The URL can be used to link to this page

Home My WebLink AboutReconnaissance Evaluation of Small Low Head Hydroelectric Installations 1980{ ; . I I I (-I 1 ; I_. . I , i l I I ·! j/YD [A.Cj i ! : I_ , r --. L ' i ~· .· PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501' RECONNAISSANCE EVALUATION OF SMALL, LOW-HEAD HYDROELECTRIC INSTALLATIONS to WATER AND POWER RESOURCES SERVICE U.S. DEPARTMENT OF.INTERIOR July 1, 1980 Contract No. 9-07-83-V0705 TUDOR ENGINEERING COMPANY 149 NEW MONTGOMERY STREET SAN FRANCISCO, CALIFORNIA 94105 I y j.: ' I RECONNAISSANCE EVALUATION OF SMALL, LOW-HEAD HYDROELECTRIC INSTALLATIONS This report was prepared by Tudor Engineering Company for· Division of Planning and Technical Services, Engineering and Research Center Water and Power Resources Service. Horace E .. Burrier, Principal Investigator, Nelson J. Jacobs, WPRS, Principal in Charge Department of Energy provided fund support under the Small Hydro Commercialization Program. The criteria and data contained in this manual are based upon generally accepted engineering standards utilized by the electric power industry in reconnaissance evaluation of small, low-head hydroelectric develop- ments. The report does not necessarily portray standards and criteria accepted by or used by the Water and Power Resources Service in appraisal evaluation of small, low-head hydroelectric developments. Date: July 1, 1980 Contract No. 9-07-83-V0705 ' - i YS·2SO (3·78) Bureau pf Reclamation TECHNICAL REPORT STANDARD TITLE PAGE I. REPORT NO. 4. TITLE AND SUBTITLE Reconnaissance Evaluation of Small, Low-Head Hydroelectric Installations 7. AUTHOR(Sl 9. PER.FORMING ORGANIZATION NAME AND ADORES~ Tudor Engineering Company 149 New Montgomery Street San Francisco, California 94105 3. RECIPIENT'S CATALOG NO. 5. "EPORT DATE July 1, 1980 6. PEFfFO~MIN'f ORGAtiiZATION C~OE B. PERFORMING ORGANIZATION REPORT NO. 10. WORK UNIT NO. 11. CONTRACT OR GRANT NO. 9-07-83-V0705 ~___,..,...,...="'"..,.,-,.~,....,...,,.,.,.,.~,.,....,.::--:-~-:-:==::-;~(4:,.,!1~5!...)L..-~9~8.!::.2.,:-~8.~.:1:.!.;3~:.!.!...... g_, 13. ~6~~Ro:D REPORT ~NO PERIOD 12. SPONSORING AGENCY NAME AND ADDRESS December 1977 Water am:! Power Resources Service Engineering and ·Research Cent~r July 1980 DenVer federal Center 14. SPONSORING AGENCY CODE Denver, Colorado 80225 (303) 234-3166 1S. SUPPLEMENTARY NOTES The report is a cooperative sponsored effort of the Water and Power Re- sources Service and Department of Energy with funding provided by the Department of Energy. 16 . .4-BSTRACT The report describes a methodology for making an appraisal level eval- uation of small low-head hydroelectric developments not exceeding 15,000 kW or having operating heads above 65 feet. Equipment and cost data required to make the evaluation are included in the report. All cost data are given in terms of July 1978 costs but methodology is presented to index cost data to any future date. Methods of determining power and energy available from any site conditions are presented. Financial analysis and methods of financing small developments are reviewed. Three examples of applying the report methodology are presented in the report. 17. KEY WORDS AND DOCUMENT ANALYSIS a. DESCRIPToRs--Low-head hydropower, small hydropower, appraisal study, feasibility study, economic feasibility, cost of small hydropower, hydro- power primary energy, lower 1 imits of sma·ll hydropower. b. IDENTIFIERS·- c. COSATI Field/Group COWRR: 18. DISTRIBUTION STATEMEto(T Available from the National Technical Information Service, Operations Division, Springfield, Virginia 22161. 19. SECURITY CLASS 21. NO. OF PAGEs (THIS REPORT) UNCLASSIFIED 407 20. SECURITY CLASS 22. PRICE (THIS PAGEl UNC!..ASSIFIED TABLE OF CONTENTS Section fage ----- SECTION 1 -- INTRODUCTION AND OVERVIEW 1-01 REPORT OBJECTIVE 1-01 REPORT METHODOLOGY 1-02 DATA AND COST BASIS 1-03 APPRAISAL STUDY OVERVIEW 1-03 FEASIBILITY STUDY 1-07 NATURE OF SMALL HYDROELECTRIC INSTALLATIONS 1-08 SECTION 2 ---- ASSESSMENT OF STATE-OF-THE-ART 2-01 GENERAL 2-01 SCOPE 2-01 METHODOLOGY 2-02 COLLECTED DATA 2-02 BRIEF SUMMARY OF STATE-OF-THE-ART 2-09 r--1 SECTION 3 l_l ESTIMATION OF POWER AND ENERGY 3-01 GENERAL 3-01 SITE CONDITIONS 3-01 THE POWER FORMULA 3-08 FLOW-DURATION CURVE 3-09 OPERATION SCHEMES 3-11 DEPENDABLE CAPACITY 3-12 INTERMITTENT CAPACITY 3-14 POWER AND ENERGY ESTIMATES -FLOW-DURATION CURVES 3-14 POWER AND ENERGY ESTIMATES -OPERATION STUDY 3-17 HYDRAULIC CRITERIA 3-23 SECTION 4 TYPICAL LAYOUTS OF LOW-HEAD PLANTS AND APPURTENANCES 4-01 GENERAL 4-01 TURBINE TYPES 4-01 TURBINE STANDARDIZATION 4-06 TURBINE EFFICIENCY 4-07 HEAD LIMITATIONS 4-09 FLOW LIMITATIONS 4-10 D TURBINE SELECTION SUMMARY 4-10 TURBINE PERFORMANCE 4-11 TURBINE SELECTION 4-14 0 TURBINE GOVERNOR 4-19 PLANT EFFICIENCY 4-21 i Section SECTION 4 (Continued) ELECTRICAL SYSTEM TRANSMISSION LINES MISCELLANEOUS POWER PLANT EQUIPMENT MULTI-UNIT POWER PLANTS STANDARDIZATION DAMS NEW DAMS REHABILITATION OF EXISTING DAMS WATERWAYS TAILRACE SITE DEVELOPMENT TYPICAL LAYOUTS SECTION 5 CONSTRUCTION AND INDIRECT COSTS POWER PLANT WATERWAY COSTS DAM COSTS SWITCHYARDS TRANSMISSION LINES SITE DEVELOPMENT INDIRECT COSTS COST SLMMARY · OPERATION AND MAINTENANCE COSTS SECTION 6 FINANCIAL ANALYSIS GENERAL ANNUAL! ZED COST GENERAL FINANCING METHODS FINANCIAL ALTERNATIVES FINANCIAL ANNUALIZED COST SECTION 7 ECONOMIC ANALYSIS GENERAL PROCEDURE ANNUAL OPERATING EXPENSE INFLATION i i 4-23 4-28 4-28 4-31 4-32 . 4-34 4-39 4-45 4-46 4-52 4-53 ' 4-56 5-01 5-01 5-08 5-13 5-17 5-18 5-18 5-20 5-22 5-24 6-01 6-01 6-01 6-03 6-05 6-08 7-01 7-01 7-01 7-03 '7-06 l_ ,--l ' It \ ! L_j Section SECTION 7 (Continued) VALUE OF ENERGY TYPICAL POWER AND ENERGY DEMANDS BENEFIT/COST ANALYSIS SECTION 8 PRIMARY ENERGY REQUIREMENTS AND ENERGY BALANCE GENERAL REQUIREMENTS SECTION 9 SMALLEST PRACTICAL SIZE DEVELOPMENT GENERAL ECONOMICS SITE CONDITIONS EQUIPMENT SUMMARY SECTION 10 DEMONSTRATION OF PROCEDURE GENERAL EXAMPLE -CANAL INSTALLATION EXAMPLE -EXISTING DPM INSTALLATION EXAMPLE -NEW DAM INSTALLATION SECTION 11 FEASIBILITY STUDY PROCEDURE GENERAL PROCEDURE SECTION 12 SUMMARY APPENDIX COMPUTER PRINTOUT OF SMALL HYDROELECTRIC DATA EQUIPMENT MANUFACTURERS DATE EQUIPMENT SIZE DATA i i i _Page_ 7-07 7-07 7-11 8-01 8-01 8-02 9-01 9-01 9-01 9-02 9-02 9-03 10-01 10-01 10-02 10-17 10-35 11-01 11-01 11-01 12-01 A-01 B-01 C-Ol Section COST SUMMARY SHEET LIST OF REFERENCES D-Ol i v Number 2-1 3-1 3-2 3-3 3-4 3-5 3-6 3-7 3-8 4-1 4-2 4-3 4-4 4-5 4-6 4-7 4-8 4-9 4-10 4-11 4-12 4-13 4-14 4-15 4-16 4-17 4-18 4-19 4-20 4-21 4-22 4-23 4-24 4-25 4-26 4-27 4-28 4-29 4-30 4-31 LIST OF FIGURES O&M and Replacement Cost Typical Flow -Duration Curve Reservoir Operation -Capacity Credit Non-Storage Operation -Capacity Credit Non-Storage Operation -No Capacity Credit Typical Non-Storage Flow -Duration Curve Typical Canal Flow -Duration Curve Heads -Reaction Turbines Hydraulic Losses Turbine Cross Sections Shop Assembly of Tubular Turbine Tubular Turbine Dimensions Turbine Performance Curve Francis Turbine Turbine Performance Curve -Kaplan with Wicket Gate Turbine Performance Curve -Kaplan - Fixed Guide Vanes Turbine Performance Curve -Propeller Turbine Tubular Turbine Performance Curves Francis Turbine Throat Diameters Kaplan and Propeller Turbine Throat Diameters Recommended Total Draft Head Types of Governors One Line Electrical Diagram-Line Breaker One Line Electrical Diagram -Generator Breaker Switchyard Arrangement Transmission Line Capacity Types of Power Houses Layout -Vertical Francis Turbine Layout -Horizontal Francis Turbine Layout Propeller Turbine -Penstock Layout -Propeller Tu.rbine -Headworks Layout -Open Flume Turbine -Without Bypass Layout Open Flume Turbine -With Bypass Layout -Tubular Turbine -Penstock Layout -Tubular Turbine -Headworks Layout -Bulb Turbine Layout Rim Turbine Layout -Crossflow Turbine Layout -Vertical Francis Turbine -Multiple Units Layout -Horizontal Francis Turbine -Multiple Units Layout -Open Flume Turbine -Without Bypass - Multiple Units v Page_ 2-12 3-30 3-31 3-32 3-33 3-34 3-35 '3-36 3-37 4-64 4-65 4-66 4-67 4-68 4-69 4-70 4-71 4-72 4-73 4-74 4-75 4-76 4-77 4-78 4-79 4-80 4-81 4-82 4-83 4-84 4-85 4-86 4-87 4-88 4-89 4-90 4-91 4-92 4-93 4:..94 Number 4-32 4-33 4-34 4-35 4-36 4-37 4-38 5-1 5-2 5-3 5-4 5-5 5-6 5-7 5-8 5-9 5-10 5-11 5-12 5-13 5-14 5-15 5-16 5-17 5-18 5-19 5-20 5-21 5-22 5-23 5-24 5-25 5-26 5-27 5-28 5-29 5-30 5-31 5-32 5-33 5-34 5-35 5-36 Layout -Open Flume Turbine -With Bypass - Multiple Units Layout -Tubular Turbine ~Multiple Units Layout -Bulb Turbine -Multiple Units Layout -Rim Turbine -Multiple Units Layout -Crossflow Turbine - Muitiple Units Layout -Typical Project Plan Layout -Alternative Turbine Arrangements -Sections Francis Turbine/Generator Costs Kaplan Turbine/Generator Costs Open Flume Turbine/Generator Costs Closed Flume Turbine/Generator Costs Tubular Turbine/Generator Costs Bulb and Rim Turbine/Generator Costs Crossflow Turbine/Generator Costs Station Electrical Equipment Costs Miscellaneous Power Plant Equipment Costs Vertical Francis Powerhouse Cost Horizontal Francis Powerhouse Cost Kaplan Powerhouse Cost -Penstock Kaplan Powerhouse Cost -Headworks Open Flume Powerhouse Cost -With Bypass Open Flume Powerhouse Cost -Without Bypass Tubular Turbine Powerhouse Cost -With Penstock Tubular Turbine Powerhouse Cost -With Headworks Bulb Turbine Powerhouse Cost -With Headworks Rim Turbine Powerhouse Cost -With Headworks Crossflow Turbine Powerhouse Cost Powerhouse Excavation Costs Powerhouse Stability Intake Costs -Type A Powerhouse Gate Costs Penstock Costs -Steel Penstock Costs -Concrete Valve Costs Penstock Bifurcation Costs Bypass Costs Concrete Dams -Field Costs Earth Dams -Earthfill Per Lineal Foot of Dam Earth Dams -Field Cost of Structure Earth Dams -Field Cost of Spillway Earth Dams -Field Cost of Outlet Works Diversion Dam -Field Cost of Spillway and Sluiceway Diversion Dam -Field Cost of Gated Spillway and Sluiceway vi Page_ 4-95 4-96 4-97 4-98 4-99 4-100 4-101 5-29 5-30 5-31 5-32 5-33 5-34 5-35 5-36 5-37 5-38 5-39 5-40 5-41 5-42 5-43 5-44 5-45 5-46 5-47 5-48 5-49 5-50 5-51 5-52 5-53 5-54 5-55 5-56 5-57 5-58 5-59 5-60 5-61 5-62 5-63 5-64 ___ ) Number 5-37 5-38 5-39 5-40 5-41 5-42 5-43 5-44 5-45 5-46 5-47 5-48 5-49 5-50 5-51 5-52 7-1 7-2 7-3 7-4 7-5 8-1 8-2 9-1 9-2 9-3 9-4 9-5 9-6 9-7 11-1 Diversion Darn -Field Cost of Canal Headworks Switchyard Civil Costs Switchyard Electrical Cost -Generator Breaker Switchyard Electrical Cost Line Breaker Transmission Line Cost Grading and Miscellaneous Costs Cost Indices -Earth Dams Cost Indices-Canals Cost Indices -Miscellaneous Cost Indices Hydroelectic Plants Cost Indices Hydroelectric Plant Equipment Cost Indices -Electrical Equipment and Transmission Cost Indices -General Building Cost Indices Dams Construction Cost Variation in U.S. O&M and Replacement Cost Indices Load Factors and Annual Costs Typical Daily Load Curves Load Duration Curve Yearly Load and Energy Curve Benefit/Cost Ratio and Discount Rate Primary Energy for 5 MW Addition Primary Energy for 12 MW Construction Unit Cost -Energy Value -Load Factor Curves Unit Costs -Tubular Turbine Powerhouse Unit Costs -Kaplan Turbine Powerhouse ~ Penstock Unit Costs -Kaplan Turbine Powerhouse Headworks Unit Costs Vertical Francis Turbine Powerhouse Unit Costs Horizontal Francis Unit Costs -Open Flume Turbine Powerhouse Generalized Study'Flow Chart vi i -~age 5-65 5-66 5-67 5-68 5-69 5-70 5-71 5-72 5-73 5-74 5-75 5-76 5-77 5-78 5-79 5-80 7-18 7-19 7-20 7-21 7-22 8-7 8-8 9-7 9-8 9-9 9-10 9-11 9-12 9-13 11-10 Table 3-1 3-2 4-1 4-2 4-3 5-1 . 5-2 5-3 5-4 6-1 7-1 7-2 7-3 7-4 8-1 8-2 9-1 9-2 LIST OF TABLES Example -Hand Calculation of Hydroe1ectric Generation Operation Study -Computer Printout Turbine Performance Characteristics Generator and Equipment Efficiency Access Road Design Standards Miscellaneous Costs Steel Penstock Minimum Thickness Tai 1 race Cost Site Preparation Costs Cost ot Serv1ce Calculation Maximum and Minimum Power Demands Present Worth Stream - 6 Percent Discount Rate Present Worth Stream 15 Percent Discount Rate Present Worth Stream -Sensitivity Analysis Energy -Intensity Factors for Construction Annual Energy Use for O&M Replacement Small Low-Head Hydraulic Turbine Data Minimum Turbine/Generator Size vi i i 3-28 3-29 4-62 4-63 4-63 5-27 5-27 5-28 5-28 b-13 7-14 7-15 7-16 7-17 8-6 8-6 9-6 9-6 ABBREVIATIONS air circuit breaker .•....•.......•......•• ACB alternating-current (adjective) •.......••. a-c alternating-current (noun) •.•••.•••.••.•• a.c. aluminum conductor alloy reinforced •.•••.•••••••....•..•.••• ACAR aluminum conductor steel reinforced •••.••......•.••..•.•.••• ACSR American Institute of Steel Construction, Inc •.•••••••••......• AISC American Gear Manufacturers Associ at ion ••.•.•••••..•••••••••••••..••. AGMA American National Standards Institute .•••••.•...•••.••..••• ANSI American National Metric Council .....••.•.••..•...•••••••.• ANMC American Society for Testing and Materials ••.•.•.••••••••••••• ASTM American Water Works Association ••••.•..••••••••••••..•••.•••• AWWA American Welding Society ...••••••••••••••• AWS American Wire Gage ••.••..•••••••••••••••.• AI'vt ampere •••••••••••••.•••••••••••••••••••..•.• A ampere hour (ampere-hour) .•••••••••••••.•• A"h and so forth •••••••••••••••..•••.•••••••• etc. atmosphere ••••••••••• ~ ••••••••.••••••••••• Atm automatic data processing ••.••..•••••••.•..•.••••••••.•. ADP average ••••.•.•..•••••••••••.••.••••••••. avg. avoirdupois, pound •••••..•••••...•.•• lb, avdp barrel ••••••••••••••••••••••••••••.••••••• bbl barrel per day •.•••••••••.•.•••••••••••• bbl/d basic impulse insulation level ••.•.•••••••••••••••••••••••••••.•••• BIL brake horsepower •••••••••••••••••••••••••• bhp Brinnel hardness number •••••.•••.•••••••••••••••••••••••.•• Bhn BriUsh thermal unit ...................... Btu Bureau of Reclamation •••••••••.•••••••••• USBR ix Celsius (also centigrade (obsolete) ••••.••••••••....•.•••. C cent .....••••••••••...•.••••••••••••.••••••• ~ center to center ••••••.•••••••••.•••• c. to c. center line ••.•••••••.•.. · .••••••••••.•.•..•. CL centimetre •••••••••••.•..•.••.•••••••••.••• em circular miL •••••••..•••.•••••..•.••.•.• emil Camp any ...•.•••.•••••....•••.•••...••••••• Co • continued ••.•••••••.•••••••••.•••.•....•• con. conventional foot of water ••....•...•.•• ftH 2o conventional inch of mercury .•..•••..•••. inHg conventional inch of water •••.•••.••..•. inH 2o conventional millimetre of mercury •••..•.•••••••.•..•••••••.•.•• mm Hg Corporation •••.•..•••••••••••...•••••.•• Corp. critical path method ..................... cPM cubic centimetre ••••••••..•••••••••••••••• cm 3 cubic foot ••••••••••••••••••••..••.••••••• ft 3 cubic foot per minute ••••••••••••••••• ft 3/min 3 cubic foot per second .•.•.•••••••••••••• ft /s cubic hectometre ••.••••••••••.•••••••••••• hm 3 cubic inch •••••••••.•••••••••.•.•••••••.•• in3 cubic kilometre ••...•••••••.••..•.•.•••.•• km 3 cubic metre •.•.•...••••.••.•••......••••... m3 cubic metre per, second •••••••••••.•.••••• m3/s . 3 cubic yard ...•..•••..••••••...•••••••....• yd degree (plane angle) •...•.••••••••.. 0 , as 36° degree Celsius •••••••••..•••••.••..•..•••• °C, degree Fahrenheit ••.••••••••..•.•.•.••..•• °F, Department of Energy ••••••.••••••.••.•.•.• DOE Department of the Interior •••••••.••.••••.•••..•••••••••••• USDI Department of Transportation •••••••••••••••.••••••••.••• DOT Diameter •••••••••••.•••••••••••••••••••• (SI)!il ••••.••••••••••..•••••...•••• (customary) dia. Direct-current (noun) ••••.••••.•••••••••• d.c. Direct-current (adjective) •••••••••••••••• d-c dollar ••••••••••••••• o'o ••••••••••••••••••••• $ drawing •••••••••••••••••••••••••••• dwg or Dwg efficiency •••••••••••••••.•••••••••••••••••• n Environmental Impact Statement •••••••••••••••••••••••••••••.••• EIS elevation ••.••••••••••••••••••••••••••• (Sl)EL ••••••••••••••••••••••••••••••• (customary)El. Environmental Protection Agency ••••••••••••••••••••••••• EPA extra high voltage •••••••••••••••••••••••• EHV Fahrenheit ••••••••••.••••••••••••••••••••••• F figure ••••••••••••••••••••••••••••••••••• fig. Final Environmental Statement ••••••••••••••••••••••••••••••••• FES finish •••••••••••••••••••••••••••••••••••• fin fiscal year •••••••••••••••••••••••••••••••• FY foot ••••••••••••••••••••••••••••••••••••••• ft foot per second •••••••••••••••••••••••••• ft/s 2 foot per second squared ••••••••••••••••• ft/s foot-pound •••••••••••••••••••••••••••••• ft-lb for example ••••••••.••••••••••••••••••••• e.g. free on board •••.•••.•••••••••••••••••• f.o.b. frequency modulation ••••••••••••••••••••••• FM gallon •••••••••••••••••••••••••••••••••••• gal gallon per minute ••••••••••••••••••••• gal/min gravitational constant. •••••••••••••••••••• Gy hertz (singular or plural) ••••••••••••••••• Hz high frequency ••••••••••••••••••••••••••••• hf horsepower ••••••••••••••••••••••••••••••••• hp horsepowerhour •••••••••••••••••••••••••••• hph hour •••••••••••••••••••••••••••••••••••••••• h inch(es) ••••••••••••••••••••••••••••••••••• in Incorporated ••••••••••••••••••••••••••••• Inc. input-output •••••• , ••••••••••• ; ••••••••••• I/0 inside diameter •••••••••••••••••••••••••• i.d. X iron pipe size ••..•....••••.•••••••.•.•••• ips kilo (prefix, 10 3 ) ••••••••••••.•.••••••••••• k kiloampere •••••••.••••••••••••••••••••..••• kA kilogram ••••••••.•••••••••••••••••••••••••• kg kilogram per cubic 3 metre ••••••••••••••••••.•.•••••••••••••• kg/m kilohertz ••••••.••••••.••••••••••••••••• ,• . kHz kilo-ohm ••••••••.••••••••••••••••••.••••.•• kQ , kilo-metre ••••••••••.•••••••••••••.•••••••• km kilovolt., .••••••••••••••••••••••••••••••.•• kV kilovolt ampere •.•••••••••••••••••••••••• kV"A kilovolt ampere hour ••••••.•••••••••••• kV •A "h kilowatt ••••••.••••••••••.••••••••••••••••• kW kilowatthour (kilowatt-hour or kilowatt hour) ••••••••••••••••••••••••• kWh lineal foot •••••••••••••••••.•••••••••• lin ft maximum •••••••••••••••••••••••••••••••••• max. mega (prefix, 10 6 ) •••••••••••••••••••••••••• M megahertz ••••••••••••••••••••••••••••••••• MHz megajoule •••••••••••••••••••••••••••.•••••• MJ megavar •••••••••••••••••••••••••••••••••• Mvar megavolt ••••••••••••••••.•••••••••••••••••• MV megawatt ••••••••••••••.••••••.••••••••••••• MW megawatthour (metawatt-hour or megawatt hour) •••••••••••••••••••••.••• MWh megohm ••.•••••••••••••••••••••••••••••••••• MQ metre •••••••••••••••••••••••••••••••••••• • •• m metre per second •••••••••••••••••••••••••• m/s mil (0.001 inch) •••••••••••••••••••••••••• mil mile (statute) ••••••••••••••••••••••••.•••• mi mill (0.001 dollar) ...................... mill millimetre ••••••••••••••••••••••••••••••••• mm million gallons per day •••••••••••••••• Mgal/d minute (time) ••••••••••••••••••••.••••••• ;min month ••••••••••••••••••.••••••••••••••••••• rna National Bureau of Standards ••••.••••••••• NBS National Electrical Code •••••••••••••••••• NEC National Electrical Manufacturers Association •..••••••••••••• NEMA National Electrical Safety Code •••••••••• NESC National Environmental Protection Agency ••••••••••••.••••.•••••. NEPA National Fire Protection Association ••••• NFPA normally closed •••.•.•••.•.•••.•••••••••••• NC normally opened •••••••••••••••••••••.••.••• NO number ••••••••••••••.•••••••••••••••••.••. No. Occupational Safety and Health Act ••••••••••••••••••••••••••• OSHA ohm ••••••••••••••••••••.••••••••••••••••••• ,Q oil circuit breaker ••..•...•••••••••••.... OCB Operation & Maintenance ••••••••••••••••••• O&M outside diameter ••••...•••.•.••••••••.••• o.d. paragraph •••••••••••••••••••••••••••• • ••• par. percent (use% in tables only) ••••••• pct or% phase •••••••••.•.••.•••••••••••••••••••••••• )ll poly (vinyl chloride) pipe ••••••••••• PVC pipe pound ••••••.••••••••••••••••••••••••••••..• lb pound-foot ••.•••••••••••••••••••.•••.••• lb-ft pound-force ••••.•••••••••••••••••••••••••• lbf 2 pound-force per square foot ••••••••••• lbf/ft 3 pound per cubic foot •.•••••.••••••.•••• lb/ft pound per foot •••••••••••••••••••••••••• lb/ft 2 pound per square foot ••••..•.••.•.••••. lb/ft pound per square inch absolute •••• lb/in2 (abs) pound per square inch gage (psig) •••••••••••••••••••••• lb/in2 (gage) power circuit breaker ••••••••••••••••••••• PCB power factor ••••.••••.••.•••••••••..•••••.• PF radiofrequency~ •••••••.••••••.••••••••••••• RF reference.· •••••••.•••••••••••.•.•••••••.• ref. reinforced concrete pressure pipe •••••••••••••••••••••••••••. RCPP revolution per minute ••••••••••••••••••• r/min root mean square ••..•••••••••••••••••••••• rms second (time) .••..•••••••••.•••••••••••.•••• s .J xi section ................................... sec. square centimetre ••...•.•....••...••••.••. cm 2 ~ 2 square foot •••...•••••••.••••••••.•••••••• ft square hectometre ••••••.•••••.•••••••....• hm 2 square inch ••.••.•••.••.•••••••••••••••••• in2 square kilometre ••••.••••••.••••••••..•.•. km 2 square metre ••••••••••••••.•.•••••.•••••.• m 2 '1 .2 square m1 e ••••••••.•••••••••..•.••••••••. m1 square yard •••• : •••••••••••••••••••••••..• yd 2 standard •••••••••••••• , •••••••••••••••.•• std. 3 standard cubic foot (feet) ••..•......•. stdft standard cubic feet per minute .••.••• stdft3/m Standard (or Standing) Operating Procedure ••...•••.......•.•.•.•• SOP standard temperature and pressure ••••••.•• STP therm ••.••.•.•••••••••••••••••••••.••••••• thm thousand pounds .•••••••••••••••••••••••••• kip three conductor •••••...•••.••••.•••••••..• 3/c time: before noon •.••.••.•.•.••...•••••• a.m. afternoon ••••••••••••••••••.•••••. p.m. noon .. •.• ........................•... m. two conductor •••••••••••••••••••••••...••• 2/c ultrahigh frequency •••••••••••••••••..•••• uhf U.S. Geological Survey ••••••••••••.•••••. USGS versus •••..•••••••.••••.•••.•.•...•••••••• vs. volt •••••••.•••••••••••••••••••••••••••••••• V volt ampere (volt-ampere) ••.••.••••••••••• v•A volt ampere reactive •••••••• (Sl) v•A reactive •..••••••.•••••••••••••••••••. (customary) var volt per meter •••••••••••••••••••••••••••• V/m volume •••.•••••••••••••.•••••.••••••••••• val. water surface ••••.•••.••••••.•••••••••••• W.S. watt ••••••••••••••••••.••••••••••••••••.•••• W watthour (watt-hour, watt hour) .••.• w•h or Wh Water and Power Resources Service (formerly Bureau of Reclamation) ••••••••• WPRS weight ••••.••••••••....••••••••••••..•••••• wt yard ••••••••••••.••••••••• · ••••••••••••••••• yd year ••••••••••••••••••••••••••••••••.••• (SI)a •••••••••••••••••••••••••••••••• (customary)yr xii '~- i ' ' I ' I . I . I I ,- i " I ' . ' I ; I r -i SECTION 1 INTRODUCTION AND OVERVIEW REPORT OBJECTIVE The report objective is to present a method of analysis for determining the lower limit for a practical size of various types of low-head hydro- electric plants. Data are presented on both technical and economic factors required to achieve this objective. The economic factor, from a practical standpoint~ is predominant. For this reason most of the re- port•s effort is directed towards the preparation of technical data required for economic studies. Guidance is given for preparing these studies for various types of small low-head hydroelectric developments with different site conditions and equipment. This report is limited to power developments of not greater than 15,000 kW and a maximum head of 65.6 ft (20m). All elements and cost normally included in the economic analysis ar_e discussed. Thi$ report is divided into se~tions which consider those subjects of im- portance in the deve 1 opment of small 1 ow-head hydroelectric projects. These sections present data on: 0 State-of-the-art in hydroelectric development o Methods for estimating potential output from a proposed project o Typical site and plant 1 ayouts o Procedure for estimating project cost 0 0 Financial analysis Techniques of economic assessment o Determination of primary energy requirements 0 0 Description of an economic analysis and lower limiti of projects Three examples of economic assessments 1-1 Evaluation of the lower practical limits of small low-head hydroelectric developments is included in Section 9. · This report has been prepared for a reader who has an engineering back- ground and some familiarity with the field of hydroelectric project deve 1 opment and design. The reader, however, need not be an expert in all phases of civil, electrical or mechanical engineering required by hydroelectric project design. Accordingly, the basic engineering design fundamentals are not presented; however, references are given in those areas where additional design data may be beneficial. REPORT METHODOLOGY The sequence topics which are addressed within this report represents the order that coincides with the normal progression of an appraisal (also termed reconnaissance) level study. A full appraisal study assessment requires certain feedback and iterative procedures that are only obvious after the entire process is understood. Therefore, it is suggested that the reader with little prior background in hydroelectric evaluation before beginning as appraisal assessment briefly review the entire re- port. After the full process is understood, an economic analysis can be prepared utilizing the report sections in sequential order. Occasional regression to previous sections may be required for project optimization. Three examples of hydroelectric development economic assessments, each having different site conditions, are presented in Section 10. o Site at an existing water canal drop o Site with an existing dam o Site requiring construction of a dam Each example illustrates the necessary techniques and all should be re- viewed before beginning an economic assessment. 1-2 DATA AND COST BASIS All of the data developed for presentation within this report, particu- larly the cost data, were prepared based upon numerous assumptions. These assumptions are cle.arly outlined throughout the report, particu- larly on the graphs through which the data are presented. Use of any of the data for conditions other than those described by the assumptions wi 11 result in erroneous results. Of particular importance is the as- sumption regarding date of cost estimates. All costs presented within this report are presented at July 1978 price levels. Use of these costs at any subsequent dates must be done using cost escalation factors. Cal- culation of these escalation factors is described within the report. APPRAISAL STUDY OVERVIEW Purpose This report primarily addresses the preparation of appraisal studies. The purpose of any appraisal study is to determine the advisability of proceeding with a feasibility study of the project. If a potential site does not appear to allow an economically feasible hydroelectric develop- ment, this fact must be ascertained and further. work on the project should be halted. At various stages within the project development process, prior to pro- ject design and construction, different levels of economic assessment are required. When screening a large number of potential sites for possible viable projects, only a cursory evaluation is required. A rough deter- mination of project cost and expected output is usually sufficient. After a potential site has been identified, an appraisal study is made. An appraisal study, including a cost estimate, is based on various cost graphs, empirical data, prior plant construction costs and rough designs, generally of a conceptual nature. From this type of data by comparing the main project features such as dam type or sites, powerplant location and capacity, either the most probably economical plan or rating of plans 1-3 is determined. This type of a study serves neither as the basis for allocation of construction funds nor is of sufficient depth and accuracy for management to approve the project. An appraisal study addresses many of the topics addressed within a full feasibility study, but in less de- tai 1. An appraisal study determines whether a much more expensive fea- sibility study should be performed. Another objective of any economic study is project optimization. Evalua- tion of a number of alternative project configurations should yield the optimal configuration~ As with the overall assessment process, the refinement of the optimization process should increase as the project development phase proceeds. Often the ultimate project configuration is not known until completion of the final feasibility study. Frequently minor changes may later be required in the powerhouse layout after purchasing the turbine-generator unit. Typical Procedure 1.) General The various elements of an economic study are introduced below. The elements are described briefly, as an introduction to Sections 2 through 8. 2.) Site Conditions . A survey must be made of the existing site conditions. Items of concern include: o Flow records o Site plans o Local topography o Project operation criteria o Availability of transmission line capacity 1-4 , I ,- 3.) Estimated Power Potential An estimate should be made of the potential energy generation for each of the proposed configurations. Several techniques described in Section 3 may be utilized. 4:) Turbine/Generator Selection For use in the optimization process a number of turbine/generator config- urations should be selected. The determination should include the tur- bine type, number of turbine/generator units and capacity of each. The selection should form a band around the expected optimum configuration. The previously determined estimated power potential is revised, if neces- sary, using the characteristics of the selected turbine/generator. 5.) Power Plant Selection Based on the selected turbine/generator configurations, the various powerhouse configurations should be selected. The existing site condi- tions will affect the selections. 6.) Power Plant Appurtenances and Transmission Line Selection For each of the proposed powerhouse configurations, the required power plant appurtenances should be selected. These appurtenances include: switchyard equipment, penstock and tailrace. The proposed transmission line should also be determined, but this will likely be independent from selected plant configuration. 7.) Additional Feature Selection Any other project features that may be required for any of the proposed configurations should be selected. These features could include dams·, spillways or outlet works. 1-5 8.) Project Cost Estimate The total required capital investment should be estimated for each of the proposed configurations. The capital costs should include: o Construction costs o Contingencies o Engineering o Financial and legal fees o Interest during construction The annual cost for operation, maintenance and replacement .for the pro- posed project should be estimated. The cost should include all direct costs and any indirect costs such as taxes or insurance. 