued to the purchaser. Competent chemical supervision should be provided. and soluble iron salts. supplemented by consultants on boiler-water and scale problems during the chemical cleaning process. Startup.13 Auxiliary Equipment. of this handbook.6. Instructions for turbine generator installation are definitive for each machine and for each manufacturer.1 Boiler Chemical Boil out. 5. solvent adhering to the surface. a) The internal heating surfaces are washed with an acid solvent containing a proper inhibitor to dissolve the deposits completely or partially and to disintegrate them.1 Cleanup. The purchase price of a turbine generator shall include technical installation. For description of steam jet air ejectors.MIL-HDBK-1003/7 During turning gear operation. Steam Condensers. For turbine generators.4.15 5.14 Installation. para.
1. since. e) Continuous Circulation. and other foreign substances are blown free. a) Temporary Piping. and temporary hangers and braces to make the systems safe during the blowing operation shall be installed. The circulation method is particularly suitable for cleaning once-through boilers. depending on deposit conditions. 5. reheat stop. valve internals. To assure complete removal of deposits. f) Soaking. control testing during the course of the cleaning is not conclusive. Cleaning is considered complete when the acid strength and the iron content of the returned solvent reach equilibrium indicating that no further reaction with the deposits is taking place. and braces shall be removed. except by using a circulating pump of impractical size. shall be removed. sand. valves. The main steam lines. rust. the hot solvent is recirculated until cleaning is completed. auxiliary steam lines from cold reheat and auxiliary boiler. temporary cover plates. cover plates. and economizers with positive liquid flow paths to assure circulation of the solvent through all parts of the unit.MIL-HDBK-1003/7 d) The unit is flushed with clean water as a final rinse to remove any remaining loose deposits. unlike the circulation method. and valves shall be restored to a state of readiness for plant operation. the unit is allowed to soak for a period of four to eight hours. and cover plates shall be reinstalled. strainers. Temporary piping shall be in stalled at the inlet to the main turbine and the boiler feed pump turbine to facilitate 72 . The soaking method is preferable for cleaning units where definite liquid distribution to all circuits by the circulation method is not possible without the use of many chemical inlet connections or where circulation through all circuits at an appreciable rate cannot be assured. The piping systems. and intercept valves. Samples of the return solvent are tested periodically during the cleaning.15. after filling the unit. Blanking fixtures. In cleaning by the soaking method after filling with the hot solvent. superheaters. hangers. Cover plates and internals for the main steam stop valves. reheat steam lines. and all main turbine seal steam lines shall be blown with steam after erection and chemical cleaning until all visible signs of mill scale. The strainers. The two generally accepted methods in chemical cleaning are continuous circulation and soaking. vent and drain piping. In the circulation method. After blowing. because samples of solvent drawn from convenient locations may not truly represent conditions in all parts of the unit. all temporary blanking fixtures. temporary vent and drain piping. the acid strength of the solvent must be somewhat greater than that required by the actual conditions.2 Main Steam Blowout.
ft3/in2.15. ANSI/ASME B31. Temporary strainers shall be installed in the piping system at the suction of the condensate and boiler feed pumps to facilitate removal of debris within the piping systems resulting from the installation procedures.1. R = (Qc/Qm)2 x [(Pv)c/(Pv)m] x (Pm/Pc] (4) 73 . 5. Boiler and turbine manufacturers provide a recommended blowout sequence for the main and reheat steam lines. And is written specifically for drum (controlled circulation) type boilers but may be adapted to once-through (combined circulation) type boilers by making appropriate modifications to the procedure. The temporary strainers shall be removed after completion of the flushing and chemical cleaning procedures. psia Pc = Pressure during cleaning at boiler outlet. EQUATION: where: R = Cleaning ratio Qc = Flow during cleaning. The temporary piping and valves shall be sized to obtain a cleaning ratio of 1. The strainers shall be cleaned during the course of all flushing and chemical cleaning operations. The most satisfactory method for cleaning installed piping is to utilize the following cleaning cycle: (1) Rapid heating (thermal shock helps remove adhered particles). psia This design procedure is applicable to fossil fuel-fired power plants. (2) High velocity steam blowout to atmosphere. (3) Thermal cool down prior to next cycle. Temporary piping shall be designed in accordance with the requirements of the Power Piping Code. The cleanout ratio is determined using the following equation.3 Installation of Temporary Strainers. lb/h Qm = Maximum load flow. ft3/in2 Pm = Pressure at maximum load flow at boiler outlet.0 or greater in all permanent piping to be cleaned.MIL-HDBK-1003/7 blowout of the steam to the outdoors.1. b) Blowout Sequence. (Pv)m = Pressure-specific volume product at maximum load flow at boiler outlet. The same basic concepts for cleaning piping systems apply to all boiler types. lb/h (Pv)c = Pressure-specific volume product during cleaning at boiler outlet. The above cycle is repeated until the steam emerging from the blowdown piping is observed to be clean.
000 mg/L trisodium phosphate. c) Condensate-Feedwater and Air Preheat Systems.1.15. and the feedwater heater drain piping.0 percent hydroxyacetic acid. the condensate-feedwater and air preheat systems shall be flushed with demineralized water. Lines not having spray pipes in the condenser may be flushed into the condenser. are the feedwater heater shell sides. 0. b) Cycle Makeup and Storage System. boiler feedwater piping from deaerator to economizer inlet. Systems to be alkaline cleaned only. and demineralized water storage tank shall be flushed and rinsed with service water. 1. Those with spray pipes should be flushed before making the connection to the condenser. and foaming inhibitors and wetting agents as required. After cleaning and rinsing. The condensate pumps shall be used for the service water flushing operations. The cycle makeup and storage system. a) Deaerator Cleaning. feedwater heater tube sides. Clean the pump suction strainers. All piping systems with lines to the condenser should be completed and the lines to the condenser flushed with service water. Prior to installing the trays in the deaerator and as close to unit start-up as is feasible. Clean the interior of the condenser and hot well by vacuuming and by washing with an alkaline solution and flushing with hot water. 74 . Normal water level in the condenser should be maintained during the service water flushing operation by making up through the temporary service water fill line. Open the condensate pump suction strainer drain valves and flush the pump suction piping. The water storage tanks should require only a general hose washing. The condensate-feedwater and air preheat systems (if any) shall be flushed with service water. Remove all debris.0 percent formic acid. 2. and chemical cleaning pump suction and discharge piping. The chemicals and concentrations for acid cleaning are 2. and foam inhibitors as required. After the service water flush. condensate storage tank.4 Condenser Cleaning.5 Condensate System Chemical Cleaning. The chemicals and concentrations for alkaline cleaning are 1000 mg/L disodium phosphate.1. the cycle makeup and storage system shall be flushed with demineralized water until the flushing water has a clarity equal to that from the demineralizer. the interior surfaces of the deaerator and deaerator storage tank shall be thoroughly cleaned to remove all preservative coatings and debris. The makeup water system should be flushed until the flush water is clear. Cleaning shall be accomplished by washing with an alkaline service water solution and flushing with hot service water. building heating heat exchanger shell sides. non-foaming wetting agent as required. air preheat system piping. 5. After the service water flush. the deaerator and deaerator storage tank shall be protected from corrosion by filling with treated demineralized water. Systems to be acid and alkaline cleaned are the condensate piping from condensate pump to deaerator discharge.MIL-HDBK-1003/7 5. The final rinse shall be with demineralized water. Prevent flush water from entering the pumps.25 percent ammonium bifluoride.15.
ensuring open and close limit adjustment. 5. flush the condensate-feedwater. Operational linkage adjustment shall be performed as required. Preliminary checks and inspection. preheated to 200 degrees F (93. The lubricating and seal oil systems of the turbine generator shall be cleaned as recommended by the manufacturer. shafts. until the desired concentrations are established. belt guards. Manual set of all linkages shall be performed. This shall be followed by cycling of circulating hot and cold oil until the system is clean.3 degrees C) by steam injection. The condensate-feedwater and air preheat water systems shall be alkaline cleaned by injecting the alkaline solution into circulating treated water. a) Shaft Alignment. and any required corrective work shall be performed on all equipment in accordance with the equipment manufacturer's recommendations. d) Alkaline Cleaning. All coupling guards. and other moving parts shall be b) Linkage Alignment. and drain piping systems with demineralized water. Acid cleaning of the condensate feedwater and air preheat water systems shall be similar to the alkaline cleaning. The feedwater heaters and drain piping shall be alkaline cleaned by soaking with hot alkaline cleaning solution in conjunction with the condensate-feedwater and air preheat water system alkaline cleaning.6 Turbine Lube Oil Flush and Recirculation. The alkaline solution should be circulated for a minimum of 24 hours with samples taken during the circulation period. After the alkaline cleaning is completed.15. e) Acid Cleaning. safety items shall be installed.15.MIL-HDBK-1003/7 After the demineralized water flush. feedwater heater.1. The condensate-feedwater and air preheat water system shall be heated to 200 degrees F (93 degrees C) and hydrazine and ammonia injected into the circulating water to neutralize the acid solution. The cleaning shall be a cold flushing of the system and cleaning of the oil reservoir. c) Safety Equipment. and other personnel 75 . 5. checked for proper alignment.2 Equipment Startup 5. Oil samples shall be tested to determine contamination levels. All bearings.2. The samples should be analyzed for phosphate concentration and evidence of free oil. air preheat water.1 Preliminary Checks.15. the condensate-feedwater and air preheat systems shall be drained and refilled with demineralized water. except that the circulation period shall only be six hours. The systems shall then be flushed with demineralized water until all traces of acid are removed. The heater shells and drain piping should be drained once every six hours during the circulation of the alkaline cleaning solution through the condensatefeedwater and air preheat water systems.
All mechanical seals shall be removed as required to ensure clean sealing surfaces prior to starting. All pump suction pits shall be free of trash. All temporary shipping braces.2 startup: Initial Plant Startup. reservoirs. Each lubricating oil system shall be flushed and the filters inspected. and condenser. All pump suction strainers shall be installed. l) Tanks and Vessels. All stuffing boxes shall be checked for j) Stuffing Boxes and Packing. and sheaves shall be checked for correct alignment and belt tension. All points requiring manual lubrication shall be greased or oiled as required. deaerator. All belts. All oil tanks. Seal adjustments shall be performed as required by the manufacturer. Seal water piping shall be cleaned to the extent necessary to ensure no face contamination. hydrostatically tested. i) Pump Suction Strainers. blocks.MIL-HDBK-1003/7 d) Piping. All power actuated valves shall be checked for correct valve action and seating and the actuators and converters shall be given initial adjustment. k) Mechanical Seals. e) Pits. All cooling and sealing water supplies shall be flushed and checked for proper operation. All spring type pipe hangers shall be checked for proper cold settings. and constant level type oilers shall be checked for proper oil levels. and Sheaves.15. All manual valves shall be operated to ensure correct operation and seating. and shall be flushed or blown clean. gear cases. or tie rods shall be removed from expansion joints. All safety valves shall be checked for correct settings. or air tested. All tanks and vessels shall be thoroughly inspected The following steps shall be followed for plant a) Operate demineralizer and fill condensate storage/return tank. All piping shall be nondestructively tested. b) Fill boiler. f) Lubrication. pulleys. 5.2. 76 . correct takeup on the packing. Pulleys. leak tested. h) Cooling and Sealing Water. as applicable. internally before securing. g) Belts.
see Section 19 this handbook. All rotating equipment shall be checked for overheating. a) Equipment or systems completed to the point where they may be energized.15. noise. 5. and all other field testing should be conducted during initial plant startup. each piece of equipment shall be given a trial operation. After all preliminary checks and inspections are completed. pressurize. f) Start condensate pumps. and other such components. vibration.MIL-HDBK-1003/7 c) Start boiler feed pumps. 5. d) Warm up boiler using manufacturer's recommendations. Tags should indicate status and the mandatory clearances required from designated personnel to operate. or being operated. cooling systems. 5.16. The sources of power or pressure shall be turned off and tagged. and other abnormal conditions. h) Start turbine lubricating oil system. pressurized. improper support adjustment. and any other conditions which would tend to shorten the life of the equipment. g) Start condenser exhauster (air ejectors).3 Operation Control. interferences. shall be tagged. but not yet checked out.3 5. or remove from service such equipment or systems. The system should consist of placing appropriate tags on all equipment and system components.16. 77 . A system of control to protect personnel and equipment as the permanent plant equipment and systems are completed and capable of energization. energize. All functional and operational testing of protective interlocking. e) Start cooling water system pumps. excessive vibration. alarm systems. Steam traps should be verified for proper operation and integral strainers cleaned.1 Trial Operation. i) Roll turbine using manufacturer's startup procedures. All piping should be visually inspected for leaks. or operated. Trial operation of all equipment and systems shall extend over such period of time as is required to reveal any equipment weaknesses in bearings. Main systems should be trial operated and tested after each individual piece of equipment has been trial operated and ready for operation.2 Main System Operation. or any performance deficiencies which may later handicap the operation of main systems and the complete plant. automatic controls. The controls established should encompass the following phases.16. should be established. instrumentation.16 Testing. 5. pressurization. Operation For testing requirements. heat exchangers.
78 .MIL-HDBK-1003/7 b) Equipment and systems released for preoperational check-out shall be so tagged. all controls and sources of power or pressure shall be tagged out and shall not be operated under any circumstances. When a request to remove from service is made.
1. The distinction is based on the relationship between the generating unit and the auxiliary transformer supplying power for its auxiliary equipment. For instance.1. the standard lists applicable motor and motor control nameplate voltage ranges up to nominal system voltages of 13. Refer to ANSI Standard C84. Rules for selecting motor voltage are not rigid but are based on relative costs. Insofar as possible. the higher the voltage. 6. and it would be difficult and expensive to get a different voltage rating.2. to a lesser extent. Motor sizes for draft fans and boiler feed pumps usually control the selection of the highest station service power voltage level.8 kV to suit the size of the unit and primary distribution system voltage. Electric Power Systems and Equipment Voltage Rating. b) Station service power requirements for combustion turbine and internal combustion engine generating plants are such that 208 or 480 volts will be used. Generally.1.1 General. The primary distribution system with central in-house generation should be selected in accordance with MIL-HDBK-1004/1. the auxiliary equipment for each generating unit usually will be supplied by a separate transformer with appropriate interconnections between the secondary side of the transformers.1. b) The unit type system has the disadvantage that its station service power requirements must be supplied by a startup transformer until the generating unit is synchronized with the system. 6. the generator voltage should match the distribution voltage to avoid the installation of a transformer between the generator and the distribution system.8 kV.1.1 General. it might be a good choice to select this one larger motor for 460 volts so that the entire auxiliary power system can be designed at the lower voltage.MIL-HDBK-1003/7 Section 6. Two types of station service power systems are generally in use in steam electric plants and are discussed herein. for voltage ratings for 60 Hz electric power systems and equipment.1.1. Generators in this size range will be offered by the manufacturer in accordance with its design. They are designated as a common bus system and a unit system. Generators for a power plant serving an installation will be in the range from 4160 volts to 13. 79 .1. In the unit system the auxiliary transformer will be connected solidly to the generator leads and is switched with the generator. distances of cable runs. In addition. 6.1. This arrangement requires that the station service power supply be transferred from the startup source to the unit source with the auxiliary equipment in operation as a part of the procedure of starting the unit. the larger the generator. if there is only one motor larger than 200 hp and it is.2 Station Service Power Systems 6.1. In either case. say. only 300 hp. 6.4 Distribution System. This startup transformer also serves as the backup supply in case of transformer failure. a) In the common bus system the auxiliary transformer will be connected through a circuit breaker to a bus supplied by a number of units and other sources so that the supply has no relationship to the generating unit whose auxiliary equipment is being served.1.1 6.1 GENERATOR AND ELECTRICAL FACILITIES DESIGN Typical Voltage Ratings and Systems Voltages 6.3 Power Plant Station Service Power Systems a) Voltages for station service power supply within steam electric generating stations are related to motor size and. Terminal voltage ratings for power plant generators depend on the size of the generators and their application.2 Generators.1. 6.
2. 6. The advantage of switching the generator and its auxiliary transformer as a unit is not very important.MIL-HDBK-1003/7 c) The advantages of the unit system are that it reduces the number of breakers required and that its source of energy is the rotating generating unit so that. Provision shall be made for the standby transformer to supply any auxiliary bus.1. the generating unit and its auxiliaries can easily be isolated from the rest of the system. For steam turbine generating plants the auxiliary loads for each unit in the plant will be isolated on a separate bus fed by a separate transformer.1. 6. generators will be connected to a common bus and the auxiliary transformers for all generating units will be fed from that common bus. The unit type station service power system will beused for a steam electric or combustion turbine generating station serving 80 . a) Figure 22 is a typical one-line diagram for such a system. This type system will be used for steam turbine or diesel generating plants with all station service supplied by two station service transformers with no isolation between auxiliaries for different generating units. b) The buses supplying the auxiliaries for the several units shall be operated isolated to minimize fault current and permit use of lower interrupting rating on the feeder breakers.2. This bus may have one or more other power sources to serve for station startup. In this system. and it serves the loads common to all units such as building services. A standby transformer is included. in case of system trouble.2 Common Bus System.3 Unit Type System. so the common bus system will normally be used. It also will be used for gas turbine generating plants.
used for a diesel generating station of any kind.1. a) This common system has three principal functions: (1) To provide a source of normal power for power plant equipment and services which are common to all units. In addition to the above items. coal and ash handling equipment. and circulating water pumps which use the highest station service voltage. Figure 25 is a typical one-line diagram of this arrangement. If the unit is to be connected to a system voltage that is higher than the generator voltage.2. This is shown in Figure 23. 82 . as a rule. 6. Each unit sub station will include a transformer to reduce voltage from the highest auxiliary power level to 480 volts together with air circuit breakers in a lineup for starting of motors 100 to 200 hp and for serving 480-volt motor control centers. 6. the auxiliary switchgear air circuit breakers will only serve motors 250 hp and larger. and similar items. and for distribution of power to various unit substations and motor control centers to serve the remaining station service requirements. The common bus system may have a similar arrangement for the standby transformer. It will not be. are normally supplied by the auxiliary transformer connected to the generator leads.16 kV. shops.5 Startup Auxiliary Transformer. water treating system. air circuit breakers will be used for control of large auxiliary motors such as boiler feed pumps. fans..1. say 4. and feeders to unit substations.2.4 Station Service Switchgear. since the station service power requirements are minimal. the unit concept can be extended to include the step-up transformer by tying its low side solidly to the generator leads and using the high side breaker for synchronizing the generator to the system. If the highest level of auxiliary voltage required is more than 480 volts. The motor control centers will include combination starters and feeders breakers to serve motors less than 100 hp and other small auxiliary circuits such as power panels. the unit auxiliary type system will incorporate a "common" or "startup" arrangement which will consist of a startup and standby auxiliary transformer connected to the switchyard bus or other reliable source.MIL-HDBK-1003/7 a utility transmission network. plus a low voltage switchgear and motor control center arrangement similar to that described above for the unit auxiliary system. The distinguishing feature of a unit type station power system is that the generator and unit auxiliary transformer are permanently connected together at generator voltage and the station service power requirements for that generating unit. including boiler and turbine requirements. This arrangement is shown in Figure 24.g. e. (2) To provide backup to each auxiliary power system segment if the transformer supplying that segment fails or is being maintained. lighting. A station service switchgear lineup will be connected to the low side of the auxiliary transformer. air compressors.
83 .
MIL-HDBK-1003/7 (3) In the case of the unit system. or 1. salient pole generators.14. Interconnections will be provided between the common and unit switchgear. 3. air-cooled with water cooling for air coolers. to allow for possible future additions to the plant.600 rpm for 60 Hz frequency (sometimes connected through a gear reducer up to 10. d) Generators for diesel service are revolving field. two-pole. and generator. six-pole. Steam Turbines for Mechanical Drive Service.000-32.10. self-ventilated.800 rpm. and SM 24. open drip-proof type. because of high ambient temperatures or polluted atmosphere. b) The startup and standby transformer and switchgear will be sized to accomplish the above three functions and. open drip-proof type. Non-salient pole generators are two-pole.1 Type. direct connected. 3. Self-ventilation is provided for generators larger than 5.000 KW.2 6. Number of poles is six or more to match low speeds typical of diesels. direct connected. Generators may be obtained totally enclosed with water cooling.2 Standards. to the gas turbine power takeoff shaft. a) Generators for steam turbine service rated 5.200 rpm.1.000 kVA and below are revolving field. nonsalient or salient pole.000 kVA by some manufacturers. so that no more than one auxiliary transformer can feed any switchgear bus at one time. sometimes connected through a gear reducer. aircooled. sometimes connected through a gear reducer to the turbine with the number of poles dependent on the speed selected which is the result of an economic evaluation by the manufacturer to optimize the best combination of turbine. in addition.000 kVA. open type. self-ventilated.000 kVA or more). to provide startup power to each unit auxiliary power system until the generator is up to speed and voltage and is synchronized with the distribution system. but this is not recommended for steam power plant service. and C50. 6. totally enclosed. non-salient. 86 .2. Land Based Steam Turbine Generator sets 0 to 33. 6. four-pole. are revolving field. Generators for power plant service can be generally grouped according to service and size.600 rpm for 60Hz. nonsalient or salient pole. if desired. These are applicable as well as the requirements of National Electrical Manufacturers Association (NEMA) SM 23. depending on manufacturer's gas turbine design speed.500 kVA may utilize 1.2. Generators shall meet the requirements of ANSI C50. although manufacturers of machines smaller than 1.2.1. b) Similar generators rated 5. C50. gear. salient pole. c) Generators for gas turbine service are revolving field.1 Generators General Types and Standards 6.13. and with amortisseur windings to dampen pulsating engine torque. Appropriate interlocks will be included.
375 kVA and 0.25 times the turbine rating. and for 18.000 kVA air/water-cooled units. Power factor for salient pole generators is usually 0. b) Generator kVA rating for steam turbine generating units is standardized as a multiplier of the turbine kW rating. Generators have 87 . fast acting voltage regulation can also assist in achieving generator stability without the heavy expense associated with the high cost of building high short circuit ratios into the generator. Open. the multiplier is 1. must be equal to or greater than the base rating of the turbine over a specified range of inlet temperatures. e) Generator short circuit ratio is a rough indication of generator stability.625 kVA and 0. 3.5 inches Hg (12 kPa) absolute exhaust pressure. Standard power factor ratings for gas turbine driven air-cooled generators usually are 0. with increased kVA rating. For air-cooled generators up to 15.90 for 12.MIL-HDBK-1003/7 a) ANSI C84. Turbine rating for a condensing steam turbine with controlled extraction for feedwater heating is the kW output at design initial steam conditions. Power factor lower than standard. These ratings are for water-cooled generators with 95 degrees F (35 degrees C) maximum inlet water to the generator air or hydrogen coolers. do not affect the capability of the turbine and generator to the same extent so that kW based on standard conditions and generator kVA ratings show various relationships. However. Non-standard generator ratings can be obtained at an additional price.1 designates standard voltages as discussed in Section 1. Turbine rating for a noncondensing turbine without controlled or uncontrolled extraction is based on output at design initial steam conditions and design exhaust pressure.650 kVA air-cooled and 25.000 kVA.600 kVA to 32. self-ventilated generator rating varies with ambient air temperature. Changes in air density. automatic extraction turbine ratings are complicated by the unique steam extraction requirements for each machine specified. c) Generator ratings for gas turbine generating units are selected in accordance with ANSI Standards which require the generator rating to be the base capacity which. d) Power factor ratings of steam turbine driven generators are 0. However.625 kVA.80. three percent cycle makeup. in turn.85 for 17.20. and all feedwater heaters in service. can be obtained at an extra price.80 for machines up to 9. 1. however. Turbine standard ratings for automatic extraction units are based on design initial steam conditions and exhaust pressure with zero extraction while maintaining rated extraction pressure. Power factors of large hydrogen cooled machines are standardized at 0. standard rating usually is at 104 degrees F (40 degrees C) ambient. the higher the short circuit ratio.500 to 32. the more stable the generator under transient system load changes or faults.750 kVA air-cooled and hydrogen-cooled generators.90.80 for ratings up to 15.
2. b) The generator will be capable of withstanding.3 Mechanical Withstand.300 feet.e. provided the integrated product of generator negative phase sequence current squared and time (I22t) does not exceed 30. 88 . and time in seconds.2.2. without injury. including the decaying effects of field current and DC component of stator current for times up to 120 seconds. and the field winding will be capable of operating at 125 percent of rated load field voltage for 1 minute not more than twice a year. 6. Unit will operate with voltage variations of plus or minus 5 percent of rated voltage at rated kVA. the armature will be capable of operating.MIL-HDBK-1003/7 standard short circuit ratios of 0. i.. power factor and frequency.1 Voltage Variations.2. If a generator has a fast acting voltage regulator and a high ceiling voltage static excitation system. this standard short circuit ratio should be adequate even under severe system disturbance conditions. Stator windings must withstand a normal high potential test and show no abnormal deformation or damage to the coils and connections. Generator will be capable of withstanding. The following features and accessories are available in accordance with NEMA standards SM 12 and SM 13 and will be specified as applicable for each generator: 6. provided that maximum phase current is limited externally to the maximum current obtained from the three-phase fault. The thermal effect of unbalanced faults at the machine terminals includes the decaying effects of field current where protection is provided by reducing field current (such as with an exciter field breaker or equivalent) and DC component of the stator current. f) Maximum winding temperature. without mechanical injury any type of short circuit at its terminals for times not exceeding its short time thermal capabilities at rated kVA and power factor with 5 percent over rated voltage. at 130 percent of its rated current for 1 minute not more than twice a year. losses and temperature rises may exceed standard values when operation is not at rated voltage. at rated load for standard generators. 6. Negative phase sequence current is expressed in per unit of rated stator current.2 Thermal Variations a) Starting from stabilized temperatures and rated conditions.58 at rated kVA and power factor.2 Features and Accessories.2.2. with balanced current. this may be upgraded for higher altitudes at an additional price. the thermal effects of unbalanced faults at the machine terminals. Higher short circuit ratios are available at extra cost to provide more stability for unduly fluctuating loads which may be anticipated in the system to be served. 6.2. but not necessarily in accordance with the standards of performance established for operation at rated voltage. is predicated on operation at or below a maximum elevation of 3.
3 Excitation Systems.2. Rotating commutator exciters as a source of DC power for the AC generator field generally have been replaced by silicon diode power rectifier systems of the static or brushless type. necessary devices for mounting on a remote panel. 6. 6. three single-phase current transformers. an excitation cubicle with field breaker and discharge resistor. viewing during operation must utilize a strobe light. Excitation ceiling voltage on manual control will not be less than 120 percent of rated exciter voltage when operating with a load resistance equal to the generator field resistance. The exciter rotating parts and the diodes are mounted on the generator shaft.2. a) A typical brushless system includes a rotating permanent magnet pilot exciter with the stator connected through the excitation switchgear to the stationary field of an AC exciter with rotating armature and a rotating silicon diode rectifier assembly.2. Also. If this bus operates at a voltage of 4.16 kV. which in turn is connected to the rotating field of the generator. These criteria. Exciter response ratio as defined in ANSI/IEEE 100. Deviation factor of the open circuit terminal voltage wave will not exceed 10 percent.2.2.3 Generator Leads and Switchyard 6. will not be less than 0.50. a full wave static rectifier. The balanced telephone influence factor (TIF) and the residual component TIF will meet the applicable requirements of ANSI C50. part of the system is a solid state automatic voltage regulator.2. Dictionary of Electrical & Electronic Terms. and necessary control devices for mounting on a remote panel. The connection of the generating units to the distribution system can take one of the following patterns: a) With the common bus system. and excitation system will be capable of supplying this ceiling voltage for not less than 1 minute. and a collector assembly for connection to the generator field. a means of manual voltage regulation.2.4 Excitation Voltage. b) A typical static system includes a three-phase excitation potential transformer.1 General. the generators are all connected to the same bus with the distribution feeders. 6. 6.13. Excitation system will be wide range stabilized to permit stable operation down to 25 percent of rated excitation voltage on manual control. This arrangement eliminates both the commutator and the collector rings.3. this 89 .5 Wave Shape. as set for manual control.MIL-HDBK-1003/7 6. one automatic and one manual static thyristor type voltage regulators. will permit operation when on automatic control.6 Telephone Influence Factor.
For larger stations. Switching arrangement selected will be adequate to handle the maximum calculated short circuit currents which can be developed under any operating routine that can occur. and the area covered by the system requires distribution feeders in excess of 2 miles. Since the contribution from generators connected to other bus sections must flow through two reactors in series fault current will be reduced materially.000 kVA. this arrangement is the best for stations up to about 25. Figure 26 shows. and outside utility sources. the fault duty on the common bus reaches a level that requires more expensive feeder breakers.e. it may be to connect the generators to a higher voltage bus and feed several substations from that bus with step-down substation transformers at each substation as shown in Figure 24. b) The bus and switchgear will be in the form of a factory fabricated metal clad switchgear as shown in Figure 22.000 or 32.. distribution advantageous distribution distribution d) If the plant is 20.000 kVA. and the bus should be split. all sources will be disconnected. generators. the bus will be split for reliability using a bus tie breaker to permit separation of approximately one-half of the generators and lines on each side of the split. If the bus operates at a voltage of 13. i. In order to clear a fault.000 kVA or larger.8 kV.MIL-HDBK-1003/7 arrangement is suitable up to approximately 10. a synchronizing bus with current limiting reactors will be required. in simplified single line format. All possible sources of fault current. motors. In the event that the possible fault current exceeds the interrupting capacity of the available breakers. The switchgear breakers will be capable of interrupting the maximum possible fault current that will flow through them to a fault. For plants with multiple generators and outgoing circuits. will be considered when calculating short circuit currents. a typical synchronizing bus arrangement. 90 . c) A limiting factor of the common type bus system is the interrupting capacity of the switchgear. The interrupting capacity of the breakers in the switchgear for each set of generators is limited to the contribution to a fault from the generators connected to that bus section plus the contribution from the synchronizing bus and large (load) motors.
Alternative bus arrangements include main and transfer bus. all run in one steel armored enclosure. d) For most applications utilizing conduit.MIL-HDBK-1003/7 e) The configuration of the high voltage bus will be selected for reliability and economy. and between generator and step up transformer where distribution is at 34. If the cable current rating does not exceed 400 amperes.e. or by compression lugs where neoprene or similarly jacketed cables are used. cable installations will be provided for generator capacities up to 25 MVA.1 Generator Leads Cable a) Connections between the generator and switchgear bus where distribution is at generator voltage. For larger units.2. costs only slightly more than the main and transfer bus arrangement and eliminates the possibility of losing all circuits from a bus fault. the three phases will be triplexed.3.5 kV and higher. bus ducts will be evaluated as an alternative. depending on the installation requirements. ring bus. in steel conduit suspended from ceiling or on wall hangers. armored cable will be used to provide physical protection. 92 . shown in Figure 28. For applications where cables will be suspended from hangers or placed in tray. 6. The main and transfer arrangement. Normally it will not be used with more than eight bus sections because of the possibility of simultaneous outages resulting in the bus being split into two parts. c) Cable terminations will be made by means of potheads where lead covered cable is applied. since each bus section is included in the protected area of its circuit. is the highest cost alternative and provides the highest reliability without limitation on the number of circuits. The ring bus arrangement. b) The power cables will be run in a cable tray. shown in Figure 27.. separate from the control cable tray. In the event that single-phase cables are required. Generally. will be by means of cable or bus duct.16 kV and above. the armor will be nonmagnetic. or in ducts.2 6. and breaker and a half schemes. i. The breaker and a half arrangement. cross-linked polyethylene with approved type filler or ethylene-propylene cables will be used. shown in Figure 29. In most instances more than one cable per phase will be necessary to handle the current up to a practical maximum of four conductors per phase.3. Stress cones will be used at 4. is the lowest cost alternative but is subject to loss of all circuits due to a bus fault.
3 Isolated Phase Bus a) For steam turbine generator ratings of 25 MVA and above. 96 . either in single or multiple conductor per phase pattern.2. In the segregated phase bus. the use of isolated phase bus for connection from generator to step up transformer will be used. At such generator ratings. For these installations. b) For applications involving an outdoor gas turbine generator for which a relatively small lineup of outdoor metal clad switchgear is required to handle the distribution system. b) Isolated phase bus current ratings should follow the rule of thumb set forth above for generator cables. As a cable current carrying capacity will be at least 1. distribution seldom is made at generator voltage. the three bare bus-phases will be physically separated by nonmagnetic barriers with a single enclosure around the three buses.25 times the with kVA capacity of the generator (not the kW rating of the Segregated Phase Bus a) For gas turbine generator installations the connections from the generator to the side wall or roof of the gas turbine generator enclosure will have been made by the manufacturer in segregated phase bus configuration. An isolated phase bus system.3. The three-phase conductors will be flat copper bus.MIL-HDBK-1003/7 e) In emanating from the rule of thumb. the several generators will be connected to the switchgear via cables. the switchgear will be of indoor construction and installed in a control/switchgear building. 6. the current associated turbine).2. For multiple gas turbine generator installations.3.2 no event should the current carrying capacity of the power cables generator be a limiting factor on turbine generator output. c) Segregated bus current ratings may follow the rule of thumb set forth above for generator cables. but final selection will be based on expected field conditions. hollow square or round bus on insulators in individual nonmagnetic bus enclosures. provides maximum reliability by minimizing the possibility of phase-to-ground or phase-to-phase faults. 6. segregated phase bus will be used. External connection to switchgear or transformer will be by means of segregated phase bus or cable. utilizing individual phase copper or aluminum.
The hotwell of a condenser is that portion of the condenser bottom or appendage that receives and contains a certain amount of condensate resulting from steam condensation. In a single pass condenser. 7. The condenser tubes and baffles are arranged in such a way as to cause the steam to flow from the condenser steam inlet toward the air cooler section. Part of the condensate from the condenser is circulated through dry cooling towers and returned to and sprayed into the condenser.1. Cooling water is distributed inside the condenser in the form of a fine spray that contacts and condenses the steam.000:1. This arrangement requires two separate cooling water inlets or outlets or both to permit opening the water boxes on one side of the condenser for tube cleaning while the other side of the condenser remains in operation. the steam condenses in a fraction of a second and reduces in volume ratio of about 30.1 Spray Type. Operation of the turbine with only half the condenser in service is limited to 50 percent to 65 percent load depending on quantity of cooling water flowing through the operating side of the condenser. which is equal to the steam condensed.1. one and two pass condensers are the most common. 7. The proper size of condenser is dependent on the following 97 . As a result. Any residual steam is condensed in the air cooler section. the condensate.1 Pass Configuration. The tubes are sealed into fixed tube sheets at each end and are supported at intermediate points along the length of the tubes by tube support plates. carbon dioxide.2. Water boxes may be divided by a vertical partition and provided with two separate water box doors or covers. Use of a deaerating hotwell provides for reheating the condensate within the condenser to saturation temperature that effectively deaerates the condensate and eliminates subcooling. 7. This type has application where dry cooling towers are used.2 Divided Water Box. The balance of the condensate. Single pass condensers have an inlet water box on one end and an outlet water box on the other end. For power generation. Spray condensers utilize mixing or direct contact of cooling water and steam.2 factors: Condenser Sizes.2 Surface Type. Condenser subcooling is also undesirable because the condensate may contain noncondensible gases that could result in corrosion of piping and equipment in the feedwater system. condenser subcooling is undesirable since it results in an increase in turbine heat rate that represents a loss of cycle efficiency.005cc per liter of water (equivalent to 7 parts per billion as specified in the Heat Exchange Institute (HEI).1.1. The steam carries with it the noncondensible gases such as air.MIL-HDBK-1003/7 Section 7. will be subcooled to a temperature lower than the saturation pressure corresponding to the condenser steam side vacuum. Numerous tubes present a relatively large heat transfer and condensing surface to the steam. through the tubes. is pumped separately and returned to the feedwater cycle.1 Condenser Types STEAM CONDENSERS 7. Surface condensers are basically a shell and tube heat exchanger consisting of water boxes for directing the flow of cooling water to and from horizontal tubes. Standards for Steam Surface Condenser. while falling down through the tube bundle. Condensers may have up to four passes. with a return water box at the other end. During operation at a very high vacuum.2.1. 7. Condensers should be specified to provide condensate effluent at saturation temperature corresponding to condenser vacuum and with an oxygen content not to exceed 0.4 Air Cooler Section. 1970. 7. Two pass condensers have the cooling water inlet and outlet on the same water box at one end of the condenser.2. and ammonia that leave the air cooler section through the air outlets and flow to air removal equipment. the cooling water makes one passage from end to end. only a few pounds of steam are contained in the steam space and in contact with the large and relatively cold condensing surface at any one instant.1.2. 7.3 Reheating Hotwell. Unless the condenser is provided with a reheating hotwell (also commonly called a deaerating hotwell). 7.
lake. The condenser performance is then calculated to 98 . Condenser vacuum is closely related to the temperature of cooling water to be used in the condenser.2. Tube cleanliness factor. Number of water passes. use turbine exhaust steam flow in pound per hour times 950 Btu per pound for non-reheat turbines or 980 Btu per pound for reheat turbines.2 Condenser Vacuum.1 Condenser Heat Load. For approximation. or river water.2. Tube size (O. the maximum expected temperature is used for design purposes. Condenser absolute pressure. Effective tube length (active length between tube sheets). 7. For cooling towers. For ocean. 7. Tube material.MIL-HDBK-1003/7 a) b) c) d) e) f) g) h) i) Steam flow to condenser. and gauge). design is usually based on water temperature from the tower and an ambient wet bulb that is exceeded not more than 5 percent of the time.D. Cooling water inlet temperature. Cooling water velocity through tubes.
75 26.7 * 70 1. that is exceeded not more than 1 percent of the time. 7.1. Economical design of condensers usually results in a temperature difference between steam saturation temperature (ts) corresponding to condenser pressure and inlet cooling water temperature (t1) in the range of 20 degrees F (11 degrees C) to 30 degrees F (17 degrees C).6 degrees C) lower than ts.30.2.MIL-HDBK-1003/7 determine the condenser pressure with an ambient wet bulb temperature.220.127.116.11 * * * 85 2. The condenser terminal difference is the difference in temperature between the steam saturation temperature (ts) corresponding to condenser pressure and the outlet cooling water temperature (t2).2 Terminal Difference.8 degrees C) to 10 degrees F (5.5 19.1 * 80 2.0 .5 .6 * .1.1 * * 90 3. The difference between inlet and outlet cooling water temperatures is called the temperature rise that will be typically between 10 degrees F (184.108.40.206 25.t1 * * F(t1) In. Under the latter condition and maximum turbine load.7 . the calculated condenser pressure should not exceed 4-1/2 inches Hg Abs.0 . The turbine exhaust pressure monitor is usually set to alarm at 5 inches Hg Abs.6 degrees C) and 25 degrees F (13. Economical design of condenser will result with t2 in the range of 5 degrees F (2.5 . F * * * 50 184.108.40.206 .30.8 degrees C).3.3.1 Inlet Temperature.0 * * 55 1.3 Cooling Water Temperatures 7. 99 .3. * Cooling Water Temp.3 Temperature Rise.1 .25 26.1 .184.108.40.206 . Condenser Pressure ts .9 degrees C).1 * * * 75 2.7 . Using the peak ambient wet bulb of record and maximum turbine load.25 24. 7.2.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 7.7 * * 65 1. Hg Abs Degrees. which is near the upper limit of exhaust pressure used as a basis for condensing turbine design.0 .28.31. Table 13 shows typical design conditions: Table 13 Typical Design Conditions for Steam Condensers +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).0 .9 * * 60 1.0 23.0 .1 .2.5 21.0 . the condenser pressure should not exceed 4 inches Hg Abs.0 21.2.0 29. The HEI Conditions limits the minimum terminal temperature difference that can be used for condenser design to 5 degrees F (2.0 .