9.) Power Benefit Estimate The marketability of the power to be developed by the project should be determined. This may be based on current markets or an alternate source of power which is typical of the construction of additional capacity elsewhere in the system. The unit costs that would be entailed in procuring the power elsewhere should be determined. The value of the power for each of the proposed configurations should be calculated by multiplying the unit value of dependable capacity by the amount of dependable capacity and the unit value of energy by the amount of energy. If firm energy values are available which represent a com- posite of both capacity and energy values, a single value may be used. 10.) Economic Analysis Based upon the annual costs and annual benefits, an economic analysis should be performed for each of the proposed configurations. Techniques comparing the present worth of all benefits and costs or their annual equivalents over the project life may be utilized. These analyses will determine: 1-6 o If there is an economically feasible development o The optimal configuration 11.) Financial Analysis The annual amortization requirements of the capital investment should be calculated. The calculation will be a function of length of the period of analysis and interest rate. The most likely form of project financing should be used in the calculation. For a public entity the typical fi- nancial options include the issuance of revenue or general obligation bonds and grants or loans from governmental agencies. The payout anal- ysis should be made comparing costs to anticipated revenue. FEASIBILITY STUDY A feasibility study determines whether a project should be designed and constructed. A feasibility study and cost estimate are based on informa- tion and data obtained during investigations for project planning. These investigations should provide sufficient information to permit the preparation of preliminary layouts and designs from which approximate quantities for each type _of material and labor may be obtained. Major equipment pricing is determined on a more factual basis than that used for appraisal studies. The additional study areas that are reviewed in greater depth and accuracy than for an appraisal study include: o Preliminary layouts and designs o Availability of access o Water rights o Environmental issues and resolution of problem areas o Marketing plan for power developed and market value o Detailed schedules for obtaining permits, construction and alloca.tion of construction funds Sufficient data are made available to management so that they can be certain the most economic plan has been selected which will meet their objectives. The feasibility study also serves as a basis for management to approve the construction funding, source and amount. The feasibility study is the final major decision point in the project development process. NATURE OF SMALL HYDROELECTRIC INSTALLATIONS Small hydroelectric development is intrinsically different than major hy- droelectric development. Small hydro, while valuable, has much less im- portance to the overall power grid than does large hydro upon which major portions of the grid may depend. The sudden failure of a large hydro- electric plant may cause disruptions or blackouts throughout a portion or all of the system while the similar failure of a small plant, with minor adjustments would have 1 ittle or no effect on the system. Thus the vast amount of equipment on a large hydroelectric plant to prevent failure and to facilitate plant restarting are not economically feasible for smaller plants. Many small hydro installations, while equipped for remote start, do not have the capability for remote failure reset. A site visit is then required by a plant attendant to place the unit on the line. Another difference between large and small hydroelectric development is ) -the required attendance. Virtually all large hydro plants have either a plant operator in attendance or sophisticated control and monitoring fa- cilities used in conjunction with a nearby attended plant, while few smaller plants are so equipped or manned. Thus, the primary differences between small and large hydro consists of the degree of appropriate auto- mation and the facilities necessary to support manned operation. Also, the large work areas necessary for maintenance of major installations are not required for smaller plants. The size and weight of the small plant turbine/generator allows the use of portable equipment during overhaul. The smallness permits easy transportation of components requiring rework to central overhaul centers so facilities and space do not have to be provided at the site. 1-8 I - I I I I i I ' ' ' I ' GENERAL SECTION 2 ASSESSMENT OF STATE-OF-THE-ART Low-head hydroelectric installations are not a new concept in hydroelec- tric design. They have been in existence since the end of the last cen- tury. However, in the past, low-head low-capacity hydroelectric instal- lations were considered a necessity as the sole source of energy. As the demand for more power and energy grew, fossil-fuel plants were introduced to meet this demand. The fossil-fuel plants had both low initial and low fuel costs. Continual upgrading of the fossil-fuel plant steam cycle and higher capacity units required that the hydroelectric developments to be competitive must use higher capacity and higher head units than used by the earlier small low-head developments. In recent decades, low-head and low-capacity hydroelectric projects, as compared to fossil-fuel plants, were considered uneconomical. Due to the recent increase. in energy costs,· the concept of utilizing low-head and low-capacity hydroelectric developments is being considered as a possibility for an energy source. This Section of the report wi 11 assess the current State-of -the Art re- garding low-head low-capacity hydroelectric developments. SCOPE This Section provides an overview of the type and'--availability of equip- ment for small hydropower developments, the problems and costs associated with their operation and maintenance. An inventory of the various €quipment manufacturers is presented together with a brief description of the type and availability of the equipment. Technical considerations are considered in more detail in Section 4 and costs in Section 5. 2-1 The problems and cost of operating and maintaining the equipment are pre- sented in some detail. This information is intended for use in analyzing the feasibility of small hydro power developments .. METHODOLOGY OF ASSESSMENT The type, cost and availability of equipment items required for small hy- dro power development has been obtained principally from the various man- ufacturers. In some cases information was developed from their litera- ture. Operation and maintenance costs and operational information was obtained principally from a survey of owners of existing small hydro power devel- opments. Additional information was selected from various publications including those of FERC, WPRS* and the U.S. Army Corps of Engineers. ~~here suitable data on hydroelectric plants in the 1 to 3 MW range was not forthcoming the information from plants containing multiple units of these sizes was prorated to give the required information. COLLECTED DATA Operation, Maintenance and Replacement Costs. Operation and maintenance costs data for plants up to 65.6 ft. (20m) of head and 15 MW of capacity was obtained from two main sources: * o Available data from Government publications o Data requested from utility and private companies which operate small hydroelectric power plants Water and Power Resources Service, formerly Bureau of Reclamation. 2-2 '- \ I ' Available data from government publications was found in the Federal En- ergy Regulatory Commission•s report entitled .. Hydroelectric Plant Con- struction Cost and Annual Production Expenses 11 for years 1953 through 1973. Operation cost data given, in mills per kilowatt-hour, includes items such as supervision, engineering, hydraulic and electric expenses, and miscellaneous power generation expenses. Maintenance cost data also given in mills per kilowatt-hour includes supervision, engineering, main- tenance of structures, electric plant and other miscellaneous equipment. A total of 160 public and private utility companies were contacted to ob- tain plant operation and maintenance cost data for years 1973 through 1978. Responses were received from 56 utility companies for a total of 151 plants, of which 134 plants contained data applicable to this re- port. The operation and maintenance cost data were also given in mills per kilowatt-hour. Appendix (Page A) shows examples of the data received from 6 utilities for 16 hydroelectric plants. Original construction costs for these projects have not been included. These projects extend over a time period of more than seventy-five years. ·Escalation of costs for this long a period is difficult to make in order to have a comparable present day cost which would assist in es- tablishing the reports objective. During this period of time there have been developments and refinements in equipment design and attendant aux- iliaries for small low-head hydroelectric plants which are reflected in the data presented in Sections 4 and 5. The operation and maintenance cost data collected were analyzed using a computer. The computer program basically stored.the data, escalated operation and maintenance costs to July 1978 levels and obtained long term average costs for each one of the 134 pl~nts. Costs were escalated based on Engineering News Record•s cost indices. The computer results were then plotted against head and/or capacity. 2-3 An examination of the results indicated that operation and maintenance had minor variations in relation to head within the low-head range of the report. Accordingly, the long term operation. and maintenance cost of each plant was plotted against capacity. This method showed a more def- inite variation and pattern of costs. Figure 2-1 shows a plot of an average curve which best fits the shape of the plotted points. The user should exercise his own judgment in deciding whether the selected value for operation and maintenance costs of any project should be above or be- low the average curve, based on: 0 Nature of the project 0 Characteristics and quality of the water 0 Plant location; and 0 Plant capacity factor Analysis of the questionnaire data showed that replacement costs are on the average approximately 23 to 24 percent of the operation and main- tenance costs. Typical Maintenance Problems Normal maintenance consists of a weekly inspection of the power plant to visually inspect the following items: o Generator bearing oil levels o Hydraulic pressure set oil levels o Turbine shaft seal o Speed increaser oil level o -Cooling water pressure o Flow and head recording tapes 2-4 i I I ! ) \ I ) I • I Annual maintenance requires one to two weeks of plant shutdown and is normally scheduled during periods of low or no flow. This work consists of the following: o Changing or filtering of governor, valve, turbine bearing, speed increaser and generator bearing oil· o Turbine shaft run out test o Replacing turbine shaft seal packing o Inspection and weld repair of the runner o Inspection and/or replac_ement of wicke:t gate packing and bushing o Inspection and repair of. wicket gate seal surfaces o Inspection and replacement of water seals on submerged bearings o Inspection of turbine shutoff valve seats and shaft packing o Dialetric test of the transformer and breaker oil o Washdown of porcelain insulators o Cleaning of control compartments o Trip setting tests on relays The extent of annual maintenance repair is influenced by the water qual- ity. Power plants using water containing sand or silt require more main- tenance on bearings and flow passageway surfaces. The corrosiveness of the water also influences the. maintenance. However, when these condi- tions are known prior to design, proper selection of materials and flushing devices can be incorporated into the design to minimize the an- nual maintenance. The amount of pitting of the runner and discharge ring caused by cavita- tion is influenced by the operating conditions and the turbine setting. If the unit is required to operate at low tailwater conditions or for ex- tended times at overload conditions more repair of the surfaces may be required. 2-5 Major overhaul of the generator windings is dictated by the power grid and the amount of time the unit is operated above overload. Dependent upon the overload operating conditions a_nd temperature conditions the generator windings may be in service upwards of 50 years before it is required to rewind the generator. Performance Data Data on the performance of small hydro plants was obtained from two sources; a survey of small hydro plant operators, and the WPRS Hydroelec- tric Unit Service Record for the years 1973 and 1974. Definitions used are as follows: Annual Operation Factor Annual Availability Factor Annual Maintenance Factor = Hours of Actual Operation 8760 = Hours Available for Operation 8760 = Hours Unit Off the line due to Maintenance Time 2-6 Detailed comments on the results are as follows: 1.) Summary of Small Hydro Plant Operation Two questions were asked about plant operation: (a) On line operation percent of ·year (b) Plant breakdown and outag~ data o Days in 1974 o Days in 1975 0 Days in 1976 o Days in 1977 o Days in 1978 Answers to the above questions were analyzed giving· the following re- sults: Question (a): Number of answers 96 Mean value, percent 83 Standard deviation, percent 22 Question (b): Number of. answers 62 Mean value, hours 414 Standard deviation, hours 599 2-7 2.) WPRS Hydroelectric Unit Service Recor~ From the WPRS Service Records for 1973 and 1974 thirty-nine plants under 15 MW were selected and statistically analyzed as follows: 1973 1974 Mean Annual Availability Factor,percent 93.37 89.38 Standard Deviation of Availability Factor, percent 7.74 19.65 Mean Annual Maintenance Factor, percent 1. 50 1.63 Standard Deviation of Maintenance Factor, percent 1. 85 2.08 These results show that the availability factor for small hydro plants is well over 80 percent. Data From Turbine Generator and Valve Manufacturers A large number of turbine, generator, governor and valve manufacturers produce equipment for low-head hydroelectric installations. Details of the equipment offered by a selection of the major manufacturers is shown in the Appendix (Page B). Hydraulic turbines are generally custom designed for specific installa- tions although a number of manufacturers are now offering units on a standard design basis. Custom built units usually require 24 to 30 months for delivery. Standard designs may require 9 to 15 months deliv- ery in the USA depending on the type of turbine. The time required to manufacturer custom built turbines may be shortened considerably if the manufacturer has already model tested a runner of similar specific speed and can bypass this phase of the design. 2-8 Generators for low head small hydroelectric installations are almost ex- clusively of standard designs. Where speed increaser gearing is used generators designed for 900 and 1800 rpm may, in some cases, be obtained as •off the shelf• items. Some form of energy dissipating valve may be required to bypass water around the power plant during periods when the turbines are shut down. Several types of valve are available for these duties. Slide gates, and fixed cone valves are available •off the shelf• from a number of manufac- turers, and these will give adequate flow regulation at reasonably low heads. Slide, roller and Tainter gates are usually custom designed for most hy- droelectric installations. However, as shown in the Appendix (Page B), that for the smaller sizes there are a number of manufacturers. who can supply these gates •off the shelf•. BRIEF SUMMARY OF STATE-OF-THE-ART History Modern low head hydro power development may be considered a direct de- scendent of the ancient water wheel. Evidence of these machines in use several thousand years ago, have been found in China and the Middle East. European development of the water wheel dating from 200 AD re- sulted in extensive use of the overshot brest and undershot wheels. These machines were substantially gravity types but some impulse effect was usually present. Modern practice dictates the installation of impulse turbines for heads above 2000 ft. (600 m). Banki and Mitchell (1917) independently developed the •double shot• crossflow turbine. This impulse type turbine is suitable for small hydro power projects. 2-9 The reaction turbine is a relatively modern development. A Barker Mill is probably the earliest example of this type and may be seen today as the lawn sprinkler with the rotating head. The earliest commercial reac- tion turbine is due to Fourneyron who installed an outward flowing cen- trifugal turbine at St. Blaison in 1835. Francis (1849) changed the con- figuration so that the flow through the turbine was radially inward. This resulted in a ,substantial reduction of flow at runaway speed and also allowed the use of a draft tube which had been independently de- veloped by Henschel and Jonural. The Francis configuration is essen- tially unchanged to the present time. Francis turbines provide economic installations in the head range of 65 to 2000 ft. (20 to 600 m). Improvements in the design of propeller turbines has been a relatively. recent development. Kaplan obtained a patent in 1913 for an adjustable blade propeller turbine with vertical shaft, spiral case and draft tube. This configuration has been used for all major developments co- vering the head range of 32 to 165 ft. (10 to 50 m). Parallel de- velopment of the tubular, bulb and rim turbines has made these turbines especially suitable for relatively small low head installations. Harza obtained a patent in 1919 for the rim turbine but mechanical problems have unt i 1 recently retarded the deve 1 opment of this turbine/ generator combination. Bulb and tubular turbines have also reached a stage of considerable sophistication and are particularly suitable for low-head installations. Hydro electric energy projects could not attain their modern form until the problems of high voltage transmission of electricity were solved in the latter part of the 19th century. Parallel progress in generator design all owed the utilization of the hydro power potential available in many remote locations. Likely Future Developments The major problem with high· capacity low-head hydro projects is large quantities of water that must be conveyed through the turbine. These turbines become physically very large as do the costs associated with the mechanical and civil structures. Future developments are therefore 2-10 likely to concentrate on configurations that minimize these costs. Bulbs, tubular and rim turbines are examples of this trend. Further development of the propeller turbine will also undoubtedly oc- cur. Research aimed at increasing the specific speed for a given turbine submergence would, if successful, result in considerable cost savings. A less costly blade mechanism would also result in more universal adapta- tion ·Of this device. Development of impulse and Francis turbines to dis- place the propeller turbine at low heads seems unlikely at this stage. In recent years the oil industry has completed off shore projects that require the prefabrication of major structures in dry dock. The struc- ture is subsequently floated into its final location and secured to the ocean floor by piling. The extension of this technique to hydroelectric power plant construction is rare but several proposals have been made for the construction of tidal power plants using this method. More recently a contract has been awarded for complete bulb turbine units to be con- structed in dry dock and floated to their final river location. There appears to be no major constraints, other than that of transporta- tion, on the extension of these techniques to the construction of small hydro plants. Modules can be fabricated incorporating turbine, generator and governor complete with wiring and piping. The economic advantage would result from the reduction of the amount of field assembly work, and a reduction· in civil construction costs. Where weir type structures are involved the modules could possibly be floated into position and pinned to the foundation with piles. Where floatation techniques were not pos- sible the modules would be lifted into position and pinned to the founda- tion with rock bolts, or prestressing tendons. The module structures could be readily fabricated in sandwich construc- tion with subsequent filling of the cavities with concrete. Where steel was not protected by the concrete special provision would be required to avoid excessive corrosion of the steel. 2-11 NOTE: Cost base is July 1978 I Figure 2-1 Operation, Maintenance and Replacement Costs 2-12 ,- 1 i I ' I I I J ( I I I I I i ' li i I . GENERAL SECTION 3 ESTIMATION OF POWER AND ENERGY The first building block in the economic studies of low-head hydroelec- tric development is the estimation of power (capacity) and energy to be realized from an installation. A complete and detailed presentation of se 1 ected methods of estimating capacity and energy is made by giving a step by step explanation of the procedures for each method, denoting areas of application, stating apparent and inherent assumptions, speci- fying data requirements, and stating the specific virtues and 1 imitation of each method. An illustrative example is given for each method. The hydropower capacity and potential energy output of a prospective de- velopment site, whether it is new or an addition to existing facilities, depends primarily on the magnitude and distribution of the flow and head available at the site. SITE CONDITIONS General The viability of a prospective site for the production of power and ener- gy _is affected by a myriad of factors, and the relative importance of the individual factors may vary from site to site. These factors have to be given due consideration in all or some of the stages of the project for- mulation, investigation and development; from determining whether there could be a project at all to selecting the best alternative for implemen- tation. 3-1 A list of such factors would include but not necessarily be limited to: o Stream flow conditions: magnitude and temporal distribution of flow o Available head and its variability o Potential for improving the magnitude and/or the distribution of the flow and/or the head o Site hydroclimatic and hydrogeologic characteristics o Site accessibility General Data Requirements Two types of basic data are required to estimate the capacity and energy output of a hydropower site. The first is topographic data fr·om which the available head is determined and the second is hydrologic data from which the available discharge is determined. The hydrologic data is more often the most difficult to obtain yet the most important one since both the capacity and energy developed are dependent upon the characteristics of the flow hydrograph of the site under consideration. The specific type, quantity and quality of the data to be used should be determined based on the typ·e, size and intended purpose of the project. Possible sources of the above data and ways of processing them for use in esti- mating power and energy output are presented in this section. Topographic Data Topographic data are necessary to work out the best plant layout that will possess the highest attainable head with best· flow conditions. The selection of the type of plant is substantially influenced by the topog- raphy of the area. The major topographic element needed in determining the potential plant capacity is the gross head on the turbine. Depending on the preliminary layout and comtemplated type of plant, the topographic data necessary to determine the gross head may range from im- promptu field notes to as-built drawings of existing hydraulic structures and associated topographic maps. The U.S. Geologic Survey (USGS) topo- 3-2 graphic quad sheets may be useful in this regard although may prove in- adequate for some cases because of their large scales. Other sources in- clude state highway department maps, especially if a major highway is lo- cated in the area of interest. In all cases topographic maps of adequate scale and/or design drawings showing sections of existing structures with upstream and downstream water surface conditions for design flows must be obtai ned. The variation of power and energy output is dependent on the variation of head and flow. Variations in head is primarily due to elevation varia- tions in headwater and tailwater surfaces. Therefore, an adequate number of river cross sections starting from a sufficient distant downstream of the plant must be obtained in order to develop a reliable tailwater rating curve employing backwater curve computation methods. Topographic maps are adequate for preparing a reservoir capacity curve to assess headwater variation where creation of pondage is desired. Where pondage is not required, the headwa~er surface elevation may be determined by straight forward hydraulic ca 1 cul at ion of head 1 ass and backwater forma- tion. Hydrologic Data Hydrologic data are vital for the proper planning and design of hydro- electric projects. They are needed for both the conservation use and safety aspects of the project. In the first case average flow records are used for the determination of minimum available output capacity as well as determining the requirements for additional reservoir capacity development. In the second case peak flow records are used for the plan- ning and design of facilities necessary for the safe bypass of flood flows in order to maintain the project integrity. Depending on the level of the study being carried out and the type of de- sired power plant, the form of the flow record necessary may vary from annual average flows to hourly flows. For an appraisal type of study most of the time average monthly flows would be adequate enough to use in 3-3 estimating potential capacity of a site since the purpose of an appraisal study is to quickly determine if there may or may not be a possibility for a project to be considered for development. For feasibility level studies usually monthly average flows are used. Monthly average flows may not be adequate in some cases and weekly or daily flows may be re- quired. Judgement based on experience is necessary to determine which flows should be used. For example, when studying the potential output capacity at a mountain stream which has a highly variable flow, use of monthly average flow records invariably leads to overestimation of poten- tial dependable capacity thus flow records of less duration must be used. Hourly flow records may be needed to assess the potential of a plant to serve as a peaking plant. Sources of Hydrologic Data Flow records may be obtained from several different sources. The main Federal agency charged with the collection and maintenance of river flow data is the USGS. The USGS publishes daily flow records annually for each state as Water Resources Data for the given state. It also pub- lishes a summary of monthly flows by regions every five years. All these records; daily, monthly, annual average flows, are also available for any USGS river gaging station on the USGS 1 s computerized National Water Data Storage and Retrieval system 11 WATSTORE 11 , and are obtainable for a nominal fee. In addition, the USGS can provide statistics on the desired types of flows such as means, standard deviations, peak flow frequency, 1 ow flow magnitude -duration -frequency relationships, flow-duration curves, etc. The data contained in the WATSTORE daily discharge files has been dupli- cated by the Corps Hydrologic Engineering Center (HEC), and is available on the Lawrence Berke 1 ey Laboratory (LBL) CDC 6600 computer systems. This duplication was accomplished as an element of the National Hydro- power Study, and serves as the data base for evaluating all potential hy- dropower sites in the United States for this project on a very prel imi- nary level. This program is called GETUSGS, and has a variety of unique 3-4 .. -~ I ' --J features that were developed especially to-meet the requirements of the National Hydropower Study. One. useful feature that has been built into the GETUSGS system is its capability to access streamflow data files by inputing the longitude and latitude of the study site. From this single input, GETUSGS will search the data files, determine the nearest gaging station (or stations), correct for differences in drainage area, and then compute flow-duration curves· or daily flow data tables~ Other output op- tions are also available. from GETUSGS.-At the present time, approxi- mately. 16,000 stream gaging stations with some 320,000 station years of record are contained i.n the GETUSGS data files. For the most part, gaging station daily flow records in GETUSGS are complete for the entire period of record, including the 1977 water year. Present plans call for the periodic updating of these files, as demand warrants, so GETUSGS.re- cords will not always be as camp l ete as WATSTORE. Futher information on accessing or using the GETUSGS program can be obtained from the Hydro- logic Engineering, Center. Users of either· system of data retrieval are cautioned to review ·individual station .records carefully, because data management progr.am of this magnitude can contain some errors in the re- cording of data L2J. In isolated cases flow records may be kept by the WPRS, Army Corps of En- gineers, Soi·l Conservation and Forest Service. These are also the best sources for records cif, releases and operating criteria for most of .the existing major projects. In addition, state and regional agencies such as -state water· resource departments and boards, river basin authorities, utili·ty companies, irrigation districts, municipalities, water companies and other water using· organization.s are possible sources for hydrologic data. Even though flow records are avail able at several strategically located sites of the U.S. river network systems they rarely, if at all, are neither at a site of a future power plant, nor are they of sufficient duration. They may also contain some data not needed for the study. 3-5 Such being the case, almost always the data has to be processed in order to bring it to at least the minimum desirable form. Hydrologic Data Processing In order for a historic set of hydrologic data to be used for analysis of future conditions on the basis of the simplifying assumption that the fu- ture conditions may be approximately represented by the past conditions, the set of data must meet certain minimum criteria with regards to both quality and quantity. As a minimum, the data must be homogeneous and for a long enough period to warrant making reliable deductions from a statis- tical analysis of the data. Quality of Data The primary requirement for all hydrologic data is to be homogeneous, i.e., to be samples from the same population. A time series is homoge- neous if the identical events under consideration in the series are equally likely to occur at all times and places. There are two types of non-homogeneity that are of concern in hydrologic data analysis: 1) mixed (data) population; 2) trend and cyclicity. 1) Mixed (Data) Population Data from mixed population is the most common type of non-homogeneity found in hydrologic data. This type of inconsistency usually results from human activities such as the construction of flow regulating reser- voirs or diversion dams upstream of the study site. Denuding of water- sheds by forest fires or harvesting of lumber also lead to non-homoge- neous data. Existence of such changes may readily be detected from a plot of the hydrologic parameter, say discharge, and time. Another method for detecting such inconsistencies in hydrologic data is the double mass curve. It is a graph of the cumulative data of one vari- able versus the cumulative data of another related variable. The plot will be a straight line as long as the relationship between the variables is a fixed ratio. Breaks in the double mass curve of such variables in- 3-6 I ) dicate changes in their relationship~ This method may also be ·used to correct the incons'istency as well· as to extrapolate the data. 2) Trend and Cyclicity Existence of persistent trend and cyclicity may also be detected from simple plots of the data -in time if sufficiently long records are avail- able. Regressing moving averages in -time is an excellent method for trend analysis. Here again the reader should refer to publications on statis- tical hydrology and time series analysis if there is reason to believe that the aforementioned simpler methods are inadequate. Length of Records The length of flow record necessary to warrant reliability of power (ca- pacity) and energy estimates at a prospective site depends on, among other things the g~ographic · location, hydrologic characteristics and variability of the flow regimen of the watershed of the site under study. On the other hand sufficiency of data is a function of method employed for analysis which in-turn is dependent upon the stage of study as well as the type and scale of envisaged development. Even though use of record lengths of up to 100 years and multiples there- of are being suggested by more and more .people involved in the field, in present day general practice 30 to 50 years of record would be considered adequate. When it is possible to .determine that the longer period flow records may be accurately represented by a shorter time interval,. such as 10-15 years, then the number of computations will be decreased. Findings of some comparative studies [2J conf_irm. the adequacy of these practic.al ranges. It is particularly important that the length of record should span peri- ods of extreme events in order for the planning effort to yield solutions that would be most effective in providing for future critical periods. Therefore, all possible means available should be used, including written 3-7 and oral accounts, to learn about the past flood and drought hi story of the region and insure that the data properly reflects these events. THE POWER FORMULA A body of water stored at an elevation H above a given datum has a poten- ' tial energy with reference to the datum equal to the product of its weight and the distance H. This energy may take differ.ent forms such as kinetic energy and be ~sed to turn a turbine. The theoretical power of flowing water measured in kilowatts is given by the power formula: Pt = 0.0846 QH (9.804 QH in Metric units) (3-1) where Pt = theoretical power of flowing water in kilowatts Q = available flow in n3;s (m3/s) H = gross head that the flow drops through ft (m) In the production of hydroelectric power some losses of head and dis- charge are incurred in the electromechanical generating units. The losses associated with the turbine and generating units are accounted for by the product of their respective efficiencies which for appraisal estimating purposes can be assumed to be 85 percent. This efficiency is based on: o Design head on the turbine, and o Average turbine efficiency over the normal load operating range 3-8 . 1 The power of. a hydroelectric installation at the ge~erator busbar in kilowatts is: Where FLOW-DURATION CURVE Pw = 0.0846 QHnn (9.804 QHnn in r~etric units) p = w power produced, kW n = plant efficiency Hn = net head on the turbine~ ft (m) Q = Quantity of water flowing through the turbine, ft 3/s (m 3/s) (3-2) Fortunately there are sufficient number of methods for estimating avail- able flow at a prospective project site for hydropower production. The methods vary in level of sophistication and hence reliability of re- sult. One method may be more suited than others to a given situation, therefore, judgment should be exercised in selecting the method . A flow-duration curve is a cumulative frequency curve that shows the per- cent of time that specified discharge values are equaled or exceeded dur- ing a given period. There are several different ways of preparing flow- duration curves in practical use and the selection of any one particular variant should be based on intended use. In general, to prepare a flow- duration curve, daily, monthly, or annual flows during a given period are arranged in descending order and the relative percentage of time during which each flow in the series has been equaled or exceeded is computed. Then the curve is P.lotted showing the flows as ordinates and the percent of time as abscissa. The area under the flow-duration curve represents the quantity of water available at the particular site being considered. When the head is known, then the power and energy potential for the site m(!y be deter- mined. Assume the average flow determined from a flow-duration curve, 3-9 Figure 3-1, is 3530 n3 (100 m3/s). In addition, assume the average head on the turbine is 59ft (18m). If the average plant efficiency over the operating range is 85 percent, the unit size and possible energy genera- tion is: Available Power, Pw = 0.0846XQ X Hn x n (3-2) = 0. 0846 X 3.500 X 59 X 0.85 = 14,980 kW Energy generation = 14,980 X 8760 = 131 X 10 6 kWh To produce this amount of energy represented by the flow-duration curve assumes that the turbine is capable of operating under all flow condi- tions represented by the flow-duration curve and still maintain a con- stant efficiency over. the flow range. Another assumption made is that at high flows the tailrace elevation does not change. It is not unusual that during high flows the tailrace water elevation will rise which de- creases the net head on the turbine. This decrease in head may necessi- tate removing the unit from the line if the lower head is beyond the operating range of the turbine. At the time of preparing the final feas- ibility analysis it is imperative that an assessment be made as to the changes in the tailwater backwater curve to determine if there is a de- crease in head on the turbine during per.iods of high flows in the tail- race channel. The flow-duration curve is an excellent tool for use in appraisal studies but is not usually used for feasibility studies. For appraisal use, average monthly flows are normally used. Use of weekly flows is a re- finement that is not required during the early stages of project formu- lation. The selection of the design turbine flow for use in determining the plant rating and energy output from the flow-duration curve is an economic selection by a trial process. Usually the design flow is based on the use of rough parameters and experience of the user. 3-10 --' I OPERATION SCHEMES There are several ways to classify the functional use of hydroelectric plants. For the small hydroelectric ~lant this classification will be as follows: (1) Non-Storage and (2) Reservoir Operation. 1) Non-Storage Non-storage operation is typical of a small dam with no active storage. The· generation pattern es·sentially follows the pattern of stream flow which may or may not enhance the dependable capacity of the electrical system during times of critical demand. It is essentially a 1 run of the river 1 project. Generation is ·also limited by high tailwater during floods and by low flows during drought periods. Operation of the tur- bines at low gate openings during drought periods could result in unac- ceptable vibration and rough running of the turbine. Non-Storage opera- tion is also typical of operation on a water canal where the primary use of the water is for· irrigation· purposes. For operation using a water canal, there is very little change in the head on the turbine regardless of the amount of water passing through the turbine. 2) Reservoir Operation This type of operation is based on a reservoir being used primarily for other uses than energy generation. The generation of energy is a secon- dary requirement and energy may not be generated if th'e water supply is in a critical state.· The flow to the turbine is highly variable and the head on the turbine is also a variable. Generally this type of operation will be infrequent with small low head hydroelectric projects especially when large reservoirs are used. This often results in projects having heads on the turbine in excess of 65.6 ft (20m). which exceeds the ·report limits. 3-11 DEPENDABLE CAPACITY The traditional definition of dependable capacity of the plant as used by the Federal Energy Regulatory Commission is the capacity which under the most adverse flow conditions of record can be relied upon to carry its share of the system load and provide dependable reserve capacity and meet firm power obligations. If the plant is in an isolated system its de- pendable capacity will be limited by the minimum flow occurring at any time and in unregulated streams will frequently be zero. As part of a larger system, the dependable capacity is affected by the characteristics of the other plants in the system and how the low flow period relates to the occurrence of peak loads on the system. Assessments of the dependable capacity benefit requires consideration of both the output of the small hydro and the output of the electrical sys- tem into which the power is delivered. It should be noted that a depend- able capacity benefit may also be present where active storage is not available for use in electrical generation. The conceptual basis for claiming a dependable capacity benefit is that the capacity of the hydro plant must be available to the electrical system when the generating ca- pability of other generation in the system is lowest. The common dependable capacity concept can be overly restrictive if applied to the small low-head hydro plants. It is believed that some of the hydro plant capacity should be available 100 percent of the time to be considered as dependable generation. This would only be an appropriate requirement if the system•s sole energy was hydrogeneration and the unit being added was relatively large compared to the system•s capacity. It appears reasonable to use other criteria to serve as a basis for de- termining dependable capacity credit of a small hydro plant. It is unlikely that one 15 MW hydro plant is going to forestall construction of a thermal generating plant. If a total of 200 to 300 MW capacity of 3-12 r ' I ' .-----, L. small hydro plants were to be built over a 2-3 year period, then this amount of .additional capacity could conceivably postpone construction of a thermal plant. There is presently no industry-wide agreement as to the method or amount of a small hydro plant•s capacity that should be credited for firm (or dependable) capacity. The· capacity credit allowed for the small hydro plant must be agreed to between the 1 developer and purchaser. An arbi- trary value of 90 percent availability of the small hydro plant capacity is recommended for use in an appraisal study unless there is an agreement of another value ·between the developer and the probable purchaser. The application of the 90 percent value is discussed in the following. The following are several possible comparisons between the small hydro plant generation and the connecting system load pattern. 1. Reservoir Operation. In this type of operation, it is assumed there is generation every month. The average monthly generation on an annual basis can be determined .. Figure 3-2 shows the sys- tem•s average monthly load curve and the average monthly output of the small hydro plant. In small hydro plant appraisal studies, it is recommended ·that ·the dependable capacity credit be based on the generation that is available at least 90 percent of the time on an annual basis. 2. Non-Storage Operation. In this type of operation, due to water availability being less than minimum flow requirements of the turbine, the small hydro plant can have periods of non-genera- tion. However, if there is energy production during the sys- tem•s peak, then some capacity credit should be allowed the small hydro plant. Figure 3-3 shows the condition between the monthly system requirements and ·the small hydro plant energy production. For these types of situations in small hydro plant appraisal studies, it is recommended that the dependable capa- 3-13 city credit be either 90 percent as shown on Figure 3-3 or zero when the small hydro plant does not operate during peak system load conditions as shown on Figure 3-4 INTERMITTENT CAPACITY The small hydro plant should also receive additional energy credit for intermittent capacity. To receive this credit the capacity must be available for substantial periods of time in relation to the system sea- sonal peak loads. The WPRS recognizes that energy available 50 to 75 percent of the time, either on· an annual or a seasonal peak load basis can be assigned an energy va 1 ue equal to one-fourth the difference be- tween nonfirm and firm values. Energy available 75 to 90 percent of the time can be assigned an energy value of 50 percent of the difference be- tween nonfirm and firm values. Modeling studies are currently being made by FERC and others which may result in a more refined method of eval- uating intermittent capacity than discussed in the above. POWER AND ENERGY ESTIMATES -FLOW-DURATION CURVES Genera 1 The general application has been demonstrated for use of the power equa- tion (3-2) in conjunction with the flow-duration curve to determine the available power and energy at a site represented by a flow-duration curve. The following will present in more detail the use of the flow- duration curve to determine the unit size with the corresponding energy produced. Procedure Figure 3-5 is a flow-duration curve which may be considered as typical for either a 1 non storage 1 or 1 run of the river 1 type of plant opera- tion. As previously discussed, the area under the curve represents the available power and energy when the head condition is known. For Figure 3-5 the average flow, A-B, is about 1800 n 3;s (51m 3/s). Assume the 3-14 average head on the turbine is 65.6 ft. (20m) and a plant efficiency of 85 percent. Then the unit size represented by this flow-duration curve and the energy produced becomes: Pw = 0.0846 X Q X Hn X n (3-2) = 0.0846 X 1800 X 65.6 X 0.85 = 8,490 kW Annual energy generated = 8490 x 8760 = 74.4 X 10 6 kWh For turbines used in this report the minimum turbine flow and maximum turbine flow may be taken as 30 and 115 percent respectively of the tur- bine rated flow. This establishes both the lower and higher limits of the flow-duration curve which repres~nts the power and energy that may be developed for the appraisal study, assuming a single unit installation. A new average flow is determined for the area bounded by the high and low flow limits and the flow-duration curve. For the rated flow of 1800 ft3/s (51 m3/s) the low flow, Figure 3-5 (E-C), is 540 ft3/s (15.3 m3/s) at flows lower than this value the unit must be taken off the line. The high flow, Figure 3-5 (F-G) is 2070 ft 3/s (58.E m3/s) and flows in excess of this amount must be bypassed and accordingly not avail able for energy production. The total energy generated is represented by the area FGCDJF (Figure 3-5) which on an annual basis is an average flow of 950 n 3;s (26.9 m3/s). This is representative of a 4481 kW unit with an annual generation of 39.2 x 106 kWh. The capacity factor = 39.2 x 1o6x 100 74.4 X 10 6 = 52.7 percent Dependent upon the shape of the flow-duration curve it is often found that the capacity factor can be increased if the rated flow is selected between the 15 and 25 percent time exceeded on the flow-duration plot in- stead of using the average as in the example. The practical selection of 3-15 the rated flow is based on both experience and trial solutions to maxi- mize the energy output for given flow conditions. In the foregoing e~ample of a rated flow of 1800 ft3/s (51 m3/s) it is obvious that more than a single unit could be used in order to take ad- vantage of the high flows. Two units could be operated on flows up to 4140 ft3/s (117.2 m3/s) Figure 3-5 (K-L) which would represent an annual average flow of about 1200 ft 3/s (34 m3/s). The capacity and annuaJ energy represented by this flow becomes: PW = 0.0846 X 1200 X 65.6 X 0.85 = 5660 kW Annual energy generated = 5660 x 8760 = 49.6 X 10 6 kWh 6 Capacity factor = ~:~ ~ !~6 x 100 = 66.7 percent This is an improvement in the plant capacity factor and the decision to have a one or two unit plant will be based on an economic analysis of both plant arrangements. Variation of Flow-Duration Curves Most flow-duration curves will be of the general shape shown in Figures 3-1 and 3-5. There may b_e minor variations which could be a steepness of the curve in the low percent time exceeded region and some increase in flow in the high percent time exceeded region. There is, however, one type of operation which generally makes significant changes in the gen- eral shape of the curves. This is for flow conditions of a plant using irrigation flow, generally from a canal, on a seasonal basis. This type of flow-duration curve is represented by Figure 3-6. 3-16 i ! u I' ' I I'--' [] ,--~ I . I I L-1 [j r--, \ ' I ' L_.J [J r 1 , I l_j ·'I i I L __ _! f -' I. I -~ ~~ L_J ll I I I I L_J c J The use of the flow-duration curve for this type of water supply, (Fig. 3-6) is used in a similar manner as for Figure 3-5. There is a differ- ence, however, in that the turbine rated flow will be higher than the average flow and may be se 1 ected at a percent time exceeded va 1 ue nearer the maximum flow. It is not uncommon to use a point as low as 10 percent of the time exceeded instead of the 15-25 percent time exceeded value used for the 'run of the river' flow-duration curve. In this shape of curve the low flow cut-off point permits only a small percentage Of the water not being available for energy production. In the example shown the average flow is about 303 ft3/s (8.6 m3/s) which permits turbine operation down to 91 ft3/s (2.6 m3/s) or 58.5 percent exceeded time. On the basis of the head being 65.6 ft (20m) and a plant efficiency of 85 percent the capacity and annual energy generation represented by the flow-duration curve is 1429 kW and 12.5 x 10 6 kWh. Selection of 303 ft3/s (8.6 m3/s) as the rated turbine flow and using flows between 30 and 115 percent of turbine rating will result in an annual production of 7.6B x 106 kWh or a capacity factor of 61.3 percent. However, if a unit were se 1 ected with a rated flow, as recommended about the 10 percent time exceeded value of 695 \ft3/s (19.7 m3/s) the selection would be too large a turbine as the turbine could be operated up to flows of 115 percent of 695 ft3/s or 799 n3/s (22.6 m3/s) which exceeds the maximum flow, 725 ft3/s (20.5 m3/s), of the flow-duration curve. For this particular flow- duration curve~ a better criteria would be to select a turbine that has a 115 percent of turbine rated flow equivalent to the maximum expected flow of 725 ft3/s. Accordingly a turbine is selected with a rated flow of 630 n3;s (17.8 m3/s). This selection would result in an annual generation of 12.15 x 106 kWh which represents a 97 percent capacity factor. POWER AND ENERGY ESTIMATES -OPERATION STUDY Procedure The use of the flow-duration curve for determining power and energy de- veloped is satisfactory for an appraisal study but rarely affords the ac- 3-17 curacy or refinements required for a feasibility study. Feasibility studies require that an operation study be performed to determine the unit size or sizes and the energy produced. An operation study, which may also be known as a routing study,. entails the calculation of potential energy generation during dis·crete periods of the site record. Repetition of the calculation for all of the periods of record is performed. The period used is usually either a week or a month, depending on record availability. If the site is on a natural stream where records are main- tained by the USGS or another similar organization, the flow ·records are typically available in a monthly format. For irrigation systems, records may be kept on either a weekly or a monthly basis. The use of daily re- cords in an operation study gives 1 ittle improvement in accuracy at a large increase in computational effort. Nonetheless, daily studies may be occasionally performed for special purposes, such as to evaluate the potential power plant performance during a spring flood season. A distinction in operation study techniques may be made between opera- tional and non-operational systems. In a non-operational system, all site discharges are dictated by criteria other than energy requirements, such as irrigation or domestic water requirements. The function of a power plant in this type of system is to generate only the energy possi- ble with the dictated releases. A typical non-operational site is a drop in a canal system where the passage of water is dictated solely by irri- gation requirements. In an operational system, some discretion regarding releases remains and may be used to enhance energy generation. An opera- tional site configuration often encountered is a reservoir with a known hydrologic inflow record and a fixed pattern of demand. Discretion may be used in the storage of excess inflows in order to meet subsequent demands .and to retain releases until the potential generation is of more value, such as during the summer months. For an operational system, the system operation is included integrally with the energy calculation. 3-18 . ' .. , , I I J -., ! I _i ' J -l ' j ---' I ,---.., i I ' ' .. ' I ' r - r - ' ) f ., ' l_ An operation study may be used to determine power plant parameters, such as optimal turbine/generator size and project dependable capacity. A series of operation studies may be performed using different turbine ca- pacities and configuration. The average annual energy and' capacity value for each of the alternatives would be determined. If the value of energy is known, pre 1 imi nary cost estimates may be prepared and the optima 1 plant' capacity evaluated on the basis of incremental benefit-cost analy- ses. Dependable capacity may be evaluated for operational systems by performing repeated studies with varying capacity criteria until the sys- tem passes,· with a minimal level of reserve, through the critical drought period. Dependable capacity for a non-operational system is rarely a meaningful concept. Several different calculation techniques may be used to evaluate the en- ergy generation for given flow and head conditions. Among the simplest, yet most theoretically appropriate, is the use of the turbine operation curves presented in Section 4 (Figure 4-4, etc.) of this report. In fact, the curves were originally developed for ease of usage on digital computers. Based on the average flow and the average effective head over the period of operation, the operating power level may be determined. From the number of hours in the period; the energy generation may be cal- culated. If the system is required to operate on a schedule other than uniform release, such as generation for only sixty hours per week, straight-forward mathematical transformations may be performed on the flow and head data and the turbine operating curve still used to deter- mine power and energy. In many cases, a period of record that may be sufficient for a flow-dura- tion analysis is insufficient for an operation study analysis. This is particularly true when a dependable capacity ·calculation is required and the period of record does not include the design drought. Several record extension techniques exist. However, the most used and accepted tech- nique is the use of 11 HEC-4, Monthly Streamflow Simulation .. , a computer 3-19 program prepared and supported by the Hydrologic Engineering Center, U.S. Corps of Engineers. HEC-4 uses the long-term records in surrounding drain age basins to extend, by corre 1 at ion, the record at the potentia 1 power plant site. Hand Computations The principles that underlie operation studies are relatively simple. Studies may be performed either by hand calculation or by computer with equivalent accuracy. The advantage of a computer is speed of calcul a- t ion, a feature which allows the performance of numerous operation studies much quicker than could be accomplished by hand. However, the initial preparation of a computer progratn can entail extensive effort. In many cases, an answer of sufficient accuracy can be obtained quicker by hand calculation. The same data would be required for either a hand calculation or a com- puter study. A record of flow and head must be available, along with any other data necessary to describe the flow characteristics of the site. This data should include head loss characteristics, bypass capabilities and the proposed power plant configuration. A turbine dimensionless per- formance curve, as described in Section 4 of this report, is also neces- sary. An example hand calculation is shown in Table 3-1. The techniques shown are virtually identical to those that would be utilized within a computer operation study. The example shown is for only six months. In most cases, a much longer record, at least eight to ten years, is necessary to achieve a reasonable estimate of the average annual energy. In some circumstances, where the flow for each month of the year is virtually constant from year to year, an average flow may be calculated for each month and the average annual energy estimate based on a twelve-month study using the average flows. 3-20 n l_J I I I ,--' ' I I L_J I . ' J l_ r---... I i i I '----_) 1--( l __ j [] In most cases, however, it is more accurate to use a long-term record, which emphasizes the advantages of a computer. The following is an example of an operation study performed by hand com- putations. Given: Six month record of flow and static head Flow Head n 3/s (m3/s) ft (m) - January 150 (4.2) 35 (16.6) February 70 (2.0) 40 (12.2) March 200 (5. 7) 55 (16.8) Apri 1 310 (8.8) 60 (18.3) May 650 (18.4) 60 (18.3) June 300 (8.5) 50 (15.2) Estimated head loss -hl = 0.00004 Q2 Sufficient bypass capacity is available through either spillway or alter- nate outlet works, to pass all flows in excess of the turbine capacity. Proposed Development-One Semi-Kaplan turbine, with a rated head of 50 ft. (15.2 m), a rated output of 1,200 kW and an efficiency at rated head and power of 87 percent. Rated flow may be calculated: Pw = 0.0846 Q Hnn (3-2) Q = p w 0. 0846-H-nn 3-21 1200 Q = ...,........,=--;;-.,.------i:-:,:,---=-....,..,... 0.0846 X 50 X 0.87 Results of the hand calculations for the six month operation study is shown on Table 3-1. The .unit is operated for the six month period as, follows: 0 January -Insufficient head for generation 0 February -Insufficient flow for generation 0 March Normal operation, plant operating at half capacity 0 Apri 1 -Normal operation, plant operating in overload 0 May -Spill occurring, plant operating at peak capacity 0 June -Normal operation, plant operating near peak efficiency Computer Computation One page of a typical computer operation study is shown as Table 3-2. The example shown is for a typical low-head site, with a net head of 60 ft (18.2 m). The example shown has a fixed head, but variable head sites may also be evaluated using a computer. The proposed site development consists of two 500 kW Semi-Kaplan turbines. For each month of the oper- ation study, an evaluation is made to determine if power generation is possible within the flow and head restraints on turbine operation. If the project can be operated, an iterative evaluation is made to determine the optimal combination of on-line turbines. The result of this deter- mination is shown in the "Units" column of the output; "0" indicates that generation cannot be made, "P indicates that only the first turbine is on-line and "21" indicates that both turbines are on-line. As necessary, flow can be bypassed around the power plant. The extent of these by- passes is shown in the four flow columns of the output. The effective head is calculated using the average monthly water surface elevation, the interpolated tailwater elevation and the calculated head loss. 3-22 ~l I I 1 i _1 ! 1 i -I i I I ! 1 I ' I I l_J 0 r--~ I t I I l.~ r--~ I I I I L -J ,---, i : ! I L_J D HYDRAULIC CRITERIA General In the production of hydroelectric power some losses of head are incurred in the intake and water conveyance facilities. These head losses may be represented by: Head v2 h = k-2g where k = loss coefficient V = water velocity ft/s (m/s) g = gravitat~onal constant, 32.2 ft/s 2 (9.8 m/s ) v2 -2g-velocity head, ft (m) (3-3) Some of the most commonly used concepts of head .in conjunction with hy- droelectric power installations are shown on Figure 3-7. The following definitions of heads are from [3] and have been modified to represent low head installations applicable to this report. Gross head (Hg): is the difference in elevation between the water levels of the forebay and the tailrace. Net head (Hn): is the gross head less all hydraulic losses ex- cept those chargeable to the turbine. Net head is the head available for doing work by the turbine. The intake and penstock losses are not in- cluded in net head, but the spiral case and draft tube losses are consid- ered chargeable to the turbine and are included in net head. For small hydroelectric plants covered in this report, the hydraulic losses should not exceed five percent of the rated head. Penstock velocities should be based on economic studies, but should not normally exceed about 10 ft/s (3m/s) for small low head hydroelectric installations. 3-23 Maximum head (Hmax): E 1 evat ions between the maximum forebay level without surcharge and the tailrace level without spillway dis- charge, and with one unit operating at speed-no-load (turbine discharge of approximately 10 to 15 percent of rated flow). Under this condition, hydraulic losses are neglible and may be disregarded. Minimum head (Hmin): Is the net head resulting from the differ- ence in elevation between the minimum forebay level and the tailrace lev- el minus losses with all turbines operating at full gate. Design head (hd): is the net head at which peak efficiency is desired. This head should be selected so that the maximum and minimum heads are not beyond the permissible operating range of the turbine. This is the head which determines the basic dimensions of the turbine and therefore of the powerplant. Rated head (hr): is the net head at which the full gate output of the turbine produces the generator rated output in kilowatts. The turbine namplate rating usually is given at this head. Design hea~ and rated head are usually the same for small hydro- electric plants. Head Losses In addition to the head loss effected at the turbine, which is expressed by the turbine efficiency, head losses also occur in the water passage ways. The magnitude of the 1 asses in each segment as we 11 as the tot a 1 is dependent upon the part i cu 1 ar 1 ayout of the camp 1 ex adopted for the site. For small low head hydroelectric developments these values are generally sma 11. At the appraisal level of investigations, depending· upon the configuration and overall layout of the facilities, these losses may be assumed to be either negligible, zero, for a tubular or bulb 3-24 I i ' ' i ~ ' -) turbine located at the dam or canal drop or taken as a small percentage, no more than five percent, of the gross head (Figure 3-8). In cases where the head losses may be considered substantial compared to available head, they should be estimated using the best available methods [4, 5, 6] and data. This is specially important with regards to small hydroelectric plants, 65.6 ft (20 m), since their power output capacity is highly sensitive to the net head and a slight difference in its value may make the difference between a feasible and an infeasible project. The different head losses for the various components of the hydraulic conveyance system can conveniently be expressed in a generalized form as a function of the respective average velocity head, Equation 3-3. Simplified ways of estimating the loss coefficient, k (in equation 3-3), for the most common causes of head loss in the water ways are presented in the following. 1.) Head Loss Through Trashracks The head loss through trashracks is a function of the shape, bar spacing, clear opening and water velocity. The losses may be taken as 0.1 ft (0.03m), 0.3 ft (0.09m) and 0.5 ft (0.15m) respectively for velocities of 1 ft/sec(0.3 m/s), 1.5 ft/sec (0.46 m/s) and 2 ft/sec (0.61m). If a closer approximation to the head loss through the trashrack is required, then reference is made to [7J wherein data are presented for several types of bar designs over a range of bar spacing. 2.) Penstock Entrance Loss The head loss at the entrance of a penstock depends mainly on the shape of the entrance and may be expressed in terms of the velocity head. Losses in circular bellmouth entrance are estimated to be 0.05 to 0.1 of the velocity head [7]. For square bellmouth entrances, the losses are estimated to be 0.2 of the velocity head [7j. 3-25 3.) Friction Loss in Penstocks Head loss velocity, pipe, the formula: in pipes, because of friction is a function of the flow fluid viscosity and surface roughness. For large steel Scobey formula for head loss is generally an acceptable vl.9 vl.9 hf = ks- 0 -.r-1----..1.--(2.587 ks--;;r.-1 r~etric units) (3-4) where hf = head loss in ft (m) per 1000 ft (m) ks = loss coefficient, determined experimentally v = flow velocity in pipe ft/s (m/ s) D = diameter of pipe in ft (m) For appraisal studies, a value of ks = 0.34 is acceptable and is ap- plicable to old pipe that can be maintained without too much deter- ioration of the inner surface [7]. Head loss charts are available in reference [7]. For feasibility studies if a more detailed analysis is required, a method of determining friction head loss using the parameters of Reynolds Number and surface roughness is presented in [8]. 4.) Bend Losses in Penstocks The bend loss excluding the friction loss for a large circular con- duit is a function of the pipe diameter, bend radius and deflection angle of the bend. If the ratio of bend radius to pipe diameter is about four, the head loss will be less than a quarter of the velocity head. It is not economical for the ratio of the bend radius to pipe diameter to be greater than five [7]. Experimental work has been done on small diameter brass bends at Reynolds numbers up to 225,000 3-26 i ' -~~ I ' _) I I ! - : I ___ J :-l , ___ J --, l ' ! ' J which has been accepted for more detailed design values of head loss in bends [7]. 5.) Head Loss in Valves Head loss in valves depends upon the type, size and percentage of opening of the particular valve in use. Throttling is accomplished by the turbine wicket gates so only the losses at full gate opening is of concern. At full opening the 1 osses are very sma 11 and an average value of head loss for a gate valve is 0.1 velocity head [7]. For needle valves, the factor is 0.2 and for a medium size but- terfly valve with ratio of leaf thickness to diameter of 0.2 a value of 0.26 may be used [7]. 6.) Summary ~.Jhile the foregoing factors influence the feasibility of a project, its energy output and capacity depends exclusively on the magnitude and distribution of flow, method, and the characteristics of the tur- bine/generator. The power output of a hydroelectric plant is ex- pressed by the formula 3-2. 3-27 Explanation of Columns (3) = (1)-(2) (4 ) = (2) X 100 326 (5) A Given Condition (6) = (5) -0.00004 X (2)2 (7) = (6) X 100 50 (8) From Turbine Chart Fig 4-4 ect. for corresponding values of (4) & (7) 1200 X (8) (9) = 100 (9) X 100 (10) 0.0846 X (2) X (6) (11) = (9) x Number of Days in Month x 24 ~ 10 6 3-28 TABLE 3-2 EXAMPLE -OPERATION STUDY HYDROELECTRIC GENERATION TURBINE CHARACTERISTIC: 2UNITS, PROPELLER TYPE, p = 500 kW, Q = 115.4 3 ft /s, H = 60 ft, N = 127 s Yearl~ Out~ut L Outflow(cfs> Effective Units Power Efficiency Energy ~1or1t. h Total Tur·b i ne i 11 Head< ft.> (ki-J) (%) <MkWh> Oct. 70 70 0 e 59.8 1 304 85.2 0.23 Nc•v 86 86 e 0 59.7 1 375 86.6 0.27 D.:·c 50 50 0 0 59.9 1 205 8e.3 e. 15 Jan 56 56 e 0 59.9 1 234 82.2 (1. 17 Fe·b 65 65 0 0 59.8 1 276 84.3 0.19 Mar-130 130 e 0 59.3 21 550 84.4 0.41 Apr· 308 249 e 59 57.5 21 1007 83.1 0.73 ~1a~' 928 249 0 679 57.5 21 1007 83.1 0.75 Jun 1087 249 0 838 57.·5 21 1008 83.1 0.73 Jul 191 191 0 0 58.5 21 820 86.8 0.61 Aug 68 68 e 0 59.8 1 291 84.8 0.22 Sep 57 57 0 0 59.9 1 237 82.4 0.17 Total 4.61 L Outflow<cfs) Effective Units Power Efftct·ency EnerQY Month Total Turbine B 111 Head(ft> ('klol) (%) <MkWh> Oct 118 118 0 59.4 1 505 84.9 0.38 Nov 89 89 0 59.7. 