44 20. 7.000 square feet.2. 7. and 24 gauge. Surface +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). and 1-inch OD tubes are the most prevalent sizes. For stainless steel tubes.2.000 100. The length of tubes is important because of its direct relation to friction loss and steam distribution over the tube bundle.5 Tube Outside Diameter and Gauge. As a general rule. The maximum cooling water velocity through the tubes is limited by erosion of the inlet ends of the tubes and by the water side pressure drop (friction loss).000 to 500.000 to 50.8 to 7. the tube water velocity should be at least 7 feet per second to ensure that the tubes are continually scrubbed with oxygen for passivation of the stainless steel and maximum protection against corrosion. 16. * Tube Condenser * Length Surface * * * Feet Sq. Condensers larger than 50. Normally. 22 BWG tubes are normally used. For inhibited Admiralty or arsenical copper.36 . Where conditions require the use of stainless steel tubes. 7. Higher velocities provide higher heat transfer but will cause increased friction loss. space available for the installation.4 Tube Water Velocity. 7/8-inch. Condenser tubes are available in the following six outside diameters: 5/8-inch. * * * 16 . 1-1/8 inch.000 to 100. economical tube length for single pass condensers will fall in the ranges as shown in Table 14.Ft. 7/8-inch tubes are used in condensers between 15.30 . and 1-1/4 inch.000 and 50. The normal tube water velocity ranges from 6 to 8 feet per second. 3/4-inch tubes are used in small condensers up to 15.MIL-HDBK-1003/7 7. Velocities in excess of 8 feet per second are seldom used. 1-inch. As a general rule. 18. Condenser tubes are readily available in 14. and cooling water pump power required. 7/8-inch.000 .6 feet per second has very little effect on the economics or performance of the entire cooling water system. Table 14 Typical Condenser Tube Length vs. 22.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 100 . Previous studies indicate that varying cooling water tube velocities from 6. 20. The selection of tube length depends on condenser surface required. water velocities should be limited to about 7 feet per second to prevent excessive erosion.000 * 22 30 32 . 3/4-inch. 18 BWG tubes are normally used. Two pass condensers will normally have shorter tube lengths.000 square feet.24 Less than 20.5 feet per second water velocity is used with stainless steel tubes. When using admiralty tubes. For power plants.000 50.6 Tube Length.2.000 square feet normally use at least 1-inch tubes. 3/4-inch.
A single pass condenser is commonly used where the water is supplied from natural sources such as rivers or oceans. * * Generator Kw * Single Two Single Two Feet Inch * * Pass Pass Pass Pass * * * 3.000 7.921 30. Table 15 Typical Condenser Size and Cooling Water Flow +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). Plant layout and orientation with respect to cooling water source may also dictate the use of a two pass condenser.754 7. In general.728 17.607 4. Typical condenser sizes and cooling water flows for a given turbine generator capacity are given in Table 15.637 32.D.929 28 7/8 * * 40. condensing pressure. Design tube cleanliness can vary from 70 to 95 percent depending on tube water velocity.2.486 24.525 24 7/8 * 24.90.071 33.147 6.000 30.051 24.096 79. 7.645 30 1 * * 60.000 48.911 6.5 ft/sec tube water velocity. a lower value should be used.205 38.650 20 3/4 * * 10. cooling tower) a factor of 0.100 30 1 * *100.889 57. a two pass condenser will probably be the best selection since a single pass condenser requires more cooling water per square foot of condenser surface and per kilowatt of electrical generation. When the cooling water is clean or is chlorinated. 101 .90 or 0.000 12. 6. 85 degrees F (29.2.701 20 3/4 * * 30. If the source of circulating water is at all limited.95 could be used. the heat transfer coefficient is reduced and the condenser vacuum is decreased.706 52.418 53.500 5. As condenser tubes become dirty. lake.705 46.MIL-HDBK-1003/7 7. and 18 BWG tube wall thickness.800 43.85 is normally used. For a cooling tower system with Admiralty condenser tubes.301 21.4 degrees C) cooling water inlet.8 Tube Cleanliness Factor.295 63.223 8.201 20 3/4 * * 20.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- Note: Based on use of Admiralty tubes. 2-1/2 inch Hg Abs.000 * 80. ocean. For a cooling tower system with stainless steel condenser tubes. 85 percent cleanliness factor.096 9.079 21. Usually.85 should probably be used because of lower tube water velocities through the tubes. a tube cleanliness factor of 0. a two pass condenser is used with cooling towers or a cooling lake.433 20 3/4 * * 5. a value of 0.180 65.90 is commonly used for stainless steel tubes. For bad water conditions.85 is commonly used for copper alloy tubes and 0.211 42. and cooling water scale-formation characteristics. a factor of 0. If sufficient water is available.000 38.721 9.000 18.290 36.836 5.202 30 7/8 * 34.000 * 50.704 43. cooling water cleanliness.924 14. it is practical to use a value of 0. with all types of cooling water (river. A single pass condenser is normally smaller in physical size than the equivalent two pass unit. the most economical condenser is a single pass.522 12.7 Number of Water Passes.650 30 1 * .000 * 7. * Turbine Condenser Surface Cooling Water Tube Tube * ft2 Gpm Length O. If the cooling water conditions are very good.
Low and Intermediate Tensile Strength.t1) (10) 7. Shapes.2. Recommended tube. water boxes. 7. gpm 7. A = Q/Um (5) C x V0. Typical materials of construction for condenser shell. (see para. tube sheets.t2)]} t2 = cooling water outlet temperature. Specification for Pressure Vessel Plates. Specification for 102 . and Bars. 7. lb/h heat rejected latent heat of exhaust steam. ft2. and tubes are listed in HEIS. and ASTM A516 Grade 70. (see Figure 30) C1 = correction factor for inlet water temperatures other than 70 degrees F. ASTM A285 Grade C.2.10 EQUATION: where: G = Condenser cooling water flow.2.MIL-HDBK-1003/7 7.8) m = logarithmic mean temperature difference = (t2 . condenser heat load = W x Hr. The condenser shell is usually welded steel construction reinforced against collapsing forces resulting from high vacuum. 18 BWG Admiralty (see Figure 30) Cf = correction factor for tube cleanliness.1 Shell. fps = heat transfer coefficient at 70 deg F.9 EQUATION: where: Surface. 950 Btu/lb for nonreheat unit. degrees F of exhaust steam corresponding to condenser pressure A Q W Hr = = = = Cooling Water Flow.t1)/(ts . Shapes. 980 Btu/lb for reheat unit U = heat transfer coefficient = C x V0. Carbon steels ASTM A283 Grade C. tube sheet. and water box materials are shown in Table 16. The condensing surface may be calculated by use of Equation 5.5 condensing surface (outside active tube area).t1)/{loge[(ts . Specification for Low and Intermediate Tensile Strength Carbon Steel Plates. G = May be calculated by use of Equation 10. Carbon Steel. Q/500(t2 .3. degrees F t1 = cooling water inlet temperature. (see Figure 30) C2 = correction factor for tube material and thickness other than No.3 Condenser Materials.5 x C1 x C2 x Cf V = velocity of cooling water through tubes. degrees F ts = saturation temperature. Btu/h exhaust steam from turbine.
Carbon steel plate. Stress corrosion cracking. concentrated cooling tower water. The relative resistance to various failure mechanisms of most widely used materials is shown in Table 18.3. 22 gauge Type 304 stainless steel tubes shall not be greater than 48 inches. etc. 103 . The maximum spacing for 1-inch.3. and application are shown in Table 17. particularly seashells. NEI standards require 1/32-inch corrosion allowance and 1/16-inch corrosion allowance is usually specified. water velocity. Tube water velocity. 7. Galvanic corrosion and protection. seawater. Tube support plates should not be less than 3/4 inch thick.2 Tube Support Plates. 7. for Moderate and Lower Temperature Service. Foreign body contamination. Chemical attack. Biofouling. are commonly used without preference of one type over the others. Tube impingement and vibration. The spacing of the tube support plates shall be in accordance with HEI standards. polluted water. A final choice of tube material should not be made without a thorough understanding of the effects and problems related to the following: a) b) c) d) e) f) g) h) i) j) k) Tube metal corrosion.3 Tubes. either ASTM A283 Grade C or ASTM A285 Grade C material is usually used. l) Cooling water characteristics such as freshwater. Recommended condenser tube gauge. Carbon Steel. brackish water. Tube support plates are located at periodic intervals along the length of the tubes to steady and prevent vibration of the tubes that could otherwise result from impingement of high velocity steam or possibly from cooling water flow. Tube metal erosion. Cooling water scaling characteristics.MIL-HDBK-1003/7 Pressure Vessel Plates. Dealloying such as dezincification.
000 1.MIL-HDBK-1003/7 TABLE 16 Recommended Tube. such as ph and iron and manganese concentration. Bronze Steel2 Current * * High TDS (Alloy D) * * Freshwater C61400 * * * * Clean 30. 2 ASTM A 285 Gr C or ASTM A 283 Gr C.000 15. Aluminum Carbon Yes Impressed * 3 2 ASTM Bronze Steel Current * * Seawater * B 338 Gr (Alloy D). Tube Sheet and Water Box Materials +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).000 1. 105 . * * C61400 * . 3 Polluted seawater includes water with sulfide related content.500 304 SS Carbon Carbon Yes Sacrificial * * water ASTM Steel Steel2 Anodes * * ASTM * * A283 Gr C * * * * Brackish 9.000 15. Carbon Carbon None Sacrificial * * Fresh* water ASTM Steel Steel2 Anodes * * A 249 ASTM * A283 Gr C * * * * * Fresh9. Carbon Carbon None None * * Fresh* water ASTM Steel Steel2 * * A 249 ASTM * * A283 Gr C * * * 6.000 304 SS.500 90-10 Aluminum Carbon Yes Impressed * * water and Cu-Ni.000 1. Sulfides and sulfide related compounds may be found in cooling waters other than seawater.000 250 304 ss. Full classification of the cooling water must be on a project by project basis. Specific Tube Interior Water Cathodic * * * Water Conductance/ Tube Sheet Water Box Box Protection * * Type Chlorides1 Material Material Material Coating Type * * ms/cm mg/L * * * 2.000 Titanium. Bronze Steel2 Current * * C70600 (Alloy D) * * C61400 * * * * Polluted 30.000 90-10 Aluminum Carbon Yes Impressed * * Seawater Cu-Ni.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))1 Other chemical characteristics of the cooling water must be considered.
Possible Applications * * * Air * * Gauge Velocity Main Removal * BWG FPS Body Section Periphery * * Freshwater Alloys * * * * Once-Through System * Admiralty Brass 18 8 max X * * 90-10 Copper Nickel 20 10 max X X X * * 70-30 Copper Nickel 18. Low chloride content waters only. 106 . and Application +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).20 15 max X X * * * 304 Stainless Steel1 22 5 min X X X * * * * Once-Through System * 90-10 Copper Nickel 18.20 15 max X X * * 304 Stainless Steel 22 5 min X X X * * * * Recirculating System * * 90-10 Copper Nickel 20 10 max X X X * 70-30 Copper Nickel 18.20 15 max X X X * * "Super" Stainless * * Steel 22 5 min X X X * Titanium 22 5 min X X X * * . 2.MIL-HDBK-1003/7 Table 17 Recommended Tube Gauge.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 1. Source: Olin Fineweld Condenser and Heat Exchanger Tube Symposium.20 8 max X X X * * * 85-15 Copper Nickel 20 max X X X * * 70-30 Copper Nickel 18. Recommendations are the same for a once-through system or a recirculating system. Water Velocity.
stainless steel (Type 304) is the best tube material for freshwater once-through or recirculating cooling water systems. Admiralty is susceptible to stress corrosion cracking if ammonia is present. 107 . Stainless steel provides a good resistance to sulfide attack. Their main advantage over stainless steels is better resistance to biofouling. Admiralty is also susceptible to dezincification.3. can be traced to the problem of tube fouling (including seawater applications). stainless steels are susceptible to biofouling. Stainless steels. good thermal conductivity and strength. and scale buildup can also be a problem. Almost all failures of stainless steel tubes. and some resistance to sulfide attack. Admiralty and 90-10 copper-nickel have been used in both once-through and recirculating freshwater cooling systems. * 90-10 70-30 Stainless * Admiralty Cu-Ni Cu-Ni Steel Titanium * * Failure Mechanism * * * General Corrosion 2 4 4 5 6 * 2 4 5 6 6 * * Erosion Corrosion * Pitting (Operating) 4 6 5 4 6 * 2 5 4 1 6 * * Pitting (Stagnant) * High Water Velocity 3 4 5 6 6 * * Inlet End Corrosion 2 3 4 6 6 * * Steam Erosion 2 3 4 6 6 * * Stress Corrosion 1 6 5 1 6 * 3 6 5 1 6 * * Chloride Attack * Ammonia Attack 2 4 5 6 6 * . good biofouling resistance. and to deposit related attack. Admiralty provides good corrosion resistance when used in freshwater at satisfactory velocities (less than 8 fps). However. because of corrosion. For 304 stainless steel. 7.1 Freshwater Service. Because copper alloys are susceptible to ammonia based stress corrosion cracking.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- NOTE: Numbers indicate relative resistance to the indicated cause of failure on a scale of 1 (lowest) to 6 (highest). chlorides less than 1500 mg/L should be acceptable. to blockage induced erosion/corrosion. but the chloride levels must be kept low. Admiralty should not be used in the air removal sections.3. to a lesser extent.MIL-HDBK-1003/7 Table 18 Relative Resistance of Most Widely Used Tube Materials to Failure +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). The most commonly used tube materials for freshwater service are Type 304 stainless steel (ss). Copper alloys have also been used successfully in freshwater applications. both type 304 and 316. Admiralty metal. provide excellent resistance to all forms of corrosion in fresh water. Type 304 stainless steel is a good selection for freshwater makeup cooling tower systems. 90-10 copper nickel and.
increased attention is being given to newly developed austenitic and ferritic stainless steels. the molybdenum content should be 6 percent with a chromium content of 19 to 20 percent. As long as the seawater is relatively clean and free of pollution. When inlet end infringement and erosion attack due to water flow is a potential problem. However. Where scale formation or microbiological slimes can possibly occur. Type 316 stainless has been used successfully in a few instances and where special care was taken to keep the tubes free of fouling. the recommendations for brackish water materials are applicable. 7. Because of overall failure rate experience.MIL-HDBK-1003/7 7.2 Brackish Water Service.3. 108 .3. aluminum bronze. Copper alloys. Because of stringent preventive maintenance requirements and procedures. Type 316 stainless steel is not considered the best tube material for use in brackish water applications. For condenser cooling water with high chloride concentration.3 Seawater Service.3. Careful attention must also be given to support plate spacing to avoid vibration when using thin walled titanium tubes and extra support plates are needed. It is generally accepted that for austenitic stainless steel to resist corrosion. 90-10 copper-nickel is the recommended tube material for use with brackish water in the main body of tubes with 70-30 copper-nickel in the air removal sections. including aluminum brass. In spite of overall excellent corrosion resistance. For ferritic steels. and its low modulus of elasticity. Titanium tubes are being used with increasing frequency for seawater application. The major problems with titanium tubes include its high fouling rate in low water velocity systems. Brackish water also refers to the recirculating systems with freshwater makeup where the cycles of concentration produce high chlorides and total dissolved solids. Seawater materials are considered wherever the chlorides in the cooling water are greater than 15. 85-15 copper-nickel should be considered. if the brackish cooling water is also characterized by high sulfide concentrations. an on-line mechanical tube cleaning system is required to maintain a high tube cleanliness factor. and copper-nickel have been used extensively in brackish water applications.000 ppm.3. Titanium is essentially resistant to all oxidizing media by virtue of the stable. its susceptibility to hydrogen embrittlement. Brackish water is defined as any water with chlorides in the range of 1500 mg/L to 12000 mg/L and associated high concentrations of total dissolved solids. stainless steels have not been used extensively in brackish or seawater. protective oxide film. Seawater also includes cooling tower systems where brackish water is concentrated and high chlorides and total dissolved solids result. consideration for use of the "super" stainless steels is recommended. the molybdenum content should be at least 3 percent and the chromium content should probably be 25 percent or more.
Aluminum bronze is the preferred tubesheet material for copper-nickel installations since silicon bronze is not easily weldable and since Muntz metal does not provide as much strength. 7. copper based alloy tubes are not considered feasible polluted water materials.MIL-HDBK-1003/7 Because of the expense and potential problems with titanium tubes.3. 7. 7. the obvious selection of tubesheet material for new units is the use of same material as the tubes.3.1 Freshwater Service. are less expensive than titanium and are not expected to experience any of the problems with cathodic protection systems that are possible with titanium tubes. as a 109 . this may be prohibitively expensive. it is the obvious tubesheet material selection for use with stainless steel tubes. the new austenitic and ferritic stainless steel condenser tube alloys should be considered since 90-10 copper-nickel and 70-30 copper-nickel are highly susceptible to sulfide pitting attack. the results have been favorable for the "super" stainless steels used in this application.4. or elemental sulfur are present in the cooling water. aluminum bronze is the most common choice for tubesheet material involving welded tubes. polysulfides. (Cathodic protection is required. Tubesheet material compatible with stainless steel tubes are carbon steel and stainless steel. Polluted water materials should be used whenever sulfides.3. To date.4.) Silicon bronze tubesheets are not widely used. Carbon steel has been used successfully for tubesheet material. When the seawater is also characterized by a high sulfide concentration. The materials are compatible with all copper alloy tubes. The next best choice is to use materials that are as close as possible to one another in the galvanic series (see Figure 31) or ensure satisfactory performance by using coatings or cathodic protection. Also. Even if titanium tubes are used. however. However. Since it is less expensive than stainless steel. Muntz metal is the most widely used tubesheet material with copper-nickel tubes. aluminum bronze and silicon bronze provide good tube-to-tubesheet joint integrity and good pull-out strength. the "super" stainless steels.4 Tubesheets. Muntz metal is also suitable for use with Admiralty tubes. 90-10 copper-nickel and 70-30 copper-nickel tubes are considered better selections for clean seawater applications.2 Brackish and Seawater Service. This leaves titanium and the new austenitic and ferritic stainless steels.3. However. Therefore. Sulfides produce and accelerate corrosion of copper alloys. Stainless steel is also not acceptable since the polluted water is usually brackish or seawater.3.4 Polluted Water Service. The most acceptable of these tube materials is titanium based mainly on its greater experience. which were created predominantly for use with polluted cooling water. In order to prevent galvanic action between tubes and tubesheets. Because of their relatively high yield strengths. 7. The majority of installations using these new "super" stainless materials are located in coastal areas with polluted cooling water.
if any. pitting.4. 7. However. 7. Water box materials include carbon steel. will occur on the thicker tubesheet instead of the thinner walled tubes. The cost difference between aluminum bronze and silicon bronze is slight. Muntz metal tubesheets are often used with copper-nickel tubes. there is no advantage to using stainless steel over carbon steel since stainless steel is more expensive and is also susceptible to corrosion. Carbon steel is an acceptable choice assuming that the interior of the water box is properly coated and that some form of cathodic protection for the water box is provided. This arrangement would prevent any potential galvanic corrosion of the aluminum bronze as well as eliminate any problem with corrosion due to the sulfides. aluminum bronze is significantly less susceptible to galvanic corrosion than Muntz metal. 7. The actual material cost of silicon bronze is slightly lower but the added thickness or supports required for high pressure designs negates any material savings.1 Freshwater Service. Use carbon steel ASTM A285 Grade C or ASTM A283 Grade C with copper alloy or stainless steel tubes. The 316L and similar tubesheet materials are also slightly cathodic to the "super" stainless steel tube alloys.3. Stainless steels such as Type 316L and other proprietary alloys are similar to Type 304 stainless steel but with the addition of molybdenum that offers increased resistance to general corrosion.2 Brackish and Seawater Service.MIL-HDBK-1003/7 tubesheet material.3. stainless steel. Recommended tubesheet materials for use with tubes made of the new austenitic and ferritic stainless steels are the same as described under brackish water. as with freshwater.3 Polluted Water Service. A feasible alternative is 90-10 copper-nickel but it is significantly more expensive than carbon steel. Galvanic corrosion between the new "super" stainless steel condenser tubes and these tubesheet materials is minimized because their similar compositions places them relatively close on the galvanic series chart. A properly designed cathodic protection system should protect the aluminum bronze tubesheet.3. In brackish water. Aluminum bronze is the preferred tubesheet material for titanium tubes.5. and 90-10 copper-nickel. Muntz metal is not the best material since it does not have the strength required to ensure adequate tube-to-tubesheet integrity.5. 111 . This is desirable since whatever corrosion takes place.3.5 Water Boxes 7. New condenser tubesheet materials are under consideration as a result of the ever increasing use of the new austenitic and ferritic stainless steel condenser tube materials. and crevice corrosion attack. a titanium tubesheet (or titanium cladded tubesheet) should be considered. For extremely polluted water.
7. however. For bottom supported condensers.5. there can be and usually is a difference in expansion between the shell and tubes during operation. either as a part of the exhaust neck of the condenser or separate component. The condenser is bolted to and supported from the turbine The center of gravity of the condenser must be centered on the turbine As with the spring support method. expansion units.7.3 Polluted Water. This avoids the use of an expansion joint in the condenser neck.7. The majority of all condensers are now furnished with a rubber (dogbone type) expansion joint.1 Exhaust Neck. Depending upon the type of tube to tubesheet joining.3.2 Spring Support.3.MIL-HDBK-1003/7 7. Coated carbon steel water boxes with cathodic protection is the recommended choice for use with titanium or the new austenitic and ferritic stainless steel tubes.4 Condenser Support 7. This method is seldom used. or rubber is located between the turbine exhaust flange and the main body of the condenser.4. all auxiliary piping must be provided with joints. or condenser neck as it is commonly called is attached to the turbine exhaust flange by bolting or welding and contains an expansion joint of stainless steel. turbine exhaust extension piece. exhaust.3 exhaust. The rubber dogbone type is preferred because it can more easily be replaced as compared to a stainless steel joint. the majority of condensers are furnished with a steel U-bend type that is usually located adjacent to one of the tube sheets. The condenser is bolted directly to the turbine exhaust flange and supported at the bottom feet by springs to allow for expansion. Both flexing steel plate and U-bend type have been used. 7. 7. Corrosion of copper joints has caused the use of this material to be essentially discontinued. 7.3. The connection piece extending from the turbine exhaust flange to the main body of the condenser and often referred to as the condenser neck is made of the same material as the condenser shell. all piping connected to the condenser for auxiliaries must be provided with expansion joints to permit free movement of the condenser.7 Expansion Joints 7.2 Shell.6 Exhaust Neck. The use of stainless steel is satisfactory but expensive. copper. an expansion joint made of copper. stainless steel. or rubber. Suitable means must be incorporated in the design of the condenser to provide for this differential expansion.3. 7.4. However.3. 7.1 Bottom Support. Bottom support is the simplest method and consists of mounting the condenser rigidly on its foundation. The condenser dome.4. The use of this method is restricted to small turbine generator 112 . Rigid Support.
Hogger capacities as shown in HEIS are shown in Table 20.000 7.001 to 250.000 4.001 to 500. SCFM . Dry Air SCFM1 * * * Turbine Exhaust (at 1. For other condenser arrangements refer to complete tables presented in HEIS.0 * * * 100.0 * 50.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 1.5 Condenser Air Removal 7.000 100 * * 250.001 to 250.001 to 1.000 10. Table 19 Venting Equipment Capacities For Single Shell Condenser +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).000 50 * * * 100. Table 20 Hogger Capacities +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).MIL-HDBK-1003/7 7.000 200 * 500.5 * * 250.1 Continuous Air Removal.5..14. Recommended capacities of air removal (venting) equipment for single shell condensers should not be less than shown in Table 19.2 Hogging Air Removal.5. a steam operated hogging ejector or mechanical air exhausters (the same equipment as used for continuous air removal) must be used.000 3. Continuous air removal is accomplished by use of either a steam jet air ejector or mechanical air exhausters (vacuum pumps). when starting up to a condenser pressure of about 10-inch Hg Abs.000.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 7.000 350 * * .0" Hg Abs * Steam Flow lb/hr suction pressure) * * * * Up to 100.000.001 to 1. * Turbine Exhaust Steam/Air * * Steam Flow Mixture * * lb/h SCFM * * * * Up to 25.000 12.000 5.5 * . For evacuating steam space.0 * * 500.0 * * 25.001 to 100.001 to 50.7 psia and 70 F 113 .001 to 500.
For additional requirements see MIL-HDBK-1003/6. AUXILIARY EQUIPMENT 8. The vertical can type pumps are often used because the construction and installation provides for net positive suction head (NPSH) requirements without the use of a pit for pump location. A tank sized for twice the cycle water swell volume will usually provide sufficient capacity for normal condensate makeup and dump requirements. Condenser condensate pumps are used for pumping condensate from the turbine condenser to the deaerator through the low pressure feedwater heaters. pump glands. 8. and the turbine gland steam condenser (if any). 114 . each capable of handling full load operation. These losses occur at points such as the deaerator continuous noncondensibles and steam vent. and continuous water and steam samples.3 Condensate Receivers and Pumps Sizing. The amount of storage required is about 1. Provide two pumps for transfer of water as needed from these tanks to the condensate storage/return tank. Demineralized water is also required for filling the boiler/turbine generator unit system initially prior to startup and during times of boiler or cycle maintenance and chemical cleaning.5 percent of the steam flow to the turbine is lost from the cycle. see Section 4. shall be provided of either the horizontal split case or vertical can type.MIL-HDBK-1003/7 Section 8. The condensate storage and transfer equipment is illustrated in Figure 32. the excess or deficiency of cycle water caused by load changes is usually handled by providing a condensate storage tank which can accept and hold excess condensate or provide condensate makeup for cycle water deficiency. 8.1.1.000 gallons per MW storage capacity is necessary. If an evaporator is used for cycle water makeup.1 Condensate Storage Tank. For normal operation. Two condenser condensate pumps. Power Plant Steam Generation.000 gallons per MW of installed electric generating capacity which is usually divided into not less than two tanks.1. valve packing leaks. For sizing of condensate receivers and associated pumps. 8. a similar amount of 1.4 Condensate Pumps.1 Condensate Storage and Transfer. for maintenance or for chemical cleaning.2 Deionized or Demineralized Water Storage Tank. About 0. 8. the steam jet air ejector. For cogeneration plants. continuous boiler blowdown. Condenser vacuum is normally used as the motive force to draw condensate from the storage tank to the condenser through makeup control valves. Condensate dump from the cycle to the storage tank usually is made from the condensate pump discharge through dump control valves. the function of condensate return from heating and other processes is usually combined with the function of condensate storage using a single tank. is usually stored in separate tanks which contain deionized or demineralized water.1. Water required for filling the cycle or boiler either initially.
Low pressure feedwater heaters are used in the condensate system between the condensate pump discharge and boiler feed pumps.1. and utilize low pressure turbine extraction or auxiliary turbine exhaust steam for heating the condensate. back to the deaerator in a fashion similar to the heater drain system for the low pressure heaters. The selection. and utilize high pressure turbine extraction steam for heating the feedwater.2 Feedwater Heaters. The standby condensate transfer pump can be used for boiler fill.1 Low Pressure Heater(s).2 High Pressure Heater(s).6. leaf filters. emergency condensate makeup to the deaerator. Condensate transfer pumps are used to pump condensate from the main condensate storage/return tank to the deaerator. diatomite.1.6. The heater drains are cascaded from the higher pressure heater to the next lower pressure heater with the lowest pressure heater draining to the condenser. The condensate or feedwater temperature increase for each feedwater heater will be in the range of 50 to 100 degrees F (28 to 56 degrees C) with the actual value determined by turbine manufacturer's stage location of steam extraction nozzles.1 Wastage.2. High pressure feedwater heaters are used in the feedwater system between the boiler feed pump discharge and the boiler.2. The heater drains are cascaded from heater to heater. or other acceptable methods to clean the condensate.1. Condensate containing oil should be wasted. Oil and other undesirable matter should be removed from condensate returned from the process and fuel oil tubular heat exchangers.6 Condensate Cleaning. Two condensate transfer pumps.MIL-HDBK-1003/7 8. Where the amount of oil-contaminated condensate is so great that it would be uneconomical to waste it. 8. 8. 8.1. each capable of handling full load operation. Use one or more low pressure feedwater heaters to raise the temperature of condensate from condensate pump discharge temperature to the deaerator inlet temperature.3 Heater Drain Pumps 116 . and initial fill of the condenser. 8. some turbines offer alternate number of extraction nozzles with usually a choice of using the highest pressure extraction nozzle. 8. 8. shall be provided of either the horizontal split case or vertical can type. Depending on turbine size. in this case. of the total number of feedwater heaters to use should be based on economic evaluation. The feedwater heater equipment is illustrated in Figure 32.2 Filtration. 8. Use one or more high pressure feedwater heaters to raise the temperature of feedwater from deaerator outlet temperature to the required boiler economizer inlet temperature. Oil will cause foaming and priming in the boilers as well as scale. provide cellulose.5 Condensate Transfer Pumps.
1 Low Pressure Heater Drain Pump. 8. the manufacturers recommend that the 117 . the deaerator will normally perform the following functions: a) Heat the condensate in the last stage of condensate system prior to the boiler feedwater system. f) g) Receive drains from high pressure heaters. Use two full capacity pumps with one of the two pumps for standby use.4 Deaerators.2 Deaerator Design Pressure a) Turbine manufacturers indicate that the extraction pressure quoted on the heat balances may vary as much as plus or minus 10 percent.3. Receive the boiler feed pump recirculation. In addition. e) Provide hot water for air preheating and combustion gas reheating (if any) and/or other auxiliary heat requirements. 8. and MIL-HDBK-1003/6. 8. The primary function of the deaerator is to remove dissolved oxygen from the condensate in excess of 0. Pumping of the heater drains in this fashion provides recovery of heat which would other wise be lost to the condenser. Use only one pump and provide alternate bypass control of drains to the condenser for use when the drain pump is out of service.005 cc of oxygen per liter of condensate at all loads. d) Receive water from the condensate system and provide surge capacity in the storage tank. Table 6.4. Deaerator(s) for power plants usually heat the condensate through a range of 50 to 75 degrees (28 to 42 degrees C). when high pressure heater drains are cascaded to the deaerator. Provide at least one deaerator for the generating plant. 8. The deaerator usually is arranged in the cycle to float in pressure with changes in extraction pressure (which changes with turbine load).MIL-HDBK-1003/7 8. b) c) suction head. Low pressure heater drain pumps may be used for pumping drains from the lowest pressure heater to a point in the condensate piping downstream from the heater in lieu of returning the drains to the condenser. Receive high pressure trap drains. in order to overcome the elevation difference between the lowest high pressure heater and deaerator. Considering operation with extraction heaters out of service. Provide the boiler feed pumps with the required net positive The deaerator functions are illustrated in Figure 33. The use of low pressure heater drain pumps can be decided by economic evaluation.3. See Section 4. High pressure heater drain pumps are required.1 Deaerator Function. for further requirements.4.2 High Pressure Heater Drain Pumps.
15 plus allowance for safety valve. psig Pv = Vapor pressure of boiler feedwater at boiler feed pump suction. The maximum allowable working pressure shall be assumed to be equal to the design pressure. elevation. the deaerator shall also be designed for full vacuum (thereby eliminating the need for a vacuum breaker. psia D = Density of boiler feedwater. Volume 83. ft f = Friction loss in piping from deaerator to boiler feed pump suction.) 8. ASME pp 69-73. hs = Static head between deaerator water level and centerline of boiler feed pump. and boiler feed pump net positive suction head (NPSH) are related as outlined in Rodney S. ft.15 x 0. b) Safety valve manufacturers recommend that a suitable margin be provided between the maximum operating pressure in a vessel and the set pressure of the lowest set relief valve. Thurston's paper "Design of Suction Piping: Piping and Deaerator Storage Capacity to Protect Feed Pumps. The boiler feed pump NPSH is calculated using the following equation: EQUATION: where: Pa = Atmospheric pressure. c) The deaerator design pressure shall be specified with a design pressure equal to maximum extraction pressure x 1. They suggest that this margin be approximately 10 percent above the maximum operating pressure or 25 psi. January 1961. lb/cu. psia Ps = Steam pressure in deaerator.f (11) 118 .Pv) x (144/D) + hs . The design pressure should be rounded up to the nearest even 10 psi. whichever is greater." Journal of Engineering for Power.MIL-HDBK-1003/7 deaerator be designed for a possible 15 percent increase in the pressure from that shown on the manufacturer's heat balance. This prevents any undesirable operation of the relief device. d) If the deaerator design pressure is 75 psi or greater. The allowance for safety valve shall equal maximum extraction pressure x 1. whichever is greater.3 Deaerator Storage Volume.4. ft NPSH = (Pa + Ps .1 or 25 psi. The deaerator storage volume.
and MIL-HDBK-1003/6. desuperheating station is shown in Figure 34.2 Oxygen Removal.1 Rated Capacity.MIL-HDBK-1003/7 a) Deaerator storage volume should be not less than the volume of feedwater equivalent to 10 minutes of feedwater flow at full turbine load. b) The deaerator is usually located at the same elevation as the boiler main upper drum. Main steam supply to steam jet air ejector. at all loads. use one for one-third of total load and the other for two-thirds load instead of single pressure reducing valve.4. 8. Deaerators should be specified to provide condensate effluent.4.6.4. Main steam supplemental and standby supply to export For load variations of 3:1 and larger.5 Boiler Feed Pumps. b) steam. Table 6. see Section 4. 8. 8. if used.6 Pressure Reducing and Desuperheating Stations. are as follows: A pressure reducing and Typical use of pressure reducing control valves a) Boiler drum steam supply to auxiliary steam system supplying building heating equipment.4. c) d) High pressure extraction bypass to deaerator. 8.4 Deaerator Rating 8.4. For design and other data relative to boiler feed pumps and feedwater pumping systems. and deaerator standby steam supply. fuel oil heaters. or station.005cc of oxygen per liter of condensate. at saturation temperature corresponding to deaerator pressure and with an oxygen content not to exceed 0. use two parallel pressure reducing stations with a common valved bypass. 120 . The rated capacity of a deaerator is the quantity of deaerated water in pounds per hour delivered to the boiler feed pumps by the deaerating unit and includes all of the steam used for heating in the deaerator.1 Pressure Reducing Stations. 8.
for air compressor jackets and aftercoolers. receivers. 8. 122 .7.6. A closed circulating cooling water system shall be provided for cooling the bearings of auxiliary equipment such as pumps and fans.2 Equipment Description. one head tank.05. and Arrangement. aftercoolers. see MIL-HDBK-1003/6 and NAVFAC DM-3. and air dryers. The tank should be provided with an overflow piped to drain.MIL-HDBK-1003/7 8. to provide head on the system and to provide a still volume to permit release of air from the system. For description of types. depending upon the reduced pressure of export steam) to the desuperheater. Desuperheaters may be of the steam or mechanically atomized type. depending upon the design of the boiler. Desuperheaters may also be used on the boiler steam headers for main steam temperature control. The use of compressed air for fuel oil atomizing should be economically evaluated versus steam or mechanical atomization. Water used for tempering must be of demineralized water or good quality condensate to avoid mineral deposits on the desuperheater. A typical auxiliary cooling water system is illustrated in Figure 35. To provide for expansion from cold to operating temperatures. design requirements. The system shall consist of two shell and tube heat exchangers. 8. and sample cooling coils.7 Compressed Air System 8.7. 8.1 Applications.2 Desuperheating Stations. The normal operating water level of the head tank should be approximately 70 percent of the tank capacity. This will assure a positive pressure throughout the system both during normal operation and in the shutdown mode. and instrument air supply. Compressed Air and Vacuum Systems. The tank should be located above the highest piece of equipment being cooled by the auxiliary cooling water system. The auxiliary cooling water head tank is used as an expansion tank. generator air or hydrogen coolers. soot blowing. Design. The major uses of compressed air for power plants are for plant service which includes boiler fuel oil atomizing. and necessary valves and piping. The use of compressed air versus steam blowing for soot blowers should also be economically evaluated. Desuperheating stations usually consist of a control valve station which is used to regulate the flow of desuperheating water (from boiler feed pumps or condensate pumps discharge. and arrangement of air compressors.8 Auxiliary Cooling Water System. turbine oil coolers. two water circulating pumps. a volume equal to approximately one percent of the volume of the system should be provided between the normal operating level and the high water alarm.
123 .
The auxiliary cooling water in the system is treated initially upon filling with chemical additives to prevent corrosion throughout the system. This is accomplished by means of a pot feeder located on the discharge of the auxiliary cooling water pumps. Chemical concentration of water contained in the system is maintained during plant operation by periodic injection of chemicals.MIL-HDBK-1003/7 The temperature of auxiliary cooling water from the heat exchangers should be maintained constant by use of an automatic temperature control system which regulates a control valve to bypass auxiliary cooling water around the cooling water heat exchangers. 124 .
Clamshell bucket unloaders range in size from 400 tons per hour to 2. The haul system consists of a hauling winch. The tower structure of the unloader may be either stationary or movable. Barge unloaders are required for river barges (195 feet long x 35 feet wide x 12 feet side. The capacity of a clamshell unloader is specified in tons per hour-free digging rate based on a mean duty cycle. Unloading systems are required at the plant site for removing or discharging coal from the primary carrier.1. The mean duty cycle is based on the average travel and lift of the bucket required for a barge of specified dimensions. return winch.500 to 5. The stationary type requires a system of hauling and breasting winches and cables to move and position the barge along the dock relative to the unloader tower structure and boom. The barge unloading procedure used with the continuous ladder unloader will vary with the size of barge being unloaded and number of digging elements. Barges are moved under the unloader by use of a barge haul system especially designed for this type of machine. 1. the continuous bucket ladder type has also been used. Each winch must be designed to exert a retarding torque during barge unloading in order to keep the cables tight and prevent barge drift. The unloader supports one or two bucket elevator type digging elements as shown in Figure 36. however. COAL HANDLING 9. Ocean barges have four or more 125 .500 ton capacity each) and for ocean barges (462 feet long x 82 feet wide x 28 feet side and combing.2 Ocean Barge Unloader. The unloader may be arranged to either lower and raise the elements relative to the barge or swing into and out of the barge from a pivot at the upper end.1 Barge. The hauling winch is designed to move the barge at an adjustable speed from approximately 5 to 50 feet per minute. Section 5. 9. 9. the barge being unloaded must be kept in alignment with the dock face.1. For a 195foot x 35-foot standard hopper barge. 13. sheaves.1 Unloading Systems. The return winch is designed to move the barge at faster rates of speed. Unloaders for ocean barges are usually of the clamshell bucket type. With the continuous ladder type of unloader. The unloading system is an integral part of the overall coal handling system for a power plant.000 tons per hour. See MIL-HDBK-1003/6.1. 9. a "two pass" unloading procedure is generally used with a single digging element and a "three pass" unloading procedure is generally used with twin digging elements.1.MIL-HDBK-1003/7 Section 9. for railroad and truck delivery and coal handling. Unloaders for river barges are usually of the continuous bucket ladder type. Unloaders of this type range in capacity from 1.000 tons per hour. and wire rope cable.1 River Barge Unloader.000 to 18.1.000-ton capacity each depending upon allowable draft).