1 389 86.7 0.28 Dec 64 64 0 !59,8 1 273 84.1 0.20 J&n 64 64 0 !59.8 1 273 84.1 0.20 Feb tee 100 0 59.6 1 436 86.6 0.29 Mar 99 99 0 59.6 1 431 86.6 0.32 Apr 358 249 199 !57.5 21 1007 83.1 0.73 May 117!5 249 926 57.5 ~1 1007 83.1 0.75 Jun . 1887 249 1637 57.!5 21 1007 83.1 0.73 Jul 707 249 457 !57.!5 21 1'007 83.1 0.75 Aug 216 216 0 !58.1 21 911 85.9 0.68 Sep 141 141 0 59.2 21 602 85.3 0.43 Total 5.73 3 Outflow<cfs> Effective Units Power Efficiency Energy Month Total Turb i.ne B i 11 Head(ft) <kW> 00 (Mklolh) Oct 166 166 0 58.9 21 718 86.6 0.53 Nov 123 123 0 59.4 1 52e 84.2 0.37 Dec 70 70 0 59.8 1 304 85.2 0.23 Jan 64 64 e !59.8 1 273 84.1 0.20 Feb 64 64 e 59.8 1 273 84.1 0.18 Mar 96 96 e 59.6 1 42e 86.7 0.31 Apr 655 249 406 57.5 21 1007 83. 1 0.72 May 1174 249 925 !57.5 21 1007 83.1 0.75 Jun 570 249 321 57.5 21 1e07 83.1 0.72 Jul 102 102 0 !59.6 1 444 86.5 0.33 Rug 53 53 0 59.9 1 220 81.3 0.16 Sep 52 52 0 !59.9 1 215 81.0 e. 16. Total 4.68 Average Annual Energy !5.01 3 .. 29 Figure 3-1 Typical Flow-Duration Curve 3-30 •• • r-~, ~~-~ [_~1 l I I f _~ i l-~; ~-- I . [! I • r- 1 i I I I i l-1 [! ·: -3! ~ ->-._ (.) ~ <( (.) _J_.r---,_ _r --= .r---~---, -., - J MONTH SYSTEM LOAD --SMALL HYDRO PLANT AVERAGE MONTHLY CAPACITY A DEPENDABLE CAPACITY (ANNUAL GENERATION AVAILABLE 90 PERCENT OF TIME) Figure 3-2 Reservoir Operation -Capacity Credit 3-31 D >-..... u ~ <( u • PEAK PERIOD I I I I I I -:?' ~ ~ r---...J'-~-----1 I <( I -l I J F I M I. A I M I J I J I A I s I 0 I N I D MONTH , I l I ----SYSTEM LOAD ---SMALL HYDRO PLANT-AVERAGE MONTHLY CAPACITY ~ -1 A DEPENDABLE CAPACITY (GENERATION AVAILABLE 90 : __ j PERCENT OF TIME DURING PERIOD OF PEAK SYSTEM LOAD) : I ! ' I I i Figure 3-3 Non-Storage Operation -Capacity Credit 3-32 , -I I I { ! I I I I : I J •• >-1- (.) ~ <t (.) J MONTH _-I_r-----1 SYSTEM LOAD --SMALL HYDRO PLANT-AVERAGE MONTHLY CAPACITY NOTE: NO ALLOWANCE FOR CAPACITY CREDIT AS CAPACITY IS NOT AVA[LABLE DURING SYSTEM PEAK LOAD Figure 3-4 Non-Storage Operation -No Capacity Credit 3-33 D • Figure 3-5 Typical Non-Storage Flow-Duration Curve 3-34 i_ ,-1 I • Figure 3-6 Typical Non-Storage Water Canal Source Flow-Duration Curve 3-35 MAXIMUM WATER SURFACE }:.---------------~--------MAXIMUM ;-·:1 : .._ ____ HEAD,Hmax. SURCHARGE-~- ---------=-- I WEIGHTED AVERAGE WATER L9SSES -----------~-------- +-----DESIGN HEAD,hd REQUIRED SUBMERGENCE _r-LOSSES ~~~~~~~~~==~~~ INACTIVE AND DEAD CAPACITY Figure 3-7 Heads -Reaction Turbines [3] 3-36 MINIMUM HEAD, Hmin. ~-+---+--RATED HEAD, hr TURBINE FULL- GATE OUTPUT PRODUCES GENERATOR RATED OUTPUT TAILRACE '---'---'---ALL UNITS OPERATING FULL GATE '------ONE UNIT OPERATING SPEED-NO-LOAD Ll Figure 3-8 Hydraulic Losses (to be deducted from the static head) 3-37 ASSUME LOSS 5% ! : jl I ,- 1 I I ' I l I I ! I i CLARIFICATION NOTE The terminology "Capacity Factor" as used (pp. 3-15,3-16 and 3-17) in application of the flow-duration curve for sizing· turbine/generators is in essence the plant utilization factor. The design plant utilization factor is the ratio between the energy developed and the energy available. A turbine/generator capacity factor is equal to the ratio of the actual energy generated to the energy the turbine/generator is capable of developing. 3-0 ' ' ) I ' I GENERAL SECTION 4 TYPICAL LAYOUTS OF LOW-HEAD PLANTS AND APPURTENANCES The major equipment item in a hydroelectric plant is the turbine/genera- tor unit. The remainder of the plant equipment is to control, protect and provide services to the main generating unit. This section reviews these supporting systems as used in small low-head hydroelectric plants. To develop the full potential of any site, the proper selection of a hy- draulic turbine is of prime importance. There are two fundamental types of hydraulic turbines, reaction and impulse. For low-head hydro plants, the reaction type is most often used. Reaction type turbines are prin- cipally classified as a propeller or Francis type. However, within the maximum head limits of this study, 65.6 ft. (20m), there is available in addition to the reaction type turbines, a type called 11 crossflow 11 which is of the impulse type and commercially made in sizes up to about 2 MW. For a more iri depth description of hydraulic turbines, the reader is re- ferred to reference [3]. This section describes the performance and characteristics of the various arrangements of reaction turbines which may be used within the head and power range of this report. TURBINE TYPES General ---- The various types of turbines are described in detail in the following section. Figure 4-1 illustrates the mechanical arrangement of reaction type turbines and the crossflow turbine currently commercially available with the names commonly used for the various configurations. Table 4..:.1 gives data on the head range and capacity for each turbine classification discussed in this section. 4-1 Vertical Francis Turbine Francis turbines are available for operation at heads of 16.4 ft (5 m) and above. The hydraulic characteristics of a Francis runner are such that operating speeds are lower than comparable propeller runners, hence may not be as cost competitive due to the increased physical size of the turbine and higher generat_or costs. The turbine shaft is connected to the generator by a flanged coupling driving the generator at the turbine speed or through a speed increaser permitting use of a higher speed lower cost generator. Some manufacturers offer integral one piece turbine gen- erator shafts. A Francis turbine has an efficiency curve with a slope ·which falls be- tween the fixed blade propeller and the Kaplan turbine. Power output range is equal to the Kaplan turbine, however, efficiencies are lower when operating at lower loads than rated output. Efficiencies at off- rated heads are also lower than the Kaplan turbine but higher than the fixed blade propeller unit. Horizontal Francis Turbine A Francis turbine may be designed for horizontal mounting. The turbine shaft is parallel with the powerhouse floor and coupled direct or through a speed increaser to a horizontal generator. The cost of the generator is less than that of a vertical generator due to the smaller size and re- duced thrust bearing requirements. However, the horizontal mounting will require greater floor space than a vertical unit but less vertical height. In general, vertical units are more cost competitive than hori- zontal units when the throat diameter of the turbine is over 4 ft (1.2m) in diameter. Vertical Propeller Turbine Propeller turbines are available for operation through out the head range of this report and are offered with fixed blade or adjustable blade 4-2 l_ (Kaplan). Power output of these turbines is controlled by wicket gates and/or positioning of the runner blades. Vertical Fixed Blade Propeller Turbine A fixed blade propeller turbine has a sharply peaked efficiency curve. When operated at loads below the rated capacity, efficiency drops off, rapidly ~educing both power output and range. Vertical Kaplan (Adjustable Blade Propeller) Turbine A Kaplan turbine has a broad flat efficiency curve and provides optimum power output over a wide range of load and heads above and below rated capacity and head. Damage from cavitation is less than either the fixed blade or Francis type when operating at off-rated conditions. Open Flume Francis or Propeller Turbine Both Francis and propeller runners may be used as an open flume tur- bine. The design consists of a wicket gate and stay ring assembly mounted vertically in a nonpressurized flume. The turbine guide bearing and wicket gate mechanism are submerged and generally water lubricated which increases maintenance costs. Operation in applications where silt is in the water will cause excessive wear on the wicket gate mechanism. This type of turbine is limited to an operating head of 33 ft (10m). Above this head the turbine shaft length becomes excessive. When this type of turbine is suitable, the equipment and civil costs are lower than the other types discussed. Overall efficiency is one to two percent lower than the spiral case design. " Closed Flume Francis or Propeller Turbine Performance is the same as for units with a spiral case except turbine efficiencies will be approximately one to two percent lower due to the spiral case design. Excessive wear due to submerged wicket gates will occur when silt is in the water. 4-3 Tubular Turbine Tubular turbines are horizontal or slant mounted turbines with fixed or adjustable blade propeller runners. The generators are either direct coupled to the turbine shaft or connected through a speed increaser. The generators are located outside the water passage ways which result in larger floor space requirements than the vertical or· Bulb type units. These higher civil costs are offset by reduced height requirements for the building and lower turbine and generator costs. The tubular turbine design is adaptable to standardization and is discussed separately in this Section. Slant mounting of the tubular turbine reduces the floor space requirements, however, it adds cost for the turbine and generator due to higher thrust and longer shafts. Tubular Turbine (With adjustable blades and fixed gates) A tubular turbine with fixed gates is controlled by adjusting the runner blades. The efficiency curve is between the fixed blade propeller and the Kaplan units when operated at off-rated conditions. Damage from cav- itation at off-rated conditions is generally less than fixed blade units. Tubular Turbine (Fixed blade runner with wicket gates) The performance characteristics are the same as for the Vertical fixed blade propeller unit except that the turbine efficiency will be approxi- mately one percent higher than the same size vertical unit due to the nearly straight through flow conditions. Tubular Turbine (With adjustable blad~s and wicket gates) When a tubular turbine is equipped with both adjustable blades and wicket gates the performance characteristics are the same as a vertical Kaplan turbine. Bulb Turbine Bulb turbines are horizontal units which have wicket gates and fixed or adjustable blade propeller runners directly connected to the generator. The generator is enclosed in a water-tight structure (bulb) located in 4-4 .I the water passage ways. This design permits a compact powerhouse structure with minimum floor space and height. The straight flow water passage way also minimizes head loss. This reduction in space requirements is offset by increased turbine and generator costs due to the water tight requirements. Bulb turbine•s performance will be the same as for a vertical Kaplan unit except overall turbine efficiencies will be approximately one to two per- cent higher due to straight flow water passage \-Jays and reduction of en- trance head loss. Bulb units are available with fixed blade runners and have the same performance characteristics as the vertical propeller unit with higher efficiencies. Rim Turbine The concept of a rim type turbine, which has the generator rotor mounted on the periphery of the turbine runner blades, was developed 40 years ago and approximately 75 units are in service with capacities of 1000 to 2000 kW at heads up to 50. ft (15 m). The Rim turbine offers a potential saving in powerhouse construction cost due to its compact design. Stan- dardized units are available for heads up to 50 ft (15m) and power out- puts of 20 MW. Custom designs to higher heads .are available. Right Angle Drive Propeller Turbine Fixed blade propeller turbines with a right angle drive speed increaser located. in a bulb upstream from the runner are commercially available up to capacities of approximately 2 MW. Performance characteristics are the same as a tubular turbine except that the overall efficiency is two to three percent less due to losses in the speed increaser. Crossflow Turbine The crossflow or •double shot• turbine was developed independently by Banki and.~ichell in the early part of this century. The crossflow tur- bine is essentially of the impulse type and may be regarded as a further development of the undershot water wheel. 4-5 The low specific speed associated with this turbine is characteristic of the impulse type and results in large unit dimensions for low heads and large flows. Normal configurations include a gearbox to increase the generator speed. Several manufacturers have developed stock turbines which can operate at heads of from 6.6 ft (2m) to 328ft (100m). The turbine appears to be attractive for small "packaged" units. Cross flow turbines are normally free from construction problems due to the lack of embedded parts but data on operation are sparse. The turbine is self-cleaning due to the reverse flow on exit from the turbine runner. Pelton Turbine Impulse (Pelton) turbines are designed to operate with the jet in free air, therefore, the unit must be installed above the maximum tailwater elevation. This results in a head loss of from 4 to 12 ft (1.2 to 3.6 m). Compressed air systems for tail water depression have been used to permit operation of impulse units during high tailwater conditions, how- ever, the net energy produced by the plant is less due to the energy re- quirements of the air compressor. For the 65.6 ft (20 m) maximum head covered in this report, the 4 to 12 ft (1.2 to 3.6 m) head loss, the large size and associated high costs generally eliminate the impulse turbine as a possible selection when compared to the reaction turbines. TURBINE STANDARDIZATION Reaction turbine runner models have been developed and tested by turbine manufacturers and cover the full specific speed range of turbines applic- able to the head range of this report. The majority of the existing tur- bines are custom designed by using the model affinity laws applied to a model runner of the suitable specific speed and selecting the appropriate· size and speed for the prototype turbine. The design development cost of a custom made turbine is high and independent of either the capacity of 4-6 I -I L __ ; the uriit or the turbine manufacturing costs .. When this fixed cost is ap- plied to. the costs of the turbine sizes included in this report, 15MW and under, it represents a substantial percentage of the total cost. Encour7 aged by the market potential for low-head turbines, manufacturers have developed complete designs of a range of turbines suitable for low-head application. Figure 4-2 shows the shop assembly of a standardized tubular turbine. Presently, ten sizes are available from one manufacturer with .runner diameters up to 118.1 in (3000mm) covering applications up to 5MW with heads from 7 to 50ft (2 to 15m). Foreign manufacturers have also developed standardized designs of vertical and horizontal Propeller, Kaplan, and Francis turbines as well as Bulb turbines.. In addition to the lower first costs of a standardized turbine, equipment delivery time is reduced. Current delivery time for standardized units is approximately nine months. Refer to Fig. 4-3 for standardized tubular turbine data. TURBINE EFFICIENCY General On the Francis type reaction turbine, the flow enters the runner radially and is discharged axially with-respect to the turbine shaft. The Francis type is generally suitable for higher heads than covered by this report, however, this type may be competitive at heads above 32.8 feet (10m). On the propeller (either the fixed blade or adjustable blade, the Kaplan,) reaction turbine the flow is throu~h the runner axially with re- spect to the turbine shaft. The propeller type h suitable for applica- tion throughout the head range of this report. When the prope 11 er type is used in a "tubular" configuration, due to the straight through water passageway, there is generally an overall increase in efficiency. Peak Efficiency Reaction turbines have a peak efficiency which occurs at the best power and head condition for the specific speed design of the runner. This point varies between different manufacturers designs due to variation in 4-7 bucket and blade contours and number of buckets as well as other 'devi a- t ions in designs. However, generalized parameters may be established and used for power studies which wi 11 be. within the· accuracy 1 imits of the report and apply to the various commercially available designs. Typi- cally, the point of peak efficiency at rated head is· at 80 percent of rated power for fixed blade propeller and Francis. turbines. With adjust- able blade propeller turbines, the point of peak efficiency occurs near 60 percent of rated power. This permits a broader .operating range for the adjustable blade propeller turbine. Efficiency Step Up Reaction turbines are model tested and prototype performance is predicted from the model test. The scale effect in efficiency step up from model to prototype may be predicted from the Moody formula [3]: .lln = ( 1 -. nm) Where 1/5 [1 _ ( Dm) ] Dp .lln = Efficiency step up at best efficiency nm = Model turbine best efficiency Dm =Model .turbine throat diameter, feet (m) Dp = prototype turbine throat diameter, feet (m) (4-1) The (4-1) empirical formula was developed for only the best efficiency point. However, for practical purposes it is generally assumed that· the .lln calculated for the point of best efficiency is applicable to all heads and gate openings. 4-8 I , I -_, ' I ·. I ~--) For purposes of power studies, the amount of step up in efficiency may be calculated from the (4-1) formula using the efficiencies for the type of turbine selected and the turbine throat diameter. Typical efficiencies obtained in a 12 in (305 mm) model are as follows: Francis Propeller Kaplan Peak Efficiencies Percent 89 89 89 Crossflow and Impulse Turbine Efficiencies Rated· Efficiency Percent 87 88 85 Impluse turbines have a peak efficiency of 90 percent plus or minus 2 percent. There is very little reduction from the peak efficiency when operating from 20 to 100 percent of rated load. For purposes of power studies a value of 90 percent may be used. Crossflow turbines also have a flat efficiency curve, however, the peak efficiency is generally expected to be 85 percent and guaranteed to be 83 percent. A value of 84 percent may be used for power studies through the operating range of 20 to 100 percent of rated load. HEAD LIMITATIONS Reaction turbines are restricted to operation within upper and lower head limits by their performance characteristics, cavitation and unstable operation. At the lower limit, efficiency drops rapidly and the flow distribution at the inlet of the runner becomes unstable as the whirl imparted by the guide vanes and/or wicket gates is in a transition range. During this transition there may be power surges which results in rough operation. Efficiency at heads higher than the rated head will not drop off as rapidly as at low heads. The upper limit is established by the cavitation limit of the turbine setting. The critical sigma and plant sigma as discussed in 11 Turbine Selection 11 section must be evaluated 4-9 at the highest operating head and an appropriate turbine setting selected. FLOW LIMITATIONS Discharge limits of reaction turbines are restricted on the low side by unstable operation and on the high side by cavitation limits and/or the maximum discharge capability of the runner. The guide vanes and wicket gates at the entrance of the runner are set at an angle which establishes a whirl in the flow stream of the runner bucket passageways. Establish- ment of this whirl occurs between 20 and 40 percent of rated load and is dependent upon the runner characteristic as well as the entrance and exit water passageways of the power house. Because model testing is normally done in a test flume, where the power house water passageways are not duplicated, the lower limit generally can not be accurately predicted. During the establishment of the whirl rough operation may occur causing vibration and/or power surges. When operation is required at low out- puts, vanes may be installed at the discharge of the runner which reduce the roughness of operation. The vanes, however, will also reduce efficiency and/or capacity at high performance loading. At· the upper limit of discharge, the efficiency drops abruptly as the maximum discharge capacity of the runner is approached. This reduction is efficiency and hence horsepower is measured in model tests to establish the critical sigma of the runner. The limit of discharge or gate opening is then established by the turbine setting. TURBINE SELECTION SUMMARY The designs and-performance of turbines available from manufacturers vary and it is impractical to perform a detailed analysis of all the various units offered when evaluating the feasibility of a hydroelectric power project on an appraisal level. The variance in design and performance generally occurs at the off rated conditions and have a negligible effect on the accuracy of the study. Performance experience is avail able and 4-10 typical limits of head and discharge ranges as well as values for ef- ficiency have been established from both public and private utilities and turbine manufacturers. In order to provide a convenient means to compute a power estimate, dimensionless performance curves have been prepared for the various runner types and discharge control schemes. The limits shown are typical and operation outside of these limits may be possible. How- ever, consultation with turbine manufacturers and other design criteria ; should be reviewed if operation is beyond the limits shown. TURBINE PERFORMANCE General Dimensionless performance curves were developed from typical performance curves of the turbines of a specific speed that was average for the head range considered in this report. The data used was obtained from turbine manufacturers 1 data and [3]. Comparison of performance curves of various specific speed runners were made and the average performance values were used. The maximum error occurs at the lowest power output and is approx- imately three percent. These curves may be used to determine the power output of the turbine and generator when the flow rates and heads are known. These curves are proposed herein because they are easily adapted for use in a digital computer instead of the more conventional 11 Contour- type11 performance curve often found in turbine literature. The curves show turbine discharge, QR, versus generator rating, PR, throughout the range of operating heads for the turbine. 4-11 The following lists the dimensionless performance curves: Turbine Runner Control . _ _lype ______ Fi gu!:_~_Numb_er Francis Propeller (Adjustable Blade) Propeller (Adjustable Blade) Propeller (Fixed Blade) Turbine Performance Wicket gates Wicket gates & Blade Pitch Blade Pitch Wicket gates Vertical or Horizontal Francis 4-4 Vertical Kaplan, Tubular, Bulb & Rim 4-5 Tubular 4-6 Vertical Propeller Tubular, Bulb & Rim 4-7 Following determination of the selected turbine capacity the power output at heads and fl,ows above and below rated head (HR) and flow (QR) may be determined from the curv~s as follows. Calculate the rated discharge QR using the efficiency values discussed previously. QR PR = 0.0846 = HR nR PR m3 !s metric units) 0 Where: PR = Rated Generator output, kW HR = Rated Turbine head, feet (m) nR = Turbine Efficiency at rated condition, nG = Generator efficiency 4-12 (4-2) Compute the percent discharge, percent QR and percent head, percent HR, for the various flow and head requirements of the site. percent Q = _g__ R QR X 100 (4-3) percent HR H X 100 -HR (4-4) Enter the curves Figure 4-4, 4-5, 4-6 or 4-7 with the percent QR and find the percent PR on the appropriate percent HR line. The heavy lines at the border of the curves represent limits of satisfac- tory operation within normal industry guarantee standards. The top boun- dary line represents maximum recommended capacity at rated capacity. The turbine can be operated beyond these gate openings, however, cavitation guarantees generally do not apply beyond these points. The bottom boun- dary line represents the limit of stable operation. The bottom limits vary with manufacturer. The right-hand boundary is established from standard generator guarantees of 115 percent of rated capacity. The head operation boundaries are typical, however, they do vary with manufac- turer. When the percent QR for a· particular selection is beyond the curv~ boundaries, generation is limited to the maximum PR for the percent H0 . The excess water must be bypassed. When the percent QR is below the boundaries, no energy can be generated. When the percent H0 is above or below the boundaries, energy can not be generated. Standardized Tubular Turbine Performance curves for the Allis-Chalmers units are shown on Figure 4- 8. The same procedure for selection of turbines previously-described is applicable for tubular turbines. Following selection of the size, Fig- ure 4-6 may be used for estimating power over the range of flow and head. 4-13 TURBINE SELECTION Reaction Turbines Reaction turbines may be operated with the runner installed either above or below the tailwater surface elevation. The net effective head for de- veloping power is uneffected by the setting provided the discharge of the draft tube is submerged at least one foot (0.3 m) below minimum tailwater elevation. However, unstable operation and/or excessive pitting of the runner and discharge ring may occur due to cavitation if the setting of the turbine is not properly matched to the specific speed of the run- ner. The primary dimension of a turbine is the throat diameter, o3. This dimension establishes the power capacity and can be used to estimate the overall dimensions of the turbine. The civil construction ·costs shown in Section 5 are based upon the turbine throat diameter, o3 . Two methods of estimating the throat diameter are presented. Method A is a simplified chart shown in Figures 4-8, 4-9 and 4-10. By use of Figures 4-8, 4-9 and 4-10, 03 may be determined graphically for the turbine types and sizes of this report. Figure 4-8 shows 03 for ten turbine sizes manufactured by Allis-Chalmers and of a type referred to in this report as standardized tubular turbine. Figures 4-9 and 4-10 shows the variation an uncorrected value of 0 3 with the turbine head for various turbine types and sizes. A correction factor, which is a func- tion of turbine setting, is included in these two figures for determining the corrected value of o3 . The following is an example for the method of applying either Figure 4-9 or 4-10. Assume o3 is needed for a 5MW Kaplan turbine operating at a head of 20ft (6.1m) and installed at and elevation of 1000 ft. (305m) with the distri- butor 3 ft (0.9m) above the tailwater. 4-14 From Figure 4-10 the uncorrected o3 = 12.5 ft. Altitude correction = +1 percent Tailwater correction = +3 percent Then 03 = 12.5 X 1.01 X 1.03 = 13 ft ( 3. 96m) Method B is a more precise method and may be used when the turbine set- ting is dictated by site conditions or pre-determined.The dimensional parameters used to define the setting of the turb·ine· are as established in [3]. Figure 4-11 is a reproduction of charts and graphs defining these dimensions. A cavitation factor o has been developed from model tests and prototype performance experience to select a safe setting for reaction turbines. This cavitation factor is generally referred to as plant sigma and defined as follows: 0 p Where op = Plant cavitation factor (plant sigma) Hb = Ha -Hv = atmospheric minus vapor pressure in feet b = vertical distance distributor center line to throat (at o3 ) in feet (4-5) Hs = static draft head in feet (Plus above the tailwater elevation, minus when below) H = net turbine effective head in feet Reaction turbines have critical which are dependent upon the established by model testing. cavitation factors, ocr• design of the runner. The static draft head (critic a 1 sigma) This value is (Hs) is lowered maintaining a constant speed and net head then the critical sigma (ocr) is established when the output (kW) of the turbine decreases. Selection of the turbine speed (N) and throat diameter (0 3 ) can be made from the 4-15 critical sigma (ocr) and plant sigma (op) by selecting a proper safety margin. Typical safety margins for propeller and Kaplan turbines are 5 to 6 feet (1.5 to 1.8 m) and 4 ft (1.2 m) for Francis turbines. The safety margin factor (sigma margin) om is defined as follows: Where Hm. = safety margin in feet H = net turbine effective head in feet The plant sigma (op) must be equal or greater than the sum Df the criti- cal sigma (ocr) and sigma margin (om) to avoid cavitation and results in the following formula: (4-7) Sizing of the turbine can be established when critical sigma (ocr) is known. If the critical sigma is unknown, Figure 4-11 may be us·ed to ap- proximate the value. Figure 4-11 is based upon typical values. Fol- lowing is an example of selection of size and speed for a propeller turbine: Given P = turbine rated output = 10,000 kW H = turbine rated head = 56 ft (17m) Minimum Tailwater elevation = 4920 ft (1500 abmsl) Centerline of Distributor elevation = 4917 ft (1499 abmsl) 4-16 Calculate plant sigma: ·CJ = p (4-5) Assume b to be 1.6 ft (This can be recalculated after throat diameter is known). Hb = Ha-Hv = 28.34-0.59 = 27.75 ft (8.46m) Hs = 4917 -4920 = -3.0 ft (0.91m) crp = 28.34 +5~.6 + 3 = 0.588 Calculate sigma margin: -Hm crm -H Hm = 6 ft (1.8) (Typical for propeller turbines - 6 crm -50 = 0.120 Calculate critical sigma: (4-6) crcr = crp -crm = 0.588 -0.120 = 0.468 (4-7) Enter Figure 4-11 and select specific speed (Ns) and calculate turbine speed. Ns H 514 N = pT/2 4-17 (4-8) \ N = 104 X 153.19 100 = 159.3 r/min Correct to synchronous speed (next lowest speed) based on system frequen- cy, 60 hertz. Calculate throat diameter of turbine, o3 , for a propeller turbine is as follows: 0 = 3 (4-9) Where 03 = Velocity ratio at o3 = 0.063(Ns)213, (metric, 0.0233(Ns)2/3) 03 = 153 x 0.063(1m 213 (~)112 (4-9) = 10.64 ft (3.24 m) The above method should only be used for preliminary sizing of the tur- bine. Both critical sigma and specific power vary with different manu- facturers designs. The method is useful, however, to compare alternate settings of the turbine from a cost standpoint. The lower the setting of the turbine the smaller the size and higher the speed. This results in a lower cost turbine and a lower cost generator. These amounts can be com- pared with higher excavation and civi 1 structure costs to determine the most economic selection. 4-18 r--, l ) I : L....,...- '---...--' I I I I I ', L.~· '-, ! ' -1 j ' \ i ' ' ' i_-J , _______ ! r --1 I I To calculate the throat di~neter of a Francis turbine the same method is used as that shown for· the propeller turbine except the velocity ratio, 03 , used in equation (4-9) changes. For the Francis turbine the velocity ratio at o3 becomes: TURBINE GOVERNOR General The governor is the primary turbine controller of a small hydroelectric plant. The governor may be actuated by manual or remote operation, by float level control in the waterway or by the pressure of the water in a conduit. Each method provides control for starting and loading the unit. The synchronous generator is controlled through the excitation and vol- tage regulation equipment. In coordination with. the sychronizing equipment and the turbine governor, these systems allow for unit start- up, and voltage and power control when the unit is on the line. There are several differences in the control systems required for large versus small hydroelectric installations. A comparison of the two in- stallations indicates that the primary descriptions of the above contro 1 systems are representative for both classes. In large plants, the com- plexity of the regulation equipment (i.e., governor, synchronizing, ex- citation gear) will be greater since slight increments in turbine gate position or generator field adjustment may result in large increments of power swing relative to the power grid. Small hydroelectric units do not create such an impact on the system and thereby require less costly and complex equipment. The other area where a difference occurs is in the horsepower of the auxiliary pumps, storage battery capacities and protec- tive systems. Large hydroelectric plants employ larger control systems simply because the auxiliary systems are larger. 4-19 Governor Systems There are three types of commercia 11 y av a i 1 ab 1 e governor sys terns to con- trol ·the turbine, namely, Cabinet Type, Gate Shaft Type and Electric Motor Type. In addition to these three ·types commercially available electric motor valve operators have also been adapted for load control and shut down of low capacity turbines. 1) Cabinet Type Cabinet Type governors are custom designed to meet the hydraulic servo motor requirements.of the turbine. This type is, generally used on large capacity units and provide speed regulation within .02 percent, load con- trol and emergency shut down. They are available with mechanical or electronic speed sensing devices. The electronic type 'is generally se- lected. Figure 4-12 shows a typical Cabinet Type Governor. 2) Gate Shaft Gate Shaft type governors are a self contained hydraulic oi 1 cylinder system which provide effort and control to operate the wicket gate mech- anism. The unit is available in standard sizes which will accomodate the majority of the turbines considered in this report. Speed regulation, 1 oad contra 1 and emergency shut down functions are provided through me- chanical or electronic speed sensing. Figure 4-12 illustrates this type of unit. 3) Electric Motor Electric Motor type units are a recent development and may be used when speed regulation of the turbine is not required. Current units commer- cially available are limited in speed and gate shaft effort, however, when suitable for low head, low capacity turbines, they provide a sub- stantial cost savings. Ths units are equipped with a d-e motor and a battery system which is capable of emergency shut down in the event of station service outage. Figure 4-12 illustrates this type of unit. 4-20 ~~ \ I ' i ' -J : 1 ~ 1 , I I ' I ) . ~, I I ' ! I ' ,--I ;J I J ,""'-~, : I I I ',~~) I I L __ ,..J, ' ' ,_ ~ _) . -, i i I I L_ _; ' __ ! ~--- \ I I i L j I i '----' I L~ r---l I I ! ~ Turbine Control Small low-head hydroelectric installations generally have little effect on the frequency of the power grid and may be installed without speed regulation governors which result in a cost savings. Gate control equip- ment is generally part of the equipment furnished by the turbine manufac- turer and the estimated costs are included in the turbine/generator cost curves (Section 5). For small hydroelectric installations, non-speed-regulating governors may be either hydraulic or electric-operated and their function is to bring the turbine to near synchronous speed for start-up, to regulate load after synchronous speed has been achieved and to shut down the unit dur- ing both normal and emergency conditions. The units must be equipped with mechanical speed switches and an independent energy. source which will shut down the turbine in the event of load rejection or loss of sta- tion power. ~~hen hydraulic· systems are used, an air-oil accumulator is used as an independent energy source. When electric operators are used, a d-e battery system is required. In cases where load regulation is not required, the turbine is equipped with an inlet valve which must be able to shut the unit down under emer- gency conditions. The power to close the valve can be provided by a hy- draulic accumulator system, a battery system or a weight trip lever de- vice. PLANT EFFICIENCY Genera-l The plant efficiency is based on the power losses in the turbine/gener- .ator and the auxiliary equipment. The power losses of the generator also include additional mechanical losses when the generator is driven at a speed which is different than the speed of the hydraulic turbine. 4-21 Generator Efficiency The full load efficiency of a modern commercially available generator is approximately 97 percent. A small decrease in efficiency will occur when operating at part load. This decrease in efficiency of part load opera- tion is small and has negligible effect on the accuracy of an energy study. Therefore, the peak generator efficiency is· generally used at all loads for energy estimates. When speed increasers are used to take advantage of generators which are smaller in physical size and of lower cost, the efficiency of the speed increaser is included in the generator equipment net efficiency. Commer- cial speed increasers are available in single· and double gear train de- sign. Each gear train has an efficiency of approximately 98.5 percent and is capable of increasing the speed up to a maximum ratio of 6:1. Synchonous generator speeds of either 900 or 1200 r/min are generally se- lected. The number of gear trains. required can be determined based on the turbine speed computed as indicated in this section entitled 11 Turbine Selection 11 • Auxiliary Equipment The energy lost from auxiliary equipment and part load operation of the generator is typically accounted for by applying a station efficiency of 98 percent to each generating unit of the power plant. Generator and Equipment Efficiency The generator and equipment efficiency is a combination of the generator and auxiliary equipment efficiencies. On the basis of the efficiency being 97 percent for the generator and 98 percent for the auxiliary equipment the generator and equipment efficiency is 95 percent when the generator is direct driven. Table 4-2 summarizes these efficiency values for direct driven generators and for conditions when using speed in- creasers. The hydraulic turbine efficiency is not included in these ef- ficiencies. 4-22 1 I I I I ·-l : I .. ' I I ! \ i I --' I i I , .. , I , i ! ·-- ) i l_ ·- I i L J I I \. ---- I I I I Net Plant Efficiency The net plant efficiency used in the power equation (3-2) is obtained by combining the turbine efficiency with the generator and equipment effi- ciency. For preliminary estimates of available power capacity it is us- ually sufficiently accurate to assume a turbine efficiency of 90 per- cent. This assumption results in an overall plant efficiency of 85 percent when the generator is direct driven by the hydraulic turbine. The use of speed increasers decrease the overall plant efficiency from 2 to 3 percent. ELECTRICAL SYSTEM Generators There are two types of alternating current generators, Synchronous and Induction, .available for indoor, outdoor and submerged service. A syn- chronous generator requires an exciter and a voltage regulator and is suitable for both isolated or large power systems. This type is avail- able through the power output range of this report. An induction generator does not require either an exciter or a voltage regulator, but must. be operated in conjunction with large power systems. Induction generators may be lower in cost than synchronous generators and are commerci.ally available up to capacities of 1.5MW at speeds of 900, 1200 and 1800 r/min. For capacities above 1.5 MW the induction generators are not necessarily less costly than the synchronous generators. When a cost evaluation is made between these two types of generators the lower power factor and efficiency of the induction generator normally prevents the induction generator from having a lower overall initial and operating cost. Normal generator voltage is 480 or 4160 V for small hydroelectric plants. When it is possible to use a gear driven generator operating at a syn- chronous speed of 900 r/min, or higher, it is often feasible to use a commercially available generator (of a type normally driven by an inter- nal combustion engine) for sizes of about 1 MW or lower. In this in- 4-23 stance, the generator must be capable of sustaining the run-away speed ,imposed· on it by the hydr·aul ic turbine. The voltage 1 evel on a generator of this type would normally be 480 volts. Motor starters utilizing molded-case circuit breakers which are available for 480 volt application can be used for generator protection on small units at a lower cost than other types of switchgear. Another type of generator is the direct current generator. · This type of generator may be particularly suitable to supply power directly to d-e motorized equipment. Alternately the generator output may be converted to a-c single or three phase power by use of static inverters. Excita- tion of the. rotor windings is usually taken from the generator output. This type of generator excluding inverter equipment is more expensive than both types of alternating current generator. Generator and Line Circuit Breakers Generator and 1 ine circuit breakers are the 1 ink that connects the generator to the power grid. The generator circuit breaker closing occurs when the unit is in synchronism with the power grid. These circuit breakers also act as an interrupting or tripping mechanism to disconnect the unit from the system when either an abnormal condition occurs or for a normal shutdown. Circuit breakers are classified by type, voltage class, continuous rated current and interrupting capacity. Types of circuit breakers include magnetic, air blast, gas, oil and vacuum and are indicative of the medium in which the electrical arc is extinguished. The connection to the line can be made with a group operated disconnect switch combined with high voltage fuses for multiple unit arrangements with a single step-up trans- former or a single unit plant with a generator breaker. A separate gen- erator breaker is required for each generator in a multiple unit plant. Some single unit plants eliminate the generator circuit breaker and con- nect the plant to the system with the line circuit breaker. When a line circuit breaker is used a back up source for station service power must 4-24 I I J . 1 I ~ I ·-J ,-, I i ,I l ' ' ! I . I i ',_< __ ) ' ' \.,_ ___ ; ' ' be added. See Figures 4-13 and 4-14 for a typical one-line diagrams of single-unit plants which illustrate the differences in the equipment. Generator circuit breakers for small hydroelectric installations are com- monly air blast or vacuum type, metal-clad units rated at 4.16 kV. The interrupting capacity is dependent on fault calculations which determine . system and generator contribution to a fault. Metal-clad units can be supplied with associated metering and instrument transformers. The line circuit breaker, where used, is located on the high voltage side of the step-up transformer in ·the switchyard. Vacuum and gas type are being installed more frequently due to decreased maintenance costs. How- ever, many utilities still standardize designs for small installations around the oil type unit. Standard voltage levels are 15,500, 38,000, 48,300, 72,500 and 121,000 volts. For the various types of breakers, control cabinets and consoles are available for the circuitry required to close and trip the breaker. Op- tions include relaying equipment and key interlocks. For small plants, in the 1 t~W or lower classification, it is feasible to use commercially available motor starters for the generator circuit breaker. The voltage level of this type circuit breaker would normally be 480 volts. Transformers The power transformer is a highly efficient device to step the voltage from generation level to transmission level. Efficiencies are generally in the range of 99 percent. For small hydroelectric installations, a single, two winding, oil-filled substation type transformer is used. The main tank is pressurized with nitrogen to, preserve the dielectric strength of the insulating oil. High and low pressure switches protect against failure of the gas cushion which also provides for temperature expansion of the oil. Connections to the transformer are insulated by 4-25 porcelain bushings, which may be supplied with current transformers for metering, relaying and instrumentation. Separate potential transformers are required. A terminal cabinet is located on the side of the transfor- mer for termination of auxiliary devices such as the sudden pressure relay, oil and windin~ over-temperature devices, pressure switches, cur- rent transformers, and cooling fans. The cooling system consists of fin- type radiators for convection cooling. To augment natural cooling (OA), fans (FA) or fans combined with oil circulating pumps (FOA) may be em- ployed. A further refinement of cooling can be accomplished with oil-to- water heat exchangers.. This method, however, requires that the coo 1 ers be operated at all times. The most economical application of trans- formers for the range of plant capacities in this report is to use OA transformers for the lower capacities and OA/FA transformers. above about 1 MW. The industry standard overload capacity for generators and transformers is different. To size the transformer, 115· percent of the generator rated kVA should equal 112 . percent of the transformer rated kVA. For multi unit plants, the total plant kVA should be used. Relaying Equipment and Surge Prote~tio~ An important part of hydroelectric plant operations deals with safety and protection. In particular, short circuits and ground faults within the p 1 ant must be man ito red and corrective action must be initiated to prevent injury to personnel or damage to equipment. The plant must be isolated from the line in the event of a line fault which is not cleared by utility equipment. Surge protection is required for the generator. This protection consists of capacitors and lightning arresters located as close to the generator terminals as possible to prevent insulation damage or flashing over on the generator windings. The breakdown voltage of the surge protection is well below the insulation level of the windings and effectively protects against induced overvoltages, potential rise in event of a fault, and lightning or switching surge overvoltages on the transmission line. 4-26 r-, ) I i l _____ _) L __ ) I I ! ! , ____ _) ! t ,--' i : i l_ ) ,- ! I ,---1 I ! I -) Protective relaying must be provided to immediately shut down the various equipment under fault conditions and for other abnormal events. The primary relaying for generators and transformers is differential relays which operate on an unbalance of the currents in and out of the protected equipment and are extremely high speed devices. Zones of protection of the relays for the generators and transformers sh~uld overlap. The gen- erators are also protected by overcurrent relays for each phase and neu- tral and by undervoltage and overvoltage relays. Phase and neutral relay contacts are generally paralleled to pick up an auxiliary relay for tripping of an associated circuit breaker. Less critical equipment such as auxiliary transformers do not warrant the expense of differential schemes and can be adequately protected by overcurrent relays. There is a difference in overall cost for a single unit plant with a gen- erator voltage metal-clad circuit breaker or with an oil type breaker at line voltage. The choice between them often results from a preference by the purchaser or the organization which will maintain the equipment. The basis for such preference may be based on similar equipment in the system or space requirements. At and below 15 kV, metal-clad units may also be used for line circuit breakers. The variety of equipment available within a narrow cost band permits a great deal of flexibility in meeting the needs of the owner and/or power purchaser. Switchyard The switchyard is comprised of line circuit breakers, if used, or fuses, disconnect switch, transformers, structures, bus~ork and miscellaneous power plant equipment. The arrangement of this equipment should allow for the future maintenance of circuit breakers and other major equipment with minimum effect on de-energizing buswork and other equipment. For single unit small hydroelectric installations, the switchyard will con- sist of the generator bus or cable, step-up transformer, a disconnect switch, a line circuit breaker or fuse and a take-off tower. Station transformers, excitation transformers, and surge and· metering cubicles may also be included in the switchyard to decrease floor space require- 4-27 ments in the powerhouse structure. Another alternate arrangement would have the metal-clad generator breakers located in the switchyard. A typical arrangement drawing for a single unit plant is shown in Figure 4-15. Multiple unit switchyards may be similarly arranged as long as electrical prote~tion and a means for isolation is provided for indi- vidual generators by use of generator breakers. Plants having capacities in the lower range of this report, up to about 1 MW, could conceivably have the switchyard reduced to a single guyed pole having both the lightning arresters and group operated switch pole mounted. The transformer, if required, could be either of the dry type and pad mounted inside the plant or an outdoor type pole mounted. The location of the switchyard with respect to the powerhouse is depend- ent on soil conditions, space requirements and topography. Where feasible, the best location of the switchyard is close to the powerhouse structure. This eliminates costly extension of the generator bus and re- duces power losses in the bus. TRANSMISSION LINES Transmission line voltage from the small hydro plant must be at the same voltage level as the transmission line voltage of the local distribution net work. Figure 4-16 indicates for several voltage levels the maximum distance a capacity may be transmitted based on loss criteria noted on the figure. MISCELLANEOUS POWER PLANT EQUIPMENT General Small hydroelectric installations are generally operated and monitored from a remote 1 ocat ion and therefore designed to house only the genera- tion equipment. Heating, ventilation and air conditioning are minimal and waste systems for personnel are normally not required. During 4-28 I I I "' __ ... ! I _I '-__ ) I t ~ ' i ~---' infrequent maintenance periods, bottled water and portable toilet facilities may be provided. The estimated costs for miscellaneous equipment contained in this report reflect minimum equipment for average site conditions and consist of the following: Ventilation A central blower located in the roof or walls with temperature control to actuate when ambient temperature rises above 74UF (23UC) is normally provided. Filtered air inlets near the floor at generator level are also included. l~ater System A duplex pump system with strainers, taking water from the tailrace, is provided for water-cooling requirements of the turbine/generator bearings. Water taken from the penstock can be used for backup. The cooling water system should operate independently of the plant generating equipment. Crane A permanent powerhouse. crane is not recommended for small hydroelectric plants. Due to size and cost of equipment, it is considered more econo- mical to bring in portable equipment for major plant overhauls. Provi- sions for a portable gantry crane for larger power plants may be provided if one could normally be available. This would include crane rails em- bedded in the generator deck and an electrical power connection. Appro- priate hatches should be provided for access for removing any equipment located below grade which may require removal for maintenance or replace- ment. Fire Protection A co 2 fire protection system is employed in the generator housing assem- bly and general plant area. The purpose of the generator co 2 system is to extinguish fires that occur within the generator hollsing .. A bank of cylinders for both initial and delayed discharge is actuated by co 2 ther- 4-29 mal switches. Portable extinguishers are positioned about the plant for use against a local fire. Water may be used in place of co 2, but re- quires that the generator be disconnected from the bus and the excitation system before the fire protection system is activated. A further advan- tage of co 2 is the fact that it is harmless to the insulation. A common physical configuration is a bank of cylinders against a wall with dis- charge headers and piping to the generator housing for the initial and delayed discharge systems. co 2 systems can only be used on installations where it is possible to contain the co 2 discharge. If the generator is air cooled, not air-to- water cooled, then a co 2 system can not be effectively used without having all exterior openings in the unit and building closed during the co 2 discharge. Water may be used for fire protection in this type of in- stallation. Small hydroelectric installations may not warrant automatic fire systems. Local hand-operated co 2 extinguishers may be sui tab 1 e. However, for un- attended plants the time lag involved because of non-automatic operation must be considered. If the co 2 system is automatic, then provisions have to be made to remove any discharged gas that may collect inside the powerhouse structure prior to any_entry by personnel. _Drainage A sump for collecting all drainage water within the powerhouse is con- structed at the lowest elevation within the powerhouse. It is customary to provide facilities for dewatering the draft tube. This requires piping from the lowest point of the draft tube invert to a drainage sump having a low water operating level lower than the draft tube invert. In addition either draft tube gates or stop logs at the end of the draft tube are required to isolate the draft tube from the tail race for dewatering. Electric driven sump pumps, automatically controlled by sump water level, remove the collected water and discharge it at an acceptable point. 4-30 ( J MULTI-UNIT POWER PLANTS .Differences and Similarities with Single-Unit Power Plants Except for overall physical size, there are only minor differences be- tween single unit and multiple unit power plants. If the design is on a unit basis, then the differences are mainly in the waterways and elec- trical separation of the units. Unit construction in a multi-unit plant implies that each generating unit has its own independent support systems and the failure of a required support system. on one unit will not affect any other generating unit. On very large hydroelectric units in a multi- unit powerhouse the concept of unit construction is generally followed, however, on small units represented in this report if possible all 8upport systems should be made common to all units. These systems involve oil, cooling water, compressed air, co 2 and d-e supply. Usually the lubricating oil requirements of these small units can best be handled by portable equipment for oil replacement and filtering. If sta- tionary equipment is to be used on multi-units, a common dirty oil sump, oil pump and filter are used with connections to all units. If the governors used are of the hydraulic type, then there can be a com- mon governor oil sump and accumulator for the multi -unit plant. If the units are small enough, less than 2MW, it may be possible to use an electric operated governor in which case the d-e supply system would be common to all units. On very small generating ·units that have the generator air cooled, the cooling' water requirements are minimal, being required only for bearing cooling. However, even though water is required for generator cooling, a common pump and manifold to all units minimizes the costs. A water sump common to all units with one set of sump pumps is used on a multi-unit plant. 4-31 . The compressed air system which is normally used only for braking and in some types of units, raising the rotor, can be manifolded to all units. Often the air for maintenance operation is the governing item in sizing the compressed air system. When co 2 is used for fire suppression in the generator, it is possible to manifold all the generator systems together using adequate thermal actua- ' ting valves. If this manifolding is not done, then the co 2 system for the multi-unit plant is the same as the single unit plant, namely, an independent system for each generator. The principal difference in waterways between single and multi-unit plants is in the penstock design. If each unit has a penstock, the de- sign for both single and multi-unit plant is the same·. When only o~.e penstock is used by more than a single unit, then a bifurcation in the penstock is required for each unit in a multi-unit plant. In addition, a shut-off valve is required upstream of each turbine, a requirement that may not be necessary in a single unit plant. Each unit in a multi-unit plant must have provisions for isolating the downstream side of the unit from the common tailrace. Normally single units have this same down- stream feature but with some designs it is not required. The one-line electrical diagram, Figures 4-13 and 4-14 for a single unit indicates a disconnect switch on the high side of the power transfor- mer. On multi-unit plants, unless each generator has a separate power transformer, there must be an electrically operated disconnect device between the generator and the common power transformer. STANDARDIZATION Standardization in a hydroelectric project is having items in conformity with a standard which may include items either of design or equipment. Design standardization is most usually accomplished in having features of the project interchangeable to decrease inventories, with a corresponding 4-32 : .. l cost savings. An example on a civil iteni could be use of a single slide gate for several openings where all openings do not have to be closed si- multaneously. Design standardization can include other features such as maintenance items like crane facilities for a portable crane which may be a common element to several closely-located powerhouses. Equipment standardization comprises use of commercially-available equip- ment items or identical equipment items either within a single plant or in more than one plant. Usually the basis for requiring an equipment item having special features is either it is believed the commercially- available counterpart does not have the required reliability, or perhaps the purchaser•s past practices need to be reviewed and modified to agree with the current commercial market availability. For small hydroelectric projects covered by this report, the generating unit capacity is normally small when compared to the power grid capacity to which it is connected. The loss of power by malfunctioning of the small unit is not critical to the power grid. Accordingly, the specifying of special features'·' in an equipment item to improve the item•s reliabilty is not justifiable, pro- viding the commercially-available items are manufactured by a company with proven quality and performance of its products. Equipment standardization within a plant can be accomplished by using identical equipment for identical or near-similar duties, even though the highest efficiency is not realized in all the systems. Standardization of the main generating unit can be accomplished only when turbine manu- facturers offer units which have been pre-engineered and all special pro- duction tooling is also available. In isolated cases, a modified stan- dardization of generating units is accomplished when either all units of a multiple-unit powerhouse are identical or more than one hydroelectric installation have identical hydraulic characteristics, making possible multiple use of the same generating unit. On small hydroelectric projects, it is advisable to use commercially- available items of good quality, modifying designs wherever feasible to 4-33 use identical equipment items either within one plant or between s~veral plants. The use of pre-engineered packaged generating units. should be used whenever possible. Standardization will decrease equipment costs, improve delivery time, and minimize spare parts inventory. Often spare parts need not be maintained if the project is located close to a reput- able supplier of commercial equipment. DAMS General The dams covered in this report could have a maximum height of about 65.6 feet (20m) but would normally be less. Due to the variability of condi- tions, it is not possible to standardize either the requirements or costs. Each site must be treated individually to evaluate its cost and effect on the project. Usually the development of a small hydro plant site will be proposed be- cause of the existence of some other facility which then provides the necessary head drop and sufficient water to generate energy in practical amounts. Frequently this will take the form of an existing dam built for other purposes or no longer used. While the elimination of extensive headworks is usually a significant factor in obtaining a project which is economically feasible, there may be situatio.ns where new dams or head works will be required or where an undeveloped stream will require a dam for its development. In many cases new headworks will take the form of simple low-head diver- sion dams. In some instances it may be feasible to build larger struc- tures which will provide some storage and streamflow regulation and ad- ditional head. However, as the plant size decreases, with a correspond- ing increase in the cost per kilowatt of the power features, there is a reduction in the amount of capital which can be used to construct the headworks and still obtain an economical project. 4-34 : l ',-J ) I I I I_ I The comp 1 ex i ty of the prob 1 em wi 11 depend on the type of dam proposed. Where this is a diversion dam it can be dimensioned from the simple hy- draulic requirements and there is little or no variation in the operating head due to fluctuation of the upper water level. The determination of project costs and outputs is therefore simplified. Where the dam is used for storage, and the water surface and discharges vary in consequence, the determination of the reservoir and dam size and the optimum power output for the project is then more complicated. With a diversion dam, the power p 1 ant wi 11 tend to operate under a re 1- atively constant head. This has the advantage that the turbine may be ab 1 e to operate within a sma 11 head range about the design head, at which the efficiency is highest. A disadvantage, however, is that the turbine may have to operate as a 1 run-of-river 1 plant which can result in a loss of power when flows are too low to permit safe operation of the turbine (about 30% of its design discharge). Where the dam will permit some variation of its water level, yet still satisfy the downstream water users, the reservoir, even if small, may permit daily storage of low flows for intermittent hourly use at a dis- charge rate which can be utilized by the turbine. This, of course, can only be done if the variable turbine discharge is acceptable in meeting the requirements of users downstream. Within the head range and unit capacity considered herein, it will be rarely that any dam can provide long term storage.. However, even a re- servoir used only for daily or seasonal pondage may experience a large variation in the operating head. This could in some cases mean that water used for purposes other than energy generation will have to be dis- charged at heads which lie outside the operating range of the turbine, resulting in a loss of power. A careful selection of the design head must then be made to maximize the power output. 4-35 The inability to generate energy whether as a result of the occurrence of flows or heads, which lie outside the operating range of the turbine, can result not only in a loss of potential energy, but also in the inability to assign any dependable capacity to the plant. The energy thus gener- ated is, in terms of the marketplace, of a lo~t1er quality and lesser value than woulcj otherwise be the case. Selection of the plant capacity, de- sign head and the number of units should endeavor, therefore, to overcome the above factors as far as possible. At diversion dams, the silt content of the streamflow is liable to be higher than at dams with a significant reservoir volume and result in either higher maintenance or the need for special desilting facilities in extreme cases. A factor to be considered is the sediment content of the watercourse. In storage dams the effect of heavy sediment content is to reduce the effective vo 1 ume and therefore the project output. Mai nten- ance of the power facilities may be improved due to reduction in the sediment content in the power flow. With a diversion dam, it may be necessary to provide means of dischar.ging the sediment to maintain the usefulness of the dam. In some instances existing dams may have been built to serve a power plant, since discontinued or of a smaller capacity than could now be ec- onomically justified. In these cases the layout of a new installation may simply follow that of the original scheme, or conversely require some new approach because of space limitations imposed by the old plant. In most instances, however, the dam wi 11 have been provided to store, regulate or simply divert water for other purposes, and some modification of the dam or outlets will be required to permit installation of the power waterways, or to optimize the head for power generation. This may require review of the manner in which flows are regulated or discharged in order to optimize the various water uses. Frequently the existing uses will take precedence and power will then be generated as a secondary function. 4-36 ., I. ---1 '_ --~ --- ' '--I --, : : I ' ' ' I The use of an existing dam will require study to determine the most ad- vantageous location for the power intake and waterways, and if these may replace or be combined with the existing outlet facilities. This will entail study of the discharge requirements for the existing facilities, the technical problems involved with removal or combination of facilities and the needs for the continuing satisfactory operation and ma_intenance. The provisions for demolition and replacement of the affected portions of the old structures must be reviewed both with respect to the safety of the structure and to the need to continue operation of the existing fa- cilities during construction. If possible the renovation work can be carried out at time when the current water use is seasonally suspended or reduced. Such reductions, as with irrigation uses, however, may occur in the winter when .construction may be more difficult or expensive, and a fewer number of effective working days. Dam Safety Considerations The construction or operation of a dam, new or old, implies the need to consider not only the integrity of the facility to function properly, _but also its effect on people and property downstream. Public Law 92-367, 1972, authorizing the Secretary of the Army, to underake a program of in- spection of dams applies to all dams 25 feet (7.6m) or more in height or impounding more than 50 acre feet (61,700 m3) of water. Excluded are dams less than 6 feet (1.8m) in height or storing less than 15 acre feet (18,500 m3), regardless of height. Similar classifications are used by some· State Authorities. Any proposed dam construct ion should therefore meet the applicable requirements of Federal or State authorities. Never- theless the responsibility of safety will lie with the owner of the dam, regardless of its size. The dam should be constructed to accepted stan- dards of safety. 