The unloader bucket is supported by cables from a trolley that moves back and forth along the boom. see MILHDBK-1003/6. Conveyor belt type scales can also be used to measure the amount of coal stockpiled or delivered to the in-plant bunkers or silos.MIL-HDBK-1003/7 separate compartments with each compartment provided with a large hatch cover. Coal is dropped into a receiving hopper from which it is discharged to a yard belt conveyor.4 Coal Reclaiming.3 Coal Storage. should be provided on the conveyor system feeding plant bunkers or silos. Separate bunkers or silos should be provided for each boiler. 9. These cables are also used to lower a bulldozer into each compartment for final cleanup of coal. 9. 9. Railroad track scales and truck scales are optional for use in measuring the amount of coal received. In-plant bunkers and silos are used for storage of coal for day-to-day operation of feeding the boiler coal burning system. lower. For additional information relative to coal crushing equipment. which allows the unloader to be used also for coal reclaim from an onshore stockpile. The tower structure supports a machinery house that contains DC motor driven hoisting and trolley movement equipment. The bunker/silo fill system capacity should be equivalent to twice the maximum coal burn rate plus 15 percent. One type incorporates permanent or electromagnets into the head pulley 127 . Storage shall be as required in MIL-HDBK-1003/6. Basically. the use of belt type scales is more economical than track or truck scales. 9. a coal crusher must be provided to reduce the coal to uniform lump size suitable for storage and firing or pulverizing. In climates where frozen coal may be a problem. The coal gallery will contain a coal distribution system consisting of a belt tripper flight conveyor or cascading belts. The unloader mechanism includes a holding hoist to raise.7 Coal Scales.5 Plant Bunker or Silo Storage." except that the outside storage reserve stockpile shall be designed to store 90 days usage of coal at full plant capacity. The boom may also be provided with a movable operating cab which can be positioned to serve at either end of the boom. a trolley winch that moves the trolley. Coal reclaiming is usually done by means of bull dozing the coal from the reserve stockpile into a separate reclaim hopper which shall include a feeder and a conveyor that transports the reclaimed coal onto an unloading belt or bucket elevator. under paragraph titled "Fuel Handling. Magnetic separators shall be used in coal conveying systems to separate tramp iron (including steel) from the coal. a coal cracker for breaking up frozen lumps. however. if an unloading belt conveyor is used. and a tower drive (if the tower is of the movable type). a closing hoist that opens and closes the bucket. The unloader boom may be extended on both sides of the tower structure. and electrical control equipment.2 Coal Crushing. motor generator sets. two types are available.6 Bunker or Silo Filling Systems. and hold the bucket. The bunker or silo filling system will consist of a bucket elevator or belt conveyor that is used to elevate the coal from reclaim hopper discharge to top of bunker/silo coal gallery. 9. If unsized coal such as run of mine is delivered to the plant. The amount of coal for this storage should be equivalent to 96 hours of plant operation at full load.8 Magnetic Separators. 9. For additional information see MIL-HDBK-1003/6. 9. Hatch covers are moved to the open position by means of cables attached to the unloader bucket. For description of system components and requirements see MIL-HDBK-1003/6.
c) Flanged belt sample feeders with rubber-lagged head pulleys and variable speed drives. Sampling of coal may be done either manually or automatically. and/or just prior to coal discharge to the in-plant bunker or silo fill system. The major components of automatic sampling systems are as follows: a) In-line. 9. Coal sampling is done when there is a need to determine or verify the analysis or content of some constituent in the coal either on an as-received or as-fired basis. spoon-type primary and secondary sample cutters with electric or hydraulic drive assemblies. d) Sample crushers with adjustable breaker plates or screen bars to permit control of product size and compensate for wear. The other type consists of permanent or electromagnets incorporated into a belt conveyor that is suspended above a belt conveyor carrying coal.MIL-HDBK-1003/7 of a belt conveyor.9 Coal Sampling. Magnetic separators shall be used just ahead of the coal crusher. If moisture content determinations are to be made. which in turn holds and carries the tramp iron to a collection hopper or trough. b) Motor-driven. In either case. the sample must be collected in a container which can be immediately sealed following the sample collection. rotary tertiary sample cutters. if any. The tramp iron is pulled from the moving coal to the face of the separating conveyor. The tramp iron clings to the belt as it goes around the pulley drum and falls off into a collection hopper or trough after the point at which coal is discharged from the belt. the method of sampling must provide a representative sample of a relatively large amount of coal without bias. 128 .
Standard Method of Preparing Coal Samples for Analysis.MIL-HDBK-1003/7 e) f) Automatic rotary sample collectors. 129 . Standard Methods for Collection of Gross Sample of Coal and ASTM D2013. Means of returning sample rejects to coal conveyor. The method of sampling and coal sampling system must conform to ASTM D2234.
operation. See MIL-HDBK-1003/6 Section 4. Table 21 Typical Distribution of Boiler Ash +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). The typical distribution of ash from combustion of coal is shown in Table 21.MIL-HDBK-1003/7 Section 10. Fly ash is collected in the boiler. electrostatic precipitator hoppers. Ash production rates can be determined using the known ash content (from proximate or ultimate analysis) and firing rates of the coal.1.1. last pass hoppers or hoppers below an economizer. The removal and handling of bottom ash and fly ash from collection hoppers is accomplished by the use of one of several systems which are described as follows. thermally by the use of a steam jet pump. Paragraph titled "Ash Handling". or bag house filter hoppers.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- Bottom ash is collected in the boiler bottom ash hopper. * Eastern Western * * Bituminous Sub-Bituminous * Percent Percent * * * * * Stoker Coal Boiler: * Bottom ash 35 35 * * * Fly ash 60 60 * * Last pass or economizer hoppers 5 5 * * * * * Pulverized Coal Boiler: * Bottom ash 20 30 * * Fly ash 75 65 * * Last pass or economizer hoppers 5 5 * . mechanical dust collector hoppers. The ash is then conveyed to a storage silo through 130 . Also see ash handling equipment manufacturers' reference manuals for detailed descriptions of arrangement. For a stoker coal fired boiler. Vacuum for conveying bottom ash or fly ash is produced hydraulically by the use of a water jet pump. 10.1 Ash Handling Systems. ASH HANDLING 10. Pneumatic ash handling systems are available as a complete vacuum system. or mechanically by the use of motor driven rotary exhausters. Ash handling systems are required for removal of bottom ash and fly ash from coal fired boilers.1. 10. and control of ash handling components and systems. bottom ash also includes ash which falls through the grate into the siftings hopper. Air is admitted into the end of the conveyor pipe and ash is admitted at intermediate points through ash intake fittings or automatic valves.1 Vacuum System.1 Pneumatic. complete pressure system or a combination vacuum-pressure system. hoppers below an air heater. for requirements.
Because of the associated history of line plugging and other mechanical difficulties.2.2 Pressure System. using high pressure water as the conveying medium for bottom ash. A pressure system should be used when the fly ash conveying distance is greater than can be served by a vacuum system. In the dense phase system. Dewatering bins allow storage of bottom ash up to several days. For bulk density of bottom ash. This type of system permits the use of vacuum to remove fly ash from hoppers at a high rate to a collecting point nearby where the fly ash is continuously transferred to a pressurized conveyor for discharge at a remote terminal point. For a water impounded bottom ash hopper.1 Stoker Firing.1. In this system. The silo air vent shall have an exhaust fan which discharges the vented air to the boiler flue gas dust collector. An air lock tank type feeder is located at each fly ash hopper outlet or discharge.MIL-HDBK-1003/7 primary and secondary cyclone type air and ash separators.2 Bottom Ash Hoppers 10.2. Need for further developmental work is indicated and is ongoing. or a separate bag filter may be used to clean the silo vented air. material is pushed through a pipeline as a fluidized slug at higher ash to air ratios than conventional dilute phase conveying. bottom ash hoppers are fitted with ash discharge gates each followed by a crusher which in turn discharges to a centrifugal materials handling pump or a hydraulic ejector utilizing high pressure water as the motive force and ash conveying medium. 10.1. Pressurized conveyors can be used to convey fly ash several thousand feet. 10. 10. ash is discharged into trucks. Discharge gates shall be air-cylinder operated with intermediate positioning capability.2 Hydraulic. Sizing of the bottom ash hopper volume should also consider that the bottom ash will contain unburned coal in the amount of 5 to 12 percent of the bottom ash.1. and then opened to the conveyor pipe allowing the fly ash to discharge into the conveyor pipe air stream. the feeder is closed to the ash hopper. A combination of vacuum and pressure conveying of fly ash should be considered where conveying distances rule out the use of vacuum alone. Ash is dumped from the separators into the storage silo through air lock type automatic gates. or 12 hours of storage based on the maximum expected amount of ash to be produced for any 12-hour period. The bulk densities of bottom ash as given above under stoker coal firing may be used also for pulverized coal firing.2 Pulverized Coal Firing. there have been only a limited number of successful installations of dense phase systems in the United States. When full. dry. 10. or to dewatering bins. 10. preferably 12 hours of storage at the maximum bottom ash production rate.3 Dense Phase.3 Vacuum-Pressure System. Hydraulic ash removal systems.1. are used only for utility type boilers and will not be considered for most Navy installations. Design structural loads shall be based on 70 pounds per cubic foot. Careful investigation should be made before considering the use of a dense phase system. Coarse or damp material cannot be conveyed by this method. Air from the secondary separator is passed through a bag filter for residual ash removal prior to the air being admitted to the vacuum producing exhausters. 10. Compressed air for conveying fly ash is produced by motor driven positive displacement rotary blowers. The air-entrained fly ash is then conveyed by the pipeline and discharged into the storage silo. The bottom ash hopper should be sized to provide not less than 8 hours. The ash is conveyed in a slurry (approximately 20 percent ash by weight) to a disposal area or pond. fluidizable material such as fly ash. use 45 lb/ft3 for eastern bituminous coal and 35 lbs/ft3 for western sub-bituminous coal.3 Clinker Crushers 131 . The feeder is closed to the conveyor pipe and opened to the ash hopper during the feeder loading cycle. The feeder discharge is attached to the conveyer pipeline. 10. rail cars or barges for final disposal.1. pressurized with compressed air. The dense phase system requires fine.1. the hopper volume should be sized to provide 8 hours of storage at the maximum production rate. After the water is drained from one of the dewatering bins.
motor driven clinker crushers shall be installed below the hopper outlets and above the pneumatic ash intakes. Motor driven rotary dustless unloaders (conditioners) shall be used to unload the silo into trucks or railroad cars. 132 . In order to avoid clinker crusher plugging problems.4 Ash Storage. 10. On bottom ash handling systems. For pulverized coal firing.1 Stoker Coal Firing. see MIL-HDBK-1003/6. 10.MIL-HDBK-1003/7 10. Silos are used for storage of pneumatically conveyed bottom ash and fly ash. For additional requirements.3. each bottom ash hopper discharge gate is provided with a clinker crusher.3. pulverizer pyrites rejects should be discharged to a separate holding tank and not to the bottom ash hopper. Minimum silo storage capacity should be 72 hours based on maximum ash production rate.2 Pulverized Coal Firing. The use of silos facilitates the disposal of ash by truck or rail cars.
There are basically three types of industrial instrumentation systems for power plant control: analog. electromagnetic field (EMF).4 Pneumatic Control Systems. Consideration should be given to the ability to readily interface to or add to a utilities energy management system or other computer networks.5 Types of Control Systems Available. a) b) c) d) On-off controls.2 Microprocessor-Based Control Stations.1. 11. or a computer can be used as a supervisory control for analog control system.1. 133 . DDC control can perform all of the control functions. Parallel positioning system. b) Electronic . CONTROL AND INSTRUMENTATION 11. or a split-architecture control system offering powerful. EMF etc. or as a data logger with graphic displays. 11. 11. These units can accept standard analog electronic inputs plus digital inputs and give analog outputs plus digital outputs. Single point positioning system.1 Types of Controls and Control Systems. Parallel metering system.1. configurable control capability on a modular basis.1.1. Analog control is the representation of numerical quantities by means of physical variables such as current. reports and calculations for efficiency and controller tuning. other operator interfaces are easily added. These are a digital stand alone single controller type. as the power source to represent numerical values. By connection to a data highway for communication. operator displays and graphics. etc.1 Analog.the use of air pressure (or other gases occasionally) as the power source to represent numerical values. 11.the use of current. Pneumatic control systems should only be considered when adding to an existing power plant already equipped with pneumatic control instruments. Analog control over the last 30 years has consisted primarily of two types: a) Pneumatic . resistance.MIL-HDBK-1003/7 Section 11. rotation. air pressure. voltage.Direct Digital Control (DDC) or Supervisory Control (SC). and computer. Choice of analog versus microprocessor based control units or computer (DDC) (SC) should be based on relative cost and future requirements. 11. voltage. microprocessor. resistance.3 Computer . microprocessor based control units.
safe. See Table 23 for temperature sensing devices. For the metering type (proportioning plus reset plus rate action). and other contaminants than its electronic counterparts. pneumatic instrumentation will require more frequent calibration checks because of its inherent mechanical linkage design versus solid state electronic units. Oil. c) Refer to the ASME Boiler and Pressure Vessel Code Section VII subsection C6 for minimum basic instruments required for proper.1 Combustion Control.2. 11. Oil.2. Feedwater control shall be as listed in MIL- 134 . Section 6 and Table 13.1. Also. 11. and MIL-B-18797. d) e) Refer to Tables 13 and 15 in MIL-HDBK-1003/6.6 Maintenance and Calibration.2 Steam Power Plant Controls. Single. Steam temperature control shall be as listed in MIL-HDBK-1003/6. Section 6. Combustion control comprises a series of devices on a boiler developed to satisfy steam demands automatically and economically by controlling furnace combustion rates through adjustments of the burning components while maintaining a constant set point (such as a fixed but adjustable pressure or temperature) and an optimum (adjustable) ratio of fuel to air. oil. Table 13. CO trim w/coal. Burner. Mechanical-Draft. See Military Specification MIL-B-18796. Gas. especially for coal firing. f) Steam flow/air flow metering system. Maintenance and calibration is a necessity regardless of the type of control equipment being used. moisture. An automatic fuel-trip device is required for steam temperature out of normal range. Section 6. 11. See Tables 22. CO trim should be considered for larger boiler installations as an adjunct to oxygen trim for increased efficiency. Automatic. Critical temperatures should be recorded and also alarmed. efficient operation. 11. Boilers should have oxygen trim in order to optimize fuel usage. and 24 for typical lists of instruments.2 Steam Temperature Control.2. Pneumatic instrumentation will require more maintenance because of its usage of air that contains dirt. And Gas/Oil Combination. Steam power plant controls are shown in MIL-HDBK- 11. b) Combustion safeguard.3 Feedwater Control. Burners.MIL-HDBK-1003/7 e) Parallel metering system with oxygen trim. a) see Figure 37. 1003/6. 23.
* * Sensing Element Location of Sensing * Element Indicator Recorder Totalizer * * * Steam boiler drum A * * Pressure * Superheated steam outlet A * Main steam header A * * * Feedwater header A * * Fuel oil header A * * Gas fuel header A * * Steam at Turbine * (extraction or condensing) A C * * * Steam at turbine first * * stage A * Steam at turbine No. 1 * * * extraction A * * Steam at turbine No.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 136 . 2 * * extraction A * Steam at turbine No. * * * or I.D. 3 * * * extraction A * * Steam at turbine exhaust A * * Instrument air A * * House service air A * House service water A * * * Auxiliary steam A * * * * Draft Forced draft fan discharge A * * Burner or stoker windbox A * Furnace draft A * * * Boiler gas outlet A * Air heater or economizer * * * gas outlet A * Dust collector outlet.MIL-HDBK-1003/7 TABLE 22 List of Instruments on Control Panels +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). fan inlet A * * Air heater air discharge A * Flyash return fan A * * * * * Temperature Superheated steam A * * Boiler outlet gas A * Air heater or economizer * * * outlet gas A B * * Air heater outlet air A A * * Economizer water outlet A B * * Feedwater header A * .
MIL-HDBK-1003/7 Table 22 List of Instruments on Control Panels (cont. turbine A * * * * Vacuum flow Absolute pressure at * * turbine exhaust A * * Steam A A * * Air A * Feedwater D * * * CO2 (alternate to * * air flow) E * Fuel Oil A * * * Gas fuel A A * * Coal weight A * * Steam to extraction * turbine A A * * * Extraction steam from * * extraction turbine A A * * * * Level Boiler drum A * Coal bunker . * * Sensing Element Location of Sensing * Element Indicator Recorder Totalizer * * * Steam to extraction * * Temperature * Cont.) +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). * * * Conductivity Condenser Hotwells A * * Sample coolers A * * * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 137 .pilot lights A * * * Fuel oil tank A * Deaerator storage section A * * * * * * A * * Flame safeguard Safeguard panel * * Combustion control A * * Control * instruments * * * * Hand Automatic Combustion control: * * selector Fuel control A * Forced draft damper A * * stations * with indicators Induced draft damper A * * for remote or Feedwater control A * * automatic * * * operation.
flow * * * differential and large flows nozzle. and Venturi * pressure totalizing nozzle meters.) +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). * * Sensing Element Location of Sensing * Element Indicator Recorder Totalizer * * * Annunciator A * * Alarms * * Stack Percent A * * O2 * * * CO Stack Percent (coal) A * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- A B C D E = = = = = necessary desirable necessary necessary alternate but not in some but not to some necessary instances but not in others necessarily on located panel other instrument Table 23 Sensing Elements for Controls and Instruments +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). * * * with constant V-slot * area * * * Variable Combustion Control valves Air and gas flow * * differential * pressure * * * with constant * * area * * Constant Tapered Proportioning Rotameter * differential tube and small flows * * * pressure with float * * variable area * * * * * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 138 .MIL-HDBK-1003/7 Table 22 List of Instruments on Control Panels (cont. * Common Applications * * Element Type Control Instrument * * * * Flow Mechanical Batch Filling containers Weighing containers * Totalizing Totalizing positive * * * displacement water * * and gas meters * Variable Continuous Proportioning Orifice.
F * * Fluid Mercury Glass thermometer * * expansion or alcohol 38 to 750 deg. F* * alumel * * Platinum1300 to 3000 deg. liquid flow. * * steam flow * * * Bimetal On-off thermostats Dial thermometer * *Tempera. F* Platinum * * * rhodium * * * * * . F * * vapor liquid * Gas 400 to 1000 deg. * flow and control valves. Vortex flowmeter * * volumetric continuous proportional flow. F* * * Gas expansion Nitrogen gas Temperature Recorders. F * liquid * * * Organic 40 to 600 deg.) +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). and * regulators transmitters * * * 350 to 1400 deg.MIL-HDBK-1003/7 Table 23 Sensing Elements for Controls and Instruments (cont. F * Thermocouples CopperTemperature Low voltage * * * constantan regulators 300 to 600 deg.Solid *ture expansion 100 to 1000 deg. F * * Mercury in Temperature Dial thermometer * coil regulators 38 to 1000 deg. Filling containers. 16 to 1 turndown. Common Applications * * * Element Type Control Instrument * * * Variable Pitot tube Airflow Airflow * * * differential Velocity * with variable Electric Potentiometer * * * velocity resistance * * anemometer of hot wire * * affected by * * Velocity of * flow * * * Vortex-linear Batch. F * * * Organic 125 to 500 deg. F * constantan * * * Chromel600 to 2100 deg.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 139 . air * * * totalizing flow. F * * Iron0 to 1400 deg.
1" H2O * * to 1.Elec resistance Copper * ature of metals regulators 40 to 250 deg. F * * * thermoregulation * * couples * Fusion Pyrometric Cones * * * 1600 to 3600 deg. F * * pyrometer rad energy * * Radiation Radiant Flame safeguard Potentiometer * pyrometer energy on Surf. 200 to 7000 deg. F * Nickel 300 to 600 deg.i.000 p. Common Applications * * * Element Type Control Instrument * * * Temperature Potentiometer * * Temper.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 140 . F * Bourdon Pressure.) +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).200 psig * * * * Level Visual Gauge stick. temp.1" H2O * * * to 1. F * * Optical Comparative 850 to 5200 deg. * * vacuum * Variable CapaciPressure Indicators and * * * capacitance tance regulators recorders .1 micron Hg.50. F * * Crayons * * 100 to 800 deg. * resistance due * * * to strain * * Variable ThermoVacuum regulator High vacuum * electric couple 1-700 microns Hg.200 psig * * Variable Frequency Pressure Indicators and * frequency transducer regulators recorders . * * Transparent tube * . F * * * Platinum 300 to 1800 deg.s.MIL-HDBK-1003/7 Table 23 Sensing Elements for Controls and Instruments (cont. draft Pressure gauge * * Pressure Mechanical * tube and vacuum * * Bellows or vacuum regulators Low pressure. * * * resistance due * to vacuum * * * Variable Vacuum Vacuum regulator High vacuum * electronic tube down to * * * resistance to 0. * * Manometers Barometer * Variable Pressure Process pressure Potentiometer: * * * electric transducer regulator 100 . draft * * diaphragm and vacuum gauges.
* * * * Electric PhotoFlame safeguard Photo-electric cell * * and conductivity Smoke density * * electro.Elec Probes Alarm pH of water * conductivity Oil in condensate * * nic .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 141 .Pneumatic level Torque * * * ment regulator * * Differential Manometer Level regulator Remove level gauge * * pressure * * Hydrostatic Diaphragm Level regulator Tank levels with * in tank viscous fluids * * * bottom * * Motion Centrifugal Speed governs Tachometer * Vibrating read Tachometer * * * Relative motion Stroboscope * * Photo-electric Limit control Counter * * cell * * * * Chemical Flue gas analysis Combustion control Orsat * * Water analysis Water Treatment Water constituents * * Fuel analysis Ultimate analysis * * of fuels * * * * Physical Specific gravity Hydrometer for * liquids * * * Weight Scales for * * solids * Humidity Hygrometer * * * Smoke density Ringelman chart * Gas density Combustion CO2 meter * * * Heat Combination Combustion Btu meter * of water * * * flow and * * temp. diff. Common Applications * * * Element Type Control Instrument * * * Float Buoyant Mechanical level Tape connected to * * Level * float regulator float * Displace.) +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).MIL-HDBK-1003/7 Table 23 Sensing Elements for Controls and Instruments (cont.
))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- A = necessary 142 .MIL-HDBK-1003/7 Table 24 Locally Mounted Instrumentation +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). * Sensing * Location of Sensing Element Indicator Recorder Totalizer* * Element * * * Pressure Boiler drum A * Boiler outlet steam A * * gauges * Turbine steam inlet A * Extraction steam outlets A * * * Feedwater heater steam inlet A * * Deaerator steam inlet A * * Condenser hotwell A * * Condenser pumps discharge A * Boiler feed pumps suction A * * * Boiler feed pumps discharge A * * Deaerator condensate inlet A * Feedwater heater condensate inlets A * * * Feedwater heater condensate outlet A * * Cooling water pump discharge A * * Condenser cooling water inlet A * Condenser cooling water outlet A * * * Pressure reducing valves-low * * pressure side A * * Air compressor discharge A * * Compressed air receiver A * A * * Thermometers Boiler steam outlet * Turbine steam inlet A * Feedwater heater steam inlets A * * * Turbine Exhaust A * * Condenser condensate outlet A * Deaerator condensate outlet A * * * Feedwater heater condensate inlets A * Feedwater heater condensate outlet A * * * Boiler flue gas outlet A * Economizer feedwater inlet A * * * Economizer feedwater outlet A * * Condenser cooling water inlet A * Condenser cooling water outlet A * * * Cooling tower basin water A * * Level Boiler drum A * * Deaerator A * Condenser hotwell A * * * Condensate Storage/return tank A * * Fuel oil tanks A * .
and alarms should be installed as recommended by the equipment manufacturer. Inc. A standard EHC system is comprised of four primary functions: a) b) c) d) Speed control Load control Flow control Trip 11.MIL-HDBK-1003/7 HDBK-1003/6 Section 6. Implosion concerns have resulted in many new control-system developments. Protection against boiler implosions is not so well understood. which gives improvement in control reliability and accuracy which is manifested in improved turbine performance. see also Combustion Engineering. Each steam generator manufacturer has recommendations and the National Fire Protection Association has issued NFPA 85-G on the subject. 1981. and gas fired boilers can have different shutdown safety trips.2. See Table 14 in MIL-HDBK-1003/6 Section 6 for selection factors and reasons for use. Criteria for protection against boiler explosions have been well established.4 Steam Turbine Generator Control. Automatic startup and shutdown is easily done with microprocessor based control equipment. For a detailed discussion of boiler implosions. Boiler implosions are caused by one of two basic mechanisms: (1) The induced draft fan of a balanced draft boiler is capable of providing more suction head than the boiler structure is capable of withstanding and (2) the socalled flame collapse or flameout effect. With the rapid advancement of electronics. Safety devices such as boiler shutdown devices. Table 13. Safety controls for boilers are needed for protection against explosions and implosions. Coal. Many are still in use but they are for the most part not a currently manufactured unit.3 Safety Devices and Interlocks. 11. See Figure 38 for a typical EHC system. The EHC system is more versatile and faster responding. For a boiler. an electrohydraulic control (EHC) system is desirable over an all mechanical system. 144 . oil. implosion would be the result of a negative pressure excursion of sufficient magnitude to cause structural damage. For small packaged boilers and boilers with constant loads a single or two element feedwater control system will suffice. Check boiler manufacturer's recommendations and ASME Boiler and Pressure Vessels Code Section VII for standard trip conditions. Larger boilers and boilers with widely fluctuating loads should use a three element type. An automatic fuel trip device is required for low drum water level. Steam turbine controls should be supplied by the turbine manufacturer. startup and shutdown interlocks. The Mechanical Hydraulic Control System (MHC) has not been used since the late 1970's.
condenser hotwell water level. Refer to MIL-HDBK-1003/6 for required pressure measurements and instrument selector factors. A typical temperature control loop is shown in Figure 39b.5 Flow meters. Accuracy is normally 0. The new meters such as vortex.3 Level. Flow meters. and Doppler have added improved accuracy. for applications see Table 23. 11.4. and deaerator storage tank water level. auxiliary steam pressure. and fuel oil pressure. Local-mounted gauges give a "backup" reading and also help operators in determining if equipment or pressure systems are working satisfactorily.2 Temperature. the controller.MIL-HDBK-1003/7 11. accuracy 2-3 percent and rangeability of 4:1 maximum. 11. 11. and for a listing of required flow measurements for steam power plants.4. or liquid level type. 11. feedwater heater drain cooler water level. Liquid level control loops may be used for control of boiler drum water level. With the improvements in electronic transmitters over the past decade there has been an improvement in their overall specifications.5 percent gauges. have remained unchanged over the past decade. building heating steam pressure. 11. temperature.4. A typical liquid level control loop is shown in Figure 39c.5 to 1 percent of span. A typical pressure control loop is shown in Figure 39a. ultrasonic.1 Pressure. For test and calibration purposes use 0. particularly differential pressure type. the differential pressure type flow meters have remained the same. There have been several new types of flow meters added to the flow measurement arena. deaerator pressure. 145 . For control of boiler pressure the final control element regulates fuel flow to the boiler in response to boiler drum steam pressure. refer to MIL-HDBK-1003/6. Temperature control loops may be used for control of steam temperature from boilers or desuperheaters and fuel oil temperature from fuel oil heaters. and final control element including positioner.4 Control Loops. controlled variable transmitter. However. and rangeability as high as 16:1. A single control loop includes a controlled variable sensor. Size and ranges are specified by user. Pressure gauges are usually direct-connected and fieldmounted. Cost of electronic transmitters are now lower than pneumatic counterparts and should be used except for all pneumatic systems. linear signals. automatic-manual control station. if any. For other pressure applications the final control element is usually a pressure reducing control valve which regulates in response to downstream pressure.6 Pressure Gauges. For types of flow meters see Table 25. Pressure control loops may be used for control of boiler pressure.25 to 0. Control loops used for power plants are usually of the pressure.
02 C).MIL-HDBK-1003/7 11. Thermocouples are non-linear. Where transmission line length (pneumatic) poses a problem in a flow loop. Copper is quite linear but nickel is quite nonlinear. thermocouples. 11. since it operates on the measured change in the resistance of a metal or semiconductor (thermistor) with temperature. Transmitters are primarily used to transmit an analog output (pneumatic or electronic) proportional to its measured signal. 11. Materials of construction is of prime importance when selecting a transmitter. Sensing line lengths longer than 50 feet are not usually recommended and should be used only when absolutely necessary. Thermocouples can be used with pneumatic and electronic transmitters or they can be direct connected to some instruments. The American Petroleum Institute Recommended Practice 550 suggests for general service applications that the pneumatic tubing length from transmitter to controller to control valve not exceed 400 feet.03 degrees F (0. use a volume booster.3 Resistance Temperature Detector. Standard output signal for pneumatic transmitter is 3-15 psi with a 20 psi air supply and 4-20 mA DC for electronic transmitters with a nominal 30 VDC power supply. The basic types of temperature sensors are thermometers. Resistance detectors can be used with pneumatic and electronic transmitters or can also be direct-connected to some instruments. Recent electronic enhancements have made most electronic transmitters much more accurate. and less expensive than its pneumatic counterpart. because of its inherent stability and linearity is becoming the standard of the industry with some copper and nickel still being used.7. or mount the controller near the valve. There are options for other output signals depending upon the manufacture. 11.7. Electronic signals are easier to adapt to microprocessor and computer based systems and should therefore be given prime consideration over pneumatics.8 Transmitters. reliable. 147 . Platinum. weight. See Table 23 for ranges and use.2 Thermocouples. Neither run should exceed 250 feet. Most transmitters are field-mounted near point of measurement. Many options are available and should be selected on the basis of need or life expectancy and cost. The resistance detector does not have a reference junction. and resistance temperature detectors. 11. as a thermocouple.7 Temperature Sensors. Most electronic transmitters are the two wire type.7. Resistance temperature detectors offer a temperature range about the same as a copper-constantan thermocouple with detection of temperature changes of 0. Thermometers are located on equipment and piping to provide local temperature indication. Thermocouples provide a reliable and accurate temperature measurement for most remote temperature sensing applications. and smaller in size.1 Thermometers.
feed forward schemes respond directly to upsets and. 11.9 Recorders. Trend recording also allows for recording of critical points during startup. See Figure 40a. 250. and is compared to a reference or set point. b) Equipment manufacturer recommendations.10 Controllers. (roll. circular) and number of recording points. Open loop control simply does not have a measurement sensor to provide an input to the controller for a comparison. e) Operator requirements. Trend recording is becoming more popular since it allows the selection of a large number of inputs to be recorded and for time periods as desired by the operator. see NEMA. Most field-mounted recorders are the 12-inch circular large case type because they usually meet NEMA Type 3 or better protection. when it can no longer be changed by its input signal. 60 cycle. d) Safety requirements. The selection of types should be based on suitability to needs and. Recorders are primarily used to record data to provide a permanent record of present and past conditions. some can be supplied with a pneumatic impulse or mechanical chart drives. or failure of the final operator. Most panel-mounted recorders are the 4-inch strip chart type because of space requirements. the number of points being recorded. Selection of recording signals should be based on the following: a) Federal and state requirements. See Table 22 for selection of signals to be recorded. Recorders are normally supplied with 115 V. See Figure 40b. There are also several types of control units available such as: a) Ratio control. Controllers can be used in either closed loop (feedback) or open loop control configurations. or 24 VDC for the chart drives. If a difference or offset exists between the measured variable and set point. While feedback control is reactive in nature and responds to the effect of an upset which causes an offset between the measured variable and set point of the controller. Recorders are available in different sizes. offer improved control. shapes. 149 . Enclosures for Electrical Equipment (1000 volts Maximum). In a closed loop control configuration. c) Accounting purposes.MIL-HDBK-1003/7 11. Open loop control can also occur when an automatic controller is placed in its manual position. Standard Publication/No. Feed-forward control is relatively new and in most cases it is also used in closed loop control configurations. in particular. See Figure 40c. fold. saturation of the controller output at zero or 100 percent of scale. the automatic controller will change its output in the direction necessary for corrective action to take place. a measurement is made of the variable to be controlled. thus.
With the new microprocessor-based control stations they can perform most of the types of control listed above without additional devices and still provide 18 or so control algorithms. The new microprocessor-based controllers should be given first consideration as they are less expensive. and can perform many more functions than a standard analog controller without additional pieces of equipment. the controller must be properly tuned. Auto-selector control. 11. state of the art. Each controller must be tuned for its control loop--seldom are two alike. Operators are used to drive (move) final control elements such as control valves and dampers from one position to another. The general types of operators are pneumatic diaphragm or piston. This is a major addition for exact tuning of the control parameters to match the process dynamics. electric. and air conditioning systems.1 Pneumatic Operators. This can be time consuming. Electric operators are used prevalently in heating. 11. For standard controller action see Figure 41.MIL-HDBK-1003/7 b) c) d) Cascade control. These units can be analog type and either electronic or pneumatic. Some new microprocessor controllers have "Self Tuning" capability. and electro-hydraulic.11 Operators.11. ventilating. Operators (final control elements) for major control loops should be pneumatic unless normally furnished otherwise on equipment as standard by a manufacturer. These new units should also be considered for retrofit work as they can easily replace old electronic and pneumatic analog controllers and other devices. 150 . however. For a controller to operate correctly. Some of the new microprocessorbased controllers are configured from push buttons located on the controller face plate.2 Electric Operators. but it is necessary to have correct controller response to process changes. additional pieces of instrumentation may be required to actually do the above types of control. 11. Pneumatic operators including I/P converters are the least expensive when compared to electric or electric-hydraulic types.11. Special calibrators or mini-computers are not required to configure these stand alone controllers. Nonlinear control.
Adequate light.3 Electro-Hydraulic Operators. a positioner will be helpful but not essential. See Tables 22 and 23 for typical lists of analog instruments. A positioner should be used for liquid level. use a positioner on control systems that have a relatively slow response such as liquid level. to compensate for long pneumatic transmission lines. 11.11. Clean dry atmosphere. volume (as in blending). Positioners are used primarily to overcome valve stem friction. the operator 153 . The control room should be located in the boiler turbine area where visual inspection can still be made.12 Positioners. As a general rule. dry air of adequate pressure and capacity (for pneumatic g) Air conditioning (a necessity for electronic distributive control systems and computers).13 Control Room. For temperature control. No vibration. Electro-hydraulic operators are used for high force or torque applications and in remote locations where lack of compressed air supply rules out the use of pneumatic operators. Every control valve exhibits from 2 to 10 percent hysteresis unless it is equipped with a positioner. The effect of valve position hysteresis is indicated in Figure 42.MIL-HDBK-1003/7 11. A positive pressure should be maintained within the control room to keep dust and other dirt particles from entering. most flow. Do not use a positioner on control systems which have a relatively fast response such as liquid pressure. Clean. but completely enclosed and air conditioned with high efficiency filtration. and temperature control loops. With the new microprocessor-based control systems. The control room must have: a) b) c) d) e) f) instruments). or when extreme or variable line pressure can offset the valve plug. Relatively constant temperature and humidity. 11. free of surges in voltage and frequency. Positioners are used on control valves to force the stem and valve plug to move to a position as called for by the control signal. and weight (as in blending) whenever a two mode controller (proportional plus integral) is used. Reliable electric power. blending. and some pressure control loops. Instruments should be mounted on a panel within the control room.
MIL-HDBK-1003/7 interface can be a color or black and white cathode ray tube (CRT) monitor. The operator can control the boiler plant from a single CRT with redundant CRTs located elsewhere if desirable. All field measurements should come into one central control room. Field inputs and outputs should be done through the floor or ceiling of the control room. 155 . thus eliminating the need for panels.
Makeup water to a cooling tower cooling water system is required to replace losses from evaporation. 12. WATER SUPPLY. cooling tower system fill and makeup. of Concentrations -1) EQUATION: Makeup = Evaporation + Drift + Blowdown (13) (12) For additional information relative to cooling towers. 12.2 Cooling Tower Makeup. plus process or heating system steam and condensate losses. The blowdown rate will depend on the number of concentrations of total dissolved solids to be maintained in the cooling water. or consider the use of a pneumatic ground floor level pressurized system. Boiler-turbine cycle water makeup is a requirement and continuous demand when the boiler-turbine cycle is in operation. see MIL-HDBK-1003/6.7. The design of the makeup system should be based on a demand of 1. Consider the use of a raw water storage tank if necessary to back up any uncertainties in water supply or for fire fighting. and fire protection. Water treatment equipment will be required to provide cycle water fill and makeup of suitable quality.03 percent to a maximum of 0. and condensate losses in a process or facility heating system which is supplied with steam from the boiler-turbine cycle. AND TREATMENT 12. 12.2 percent of the cooling water flow rate. water treatment equipment backwash. For additional information.5 percent plus the makeup required for steam atomization of oil burners.MIL-HDBK-1003/7 Section 12.1 Cycle Makeup. see para 12. MIL-HDBK-1005/7. The final quality will depend on the 156 . For additional information see MIL-HDBK-1003/6. Provide in-plant overhead tank or outdoor elevated tank for pressurization of distribution system. The relationships of these variables are as follows: EQUATION: Drift + Blowdown = Evaporation / (No.5 percent of the main steam flow to the turbine to provide for condensate losses from the cycle. and blowdown. ash conditioning.2. domestic (potable) water.2. Normal operation of the power plant will usually require an actual condensate makeup rate to the cycle of about 0.2 Water Makeup 12. Drift loss from a mechanical draft tower will range from a minimum of 0. plant service water. plus steam usage for oil atomization and steam soot blowers. Raw water is required for supply to water treatment equipment for boiler-turbine cycle water fill and makeup.3 Water Treatment.1 Water Supply. drift. Water Supply Systems. MAKEUP. steam operated soot blowers.
gal/day (14) The demineralizer should be sized to produce the amount of water as determined by Equation 14 by operating the demineralizer 18 hours per day. The advantages of the wet/dry tower as compared to the wet tower are lower water consumption and reduced water vapor (plume) discharge. all depending on the quality of the raw water supply. lb/h Atomizing steam requirements. 12.1 Once-Through System.4 Cooling Water Systems 12. a condenser. cooling water pumps to provide for water static and dynamic head losses.2. The cooling tower combines a water to air heat exchanger section with an evaporative type cooling section.2. and a discharge or outfall structure located so that significant recirculation of warm water will not occur.4. and finally back to the cooling water pumps for recycling.2. it shall be sized as follows: EQUATION: Gallons/day = (0.015 x F x 24 x 60 + SA + SB + P) / 500 where: F SA SB P = = = = Maximum boiler steam flow. 12.4. mechanical draft) or basins.4. Water treatment of raw water may also be required in conjunction with cycle water makeup treatment and/or to provide potable water for domestic use. Cooling water is pumped through a closed circuit passing through the condenser where heat is absorbed. Where a demineralizer is used for cycle water makeup.2 Recirculating System This system utilizes cooling towers (natural or 12. then through a water-to-air heat exchanger.4. For additional information see MIL-HDBK-1003/6. 12.4. 157 .2 Non-evaporative Dry Cooling.MIL-HDBK-1003/7 operating pressure of the boiler. This system uses a combination of wet and dry systems as described above. gal/day Process or heating steam and condensate losses. 12. Once-through systems have an intake structure including screens. The sizing should also be such that it should not be necessary to regenerate the demineralizer more than once per day. gal/day Soot blower steam requirements.1 Evaporative Wet Cooling. leaving 6 hours per day for demineralizer regeneration.3 Combination Wet and Dry Cooling. conduits to carry the water.
4 Traveling Water Screen a) Use screen approach water velocities of 0. Inlet ports to the entry wells should be covered with trash racks as a rough screen for such items as logs.2 Arrangement. 12. whereas horizontal centrifugal pumps may be installed in a dry well below low water level. usually made of concrete.5. They should be designed to pass maximum velocities of 2 feet per second at extreme low water levels and arranged for manual raking from the outside. In the combination intake structure and pump chamber.1 Location. A determination of extreme low and high water levels of the water source must be made. after deducting for the screen frame and boot interference. 158 .5 feet per second at extreme low water level. The net screen area is one-half of the waterway area. sticks. Locate the intake structure as close to the water source as possible in order to limit the hydraulic losses to the pump suction and to eliminate the possibility of a sand silt buildup in the wells of the structure. c) One or two speed drives are available. shall contain stationary and mechanical traveling screens that are used to remove debris from the cooling water before entering the pumps. The pump chamber may be combined with the intake structure when the power plant is some distance away or they may be separated by flume or pipe when they are close by and the pumps are installed near the condensers.5. vertical centrifugal pumps are usually installed above a wet well.5.5 to 0. Manufacturers will guarantee a maximum 2 feet head loss under the above conditions. and ice. 12. Connect the structure with the power plant through suitable pipes or reinforced concrete flumes or tunnels. 12.MIL-HDBK-1003/7 12. 12. with a traveling water screen. Each set shall contain an entry well. the higher speed for intermittent operation when debris is light and the lower speed for continuous operation when the debris is heavy. with a trash rack in front and a sluice gate (or stop logs) at its outlet.5. a screen well.3 Trash Racks.5 Intake Structures. leaves. and a crossover well with sluice gates to permit closing off the screen well and directing the water flow from either set of wells to a selected pump flume or pump well. The intake structure. b) The maximum water velocity through the net screen area when passing the circulating pump capacity should not exceed 2.75 feet per second to avoid entrapment of fish. The intake structure shall be provided with access roads and power wiring. Provide at least two parallel sets of wells in the structure to permit alternate operation when one set is being cleaned.
12. Oversizing these pumps will result in wasted power and in premature wear from operating continuously at pumping heads less than the design point. where required. A fire pump. it may be necessary to back up the traveling screen with a fine stationary screen that can be lifted out for cleaning. Pump materials should be suitable for the water conditions. Trash cannot be pumped back into water. f) In the extreme case of large quantities of water plants and algae. Use vertical pumps for large differences in extreme high and low water levels and obtain manufacturers' recommendations on installation. Provide space for pump motor controllers. 12.MIL-HDBK-1003/7 d) Select screen size and material to suit water conditions. Provide a trash trench. may be installed in the crossover well of the intake structure.3 Backwash Pump. Note that the distance of the bell from the bottom of the well is critical. 12. provide a means of priming the pumps. and closed cooling water system. and backwash pump on top of the structure. use horizontally split centrifugal pumps in a dry well below extreme low water level to avoid the necessity of foot valves and priming. Where economically justified. Each condenser circulating pump should be sized to serve half of a condenser plus the water quantity required for turbine lubricating oil coolers.1 Vertical pumps. Design the suction chamber in accordance with Figures 43 through 46. traveling screen.5 Pumps.5. Where the intake structure and the circulating pump chamber are separated. backwash pump and dewatering bin for cleaning the screens. 159 .5.5. generator air coolers. as they are not as sensitive as vertical pumps to inlet flow conditions. but is disposed of either by incineration or in a landfill. because these pumps are very sensitive to poor distribution of flow at suction bell entrances.5. e) The flow area below the extreme low water level and the extreme high water level determines the height of the traveling screen. Where horizontal circulating pumps are located away from the intake structure but above the suction flume. The backwash pump for a traveling screen should be of the horizontally split centrifugal type and should take its suction from the circulating pump discharge.5. it will be necessary to install a vertical backwash pump in the traveling screen well after the screen and to lengthen the intake structure accordingly.2 Horizontal Pumps.5.5. 12.
5.2 Seal Wells. advantage may be taken of the siphon effect to reduce the total pumping head. The maximum practical differential elevation between the extreme low water level of the source and the top of the condenser water box is usually between 28 and 30 feet. the discharge end of the cooling water conduit must be maintained below water in order to provide and maintain a seal between the water in the conduit and the atmosphere. 12. as covered in MIL-HDBK-1004/10. Discharge of cooling water from the condenser is made through conduits terminating at an outfall structure (usually made of concrete) located at the shore of an ocean. 12. or river. Locate the end or ends of the discharge conduit down stream from or as far from the intake structure as feasible. Where economically justified.1 Location. Because of its location at the end of the discharge conduit. The actual value is limited by the vapor pressure of the cooling water corresponding to the actual maximum temperature of the cooling water at the point of maximum vacuum (resulting from the siphon). in order to reduce the possibility of recirculation of the warm discharge water.1 Chlorination. the outfall structure can also be used to provide the necessary seal for cooling water systems operating with a siphon. 12. basin. and include an inside crane.MIL-HDBK-1003/7 12. Provide chlorinator and storage for one ton chlorine containers for chlorination of the circulating water. or mobile boom hoist or cranes. Where the top of the condenser water box is above extreme low water level of the cooling water source. If.6.5.5. Provide all equipment necessary to protect exterior surfaces of the water screens. if needed to control sea life growth.7 Housing.2 Cathodic Protection.6.6. this limit should be 160 . The purpose of the outfall structure is to control the discharge of cooling water in such a manner to avoid bank or bottom erosion of the main body of water.6 Water Treatment 12. during operation. For outdoor installations. provide roof hatches over the screens and pumps to enable removal of the pumps. For unfavorable weather conditions. In order to start and maintain the siphon. pumps. 12. temporary rigging and hoist. and piping below the water from corrosion by cathodic protection. the screens and pumps must be raised by some other means of hoisting such as a traveling gantry crane. lake.6 Outfall Structures.6. consider bypassing some of the discharge water to the intake structure for controlling ice formations or sea life growth.5. house the equipment on top of the structure. Chlorine concentration should be closely controlled and monitored to avoid injury to fish and/or loss of fish life. 12.
For a detailed description of construction and theory of operation of cooling towers. through drift eliminators. Water flows through the coils while air is drawn across the outside of the finned tubes.1. 165 . see American Society of Heating.1. Refrigerating. Where the maximum allowable siphon is exceeded because of difference in elevation between the water level of the source and top of the condenser water box. and out through the fans and fan cylinders.1 Induced Draft Wet Type.2 Natural Draft Towers. air circulation system. Cooling towers consist of a structure.3 Induced Draft Dry Type. Natural draft cooling towers are generally economical for use only with very large scale power generating plants.8 Cooling Water System Chemical Treatment 12. through the falling water and fill.7.7. the cooling water at this point will partially flash into vapor (steam) and the siphon will collapse. Atmospheric air is drawn in through louvers or grating. HE Equipment Volume. 12. a seal well with an adjustable discharge weir must be provided at the end of the discharge conduit to limit the siphon head. 12. This type utilizes propeller fans with exhaust velocity recovery fan cylinders. some type of fill to break the warm water into droplets.7. The warm water to the tower usually flows first through the heat exchanger and then is distributed over the fill of the wet section. 12. 12.7.1 Chemical Analysis.1.7 Cooling Towers. and Air Conditioning Engineers. 12. warm water distribution system. The chemical analysis.8. and the physical analysis of the raw water should be examined to determine what treatments are necessary. This combines induced draft fans and finned tube heat exchanger surface. The addition of the heat exchanger reduces water consumption and water vapor discharge. the source. and basin for collection of cooled water. which can be afforded by the maximum practical siphon.7. Atmospheric air is drawn in through the heat exchangers in parallel with air through the wet section. The adjustable weir is made up of stop logs that are installed by the operators as necessary to obtain the maximum possible head recovery. This type combines a wet type as described above with a finned tube heat exchanger. which are mounted at the top of the cooling tower at the fan deck. 12.MIL-HDBK-1003/7 exceeded as a result of higher vacuum or higher water temperature.1 Mechanical Draft Towers 12. ASHRAE Handbook.2 Induced Draft Wet/Dry Type. Typical fan size for power plant use would be 28-foot diameter and powered with a 200 hp motor (single or two-speed) through a right angle gear reducer.
Corrosion inhibitors. * * Velocity limit. For collateral reading on the problem. * Removal of abrasives. algaecides. Polyphosphates. * * * * Chlorination. Chemical algaecides. * * and slimicides. See Table 26 for a general guide to avoiding circulating water troubles. * * pH control. Manual cleaning. * * Corrosion inhibitors. * Manual cleaning. rivers. Velocity limit. * * * Softening. and National Association of Corrosion Engineers (NACE). * Water Problem Treatment for Systems * * * * Once-through Open recirculating * * * * Scale Polyphosphates Continuous blowdown. Removal of abrasives. * * Coatings.8. * * Manual cleaning. Table 26 Cooling Water Treatments +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 1.2 Selection Factors. materials. Cooling Water Treatment Manual. etc. * * * None pH control * * Delignation of * wood * * * * Fungus rot None Pretreatment of wood * . * * * * * Erosion Erosion resistant Erosion resistant * * materials. Systems Volume. lakes. pH control. Coatings.1 Velocity. * * Slime and * algae Chemicals. Biodegradable materials should be used to avoid environmental damage to streams. see ASHRAE Handbook. 166 . * pH control. * * * Corrosion resistant Corrosion resistant * * Corrosion * materials. Corrosion and Water Treatment. Continuous blowdown. materials.MIL-HDBK-1003/7 12. pH control.
such as leakage-loss of tank contents. The investment cost plus operating and maintenance costs of a program should be less than the sum of the following: a) structures. including indirect losses. 13. or chemical attack. Corrosion preventive measures are necessary where deterioration of structures. see MIL-HDBK-1003/6.3 Corrosion Controls. Military facilities must be maintained in a state of readiness at all times.1.2 Causes. and hazards. with the importance and mission determining the degree of necessity for corrosion protection.1 Justification. power failures. For additional detailed information. c) Increased costs for over design to allow for strength losses resulting from corrosion. or plastic coatings. and other items. necessity. labor losses. A corrosion protection program against severe corrosion conditions must be justified on the basis of economy.3 Hazards in Handling Materials.1. For power plants. 13.2 Operational Necessity. b) Direct maintenance costs attributed to corrosion.1 Economy. corrosion is caused primarily by oxidation. d) Costs of shutdown. CORROSION PROTECTION 13. 13. Corrosion exists in every metallic substance to some degree and in many cases to a severe degree. and cathodic protection systems. The control of corrosion involves the selection of appropriate materials.MIL-HDBK-1003/7 Section 13. see MIL-HDBK-1004/10.1. use of metallic. galvanic action. For description and design of cathodic protection systems. 13. organic. and containers and piping serving fluids or gases may cause danger of fire and explosion. Direct loss or damage costs resulting from corrosion of metal 13. 167 . inorganic. For more detailed information see MIL-HDBK-1003/6.
11 . color code and markings. Title 29.1. should be the latest most stringent standards and practices followed by industrial organizations. including those not covered by OSHA standards.Derricks. Stairs shall be constructed with abrasive treads or nosings and. 14. 14.MIL-HDBK-1003/7 Section 14. 14. Safety requirements. Special attention shall be given to platforms.2 . and Toe Boards. and the boiler plant. railings. Provide access platforms for operation and maintenance of all equipment and valves more than 8 feet 0 inches above the floor level.1.Safety Requirements for Floor and Wall Openings. means of egress. 168 .1. Not less than two exits shall be provided from catwalks.3 . Part 1910 . Department of Labor.3 Egress. ANSI/ASME B20.1. Railings. occupational noise exposure. belt sheaves. ANSI B30. closed risers. platforms longer than 10 to 15 feet in length.Occupational Safety and Health Standards.Conveyors and Related Equipment. ANSI/ASME B15.1 . fire protection. Guards shall be provided to cover all exposed rotating shafts. All federal installations must comply with the Code of Federal Regulations. 14.1 Personnel SAFETY PROTECTION 14.1. safety relief valves.Fixed Ladders. ANSI/ASME B30.1 . Occupational Safety and Health Administration.Mechanical Power Transmission Apparatus. landings shall be provided when stair run is in excess of l2 feet 0 inches. Handrails and toe guards shall be provided on platforms and floor openings. National Industrial Safety Codes.Monorails and Underhung Cranes.2 b) c) d) e) f) g) ANSI A14. Emergency lighting shall be provided for all modes of egress. boiler aisles.1. and control valves. preferably. couplings.Overhead and Gantry Cranes.6 . Safety cages and guards shall be provided for conveyor belt takeups. floor levels. 14.1 Equipment Guards. and driven belts.1. The following codes shall apply: a) ANSI A12 . flywheels.2 Platforms and Stairs. safety signs. ANSI/ASME B30. Stairs shall be provided where possible in lieu of ladders.1. Safety Requirements.1 OSHA Standards. Chapter XVII.
and hearing conservation including protection requirements. n) ANSI/NFPA 37 .. dBA slow * * Hours response * * * * 8 84 * * 6 85 * * 4 88 * * 3 91 * * 2 96 * * 1-1/2 101 * * 1 112 * . 14.23B. the mixed 169 .1. Emergency. NAVFAC P-309 . rather than the individual effect of each. 14. Navy Occupational Safety & Health Program.1 . then.Installation and Operation of Pulverized Fuel Systems.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- When the daily noise exposure is composed of two or more periods of noise exposure of different levels. l) ANSI Z358.3 Hearing Conservation.3. m) ANSI/NFPA 31 .3 . * Sound level Duration per day.National Electrical Code.Overhead Hoists (Underhung). their combined effect should be considered. k) ANSI Z83. o) ANSI/NFPA 70 . ANSI C2 .Color for Naval Shore Facilities.MIL-HDBK-1003/7 h) i) j) ANSI B30.Eyewash and Shower Equipment.1 Permissible Noise Exposure.16 .Combustion Engines and Gas Turbines.National Electrical Safety Code.Installation of Oil Burner Equipment.1. In accordance with NAVOSH Standards. p) ANSI/NFPA 85F .Gas Utilization Equipment in Large Boilers. If the sum of the following fractions: C1/T1+C2/T2+.Cn/Tn exceeds unity. protection against the effects of noise exposure shall be provided when sound levels exceed those shown in Table 27.. are presented in Chapter 18 of OPNAVINST 5100. Table 27 Permissible Noise Exposures +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))). NAVOSH Standards for noise exposure.
Volatile toxic chemicals will require special ventilation and adequate personnel protective clothing. and laboratories. see the American Society of Heating. see MIL-HDBK-1003/17 Industrial Ventilation Systems. OSHA standards for hazard communications are presented in Title 29. The acoustical design goals for these areas is the achievement of background sound levels which will not interfere with the occupancy requirements. 14. 170 .4. instructions.1.1.4. CFR Part 1910.. Subpart Z. For design guidance of local exhaust systems for mixing tanks. Refrigerating.6 Gaseous Chemicals. hydrazine. Subpart H .4 Dry Chemicals. morpholine. Cn indicates the total time of exposure at a specified noise level.1200. paragraph 1910. Power plant areas which require air conditioning usually require consideration of sound level also.4.4. See 29 CFR 1910. 14. Equipment which cannot meet this specification shall be provided with appropriate silencers or enclosed as necessary to contain or direct the emanating sound. refer to ACGIH Industrial Ventilation Manual. Exposure to impulsive or impact noise should not exceed 140 dB peak sound pressure level. For complete information relative to design.1. see MIL-HDBK-1032/2.1. Covered Storage. For design criteria.1.4. and Tn indicates the total time of exposure permitted at that level.1. 14.3. etc. and ACGIH Industrial Ventilation Manual.4. etc.1 Hazard Communication Standard. and Air Conditioning Engineers (ASHRAE) Handbooks.4 Handling of Toxic and Hazardous Substances 14. These areas include central control rooms.2 Equipment Design Sound Levels.Toxic and Hazardous Substances.0002 microbar) when measured 5 feet above the mounting floor level and 3 feet from the equipment base.5 Liquid Chemicals. and testing of sound.1.1. test bench hoods.3 Storage.MIL-HDBK-1003/7 exposure should be considered to exceed the limit value. local feed systems. 14. Fundamentals and Systems Volumes. offices. 14. 14.2 Local Exhaust.Hazardous Materials and Subpart Z .3 Space Design Sound Levels. For design criteria pertaining to storing of all types of toxic and hazardous substances. control. included in this category are chemicals such as acids.1. All equipment which produces noise as a side effect of operation shall be specified for noise level not in excess of 84 dBA (A scale rated sound pressure level referenced to 0. Provide storage per manufacturer's recommendations or 14. 14.3. Provide curbed area around liquid storage or mixing tanks and chemical feed equipment.
and NAVAIR 51-50AAA2. See also Federal Aviation Administration advisory circular AC 70/7460-1F.MIL-HDBK-1003/7 14. 14. Specification for Obstruction Lighting Equipment. for security 171 . and laboratory equipment. Provide safety relief valves on piping in accordance with ANSI/ASME B31.2. To protect both equipment and personnel.1.12. 14.2 Boilers and Pressure Vessels. heat exchangers. Security. Provide safety relief valves on boilers. presents an obstruction to air navigation. Part 77. Power Piping (ASME Code for Pressure Piping). 14. receivers.1. MIL-HDBK-1023/1.Fencing. Airfield Lighting.2 Piping and Equipment 14.4 fencing. Obstruction Marking and Lighting.1.3 Air Navigation. within any work area in which personnel eyes or body may be accidentally exposed to injurious corrosive materials. provide enclosures for batteries. and other pressure vessels in accordance with the ASME Boiler and Pressure Vessel Code. such as the stack. and Guard Towers.3 Air Compressors and Positive Displacement Pumps.4.7 Emergency Shower and Eye Wash Fountain. To determine if any part of the power plant. 14. Battery rooms shall be provided with forced ventilation exhaust type fans.2. refer to Title 14 Code of Federal Regulations. meeting ANSI Z358. General Requirements for Shorebased Airfield Marking and Lighting. See NAVFAC DM-5. FAA 150/5345-43c. Gates.1 Piping. 14. Provide an emergency shower and eye wash fountain.2.2. 14.4 Equipment Enclosures. Provide safety valves as necessary to protect air compressors and positive displacement pumps in the event a discharge valve is closed with the equipment in operation. machine shop.
1 General Requirements. 15. 15. Whether or not an area or piece of equipment requires the installation of fire protection equipment depends on the initial costs of buildings and equipment being considered and the relative cost of the fire protection system. see NFPA 30. For fire protection of coal facilities. Standpipe and fire hose stations shall be strategically located at various levels of the power plant and at various locations on each floor. The criticality of an area or piece of equipment to the mission of the power plant must also be considered. The designer shall be governed by the above Navy criteria. dry pilot. Fire Protection for Facilities Engineering. Installation of. shall be protected by automatic.7 Typical Fire Protection Systems for Power Plants. See MIL-HDBK-1190 and MIL-HDBK-1008. All questions concerning fire protection should be directed to the fire protection branch.3 Transformers. Table 28 lists the various areas or pieces of power plant equipment that should be considered relative to the need for fire protection.5 Standpipe and Fire Hose Stations. Table 28 also lists the recommended type of fire suppression system. Oil Burning Equipment. FIRE PROTECTION 15. 172 . 15. applicable Factory Mutual Engineering Loss Prevention Data Sheets and National Fire Protection Codes shall be consulted. The extinguishing agent shall be selected based on the fire hazards encountered in the immediate area. 15. Where Navy criteria do not address a particular subject.2 Fuel.6 Portable Hand-Held Extinguishers. if any. For fire protection requirements for oil fuel. 15. Flammable and Combustible Liquids Code and NFPA 31. deluge water spray fire protection equipment.4 Lubricating and Hydrogen Seal Oil Equipment. see MIL-HDBK-1003/6. Portable hand-held fire extinguishers shall be provided at all standpipe hose stations and other strategic locations. Design and Construction. dry pilot. deluge water spray fire protection equipment. and hydrogen seal oil unit. For additional requirements. Outdoor generator step up transformers and outdoor auxiliary transformers shall be protected by automatic. type of detection. see MIL-HDBK1003/6. 15. and operation.MIL-HDBK-1003/7 Section 15. The turbine lubricating oil reservoir and conditioner.
)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 173 . * Type of Fire * Suppression * * * Location System Type of Detection Operation * * * Wet pipe Fixed temperature Automatic * * Administration * Area (excluding sprinkler quartzoid bulb * * * Halon protected areas) * * * Plans and records Halon 1301 Cross-zoned Automatic * * storage room ionization and * * photo-electric smoke * detection system * * * * * Control room (below Not applicable Ionization smoke Alarm only * detection * * ceiling) * * * Control room (above Not applicable Ionization smoke Alarm only * * ceiling) detection * * * * Control room (main Not applicable Ionization smoke Alarm only * * control panel) detection * * * * Control equipment room Halon 1301 Cross-zoned Automatic * ionization and * * * photo-electric * * * * Cable spreading room Wet pipe Fixed temperature Automatic * * sprinkler quartzoid bulb * * * * -Ionization smoke Alarm only * detection * * * * Dry pipe Fixed temperature Automatic * * Turbine underfloor * area. grade and sprinklers quartzoid bulb * * mezzanine level * * * * Turbine generator Preaction Fixed temperature Manual * * bearings spray * * * Deluge Dry pilot Automatic * * Boiler feed pump * turbine spray * * * .MIL-HDBK-1003/7 Table 28 Typical Fixed Fire Detection and Suppression Systems +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).
MIL-HDBK-1003/7 Table 28 (Cont.) Typical Fixed Fire Detection and Suppression Systems +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). Type of Fire * * * Suppression * * Location System Type of Detection Operation * * * * Warm-up guns and Preaction Fixed temperature Automatic * spray * * igniters * * * Igniter oil pumps Deluge Dry pilot Automatic * * spray * * * Deluge Dry pilot Automatic * * Hydrogen seal oil unit * * * Turbine lube Deluge Dry pilot Automatic * spray * * oil reservoir and * conditioner * * * * Main generator and Deluge Dry pilot Automatic * spray * * auxiliary transformers * * * Reserve auxiliary Deluge Dry pilot Automatic * * transformers spray * * * None Smoke detection Alarm * * Switchgear areas and * major motor control only * * * center * * * Coal conveyors within Dry pipe Fixed temperature Automatic * sprinklers quartzoid bulb * * generation building * * Deluge Infrared hot Manual * * Air heaters * spray spot detectors * * * * Coal pulverizers Steam Carbon monoxide Manual * * inerting monitoring * * * * Waterwash Manual * * (for B&W * * only) * * * * Coal dust collectors Preaction Thermistor wire Automatic * * sprinkler * * * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 174 .
) Typical Fixed Fire Detection and Suppression Systems +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).MIL-HDBK-1003/7 Table 28 (Cont. Type of Fire * * * Suppression * * Location System Type of Detection Operation * * * * Coal silos Low pressure -Automatic * CO2 on master * * * fuel trip * * or manual * * for fires * * * Dry pipe Fixed temperature Automatic * * Silo fill galleries * and plant conveyor sprinklers quartzoid bulb * * gallery * * * * Coal feeders Provisions -Manual * * for CO2 * * inerting * or for water * * * hose streams * .)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 175 .
Locate anchors to control heat pipe movement or to limit movements of branch takeoffs from a main line.1 Piping. see ANSI/ASME B31. and Jacketing 16. Exterior Distribution of Utility Steam.2. To prevent galvanic corrosion. or painted with a variety of finishes. Hangers and Supports. see MIL-HDBK-1003/6. platforms. Use rigid (rod or roller) or spring type pipe hangers for supporting overhead piping.2 Lagging. All insulated piping and equipment should be completely covered with aluminum or stainless steel jacketing. Metal lagging is used to cover insulation applied to breeching.MIL-HDBK-1003/7 Section 16. and ductwork to conserve energy and for comfort and safety. 16. tin. 16. MISCELLANEOUS 16. corrugated.2 Insulation. Thickness for energy conservation shall be dictated by an economic comparison of the value of heat energy saving versus the cost of additional thickness of insulation. For additional information. Lagging. or nickel alloys including Monel metal. Lagging surface temperature shall not exceed 150 degrees F (66 degrees C).1 Insulation. or stainless steel in a variety of profiles with the selection depending on the application and exposure. Follow manufacturer's recommendations and instructions for application.3 Jacketing. equipment. nickel. and other equipment having large flat surfaces. scrubbers. High Temperature Water (HTW). or other suitable surfaces is often supported from below by rigid floor stands. copper alloys. aluminized steel. Lagging can be aluminum. lead.2. and Compressed Air. large fans. electrostatic precipitators.2. embossed.1. Lagging can be plain.4 Pipe Supports. 16. Insulation shall be non-asbestos composition and shall be applied to piping. avoid permanent contact of aluminum jacketing with copper. Power Piping (ASME Code for Pressure Piping). baghouse filters. 16. Piping located near floors. See Federal Specification WW-H-171E. galvanized steel. See also MIL-HDBK-1003/8. For design of power plant piping and selection of piping materials. Fuel Gas. 16. Pipe. 176 . for type selection. unpainted. Chilled Water (CHW). ductwork. Piping that is subject to freezing shall be protected with electric heating cable. Aluminum jacketing should not be used for piping in trenches or buried directly in the ground.3 Freeze Protection. See also MIL-HDBK1003/8.
Provide adequate forced ventilation for the boiler room and the turbine room by use of roof-mounted exhauster fans. toilets and washrooms.03.6.6 16. Perform formal piping flexibility and hanger support calculations to make certain that pipes will be adequately and properly supported.1. shops. pumps. locker rooms.3 Hoists. fans. Heating systems shall be provided for boiler room. and moments) such as ADLPIPE can also be used. warehouses. Inc.1 Cranes and Hoists General. or expansion joints) in all steam or hot liquid piping. 16. Central control rooms and offices should utilize air handling units with duct systems for air distribution. Ventilating. Heat from boiler and equipment operation shall not be taken as a credit. ITT Grinnell.3 Air Conditioning. refer to publications such as Piping Handbook. Include humidification where necessary for comfort.2 Ventilating.5. forces. and other areas where personnel are expected to operate or maintain equipment. tunnels. Exhaust air from areas with suspended particulate shall be cleaned sufficiently to satisfy environmental regulations.1 Heating.5 Heating. Provide a beam 177 .5. and Air Conditioning. Use air tempering (heating and cooling) for central control rooms and for areas such as offices where air conditioning for comfort is justified. 16. lunch rooms.6. enclosed coal galleries. Provide turbine room crane for erection and maintenance of turbine 16. pump and equipment rooms.2 Cranes. 16. 16. For piping hanger and flexibility calculations. Refer to MIL-HDBK-1003/6 and NAVFAC DM-3. Providence.6. generators. turbine room. Computer programs for analyzing piping flexibility (stress.MIL-HDBK-1003/7 Provide adequate flexibility (by use of change in pipe direction. RI.5. 16. and administration areas if required for comfort or for freeze protection. Heating. and that piping reactions and movements at equipment piping connection or piping anchors will not be excessive. Provide hoists and supports for maintenance on water intakes. In dry climate regions. and other heavy equipment. Weight-Handling Equipment. Air Conditioning and Dehumidifying Systems for boiler plant requirements. expansion loops. Other areas to be ventilated include shops. Sabin Crocker or Piping Design and Engineering. Refer to NAVFAC DM-38. compressors. humidification of the boiler and turbine rooms may also be necessary for personnel comfort. Ventilating. 16.01. that pipe stresses will not exceed limitations permitted by ANSI/ASME B31.
1. Meters shall be provided on fuel lines.3 Equipment. Control systems shall be designed so that loss of the control media (air or electricity) will leave the control in a fail-safe position. 16.1 Power Plant Buildings. Pipe penetration through building walls and floors shall be made through pipe sleeves and with swing joints or other means of permitting independent pipe movements. 16.10. thereby reducing construction costs. 16. 16. An economic study should decide whether indoor or outdoor housing should be used. completely outdoors. 16. Boiler plants and generators. Steam output metering of the header and at each steam generator shall be provided for periodic reports and testing.MIL-HDBK-1003/7 into the plant.10 Architectural Criteria 16. weatherproofing equipment makes operation and maintenance more difficult. All piping systems shall be designed to permit freedom of movement of the pipes in all directions.9. electrical and water services to the buildings. if possible.1 Outdoor and Semi-Outdoor Plants. However.9 Refer to MIL-HDBK-1003/6. 16. All mechanical equipment and tanks shall be securely anchored to their foundations. 178 .2 Piping. Weatherproofing equipment for outdoor service saves a good part of building construction. 16. under Drainage and NAVFAC DM-3.4 Controls.9. All piping critical to the operation of the power plant shall be steel. Supports for equipment shall be steel in lieu of cast iron. Plumbing Systems. in lieu of a brittle material. Definitive steam electric-generating plants have semi-outdoor boilers.9. Cast-iron or cement-asbestos pipe shall not be used for condenser cooling waterlines. and provide steel above an opening between floors to hoist large equipment to an upper level. Power plant buildings shall be in accordance with Seismic Design for Buildings. may be feasible in warm and temperate climates. Proper measures against freezing of stationary water must be made.9. NAVFAC P-355. Seismic Design Criteria 16. and to the major equipment and boilers in the building.8 Drainage.7 Metering.
11. lockers. 16. and control rooms.10. Sufficient aisle and laydown space. and other heavy equipment. boilers. Localization of operations.2 Arrangements. it should be separated from other foundations and floor slabs. offices. Power plant foundations require careful design because a site is frequently on marsh or filled ground close to the sea. Adaptability to various makes of equipment.1 Foundations. Where low water levels are anticipated. Parking. Equipment platforms with access. Ease of replacing equipment and extending a plant. Loading and unloading fuel and equipment. a detailed subsurface study is necessary. Seismic conditions at the site should be investigated. fuel oil tanks.3 Criteria Source. see MIL-HDBK1003/6. coal silos. storage. work shops. b) Where heat from a furnace is transmitted to a boiler foundation.10. 16.11 Structural Criteria 16. Centralization of electrical equipment and controls.MIL-HDBK-1003/7 16. a) b) c) d) e) f) g) h) i) j) k) Architectural arrangements should provide for: Minimum total building volume. Toilets. and an expansion joint at floor slab level installed around its periphery. For general architectural design criteria. a) Extra piling may be required for stack foundations. 179 . under Architectural Criteria. Adaptability to definitive designs. c) Equipment foundations should be designed in accordance with manufacturers' instructions. turbine generators.
a) b) Systems and access doors for inspection need only ladders.1. 16. Connect the platforms to two means of exit. Include pipeline listing of pipeline section description. 16. as listed below.2 Description of system and associated major equipment. Platforms shall have toe guards and railings. closed. List and describe all electrical components. Include pictures as necessary. and thickness and type of insulation. and state normal valve position (open. Exterior mechanical equipment and systems should be anchored. Coal silos and conveying systems. 16.3 Typhoon or Hurricane Considerations.MIL-HDBK-1003/7 16. each covering a complete operating system.11.13.11. evaporative condensers and coolers.3.13. installation. boiler stacks. and anchorage of the typical mechanical features.11. Each section or part shall be formatted as follows: 16. Electrical Criteria. Provide platforms for all systems more than 4 feet above the ground floor requiring access for operation and cleaning. and fuel distribution lines mounted above ground on structural supports.13. or guyed to withstand the wind velocity specified for design of structures (see MIL-HDBK-1002/2. See MIL-HDBK-1003/6. shall be given special attention to ensure minimum damage due to typhoon or hurricane phenomena: 16. Loads).4 16.3. Preparation of operating and maintenance manuals shall be in accordance with the latest revision of Military Specification MIL-M-38784.11. The manual shall be composed of sections or parts. and roof-mounted heating and air conditioning units. Describe system function. compressed air. Refer to MIL-HDBK-1003/6.1 Plant Operation and Maintenance Manual. 16.13 Operation and Maintenance Manuals. outside boilers. cooling towers. 16.1.2 Platform and Ladders. Manuals. Designs for construction. braced. 180 . Steam. Reference Equipment Data Manual for each piece of equipment.11. List all valves. state valve function. duct work. and each piece of equipment. water. pipe material.12 Collateral Reading. The plant operation and maintenance manual shall be divided into volumes separating mechanical and electrical systems. under Electrical Criteria.1 Miscellaneous. or throttled).1 System designation 16. List special tools or test equipment that are needed or furnished with equipment. each process system and subsystem. Technical: General Style and Format Requirements.2 Exterior Piping Systems. Each power plant shall be provided with a complete set of operating and maintenance manuals covering the plant.
piping and instrument diagrams. Operational checks and tests. frequency (monthly. location. name of supplier/manufacturer. lubrication. shutdown. probable cause. 16. The Equipment Data Manual shall consist of one or more volumes. location of item. Maintenance. 16. Include list of trouble. Foldout drawings including system descriptive drawings.1. preparation. Adjustments. Include description of each maintenance action by steps.) and Equipment Data Manual reference. List maintenance actions. and troubleshooting. and monitoring. starting. List troubleshooting activity by equipment piece including reference to Equipment Data Manual. and inspection procedures and intervals. schematic diagrams. post-shutdown. electrical oneline diagrams. 16. flow diagrams. Sequence of operation (startup.13. Troubleshooting of system including safety precautions. to contain manufacturer's literature and data covering operation and maintenance procedures.4 Maintenance. and alarm.13.13. units (such as ON/OFF). (1) (2) (3) (4) (5) 181 . operating. maintenance procedures (refer to data contained in Equipment Data Manual wherever possible).2 Equipment Data Manual. as necessary. heat balances.1. as necessary.1. preparations.5 Troubleshooting. This data manual should be indexed and sectioned by major pieces of equipment. annually. and data location in the manual. Include list of monitor description.3 Operation. name of item of equipment. semi-annually.1. Equipment data should include the following information: a) Master equipment list including equipment identification or tag number. including original equipment manufacturer's accessories. etc.13. other identifying characteristics such as capacity or type. Operation of system including procedures for prestart.13. Maintenance of system including safety precautions.MIL-HDBK-1003/7 16. b) Manufacturer's data for each piece of equipment including: General description. status. quarterly. and reduced copies of sheets of construction plans. and shutdown).6 Drawings. 16. and corrective action for each piece of equipment. control panel layouts.
(11) Original equipment manufacturer's data for associated auxiliary or accessory equipment. (9) data sheets. including price list. Manufacturer's data report for boilers.MIL-HDBK-1003/7 (6) (7) (8) exchangers. (10) Parts lists. 182 . Recommended spare parts. pressure vessels. and heat Manufacturer's certified pump performance curves and factory test Piping and wiring diagrams.
application. 17. recently there has been much development work performed with techniques for reducing NOx emissions with the use of Urea. the most important of which are fuel type and fuel burning equipment. A discussion of emission limits as they relate to fossil fueled steam power plants is contained in Section 18. The amount of each formed is dependent upon many factors. Point source emission rate tests are a necessary part of the environmental impact assessment required for all new Government-funded facilities. Air Pollution Control Systems for Boilers and Incinerators. However.2 Emission Limits. state. Revisions to the regulations regarding air pollution test requirements for federal installations appear in the Federal Register. Details of NOx reduction techniques are given in TM-5-815-1/AFM 19-6. and local regulations. Nitrogen oxides are not normally removed from the exhaust. 17. design considerations. compliance is determined through point source emission rate tests. Sulfur dioxide is normally removed with wet or dry scrubbers. Data on emissions of pollutants produced while burning a fossil fuel in a boiler are given in TM-5-815-1/AFR 19-6. and particulate matter are produced. The basic operation. 17. and fabric filters (baghouses).1. nitrogen oxides (NOx).1.1. Ammonia or Selective Catalytic Reduction. SO2. rather. The point source emission rate test methods and requirements approved by the EPA are published in the Code of Federal Regulations. Examples of particulate matter removal equipment include mechanical cyclones.MIL-HDBK-1003/7 Section 17. 183 . These systems have been installed on many recent boilers and combustion turbines. and combustion modifications can be employed. load reduction.1 Air Quality Control POLLUTION CONTROL 17.4 Monitoring and Reporting. The amount of the pollutants produced in the boiler that are allowed to pass out of the stack as emissions is governed by Federal. As a fossil fuel is burned. Environmental Regulations and Permitting. In the upgrading of existing installations.1. electrostatic precipitators.3 Equipment Selection. the pollutant production in the boiler is minimized. Various techniques such as fuel changing. and visible emissions and are listed in Table 29. The techniques included are for testing for particulate. wet scrubbers. air pollutants such as sulfur dioxide (SO2).1 Pollutant Production. NOx. and selection of air pollution control equipment are contained in TM-5-815-1/AFR 19-6. 17.