4-37 The initial design should include consideration of the following factors: 1) Stability and permeability of areas to· be inundated by reservoir. 2) A determination of how the reservoir will be operated in normal and exceptional conditions; and the range of heads operating on the dam. This will include provisions for filling, drawing down, and in some cases emp- tying, the reservoir. 3) An appraisal of the effect of the operations, normal and extreme, on the areas downstream. 4) Adequate spillway capacity. 5) A knowledge of the dam foundation conditions commensurate with the height of the dam or reservoir volume. This will include permeability, strength and deformation characteristics and the possibility of the exis- tence of faults or seismic activity. 6) A knowledge of the characteristics of the materials of which the dam is composed, and an adequate analysis of the stability of the dam, and its foundations under various operating conditions, normal and extreme. Extreme operating conditions should include seismic activity. 7) A safe and practical arrangement of the operating mechanisms, such as gates, valves and conduits, to permit discharge or retention of water in the manner intended, for all operating ~onditions, normal or extreme, and appropriate for the type of dam used. 8) Adequate access to the site at all times especially in times of flood. 4-38 : 1 --' fl 'J : l , I ll :_I . , 1-j I I . I ,,_1 ' ' ! ... J . I I 0 •..__ _ _, Other factors of a more detai 1 ed nature, for example communication ·and monitoring systems and further safety studies may ultimately be required but are usually not significant in the early planning stages. NEW DJlMS General A new dam may be either a diversion dam or a storage dam. For dams less than 65.6 feet (20m) in height, it will be difficult to find sites that could provide long term storage. However, even the smaller volumes that can be achieved, may produce significant benefits in improving both the quality and the amount of povo~er generated. In rivers with steep gradi- ents especially, the small storage volumes possible would seldom justify construction of a dam for storage or regulation. Since any increase in head resulting from the dam will produce additional power, in general, the incremental cost Of raising the dam should be con- sidered in relation to the value of the extra power generated. However, in the head and power range considered, it will probably be difficult to justify increasing the dam height beyond that required to divert the streamflows or to provide short term pondage . The design of dams above 25 feet (7.6m) in height have to comply with the requirements of Dam Safety of the Federal and some State Agencies. Their design and construction must be accomplished with care. However, even the smaller dams should meet rational safety requirements. A reference for designs of such structures is published by the WPRS [5]. All dams must be designed to pass the design floods. for that site and usually to provide for temporary diversion of the streamflows during con- struction. As the flood flows to be designed for increase in magnitude the spillway and diversion features become of greater significance and can become a major part of the total cost even when the proposed dam height is relatively low. 4-39 The spillway and divers ion requirements and the found at ion characteri s- ties should be evaluated early in the study since, in locating the dam, the site with the minimum apparent dam volume may not, after inclusion of the other features, be the one having the lowest total cost. The provision of a new reservoir will probably entail consideration of its use for other purposes especially recreation. The effects of the re- tention of water by the reservoir on water quality and fish life will also have to be considered. This frequently results in additional costs for mitigation facilities or a loss of power due to the need for special downstream releases of water. The inclusion of additional uses such as recreation may, however, produce benefits to the project which may add significantly to its acceptability. Dam Types The dam can be one of the following types: 1. Embankment: o Homogeneous earthfill, with drains o Zoned earth fill with impervious core; or o Rockfill with impervious core, or concrete face 2. Concrete: o Gravity o Arch o Slab and buttress; or o Hollow gravity The selection of the best type of dam for a particular site calls for thorough consideration of the characteristics of each type~ as related to the physical features of the site and the adaptation to the purposes the dam is supposed to serve, as well as economy, safety, and other pertinent limitations. Usually, the greatest single factor determining the final choice of type of dam will be the cost of 4-40 ' r ' I I _, l , ___ j c.,_ __ / ' ' construction. The following discuss important physical factors in the choice of type of dam. (1) Topography, in large measure, dictates the first choice.-of type of dam. A narrow stream flowing between high, rocky walls would naturally suggest a concrete arch dam with a separate spilling. The low, rolling plains country would suggest an earthfill dam with a separate spillway. For intermediate conditions, other considerations take on more importance, but the general principal of satisfactory conformity to natural conditions is a safe primary guide. (2) Foundation conditions depend upon the geological character and thickness of the strata which are to carry the weight of the dam, their inclination, permeability, and relation to underlying strata, existing faults, and fissures. The different foundations commonly encountered are briefly discussed below: (a) Solid rock foundations~ because of relatively high bearing power and resistance to erosion and percola- tion; offer few restrictions as to the type of dam that can be built upon them. Economy of materials or overall cost will be the ruling factor. (b) Gravel foundations, if well compacted, are suitable for earthfill, rockfill, and low concrete gravity dams .. (c) Silt or fine sand foundations can be used for the support of low concrete gravity dams and earthfill dams if properly designed. 4-41 (d) Clay foundations can be used for the support of earthfill dams but require special treatment. (e) Nonuniform foundations. Situations may occur where a nonuniform found at ion of rock and soft material must be used if the dam is to be built. Such unsatis- factory conditions can often be overcome by special design features. For embankment dams, tre zoned earth fill or rockfill dam with an imper- vious core would normal Ty be. preferred for the higher dams if the re- quired materials can be found within reasonable haul distance. If ne- cessary, or for low diversion dams, homogeneous earth fill dams are acceptable. The concrete face dam would normally only be used where im- pervious material could not be obtained, however, for the small quantity of material required for dams of reference, it will usually be possible to find impervious material. For dams below about 20 ft. (6.1 m) in height, and where the flow condi- tions are not too severe, consideration should be given to alternatives to the above standard types with a view to reducing the cost and bringing the project into the range of economic feasibility. This could include use of reinforced rockfill, to permit overtopping; plastic, asphalt, or steel plate as impervious membranes; and inflatable fabric dams:, while crib or wooden dams of the types used earlier in the century may have merit, provided they are examined on. a life-cycle basis. These alterna- tive means for increasing the dams effective height should only be used for projects where failure of their portion of the dam 1-'/0uld not be disasterous to the area downstream of the dam. Spillways Spillways are necessary to convey flood water safely around or over the dam. Inadequate spillway capacity and design are the most frequent cause of failure of small dams. Since the spillway size is dependent on the 4-42 -, I . ~, I _J \-_) ~-' I t ___ .. expected floods, a primary concern is the magnitude of this flood. For the larger dams where downstream safety· is paramount, the design flood should be the probable maximum flood. For smaller diversion dams a lesser flood may possibly be used to dimension the spillway,. provided that larger floods can be passed safely, even if major damage should re- sult to the proje·ct structures. The spillway may be located either on the dam itself,· as in the overflow monoliths of a concrete dam; as a chute discharging around the abutment of an embankment dam; or, if the topography is favorable; into a neigh- boring water course. For smaller dams the spillways will probably be ungated. It may, how- ever, be advantageous to use radial gates for larger dams; in cases where the water course is narrow or the floods are large; or in low dams, where there is a significant sediment load at flood stages. An important and sometimes costly feature of the spillway is the energy dissipating structure. The requirements and costs for this can vary from minimal for low-head dams on sound rock to very large for a properly de- signed stilling basin with high head and an erodible foundation. Foundations The evaluation of the proposed dam foundation is a key element in deter- mining its feasibility. An appraisal of the foundation must determine its suitability to sustain any type of dam proposed,. its permeability and, importantly, the amount of excavation necessary to reach a firm base for the dam. With low dams the depth of excavation can ·have a si_gnificant effect on the dam volume. The use of foundation grouting and drainage, and foundation cut-offs should be included as necessary. 4-43 Where the dam is to be founded on sound rock, visible at the surface, the early appraisal may be rather simple. If not, subsurface investigation may be required as the conditions prevailing and accuracy of the study may warrant. Where an embankment dam is to rest on earth materials the embankment slopes and type may be governed by the character of the foun- dation material rather than by the type of materials available for the embankment. For dams in the lower range of height, it may, not uncom- monly, be found necessary to utilize sites having a considerable depth of pervious alluvium as the foundation material. Such sites require special care in pro vi ding for seepage contra l, uplift pressures~ settlement and downstream erosion, but are not necessarily to be discarded for these reasons, unless shown to be too costly. Access The need for access to the dam site should be studied, especially if the dam is to be located in a narrow valley where roadway excavation is dif- ficult. The access routes should be plan ned for several purposes, the requirements for which are different, namely a) to permit access during construction, b) to permit access for permanent maintenance and c) to permit use by the public for recreation. Each type of access must con- sider the type of flood conditions which may occur at the times that ac- cess is required. The criteria for the road design may vary according to the above needs, or different routes may be selected for different pur- poses. It wi 11 usually be essential that access to the dam should be possible during times of flood or other emergency, especially where gates or valves have to be operated. Care of Water During Construction In order to construct the dam, the existing river flows must be. diverted safely away from the work area. This is usually accomplished by con- structing the dam in stages, planned to suit the seasonal variation of the stream flows. Where the flows are low, diversion can be acomplished readily by small earth cofferdams, and pipes or flumes. Where flows are 1 arge a tunnel or concrete conduit may be necessary and the cofferdam 4-44 .---, I ~ _) ' L ~ I -J • J . r ' ---' ~, J ! ' ! ~, I -1 I '-_.) f \ ___ J ' c ' '·-_j ( --. : -} height raised to provide flood storage and increase the operating head on the diversion outlet. The flows to be passed by the diversion waterways must be determined as part of the hydrology study. Customarily the design flood used to dimen- sion the diversion works is that having a return frequency of occurrence of once in 10 years or once in 25 years, depending on an assessment of the consequence of its being exceeded. Where a high embankment dam, with significant reservoir storage is subject to the risk of overtopping for a long period of time, use of a larger design flood (i.e., lower frequency of occurrence) may be advisable. The construction sequence is planned to utilize the low flow season as far as possible, and the works are de- signed for flood frequencies appropriate to the seasons during which they are used. Where concrete dams are used, gaps or conduits can be provided in some of the dam mono 1 iths to temporarily pass the flows. For embank- ment dams, where the diversion works may be more expensive, the feasibil- ity of passing flood flows over a portion of the partially completed em- bankment may be considered, provided the embankment is suitably rein- forced or protected. Allowance must also be made in the diversion scheme for any deep excava- tions that may be required for the foundations of the dam especially where the material excavation is permeable or likely to be unstable. REHABILITATION OF EXISTING DAMS In utilizing an existing dam, consideration must be given to its current physical condition: If the dam is old it may have been constructed to criteria or using methods that are no longer acceptable. In addition, the materials used may be subject to deterioration, which would affect the useful 1 ife and require rehabil it at ion of the dam, before further in- vestment is made in the power facilities. Consideration should be given to such factors as cracked or deteriorating concrete, seepage and the lo- cation of the seepage, slumps in embankments or foundations, the types of 4-45 materials used in the dam, or discharge facilities, and the operating status and suitability of the discharge facilities. Since the dam may have been developed in stages, the materials used in earlier stages may not be apparent without recourse to the early construction drawings or site investigation. Such factors must be reviewed against any new opera- ting conditions which may be imposed by the proposed power facilities. A review of the current operating procedures and water levels should also be made, since the· original concepts may have been modified to satisfy some condition or deficiency which may have developed during the life of the dam. Where consideration is given to raising the operating heads, the dam foundations and abutments must be reviewed to ensure that the stabil- ity, permeability and uplift pressures are acceptable. The inclusion of an existing dam in a project even when only minor changes are proposed to the dam may require that the dam be included within an FERC license. This may entail analysis of the dam safety and could require that the reservoir be utilized for recreational purposes not already included, or the provision of new facilities for fish en- han.cement. The facilities may also then be subject to the recapture re- quirements of the Federal Power Act when the license expires after 50 years. WATERWAYS General The purpose of the waterways or conveyance structures is to convey the water from the reservoir to the turbine or to convey the water in a by- pass around the turbine when it is inoperative and there is a downstream water requirement. Waterways usually consist of an intake; conveying conduit or canal, control structures such as valves or gates and in the case of a bypass around the turbine, and an energy dissipating device. 4-46 , ... --\ ' -· _.) ! , I j , __ .) I ,__ __ . -----1 (I u n L_) 0 (" . I ;~ Intake and Trashrack The purpose of an intake is to control the flow of water into. a penstock or water conduit. The intake contains racks which prohibit debris, and in cold climates ice, from entering the water passageway and ultimately damaging the hydraulic turbine. Gates are also located in the intake which can control the water flow (generally only to stop the flow) and special designs may be used to modulate the flow. For small low-head projects applicable to this report, the intake will usually be on the face of the dam. However, if there is open channel flow downstream of the initial intake, then a second intake is required at the powerhouse. The flow ·velocity. into the intake, through the trashracks and gate open- ings, must be low enough that the headloss is not a significant item on the ·low headplants but still high enough that the structure is an ecnomical design. Net velocities from 2 to 3 ft/sec (0.6 to 0.9 m/s) are acceptable. These low velocities will allow some clogging of the trashrack as much as 50 percent and not materially decrease the head on the turbine. The in- take shape should allow a gradual increase in water velocity from the trashracks to the entrance of the penstock or water conduit. There should be no sharp edges in the flow path or sudden enlargements or ex- pansion. Gradual transitions will eliminate eddies. Th.e bottom of the intake should be at an elevation that silt will not deposit on the bottom gate slot. The shallower the intake invert, the less travel there will be for the shut-off gates and the lifting of the trashracks. Trashracks for these small intakes should be sloped to assist the rakes in· cleaning the racks of debris. The bar spacing should be close enough to restrict the passage of any object that might not safely pass through the turbine. The racks should be designed for an unbalanced head of 10 to 20ft (3 to 6.1 m) which permits some clogging of the screen without having structural damage. If the racks are in an area subject to large 4-47 amounts of debris, then the racks should be designed for complete stop- page and the full head used for the rack design. If the gates· at the intake are used for emergency closure, then provi- sions must be made downstream of the gates for air admission to the water conduit. Air may be admitted through a ga~e shaft, vent or automatic valves of the vacuum breaker type, dependent upon the arrangement of the intake gates and location of the powerhouse with respect to the intake. For intakes where ice formation may be a problem, it may be required to include electric heating in the gate slots to insure the gates may be closed at any time. Also, compressed air may be used to keep ice free from the trashrack by use of a bubb 1 er system at the base of the trashracks and upstream of the racks to break up the ice and allow its removal. For design details on treatment of ice formations, refer tore- ference [6] Penstock The penstock is. the water conduit which is under pressure and conveys the water to the turbine. Normally the penstock is made of steel but it can be constructed of concrete, wood or can even be a pressure tunnel termin- ating at the powerhouse. Steel is the most common material used in penstocks· and for high oper- ating heads (heads beyond the limit of thi~ report) is perhaps the only material in use. The design of steel penstocks is cover,ed in reference [7] to which the reader is referred for design information. Reinforced concrete pipe or cast in place concrete conduit can be used for penstocks in the head range represented by this report. The advan- tages of concrete pipe is its long life and low maintenance. It is pos- sible to either cast the concrete pipe· in place or have it precast. The joints in the precast pipe have to be not only watertight, but flexible enough to allow for some expansion, contraction and settlement. The 4-48 '__j ' -.J ----J --, ' _ _j I --j .~1 I ---. i I ', ---_j r-- I ·~.._) ,_, 0 --1 ~, \ I , __ ) I '------' ' ;'-' ~. ~ joints of the bell and spigot type with fitted rubber gaskets have proven satisfactory. Friction factors for determining head loss in concrete pipe for use in equation (3-4) are given in reference L8J. Design data on concrete penstocks is in reference [6]. Penstocks have been made of wood-stave pipe for size of projects repre- sented by this report. An advantage of wood-stave pipe penstock is the ease of construction for remote and inacce·ssible areas. There are dis- advantages in that the pipe must always be kept wet and under a moderate pressure to preserve the wood. Drying out of the wood leads to leaks and rotting of the wood. The wood-stave pipe is banded with steel wire or flat steel bands. Method of designing wood-stave pipe penstocks is given in reference [6] and friction factors for calculation of head loss in reference [8]. Regardless of the material used for the penstock, the effects of water hammer must be considered in the penstock design. Water hammer is a change in the internal pressure, either above or below the normal -pres- sure, which is caused by a sudden change in the rate of water flow. Any sudden load change in the turbine/generator can change the water demand and water hammer will occur in the water conduit from the turbine to the forebay. If the turbine gates close rapidly, a positive water hammer pressure is produced. The use of a relief valve at the turbine which permits bypassing water on a rapid closing of the turbine gates can les- sen the water hammer pressure and the i.nitial change in water flow can be held to a minimum. Under some conditions, it is possible to decrease the closing time of the turbine wicket gates and allow some overspeed of the turbine/ generator, assuming the generator has been disconnected from the power grid, to decrease the magnitude of the initial positive water ham- mer. A sudden increase in demand of flowing water will set up an initial negative water hammer and this must be reviewed to determine if any of the penstock wi 11 be under a vacuum. The reader is referred to refer- ences [6], [7] and [9J for design information concerning water hammer. 4-49 Valves and Gates Under normal operating conditions the flow of water through the turbine is controlled by either, the turbine wicket gates or by the adjustable blading of the turbine runner. If load regulation by the unit is not required, then there can be a saving in project costs by not equipping the hydraulic turbine with wicket gates or having an adjustable blade runner. However, a valve or gate must be placed ahead of the turbine to control the water flow while the unit is in the st?rt-up phase. After being synchronized to the line the fl9w control device is placed in a wide open position. A flow con- trol device of this type must be equipped with automatic controls which will place the device in a closed position whenever a turbine overspeed condition exists. Whenever the turbine is not in operation, the project requirements may necessitate that water be released from the pondage. Dependent upon the project configuration, the release of the impounded water may require that its energy be dissipated by some device. In the low head range of this report, this energy may be dissipated by special gates or a fixed cone valve. The gate may be either a jet-flow gate of the WPRS design or a standard slide gate that has been designed for this type of use. The fixed cone valve is a commercially available valve, made by several manu- facturers, and known as a 11 Howell-Bunger 11 valve. Satisfactory perfor- mance of this valve requires experience in the design of its installa- tion. At low-heads, valve vibration should not be a problem. It is necessary to have some type of closure device in the water conduit ahead of the turbine not only for safety reasons but also to do that maintenance work which must be done with the turbine in the dry condi- tion. The type of closure device used is influenced by the project con- figuration, head and economics. Valves of the ball, plug or butterfly type or whee 1-mounted gates may a 11 be used. Norma 11 y for the 1 ow-head application of this report, the ball or plug type valves are not competi- 4-50 --, ; -, I ' ' l ___ ! I I r - ; -~ r I c- ,--\ . __ , i. 1,_ ~--; tive and only the butterfly valve is considered unless there is open channel flow which would allow the use of a slide gate. When a bifurca- tion is used for multiple turbine installations, a butterfly valve is placed ahead of each turbine. None of these closure devices are normally used for flow modulation and their usual use is in either the fully open or fully closed position. Bypassing Many of the small lo1t1-head hydro projects wi 11 have some commitment of water usage that must be met regardless of power production. Water con- tracts may exist wherein specified water deliveries must be met regard- less of power production. Under these conditions, provisions must be built into the project that wi 11 allow water to bypass the plant when power is not being produced. There are always times when the turbine/generator will not be operating, such as minor and major overhaul periods, operating head on the plant too low (especially for the low-head plants represented by this-report) and system problems in the connecting power grid. Bypassing water around the turbine/ generator unit must be done upstream of the powerhouse in order to permit maintenance on the turbine/generator which at times must be accomp 1 i shed with the turbine/ generator off the 1 i ne. Dependent upon the project design, the bypassing may be accomplished in the region where the penstock connects to the water source or may be immediately upstream of the powerhouse. If the bypas-. sing is adjacent to the powerhouse, then the design head will have to be dissipated prior to being released to the tailrace. The energy may be dissipated. with a hollow-jet valve, "Hewell-Bunger valve or jet-flow ga~es. Use of a Howell-,Bunger valve may require special treatment for handling the jet produced by the valve. If bank erosion will result from the jet of the Hewell-Bunger valve-, then the valve must be discharged into a chamber which is equipped with baffles and restricts the jet action. Often model tests are made of~ the valve chamber design if previous design data are not available . 4-51 TAILRACE The tajlrace is the water channel that transports the water discharged from the turbine to a reservoir, canal or river. Some canal installa- tions may have the turbine discharge directly into another section of the canal, thus eliminating the tailrace. All reaction turbines must have the turbine draft tube outlet at all times submerged a minimum of 1 ft. (0.3 m} while in operation in order to use the available _head represented by the tailwater elevation. This establishes the minimum tailwater ele- vation for satisfactory turbi.ne operation. The criteria for setting the elevation of the turbine runner with respect to the tailwater is given in this Section (Turbine Setting). If the tailrace is to terminate in a river or streambed,. it is advisable to determine the maximum and minimum surface elevation of the river or stream at the powerhouse site. At high river flows, the po~erhouse site may require special flood protection. Also at times the water level may be high enough that the head on the turbine is at a value which is. out- side the operating limits of the turbine. Backwater curves may have to be prepared to determine these critical elevations. Often local obstruc- tions in the river will have to be removed or the river widened to obtain satisfactory water surface elevations at the powerhouse. On critical sites, a model study may be required. Usually the bottom of the draft tube will be below the river invert. The tail race ch anne 1 from the powerhouse should slope up 1 to 6 (one vertical, six horizontal). Steeper slopes ·may permit rocks and debris to collect in the draft tube. To have the slope flatter can result in an unnecessarily long tailrace channel. Adjacent to the powerhouse, the tailrace channel invert ·slope can be as steep as 1 to 4. When the backwater curve indicates that on low river flows the turbine draft tube would not be submerged, ·then a weir must be built in the tailrace channel to insure the required submergence during these low flow conditions . . II 4-52 ---, I --; / ' \ I .-~ .... I I _j l I j ---~ ' I I I ·--' .--; I \ -·--., I i I _j I j -1 ·-_) ,-' L-- ~~ -~ I I ) _ ___] ! '-' i i ~-_; ! l L_ - ,-----, I ~ ; r ---. ~---! I ,_' ,-, I I l \ __ ....) r-· , I l ' ----' I l __ ,---.. ' r I "--~' \._ ___ ) '· ' --' ' \,_ __ ) When the tailrace discharges into a reservoir, the same careful review of the water surface elevation noted above must be made. Obviously, the maximum surface elevation of the water reservoir is known and the effect on the turbine head easily determined. It is necessary to determine if a weir must be placed in the tailrace to insure the turbine can be operated at low reservoir elevations. SITE DEVELOPMENT Genera 1 Site development for a small hydroelectric development involves the mod- ification of the existing terrain and results in changes in both the to- pography (cuts and fills), and in the natural or existing drainage pat- tern. This section describes the items that need to be considered in the evaluation of the site preparation activity. The technical design is considered in this section. Drainage and Erosion Control The construction of a new hydroelectric facility usually involves changes in both the topography and the drainage patterns of the project area, \vhich in turn may .result in the accumulation, at specific locations, of excessive surface and/or subsurface water. Drainage -design varies from project to project, and cannot be generalized as to the best method to be used. However, a combination of proper grading plus a system of collec- tion points (catch basins) is generally the most effective method for re- moval of surface water. Removal of ground water requires the design of an underground drainage system, which will include a network of subdrains for the collection of subsurface water. The subdrain network would be connected to main collector or the surface water collection system. Proper grading should prevent accumulation of water at any location with- in the project area. However, if-water flows over the side slopes. of cuts or fills, erosion can become a problem. The effect of the water that flows directly over the'slope can be minimized by sodding or terrae- 4-53 ing. If, because of the nature of the cut or fill, none of these solu- tions is applicable, it is often possible to divert water by means of a ditch (in cut) or a berm (in fill) along the top of the slope, with a pipe spillway arrangement at specific locations for the discharge of sur- face runoff over the slope. Access Roads Access to the project area is an importarit feature of project planning, both for construction and for operation. Existing impoundments are pro- vided with access to locations where existing structures are located (i.e., dam, intake, spillway, energy dissipater). When planning a hydro- electric addition at an existing impoundment, use can be made of existing access to serve the new facility if appr.opri ate or a new access can be developed as r,equired. An existing access road may require upgrading before being used for construction access. In either case, since hydroelectric developments often involve the transportation of large and heavy pieces of equipment, certain minimum standards for access roads need to be set. Standards for access roads are given in Table 4-3. Bridges on existing roads may be restrictive as to the size and weight of equipment that can be transported across them, and could result in addi- tional handling and equipment assembly costs. Any new bridges which may be required should be designed to adequately accommodate future construc- tion and equipment loads. Parking and Miscellaneous Site Features Site preparation for small hydroelectric installations involves the de- sign of various related features, such as parking a~eas, equipment erec- tion area, fencing, and landscaping. Depending on the size of the proj- ect, the equipment erection area may be converted into a parking area after all equipment installation is completed. Whether one area serves both purposes, Dr a different area is assigned for each purpose, the main consideration in the layout of the facility is the relative location of each with respect to the area to be served. The erection area must be 4-54 .