* * * * #7 All nitrogen oxides (NOx) in flue gas except * nitrous oxide (NO). and overall water usage and conservation measures. * EPA Method To determine: * * * * #1 Sampling site and the minimum number of sampling * points required for the extraction of a representative * sample of flue gas from a stationary source.MIL-HDBK-1003/7 Table 29 EPA Emission Sampling Techniques1 +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).2. * * * * #6 Sulfur dioxide (SO2) concentration in flue gas. SO2 removal method.2 Water Quality Control 17. Appendix A. Sampling ports will be accessible and located so that the cross-sectional area of the stack or flue can be traversed to sample the flue gas. * * #9 . extend out approximately 4 inches from the stack. The sampling ports shall be provided and located in accordance with the applicable current Federal or state regulations for fuel-burning equipment. * * #4 * * * #5 Particle emissions from stationary sources. The number and source of wastewater streams associated with a fossil-fueled steam power plant are dependent upon such factors as fuel type. On double wall stacks. * * #2 * * * #3 Concentration by volume of carbon dioxide (CO2). 17. Possible wastewater sources are listed hereinafter. * * carbon monoxide (CO). * * * Opacity of visible emissions. Sampling ports will be approximately 4 inches in diameter. * * * * * #8 Sulfur dioxide and sulfuric acid (H2SO4) mist * * concentrations in flue gas.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))1 40 CFR 60. and have a flanged removable cover. methods of ash handling. * * * * Velocity and volumetric flow rate of flue gas. sampling ports may consist of a 4-inch diameter pipe extending from 4 inches outside the stack to the inner edge of the inner stack wall. and oxygen (O2) in flue gas.1 Waste Streams. * * * Moisture content of flue gas. 184 .
g. transformers. Boiler tube chemical cleaning wastes. Any l) Flue gas desulfurization (FGD). discharge requires pretreatment for clarification and neutralization. This wastewater results when plant personnel use hoses to wash down certain equipment and areas in and around plant buildings. service buildings. restroom toilets and sinks). f) Steam boiler blowdown. i) Area washdown drains. At times. Wastewater from this source is a result of treating washdown water from such areas as fuel oil storage. For example. This wastewater is released from the boiler drums to maintain a sufficient water quality in the boiler. water quality may degrade to a point where some must be released as a wastewater.. h) Plant drains. g) Cooling tower water blowdown. This source is present only if cooling towers are employed to remove heat from the steam cycle. Chemical feed area and storage area drains. k) Ash handling system (from bottom ash removal transport system). This wastewater is released from the cooling water tower to maintain water quality. and service buildings may be periodically flushed. j) Oily waste treatment system. however. 185 . wastewater must be pretreated before discharge. Under normal conditions. Laboratory drains. floors such as in the scrubber. lube oil storage. The n) Runoff from coal storage areas and solid waste storage areas. backwash. and turbine building. process water within the scrubber system is recirculated.MIL-HDBK-1003/7 a) b) c) d) Chemical wastes resulting from water treatment. e) Sanitary wastewater. turbine. This waste source consists of sanitary wastes originating from plant buildings with sanitary facilities (e. m) Storm water runoff. This source is a result of pump seal water overflows and miscellaneous equipment water drains. and drainage.
This device operates by allowing the oil and wastewater to separate naturally (because of their difference in densities).2 Discharge Standards. Oil-contaminated wastewater must be treated before being allowed to enter a recycle basin. Environmental Regulations and Permitting.3. and metal cleaning wastewater are corrosive and should be collected in a separate piping system from other plant drains.1 Oil Spill Control Possible Sources of Spills 186 . 17. and neutralization.3. Newly constructed plants may be designed as zero discharge facilities.3 Treatment and Disposal Methods. The neutralized wastewater can then be discharged to the recycle basin or to the sanitary sewer. discharge standards apply.1 Recycle Basin. it does not have a discharge of water. which includes settlement. neutralized). Environmental regulations and permitting associated with wastewater discharge are discussed in Section 18.5 Leachate and Runoff From Coal Storage Areas. for this case. 17. Wastewaters generated by a power plant should be reused as much as practical to conserve water. discharge standards do not apply.3.3 17. Sanitary wastewater is typically directed to a sewage treatment plant located on site.3. Discharge waters from coal storage areas and solid waste storage require treatment. 17. properly treated.2. 17.2. Wastes from steam condensate treatment. Hence.3. Zero discharge means that although a plant may use water.3.MIL-HDBK-1003/7 17. the cooling water system.4 Storm Water Runoff.3.2.e. If there is any water discharge. flow to the recycle basin.3 Sanitary Wastewater. laboratory drains..2. to satisfy local regulations for wastewater discharge of storm water. These wastes are normally directed to a treatment tank where they are mixed with the proper chemicals until the entire solution is no longer corrosive (i.2. clarification. 17.2 Chemical Wastewater. The treatment plant processes the sanitary wastes and discharges either to the streams or to the recycle basin. A common method of wastewater handling at a power plant involves the use of a recycle basin (also called a reclaim pond).2. or from storm water runoff. chemical feed and storage area drains. Roof and yard drain storm water runoff is reasonably clean and discharged with the storm system without treatment. Many facilities do discharge water from the sewage treatment plant. The separated oil is directed to waste oil storage containers while the de-oiled wastewater is discharged to the recycle basin. 17. This treatment is normally accomplished through use of an oil separator.2. The wastewater streams. 17.2.6 Oily Wastewater. 17.
17.MIL-HDBK-1003/7 17. For example. transformers for electrostatic precipitators are typically located atop the precipitator structure itself.3. Additional information concerning oil spill prevention and cleanup can be found in the Code of Federal Regulations.1 Bulk Oil Storage Tanks. and uncontaminated soils shall be used as a replacement. a) b) c) d) Dikes. berms. Petroleum Fuel Facilities. appropriate containment and diversionary structures or equipment to prevent discharged oil from reaching a navigable watercourse should be provided. if unconfined.3. or lube oil drippings from equipment which. According to oil spill regulations and permitting. Most large electrical transformers are filled with oil for purposes of cooling. or valve and pipe leakage. 17. the area surrounding fuel oil storage tanks shall be provided with dikes with controlled water discharge to confine oil spills and to collect rainwater runoff that may be contaminated with oil. Oil/water separators may be required on the water discharge control to satisfy some state requirements. Permeated soils shall be removed. overflow. may be sources of oil spills.3. Spills may originate from tank rupture. Curbing. Confined spills above ground may be cleaned up through use of oil-absorbent materials. 17.3 Methods of Cleanup. appropriate clean up equipment must be on hand for spills on such a water surface.3. If the plant is located near a navigable watercourse. Oil/water separators. If a spill occurs.2 Methods of Prevention. 187 . or a truck may cause an oil spill. 17.2 Lube Oil Tanks. Spills may originate from tank rupture.1.1. Their location can be indoors or outdoors and ground level or elevated. for additional information. In addition.3. See NAVFAC DM-22. a railroad tank car. For example. valve and pipe leakage.1. appropriate cleanup action must be taken. Lubricating oil tanks are normally located indoors.3 Oil-Filled Transformers. Spills may originate as a result of rupture or seal leakage. the process of filling the tanks from a barge. or retaining walls. Gravel-filled retention area under transformers. The following systems or its equivalent should be used as a minimum.
see Combustion Engineering. Combustion Fossil Power Systems. leachate control must be incorporated. The amount produced varies with the particular coal being pulverized.1.MIL-HDBK-1003/7 17. and Boiler Emissions in TM-5-815-1/AFR 19-6.1 Solid Waste Production. the solid wastes produced at a fossil-fueled steam power plant are not categorized as hazardous by the Environmental Protection Agency. according to the Resource Conservation and Recovery Act (RCRA) of 1976. Pulverizer rejects consist of a variety of coarse. pulverizer rejects (if pulverized coal is burned). The sources and amounts of solid waste produced by a fossil-fueled steam power plant are dependent mainly on the fuel type.4.3 Pulverizer Rejects. such as fuelburning equipment. Since RCRA requires that a landfill not contaminate an underground drinking water source beyond the solid waste boundary. 17. 188 . for details of scrubber waste products for various types of SO2 scrubbers. and flue gas desulfurization scrubber solids (if an FGD device is employed).2 Bottom Ash.1 Requirements. At this time. The quantity of scrubber solids produced vary with the amount of SO2 removed from the boiler exhaust and with the type of solids produced.2. For further information.4. if it is assumed that rejects comprise 0. Therefore. See MIL-HDBK1003/6.1. a mass balance calculation is required to determine the quantity of scrubber solids generated. fuel burn rate.4. either clay or a synthetic membrane.1 Fly Ash. The particular solids formed depend on the scrubber type. heavy pieces of hard rock or slate and iron pyrite that are separated from coal during pulverization.5 percent of the coal fired. Generally. bottom ash. 17. 188.8.131.52 Methods of Treatment and Disposal 17. A reasonable estimate can be made.4. however. the wastes may be landfilled utilizing environmentally acceptable practices. Section 7. Solids from an FGD device consist of sulfate and sulfite reaction products resulting from the absorption of sulfur dioxide from the boiler exhaust.1. Bottom ash consists of the large particles of solid combustion products (ash) and unburned carbon that fall out in the bottom of the boiler.4 Solid Waste Disposal 17. 17. Other factors.4. Fly ash consists of the fine ash particles that are entrained in the boiler exhaust gases. Solid wastes produced at a plant burning fossil fuel include fly ash.1. may also affect the solid waste production rate.4 FGD Scrubber Solids. 17. Particulate emissions from natural-gas-fired boilers are negligible and thus are not a source of solid waste.4. This is usually accomplished through the use of liners. and degree of pollutant removal from the boiler exhaust.
the production of hazardous waste from a fossil-fueled steam power plant should be prevented through proper design choices. if the waste is hydraulically removed and plant space is available. Details of solid waste disposal can be found in NAVFAC DM-5. Ash Handling. The combined waste product is then disposed of as discussed in Bottom Ash above.2.4. The U.. intermediate storage. The choice of which to use depends on economics.4. Consideration of these factors and others in a detailed study is recommended before deciding on a specific disposal system. Treatment and disposal of this waste product can be the most complicated and expensive of the four discussed. are necessarily associated with the production of energy. If space is limited. demineralization regenerant. Additional information on solid waste management can be found in NAVFAC MO-213.2 Fly Ash.3 Bottom Ash. of this design manual.4. (EPA) has interpreted the fossil fuel combustion waste exemption from hazardous classification to extend to other wastes that are produced in conjunction with the combustion of fossil fuel.3 Hazardous Waste Considerations. of this design manual. and conditioning are covered in Section 10.2. Bottom ash handling and intermediate storage are discussed in Section 10. and cooling tower blowdown.2. bottom ash. In most cases. To choose a method. 17.10 and NAVFAC MO-213. Solid Waste Disposal. fly ash can be disposed of as a solid waste in a landfill. A discussion of various waste products from FGD systems can be found in MIL-HDBK-1003/6. space availability. a bottom ash pond may be preferred. Wastes which the EPA has specifically indicated would fall under this co-disposal/cotreatment interpretation include (but are not limited to) boiler cleaning solutions.e. Ash Handling.2. if the bottom ash is removed dry (i. Solid Waste Management. the bottom ash could be dewatered and then landfilled. For example. consideration must be given to the type of scrubber system employed. and availability of disposal space. pyrites. along with information on alternative disposal methods for scrubber waste products. If not sold to an outside party such as cement or concrete block manufacturers. Additional information on solid waste disposal and its management can be found in NAVFAC DM-5. 17. This waste product is generally disposed of in either settling ponds or a landfill. 17. Environmental Protection Agency 17.4.MIL-HDBK-1003/7 17. Therefore. However.S. 189 . and are mixed with and co-disposed or co-treated with fly ash. the pulverizer rejects are transferred either hydraulically. boiler blowdown. Details of fly ash handling. chemical composition of waste product.10.5 SO2 Scrubber Solids. or FGD wastes.4 Pulverizer Rejects. mechanically.4. mechanically) the preferred disposal method is a landfill. Additional discussions of FGD waste can be found in TM-5-815-1/AFR 19-6. and compatibility with the bottom ash removal system. or pneumatically to the bottom ash handling system.
1 Air Quality Regulations. 190 . the existing pollution level (background) must be known. Each of the states also regulates air pollution emissions.MIL-HDBK-1003/7 Section 18. These six pollutants include the three major pollutants discussed above. nitrogen oxides (NOx). All facilities must comply with both Federal regulations and state (and local) regulations. and particulate matter. The National Ambient Air Quality Standards (NAAQS) are established by the U. Any place where the air quality is worse than the NAAQS is said to be a "nonattainment" area. The formation of the major pollutants and their control is discussed in Section 17 of this handbook. ENVIRONMENTAL REGULATIONS AND PERMITTING Air pollution emissions from a fossil fueled 18. 18. These are standards based on measured or calculated pollutant concentrations at ground level off the site of the pollutant source. Each pollutant is characterized separately. The stack emissions of major concern in a fossil fueled steam power plant are sulfur dioxide (SO2). The facility will have to be designed to meet the most stringent requirements. The entire United States. steam power plant are regulated by the Federal Government under the Clean Air Act (42 USC & 7401 et seq. To find out if the NAAQS would be exceeded. is supposed to have air quality at least as good as the NAAQS.).1 National Ambient Air Quality Standards. SO2. NOx. Of lesser concern are carbon monoxide (CO) and various trace elements such as mercury and beryllium.1. The primary standard is established at the level requisite to protect the public health and allowing an adequate margin of safety. An area can be a nonattainment area for one pollutant and an attainment area for another.S. Environmental Protection Agency (EPA). The secondary standard is established at the level requisite to protect the public welfare (such as vegetation) from any known or anticipated adverse effects associated with the presence of such pollutants in the ambient air. and particulate matter. The NAAQS values for all six "criteria" pollutants are given in Table 30. Stack emissions are limited by direct emission limits. This is the pollutant concentration in the flue gas emissions measured in the stack. The modeled impacts of the proposed facility are added to the background. The NAAQS is important to stack emissions because a new facility will not be permitted if calculations (modeling) show that the NAAQS would be exceeded at any point off the facility site. Stack emissions may also be limited by ambient air quality limitations. It may be necessary to limit the emissions from a new source so that the NAAQS are protected.
But to receive a permit. NOx. Most states have adopted the NAAQS. new air pollution sources could be added until the ambient air quality became as bad as the NAAQS. other sources of pollution must be reduced. The maximum permitted increases are as follows: 191 . Prior to that date. the standard has been based on particulate matter with an aerodynamic diameter of 10 microns and less (PM10). These increment limits currently exist for only SO2.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- (a) Not to be exceeded more than once per year. and particulate matter. These "offsets" are part of the permitting process.300 * * 3-hour concentration (a) * 24-hour concentration (a) 365 -* 80 -* * Annual concentration * Particulate Matter PM10 (c) * * 24-hour concentration (a) 150 150 * * Annual concentration 50 50 * * Carbon Monoxide * 40 mg/m3 40 mg/m3 * * 1-hour concentration (a) * 8-hour concentration (a) 10 mg/m3 10 mg/m3 * * Ozone * 235 235 * * 1-hour concentration (b) * Nitrogen Dioxide * * Annual concentration 100 100 * * Lead * 1. (b) Not to be exceeded more than an average of one day per year over 3 years. the standard was based on total suspended particulate (TSP). Originally under the Clean Air Act (CAA).2 Prevention of Significant Deterioration Limits. The amount of offsets available can affect the amount of stack emissions permitted from a new source. Even if the area is currently nonattainment. Each state has also established ambient air quality standards.MIL-HDBK-1003/7 Table 30 Primary and Secondary Ambient Air Quality Standards (micrograms/m3 except where otherwise noted) +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).5 1. Primary Standard Secondary Standard * * * * * Sulfur Dioxide * -1. (c) Since 1987. a new facility may be permitted.1. 18.5 * * Calendar quarter . A few have more restrictive standards. Now the CAA includes limits to the amount of new pollution in clean air areas. The most restrictive standards will apply.
The most stringent classification is Class I. 192 . Just as in the NAAQS.MIL-HDBK-1003/7 Pollutant Particulate Matter (TSP) Annual geometric mean 24-hour maximum Sulfur Dioxide Annual arithmetic mean 24-hour maximum 3-hour maximum Nitrogen Dioxide Annual arithmetic mean Maximum Allowable Increase Class I Class II Class III micrograms/m3 micrograms/m3 micrograms/m3 5 10 2 5 25 2. Most of the United States is classified as Class II. A Class III area would allow the largest amount of new pollution. the amount of increment available to a new source may affect the amount of stack emissions which can be permitted.5 19 37 20 91 512 25 37 75 40 182 700 50 The maximum allowable concentration resulting from an applicable increment will not be allowed to exceed a national primary or secondary ambient air quality standard. 18. and large national memorial parks. the Class I increments must still be met at the boundaries of any nearby Class I area. Again modeling is used for the calculations. The three classes have been established to allow flexibility in new source permitting. Old sources which shut down will make more increment available. All new sources since an established "baseline date" will use up available increment. b) 40 CFR Part 60. Standards of Performance for Fossil Fuel Fired Steam Generators for Which Construction is Commenced After August 17. These areas are principally international parks and large national wilderness areas. 1971. Subpart D. Both the EPA and the states have new source performance standards (NSPS).1. Subpart Da. These standards are direct limits on the pollutant concentrations in the flue gas emissions. They vary depending on the fuel to be burned. The amount of increment available to a proposed new source must be calculated as part of the permitting process. 1978. large national parks. Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18. If the facility is located within a Class II area.3 New Source Performance Standards. The Federal NSPS have been established for three categories of fossil fuel steam power plants as follows: a) 40 CFR Part 60. There are no Class III areas in the country.
10 * type solid capacity factor of * * * waste other fuels * * * * * . * Maximum * * Emission Rate * Fuel Special Conditions lb/MBtu * * Pollutant * * * Particulate Coal Up to 10% annual capacity 0.10 * * * * Coal & other Other fuels greater than 0.20 * fuels except greater than 10% but * * * coal less than 30% for wood * and unit less than 250 MBtu/hr * * * * * Municipal Up to 10% annual 0. The Federal NSPS for such units are presented in Table 31.10 * * fuels 10% annual capacity * factor * * * * Wood & other Annual capacity factor 0. The most stringent of these regulations (Subpart Da) applies to new electric utility steam generating units and should not be applicable to a military power plant. NOx and particulate matter are currently regulated under these regulations.MIL-HDBK-1003/7 c) 40 CFR Part 60. SO2. Standards of Performance for IndustrialCommercial-Institutional Steam Generating Unit.05 * * Matter factor of other fuels * * * * Oil --0.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 193 . A military power plant would qualify as an industrial-commercial-institutional steam generating unit.10 * * * fuels except greater than 30% * * coal for wood * * * * Wood & other Annual capacity factor 0. The Subpart Db NSPS apply to industrial-commercial-institutional steam generating units larger than 100 million Btu per hour heat input rate. Subpart Db. Table 31 New Source Performance Standards for Industrial-Commercial-Institutional Steam Generating Units Larger Than 100 MBTU/HR Input Rate +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).
80 lb/MBtu or * * 0.) New Source Performance Standards for Industrial-Commercial-Institutional Steam Generating Units Larger Than 100 MBTU/HR Input Rate +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))).60 * * * * * Coal-derived --0. SD.40 * * * * Coal Mass-feed stoker 0.70 * * * * * Lignite ND.102 * * Nitrogen * Dioxide or distillate * * oil * * * * Natural gas High heat release rate 0.50 * * * * Coal Spreader stoker or 0.80 * Lignite combusted * * * in a slag tap * furnace * * * * Lignite All other lignite 0.50 * synthetic fuels * * * * * Sulfur Dioxide * * * Coal 90% reduction4 plus * * * 1.60 * * fluidized bed * combustion * * * * Coal Pulverized coal 0.MIL-HDBK-1003/7 Table 31 (Cont.30 lb/Mbtu * .))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- 194 . * Maximum * * Pollutant Fuel Special Conditions Emission Rate * lb/MBtu * * * * Natural gas Low heat release rate 0.2 lb/MBtu * * * * Oil 90% reduction4 plus * * 0.20 * or distillate * * * oil * * * Residual oil Low heat release rate 0.303 * * * * * Residual oil High heat release rate 0. or MT 0.
Maximum * * * One Hour Average * * Pollutant Emission Rate * * lb/MBtu * * * Sulfur Dioxide1 * * * Liquid Fuel 0. the limit is 0.60 or 0.70) / (x + y + z) Where x is the percent of total heat input derived from gaseous fuel. except for one sixminute period per hour of not more than 27 percent opacity. 3 For residual oil in a duct burner used in a combined cycle plant.2 * * 2 * Particulate Matter * * Any Fuel 0.30) + z (0. 2 For natural gas or distillate oil in a duct burner used in a combined cycle plant.20) + y (0. 195 . The emission limits under Subpart D are presented in Table 32.20 * Liquid Fuel 0. fossil-fuel fired steam generating units larger than 250 MBtu/hr heat input rate which is not covered by Subpart Db or Subpart Da. 4 The percent reduction requirement is waived for facilities that have a permit limiting annual capacity factor on oil and coal to 30 percent or less. Sulfur Oxides Nitrogen Oxides y (0.)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))1 When combinations of fuel are burned simultaneously. the limit is 0.40 lb/MBtu.30 * * * Solid Fuel (except lignite) 0.2) / (x + y + z) x (0.80) + z (1.MIL-HDBK-1003/7 1 An opacity limit also exists.20 lb/MBtu. y from liquid fuel.70 * Lignite 0. Table 32 New Source Performance Standards for Fossil-Fuel Fired Steam Generating Units Larger Than 250 MBTU/HR Heat Input Rate +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). Subpart D would still apply to any new.10 * Nitrogen Dioxide1 * * * Gaseous Fuel 0.80 * Solid Fuel 1.80 * * . and z from solid fuel. Opacity must not exceed 20 percent. the applicable standard shall be determined by proration.
The purpose of water quality standards is to define the water quality goals of a water body. by designating the use or uses to be made of the water and by setting criteria necessary to protect the uses. The EPA and the States. should. preserve. physical. and serve the purposes of the CWA. Therefore. State or local emission limits will also apply the units covered by the Federal NSPS. and/or eliminate pollution. Wastewater from a power plant is regulated in two separate ways much as air pollutants are regulated. and wildlife and for recreation in and on the water and taken into consideration their use and value for public water supplies. Only the state (or local) emission limits apply to small units. The regulations of the applicable state must be examined for separate effluent regulations. and biological integrity of the Nation's waters. However. This is the case even if several units side by side add up to more than 100 million Btu/hr. shellfish. acting in coordination.2 Water Quality Regulations. Water quality standards. The objective of the CWA is to restore and maintain the chemical. 18. notably SO2. wherever attainable. Each furnace or boiler is considered a separate unit. the EPA's regulation of effluents from power plants is limited to generating units at an establishment primarily engaged in the generation of electricity for distribution and sale which results primarily from a process utilizing fossil-type fuel or nuclear fuel in conjunction with a thermal cycle employing the steam water system as the thermohydraulic medium. Only water quality standards will be addressed in this section. military installation would not ordinarily be subject to the EPA's effluent guidelines and standards for steam electric power plants.1 Water Quality Standards. States are to adopt water quality standards to protect public health or welfare. The second method is effluent standards for each specified waste stream from the power plant. The Federal NSPS does not apply to any units less than 100 million Btu/hr. Discharges to a water body must be analyzed to determine its impact on water quality. and protect the primary responsibilities and rights of states and for the states to implement permit programs to prevent. The CWA includes provisions to recognize. The first method is by water quality standards that are established for water bodies. enhance the quality of water. 196 . reduce. The facility must be designed to meet the most stringent of the federal or state emission limits. agricultural. or portion thereof. Usually the states have adopted the Federal NSPS but some states do have more restrictive limits for some pollutants. are to develop and publish regulations specifying minimum guidelines for public participation in such processes.MIL-HDBK-1003/7 2 An opacity limit also exists. Opacity must not exceed 20 percent except for one sixminute period per hour of not more than 27 percent opacity. The major Federal statute regulating water quality and wastewater discharges is the Clean Water Act (CWA). and other purposes including navigation. 18. provide water quality for the protection and propagation of fish. The Environmental Protection Agency (EPA) is responsible for administering the CWA. industrial.2.
The state is required to conduct a use attainability analysis unless otherwise exempted in the CWA. it must provide information identifying the method by which the state intends to regulate point source discharges of toxic pollutants. and revising water quality standards. establishing. In designating uses of a water body and the appropriate criteria for those uses. Where a state adopts narrative criteria for toxic pollutants. EPA is to review and approve. The state adopted standards may be more stringent than required by Federal regulation.2 Criteria. which is not an existing use. States must identify specific water bodies where toxic pollutants may be adversely affecting water quality. or are at a level to warrant concern. 18. and antidegradation policy. The state shall provide notice and an opportunity for a public hearing prior to adding or removing any use or establishing subcategories of a use.1 Designation of Uses. uses are deemed attainable if they can be achieved by the imposition of effluent limits required under Sections 301(b) and 306 of the CWA and cost-effective and reasonable best management practices for nonpoint source control. States may adopt subcategories of a use and set appropriate criteria to reflect varying needs of such subcategories of uses. the state must take into consideration the water quality standards of downstream waters and ensure that its water quality standards provide for the attainment and maintenance of the water quality standards of down stream waters. At a minimum. States are required to adopt water quality criteria that protect the designated use of the most sensitive use. criteria. or natural. Under provision of the CWA.1.MIL-HDBK-1003/7 States are responsible for reviewing. ephemeral. intermittent. There are three main factors to be considered in establishing water quality These factors are designation of uses. standards. Seasonal uses may be adopted as an alternative to reclassifying a water body to uses requiring less stringent water quality criteria. Such criteria must be based on sound scientific rationale and must contain sufficient parameters or constituents to protect the designated use. Toxic pollutants are those listed by the EPA under Section 307(a) of the CWA. or disapprove the state-adopted water quality standards.1. 197 . Each state must specify appropriate water uses to be achieved and protected.2. States may remove a designated use. 18. or low flow conditions or water levels. attainment of a designated water use.2. or establish subcategories of a use if the state can demonstrate that attaining the designated use is not feasible because of naturally occurring pollutants concentrations.
4 Public Hearings and EPA Notification. hold public hearings for the purpose of reviewing applicable water quality standards and modifying them as appropriate. Where the quality of the waters exceeds the level necessary for the designated use. In promulgating water quality standards. procedures.3 Antidegradation Policy. The pretreatment regulations contain the following specific prohibitions. The state is to submit the results of the review and any supporting analysis for the use attainability analyses to EPA. EPA notifies the state within 60 days of approval or within 90 days of disapproval.MIL-HDBK-1003/7 18. the antidegradation policy and implementation method must be consistent with Section 316 of the CWA.2.1. that quality will be maintained and protected unless after the full satisfaction of the intergovernmental coordination and the public participation provisions the state finds that allowing lower water quality is necessary to accommodate important economic or social development in the area where the waters are located. After the state submits the officially adopted revisions. and public participation requirements as established for states. EPA has also established pretreatment regulations applicable to any industrial wastewater discharges to publicly-owned sewage treatment works (POTW). that water quality shall be maintained and protected. The pretreatment regulations prohibit the discharge from causing inhibition or disruption of the receiving POTW's sewer system. any general policies. and revisions to the water quality standards are also to be submitted to EPA for review and approval. at least once every three years. If the state does not adopt changes specified by EPA within 90 days after notification of disapproval. such as waters of national and state parks and wildlife refuges and waters of exceptional recreational or ecological significance. Where a potential water quality impairment associated with a thermal discharge is involved. The methodologies used for site-specific criteria development. 18.1. EPA will promptly propose and promulgate such a standard. or operations which contribute to a violation of the NPDES permit of the POTW.2. 18. The state is to develop and adopt a statewide antidegradation policy and identify the methods for implementing the policy. The state must. A state water quality standard remains in effect.2 Pretreatment Standards.2. 198 . treatment processes. even though disapproved by EPA. Where high quality waters constitute an outstanding national resource. until the state revises its standard or EPA promulgates a rule that supersedes the state standard. EPA is subject to the same policies.
18. a single above ground container larger than 660 gallons. unless the POTW is specifically designed for such discharges. or could reasonably be expected to discharge oil in harmful quantities into nearby lakes or streams.000 gallons and which has discharged.320 gallons.0. event can the discharge have a pH less than 5. and Countermeasure (SPCC) Plan is required if the project would have an aggregate above ground storage capacity of oil which exceeds 1. Discharges cannot contain pollutants which create a fire or explosion In no b) Discharges cannot cause corrosive structural damage to the POTW.2. unless specifically approved by the POTW. or discoloration of the surface of the water or adjoining shorelines. e) Discharges may not contain heat in amounts which will inhibit biological activity in the POTW resulting in interference with the proper operation of the POTW. sheen upon. river. then coordination with the POTW will be required to ensure that the facility has the capacity to accept the discharge and to determine the industrial wastewater treatment charges. Oil discharges are considered harmful to the public health or welfare if they meet either of the following criteria. In no event can the discharge exceed 40 C (104 F). c) Discharges cannot contain solid or viscous pollutants in amounts which will cause obstruction to the flow in sewers or other interference with the operation of the POTW. or lake are prohibited by the Clean Water Act if the discharge is considered harmful. Discharges of oil into any stream. a Spill Prevention. One of the following systems or its equivalent should be used as a minimum. b) Cause a film. a) Cause a violation of applicable water quality standards.MIL-HDBK-1003/7 a) hazard. Control. 199 . To minimize the environmental effects of oil spills. or an aggregate underground storage of oil which exceeds 42.3 Oil Spill Regulations. If the power plant will be discharging to a POTW. d) Discharges cannot be of such volume or pollutant strength as to interfere with the operation of the POTW. or cause a sludge or emulsion to be deposited beneath the surface of the water or upon adjoining shorelines. Appropriate containment and diversionary structures or equipment to prevent discharged oil from reaching a navigable watercourse should be provided.
Spill diversion ponds. c) Inspection. Culverting. The SPCC Plan. Weirs. e) Personnel Training. 200 . in addition to a discussion of the method used as the minimal prevention standard. gutters. signed by the appropriate supervisor or inspector. Sorbent materials. a) Facility Drainage. d) Security. and entrance gates should be locked and guarded when the plant is not in production or is unattended. All bulk storage tank installations should be constructed so that a secondary means of containment is provided for the entire contents of tank plus precipitation. should include a complete discussion of conformance to the following listed guidelines. Facility lighting should be commensurate with the type and location of the facility. local regulations. and any other valves permitting outward flow from the tanks. should be securely locked in the closed position. should be made a part of the plan and maintained for a period of 3 years. b) Bulk Storage Tanks. or other drainage systems. A record of the inspection. or if more strict. and store oil should be fully fenced. or retaining walls sufficiently impervious to contain Curbing.MIL-HDBK-1003/7 a) spilled oil. Drainage from the diked areas should be restrained by valves to prevent spill or leakage from entering into the drainage system unless it is designed to handle such leakage. booms. Valves used for drainage should open and close only by manual operation. berms. A procedure for inspection should be incorporated in the plan. or other barriers. Each applicable facility should have a designated person who is accountable for oil spill prevention and who reports to line management. and consideration should be given to discovery of spills during darkness and prevention of vandalism. process. All plants which handle. b) c) d) e) f) g) Dikes. The master flow and drain valves. Retention ponds.
1 Dumping. the regulatory requirements for disposal of wastes which otherwise could be classified as hazardous can currently be simplified by mixing them with coal combustion wastes. The Resource Conservation and Recovery Act of 1976 (RCRA) replaced the Solid Waste Disposal Act. are classified as nonhazardous. Regulating the treatment. Prohibiting future open dumping on the land and requiring the conversion of existing open dumps to facilities which do not pose a danger to the environment or to health. 18. and scrubber sludge. unless otherwise exempted. This exception for coal combustion wastes has been interpreted by EPA to cover other power plant wastes which are treated or disposed of in conjunction with the ash or scrubber sludge wastes. a) b) c) d) Ignitability. These objectives are to be accomplished by certain steps including the following. and disposal practices and systems. transport.MIL-HDBK-1003/7 18. Corrosiveness.3. Providing for the promulgation of guidelines for solid waste collection. transportation.3 Solid Waste Disposal. Some wastes are designated specifically as being hazardous while others. Storage. and to conserve valuable material and energy resources. it must be handled as a hazardous waste. and disposal of hazardous wastes which have adverse effects on health and the environment. 18. storage.3. If the waste exhibits any of these characteristics.3. 201 . 18. all solid wastes are divided into two categories. Under RCRA. The primary effort to implement RCRA is the task of the individual states. and for listing the hazardous wastes which would be regulated. RCRA significantly expanded the scope of the regulatory authority of EPA in the area of hazardous wastes and solid waste disposal practices.3. hazardous and nonhazardous.3. and Disposal. Under RCRA the EPA was required to develop and issue criteria for identifying the characteristics of hazardous waste. Extraction Process Toxicity.2 Treatment. separation. recovery.1 Hazardous Waste. Consequently. Reactivity. The stated objectives of RCRA are to promote the protection of health and the environment. All wastes at a power plant not included within the coal combustion waste exemption must be tested or compared to each of the following generic characteristics of hazardous wastes. bottom ash. 18. including fly ash.3 Guidelines.
A fence with controlled access around the entire generating facility would suffice. the neutralization tank must meet the following requirements. the regeneration wastes from water treatment systems and the metal cleaning wastes can sometimes meet the corrosiveness test with a pH below 2. e) Any significant spills or leaks of hazardous waste must be reported to the EPA Regional Administrator. must either meet the requirements of a sanitary landfill or must have been closed. 18.3.3. a) Facilities or disposal practices in a flood plain cannot restrict the flow of a 100-year flood.MIL-HDBK-1003/7 At a power plant. and discharges of the waste. operator errors. d) The tank must be constructed of sturdy. or scrubber sludge disposal are as follows. a) The neutralization tank must be in a secure area.3. To qualify for the exception.3 Nonhazardous Waste.2 Totally Enclosed Facilities. RCRA classifies all nonhazardous waste disposal facilities as either sanitary landfills or open dumps. 18. or result in washout of solid waste. A written inspection plan and log must be kept. The portions of these regulations that would be applicable to fly ash. A Hazardous Waste Management Facility (HWMF) permit is not required for any "totally enclosed" facilities used to treat hazardous wastes. or pose a risk of fire or explosion. leakproof material and must be designed. produce uncontrolled toxic vapors. A facility is considered "totally enclosed" if the facility is constructed and operated in a manner which prevents the release of any hazardous waste constituent into the environment. Open dumps are facilities that do not provide adequate protection for health and the environment. and operated so as to prevent hazardous wastes from being spilled or leaked. 202 . b) The neutralization tank must be inspected for equipment malfunctions or deterioration. EPA has promulgated regulations that define more specifically the difference between sanitary land fills and open dumps. All nonhazardous waste disposal facilities. reduce the temporary water storage capacity of the flood plain. c) The treatment process must not generate extreme heat or pressure.3. bottom ash. The process must be conducted so as not to damage the structural integrity of the tank. They are unacceptable under RCRA and they were all to be up graded to a sanitary landfill or phased out within 5 years. then. constructed. A covered neutralization tank is an example of a totally enclosed treatment facility. Sanitary landfills are disposal facilities that do provide adequate safeguards for health and the environment.
Runoff Control.. d) Facilities or disposal practices cannot contaminate an under. In addition to the solid waste regulations already described.MIL-HDBK-1003/7 b) Facilities or disposal practices cannot cause or contribute to the taking of any endangered species or result in the destruction or adverse modification of the critical habitat of such species. operation. and maintenance of solid waste landfill disposal facilities. h) The concentration of explosive gases cannot exceed 25 percent of the lower explosive limit for such gases in facility structures and cannot exceed the lower explosive limit at the site boundaries. g) Facilities or disposal practices cannot engage in open burning. Recommendations are made in the proposed guidelines for landfill disposal of solid waste. Criteria for Classification of solid waste disposal facilities and Practices.g. a) b) c) d) e) f) Site Selection. design. Each area is covered in detail. March 26. Operation. k) Facilities or disposal practices cannot allow uncontrolled public access to the facility. f) Facilities or disposal practices must minimize the population of disease vectors through periodic application of cover material or other techniques as appropriate so as to protect public health. 1979) but has not yet issued guidelines for surface impoundments (e. i) Facilities or disposal practices cannot pose a hazard to the safety of persons or property from fires. Leachate Control. e) Facilities cannot dispose of wastes containing cadmium within 3 feet of the surface of land used for the production of food-chain crops unless the application of such wastes complies with the complex requirements of 40 CFR Section 257. The current set of guidelines shall be referred to when a solid waste disposal landfill facility is needed.ground drinking water source beyond the outermost perimeter of the disposed solid waste as it would exist at the completion of all disposal activity. Design. construction. (Federal Register Volume 44. page 18138. Furthermore. facilities or disposal facilities cannot cause nonpoint source pollution that violates an approved area wide or statewide water quality management plan. Monitoring. EPA has drafted solid waste guidelines to describe recommended considerations and practices for the location.000 feet of any airport runway used by turbojet aircraft or within 5.3-5.000 feet of any airport runway used only by piston-type aircraft cannot pose a bird hazard to aircraft. ash ponds) or landspreading operations for solid waste disposal. 203 . c) Facilities of disposal practices cannot cause a pollutant discharge in violation of the NPDES program or a discharge of dredge/fill material in violation of Section 404 or the CWA and the Dredge and Fill Program. j) Facilities located within 10. EPA has issued a proposed set of guidelines for burial of solid waste. in the following areas.
1 Obstruction or Alteration. Division Engineers are similarly responsible for civil works functions within their Divisions and report to the Chief of Engineers in Washington. The Rivers and Harbors Act of 1899 (RHA) grants authority for the control of structures in navigable waters to the Secretary of the Army and. The construction of any structure in or over any navigable water of the United States. to the Corps of Engineers. District Engineers are responsible for all Federal civil works functions within the boundaries of their respective Districts and report to the appropriate Division Engineer. location. Under the command of the Chief of Engineers. 18.4 Dredge and Fill Regulations. is subdivided into Districts headed by District Engineers.MIL-HDBK-1003/7 18. the excavation from or depositing of material in such waters. or the accomplishment of any other work affecting the course. Section 10 of the RHA prohibits the unauthorized obstruction or alteration of any navigable water of the United States.4. the Corps of Engineers administers the civil functions of the Department of the Army. headed by a Division Engineer. The two major types of activities which are regulated by the Corps are construction work or structure in navigable waters and discharges of dredge or fill material into waters of the United States. or capacity of such waters are unlawful unless the work has been recommended by the Chief of Engineers and authorized by the Secretary of the Army. 204 . DC. through delegation. The administrative organization of the Corps of Engineers for the United States and its possessions consists of 11 "divisions" and 36 "districts" based on watershed boundaries of principal rivers or other hydrologic boundary limits. condition. Each Division.
General categories of activities that are covered by the Corps' Regulatory Program are as follows. or nationwide basis for a category of activities which are essentially similar in nature. Section 11 of RHA authorizes the Secretary of the Army to establish harbor lines channel-ward of which no pier. b) Other structures of work including excavation. Individual permits are issued following a case-by-case review of the project and a determination that the proposed activity is in the public interest. However.4 Regulatory Program. and other devices on the outer continental shelf. While the statutory prohibition of this section is still in effect. c) Activities that alter or modify the course. The Corps has consolidated its civil regulatory functions into one regulatory program so that one permit will constitute the authorization required by all the various statutes administered by the Corps. a) Dams or dikes in navigable waters of the United States. the Secretary of the Army has waived its Section 13 permit authority in view of the permit authority provided the EPA Administrator under Sections 402 and 404 of the CWA. Division Engineers can override general permits and require the activity to be authorized by an individual permit. location.2 Harbor lines.MIL-HDBK-1003/7 18. or capacity of a navigable water.4. and/ or disposal activities. the discharge of refuse is prohibited. 18. 18. and will cause only minimal adverse environmental effects when performed separately. or other works may be extended or deposits made without approval of the Secretary of the Army. dredging. condition. d) Construction of artificial islands. The Corps of Engineers is authorized to issue general permits on a state. a permit application is not necessary to obtain a general permit. installations. f) Activities involving the transportation of dredged material for the purpose of disposal in ocean waters. Since a general permit is "automatically" issued upon compliance with certain conditions. The authorization required for activities subject to the Corps' regulatory program can be either a general or individual permit.3 Discharge of Refuse. General permits can be issued on either a nationwide or regional basis. may permit the discharge of refuse into navigable waters. 205 .4. In the absence of a permit. bulk heads. regional. and will have only minimal cumulative adverse effects on the environment.4. wharves. e) Discharges of dredged or fill material into waters of the United States. whenever the Chief of Engineers determines that anchorage and navigation will not be injured. Section 13 of the RHA provides that the Secretary of the Army.
The individual states may request to administer the dredge and fill permit program within their jurisdiction. The Corps of Engineers will transfer to the state pending applications for the state to issue the appropriate permits. 18.4. The state may also elect to administer and enforce the issuance and enforcement of the general permits issued by the Corps of Engineers. then the permit can be issued but must contain the conditions of the exemption.6 EPA guidelines. To request this delegation. If an exemption for the project is obtained from the Endangered Species Committee.MIL-HDBK-1003/7 18. toxic effluent standard. regional permits and individual permits and the considerations required of each type of permit.nationwide permits. c) No discharge of dredge or fill material can be permitted if it jeopardizes the continued existence of any listed endangered or threatened species. The EPA dredge and fill guidelines must be used by the Corps of Engineers to evaluate the effects of the proposed discharge of dredge and fill material. This enforcement will be effective when the state receives approval of its program from EPA and gives notification to the Corps of Engineers. or any requirement imposed by the US Department of Commerce to protect any marine sanctuary. 206 . the Corps of Engineers cannot issue a permit for the discharge under the following circumstances. The fundamental precept of this review is that the discharge should not be approved unless it can be demonstrated that such a discharge will not have an unacceptable adverse impact. and will notify the Corps of Engineers when the program has been approved. but only for ultra state waters. or results in the likelihood of the destruction or adverse modification of a critical habitat. Upon receipt of the notice.4.5 State Permit Program. so long as the alternative does not have other significant adverse environmental consequences. the Corps of Engineers will suspend the administration and enforcement of the general permit activities within the state. Paragraph 18. a) No discharge of dredge or fill material can be permitted if there is a practicable alternative to the proposed discharge which would have less adverse impact on the aquatic ecosystem. the Governor of the state must submit a request to the EPA Administrator which includes a full and complete description of the program the state proposes to administer. Under these guidelines. EPA will review the application and statutory authority of the state. b) No discharge of dredge or fill material can be permitted if it would cause or contribute to a violation of any water quality standard.5 describes each of the three types of permits .
The guidelines specify that significantly adverse effects upon the following items must be considered. c) Alternatives to the proposed actions.5. esthetic.MIL-HDBK-1003/7 d) No discharge of dredge or fill material can be permitted which would cause or contribute to significant degradation of any waters of the United States. (1) (2) ecosystems. and stability. 18.1. Human health and welfare.1. (3) (4) Aquatic ecosystem diversity. This determination of the significance of the project's impacts requires consideration of the context and intensity of the effects of the entire project on the environment. Recreational. a) The environmental impact of the proposed action. e) Any irreversible and irretrievable commitment of resources which would be involved in the proposed action should it be implemented. A new fossil-fueled steam power plant on a military facility would be a "major Federal action. and economic values. The National Environmental Policy Act (NEPA) requires that all major Federal actions which significantly affect the quality of the human environment must be accompanied by an Environmental Impact Statement (EIS) which evaluates the following.5. Federal regulations implementing NEPA have been promulgated by the Council on Environmental Quality (CEQ). productivity. 18. b) Any adverse environmental effects which cannot be avoided should the proposal be implemented. Permits Environmental Impact Statements 18.5.5 18. 207 .1 NEPA. Life stages of aquatic life and other wildlife dependent on aquatic e) No discharge of dredge or fill material can be permitted unless appropriate and practicable steps have been taken which will minimize potential adverse effects on the ecosystem." A determination must be made whether the Federal action "significantly affects" the quality of the human environment.2 CEQ. d) The relationship between local short-term uses of man's environment and the maintenance and enhancement of long-term productivity.
when.5.This single page must include a list of all Federal agencies involved in the EIS preparation. the agency will issue a Finding of No Significant Impact (FONSI) and no EIS is necessary. d) Alternatives .This section must briefly specify the underlying purpose and need for the project.1. it must publish a notice of such intent in the Federal Register describing the proposed action. 18. An EA should include a brief discussion of the need for the proposed project.MIL-HDBK-1003/7 This decision is usually made as a case-by-case basis. a designator of whether the EIS is a draft. These alternatives must include the alternative of no action and all reasonable alternatives not within the jurisdiction of the Navy.4 Federal Register. All reasonable alternatives must be rigorously explored and objectively evaluated.5 Format. and state the name and address of a person within the agency who can answer any questions concerning the action. possible alternatives. a one paragraph abstract. 208 . project alternatives. If the EA concludes that the proposed project will significantly affect the human environment. c) Purpose and Need . the title of the proposed action. and where any scoping meeting will be held. and telephone number of the person to con tact for more information. and the scoping process. Appropriate mitigation measures must be included. The notice should include whether.1. If the Navy commits itself to prepare an EIS. 18. 18. or draft/final supplement. The Navy can prepare an Environmental Assessment (EA) to assist it in making the impact significance determination. the agency will proceed to prepare an EIS. the name. a) Cover Sheet .3 Environmental Impact Statements. and the date by which comments must be received.5. b) Summary . The reasons behind the elimination of any alternative must be disclosed. the environmental impacts of the proposed projects and its alternatives. The CEQ regulations specify the following format and general information categories to be contained in an EIS. If the EA's conclusion is that the proposed project would not significantly affect the human environment.1.This section must accurately and adequately summarize the EIS and must stress the major conclusions and any remaining issues to be resolved. and a listing of agencies and persons consulted during preparation of the EA. Each remaining alternative must be considered and discussed in depth.5. final. address.This section should compare the environmental impacts of the proposal and the alternatives. The preferred alternative must be identified.
g) h) List of preparers Index.10 Time Period. any adverse environmental effects which cannot be avoided. The EPA then files a copy with the Council and publishes a notice in the Federal Register of the filing. The final EIS must also be circulated for comments to all those who received copies of the draft as well as to those who made substantive comments upon the draft EIS. mitigation measures. which is later. 18. energy and natural or depletable resource requirements and conservation potentials. and any irreversible or irretrievable commitment of resources.This section consists of material which is prepared for.1. The discussion should include direct and indirect effects and their significance. The Navy must consider its decision for at least 90 days after the Federal Register notice of the filing of the draft EIS or 30 days after the Federal Register notice of the filing of the final EIS.5. and to anyone requesting the EIS. substantiates.1. The Navy must respond in the final EIS to all comments upon the draft EIS. 209 .6 Draft EIS. or is incorporated by reference in the EIS.5. the relationship between the short-term uses of man's environment and the maintenance and enhancement of long-term productivity. f) Environmental Consequences . it is filed with EPA. When the draft EIS is completed. improvements. or modifications to its analyses. environmental effects. 18. 18. The EPA then files a copy with the Council and publishes a notice in the Federal Register of the filing. Possible responses are modifications to the alternatives including the proposal.9 Final Comment. These periods may run concurrently. i) Appendices .This section must include a discussion of the environmental impacts of the proposal and its alternatives. and explanations why the comment(s) did not warrant further Navy response. including the reuse and conservation potentials. supplements.7 Coordination.MIL-HDBK-1003/7 e) Affected Environment . The draft EIS is circulated to any other Federal agency which has jurisdiction by law or special expertise with respect to any environmental impact involved. state.1. possible conflicts between the proposal and the objectives of any affected governmental unit.1. development and evaluation of new alternatives. 18.5. The final EIS is filed with EPA. or local agency authorized to develop and enforce environmental standards.5. to any Federal. factual corrections. The minimum comment period is 45 days.8 Resolution.1. historic.This section must sufficiently describe the environment of the area(s) to be affected or created by the alternatives under consideration.5. and cultural resources and the design of the built environment. 18. Also include urban quality.
b) The proposed permit has been duly reviewed and a public hearing is held with opportunity for interested persons to appear and submit written or oral presentations on the air quality impact of the source. it will not be regulated under the PSD program unless it has the potential to emit 250 tons per year or more of any of the pollutants. Figure 47 presents the principal steps in the new source review process. 210 .2. a unit may be subject to the NSPS but not need a PSD permit. alternatives. Even if a unit is not subject to the Federal NSPS. The new source review is a rather complex process. control technology requirements. or particulate matter. it may need a PSD permit. Conversely.5. 18. then S02 will follow PSD requirements while particulate matter will follow the nonattainment path of offsets and Lowest Achievable Emission Rate (LAER). This permit is called a "new source review" although it is also frequently called a "PSD permit" for prevention of significant deterioration. Different pollutants may take different paths through the process even though they may be from the same source.2. if the area where the source is located is attainment for sulfur dioxide but nonattainment for particulate matter. In order to achieve this goal. and other appropriate considerations. The permit is required before construction begins on the power plant.1 New Source Permits. The purpose of the PSD Program is to ensure that new major sources of air pollution do not significantly degrade existing ambient air quality.MIL-HDBK-1003/7 18.2 Purpose. The PSD program is triggered in clean air areas where the proposed unit is larger than 250 million Btu per hour heat input rate and has a potential to emit 100 tons per year or more of SO2. However in this case the emission from separate new units or modifications on the same site will be added together. NOx. construction of new major source cannot commence until after receiving approval from EPA or a state which has been delegated PSD authority by EPA. A permit under the Federal Clean Air Act may be required. a) Appropriate emission limitations have been established.5.2 Air Permits 18.5. If the unit is less than 250 million Btu per hour heat input rate. A number of steps must be accomplished for each pollutant to be emitted. The following requirements must be fulfilled before a PSD permit can be issued. For instance. Actually a new source review can involve both a PSD permit and a nonattainment review.
g) monitoring. or any applicable emission standard or standard of performance.0004 0. BACT is required for each pollutant emitted by a major source if the allowable emissions are in excess of de minimis amounts specified above. Frequently. f) An analysis of air quality impacts projected for the area as a result of growth associated with the facility is performed. One of the PSD permit requirements listed earlier was that the facility must be designed in accordance with best available control technology (BACT).5.6 0. 212 .5.007 0. d) e) The facility is subject to best available control technology. Class I areas are protected.MIL-HDBK-1003/7 c) Emissions from construction or operation of the facility must be shown not to cause or contribute to air pollution in excess of the allowable increments or allowable concentration more than once per year.2. The BACT requirement will be applied on a pollutant-by-pollutant basis. Pollutant Carbon Monoxide Nitrogen Oxides Sulfur Dioxide Particulate Matter Total PM-10 Ozone (Volatile Organic Compounds) Lead Asbestos Beryllium Mercury Vinyl Chloride Fluorides Sulfuric Acid Mist Hydrogen Sulfide (H2S) Total Reduced Sulfur (Including H2S) Reduced Sulfur Compounds (Including H2S) Emission Rate tons per year 100 40 40 25 15 40 0. 18. BACT requires the imposition of emission controls capable of at least complying with the applicable new source performance standards and with all applicable state emission limitations. Once a unit is determined to require a PSD permit. then the review will extend to all pollutants which exceed the following "de minimis" amounts.1 1 3 7 10 10 10 An agreement is reached to conduct necessary ambient air quality 18. any national ambient air quality standard.4 Best Available Control Technology.3 De Minimis Amounts. the BACT review will result in a permitted emission limitless than the new source performance standards.2.
the control technology required. state. 18. In the event of a deficiency. approve with conditions. determination. A PSD permit will not be issued if the proposed source will have an adverse impact on visibility within any protected Class I area or integral vista. f) Consider all comments and issue final determination. and other appropriate considerations. Although a year of monitoring data is usually required. The general outline for consideration and issuance of the approval is as follows. a shorter period of data can be accepted if a complete and adequate analysis can be performed. EPA is granted a period of one year from receipt of a complete PSD permit application to make a final determination. protection. the date of receipt of the application is the date all information is provided. Consequently.5. a) A preliminary determination is made to approve. preservation. An analysis of ambient air quality at the site must be conducted as part of the PSD review.2. the project will be subject to a nonattainment review for that pollutant. and local agencies. alternative to the source. d) Send a copy to other Federal. e) Provide opportunity for public hearing on air quality impact. 213 . The EPA regulations specify that at least 4 months of monitoring data are required.2.5 Class I Areas. An adverse impact on visibility is defined as visibility impairment which interferes with the management. 18. and other materials used.7 Nonattainment Areas. However. EPA will examine the initial PSD permit application and within 30 days will advise the applicant of any deficiency in the application or additional information required. and advise of opportunity for hearing. If the project's emissions significantly affect ambient concentrations of a nonattainment pollutant within the nonattainment area.5. c) Notify public of the application. and amount of increment consumed.6 Ambient Air Data. The project's emissions are deemed to significantly affect a nonattainment area if the ambient air quality impact of those emissions exceed the values shown in Table 33.5. or disapprove the request. a copy of preliminary determination. and not the initial filing date. b) Make available all materials provided by applicant.2. the PSD permit application must contain continuous air quality monitoring data for each pollutant emitted in excess of the de minimis amounts. or enjoyment of a visitor's experience of a mandatory Class I area. the monitoring requirement is waived for any pollutant if the emissions from the proposed source would have maximum modeled air quality impacts less than certain amounts specified by the EPA.MIL-HDBK-1003/7 18.
214 . with all applicable Federal and state emission limitations and standards. or under common control with such person) in the state are subject to emission limitations and are in compliance. or on a schedule for compliance.0 ----* * NOx * CO --500 -2. d) The most stringent emissions limitation imposed by any state on a similar source unless proven not be achievable.0 5 -5 -* * SO2 * TSP 1. Air quality modeling must predict the emission offsets will cause a positive net air quality benefit in that portion of the nonattainment area affected by emissions from the proposed source.0 5 ---* 1. c) The owner or operator of the proposed source must obtain sufficient emission reductions to offset the impacts within the nonattainment area of the source's emissions of the nonattainment pollutant.)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))- The following demonstrations are required by a nonattainment review. e) The most stringent emissions limitation achieved in practice by a similar source.MIL-HDBK-1003/7 Table 33 Significance Levels (in micrograms per cubic meter) +))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). a) The project will comply with the lowest achievable emission rate (LAER). or 2) the most stringent emissions limitation achieved in practice by a similar source.000 * . Averaging Times * * Pollutant * Annual 24-hour 8-hour 3-hour 1-hour * 1. LAER is defined as the more stringent of 1) the most stringent emissions limitation imposed by any state on a similar source unless proven not to be achievable. b) The owner or operator of the proposed source must demonstrate that all major stationary sources owned or operated by such person (or by an entity controlling. controlled by.
or b) Construction on a site at which another source is located of a building. Consult the air pollution control agency in the state where the power plant will be built. both the NPDES permit and a separate state wastewater discharge permit will be required. A separate state or local construction and operating permit may be needed for the power plant. Permits will be issued by EPA only if the applicable effluent limitations are met. facility. 18.8 Local Permits.3. 18. from the state in which the discharge originates. reporting. the certification should be from the EPA Administrator.2. 18. No license or permit may be granted until the certification has been obtained or waived by the appropriate agency. the process or production equipment that causes the discharge of pollutants from the existing source is totally replaced by this construction. contiguous zones.2 Federal License or Permit.5. Any point source discharge of a pollutant to the navigable waters not authorized by a National Pollution Discharge Elimination System (NPDES) permit is unlawful. that any such discharge will comply with applicable provisions of the Clean Water Act (CWA). In these not approved. is authorized to prescribe conditions on the permit to assure compliance with applicable effluent limitations including conditions on data and information collection.5. EPA. About thirty of the states have been approved for this delegation. Applicants for a Federal license or permit to conduct any activity which may result in any discharge into the navigable waters are required to provide the permitting agency a certification. or the construction results in a change in the nature or quantity of pollutants discharged.MIL-HDBK-1003/7 18. and other such requirements as it deems necessary. No NPDES permit will be issued except in compliance with these guidelines for discharges into water of these seas. 18. or oceans.3 Wastewater Discharge Permit.5.3. EPA has specified that the following construction activities result in a new source. and the oceans. when issuing a permit.5. EPA is directed to promulgate guidelines for determining the degradation of the waters of the territorial seas. EPA may authorize a state to carry out the provisions of the permit program if the state can show it has enacted legislation and regulations to conform to the guidelines promulgated by EPA. a) located.5. In any case where a state or interstate agency has no authority to give such a certification.1 State Permit Program. Any person who proposes to discharge pollutants and does not have an effective permit must complete an NPDES application. or installation from which there is or may be a discharge of pollutants. the contiguous zone.3. structure. Construction of a source on a site at which no other source is 215 .3 New Source.
Any placement. conduits. EPA may also seek a court order to enjoin construction in violation. structure.6 Storm Sewers and Conveyances. facility. assembly.4 Environmental Impact Statement. b) Significant site preparation work which is necessary for the placement. 18. assembly. or installation from which there is or may be a discharge of pollutants but otherwise alters.5. ditches. or.5. replaces. 18. or installation of new source facilities or equipment. is to commence before all appropriate EIS-related requirements have been incorporated in the project and a final permit is issued. before execution of a legally binding written agreement by the applicant requiring compliance with all such requirements. for which an Environmental Impact Statement (EIS) is required. and channels) used primarily for collecting and conveying storm water runoff. or installation of facilities or 216 . or adds to existing process or production equipment. The permit applicant must notify EPA of any on-site construction which begins before the above specified times.3. 18. No on-site construction of a new source. Separate storm sewers are point sources subject to the NPDES permit program which may be permitted either individually or under a general permit.MIL-HDBK-1003/7 c) Construction on a site at which an existing source is located results in a modification rather than a new source if the construction does not create a new building. If on-site construction begins in violation of regulations.3. unless EPA determines that such construction will not cause significant or irreversible adverse environmental impact. c) Entering into a binding contractual obligation for the purchase of facilities or equipment which are intended for use in its operation within a reasonable time. Construction of a new source is considered to have commenced when the owner or operator has begun or caused to begin as part of a continuous on-site construction program: a) equipment.5 Violation of Regulations. the owner or operator is proceeding at its own risk and such construction activity constitutes grounds for denial of a permit. No on-site construction of a new source for which an EIS is not required may commence until 30 days after the issuance of a finding of no significant impact unless EPA determines that the construction will not cause significant or irreversible adverse environ mental impact.5.3. Separate storm sewer is defined as a conveyance or system of conveyances (including pipes.
EPA recommends filing much earlier. from lands or facilities used for industrial or commercial activities. A NPDES permit will be issued for a term not to exceed five years. EPA requires an application for a NPDES permit to be filed at least 180 days before the discharge is to begin. or biological warfare agent or high-level radioactive waste. 18. 217 . chemical.3. The other part of the NPDES permit application for a proposed facility is to adapt Form 2C (for existing facilities) to reflect the fact that there are no discharges from the project yet.MIL-HDBK-1003/7 Conveyances which discharge storm water runoff contaminated by contact with wastes. g) To a new source of a new discharger.5. or regulations promulgated under the CWA. raw materials. f) For any discharge inconsistent with a plan or plan amendment approved under Section 208(b) of the CWA.7 Filing Date. b) When the applicant is required to obtain a state or other appropriate certification under Section 401 of the CWA and that certification has not been obtained or waived. 18. anchorage and navigation in or on any of the waters of the United States would be substantially impaired by the discharge. e) For the discharge of any radiological. a) When the conditions of the permit do not provide for compliance with the applicable requirements of the CWA. in view of the environmental review required of new sources. However. EPA will not issue an NPDES permit under any of the following circumstances. The NPDES permit application consists of two consolidated forms. or pollutant-contaminated soil. c) When the imposition of conditions cannot ensure compliance with the applicable water quality requirements of all affected states.3. into waters of the United States or into separate storm sewers are point sources that must obtain NPDES permits.8 NPDES Permit. Form 1 is a general information form about the applicant the proposed facility. The conditions of an NPDES permit issued to a source which is subject to a new source performance standard (NPDES) cannot be made more stringent for the shortest of the following intervals. if the discharge from its construction or operation will cause or contribute to the violation of water quality standards. d) When in the judgment of the Corps of Engineers.5.
Proper operation and maintenance includes effective performance.3. or for denial of a permit renewal application. (2) Ten years from the date the source begins to discharge process or other nonconstruction-related wastewater. b) The permittee must take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with the permit. conditions based upon compliance with water quality standards or toxic effluent standards) or to toxic/hazardous pollutants not subject to any limitation in the applicable new source performance standard. adequate operator staffing and training. Violation of any permit condition will not be excused on the grounds that it would have been necessary to halt or reduce the permitted activity in order to remain in compliance. adequate funding. 18. and adequate laboratory and process controls. c) The permittee must at all times properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of the permit. revocation and reissuance. This condition requires the operation of backup or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of the permit. (3) The period of depreciation or amortization of the facility for the purposes of Section 167 or 169 (or both) of the Internal Revenue Code of 1954. including appropriate quality assurance procedures. or modification. upon the showing of any documents required by law. However. the protection from more stringent conditions does not extend to limitations not based upon technological considerations (e. d) privilege. Failure to do so is grounds for enforcement action.9 permits. to conduct the following actions. for permit termination.5.MIL-HDBK-1003/7 (1) Ten years from the date that construction is completed.g. The permit does not grant any property rights or any exclusive 218 .. NPDES Permit Conditions. The following conditions are applicable to all NPDES a) The permittee must comply with all conditions of the permit. e) The permittee must allow EPA or its authorized representative.
The results of such analyses. h) All monitoring records must be kept for a minimum of three years. To inspect any activities regulated by the permit. j) All monitoring results must be reported on a Discharge Monitoring Report. Monitoring records include the following data. The individual(s) who performed the sampling or measurements. unless other procedures are specifically approved by EPA. period can be extended by EPA. All results must be reported. and time of sampling or measurements. f) The permittee must provide EPA with any requested information pertinent to any permit action contemplated by EPA.MIL-HDBK-1003/7 (1) (2) (3) (4) To enter upon the permittee's premises. g) All samples and measurements taken for the purpose of monitoring must be representative of the monitored activity. To sample any waste streams regulated by the permit. and endanger health or the environment a written report must be submitted j) All monitoring must be conducted according to test procedures approved by 40 CFR 136. notify EPA of any planned changes to the facility. This i) The permittee must any anticipated noncompliance. All averages must be done on an arithmetic basis. Any noncompliance which may must be reported verbally to EPA within 24 hours and within five days. any permit transfer. (1) (2) (3) (4) (5) (6) The date. Guidelines establishing test procedures for the analysis of pollutants. The analytical techniques or methods used. The individual(s) who performed the analyses. To have access to and copy any records required by the permit. 219 . k) Any unanticipated bypass or upset which exceeds any permit effluent limitation must be reported to the EPA within 24 hours. The date(s) analyses were performed. exact place.
monitoring activities (e. and the reporting of monitoring results. 18. or could reasonably be expected to discharge oil in harmful quantities into nearby lakes or streams. The permit will contain requirements to monitor the mass (or other measurement related to any effluent limitation) for each pollutant regulated by the permit. The SPCC must be prepared within 6 months after the plant begins operation and must be implemented not later than one year after the plant begins operations.320 gallons.MIL-HDBK-1003/7 Noncompliance caused by a bypass can be an actionable violation. and installation).4 Oil Spill Plan.. and he must attest that the SPCC Plan has been prepared in accordance with good engineering practices. The PE certification would also include a statement that the SPCC Plan conforms to the requirements of EPA's regulations. personal injury. a single aboveground container larger than 660 gallons. The plan must be reviewed by a registered Professional Engineer (PE). overflow. intervals. or leakage). but noncompliance caused by an upset will always be excused. The permit can also require reporting within 24 hours of violation of a maximum daily discharge limitation for any pollutant of special concern to EPA. or severe property damage. careless or improper operation. An upset does not include noncompliance caused by lack of preventive maintenance. EPA has proposed revisions to the SPCC Plan regulations. The changes would require the SPCC Plan to be fully implemented when the plant begins commercial operation. Almost all power plants have this much oil after transformer oils and lube oils are considered. or an aggregate underground storage of oil which exceeds 42. or lack of backup equipment for use during normal periods of equipment downtime or preventive maintenance. proper use. the plan should include a prediction of the direction. and Countermeasure (SPCC) Plan is required if the project would have an aggregate underground-aboveground storage capacity of oil which exceeds 1. maintenance. rate of flow.g. A bypass is an intentional diversion of a waste stream from any portion of a treatment facility when there are no feasible alternatives to bypassing and it is necessary to bypass in order to avoid loss of life. and frequency). The permit will specify requirements concerning the monitoring equipment (e.5. The SPCC Plan need not be submitted but merely available to the EPA for inspection at the plant. A Spill Prevention. Where experience indicates a reasonable potential for equipment failure (such as tank rupture.. An upset is an exceptional incident in which there is unintentional and temporary noncompliance with technologically-based effluent limitation because of factors beyond the reasonable control of the permittee. If the plan is not completed on time.000 gallons and which has discharged. 220 . and total quantity of oil which could be discharged from the facility as a result of each major type of failure. type.g. Control. a request can be made to the EPA Regional Administrator for an extension. the volume of effluent discharged from each outfall and any other relevant information.
g.5 Solid Waste Disposal Permit. a leak detection system located between the liners. constructed. h) All hazardous waste management facilities located in a 100-year flood plain must be designed. or any unplanned release of hazardous waste. operator errors. 221 . unless washout of the waste would have no adverse effects on human health or the environment. Compliance with the following requirements is a prerequisite for obtaining the permit. b) The HWMF must be inspected for equipment malfunctions or deterioration. e) A written operating record is required.. treated. explosions. and access to emergency equipment. g) All hazardous waste management activities must be conducted at least 200 feet from any fault which has had displacement in the Holocene time. a method of summoning emergency assistance.5. and a leachate collection and removal system located on top of the uppermost liner). A written inspection plan and log must be kept. or disposed of by methods other than those described above. and discharges. the HWMF must have an alarm system to warn personnel of emergencies. a) The HWMF must be in a secure area. i) A ground water monitoring program meeting the requirements of 40 CFR 264. or landfill which handles hazardous waste unless EPA determines that there is no potential for migration of leachate from the hazardous waste facility to the uppermost aquifer. operated. Facilities in jurisdictions other than those listed in Appendix VI of 40 CFR 264 are assumed to comply with this requirement. The contingency plan must be designed to minimize hazards of human health and the environment from fires. f) All personnel must be trained to handle the hazardous waste safely and in compliance with all permit requirements and conditions.98 is required for any surface impoundment. or unless the facility is exempted from ground water monitoring because of its design (e. If any hazardous wastes are stored. waste pile. land treatment facility. a Hazardous Waste Management Facility (HWMF) permit must be obtained from EPA. or unless the waste can be safely moved to an upland site before flood waters can reach the facility. and a biannual report must be filed with EPA.MIL-HDBK-1003/7 18. and maintained to prevent washout of any hazardous waste by a 100-year flood. c) Unless EPA agrees that such equipment is not necessary. landfills are exempted from ground water monitoring if they have a double liner system located entirely above the seasonal high water table. d) A contingency plan must be prepared.
a combination thereof. Tanks--40 CFR 264. treat.199. The HWMF must also have liability coverage in the amount of at least $3 million per occurrence with an annual aggregate of at least $6 million (exclusive of legal costs) for claims arising from nonsudden accidental occurrences that cause bodily injury or property damage.MIL-HDBK-1003/7 j) A written closure plan must be prepared. Financial assurance for closure of the HWMF must be provided through a trust fund. a compliance ground water monitoring program must be initiated. (2) If leachate is detected.170 to 264.190 to 264. or self-insurance. Surface Impoundments--40 CFR 264. The closure plan should minimize the need for further maintenance and the post closure escape of hazardous waste constituents. a corrective action program must be initiated. letter of credit. (1) A ground water sampling program to detect the presence of leachate containing hazardous constituents at the compliance point. a) b) c) Containers--40 CFR 264. m) Landfills and surface impoundments used to store. or dispose of hazardous waste must have a ground water protection plan unless the facility has a double liner equipped with a leak detection system or the EPA deter mines that there is no potential for migration of liquid from the facility to the uppermost aquifer. surety bond. The ground water protection plan must consist of the following three phases. (3) Whenever a ground water protection standard is exceeded. l) The HWMF must be covered by liability coverage in the amount of at least $1 million (exclusive of legal defense costs) for claims arising from sudden and accidental occurrences that cause injury to persons or property. This liability coverage can be provided by liability insurance and/or self-insurance. 222 .178.230. k) A written estimate of the cost of implementing the closure plan and of post-closure monitoring and maintenance must be prepared.220 to 264. insurance. The EPA has also issued the following regulations governing waste handling practices or equipment at new HWMFs.
18. wet meadows. An estimate of the scope of the future regulations for other specific waste handling practices can be made upon examination of the following regulations for existing HWMFs. prairie potholes.382. or may be susceptible to use in interstate or foreign commerce. Incinerators-. rivers. playa lakes. including any such waters which are or could be used by interstate or foreign travels for recreational or other purposes. The states standards and permit requirements will need to be examined for specific details applicable to any proposed facility. the individual permit.405.5.270 to 264. streams (including intermittent streams). must be applied for when neither of the other two are available.351. and individual permits. the use. a) Waters of the United States--This term includes the following waters. Dredge and fill permits for the Corps of Engineers may be of three types: Nationwide permits. or from which fish or shellfish are or could be taken and sold in interstate or foreign commerce. Nonhazardous solid waste disposal permits will be issued by the State where the facility is located. including all waters which are subject to the ebb and flow of the tide. sandflats. mudflats.282. wetlands.MIL-HDBK-1003/7 d) e) f) g) Waste Piles--40 CFR 264.430. degradation or destruction of which could affect interstate or foreign commerce. Landfills--40 CFR 264.40 CFR 264.250 to 264. 223 .316. a) b) c) Thermal Treatment--40 CFR 265.300 to 264.340 to 264. (1) All waters which are currently used. (2) All interstate waters including interstate wet lands. or natural ponds. In assessing the applicability of the Corps' regulatory program to a proposed project activity. Land Treatment--40 CFR 264. and Biological Treatment--40 CFR 265.258. or were used in the past.6 Dredge and Fill Permit. Physical. The first two types authorize dredge and fill without having to obtain specific approval provided all appropriate conditions and notifications are met. Chemical.373 to 264. sloughs. or which are or could be used for industrial purposes by industries in interstate commerce. the following definitions should be utilized. The third type. regional permits. Underground Injection--40 CFR 265. (3) All other waters such as intrastate lakes.
Wetlands separated from other waters of the United States by manmade dikes or barriers. destruction of terrestrial vegetation. marshes. or other appropriate means that consider the characteristics of the surrounding areas.) f) Ordinary High Water Mark--This term means the line on the shore established by the fluctuations of water and indicated by physical characteristics such as a clear. and similar areas. b) Navigable Waters--This term means those waters that are subject to the ebb and flow of the tide and/or are presently used. a prevalence of vegetation typically adapted for life in saturated soil conditions. beach dunes. contiguous. including treatment ponds or lagoons designed to meet the requirements of CWA. settling basins. natural river berms. are not waters of the United States. natural line impressed on the bank. irrigation. The territorial sea. d) Adjacent--This term means bordering. which also meet the criteria of this definition may be waters of the United States. shelving. 224 . Wetlands generally include swamps. Note: Waste treatment systems. or may be susceptible for use to transport interstate or foreign commerce (see 33 CFR 329 for a more complete definition). (Artificial lakes created by excavating or diking dryland to collect and retain water for stock watering. (5) (6) (7) All impoundments of waters otherwise defined as waters of the Tributaries of any of the above waters. changes in the character of the soil. c) Wetlands--This term means areas that are inundated or saturated by surface or ground water at a frequency and duration sufficient to support. or neighboring. Cooling ponds. or rice growing are not included. bogs. the presence of litter and debris. as defined by 40 CFR 123. cooling. do support.11(m). or tidal area. Wetlands adjacent to any of the above waters. and the like are "adjacent wetlands. that occurs due to the widening or natural blockage or cutoff of a river or stream. or have been used in the past. or that occurs in an isolated natural depression that is not a part of a surface river or stream.MIL-HDBK-1003/7 (4) United States." e) Lakes--This term means a standing body of water that occurs in a natural depression fed by one or more streams from which a stream may flow. and that under normal circumstances.
j) Dams and Dikes--Either term means an impoundment structure. or along shore objects that indicate the intersection of the land with the water's surface at the maximum height reached by a rising tide. For intermittent streams. any fill material required in connection with construction of facilities in waters of the United States is considered a discharge of fill material. m) Discharge of Dredged Material--This term includes the addition of dredged material to a specified discharge site located in waters of the United States.) o) Discharge of Fill Material--This term means the addition of any fill material to waters of the United States. permanent mooring structure.MIL-HDBK-1003/7 g) High Tide Line--This term means the line or mark left upon tide flats. the point at which a flow of 5 cubic 50 percent of the time. any pier. h) Headwaters--This term the average annual flow is less than 5 the criterion may be the median flow. (The discharge of wastewater is not considered fill material and is regulated by the NPDES Permit Program. permanently moored floating vessel. excavation. foot per second is equaled or exceeded means the point on a national stream above which cubic feet per second. filling. wharf. riprap. l) Dredged Material--This term means any material dredged or excavated from waters of the United States. piling. that completely spans a navigable water of the United States and that may obstruct inter state waterborne commerce. weir. and runoff from or overflow from a contained land or water disposal area. Generally. k) Work--This term means any dredging or disposal of dredged material. except a weir. or other modification of a navigable water of the United States. The term includes spring high tides and other high tides that occur with periodic frequency. revetment. without limitation. power transmission line. i) Structure--This term means. dolphin. beaches. 225 . boom. or any other obstacle or obstruction. but does not include storm surges. breakwater. aid to navigation. n) Fill Material--This term includes any material used for the primary purpose of replacing an aquatic area with dryland or of changing the bottom elevation of any body of water. bulkhead. jetty. That is.
d) Survey activities including core sampling. that are located above the headwaters. water recording devices. and 2) Other non-tidal waters that are not part of a surface tributary system to interstate or navigable waters.6. and similar scientific structures. This type of nationwide permit requires compliance with the following conditions. 18.5. or replacement of a previously authorized facility. 226 .1 Nationwide Permits. c) The fill created by the discharge of dredge or fill materials must be properly maintained to prevent erosion and other nonpoint sources of pollution. seismic exploratory operations. the work must not result in significant deviations from the original plans. a) The discharge of dredge and fill material must not destroy a threatened or endangered species as identified under the Endangered Species Act or endanger the critical habitat of such species. However.2 Activities Authorized by a Nationwide Permit a) The placement of aids to navigation and regulatory markers which are approved by and installed in accordance with the requirements of the US Coast Guard. d) The discharge of dredge or fill materials must not occur in a component of the National Wild and Scenic Rivers System or in a component of a state wild and scenic river system. b) The discharge of dredge or fill materials must consist of suitable material free from toxic pollutants in other than trace quantities. streams. rehabilitation.5. and their lakes and impoundments.MIL-HDBK-1003/7 18.6. tide gages. and plugging of seismic shot holes and other exploratory-type bore holes. Maintenance dredging is not authorized by this nationwide permit. and the uses of the facility must not have been changed. c) Staff gages. Discharges of dredge and fill material into the following waters are authorized by a nationwide permit: 1) Non-tidal rivers. including any adjacent wetlands. The facility must be currently serviceable. a state can revoke a nationwide permit by refusing to grant the water quality certification required by Section 401 of the CWA. water quality testing and improvement devices. b) The repair. e) The best management practices listed later in this section should be followed to the maximum extent practicable.
the crossing will require a permit from the US Coast Guard. and discharges authorized by the Department of the Interior.500 kW which are licensed by the Department of Energy (DOE) under the Federal Power Act. Furthermore. (Intake structures by themselves are not included--only those directly associated with an outfall structure are covered by this nationwide permit. o) Activities. work. j) Return water from a contained dredged material disposal area if the state has issued a Section 401 water quality certification. the material must be "clean fill. and discharges included under categorical exclusions from environmental documentation by other federal agencies if the Office of the Chief of Engineers has been notified of the exclusion and agrees with it.) f) The discharges of material for backfill and bedding for utility lines and outfall and intake structures if no change in preconstruction bottom contours occur and excess material is removed to an upland site. l) Discharges of dredged or fill material of 10 cubic yards or less into waters of the United States if no material is placed in a wetland. and he determines that the individual and cumulative adverse effects are minimal. Causeways and approach fills are not included and will require individual or regional permits. (The dredging itself requires an individual permit if it occurs in navigable waters of the United States. ("Utility line" includes pipelines. h) Temporary and permanent minor road crossing fills of a non-tidal body of water if designed so that the crossing can withstand expected high flows of surface water and will not restrict such flows. no material can be placed in a wetland. q) The discharge of concrete into tightly sealed forms or cells where the concrete is used as a structural member which would otherwise not be subject to the jurisdiction of the CWA. This nationwide permit does not include Section 10 authorization.) g) Bank stabilization activities for erosion control if less than 500 feet long and involving less than 1 cubic yard per running foot of bank.) k) Fill material for small hydroelectric projects of not more than 1. m) Dredging of 10 cubic yards or less from navigable waters of the United States as part of a single and complete project. The project must qualify for the short-form Federal Energy Regulatory Commission (FERC) licensing procedures of DOE and the adverse environmental effects must be minimal. water flows into and out of wetlands cannot be impaired. and an individual Section 10 permit will be required if in navigable waters of the United States. 227 . (If located in a navigable water of the United States. Office of Surface Mining for surface coal mining if the District Engineer has had the opportunity to review the application and other pertinent documentation.MIL-HDBK-1003/7 e) Outfall structures and associated intake structures where the effluent from that outfall has been permitted under the NPDES program providing that the individual and cumulative adverse environmental effects of the structure itself are minimal. work." and the activity must be a single and complete project. communications cables. p) Any activity authorized by a state administered dredge and fill permit program approved by the Corps of Engineers. and electrical transmission lines. n) Structures.) i) The placement of fill incidental to the construction of bridges across navigable waters of the United States if the fill has been authorized by the US Coast Guard as part of the bridge permit. Discharge of material must total less than 200 cubic yards below ordinary high water mark and extend into adjacent wetlands no more than 100 feet from the ordinary high water mark on either side.
c) The activity will not destroy a threatened or endangered species as identified under the Endangered Species Act. b) The discharge of dredge or fill material will not occur in areas of concentrated shellfish production.6. or endanger the critical habitat of such species. compliance with the following special conditions is required for any of the above nationwide permits for specific activities to be valid. i) The best management practices listed below should be followed to the maximum extent practicable. f) The fill or structure will be properly maintained to prevent erosion and other nonpoint source of pollution. g) The activity will not occur in a component of the National Wild and Scenic River System or in a component of a state wild and scenic river system. In addition to complying with any activityspecific conditions discussed above.MIL-HDBK-1003/7 18.3 Activity-Specific Conditions. d) The activity will not disrupt the movement of those species of aquatic life indigenous to the body of water. h) navigation.5. a) The discharge of dredge or fill material will not be located in the proximity of a public water supply intake. The activity will not cause an unacceptable interference with 228 . e) The discharge of dredge or fill material will consist of suitable material free from toxic pollutants in other than trace quantities.
c) Discharges of dredge or fill material should not restrict or impede the movement of indigenous aquatic species or the passage of normal or expected high flows. d) If the activity creates an impoundment. The Division Engineer is also authorized to issue regional permits modifying any nationwide permit category by adding conditions applicable to certain activities or specific geographic areas within his division. adverse impacts on the aquatic system caused by the accelerated passage of water and/or the restriction of its flow should be minimized.5.MIL-HDBK-1003/7 18. regional permits) which meet the general criteria for a nationwide permit category (e. a) Discharges of dredge or fill material into waters of the States should be avoided or minimized through the use of other practical alternatives. Each Division Engineer is authorized to issue general permits for activities within his jurisdiction (i. e) avoided. g) Discharges of dredge or fill material into breeding areas for migratory waterfowl should be avoided. h) All temporary fills should be removed in their entirety.e. or cause the relocation of water (unless that is the primary purpose of the activity). Heavy equipment working in wetlands should be placed Discharges of dredge or fill material in wetlands area should be 18.g.. f) on mats. minimal cumulative environmental impact).6.5 Regional Permits. 229 .6..4 Management Practices. The best management practices for nationwide permit must be followed to the maximum extent practicable for both the nation wide permits in certain waters and nationwide permits for specific activities. As with nationwide permits. but which cannot qualify for any promulgated nationwide permit category. the Division Engineer can revoke a regional permit and require an individual permit for any activity.5. b) Discharges of dredge or fill material in spawning areas during spawning seasons should be avoided.
g.MIL-HDBK-1003/7 18. Availability of reasonable alternatives. (2) sanctuaries. Wetlands which provide valuable storage area for storm and Wetlands which have significant hydrological characteristics. or Wetlands which have been set aside as study areas. OMB Approval OMB 49-R0420. (5) floodwaters.6 Individual Permits. As part of this evaluation. or 230 . Wetlands which shelter other areas from wave action. ENG Form 4345. the benefits which reasonably may be expected to accrue from the proposal will be balanced against its reasonably foreseeable detriments. of the proposed activity and its intended use on the public interest. Individual permits are required for activities not authorized by either a nationwide or regional general permit or not exempted from the Corps' regulatory program. (6) Wetlands which are prime natural recharge areas for ground water. The completed application should be submitted to the District Engineer in charge of the Corps of Engineers District where the proposed activity will occur..6. erosion. b) The Corps strongly discourages activities which adversely affect any wetlands considered to perform any of the following important functions. wetlands habitat for aquatic or terrestrial species. Items taken into consideration when reviewing an individual permit are as follows. refuges. (1) Wetlands which serve significant natural biological functions. e. This public interest review is based upon an evaluation of the probable impact. Local variations of the application form to facilitate coordination with state and local agencies may be encountered. a) The Corps' general approach in evaluating applications for individual permit authorizations required by its regulatory program can be described as a public interest balancing process which reflects national concerns for both the protection and utilization of important resources. including cumulative effects. Extent and duration of beneficial and/or detrimental effects.5. (1) (2) (3) Public and private need for the proposed structure or work. (3) (4) storm damage. Applications for individual permits must be prepared using the prescribed application form. The following general criteria will be considered during the balancing process.