-' / L __ ! r--- I -- J '--_r I .... __ .._) r --~ i i ' I l ___ ) I ! L.. -~--' .---~ I . I l ____ j r-\ -J r ' ' I L...--J ,---, I : i I L __ _j .---, I '-I located so that the equipment may be moved easily to the installed loca- tion. Consideration should also be given to the dimensions of the area which will depend on the expected use (number and type of vehicles to be parked, and size of equipment to be erected). The paving for the parking and equipment erection area is generally two inch (51 rrrn) asphalt con- crete pavement and four inch ( 102 mm) each of base and subbase. Fencing is provided to protect the project facilities from vandalism and the public from accidents. The fence is usually a chain link type fence 8 feet (2.4 m) high with a one foot (30 em) extension arm. Preserving the natural characteristics of the project area is of import- ance. Consequently, the area should be landscaped in an ·attempt to re- store the original vegetative condition. Environmental Controls During Construction Environmental problems associated with small hydroelectric projects dur- ing construction are generally minor. However, they involve the following types of events: o Removal of vegetation, disposal of spoil and change of the land form by grading to provide access roads and level areas for the powerhouse, switchyard and parking areas o Noise and dust created by construction activities including blast- ing. These disturb recreation areas which may be near the site o Temporary disturbance of the stream caused by building in the streambed, which may result in temporary increase in stream .turbid- ity. Construction may also require an interruption to releases, which could affect aquatic wi 1 dl ife and downstream users; and 4-55 o The long-term commitment of 1 and and part of the streambed for project facilities, thereby preempting use of the area as 11 Wildlife habitat 11 • TYPICAL LAYOUTS Genera 1 Typical layouts have been made of powerhouses using the turbine types previously discussed in this section. The powerhouse layouts are typical for both single and two unit powerhouses with the latter indicating the additional structure required for a multiple unit installation. These layouts indicate the major equipment items used and their relative loca- tion. Representative sizes of the equipment items is given in Appendix (Page C). It is possible that all of the equipment shown will not be used in some powerhouses. As an example, the owner may elect, due to either the small unit size or the difficulty and expense of containing the co 2 discharge, not to install a co 2 system. Although each layout indicates the use of a specific type turbine the structure in some cases, for the level of detail presented and the pur- poses of this report, could be identical for one or more type turbines. However, there would be a cost difference in these instances principally in the equipment costs presented in Section 5. The following are exam- ples of these similarities: (1) the vertical propeller unit layout is typical for both the fiXed blade propeller and Kaplan type units, (2) the open flume Francis unit layout is typical for both the open and closed flume Francis and propeller type units (3) the tubular turbine layouts are typical for both the adjustable blade and fixed blade propeller units, (4) the bulb turbine layout is typical for both the bulb and rim type turbines. Whenever the powerhouse becomes an integral part of a water canal there are instances where the powerhouse structure must inc 1 ude water passage- ways to bypass the flow in event flow is required either when there is a 4-56 ', I .--~ ', __ _) r· -; ! '-J I L ___ I I I L _ _) (-1, i ! ·-~ _) ' -) I I L _ _} I 1 '-' ' i •._-_J unit outage or the flow is not within the operating range of the hy- draulic · turbine. Layouts are included with and without this bypass structure. Layouts for the tubu 1 ar turbine powerhouse inc 1 ude both the use of a penstock and the inclusion of a headworks with the powerhouse structure. During the early planning stage there is often a multiple selection of types of hydraulic turbines that may be used on a given project. The type which will be used-is not selected until all operational studies ·and cost estimates have been completed. To illustrate this condition, proj- ect layouts are included showing the use of several turbine types for the same project. Typical detailed data on some equipment items not shown cin the layouts are given in Appendix (Page C). For the purpose of clarification the most common types of small hydro de- velopment have been classified for use in this report as described below. The various types are also summarized in Figure 4-17. Type A -Canal Drop Layout This type of development will usually occur where an existing canal con- tains a drop structure dissipating the head. Operation of the canal small hydro system ~ill normally require some form of coordinated control over the canal intake gates in order to meet both the small hydro and the previously existing water demands. Canal spillways may also be needed to handle the flow when there is a small hydro full load -rejection. No un- usual diff~culties should be encountered in constructing the project but special provision may have to be made if the canal cannot be dewatered during construction. A short penstock may require a butterfly valve just upstream of the unit and a slide gate in the intake structure. A long penstock or multiple units operating from one .penstock require both the intake slide gate and the butterfly valve for each unit to provide ade~ 4-57 quate security and to ensure that energy can be generated when one unit is down for maintenance. Type B -Concrete Dam Layout A small hydro development of this type may be constructed downstream of a new or existing concrete arch, gravity, or buttress dam. Where the dam already exists the cost of development will normally be reduced by utilizing an existing outlet works conduit as part of the penstock. Connection to an existing outlet works conduit can usually be completed without incurring maj~r costs: Construction of the powerhouse in· most locations requires that the area be cofferdammed off to a level that provides adequate protection against flooding. Type C -Earthfill Dam Layout This type of development is similar to Type B in that the utilization of an existing outlet works conduit could reduce the project cost. Many earthfill dam outlet works, however, have the outlet reg~lating valve lo- cation near the centerline of the dam cross-section with the downstream section of the conduit unpressurized and free flowing. This arrangement requires a new section of penstock to be placed inside the existing conduit downstream of the regulating valve. Where the existing valve is smaller than would be desirable for po~tJer production this too must be ~eplaced. Construction of the powerhouse is similar to that required for Type B. Type D -Weir Type Layout A development of this type will usually require the construction of the combined dam and powerhouse structure. A spillway structure will a 1 so be required unless some form of spillway already exists or flood flows are controlled upstream. A major item in the construction of this type of plant is the cofferdam and dewatering of the foundation. It may be that for small plants some form of pre-fabrication may be both feasible and economical. 4-58 r ' ' -, ! ' ' j I . ·' :-l I j --~ "'I ! I . .I --i J I. --· L __ J ' l • i ' ) i ' I 1 I . , __ .,.. -' -' l --.. . .. , ( --. , I Type E -Existing Power Plant The scope of the work required to refurbish an existing power plant will vary widely. At a minimum it will usually require the installation of new turbine/generator and associated equipment. The civil structure may. require renovation to varying degrees. A thorough inspection of the existing structures and analysis of the economics of refurbishing versus ne\'1 construction is required. Single Unit Layouts 1.) Vertical Francis Turbine Flow into a Francis turbine is normally conveyed through a-pen- stock. An area must be available downstream from the impoundment to accommodate the larger site requirements of a Francis turbine. This type of turbine c~n be used either in an indoor or outdoor plant~ de- pending on site conditions. Refer to Figure 4-18 for the civil lay- out. 2.) Horizontal Francis Turbine For very small turbines, those having throat diameters less. than four . foot (1.2 m), there may .be a cost advantage in using a Francis type with a horizontal shaft. the arrangment of penstock, discharge and generator can be simpler than those for a vertical shaft unit. Refer to Figure 4-19 for the civil layout. 3.) Vertical Propeller Turbine The propeller turbine can be efficiently located to become part of the existing out 1 et works and/ or to be adjacent to the .impo!Jndment. As with the tubular turbine, propeller turbine installations can be easily adapted to canal drop sites. Refer to Figure 4-20 for the civil l.ayout using a penstock and Figure 4-21 where the headworks is integral with the powerhouse . 4-59 4.) Open Flume Configuration -Francis or Propeller Turbine A Francis turbine may be used in a flume or canal at an existing drop or vertical discontinuity in the flume or canal. Penstocks are not used with this type of configuration. Refer to Figure 4-22 for the civil layout, which does not require a bypass at the powerhouse and Figure 4-23 which has a bypass integrally with the powerhouse structure. 5.) _Tubular Turbine A tubular turbine can be efficiently located to become part of the existing outlet works and/ or to be adjacent to the existing impound- ment. This type is easily adapted to a canal installation. Nor- mally, the generator will be housed within a building. However, it is feasible to have the major erection or overhaul area outdoors. Refer to Figure 4-24 for the civil layout using a penstock and Figure 4-25 where the headworks is part of the powerhouse. 6.) Bulb and Rim Turbine The possible configurations for either the bulb or rim turbine are similar to those that are appropriate for the tubular turbine. As the turbine and generator for the bulb-type unit are in the water passage, the enclosed structure above the unit is relatively small, unless the erection and maintenance areas are enclosed. Normally, for units less than five MW capacity, these types are not as economical as the tubular type, despite the smaller powerhouse. Refer to Figures 4-26 and 4-27 for the civil layout. 7.) Crossflow Turbine The crossflow turbine can be used for either a penstock or flume in- stallation. The required erection and maintenance area is minimal. Refer to Figure 4-28 for the civil layout of a penstock application. 4-60 . .l ~] ;-l )---J \__ __ 1 -, L __ ' . I I I L _I ! -, ! I -' I Multiple Unit Layouts Layouts for multiple unit installations are shown on Figure 4-29 to 4- 36. Most of the turbine types which are included in the single unit lay- out section have been included. Project Layout Figure 4-37 shows a project layout for a powerhouse addition to an existing water supply canal. All the various types of hydraulic turbines reviewed in this Section can be used dependent upon the owners require- ments and the project economics. TABLE 4-1 TURBINE PERFORMANCE CHARACTERISTICS Turbine Type 1. Vertical Fixed Blade Propeller 2. Vertical Kaplan (Adjustable Blade Propeller) 3. Vertical Francis 4. Horizontal Francis Rated Head HR feet (m) 7-65.6 and over (2-20 and over) 7-65.6 and over (2-20 and over) 25-65.6 and over (8-20 and over) 25-65.6 and over (8-20 and over) 5. Tubular (with adjust-7-59 able blades and (2-18) · fixed gates) 6. Tubular (fixed blade 7-59 runner with wicket (2-18) gates) 7. Bulb 8. Rim 9. Right Angle Drive Propeller 10.0pen Flume 11. Closed Flume 12.Cross Flow 7-66 (2-20) 7-30 (2-9) 7-59 (2-18) 7-36 (2-11) 7-65.6 and over (2-20) and over) 20-65.6 and over ( 6-20 and over) Min/Max Head at Percent HR Percent 55-125* 45-150 50-125* and over 50-125* 65-140 55-140 45-140 and over 45-140 55-140 90-110 50-140 5,0-125 Capacity MW 0.25-15 and above 1-15 and above 0.25-15 0.25-2 0.25-15 0.25-15 1-15 1-8 0.25-2 0.25-2 0.25-3 0.25-2 Min/Max Capacity at kWR Percent 30-115 10-115 35-115 35-115 45-115 35-115 10-115 10-115 45-115 30-115 35-115 10-115 * May be operated to 140 percent if proper turbine setting is used. 4-62 ~--, I I ! J --, \ J ' J r ----: I I I I ..._ __ J TABLE 4-2 Generator and Equipment Efficiency Condition of Generator Drive Generator and Equipment Direct connected to turbine shaft Speed Increaser (single gear train) Speed Increaser (double gear train) Efficiency-Percent. 95.0 93.5 92.0 TABLE 4-3 Access Road Design Standards Design Speed 40 mph (64 km/h) Minimum Width 10 ft (3m) (one 1 ane) Maximum Grade 10 percent Minimum Curve Radius 50 ft (15 m) Minimum Sight Distance 400 ft (122 m) 4-63 VERTICAL FRANCIS HORIZONTAL FRANCIS VERTICAL PROPELLER OPEN FLUME FRANCIS OR PROPELLER TUBULAR Figure 4-1 Turbine Cross Sections 4-64 BULB RIM HORIZONTAL PELTON CROSSFLOW(OSSBERGER) ~-] (-l ' 1 ____ ) --, l I '_j i I ___ ; ,----, I : I ' ____ _) .i---~ , I '---J Figure 4-2 Shop Assembly of Allis -Chalmers Tube Turb ine 4-65 A B c D E F G H J K L M N ··-----· c---------i ~ RUNNER +----G ------+''•~- REMOVABLE TOP PORTION OF rDRAFT TUBE I TERMINAL BOX I J ~"--EN_O_;O_:_:~ST-EE'--. ~-'---'-----"-'-" _j DRAFT TUBE 1 ~--::-----:;--.L-IN-ER-,----.,----, j .. BASIC DIMENSIONS A = Runner Diameter in millimeters (inches) = 1.00 All Other Dimensions Are In Proportion From Runner Diameter 750 1000 1250 1500 1750 2000 2250 2500 2750 3000 (29.5) (39.4) (49.2) (59.6) (68.9) (78.7) (88.6) (98.4) (108.3) (118.1) 1.43 1.37 1.34 1.32 1.31 1.30 1.29 1.28 1.27 1.22 8.6 7.9 7.3 7.2 6.9 6.7 6.6 6.6 6.5 6.5 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 0.7 0.7 0.7 0.7 0.7 0.6 0.6 0.6 0.6 0.6 1.8 1.6 1.5 1.5 1.5 1.4 1.4 1.4 1.4 1.4 3.8 3.6 3.5 3.5 3.4 3.4 3.3 3.3 3.3 3.3 1.5 1.3 1.1 1.1 1.0 0.9 0.9 0.9 0.8 0.8 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 1.5 0.9 0.9 0.9 0.9 0.8 0.8 0.8 0.8 0.8 0.7 1.3 1.3 1.3 1.2 1.2 1.2 1.2 1.2 1.2 1.2 3.0 2.7 2.6 2.5 2.4 2.4 2.3 2.3 2.3 2.2 NOTE: Dimensions are approximate and may vary lor specific applications. Figure 4-3 Standardized Tube Turbine Dimensions, Allis-Chalmers 4-66 N ~TO~ -_] NOTES: 1. Dashed area of curve represents normal overload capabilities of typical turbines~ Operation in this area must be verified by turbine manufacturer. 2. Performance ~haracteristics of turbines vary with specific speed. An average specific speed was used to develop the curve. Figure 4-4 Turbine Performance Curve -Francis Turbine 4-67 NOTES: 1. Dashed area of curve represents normal overload capabilities of typical turbines. Operation in this area must be verified by turbine manufacturer. 2. Performance characteristics of turbines vary with specific speed. An average specific s~eed was used to develop the curve. Figure 4-5 Turbine Performance Curve -Variable Pitch Propeller Turbine (Kaplan) with Wicket Gates 4-68 -' I : J L--1 : I ·-_._~ I I j l -~1 i I ' I 1--~ --) i ' _, .--, I I '-__ ) I I I ' : ; ) .~ --, I i I I \ --J ( ---' i I I I ~--- -_J I I NOTES: 1. Dashed area of curve represents normal overload capabilities of typical turbines·. Operation in this area must be verified by turbine manufacturer. 2. Performance-characteristics of turbines vary with specific speed. An average specific speed was used to develop the curve. I ~ ............................................................................... .. •• Figure 4-6 Tubular Turbine Performance Curve -Variable Pitch Propeller Turbine (Kaplan) with Fixed (]uide Vanes 4-69 T II • 111 NOTES: 1. Dashed area of curve represents normal overload capabilities of typical turbines. Operation in this area must be verified by turbine manufacturer. 2. Performance characteristics of turbines vary with specific speed. An average specific speed was used to develop the curve. Figure 4-7 Propeller Turbine Performance Curve 4-70 • Cll w 0 ..:: ...J m II) ffi 0 ..:: ...J m ..,. 50 45 40 35 30 25 20 15 7 STANDARD TUBE TURBINE UNITS OPERATING RANGES 750 mm to 3000 mm GENERATOR OUTPUT IN KILOWATTS TEN UNIT SIZES -MILLIMETRES (INCHES) b'J 'ctJ_ j "If, J D< l;>< ... ~~ ... ~J.....' 2+-~~~~4-~-1~~4£~~~~~~-4~+-~-+-4~+-~-+-4~ ~ 5 00~~~~--+-~-+~--+-~-+~--+-~-+~~+-~-+~~+-~-+~ w ~ ~~~-+~--~~-+~--~~-+~--+-~-+~~+-~-+~~+-~-+~~ ~ 60 0 0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 DISCHARGE CUBIC METRES PER SECOND ~ ~.-~---r--~--------~---.--,---.-~---r--~--T-~r-~---r- :r: :r: 0 100 200 300 400 500 600 700 BOO 900 1000 1100 1200 1300 1400 1500 1600 DISCHARGE (CUBIC FEET PER SECOND) NOTE: OUTPUT BASED ON UNIT CENTERLINE SETTING OF ONE-HALF ('h) RUNNER DIAMETER (DIA/2) ABOVE TAILWATER. CENTERLINE OF UNIT AT. ELEVATION 150 m (500 ft.) ABOVE SEA LEVEL Figure 4-8 Allis Chalmers Standardized Tube Turbine Performance Curves 4-71 NOTES: a: ~ ft. 1.2 z a t 1.1 w a: gj ID u t1 Q9 I LL u 15 20 25 30 40 50 60 ft 5 10 15 20 m H -TURBINE EFFECTIVE HEAD TAILWATER CORRECTION CURVE +B +4 tO -4 -B -12 -16 H5 -TAILWATER HEIGHT (ft) MIN. TAILWATER FOR NEGATIVE H5 H5 -DISTANCE FROM MINIMUM TAILWATER TO D3 1. Estimated turbine runner diameters 03 are based upon a plant elevation of 2000 ft (610 m) and a tailwater height (Hs) of zero. 2. The estimated runner diameters may be used for both vertical and horizontal Francis turbines. 3. For plant elevations higher than 2000 ft (610 m), add 1% to 03 for each 1000 ft (305m). Subtract 1% from o3 for each 1000 ft (305m) lower than the 2000 ft (610 m) plant elevation. Figure 4-9 Francis Turbine Runner Diameters 4-72 • H -TURBINE EFFECTIVE HEAD cr: 0 1-u ;;: z 1.2 Q ~ 1.1 cr: 0: 0 1.0 u .. u TAILWATER CORRECTION CURVE ~ I I I MIN. TAILWATER FOR NEGATIVE H5 +Hs +a +4 +o -4 -a -12 -16 Hs-TAILWATER HEIGHT (ft) H 5 -DISTANCE FROM MINIMUM TAILWATER TO D3 NOTES: 1. Estimated turbine runner diameters 03 are based upon a plant elevation of 2000 ft (610 m) and a tailwater height of zero. 2. The estimated diameters may be used for Kaplan, propeller, tube, bulb and rim turbines. 3. For plant elevations higher than 2000 ft (610 m), add 1% to 03 for each additional 1000.ft (305m). Subtract 1% from 03 for eacH 1000 ft (305m). Subtract 1% from 03 for each 1000 ft (305m) lower than the 2000 ft (610 m) plant elevation. Figure 4-10 Kaplan and Propeller Turbine Runner Diameters 4-73 " c a ATMOSPHERIC PRESSURE ALTITUDE Ha Ha ALTITUDE Ha Ha FEET PSI Ft of HrO METRES mm of Ho M of H 0 0 14.696 33.959 0 760.00 10.351 500 14.43 33.35 500 715.99 9.751 I 000 14.17 32.75 I 000 . 674.07 9.180 I 500 13.92 32.16 I 500 634.16 8.637 2 000 13.66 31.57 -iWo-596.18 8.120 2 500 13.42 31.00 560.07 7.628 3 000 13.1 7 30.43 3 000 525.75 7.160 3 500 12.93 29.88 3 500 493.15 6.716 4 000 12.69 29.33 4 000 462.21 6.295 4 500 12.46 28.79 5 000 12.2 3 28.2 5 5 500 12.00 g}~-6 000 11.78 WATER PROPERTIES 6 500 11.56 26.70 7 000 11.34 26.20 TEMP Hv TEMP Hv 7 500 11.1 2 ~~:~~-"F FEET •c METRE 6000 10.91 40 0.26 5 0.069 6 500 10.71 24.74 50 0.41 10 0.125 9 000 10.50 24.27 60 0.59 15 0.174 9 500 10.30 23.81 70 0.84 20 0.239 10000 10.10 23.35 80 0.17 25 0.324 H0 =Atmospheric pressure for altitude, ft lm). Hv=Vopor pressure of water, use h1ghest expected temperature, ft lm) Hb= H0 -Hv. Atmospheric pressure minus vapor pressure, ft lm) "I',__ ____ FRANCIS------i•l I' PROPELLER oA ..... ---------·-----f------v ~ ... c 4 § " a: "' o. >O 20 I'( \ b "' v ..... v k" f.---- v v b'~ v -- .000 0.900 0.800 0.700 0.600 0.~00 0,400 ~ 0.300 " u; 0.2~0 .... ~ 0.200 ..J 0. 0.150 b .... z 0.100 ~ 0.090 ~ 0.080 ~ 0.010 8 0.060 0.050 0.040 0.030 0.02!5 0.020 0.015 0.010 10 17' 7 l-H I :: n5 1.64 n,•.s4 . cr = 4325 u.s. 17 50327 Metnc 1-[ZI I/ Cavitation unlikely J (cr plant > cr turbine) I/ "1: I / 17 ~ I l -! I Cavitation may be excessive (cr plant < cr turbine) 1 I ~ lj 15 zo 25 30 40 so so 10 eo 90 100 150 U.S. hp units sk'""&''~6''~''H8','bo' '1 ',!6' 'kbo'''''''!JH''''~~yw~~Metrichpunits SPECIFIC SPEED-ns 10 10 20 30 40 50 60 TO eo 90 100 110 120 130 140 150 160 170 U.S. hp units her= Critical head, ft (m). 50 100 150 200 250 02 at shrouding = Least diameter through shroud, f I (m) o, =Discharge diameter of runner, ft tml b =Distance from 02 to 'L of distributor, ft (m). (estimated from curve 't o, vs n5 ). n5 =Spec1fic speed.of turb1ne. Hs = Distance from 02 to minimum toilwoter (one unit operating at full gate). ft (m). Hs = Hb-crhcr or cr = (Hb-Hsl /her· ft (m) = 'L Distributor to minimum toilwoter = Hs + b (Total draft heodl,ft (m). Note: Place 'L of distributor at next lowest full foot elevation, (030 m). Figure 4-11 Recommended Total Draft Head for Reaction Turbines [3] 4-74 Gate Shaft Governor Electric f~otor Gate Operator Cabinet Governor Figure 4-12 Types of Governor 4-75 AIR BREAK SWITCH CIRCUIT BREAKER POWER SYSTEM TRANSMISSION LINE (HIGH VOLTAGE) J .. ---•• P.T.'S FOR METERING AND SYNCHRONIZATION -----J C.T. 'S FOR METERING AND PROTECTIVE DEVICES TO ALTERNATE POWER SUPPLY MAIN STEP-UP TRANSFORMER NO. I P.T.'S FOR METERING, PROTECTIVE DEVICES AND EXCITATION C.T.'S FOR f METERING, PROTECTIVE DEVICES AND EXCITATiON L....----f' -- NOTES: SERVICE STATION TRANSFORMER NO.2 STATION SERVICE BUS !~~~~:O;J;R J } I) NO. I I I STATION ------AUXILIARIES GENERATOR BUS 3 PHASE,60 HERTZ GENERATOR 1 1. C.T. and P.T. refer to current transformer and potential tranformer respectively. 2. For two or more units, a single main step up transformer may be employed; each unit will require a separate load side generator breaker at generator voltage. Figure 4-13 Single Unit One-line Electrical Diagrani (Line Breaker) 4-76 1f lU [[J)(Q)[JR • i l '-__ j • ' FUSE SWITCH AIR BREAK SWITCH MAIN STEP-UP TRANSFORMER NO. I CIRCUIT BREAKER P.T.'S FOR METERING,PROTECTIVE DEVICES AND EXCITATION C.T.'S FOR r METERING, PROTECTIVE DEVICES POWER SYSTEM TRANSMISSION LINE { HIGH VOLTAGE ) ~ .• P.T.'S FOR METERING AND SYNCHRONIZATION <>--=:a_ SURGE -=F" ARRESTER } C. T.' S FOR METERING AND A---------PROTECTIVE DEVISES STATION SERVICE BUS STATION . I I) SERVICE -y-n ( I' TRANSFORMER • I I STATION '-------' AUXILIARIES GENERATOR BUS 3 PHASE,60 HERTZ GENERATOR AND EXCITATION L-----.., NOTES: 1. C.T. and P.T. refer to current transformer and potential Transformer respectively. 1. For two or more units, a single main step up transformer may be employed; each unit will require a separate load side generator breaker at generator voltage . Figure 4-14 Single Unit One-line Electrical Diagram (Generator Breaker) 4-77 OIL CIRCUIT BREAKER MAIN TRANSFORMER ~ EXCITATION TRANSFORMER AUXILIARY STATION SERVICE TRANSFORMER GENERATOR NON- SEGREGATED BUS SURGE AND PT CUBICLE L--V---J PLAN TO TRANSMISSION LINE TAKE-OFF TOWER TO GENERATOR . BUS TERMINALS POTENTIAL TRANSFORMER COPPER PIPE BUS BAR LIGHTNING ARRESTER ELEVATION AUXILIARY STATION SERVICE TRANSFORMER SINGLE:. UNIT PLANT Figure 4-15 Typicai.Arrangement of a Switchyard with Line Breaker 4-78 \ I _) . ) '.~J i ! I , ____ _) :·-l '~ ~ -__J. l • I NOTES: 1. 20° C temperature rise. 2. 10% power loss, 5% voltage drop. 3. Three phase, 60 Hz. Figure 4-16 Transmission Line Capacity· 4-79 .j:>. I co 0 "T'I u::::l c ... CD ~ I _., ...... CANAL OR DAM W/NEW PENSTOCK TYPE A CONCRETE DAM WI EXISTING CONDUIT TYPE 8 0 EARTH DAM W/EXISTING OUTLET WORKS TYPE C TUBULAR TURBINE OPEN FLUME TURBINE BULB TURBINE PROPELLER TURBINE POWER PLANTS BUILT AS DAMS TYPE D • TURBINE SHUTOFF VALVE STOP LOG SLOT~ "' --ti-----<"-3-11'="' '-'-'j--.J----fl UNIT _j ~ .,; TAILRACE~ J-----1-f---------1'1-.. Equipment 1. Generator 2. Turbine 3. Governor 0 (\J<Il + + "' "' OCl 0101 "'"' II II ":3. 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: ACCESS SECTION A 1. Arrangement and equipment are schematic. e -£,! :;; ... ... "' "' Cl Cl <t" ~ 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-10 . Figure 4-18 Powerhouse Layout-Vertical Francis Turbine 4-81 tPENSTOCK L PLAN I''··"·' \ 2 UNIT ( 1\ TURBINE SHUTOFF VALVE -· STOP LOG SLOT ~ J ---i:UNIT _j ~~ TAILRACE~-.J ~ --------STOP LOG HOIST E" ~ -,.,~ ~.t.~~-~· !Q .---·-! -- "' 'I'~ l!l I\ Equipment 1. Generator 2. Turbine 3. Governor + + "' "' 00 "'"' <i-<t II II "'::':! 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: c· W 503 SECTION A 1. Arrangement and equipment are schematic. u 0 10 ,..; cS' TW EL <t. - ---·--·-··--N ~-------· - ~ 2.50, 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Figure 5-11. I Figure 4-19 Powerhouse Layout -Horizontal Francis Turbine 4-82 7 TURBINE SHUT OFF VALVE L TAILRACE------- PLAN STOP LOG HOIST SECTION A Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: 1.· Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-12. Figure 4-20 Powerhouse Layout -Propeller Turbine with Penstock 4-83 ·~ ,. •I TRASH RACK CHUTE ACCESS PLAN SECTION A Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: 1. Arrangement and equipment are schematic. 7 A STOP LOG SLOT + 0 --(£:-UNIT __j "l "' TAILRACE__... STOP LOG HOIST 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-13. Figure 4-21 Powerhouse Layout -Propeller Turbine with Headworks t 4-84 __ _j •• -e '!' ::; '-------FOREBAY --------.. 0" +1'11 '¢0 ~ Equipment 1. Generator 2. Turbine 3. Governor TRASH RACK CHUTE 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: --.., ~ • • "' "' 00 1010 rrirQ II II "C "C PLAN SECTION A 1. Arrangement and equipment are schematic. <t UNIT TAILRACE 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-15 . Figure 4-22 Powerhouse Layout -Open Flume Turbine, without Bypass 4-85 "' __ o 10 e 10 0 -~ A _j 1llJJ []J)(Q)~ Aloe---+--STOP LOG S OT L +A "' UNIT-~--~ ,., 0 "' ·I" Equipment TRASH RACK CHUTE I. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Contra 1 Pane 1 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: ~ "'_§ + + ,., "' oo "'"' ~r<) II II ""C ""C PLAN SECTION A 1. Arrangement and equipment are schematic. TAILRACE STILLING BASIN~ 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-14. Figure 4-23 Powerhouse Layout-Open Flume Turbine, with Bypass 4-86 E "' 0 _, "' 0 aJ ru • -· - E <D co + --' "' + 0 "' N 0 N Equipment TURBINE SHUTOFF VALVE L 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Speed Increaser 8. Sump Pumps 9. Pressure Set NOTES: SECTION A 1. Arrangement and equipment are schematic. 1 -----~UNIT 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-16. Figure 4-24 Powerhouse Layout -Tubular Turbine with Penstock 4-87 _j~UNIT ~~-_JW EL TURBINE SHUTOFF VALVE PLAN --'t_UNIT Sf;CTION A Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Speed Increaser 8. Sump Pumps 9. Pressure Set NOTES: 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-17. Figure 4-25 Powerhouse Layout -Tubular Turbine with Headworks 4-88 -E_jA <OCXl • --= "' . 0 ~ NO £,! •, ro 0 "' N Equipment __ WS EL 1. Generator 2. Turbine 3, Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle PLAN 3.5D3(5MW S. HIGHER) SECTION A 7. Surge and Protection Cubicle 8. Sump Pumps 9. Air Compressor and Tank NOTES: 1 I -STOP LOG SLOT _j A."' --'c~ __ :~_~:_::_c_E_--___ ~_1 E " 0 -"' + + "' "' 0 0 "'"' "':f'-.: oo -..., ~ ++ "'"' _ _.: ____ LLI...Lj..~::::::;;;:::::::_ ~ ~ 11 II '0::0. 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-18. Figure 4-26 Powerhouse Layout-Bulb Turbine with Headworks 4-89 w E + <Xl "' 0 + ,.._ "' •0 N r-- N "' 0 N "' 0 N NORMAL WS EL Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle E 0 1'-: "' 7. Surge and Protection Cubicle 8. Sump Pumps 9. Air Compressor and Tank NOTES: PLAN 503 2 SECTION A 1. Arrangement and equipment are schematic. 403 TAILRACE-------- E u 0 --"' + + "' "' 00 1010 1'-:1'-: oo =r·~ -""~ + + "'"' 00 ~~ II II .,., 2. Layout, ·equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-19. Figure 4-27 Powerhouse Layout -Rim Turbine with Headworks 4-90 "' 0 ~ 'E -<t N + --' "' + ob' N N •• ---\ STOP LOG SLOT TAl LRACE------- PLAN r~~---1"' STOP LOG HOIST ~UNIT----- L---~------~--~---------ll~~~ ~ l<i --+--'---T'--"W EL SECTION A Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-20. Figure 4-28 Powerhouse Layout -Crossflow Turbine 4-91 TURBINE SHUTOFF VALVE L PLAN SECTION A Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: 1. Arrangement and equipment are schematic. t · <l UNIT --1--------r TAILRACE~ (;; STOP LOG SLOT "' .,; ~UNIT-----'- 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-10. Figure 4-29 Powerhouse Layout-Vertical Francis Turbine, Multiple Units 4-92 ' _, - Equipment E "' 0 _, !Q "' 0 .t, "' L 9 1. Generator 2. Turbine 3. Governor H TAILRACE J 4. Generator Breaker 5. Cant ro 1 Pane-l- 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: H a o~~zo' SECTION A 1. Arrangement and equipment are schematic. TURBINE SHUTOFF VALVE A _j --1: UNITS 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-11. Figure 4-30 Powerhouse Layout -Horizontal Francis Turbine, Multiple Units 4-93 UNIT~?-----. _ E TRASH rACK ~ r---LffiAf ~· STOP LOG SLOT--,-;;------<++-'!'! TRASH RACK CHUTE Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: - -"' .§ + + "' "' 00 "'"' f()f() II II -c -c 3D +9' SECTION A 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-15. Figure 4-31 Powerhouse Layout-Open Flume without Bypass, Multiple Units 4-94 ~ ::::> ~ x-<( E ~ Q _J- <( 0 u _, 51 ::s ~ § "' 0 0 --, • I I I "'"t ., ~ FORE BAY-----! ~ L ! I .;- STOP LOG SLOT I I SLUICE WAY TRASH RACK CHUTE Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: ~ -r<"l ~ + + "' ., 00 tOtO r<ir<i II II "0 "0 I I STILLING BASIN-t PLAN TWEL SECTION A 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-14. Figure 4-32 Powerhouse Layout -. Open Flume Turbine with Bypass, Multiple Units 4-95 E !!?. 0 -~ ::;: ::::> ::;: x~ ·<l: E ::;: Q _J- <l: 0 u _I ~ ::l z 0 ~ 0' co N ., 0 0 TURBINE SHUTOFF VALVE L HEADWORKS PENSTOCK 7~+6' ~· , Equipment SECTION A 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Speed Increaser 8. Sump Pumps 9. Pressure Set NOTES: 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions·shown may vary according to site specific power plant conditions. 3. Powerhouse areas given in Figs. 5-16 and 5-17. Figure 4-33 Powerhouse Layout-Tubular Turbine, Multiple Units 4-96 5 ae -r<l + + "' "' c c v ~ I •. -E 0 Q "' "' +,., +,., 5________. FOREBAY 0 0 <0 ~ "' 0 ,.., (\J Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Surge and Protection Cubicle 8. Sump Pumps 9. Air Compressor and Tank NOTES: -·' ' PLAN 5 D3 (UP TO 5 MW) 3.5 D-J 5MW a HIGHER) l SECTION A 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-18. Figure 4-34 Powerhouse Layout-Bulb Turbine with Headworks, Multiple Units 4-97 <i_UNIT "' 0 "' TAILRACE~ ~UNIT E 0 0 --"' + + "' "' DO It') It') "-:f'-: 0 0 TW EL -"' ~ + + "' "' DO ~~ " "0'0 "' 0 It') "' 0 "' "' 0 "' A L ______._j "' 0 "' Equipment 1. Generator 2. Turbine 3. Governor 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Speed Increaser 8. Sump Pumps 9. Pressure Set NOTES: PLAN 5 D~ SECTION A 1. Arrangement and equipment are schematic. E u 0 --"' .;. + "' "' co I{) I{) r-:r-: oo 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-19. Figure 4-35 Powerhouse Layout-Rim Turbine with Headworks, Multiple Units 4-98 TW EL --,.§ + + "'"' co ~~ II II ,, "' 0 I{) I ' i : ! •• _H_ --------H~-------f' I I I STOP LOG SLOT TAILRACE~ I ili f----sTOP LOG HOIST Equipment 1. Generator 2. Turbine 3. Governor U II ..,.., · 4. Generator Breaker 5. Control Panel 6. Neutral Ground Cubicle 7. Cooling Pumps 8. Sump Pumps 9. Air Compressor and Tank NOTES: UNIT---li-111--- SECTION A 1. Arrangement and equipment are schematic. 2. Layout, equipment and dimensions shown may vary according to site specific power plant conditions. 3. Powerhouse area given in Fig. 5-20. Figure 4-36 Powerhouse Layout-Crossflow Turbine, Multiple Units 4-99 Figure 4-37 i' I \ 75'-o RELOCATE IIEAD WORKS ----( CONc'REn" LINED)· ---~---~ EXISTING ROAD ~-+-------------------- ,..-.. f~ {'-~---·--- ' . •••• ~----~ ?.70~-~ _·: WATER LINE (0=750cfs.!.) •. --'· LOWER CANAL ~ '" \ \ ----·· ---------------'···-- ) /----~~~ ~ _-( ... , ' .. , ~ ·v:.-::·_. /;;.-~~c,-<.SS ROAD • (CANAL BANKS RIP-RAPPED /< BOTH SIDES ' ~-: ' , '.~.,; '-... .---\ ·------------~. '. . _;_---/ '-, ?JO~ --~-... -\..-----· .::_ ___ _ NOTE: See Figure 4-38 for Section A. Alternative Turbine Arrangements --Typical Project Plan 4-100 2740 2740 _.I "' z "' 0 a: "' a. a. ::> .., TYPICAL SECTION A SCALE 1• .. 