However. g) If the proposed activity would affect the coastline or baseline of the territorial seas. Wetlands which provide natural filtration and purification of c) Evaluation of any wetlands alterations must show that the benefits of the proposed alteration outweigh unavoidable damage to the wetlands. e) The Corps will review the permit application to evaluate whether the proposed activity will comply with water quality standards and any applicable effluent limitations. i) Applications will be reviewed for consistency and compatibility with approved Coastal Zone Management Plans. affect or be affected by a federal water resource project. f) The Corps will strive to ensure that the proposed activity is. A Corps' permit may be approved prior to final approval of other certifications or required approvals. insofar as possible. the Corps' permit will be approved prior to final 231 . or similar value. recreational. When performing this evaluation. The water quality certification required by Section 401 of the CWA is considered conclusive with respect to water quality considerations unless the EPA mandates that other water quality issues be evaluated. and their state counterparts concerning minimizing direct and indirect losses and damages to wildlife resources caused by the proposed activity. cultural. the Secretary of Commerce must certify that the action can be accomplished within the regulations pertinent to such areas. consistent with and avoids significant adverse effects on areas which possess recognized historic. or be incompatible with federal projects under construction. National Marine Fisheries Service. the Corps must consult with the Attorney General and Solicitor of the Department of Interior. the District Engineer must consider whether the proposed activity is dependent on being located in. h) Permit applications will be evaluated as to the potential for proposed actions to adversely affect others. or local certifications are denied prior to final action on a Corps' permit application. d) The Division Engineer will consult with and give great weight to the views of the US Fish and Wildlife Service. conservation. j) If a proposed action affects a marine sanctuary. or local approvals. state. state. if other Federal. The District Engineer's decisions will be weighted by Congressional policy expressed in the Estuary Protection Act and state wetlands program.MIL-HDBK-1003/7 (7) water. the wetlands and whether practicable alternative sites are available. interfere with a riparian owner's access to navigable water of the United States. or in proximity to. k) Processing of Corps permit applications may involve concurrent processing of required other Federal. scenic.
232 . p) Since energy conservation and development is a national objective. applicants may be required to show that all impoundment structures comply with state dam safety standards or have been designed or reviewed by qualified persons. In such cases. Because harbor lines were established on the basis of navigation impacts only. o) Although the Corps will not impinge upon the states' authority to allocate water. the District Engineer will also strive to restore and preserve the natural and beneficial values served by flood plains. 1970 (33 CFR 209. However. and Indian tribal agencies must be considered in addition to national interest factors. the Corps' permit will be denied. but the applicant has the right to request reinstatement of processing if the other certifications are later approved. the District Engineer will give great weight to energy needs and will give high priority to permit actions involving energy projects. the District Engineer must assure. l) Specific land use plans of other Federal. to the extent practicable. if other Federal. the District Engineer will give full consideration to the public interest review to water conservation and the opportunities to reduce demand and improve efficiency in order to minimize new water supply requirements.MIL-HDBK-1003/7 approval of other certifications or required approvals. state. The District Engineer will protect navigational and anchorage interests by recommending denial of a permit unless appropriate conditions are included to avoid any substantial impairment to navigation and anchorage. local. authorizing flood plain developments or activities which have long-term or short-term significant adverse impacts upon a flood plain. or local certifications are denied prior to final action on a Corps' permit application. m) In the interest of safety. state. that the impacts of potential flooding on human health. safety.150) which declares that permits thereafter would be required for activities shoreward of the harbor lines. the District Engineer will avoid. Review of applications is based on full public interest evaluation and harbor lines serve as guidance for assessing navigation impacts. For those activities in the public interest which must occur in or impact upon flood plains. to the maximum extent practicable. r) Section 11 of RHA authorized establishment of harbor lines shoreward of which no individual permits were required. n) Whenever practicable alternatives exist outside a flood plain. q) Navigation in all navigable waters is a primary concern of the federal government. the Corps of Engineers published a regulation on May 27. and welfare and the risks of flood losses are minimized.
the application must also contain a complete description of the activity including the source. and intended use of the proposed activity. method of transportation and disposal.) (2) (3) (4) (5) The location. the project description must indicate the uses of and specific 233 . (4) If the activity would include a filled area. and quantity of the material to be dredged. purpose. composition. quantity. (3) If the activity would include the discharge of dredged or fill material in the waters of the United States. composition. notice. (1) All activities related to a single project which require Department of the Army permits should be described within the same application. (1) Necessary drawings. Transmission lines crossing navigable waters are required to have a minimum clearance over the navigable channel provided by existing fixed bridges. or local agencies for the work. including all approvals received or denials already made. type. or plans sufficient for public (This does not mean detailed engineering plans or specifications. state. or pile or floatsupported platform. The names and addresses of adjoining property owners. (6) A list of authorizations required by other federal. or the clearances which would be required by the US Coast Guard for new fixed bridges in the vicinity of the proposed power line crossing. and the site and plans for disposal of the dredged material. The minimum additional clearance above clearance required for bridges for the low point of the line under conditions which produce the lowest sag is given below for various system voltages as outlined in the National Electrical Safety Code. purpose of discharge.MIL-HDBK-1003/7 s) The Corps must authorize any power transmission line crossing a navigable water of the United States unless the lines are part of a water power project subject to the control of the Federal Energy Regulatory Commission. The location and dimensions of adjacent structures. and the method of dredging. the application must include a description of the type. sketches. Minimum Additional Clearance Above Clearance Required for Bridges ft 20 22 24 26 30 35 42 45 Nominal System Voltage kV 115 and below 138 161 230 350 500 700 750 to 765 s) All applications for Department of the Army permits should include a complete description of the proposed activity including the following. u) Permit applications should also be prepared in accordance with the following requirements. (2) If dredging is involved. Scheduling of the activity. (7) Information required for public notices. interstate. and location of disposal site.
y) The Corps strives to process applications for individual permits not requiring an Environmental Impact Statement according to the following procedure and time deadlines. w) program. (5) If an impoundment is included.MIL-HDBK-1003/7 structures to be erected on the fill or platform. the application must show that the structure complies with state dam safety criteria or has been designed. The determination as to the commercial or noncommercial nature of proposed activities will be made by the District Engineer. or modified by qualified persons. More than one owner or proposer may be represented by a single agent. Fees are required for permits issued under the Corps' regulatory 234 . x) A fee of $100 will be charged for permits for commercial activities and $10 for noncommercial activities. (6) The application must be signed by the person who proposes to undertake the proposed activity or his duly authorized agent. reviewed. Fees are not charged for applications withdrawn or denied. v) The District Engineer may request further additional information if essential to assist in the evaluation of the application. Only when an affirmative decision has been reached will the applicant be advised of the appropriate fee.
the nationwide permit for utility line crossings does not constitute authorization under Section 10 if a navigable water is to be crossed. z) If the proposed activity only needs an individual authorization under Section 10 of the River and Harbor of 1899. (3) Within 15 days of receipt of all necessary information. applicant will be given a chance to rebut or resolve adverse comments. the District Engineer will make a final decision on the application. However. (For instance. the District Engineer will issue a public notice of the proposed activity and a draft permit. (4) The public notice period will usually last 30 days but can be extended to 60 days. (2) The proposed activity would not have significant individual or cumulative impact on environmental values. if the public comment period is extended to 60 days).7 FAA Permit. the NEPA environmental impact review process. (3) The proposed work would encounter no appreciable opposition. the final decision may be delayed in order to complete other procedural requirements (e. or historical/ cultural preservation process). 18. 235 . (2) Within 15 days of receipt of the application. endangered species consultation.5. (5) The District Engineer must consider all comments received. (1) The proposed work is minor. The Federal Aviation Administration (FAA) must be notified before there is any construction or alteration of more than 200 feet in height above ground level of a site.g.MIL-HDBK-1003/7 (1) Upon receipt of the application. A letter of permission could be used in such situations in lieu of the complex permit process) the District Engineer can omit publishing a public notice and authorize the activity by a letter of permission if the work meets the following conditions. the District Engineer will assign it an identification number and acknowledge receipt of the application. the District Engineer must request from the applicant any additional information necessary for further processing. The (6) Within 60 days of the receipt of the application (90 days. and any construction or alteration of greater height than an imaginary surface extending outward and upward at one of the following slopes.. The acknowledgement will advise the applicant of the identification number assigned to its application.
the sponsor must request within 30 days that Pending completion of these studies.200 feet in actual length excluding heliports. "Notice of Proposed Construction or Alteration.7. c) Twenty-five to one for a horizontal distance of 5.1 Forms. "Notice of Progress of Construction or Alteration.2 Supplemental Notice.000 feet from the nearest point of the nearest runway of each airport which has at least one runway more than 3. the acknowledgment will contain a statement that the structure must be marked and lighted in accordance with the circular.000 feet from the nearest point of the nearest landing and takeoff area of each heliport. In such the FAA complete its studies. 236 .5.5. the construction or alteration would c) It would exceed an obstruction study is necessary to determine whether it would be cases. b) Fifty to one for a horizontal distance of 10. or greater than certain lesser heights within 6 nautical miles of an airport. it is presumed be a hazard. 18. The FAA is notified by filing four copies of FAA Form 7460-1.000 feet from the nearest point of the nearest runway of each airport which has at least one runway more than 3. It would exceed an obstruction standard but would not be a hazard standard and further aeronautical a hazard to air navigation. An existing or future structure is considered to be an obstruction to air navigation if it is of greater height than 500 feet above ground level at the site of the object. The notification form must be submitted not later than 30 days prior to the date the proposed construction is to begin. a) It would not exceed an obstruction standard and would not be a hazard to air navigation. 18. If the construction or alteration proposed is one for which marking standards are prescribed in the FAA Advisory Circular AC 70/7460-1. A supplemental notice filed on FAA Form 117-1. The FAA will acknowledge in writing the receipt of each notice. b) to air navigation." This notice should be forwarded to the appropriate FAA Regional Office.MIL-HDBK-1003/7 a) One hundred to one for a horizontal distance of 20. The acknowledgment will also state that an aeronautical study has reached one of the following conclusions concerning the construction or alteration." must be filed with the Chief of the Air Traffic Division having jurisdiction over the FAA Region 5 days after the construction reaches its greatest height in the following instances.7.200 feet in actual length excluding heliports.
b) required. An FAA regional office advises that submission of the form is 237 .MIL-HDBK-1003/7 a) The construction or alteration is more than 200 feet above the surface level of the site.
12) Generator hydrogen pressure.MIL-HDBK-1003/7 Section 19. 17) Reheater spray flow. 8) LP Turbine throttle temperature.1 Interim Test Code for An Alternative Procedure for Testing Steam Turbines. 4) HP turbine first stage pressure. back pressure. 15) Boiler feed pump discharge pressure. 11) Generator output. or automatic extraction turbine are similar in principle. 2) HP turbine throttle pressure.1. 16) Superheater spray flow. 7) IP Turbine throttle pressure. 10) LP Turbine exhaust pressure. Turbine generators shall be tested in accordance with ASME Performance Test Code. 238 . 3) HP turbine exhaust pressure. PTC 6. a) The following are the major measurements which must be made for a condensing turbine in a reheat regenerative cycle using superheated inlet steam.1 Equipment Testing TESTING 19. 9) LP Turbine throttle pressure. 6) IP Turbine throttle temperature. 5) Cold reheat temperature.1 Turbine Generators. Measurements for a non-reheat. 19. 13) Generator power factor. 14) Boiler feed pump discharge temperature. 1) HP turbine throttle temperature.
25) HP Turbine gland leakage flow. the following performance parameters can be quantified.1 Input/Output Method a) The following are the major measurements which must be made for input/output method. The changes which have been incorporated into the latest draft code. 28) Main steam flow to steam seal receiver. such as the use of continuous analyzers instead of Orsat analyzers. 22) Highest pressure feedwater heater extraction pressure. 27) HP Turbine gland leakage pressure. 19. 1) Maximum capability. PTC 4.MIL-HDBK-1003/7 18) Highest pressure feedwater heater feedwater inlet temperature.1. 1) Coal flow.1. 20) Highest pressure feedwater heater drain outlet temperature. 3) Enthalpy-drop efficiency. Steam generators shall be tested in accordance with ASME Performance Test Code. 26) HP Turbine gland leakage temperature. b) As a result of calculations based on PTC 6S methods. 23) Feedwater flow to boiler. For additional testing requirements see MIL-HDBK-1003/6. are recommended for use. Steam Generating Units.1. 24) Feedwater pressure at boiler inlet. which is currently being revised. 19) Highest pressure feedwater heater feedwater outlet temperature. 239 .2 Steam Generators. 2) Heat rate.2. 2) Higher heating value. 19. 21) Highest pressure feedwater heater extraction temperature. 3) Combustion air temperature. 4) Feedwater flow.
13) Auxiliary steam pressure.MIL-HDBK-1003/7 5) Feedwater temperature. 2) Input. 3) Output. 12) Auxiliary steam temperature. 1) Steam generator efficiency. 7) Superheat desuperheat spray flow. 18) Cold reheat steam temperature. 5) Capacity. 8) Superheat desuperheat spray temperature. b) As a result of calculations based on PTC 4. 15) Main steam temperature.1 methods. 17) Cold reheat steam pressure. 11) Auxiliary steam flow. This can be determined under the turbine generator test. In addition to these measured parameters. the following performance parameters can be quantified. 4) Steam temperature and control range. 10) Blowdown flow. 20) Hot reheat steam temperature. 19) Hot reheat steam pressure. 16) Main steam pressure. 240 . 14) Sootblowing steam flow. 6) Feedwater pressure. 9) Superheat desuperheat spray pressure. cold reheat flow is required.
2) Auxiliary steam temperature. 11) Feedwater flow at economizer inlet. 3) Auxiliary steam pressure. 7) Cold reheat pressure. 1) Auxiliary steam flow from steam generator. 5) Carbon monoxide at economizer outlet. 6) Coal flow. 19) Motor power. 241 .2 Heat Loss Method a) The following are the major measurements which must be made for heat loss method.1. 17) Main steam pressure. 10) Drum pressure.MIL-HDBK-1003/7 6) Water and steam side pressure drop. 9) Cold reheat flow (calculated by PTC 6 methods).2. 15) Hot reheat pressure. 16) Hot reheat temperature. 18) Main steam temperature. 8) Cold reheat temperature. 4) Blowdown flow. 19. 13) Feedwater temperature at economizer inlet 14) Flue gas temperature at air heater outlet. 12) Feedwater pressure at economizer inlet.
22) Reheat desuperheating spray flow. 27) Sootblowing steam pressure. a fuel ultimate analysis. b) As a result of calculations based on PTC 4. 24) Reheat desuperheating spray temperature. Condensers shall be tested in accordance with ASME Performance Test Code. 21) Pulverizer reject flow.1. 30) Superheat desuperheating spray temperature. a) The following are the major measurements which must be made. 2) Steam generator steam flow. 2) Condenser pressure. fuel heating value. 5) Water and steam side pressure drop. 3) Condenser inlet cooling water pressure. In addition to these measured parameters. PTC 12.2 Steam Condensing Apparatus. 242 . 23) Reheat desuperheating spray pressure. 29) Superheat desuperheating spray flow. 1) Steam generator efficiency. 25) Sootblowing steam flow.MIL-HDBK-1003/7 20) Flue gas oxygen at economizer outlet.2. 3) Steam temperature and control range.3 Condensers. 6) Steam generator maximum capability. the following performance parameters can be quantified. 19. 31) Superheat desuperheating spray pressure. 26) Sootblowing steam temperature. 1) Circulating water flow.1 methods. and ash (if any) heating values are required. 4) Exit flue gas temperature.
e) Cooling water flow.MIL-HDBK-1003/7 4) Condenser inlet cooling water temperature. the following performance parameters can be quantified. Cooling towers shall be tested in accordance with The Cooling Tower Institute's (CTI). 3) Condenser waterside pressure drop. ATC 105 recognizes two methods for evaluating the performance of a cooling tower: the characteristic curve method and the performance curve method. The following are the major measurements which must be made. 2) Condenser tube fouling factor. 1) Condenser tube cleanliness factor. 7) Condenser absolute pressure. 5) Condenser outlet cooling water pressure. ATC 105. Test Procedure: Part 2. 4) Condenser heat load. 243 . Acceptance Test Code For Water Cooling Towers (Part 1. Both methods require the same measured data and calculate the same performance parameter. d) Hot water temperature. b) Dry bulb temperature. c) Cold water temperature.4 Cooling Towers.2 methods. f) Fan power. 6) Condenser outlet cooling water temperature.1. Evaluation of Results).2. b) As a result of calculations based on PTC 12. 19. a) Wet bulb temperature at tower inlet.
7 Pumps. i) Blowdown temperature. the cooling tower capability can be quantified as a percent of design.1.1. 19. 7) Steam supply temperature. 3) Evaporator vapor sample. Evaporating Apparatus. the following performance parameters can be quantified. Continuous oxygen analyzers are also commercially available. 2) Evaporator feedwater temperature.MIL-HDBK-1003/7 g) Makeup water temperature. Deaerators shall be tested in accordance with Performance Test Code. Centrifugal pumps shall be tested in accordance with ASME Performance Test Code. h) Makeup water flow. ASME PTC 12. 6) Steam supply pressure.3 Part II describes several methods of determining the dissolved oxygen content in deaerated water. 19. 244 . As a result of calculations.2. 1) Maximum capacity. 4) Evaporator vapor pressure. 1) Inlet flow.2. PTC 8. PTC 14.5 Evaporators. j) Blowdown flow. 1) Evaporator feedwater flow. 2) Inlet temperature. 2) Total solids in vapor. Deaerators. These methods include the titration method and the colorimetric method. Centrifugal Pumps.6 Deaerators.1. a) The following are the major measurements which must be made.3. 5) Evaporator vapor temperature. 19. a) The following are the major measurements which must be made for each pump.2. b) As a result of tests and determinations based on PTC 14 methods. 3) Inlet pressure.2. PTC 12. Evaporators shall be tested in accordance with ASME Performance Test Code.
7) Specific speed. the following performance parameters can be quantified. 3) Pump power. For additional test requirements see MILHDBK-1003/6. 2) Volume flow/pressure.2 methods. 19. 2) Pump total head. the volume flow/pressure method which does not require fan outlet velocity pressure is recommended. PTC 11.MIL-HDBK-1003/7 4) Discharge flow. 11) Pump speed. 4) Pump efficiency.1. 8) Bleedoff temperature. 7) Bleedoff flow. 4) Air or gas inlet temperature. b) The following are the major measurements required for the volume flow/pressure method.2. 1) Mass flow/specified energy. Therefore. 5) Fan speed. 10)Pump input power. 1) Fan inlet static pressure. 5) Discharge temperature. 6) Available net positive suction head. Forced draft and induced draft fans shall be tested in accordance with ASME Performance Test Code. 5) Suction requirements. b) As a result of calculations based on PTC 8. 245 .8 Fans. Fans. 2) Fan inlet velocity pressure. Experience has shown that accurate velocity pressure measurements at the fan outlet are at best very difficult. 3) Fan outlet static pressure. The mass flow/specific energy method requires velocity and static pressure measurements at the fan inlet and outlet. 6) Discharge pressure. 1) Capacity. a) Test Code PTC 11 recognizes two methods for expressing fan performance. 9) Bleedoff pressure.
2.9 Compressors. 1) Capacity. c) As a result of calculations based on PTC 11 methods. a) The following are the major measurements which must be made. In addition to these measured parameters. 19. 5) Stage outlet static pressure (for multistage machines). 3) Discharge static pressure. 1) Fan static pressure.1. the air or gas composition is required. Vacuum Pumps and Blowers. Air compressors shall be tested in accordance with ASME Performance Test Code. 2) Inlet static pressure.MIL-HDBK-1003/7 6) Fan input power. the following performance parameters can be quantified. 246 . 3) Mass flow. PTC 9 Displacement Compressors. 4) Stage inlet static pressure (for multistage machines). 4) Fan static efficiency. 2) Volumetric flow. 6) Inlet air or gas temperature.
247 . 7) Power economy (units of power per unit of capacity). In addition to these measured parameters. 4) Stage compression efficiency. 10) Cooling water inlet temperatures to individual cylinders and coolers.2. 2) Isentropic power. the gas composition is required. PTC 12. 19.MIL-HDBK-1003/7 7) Intercooler inlet and outlet gas temperatures (for multistage machines).1 Closed Feedwater Heaters. 9) Cooling water flows to individual cylinders and coolers. 11) Cooling water outlet temperatures to individual cylinders and coolers. 1) Compression ratio.10 Heat Exchangers. 6) Compressor efficiency. 5) Mechanical efficiency. b) As a result of calculations based on PTC 9 methods. Feedwater heaters and auxiliary cooling water heat exchangers shall be tested in accordance with ASME Performance Test Code. 12) Compressor speed. the following performance parameters can be quantified. 13) Input power.1. 8) Discharge air or gas temperature. 3) Volumetric efficiency. 14) Indicated power.
14) Extraction steam pressure.MIL-HDBK-1003/7 a) Feedwater Heaters. 2) Feedwater temperature rise. 3) Feedwater outlet temperature. 4) Feedwater inlet pressure. 11) Drain outlet pressure. 2) Feedwater inlet temperature. the following performance parameters can be quantified. 1) Terminal temperature difference. 5) Pressure drop through drain cooler (where applicable). 10) Drain outlet temperature. 3) Drain cooler approach (where applicable). 248 . 5) Feedwater outlet pressure. 1) Feedwater flow. 7) Drain inlet pressure (where applicable). In addition to these measured parameters. 13) Extraction steam temperature. 8) Drain inlet temperature (where applicable). b) As a result of calculations based on PTC 12. 6) Drain inlet flow (where applicable). 12) Extraction steam flow (can be calculated). 15) Heater pressure. 4) Feedwater pressure drop. The following are the major measurements which will be required for each closed feedwater heater. the heater manufacturer's design data is also required.1 methods. 9) Drain outlet flow.
1 methods.2. 2) Shell side pressure drop. 9) Tube side flow. PTC 4. 10) Shell side flow. Boiler tubular and regenerative air heaters shall be tested in accordance with ASME Performance Test Code. 4) Tube side water outlet pressure.3 Air Heaters. 3) Approach temperature. 3) Air inlet temperature.MIL-HDBK-1003/7 c) Auxiliary Cooling Water Heat Exchangers. 1) Tube side pressure drop. 6) Shell side inlet pressure. Using PTC 12.11 Air Heaters.1. 1) Flue gas inlet temperature. the following performance parameters can be quantified. 19. the cooling water heat exchanger will be treated as an external drain cooler. 3) Tube side water outlet temperature. 1) Tube side water inlet temperature. The following are the major measurements which must be made. 5) Shell side inlet temperature. The changes which have been incorporated in developing PTC 41 are recommended for use. which is currently being revised as PTC 41. 7) Shell side outlet temperature. a) The following are the major measurements which must be made for each air heater. 249 . 2) Flue gas outlet temperature. d) As a result of calculations based upon PTC 12.1. 8) Shell side outlet pressure. 2) Tube side water inlet pressure.
O2). b) In addition to these measured parameters. 14) Outlet flue gas analysis (CO2.1. Measurements taken include particulate concentration and mass flow rate at both the inlet and outlet of the dust collector. CO.12 Dust Collectors. Mechanical dust collectors shall be tested in accordance with ASME Performance Test Code. 15) Fuel flow (measured or calculated by steam generator output and efficiency). 3) Heat capacity ratio (X-Ratio). 6) Air outlet flow. 7) Flue gas inlet flow 8) Flue gas outlet flow. 10) Flue gas side inlet and outlet velocity pressure. 12) Air side inlet and outlet velocity pressure. 5) Flue gas side pressure drop. and temperature are also measured. 11) Air side inlet and outlet static pressure.2. 2) Air leakage. 13) Inlet flue gas analysis (CO2. 4) No leakage exit flue gas temperature. For other testing requirements see MIL-HDBK-1003/6. Measurements at the inlet and outlet allow determination of dust collector overall efficiency. O2).MIL-HDBK-1003/7 4) Air outlet temperature. 250 . PTC 21 Dust Separating Apparatus except Environmental Protection Agency Method 5 (40 CFR Part 60 Appendix A. sampling (isokinetic sampler with heated filter) should be used. Reference Methods). the following performance parameters can be quantified. a fuel ultimate analysis is required. 9) Flue gas side inlet and outlet static pressure. 5) Air inlet flow. composition. 19. 1) Flue gas side efficiency. Flue gas flow rate. As a result of calculations based on PTC 41 methods. CO. 6) Air side pressure drop.
Electrostatic precipitators shall be tested for performance and compliance (if required by Federal. The test equipment shall consist of instruments and apparatus as necessary to provide indication or record of test properties and variables. for information relative to sampling ports. and NOx. Determine the necessary parties to the test.2 Preparations for Tests. Supplements to ASME Performance Test Code. PTC 19 Instruments and Apparatus should be consulted as necessary. General Instructions and ASME PTC 2. Whether cited or not in the test code. 19. Testing will be the same as described above under Dust Collectors. however.2. a) Preparations for testing includes the following. Materials shall consist of miscellaneous chemicals for charging instruments and supplies. Prepare necessary forms for recording of test data. f) g) Calibrate or verify calibration of instruments. 19. An ASME performance test code is in the process of preparation. and precautions to be observed.3 Test Equipment and Materials. EPA Method 5 or 17 for particulate matter and Methods 6 and 8 for SO2. or local regulations). methods of calibration. Testing should be done in accordance with 40 CFR Part 60 Appendix A.MIL-HDBK-1003/7 19. Determine applicable test code. b) Read and observe applicable parts of ASME PTC 1. state.1. Flue gas scrubbers shall be tested for performance and compliance (if required by Federal.14 Flue Gas Scrubbers.1. Definitions and Values. no interim PTC for scrubbers is yet available. e) Determine instrumentation to be used for tests and provide temporary supplemental instruments as necessary. Each individual test code for specific equipment contains information covering permissible choices of instrumentation. state. SO3. These supplements are as follows: 251 . c) d) Determine test data and readings required. 19. or local regulations).2. See also MIL-HDBK-1003/6.13 Precipitators.
Measurement of Shaft Power.8 Weighing Scales. Interim c) PTC 19.6 PTC 19. Measurement of Rotary Speed.MIL-HDBK-1003/7 a) b) PTC 19.13 PTC 19.5.2 PTC 19. Measurement of Indicated Horsepower.3 Pressure Measurement. Part II of Fluid Meters: Supplement on Instruments and Apparatus.1 PTC 19.16 PTC 19. d) e) f) g) PTC 19. Electrical Measurements in Power Circuits.14 PTC 19. Flue and Exhaust Gas Analyses .12 PTC 19. Determination of the Viscosity of Liquids. i) j) k) l) m) PTC 19.10 Apparatus . Linear Measurements.V Part 10.Instruments & Measurement of Time.17 252 .5 Application. Temperature Measurement. h) PTC 19.7 PTC 19. Density Determinations of Solids and Liquids.
1 Definition. However. When severe overloads occur. the plant would experience a sudden overload from which it might not be able to recover. the steam excitation frequency approaches blade resonance. 20. reducing generator output. On the average. the spinning reserve is zero and the governors may not be able to relieve the overload. the first effect is a slowing down of the large enough or if the governor cannot accommodate the and frequency will continue to drop until the plant or prevent equipment damage. However. The additional load is handled by using the spinning reserve.1.2 Requirements for Load Reduction. Should the interconnection trip.1 Objectives of Load Shedding Program.5 Hz range is generally not advisable. Generating plants are highly sensitive to frequency drop. the remaining units would experience a sudden load increase. 20. will slow down. even though other loads are lost. and the load is lost.2. or a sudden but mild overload. the blades may vibrate severely. Safety margins in generator-cooling and bearing lubricating systems will be reduced.6 to 57. possibly leading to loss of the plant. Load shedding is the deliberate and selective dropping of electrical load in accordance with a preplanned program. fatigue is 253 .1. if all generators are operating at maximum capacity. If the overload is sudden load increase.2. A typical scenario in which load shedding would be advantageous would be the case of a power plant operating in parallel with a utility. that is. The lowest safe plant operating speed will depend on the safety margins included in the plant design. LOAD SHEDDING 20. Motor-driven auxiliaries. Another scenario could involve an isolated plant (not interconnected with a utility).1. Under this condition. the unit governors will sense the resulting speed change and increase the power input to the generator.2 Turbine Blade Fatigue. the unused capacity of the generator. 20. The purpose of load shedding is to reduce plant loads so that the plant will not trip on overload and so that certain preselected loads can be saved.MIL-HDBK-1003/7 Section 20. with several generating units loaded at or near their combined capability. Should one unit trip. sudden load increases are generator.2. There are two major problem areas. When running under heavy load at about 58.1 Motor speed.5 Hz or below. producing fatigue stress. with a total system load exceeding the capability of the plant alone. 20. 20. low-pressure blades in steam turbines are tuned to operate free of resonance in a narrow band of frequencies around 60 Hz.1 Stable Operation and Overload Capability.2 Purpose.1. then speed generating unit is tripped to 20. or when large experienced. operation below the 56. When a power plant or an individual power generating unit experiences a gradual increase in load. particularly boiler feedwater pumps. The last rows of long. blades should not be subjected to more than ten minutes of severe vibration totaled over their lifespan.
The rated capacity (MW) of the machine in megawatts.2. the generator protective devices may trip the unit in this speed range. All but the largest unit in operation. a) b) c) d) The lowest safe operating speed (F) in Hz. the determination of plant capability must take into account the possibility that one or more generating units in the plant may be out of service and also that the remaining plant may experience some loss of capability because of underfrequency operation.MIL-HDBK-1003/7 cumulative. This determination must be based on plant configuration and judgment. 254 .4 Reduced Plant Capability.0 to 58. the following information is required for each generating unit in the plant. All but the two largest units in operation. The value of plant capability used to design a load shedding program should take into account the possibility that one or more generating units may be out of service when the overload incident occurs.5 Load Reduction Requirements.2 Generating Unit Sizes. regardless of load. As already explained. In order to attain stable plant operation. the following conditions should be considered. 20. 20. The inertial constant (H) of the machine in megawatt seconds per MVA. Frequency and time limits for turbines should be specified by the turbine manufacturer. and protective system operation by the plant designer. As an approximation.3 Number of Generating Units. The power factor (p) rating of the machine. a) b) c) All units in operation. The reduction in plant capability resulting from underspeed operation should be known but will generally be unavailable. load must be shed to such a degree that the total load served does not exceed plant capability.5 Hz should be avoided. 20. Operation below about 58. However. dimensionless.2. In order to design an effective load shedding scheme. 20.2. assume a capability loss of about four percent capability for each Hz of underfrequency.2.
H Plant.MIL-HDBK-1003/7 20.. Hz Inertial constant of machine. is calculated from the following formula...21 Hz per second.+MVAN) (17) where the subscripts refer to the individual generating units. In this case. The rate of frequency change can be estimated from the following formula. from fo = 60 Hz to f1 = 58 Hz would be Time = 2/1. The total time for the frequency to drop 2 Hz.f0) / H(1 . the minus sign indicates that the frequency is decreasing at a rate of 1.65 seconds. 255 . Hz Final frequency. MW sec/MVA R = pL(f1 .f12/f02 (15) For a typical calculation.1 Rate of Load Reduction.20 (16) and substituting in Equation (15): R = [(0.85 power factor machine with an inertial constant of H=4 experiences a sudden overload to 120 MW and we wish to find the rate at which frequency drops from the initial frequency of fo = 60 Hz to f1 = 58 Hz. composite values should be used to obtain a rate of frequency drop for the entire plant. The composite inertial constant for the plant. EQUATION: L = (120 MW . Load must be shed fast enough to attain the required load reduction before plant frequency has deteriorated to an unacceptable level. For calculations involving an entire plant.20)(60-58)]/[4(1 .85)(0. assume that a 100 MW.(602/582))] = . Hz per second Power factor of machine Average per unit overload (Load-Power Input)/(Power Input) Initial frequency. 0. EQUATION: Hplant = (H1MVA1 + H2MVA2+. EQUATION: where: R p L = = = = fo = f1 = H = Average rate of frequency change.1.5.21 = 1. In this case.100 MW) / (100 MW) = 0.65 seconds This indicates that the load shedding plan must accomplish a load reduction of at least 20 MW within 1.21 Hz/second..2.+HNMVAN)/(MVA1 + MVA2 +.
load restoration would be faster and easier than if the plant were lost also. They do not respond to the overload directly.5. 20. they respond only if the generators are suffering the adverse consequences of overload. for instance. The automatic methods include underfrequency relaying and various transfer-trip arrangements.5. The load shedding plan must accomplish a total load reduction sufficient to relieve the plant overload and also to provide a slight underload so that the plant will have reserve capability to reaccelerate to the normal operating frequency. Each underfrequency relay is set to trip a block of load at progressively lower frequencies.1 Underfrequency Relaying.2.2 Total Load Reduction. and 58.5 Hz. One must also take into account the loss of capability that results from underfrequency operation. with three-step load shedding being the most common.3 Minimum Power Supply.0 Hz. underfrequency relays are applied to shed load in two to five steps. 20. The rationale is that even if all load is dropped but the plant is saved. when frequency drops to a preset level. load shedding by underfrequency relaying is the most common and generally the preferred method.3 Methods of Load Shedding. with severe overloads. Automatic operation is generally advantageous because. at 59.1 Automatic Operation. 59. However.1. In the previous example (a 100 MW generator with a 120 MW load) assume that the plant frequency dropped to 58 Hz before load shedding was initiated and that the plant capability loss was four percent for each Hz of frequency drop. both automatic and manual.1. Load shedding with under-frequency relays is generally performed automatically. The time to reaccelerate may be computed from the same formulas already given.3.MIL-HDBK-1003/7 20.3. generally performed automatically. Therefore. In general. but to the deleterious conditions resulting from overload. It is reasonable to design a load shedding plan to drop nearly all or perhaps even all of the plant load. the plant capability would be only 92 percent (or 92 MW) at 58 Hz.2 Critical Frequencies.5 Hz. These critical frequencies should be computed as described previously.3. 256 . system frequency may drop faster than the plant operator can respond. In this case. The principal advantage of under frequency load shedding is that the underfrequency relays respond to the underfrequency condition resulting from generator overload. 20.2. There are many methods of load shedding. All of these methods have relative advantages and disadvantages and the choice of the most advantageous method should be based on the specific conditions that prevail. 20. 20. If 30 MW of load were shed (reducing the total load from 120 MW to 90 MW) then the generator would have a 2 MW margin (92 MW capability less 90 MW load) to reaccelerate back to the normal operating frequency of 60 Hz.
20. protective relays and circuit breakers are interlocked so that the event that causes a loss of power supply also causes certain loads to be dropped. because system loads vary and cannot be determined accurately in advance. that is. For this reason.3. the use of this method will almost always result in greater loss of load than with underfrequency load shedding. the loss of one generating unit could be sensed and used to initiate the tripping of a block of load equal to the generating capacity lost. It is important that the plan be prearranged so that the plant operator can implement it quickly under emergency conditions. It is appropriate to combine manual load shedding (to relieve mild overloads) with underfrequency load shedding (to relieve severe overloads). it need consist of no more than a list of what loads (or feeders) should be tripped and how.3.MIL-HDBK-1003/7 20. 20. In general. manual load shedding cannot be used to resolve problems of severe plant overloads. only the minimum amount of load necessary for system recovery is shed. it is appropriate to have a load shedding plan. 20. For instance. It is important to note that with a multi-stepped underfrequency load shedding system.3. With manual load shedding.3. for an isolated plant. In general. with a well designed load-shedding plan. 257 . the system frequency drops too rapidly for an operator to respond and the plant can be lost within seconds.3 Incremental Load Reduction.3. this determination can only be made in an approximate manner.1.1 Load Shedding Plan. Although transfer trip load shedding has the advantage of simplicity. quite often the overload will be eliminated and system frequency will start to recover after only one or two critical frequencies are reached. With severe overloads. Herein lies another advantage of underfrequency load shedding. etc. With transfer trip load shedding. thereby preserving a balance between load and generation. This plan can be quite simple.3 Manual Load Shedding. with an interconnected plant. overloads that are small enough to be accommodated by governor action (thereby preventing underspeed operation).) if uncorrected. the transfer trip method is generally not recommended. but that are still large enough to cause excessive equipment stress (overheating. auxiliary contacts on the interconnection circuit breaker could be used to trip certain loads whenever the interconnection failed. The amount of load to be shed at each critical frequency should be related to the expected percentage overload. Similarly. Manual load shedding is appropriate to relieve mild overloads.2 Transfer Trip Load Shedding. accelerated wear.
258 . or manual systems.4 Electrical Usage and Critcality. underfrequency. the total amount of load to be shed manually should be sufficient to relieve the anticipated plant overload. and the load shedding should proceed in stages with progressively more critical loads being shed at each stage. and this feeder is tripped first.3. transfer trip. then all loads served from that feeder are dropped. individual outgoing feeders are tripped. 20. that is. Local load shedding is the system that is the most common and easiest to implement and can be utilized with underfrequency. 20. regardless of their criticality. With manual or transfer trip load shedding. When load shedding is initiated locally. This determination will also be influenced by the load shedding method. such as the difference between summer and winter peaks or seasonal changes in plant capability because of scheduled maintenance. this approach may not be practical. With this approach.1 Local Application. In general. if a feeder is tripped. local or remote. or manual. Generally.3.3. 20. In some systems.2 Remote Application. transfer trip.2 Incremental Load Reduction.4.4. In other systems.4 Point of Application. each feeder will be tripped sequentially in a predetermined order of preference until the overload has been corrected.MIL-HDBK-1003/7 20. Remote tripping can be readily implemented with underfrequency relays installed at the remote circuit breaker. Manual load shedding can be performed in one or several steps to take account of varying system conditions. 20.3.3. each load can be given a priority and tripped sequentially in accordance with that priority. the trip signal must be transmitted to the remote circuit breaker. A disadvantage is that. The following provides guidelines for the determination of the relative criticality of loads. In designing a manual load shedding plan. the least critical loads should be tripped first. individual loads are tripped rather than entire feeders. at the power plant. In order to determine the point of application. With remote application. the designer must take into account the location of the specific loads to be shed and the electric distribution system configuration. all nonessential loads can be grouped on a single feeder.
The load shedding plan shall be designed so that critical loads are shed last. when designing the load shedding plan. 20.1 Critical Loads. In many cases.2. or of not providing power.3 Interruptible Loads.18.104.22.168.2 Diurnal Variations.1. 20. 20. if shed. it may be necessary to divide the critical loads into two or more categories and assign relative priorities to each category. would adversely impact the facility mission.4. 20. but could also be given a high priority for load restitution. load criticality will vary with time.2. may result in excessive costs.4. 20.4. a load related to providing heat could be considered critical during the winter and noncritical during the summer. For instance. In some cases.MIL-HDBK-1003/7 20. However.4 Political Implications.2 Time-Critical Loads. These variations should be taken into account.1 Seasonal Variations. The criticality of some loads may vary from day to night or from weekday to weekend because of changing usage.4. Examples may include community facilities with emergency (battery powered) lighting.1. a power outage. 20. Examples may include auditoriums. taking into account the effect on the community of providing power. along with an estimate of the magnitude of each. the selection of critical loads must be made on a purely subjective basis. 20. Life support loads include hospitals and similar facilities where loss of power may endanger life. In some cases. and offices. 20. if possible. theaters.1. the power supply to a frozen food storage facility could be considered critical during the summer and non-critical during the winter. These loads can be classified non-critical for load shedding. while not endangering the mission or life support. Some loads can withstand short interruptions but not lengthy interruptions. Under the same conditions.4. to a specific load during a widespread power failure.1 Mission Critical Loads. 259 .4.1. To develop a load shedding plan. In a severely cold climate. Mission critical loads are the loads that are essential for the operation of the facility and.3 Cost of Power Outage. the power supply to a food storage facility may be considered critical because a power outage may result in food spoilage with inherent loss of money and morale. Mission critical loads may also include base security. the critical loads shall be identified first.2 Life Support Loads. in some cases.
those that remain can be classified as non-critical and identified for first-step load shedding. In many cases. 260 .4. etc). 20. diesel generator.4 Non-Critical Loads.4. highly critical loads such as those identified as mission critical or life support will be provided with standby emergency power supplies (uninterruptable power supply.3 Standby Power. In these cases. the load under consideration can be downgraded from critical to interruptible or even noncritical depending on the capability of the standby power supply. Having identified all critical loads.MIL-HDBK-1003/7 20.
and 48 for typical cogeneration cycles. The cogenerator has a large heat demand for process use or environmental heating and can cogenerate electricity in excess of facility needs.1 Parallel Operation.2 Combined Cycle.) input to the cycle. 19. Both turbines can drive a single or separate electrical generator. 261 .1 Reasons for Paralleling a) Selective use of electrical energy from the electric utility by the cogenerator. The overall efficiency of a cogeneration cycle is a ratio of all usable energy (electricity. some electricity will be flowing either to or from the cogeneration system. The basic conventional cycle consists of a steam boiler and turbine.1. POWER PLANT COGENERATION 21. b) Sale of excess electricity by the cogenerator to the electric utility. Under parallel operation.4. 21.2 Cycles. solar. Under parallel operation.3 Efficiency. Cogeneration is the simultaneous generation of electricity (or mechanical energy) and steam (or other thermal energy such as hot air or hot water) from the same fuel (or energy) source. etc.MIL-HDBK-1003/7 Section 21. and from which steam is extracted or exhausted to environmental heating or processes. with both the cogenerator and electric utility generating electricity simultaneously. The HRSG in turn produces steam to drive a steam turbine. the cogeneration plant is electrically interconnected and synchronized with an electric utility distribution or transmission system.1 Basic Cycle. The combined cycle consists of a gas turbine which exhausts to a heat recovery steam generator (HRSG). 21. steam. Low pressure turbine exhaust steam can be used directly for process or heating purposes or the steam can be otherwise condensed and returned to the HRSG.) obtained from the cycle to the energy (fuel. which drives either an electrical generator or other mechanical equipment. 21.4. The excess electricity generated is sold to the electric utility generally at a rate which is less than the generating costs. etc. 21. See Figures 13. hot water. turbines. this is usually not economical. and electric generators arranged to produce both electricity and steam or other thermal energy. 21.4 Methods of Operation 21. 21.1 Definition.2. The cogenerator purchases electrical energy during periods and in amounts as needed to supplement its cogeneration capabilities.2. Cogeneration cycles consist of energy conversion equipment such as boilers.
4.1 Reasons for Isolation a) The facilities and cogeneration plant are in a remote location and electricity is not or cannot feasibly be made available from an electric utility to the facilities. If there is a high demand for steam during peak electric demand periods. A cogenerator may operate in isolation and may also be interconnected to an electric utility for service during maintenance down times and/or for standby service for use during an emergency outage of the cogeneration plant. In this mode of operation. 21. backstart capability must be provided. automatic extraction condensing turbine generators lend themselves to base load electric operation.MIL-HDBK-1003/7 c) Peak Shaving. Under isolated operation.2 Isolated Operation.2.4. 21. 21. Agreement for parallel operation cannot be reached with electric Critical mission requires self-contained system. c) Facility heat and electrical needs coincide to permit self-contained (total energy) cogeneration system. of electricity purchased from an electric utility through a parallel arrangement.4.3 Base Load Thermal. all electricity and steam needed and used by the facilities that it serves. Because of the duality of steam production and utilization.2 Electric Utility Crosstie. if it proves to be economical.4 Base Load Electric. In this mode of operation. as determined from periodic swings in steam load. the cogeneration plant generates. Peak shaving is usually done on a daily cyclic basis.4.4. during peak electrical use periods.2. cogeneration can be used to supplement purchased power to achieve peak shaving.4. the cogeneration equipment is sized and installed to generate electricity at a constant (base) load equal to the minimum annual (or some other chosen period) electrical demand. including onsite 263 . electrical utility. 21. Supplemental steam demands would be supplied by the use of supplementary firing of heat recovery steam generators or separate boilers. independently of the electric utility. If a cogenerator is not crosstied to an electric utility. the cogeneration equipment is sized and installed to generate electricity at a constant (base) load equal to that afforded by minimum steam demand. Cogeneration is used to minimize demand charges from the 21. d) utility. Peak shaving is accomplished by the use of onsite generation or cogeneration equipment to limit the demand. Some of the electricity included in the base load may not be cogenerated but may serve to reduce demand supplied by an electric utility. The objective of peak shaving is to economically reduce electric utility demand charges and overall electrical energy costs.5 Electric Peak Shaving. Supplemental electrical demands above the base load would be supplied by the electric utility through a parallel arrangement. b) standby. 21.
264 .6 Electric and Thermal Tracking 21. d) The cogenerator may be required to notify the utility prior to initial energizing and startup testing of the cogeneration facility. and specification of certain maintenance requirements. With thermal tracking. and steam turbine generators. Automatic extraction condensing turbine generators and combined cycles provide the means for simultaneous tracking of both electric and thermal loads. Typical examples are as follows: a) Voltage. The use of automatic extraction condensing turbine generators and combined cycles also provides the means for electric tracking.MIL-HDBK-1003/7 21.5. c) The utility may reserve the right to inspection. 21.5 Interconnection with Utility 21. observation of testing.4.6.4. Operational requirements of a cogeneration plant interconnected with an electric utility are conditions of either the electric utility rate schedule for parallel generation contract service or separate contract of agreement between the cogenerator and utility.1 Electric Tracking. b) The utility may reserve the right to limit the amount of electrical load delivered to the utility system at certain times and as utility electric operating conditions warrant. cogeneration equipment is used to generate as much electricity as the steam load will allow with supplemental electrical demands generated on other equipment such as gas turbine generators.4. Thermal tracking is defined as the continuous generation of heat or steam to meet the thermal demands of a facility as they occur throughout the daily load swings. 21. Electric tracking is defined as the continuous generation of electricity to meet the electrical demands of a facility as they occur throughout the daily load swings.6. With electric tracking.2 Thermal Tracking. and wave shape of alternating current to be delivered to the utility system shall be maintained within specified limits. diesel generators.1 Operation Requirements. cogeneration equipment is used to generate as much steam as the electric load will allow with supplemental steam demands generated directly by use of boilers. frequency. The conditions as set out in the contract may be site specific and cogeneration system specific.
3 Line and Equipment Protection. and that it must have the capability of being locked out by utility personnel to isolate the utility's facilities in the event of an electrical outage on transmission and distribution facilities serving the cogenerator. owned. Generators operating in parallel with the utility system need protection against overload. one protective relaying system is required to separate the utility system from the cogeneration bus and another protective relaying system is required to separate the cogenerator from the cogeneration bus.5. Line sectionalizing studies should be made to verify correct operation of sectionalizing devices over the range of conditions that could arise.1 Utility Standby Service.2 Parallel Operation. 21. 21. The required protective relay functions are usually designated by the electric utility and the final design of the complete protective relaying system must have the approval of the electric utility prior to initial operation of the cogeneration system.2 Interconnection Equipment 21.5. 265 .MIL-HDBK-1003/7 e) The cogenerator may be required to notify the company prior to each start of energy delivery and interconnection to the utility system. The manual switch for connect or disconnect of the utility service from the facility electric load and cogeneration system electric source is usually a mandatory contract requirement by the utility.2. The interconnection with the utility for parallel operation also requires synchronizing controls for electrically synchronizing the cogeneration system with the electrical utility system. In addition to these switches. The utility will further require that this switch be under exclusive control of the utility. This arrangement requires a manual or automatic throwover switch that will first disconnect the cogeneration electrical source from the facility electrical load before connecting the facility electrical load to the electric utility service entrance line. 21. Parallel operation introduces variables in distribution line protection in that fuses and other sectionalizing devices may be affected by generator contributions to fault currents. and maintained by the electric utility. one to disconnect or connect the cogeneration electrical source to the facility electrical load and the other to disconnect or connect the facility electrical load to the utility service entrance line. g) The utility may require a demonstration of reasonable reliability of the cogeneration plant over the life of the contract. This arrangement requires two manually operated disconnect switches. f) The utility may require that the cogeneration plant's scheduled outage for maintenance coincide with periods when utility power system demand is low. or emergencies.5.2. h) The utility may require a contract specifying technical and operating aspects of parallel generation. The other manual switch or isolation device will also usually be required by the utility contract to serve as a means of isolation for the cogeneration equipment during maintenance activities. routine outages. meters for billing will be required and are usually supplied.5. To protect both line and cogeneration equipment in the event of unacceptable fault.
The electric billing by the electric utility is usually computed and issued on a monthly basis. Billing demand is usually established on a monthly basis and is taken as the highest demand recorded.4 Utility Power Rates. 21.2 Energy Charge. 21. These are typically as follows: a) b) Service at secondary voltage.000 volts). Utility power rates are based on the utility's costs to provide both electrical capacity and energy.5.5.000 to 69. The electrical demand for billing purposes is usually determined from demand instruments located at the customer facility such as a kW meter and associated printing recorder which periodically records the kW load or demand. Rate schedules for energy will vary according to geographic area and usage.4.4. Rate schedules for demand will vary according to geographic area and usage. research and development surcharge.MIL-HDBK-1003/7 21. Service at primary voltage (12.5.1 Demand Charge. or some percentage of the highest. the demand may be determined by tests made by the utility. 21. and maintenance.5. Many utilities' rate schedules also contain a ratcheted demand clause which establishes a minimum billing demand based on the highest. The effect of the ratchet may result in a billing demand for a month of low demand.4. or some other chosen period. demand occurring in the previous 12 months. Therefore any peak shaving scheme which can be used to reduce demand can result in savings which may economically justify the investment costs for peak shaving equipment and its fuel usage. 21. and taxes.4. usually in any 30-minute interval. Energy charges are usually tied to billing demand in such a manner that low energy use at a high demand is charged at a high rate whereas a large energy use at a low demand is charged at a lower rate. The rates charged for electrical demand and energy depend on other factors or the type of service. In some cases. This is reflected in the billing as charges for electrical demand and energy.4 Other Factors for Sale of Electricity. The total electric bill will usually be the sum of the demand and energy charges plus adjustment for such items as fuel cost. for instance a winter month. The energy usage for billing purposes is determined from kWh meters located at the customer's facility.3 Total Electric Billing. that is based on a high demand in a previous summer month. operation. Rate schedules take various forms. depending on the utility and state public utility commission practices. 266 .5.
Seasonal service. cogeneration facilities that are not owned by an electric utility and that meet certain standards are eligible for special incentive rates to be paid to them by the utility as required under Section 210 of PURPA. For parallel operation with a cogenerator. An electric utility's "avoided costs" are primarily fuel cost for production of energy and capital cost of facilities for generation capacity. 21. Supplementary service. the electric utility would generate or construct itself or purchase from another source. These incentive rates that the utility is obligated to pay to qualifying facilities are not required directly by PURPA but are required by rules promulgated by the Federal Energy Regulatory Commission (FERC. "Avoided costs" include the fixed and running costs on a utility system that can be avoided by obtaining energy or capacity from a qualifying facility. rather than generating the energy itself or purchasing the energy or capacity from other suppliers.4. Breakdown service.MIL-HDBK-1003/7 c) d) e) f) g) h) Standby service. 267 .5. Space heating. electric utilities under certain terms and conditions. Water heating. The term "avoided costs" has been defined by FERC as the costs to an electric utility of energy. As covered under section 201 of the Public Utility Regulatory Policy Act of 1978 (PURPA). capacity. The amount a utility will pay a cogenerator for purchased electricity produced by the cogenerator is equal to or is a percentage of the utility's "avoided cost" as decided by agreement contract between the utility and cogenerator.5 Purchase of Electricity.) These rules by FERC provide that electric utilities must purchase electric energy and capacity made available to the electric utilities by qualifying cogenerators at a rate that reflects the costs that the purchasing utility can avoid as a result of obtaining energy and capacity from these sources. or both. that but for the purchase from a qualifying facility. may purchase excess electricity generated by the cogenerator. or as set out in a rate schedule published by the utility.
resulting from the use of cogeneration as compared to purchase of electricity from a utility. There is a fuel saving for production of electricity. the higher will be the efficiency of cogeneration or economic return on investment capital. or reciprocating combustion engine. This ratio is defined as the ratio of the power generated to heat available for process or environmental heating/cooling systems. A cogenerator using only condensing turbine generator equipment cannot compete economically with an electric utility using the same type of equipment because of the economics of large scale operations. and added maintenance. added operation. The noncondensing and condensing equipment may be combined into single machines such as automatic extraction condensing turbine generators. The higher the power to heat ratio. if the exhaust heat or steam from the prime mover is used by other process or environmental heating/ cooling systems. However. 21. The basic cogeneration systems that provide the means to utilize exhaust heat from the prime mover are the back pressure steam turbine. 21. added fuel usage.1 Fuel Savings. gas turbine. cogeneration can be economically justified if the savings in electrical energy costs.6. However. there is no fuel saving when compared to the use of boilers for the production of steam for process or environmental heating/cooling systems.6. by use of cogeneration as compared to non-cogeneration systems. Cogeneration plants are capital intensive and high maintenance facilities. condensing steam turbine generators can be economically combined with noncondensing or extraction turbine generators if the noncondensing equipment is utilized to the extent that fuel savings more than offset the increased cost of operation of the condensing equipment. 21.MIL-HDBK-1003/7 21. offset the costs of the cogeneration facility capital investment.6.6 Economics.3 Power to Heat Ratio. A gauge for match of the cogeneration system with the facility heat or steam and electric demands is often expressed as the power to heat ratio. The utility's large condensing steam turbine generators operating at high initial pressure and temperature are much more efficient than would be a cogenerator's small condensing steam turbine generators operating at lower initial pressures and temperatures.2 Competitive Systems. combined cycle. Table 34 shows typical power to heat ratios of cogeneration systems. Using cogeneration. 268 .
MIL-HDBK-1003/7 Table 34 Typical Performance of Cogeneration Systems Power to Heat Ratio +)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))). The evaluation will require complete information for the facility concerning electricity and steam (or heat) usage and load demand on an hourly basis throughout a typical year. and material costs. periodic replacement costs and salvage value may need to be determined. 269 . modes of analysis. and annual maintenance labor. a determination must be made of total capital investment cost. Gen. methods and procedures for analysis. For a complete description of life cycle costing. 21.853 1.6. 21. annual operating costs.))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))1 Gas turbine. The application of cogeneration to a facility is site specific insofar as economic evaluation is concerned. The economic evaluation of the various alternate systems is best done on a life cycle cost basis and by a present worth type analysis. and backpressure turbine generator.6. * Backpressure Gas Diesel * 1Combined * Turb. Also.171 0. Depending on the type of evaluation used.683 0. The annual costs of fuel and purchased electricity must be determined for each alternate system to be considered. parts. Life-Cycle Cost Manual for the Federal Energy Management Programs. for each alternate system considered.5 Economic Evaluation. heat recovery steam generator. and choice of most economical alternate. including an alternate without cogeneration. refer to NAVFAC P-442 or National Bureau of Standards Handbook 135.4 Economic Variables. Turbine Cycle Gen.365 * * Btu power/Btu steam . * * * * kWh/million Btu steam 50 to 1 200 to 1 250 to 1 400 to 1 * 0.
. 1735 "Eye" Street NW.. Process Instruments and Controls Handbook. Washington. Considine. DC 20006. NY. Douglas M.MIL-HDBK-1003/7 BIBLIOGRAPHY The International District Heating Association (IDHA). available from McGraw-Hill. New York. District Heating Handbook. 270 . available from IDHA. Third Edition (1985).
BULLETINS. High & Low Pressure. Unless otherwise indicated. and Gas/ Oil Combination Burners. Deaerating (For Water Only) 1. General Service and Boiler Feed. High Pressure Water Tube. HANDBOOKS. users of this handbook should use the latest revisions of documents cited herein. Oil. Packaged Type Boiler. Centrifugal. AND NAVFAC GUIDE SPECIFICATIONS: The following specifications. Horizontal. Fluid.000 Pounds Per Hour Capacity Regulator.MIL-HDBK-1003/7 REFERENCES Note: Unless otherwise specified in the text. Centrifugal. Steam & Hot Water. Forced and Induced Steam turbines For Mechanical Drive Burner. copies are available from STANDARDIZATION DOCUMENTS ORDER DESK. Automatic Manual. Firetube Packaged Type Pump Units. Oil. Water. Draft. Mechanical-Draft.600. Electric Motor or Steam Driven Heater. Gas.. Phila. Technical. PA 19111-5094. Single.000 to 1. Automatic Fan. Boiler Feed Water. standards. Steam. STANDARDS. FEDERAL/MILITARY SPECIFICATIONS. SPECIFICATIONS MILITARY MIL-B-17095 MIL-B-17452 MIL-P-17552 Boiler. bulletins and handbooks form a part of this document to the extent specified herein. General Style and Format Requirements MIL-H-17660 MIL-R-18115 MIL-F-18523 MIL-T-18246 MIL-B-18796 MIL-B-18797 MIL-M-38784 271 . 700 Robbins Ave. Building 4D.
(NPFC).01 DM-3. Ventilating. Philadelphia. 5801 Tabor Avenue. DM-3. Design and Construction Airfield Lighting Dockside Utilities For Ship Service Covered Storage Facility Planning and Design Guide NAVY MANUAL. and Compressed Air Industrial Ventilation Systems Electrical Engineering Preliminary Design Considerations Cathodic Protection Water Supply Systems Fire Protection for Facilities Engineering. Philadelphia. and Air Conditioning and Dehumidifying Systems Compressed Air and Vacuum System Solid Waste Disposal 272 . Code 1051.10 Pluming Systems Heating. HTW. P-PUBLICATIONS. the private sector must write to NPFC.MIL-HDBK-1003/7 HANDBOOKS MIL-HDBK-1002/2 MIL-HDBK-1003/6 MIL-HDBK-1003/8 MIL-HDBK-1003/17 MIL-HDBK-1004/1 MIL-HDBK-1004/10 MIL-HDBK-1005/7 MIL-HDBK-1008 MIL-HDBK-1023/1 MIL-HDBK-1025/2 MIL-HDBK-1032/2 MIL-HDBK-1190 Loads Central Heating Plants Exterior Distribution of Utility Steam. PA 19120-5099. AND MAINTENANCE OPERATING MANUALS: Available from Commanding Officer.05 DM-5. ATTENTION: Cash Sales. To order these documents: Government agencies must use the Military Standard Requisitioning and Issue Procedure (MILSTRIP). Naval Publications and Forms Center.03 DM-3. Gas. CHW. PA 19120-5099. 5801 Tabor Avenue.
1A NAVFACINST 10340.6 OPNAVINST 5100.4C OPNAVINST 4100. Unless otherwise specified. 51-50AAA-2 General Requirements for Shorebased Airfield Marking and Lighting OTHER GOVERNMENT DOCUMENTS AND PUBLICATIONS: The following Government documents and publications form a part of this document to the extent specified herein. Naval Publications and Forms Center. 700 Robbins Avenue. Naval Air Technical Services Facility. Philadelphia.14 NAVFACINST 10343. Philadelphia. Gates. Pipe NAVY DEPARTMENTAL INSTRUCTIONS: Available from Commanding Officer. PA 19111-5097. and Guard Towers Petroleum Fuel Facilities Weight-Handling Equipment Solid Waste Management Seismic Design For Buildings Economic Analysis Handbook Hangers And Support. SECNAVINST 7000. 5801 Tabor Avenue.12 DM-22 DM-38 MO-213 P-355 P-442 WW-H-171E Fencing. ATTENTION: Code 3015.MIL-HDBK-1003/7 DM-5. the issues of the documents which are DoD adopted are those listed in the Department of Defense Index of Specification & Standards (DODISS). PA 19120-5099. Navy Distillate and Marine Diesel Fuel Oils.23 Economic Analysis and Program Evaluation for Navy Resource Management Navy Special. DEPARTMENT OF THE ARMY TM 5-811-6 Electric Power Plant Design 273 . On-Shore Use of Coal Requirement and Requisitions Energy Financing and Source Selection Criteria for Shore Facilities Navy Occupational Safety & Heath Program NAVAL AIR SYSTEM COMMAND: Available from Commanding Officer.
Occupational Safety and Health Act of 1970 29 CFR 1910. 200 Constitution Avenue NW. Subpart D 40 CFR 60. Washington DC 20210) DEPARTMENT OF TRANSPORTATION AC 70/7460-IF AC 150/5345-43C 14 CFR 77 Obstruction Marking and Lighting Specification for Obstruction Lighting Equipment Object affecting navigable Airspace (available from Superintendent of documents. paragraph 1910.S.MIL-HDBK-1003/7 TM 5-1815-1/AFR 19-6 Air Pollution Control Systems for Boilers and Incinerators (Unless otherwise indicated. Government Printing Office.C. 20402) (Unless otherwise indicated. D. ST. copies are available from US Army AG Publications Center.W. copies are available from Federal Aviation Administration Office of Airport Standards (AAS-200). Subpart Db Clean Air Act Standards of Performance for Fossil Fuel Fired Steam Generators Standards of Performance for Electric Utility Steam Generating Units Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units 274 . Subpart Z. Washington. DC 20591) ENVIRONMENTAL PROTECTION AGENCY 42 USC & 7401 et seq. Missouri 63114) DEPARTMENT OF LABOR 29 CFR 1910. Washington. Chapter XVII. 800 Independence Avenue. Louis. 1655 Woodson Road. 40 CFR 60.1200. S. U. copies are available from Occupational Safety and Health Administration. Subpart Da 40 CFR 60. Hazard Communication Standard (Unless otherwise indicated.
Fifth Edition.. ASME Baumeister. Design of Suction Piping: Piping and Deaerator Storage Capacity To Protect Feed Pumps. (1944). NY. Louis E. Combustion/Fossil Power Systems. NY. Modern Turbines. the issues of the documents which are DoD adopted are those listed in the Department of Defense Index of Specifications & Standards (DODISS): Combustion Engineering. Crocker.MIL-HDBK-1003/7 40 CFR 60. Providence. Eighth Edition. available from John Wiley & Sons. CT 06095. D.S. available from ITT Grinnell Corporation.C. Inc. Appendix A 40 CFR 136 Reference Methods Guide lines establishing test procedures for the analysis of pollutants Criteria for classification of solid waste disposal facilities and practices. Fourth Edition. available from McGraw-Hill. and Disposal Facilities 40 CFR 257 40 CFR 264 40 CFR 265 (Unless otherwise indicated. 275 . copies are available from Superintendent of Documents.. Sabin (1967). Volume 83. New York. New York. 1000 prospect Hill Road. Marks' Standard Handbook for Mechanical Engineers. available from Combustion Engineering. Inc. Journal of Engineering for Power. available from McGraw-Hill Book Company. New York. Washington. Theodore. Regulations For Owners and Operators of Permitted Hazardous Waste Facilities Interim Status Standards For Owners and operators of Hazardous Waste Treatment. NY. 20402) NON-GOVERNMENT PUBLICATIONS: The following publications form a part of this document to the extent specified herein. Rodney S. Storage. Thurston. Newman. ITT Grinnell Corporation (1973). Windsor. Piping Design and Engineering. U. Government Printing Office. and Baumeister III. RI. Piping Handbook. Theodore (1978). Avalone. (1981). January 1961. Eugene A. Unless otherwise specified.
New York. Safety Requirements Mechanical Power Transmission Apparatus. Railings. Melbourne. Cincinnati. Kenneth J. Single or Multiple Girder.10 C50.02 Floor and Wall Openings. E. Inc.13 276 . 6500 Glenway. Krieger Publishing Co.MIL-HDBK-1003/7 Grant.) AMERICAN NATIONAL STANDARDS INSTITUTE (ANSI) A12 A14. L. Steam Turbines and Their Cycles. (1974). for Cylindrical Rotor Synchronous Generators B30. Principles of Engineering Economy. OH 45211. Steam/Its Generation and Use. The Babcock & Wilcox Company (1978). Power Plant Engineering and Design. New York.11 B30. available from Babcock & Wilcox. NY 10017. available from Van Nostrand Reinhold Co.. FL.03 B15.01 B30. 161 East 42nd Street. available from Robert E. Bldg D-7. Salisbury. (1982). Safety Standard for Conveyors and Related Equipment Overhead And Gantry Cranes (Top Running Bridge. copies are available from American Conference of Governmental Industrial Hygienist. NY.. 39th Edition. Frederick Tracy (1943)..01 B20. New York. AMERICAN CONFERENCE OF GOVERNMENTAL INDUSTRIAL HYGIENISTS Industrial Ventilation . Safety Requirements for Fixed-Ladders. available from Wiley & Sons. Top Running Trolley Hoist) Monorails and Underhung Cranes Overhead Hoists (Underhung) National Electric Safety Code General Requirements for Synchronous Machines Reg.A Manual of Recommended Practices (Unless otherwise indicated. and Boards.. Morse. NY.16 C2 C50.
(ASHRAE) HE ASHRAE Equipment Handbook HF HS ASHRAE Fundamentals Handbook ASHRAE Systems Handbook (Unless otherwise indicated. 1791 Tullie Circle. N. copies are available from ANSI Standards.MIL-HDBK-1003/7 C50.1 ANSI/IEEE 100 ANSI/NFPA 31 ANSI/NFPA 37 ANSI/NFPA 70 ANSI/NFPA 85F (Unless otherwise indicated.1 Z83. copies are available from ASHRAE. 1430 Broadway. NEW York. INC.14 Requirements for Combustion Gas Turbine Driven Cylindrical Rotor Synchronous Generators Electric Power Systems and Equipment Voltage Rating Gas Utilization Equipment in Large Boilers Eyewash and Shower Equipment. Emergency Power Piping Dictionary of Electrical & Electronic Terms Installation of Oil Burner Equipment Combustion Engines and Gas Turbines National Electric Code Installation and Operation of Pulverized Fuel C84.E. GA 30329) AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME) Boiler and Pressure Vessel Code Theoretical Steam Rate Tables Recommended Practices for the Cleaning. AND AIR-CONDITIONING ENGINEERS. NY 10018) AMERICAN SOCIETY OF HEATING.1 ANSI/ASME B31.3 Z358.. Atlanta. and Purification of Steam and Gas Turbine Lubrication Systems 277 . Flushing. REFRIGERATING.
8 PTC-19. Pressure Measurement Temperature Measurement Application.6 PTC-19.10 278 . Vacuum Pumps.5.3 PTC-19.1 PTC-1 PTC-2 PTC-4.7 PTC-19.2 PTC-9 PTC-11 PTC-12. Instruments and Apparatus.3 PTC-14 PTC-19 PTC-19. Closed Feedwater Heaters. Steam Condensing Apparatus.1 PTC-8.MIL-HDBK-1003/7 ANSI/ASME B31.1 PTC-19.5 Power Piping General Instructions Definitions and Values Steam Generating Units Air Heaters Interim Test Code for an Alternative Procedure for Testing Steam Turbines Centrifugal Pumps Displacement Compressors.1 PTC-4.V Part 10 PTC-19. Part II of Fluid Meters: Interim Supplement on Instruments and Apparatus Weighing Scales Electrical Measurements in Power Circuits Measurement of Shaft Power Measurement of Indicated Horsepower Flue and Exhaust Gas Analyses Instruments & Apparatus .2 PTC-19. Evaporating Apparatus.1 PTC-12.3 PTC-6. Deaerators.2 PTC-12. and Blowers Fans.
Test Procedure. copies are available from American Society for Testing and Materials. A 285/A285M-82 A 516/A516M-84 D2013-72(1978) D2234-82 (Unless otherwise indicated. TX 77388) 279 . Fairfield. copies are available from ASME order Dept.12 PTC-19. NJ 07007-2350) AMERICAN SOCIETY FOR TESTING AND MATERIALS (ASTM) A 283/A283M-84a Specification for Low and Intermediate Tensile Strength Carbon Steel Plates.13 PTC-19. Carbon Steel.MIL-HDBK-1003/7 PTC-19. PA 19103. Box 2350. for Moderate and Lower Temperature Service. Shapes. copies are available from Cooling Tower Institute. Spring. Low-and Intermediate-Tensile Strength.. and Bars. Method for Preparing Coal Samples for Analysis. Part 2. 1916 Race Street.) COOLING TOWER INSTITUTE (CTI) CTI Bulletin ATC-105 Acceptance Test Code For Water Cooling Towers (Part 1. Evaluation of Results) (Unless otherwise indicated. 22 Law Drive. (Unless otherwise indicated. Carbon Steel. Specification for Pressure Vessel Plates. Method for Collection of a Gross Sample of Coal. Specification for Pressure Vessel Plates. 19627 Tower 45 North. Suite 230.17 PTC-21 Measurement of Time Measurement of Rotary Speed Linear Measurements Density Determinations of Solids and Liquids Determination of the Viscosity of Liquids Dust Separating Apparatus. Philadelphia.16 PTC-19.14 PTC-19.
) CUSTODIAN NAVY .M. Washington..YD PROJECT NO. NY 10017) NATIONAL ASSOCIATION OF CORROSION ENGINEERS (NACE) Cooling Water Treatment Manual Handbook (Unless otherwise indicated copies are available from NACE.YD PREPARING ATIVITY NAVY . 2101 L Street. Furnace Implosions in Multiple Burner (Unless otherwise indicated. FACR-0645 280 .000 KW Enclosures for Electrical Equipment (1000 Volts Maximum) (Unless otherwise indicated.MIL-HDBK-1003/7 HEAT EXCHANGE INSTITUTE (HEI) Standards for Steam Surface Condensers. New York. Batterymarch Park. copies are available from Heat Exchange Institute. Texas 77027) NATIONAL ELECTRICAL MANUFACTURERS ASSOCIATION (NEMA) SM 23 SM 24 Standard publication/ No. copies are available from NFPA. Code Oil Burning Equipment Installation Boiler-Furnaces.) NATIONAL FIRE PROTECTION ASSOCIATION (NFPA) 30 31 85G Flammable and Combustible Liquids. MA 02269. Sixth Edition (Unless otherwise indicated. 122 East 42nd Street. copies are available from NEMA Standards. D. Quincy. Houston. 2400 West Loop South. 250 Steam Turbines for Mechanical Drive Service Land Based Steam Turbine Generator Sets 0 to 33.C. N. 20037.
UFC 3-540-02N 16 January 2004 APPENDIX B MIL-HDBK 1003/7. NOTICE 1 STEAM POWER PLANTS B-1 .
NOTICE OF CHANGE INCH-POUND MIL-HDBK-1003/7 NOTICE 1 15 May 1999 DEPARTMENT OF DEFENSE HANDBOOK STEAM POWER PLANTS – FOSSIL FUELED TO ALL HOLDERS OF MIL-HDBK-1003/7: 1. Custodian: Navy . This issuance. together with appended pages. Holders of MIL-HDBK-1003/7 will verify that page changes and additions indicated above have been entered.YD2 (Project FACR-5008) AMSC N/A AREA FACR . RETAIN THIS NOTICE AND INSERT BEFORE TABLE OF CONTENTS. is a separate publication. 3. THE FOLLOWING PAGES OF MIL-HDBK-1003/7 HAVE BEEN REVISED AND SUPERSEDE THE PAGES LISTED: ________________________________________________________________ NEW PAGE DATE SUPERSEDED PAGE DATE_______ 173 15 September 1990 173 15 May 1999 174 15 September 1990 174 15 May 1999 ________________________________________________________________ 2.YD2 Preparing Activity: Navy . Each notice is to be retained by stocking points until the handbook is completely revised or canceled. This notice page will be retained as a check sheet.
173 . grade and mezzanine level Turbine generator bearings Boiler feed pump turbine Dry pipe sprinklers Automatic Preaction spray Deluge spray Fixed temperature Manual Dry pilot Automatic SUPERSEDES PAGE 173 OF MIL-HDBK-1003/7.MIL-HDBK-1003/7 Table 28 Typical Fixed Fire Detection and Suppression Systems Type of Fire Suppression System Location Type of Detection Fixed temperature quartzoid bulb Operation Automatic Administration Wet pipe Area (excluding sprinkler Halon protected areas) Plans and records storage room NFPA or DOD approved Cross-zoned Automatic ionization and photo-electric smoke detection system Ionization smoke detection Ionization smoke detection Ionization smoke detection Cross-zoned ionization and photo-electric Fixed temperature quartzoid bulb Ionization smoke detection Fixed temperature quartzoid bulb Alarm only Control room (below ceiling) Control room (above ceiling) Control room (main control panel) Control equipment room Not applicable Not applicable Alarm only Not applicable Alarm only NFPA or DOD approved Automatic Cable spreading room Wet pipe sprinkler -- Automatic Alarm only Turbine underfloor area.
174 .MIL-HDBK-1003/7 Table 28 (Continued) Typical Fixed Fire Detection and Suppression Systems Type of Fire Suppression System Type of Detection Preaction spray Deluge spray Deluge Fixed temperature Location Warm-up guns and igniters Igniter oil pumps Operation Automatic Dry pilot Automatic Hydrogen seal oil unit Turbine lube oil reservoir and conditioner Main generator and auxiliary transformers Reserve auxiliary transformers Switchgear areas and major motor control center Coal conveyors within generation building Air heaters Dry pilot Automatic Deluge spray Dry pilot Automatic Deluge spray Deluge spray None Dry pilot Automatic Dry pilot Automatic Smoke detection only Fixed temperature quartzoid bulb Infrared hot spot detectors Carbon monoxide monitoring Alarm Dry pipe sprinklers Deluge spray Steam inerting Waterwash Automatic Manual Coal pulverizers Manual Manual (for B&W only) Thermistor wire Automatic Coal dust collectors Preaction sprinkler SUPERSEDES PAGE 174 OF MIL-HDBK-1003/7.
This action might not be possible to undo. Are you sure you want to continue?
We've moved you to where you read on your other device.
Get the full title to continue listening from where you left off, or restart the preview.