20' NOTE: ~ /TAIL RACE ----;----------------, ~=t=--=-=~-~~-~--~-~r------====¥~-J----- VERTICAL SHAFT PROPELLER TURBINE OPEN FLUME CONFIGURATION VERTICAL SHAFT PROPELLER TURBINE CONCRETE PENSTOCK a SCROLL CASE CONFIGURATION PENSTOCK POWERHOUSE AND GENERATING EQUIPMENT GENERATOR TUBULAR TURBINE CONFIGURATION BULB TURBINE CONFIGURATION GENERATOR <I z "' 0 \ _______ _ CROSSFLOW TURBINE CONFIGURATION See Figure 4-37 for project plan. Figure 4-38 Alternative Turbine Arrangements -Sections 4-101 2740 2740 2740 2740 POWER PLANT Genera 1 SECTION 5 CONSTRUCTION AND INDIRECT COSTS The power plant cost includes cost of the turbine/generator and elec- trical-mechanical equipment within the power plant. This section in- cludes these costs in addition to the powerhouse civil costs. -Costs are presented for several types of hydraulic turbines over a size range that is within the scope of the report. Total construction costs for several combinations of turbine/generator powerhouses are also given in Section 9. Turbine/Generator Costs Cost curves are presented for various types of turbines and generators. The data used was obtained from turbine, generator and governor manufac- turers over the past five years and escalated to a July 1978 price level. Price lists are not available on turbines as most turbines are custom design. In general, turbine and generator costs per installed kW decrease as the capacity of the unit increases. However,, the effective head available to the turbine has the greatest influence on the cost. The lower. the head, the higher is the cost per installed kW. This in- crease i"s due to the larger physical size of the equipment and the lower synchronous speed required by the low-head application. The cost curves are suitable to prepa~e an economic assessment of a project. However, it is recommended that prices be requested from manufacturers when final feasibility studies are made. It is also suggested that firm bids be received on the turbines and generators prior to the final design of the powerhouse. These bids would permit competition between the various types available. For each turbine type for which bids are received, estimate should be made of the civil powerhouse costs in addition to any 5-l other cost items which are affected. The total project cost for each type turbine can then be determined. The operation studies are then. revised, if necessary, using the manufacturers• turbine performance data. The annual power generation is calculated and the turbine type having the lowest production cost per kWh is normally selected. Turbine/Generator Cost Curves The cost curves included in this report are as follows: Turbine Type Figure No. Francis (includes both vertical and horizontal Francis) 5-l Vertical propeller (includes Kaplan) 5-2 Open flume 5-3 Closed flume 5-4 Tubular (includes both adustable and fixed blades 5-5 Bulb and Rim 5-6 Crossfl ow 5-7 Each cost curve is noted as to the items included in·the cost curve. Station Electrical Equipment Costs Station electrical equipment includes station switchgear, battery system, station service transformer and equipment, lighting, protection system, control board, cable and conduit. These systems represent a fixed ex- penditure of plant cost regardless of turbine type and generator se- 1 ected. Figure 5-8 i 11 ustrates the do 11 ars vs. MW for the ranges of small hydroelectric plants. Miscellaneous Equipment Figure 5-9 contains data for estimating the cost of miscellaneous power plant equipment. The costs contain only the minimal equipment as previ- ously described in Section 4. For an attended station with facilities 5-2 for operators and maintenance personnel, the costs should be increased to include the added facilities. Civil Powerhouse Costs The powerhouse civil construction costs may be determined using the cost curves included in this Section. Selection of the turbine best suited to a particular site should be made on the basis of the information present- ed in Section 4. The curves present the civil construction cost as a function of either a principal turbine dimension or the turbine/generator nameplant rating. The civil construction costs include the construction of a reinforced concrete powerhouse structure. The costs include con- crete, reinforcing steel and embedded miscellaneous metal. The power- house cost curves do not include excavation, foundation treatment, backfill or compaction. These costs are discussed separately later in this Section. The indoor plant superstructure is considered .to be of either concrete masonry unit or sheet metal construction dependent upon size and locality. These cost curve figures, in addition, indicate the area required by the powerhouse structure. This area is used, by follm-J- ing the procedure given in this Section (Excavation Costs), in deter- mining the excavation costs. The selection of the turbine elevation, throat dia. (0 3 ) and speed is made based on data given in Section 4. The turbine elevation determines the depth of excavation required for the powerhouse structure. The costs and areas shown in the figures are for both single and multiple unit powerhouses. Civi 1 Powerhouse cost curves and area required are presented for the following types of powerhouses: 1.) Francis Turbine (Vertical) Flow into a Francis turbine is normally conveyed through a penstock. An area must be available downstream from the impoundment to accommodate the larger site requirements of a Francis turbine. This type of turbine can be Used either in an indoor or outdoor plant, depending on site 5-3 conditions. Refer to Figure 5-10 for the civil costs, which are based on an indoor plant. 2.) Francis Turbine (Horizontal) For very small turbines, those having throat diameters less than 4 ft. (1.2 m), there may be a cost advantage in using a Francis type with a hori zonta 1 shaft. The arrangment of penstock, discharge and generator can be simpler than those for a vertical shaft unit. Refer to Figure 5- 11 for the civil costs, which are based on an indoor type plant. 3.) Fixed and Adjustable Blade Propeller Turbine The propeller turbine can be efficiently located to become part of the existing outlet works and/or to be adjacent to the impoundment. As with tubular turbine, propeller turbine installations can be easily adapted to canal drop sites. A propeller turbine is adaptable to either an indoor or outdoor installation. Refer to Figures 5-12 and 5-13 for the civil costs, which are based on an indoor type plant. 4.) Open Flume Either a Francis or a propeller turbine may be used in a flume or canal at an existing drop or vertical discontinuity in the flume or canal. This configuration may be used for either an indoor or outdoor type of plant, depending on the site conditions. Penstocks are not used with this type of configuration. Refer to Figure 5-14 for the civil costs, where a built-in bypass is used and Figure 5-15 which does not include a bypass. Indoor type of plant is used for these costs. 5.) Tubular Turbine A tubular turbine can be efficiently located to become part of the existing outlet works and/or to be adjacent to the existing impoundment. This type is easily adapted to a canal installation. Normally, the generator will be housed within a building. However, it is feasible to have the major erection or overhaul area outdoors. Refer to Figure 5-16 for the civil costs for tubular turbine powerhouses using a 5-4 penstock connection and Figure 5-17 where the turbine is adjacent to a headworks. 6.) Bulb Turbine and Rim Turbine The possible configurations for either the bulb or rim turbine are simi- 1 ar to those that are appropriate for the tubular turbine. As the turbine and generator for the bulb-type unit are in the water passage, the enclosed structure above the unit is relatively small, unless the erection and maintenance areas are enclosed. Normally, for units less than five MW capacity, these types are not as economical as the tubular type, despite the smaller powerhouse. Refer to Figures 5-18 and 5-19 for the civil costs, which are based on an indoor type plant. 7.) Crossflow Turbine The crossflow turbine can be used for either a penstock or flume instal- lation. Normally this type of unit is placed indoors. The required erection and maintenance area is minimal. Refer to Figure 5-20 for the civil costs, which are based on an indoor type plant. Excavation Costs Excavation for the powerhouse is necessary to correctly set the turbine elevation with respect to the tailwater elevation. The method for deter- mination of the turbine setting elevation is given in Section 4. The ex- c av at ion cost may be approximated as a function of the powerhouse area and the maximum depth of excavation. Figure 5-21 shows the relationship of the total cost of excavation to the powerhous6! area and the maximum excavation depth. This cost curve for small hydroelectric installations was developed using the following assumptions: 1.) Excavation wcruld be. done to full depth to a distance of 5 ft (1.5 m) outside the powerhouse perimeter and all side slopes would be on a 45 de- gree angle. 5-5 2.) The total volume of excavation would be one-half common excavation and one-half rock excavation. 3.) The unit excavation costs assumed were $2/yd3 (0.76m3) for common ex- cavation and 10/yd3 (0.76m3) for rock excavation. The cost curves in- clude a 10 percent allowance for backfill, compacting, and casual grading adjacent to the powerhouse. These can be typical unit costs where the construction haul is normal. The approximate powerhouse area requirements for each type of turbine are indicated in Figures 5-10 to 5-20 inclusive. Knowing the turbine throat diameter and depth required by the turbine from Section 4, and the power- house area, use Figure 5-21 to determine the powerhouse excavation cost. Excavation and Protection Costs It is required that the powerhouse structure be placed on sound material in order to develop full resistance to shearing and sliding. Any weathered material and material shattered by blasting must be removed prior to concrete placement. To insure proper foundation conditions, it may be necessary to excavate to a depth greater than that indicated by the turbine size. Often it is necessary to make a single boring at a proposed site to determine the below grade foundation conditions. An un- usual condition might be cause to select a deeper depth curve on Figure 5-21 than that indicated by the turbine parameter. However, it is not necessary for an appraisal evaluation to assess this possibility. A feasibility evaluation will have to evaluate the requirements of using a deeper depth curve. Some sites may. require the construction of a cofferdam to protect the construction site. This protection may be either in the form of sheet piling or a dike and rip-rap. Construction dewatering and care and han- dling of the stream facilities normally will be required for the exca- vated area. As these costs are unique to the site and soil conditions, ·the costs for flood protection and dewatering facilities are not included 5-6 f --' I in Figure 5-21. An evaluation should be made on a site specific basis for the costs for these items. Protection of the construction site could total 10 percent of the total powerhouse civil features cost. Foundation Costs The cost of the powerhouse foundation should be considered. It is diffi- cult to accurately estimate the extent and cost of required foundation work without some detailed soil information. On the basis that the ap- praisal assessment will be made without the benefit of a soils report, some allowance should be made in the· total estimated cost for possible additional foundation work. This additional work would primarily include cut-off walls and drainage systems. For foundation assessment; there are two basic types of power plants. As a part of a new water retaining structure or dam there is a head difference across the structure which presents the potential for subsurface flows below the structure, causing uplift and possible overturning moment. The additional cost for added excavation or structural work can be substantial, and would vary considerably with the specific site conditions. The other type of installation has the power plant separate from the dam, with the water conveyed to it through an en- closed conveyance, so that water pressure is not a problem. Although there will be some foundation costs for this type of installation, de- pending on the soil types and the site topography, the cost would nor- mally be much less than for the previous case. For the cost of the foundation work it is recommended that the FERC account 331 be increased by two percent to cover this cost. FERC account 331 includes the cost of all the structures and improvements. Foundation Stability Figure 5-22 shows various methods of stabilizing the powerhouse struc- ture. There must be enough mass in the powerhouse structure and its con- tents that will prohibit the structure from floating if there is a 5-7 hydraulic uplift. If sufficient mass is not available, and dependent upon foundation conditions, a lip may be provided to which additional concrete mass may be added in addition to allowing some of the earth mass above the 1 i p to be added to the powerhouse mass weight for overcoming flotation. There must also be enough concrete mass to resist any vibration forces from the turbine/generator unit, the heavy loads from the generator thrust bearing and any short circuit torque of the generator. Dependent upon the design of the powerhouse and the pedestal supporting the generating unit, it is sometimes necessary, the same as for uplift, to provide a lower lip on the foundation to have added concrete mass to assist in resisting these loads. Adequate drainage around the powerhouse subgrade will decrease the hydraulic Uplift. However, provisions may have to be provided to offset the tendency of the tai lwater to produce a hydraulic uplift. Full penstock pressure against the closed turbine valve or wicket gates will produce a hydraulic thrust which produces both a sliding effect and an overturning moment on the powerhouse structure. The overturning moment must be resisted by either dead weight mass, anchors, increasing the size of the powerhouse base or any combination of these features. If the hydraulic thrust is greater than the resisting force of sliding resistance by friction and cohesion on the base of the structure, then the additional thrust must be resisted by either a shear key or rock anchor bolts. The·suggested costs in the Foundation Cost section includes the treatment for stability. ·WATERWAY COSTS Intake For protection of the hydroelectric equipment, there should be the capa- bility to stop the flow of water through the intake structure during emergencies. Most existing impoundments have an emergency closure sys- tem, either at the intake itself or at some point along the outlet works conduit under the dam (valve chamber). However, if the existing facility 5-8 I does not have the capability to shut off the flow of water under emer- gency conditions, an emergency closure system should be included in the design of the hydroelectric facilities. This closure system is usually located just downstream of the intake. The closure device is usually a vertical wheel mounted gate that can be remote control operated under a power failure condition; for example, a gravity operated wheel mounted gate, or a hydraulic cylinder operated gate provided with an accumulator system. Figure 5-23 shows the type A power plant the cost of a low level intake structure for single and multiple units. The cost shown includes excava- tion, concrete, reinforcing steel, embedded steel, trash racks, gates and backfill. If trash rakes are required, this would be an additional cost. There should always be a minimum of two closure devices upstream of the hydraulic turbine. These could be stop logs, or valve at the turbine in- let. The cost of the turbine valve where noted is included as part of the turbine cost. The cost of a slide gate is shown on Figure 5-24. Tunnels and Penstocks Many types of pressurized tunnels and conduit systems have been developed and used on various hydroelectric applications. Most existing impoundments already have a water conveyance facility in service. If possible~ use of the existing tunnel or conduit for the pro- posed power generation facility should be made. The cost of a new tunnel or conduit will often make a project infeasible. However, new conduit facilities are often required. If a new tunnel is determined to be necessary, a cost of $1,300 per lin- ear foot (0.30m) (Table 5-l) may be assumed for an appraisal cost as- sessment. This cost is for a 7ft. (2.lm) diameter steel-lined tunnel. As this is the minimum diameter that can be achieved with standard boring 5-9 equipment, no cost savings can be realized by specifying a smaller tunnel. Penstocks are pressurized, low-friction water conveyance conduits which carry water from an existing source of water to the powerhouse. Penstock design is a complicated process involving aspects of economics, turbine regulation requirements, plant siting and materials [7]. A cost curve is presented to estimate penstock costs. Penstock can be constructed of wood, concrete or steel. Steel is usually the preferred material, however, and costs will be given for both steel and concrete. Penstock design must consider the stresses caused by internal pressure (static head plus water hammer), external pressure, temperature, erection and installation. One consideration in the penstock design is the stresses caused during the handling and erection phase. A minimum handling thickness, as a function of penstock diameter L7J, is required and is usually the govern- ing factor in penstock design for small low head hydroelectric power plants as defined in this report. Minimum handling thicknesses, over a range of penstock diameters, are shown in Table 5-2. Figure 5-25 shows the installed penstock costs for a small low head hy- droelectric installation. The cost include fabrication and erection, in- cluding supports for a steel penstock. It is recommended that costs be based on a penstock velocity of 10 ft (3.05 m) per second and a pipe thickness equal to the minimum thickness required for handling. However, other cost curves are shown for higher water velocities using minimum handling thickness, to be used if experience indicates a higher velocity should be used. A corrosion allowance~ that is an additional thickness has not been used, as it is normal to coat the interior of the penstock, usually with coal tar enamel, to decrease the hydraulic friction losses and the effects of corrosion. 5-10 Costs for a concrete pipeline are given in Figure 5-26. Final penstock design may indicate there could be an overall saving in owning and operating costs by increasing the penstock velocity above the value of 10 ft (3.05 m) per second. It is not necessary to consider this possibility at the appraisal level. One specialized type of penstock should be mentioned. Many existing dams have concrete outlet conduits which are designed for unpressurized condi- tions. When downstream controls are provided, conduit pressures will in- crease accordingly and measures must be taken to protect the existing outlet conduit structure against failure under the higher pressures. The most effective and least costly method to increase the pressure capacity of the existing outlet structure is to install a relatively thin, welded steel liner inside the existing concrete outlet conduit. This liner may be fabricated in place when the tunnel is in an unwatered condition. The annulus between the liner and the existing concrete conduit is then back- filled with concrete. The costs for this type of modification may be es- timated from Figure 5-25, using the unit cost increased by 50 percent. Valves, Gates, Outlet Works and Other Hydraulic Works Depending on the project configuration selected, various other hydraulic equipment will be needed for the operation of a small hydroelectric in- stallation. The nature and cost of this additional equipment is pre- sented below. Whenever the turbine is not in operation, the project requirements may necessitate that water be released from the pondage. Dependent upon the project configuration, the release of the impounded water may require that its energy be dissipated by some device. In the low-head range of this report, this energy may be dissipated by special gates or a fixed cone valve. The gate may be either a jet-flow gate of the WPRS design or a standard slide gate that has been designed for this type of use. The fixed cone valve is a commercially available valve, made by several manu- facturers (refer to Appendix Page B), and known as a "Howell-Bunger" 5-11 valve. Satisfactory performance of this valve requires experience in the design of its installation. At low-heads, valve vibration should not be a problem. Costs for this valve may be estimated from Figure 5-27. It is necessary, as pieviously stated in Section 4, to have some type of closure device in the water conduit ahead of the turbine. Normally for the low head application of this report, the ball or plug type valves are not~competitive and only the butterfly valve is considered in the cost data of Figure 5-27. When a bifurcation is used for multiple turbine in- stallations, a butterf_ly valve is placed ahead of each turbine. Some of the turbine cost curves have included the cost of the turbine shut-off valve of the butterfly type. When this cost is not included, then the costs of either a wheel mounted gate or butterfly valve wi 11 have to be included in the construction costs. Bifurcation A bifurcation splits a single flow conduit into a pair of conduits. A bifurcation is used if a single penstock conveys water to two turbines or if a bypass must be provided off the main penstock. Multiple bifurca- tions are often used. Bifurcation costs are usually estimated by calcu- lating the weight of the bifurcation and multiplying by a unit weight cost of steel. Figure 5-29 presents the cost of a penstock Bifurca- tion. Figure 5-29 presents the cost of a bypass adjacent to the powerhouse and includes all costs (structure, etc.) as noted. Tailrace Improvements and Costs The main function of the tailrace is to maintain a minimum tailwater ele- vation below the power plant and to keep the draft tube submerged. All reaction turbines, require that the tailwater be maintained above a mini- mum elevation to minimize the effects of cavitation and take advantage of the additional head available when the turbine setting is above the tailwater elevation. It is also important to keep the draft tube sub- merged, even when there is no flow in the downstream channel or tailrace in order to improve the turbine start up conditions. This is normally 5-12 accomplished by excavating the channel immediately downstream of the power plant to maintain a pool of sufficient depth to keep the draft tube covered, and by including a control structure to maintain the pool at a minimum elevatjon. Also, a section of new channel might be necessary to connect the new installation with the existing stream channel. The major proportion of the tailrace cost is in the cost for the required excavation, with some additional cost for concrete channel lining, a con- crete sill or weir, and rip-rap. The amount of excavation required de- pends on the elevation of the turbine spiral case and the length, width and depth of the channel required to return the plant discharge to the existing stream channel. The cost for the tailrace is predominately pro- portional to the tailrace length, but there is also a fixed cost to cover the excavation immediately downstream of the draft tube. The tailrace cost may be estimated as $15,000 plus $200 per linear foot (0.30m) (Table 5-3). DAM COSTS General The cost of dams and their appurtenances is based on work by the WPRS [1]. This work has been primarily based on larger structures than can be envisioned for the small low-head hydro project. It is also recognized that the purpose of this report will cover few projects wherein it will be required to construct a dam. This is discussed in more detail in Sec- tion 9. The original costs of [1] have been bro.ught to the July ·1978 price level by use of the quarterly cost indices published by the WPRS. These indices and their use are discussed in more detail in this section. The cost data l1J was intended for reconnaissance level studies. Unless there are field conditions which indicate that cost adjustments should be made, it is recommended that for the purpose of this report, these cost values be used in the economic studies discussed in this report. 5-13 Oat a Required For the cost estimate to be successful and use made of the included cost curves, certain data should be known. This data would include the fol- lowing: o Profile of damsite, including overburden o Area-capacity curves for the reservoir o Character of foundation o Type and source of construction material o Maximum capacity of spillway and outlet works o Maximum tailwater elevation Concrete Gravity Dams Figure 5-30 shows the total field cost of gravity concrete dams in dollars per cubic yard (0.76 cubic metre) of concrete based on the total- volume of the structure. This cost includes the dam structure, spillway, river outlet works, diversion and care of the river during construction and contingencies. Clearing, permanent access facilities and engineering expenses are not included in Figure 5-30; Earth Dams Figures 5-31 to 5-34 inclusive show the total field cost of earth dams and their related features. There are many variables in earth dam con- struction which influences its cost. Some of these variables include poor foundation material which will require substantial overexcavation and backfill, and/or flatter embankment slopes. It is possible for the costs to vary by a factor of 2, however, on the average these costs can be used to determine the probability of the projects feasibility at an appraisal level but engineering judgement and reliable investigation of site conditions must enter into the final project cost estimate. Figure 5-31 shows the volume of an earth filled dam per unit length of dam. Knowing the varying dam height along its length and using discrete 5-14 ' _} sections, the dam volume may be determined. Figure 5-32 shows the es- timated cost per unit volume as a function of the total dam volume. Figure 5-32 is based on an average haul length of 1 mile (1.61 km) and the cost curve values should be increased by 10 percent for each addi- tional 1 mile (1.61 km) of haul. Additional adjustments may have to be made for unusual foundation or grouting costs which may amount to 40 per- cent of the structure, only average foundation and grouting costs are in- cluded in Figure 5-32. Figure 5-33 shows the estimated cost of a spillway. The cost is shown as a function of the head, difference in elevation between the maximum re- servoir surface and tailwater, and the spillway capacity .. Outlet works cost is shown in Figure 5-34 as a function of the head and capacity. Diversion Dams-Canals Figures 5-35 and 5-36 show the cost of a diversion dam for use with an open canal. Field cost curves Figures 5-35 and 5-36 include the cost of foundation, gated spillway, spillway section (gated or uncontrolled over- flow, nominal wing dikes and contingencies). If the wing dikes are ex- tensive then an appropriate allowance should be added. Figure 5-37 shows the cost of a canal headworks discharging into an open canal. These cost curves do not include costs for automatic or remote control. Existing Dams An existing dam should not become a part of a new hydroelectric develop- ment unless it can be established that its use will not jeopardize life and property downstream of the dam. The integrity of the existing dam should be established for both its present mode of operation and the future operating constraints that will be placed on the structure. Using . . the dam for hydroelectric operation may place either drawdown cycles which are severe on an earth dam and surrounding reservoir banks or high water levels which due to the dams age may overload the structure. At an appraisal level an amount of $10,000 should be adequate for a dam 5-15 integrity review. Some of the items that should be reviewed include the following: o For concrete structures the alkali-aggregate reaction and weathering o. Slides in earth embankments o Water seepage from drains in concrete dams or along the toe of an earthfilled dam o Stream bed erosion o Undercutting of spillway structures o Wear on operating gates, hoist mechanisms and water release valves and/or energy dissipating valves The appraisal assessment should determine the probability of the following: o Is the dam structure useab 1 e for hydroe 1 ectri c deve 1 opment with only minor modifications o Does some rehabilitation work have to be done in addition to minor modification to be acceptable for hydroelectric development; or o The structure is not useable and will have to be removed and rep 1 aced The costs for any of the foregoing work cannot be generalized due to the high degree of site sensitive factors. New construction unit costs cannot be used due to the type of work involved, more than normal labor component, restricted work areas, small quantities of material, etc. It would be unusual if mechanical equipment could be used to the same extent as on new construction. Remed i a 1 work may or may not be required. If remedial. work is required the costs cannot be generalized and can only be evaluated by assessing the actual work that must be done. Normally some type of 5-16 ' '! :~_, J 1,_] ·: -'1 l' ,-] . -I ,·I '----" -l.' I __ · r~ L __ : ~--~ alternative will be required and the cost to be used in an appraisal estimate has· to be basically one of judgment. If there are extensive alterations the cost may be as much as 8 percent of the total construc- tion cost. SWITCHYARDS Economic studies are usually required to determine the location of the power transformer, circuit breaker and other items of electrical equip- ment which may be placed in the switchyard, and to determine the method of routing the electrical power conductors from the generator to the ini- tial point of the transmission line for connecting to the power grid. For small .hydroelectric installations, the power transformer can be lo- cated at the power plant. If this location is not feasible, then the power transformer is placed in the switchyard. Accordingly, the switch- yard should be placed as close as practical to the generator to minimize the length of conductors. Further, the switchyard site must be above the flood elevation and placed where any possible water spray will not effect the high voltage equipment. Using the plant rating, the switchyard civil costs may be determined by the use of Figure 5-38. Costs shown in Figure 5-38 include a normal amount of grading and fencing costs. If the switchyard site is sufficiently remote from the powerhouse structure, and where more than a normal amount of grading may be re- quired, the extra grading costs can be determined by applying the para- meters of Table 5-4 and Figure 5-42. Except for extremely unusual site conditions, any of these increases will not be significant project costs and need not be considered. The electrical equipment cost data for the switchyards is given in Figures 5-39 and 5-40. This cost data reflects the installed cost for transmission voltages up to a maximum of 115 kV. The main variable of cost is the KV·A rating of the transformer. The voltage level is the next variable in cost as higher voltage requires more insulation mater- ; al. Each transformer is provided with a control cabinet and sudden 5-17 pressure relay. It is assumed the low voltage of the hydroelectric gen- eration will be 4160 volts. Several high side voltages are presented. Figures 5-39 and· 5-40 list the equipment items included in the cost curves. The costs presented in Figure 5-39 is for switchyard with gener- ator voltage circuit breakers. The costs presented in Figure 5-40 is for switchyard with line voltage circuit breakers. Only Figure 5-39 includes cost curve for single and multiple unit plants. TRANSMISSION LINES Transmission line unit costs are a function of the transmission voltage, length ·of transmission line being constructed and type of terrain. Figure 5-41 shows the unit cost and power plant capacity for several line voltages. Section 4 recommended maximum distance and carrying capacity for each line voltage. Figure 5-41 shows the effect of construction length on the unit cost of transmission lines. It is only when the length of transmission line is less than about 18.6 mi (30 km) that the unit construction cost in- creases. The multiplier shown in Figure 5-41 is used when determining the transmission line costs shown in Figure 5-41. Figure 5-41 also in- cludes correction factors to be applied for various terrains encounter- , ed. The cost data does include ncrmal construction road costs but does not include access roads, land or rights of way, relocations or clearing. Normally transmission line costs are not considered in an appraisal study made by a developer if the power is to be purchased by others. SITE DEVELOPMENT General Site development for a small hydroelectric development involves the modi- fication of the existing terrain and results in changes in both the topo- graphy (cuts and fills), and in the natural or existing drainage pat- t-ern. This section describes the items that need to be considered in the 5-18 ----. ' -) _ _] • I ---1 I ' l --' r--., I ' ! r---' ' I ' I I I ~ ~ / I . ' "' __ J I I ----' -, evaluation of the site preparation activity. The costs are considered in this Section. Drainage and Erosion Crintrol Costs The costs for grading, drainage collection and erosion control systems are shown on Figure 5-42. Utilizing the area requiring grading, the con- struction cost is estimated using the grading curve in Figure 5~42. The drainage cost for any of the site area or parking area subject to ground water and thus requiring the install at ion of a network of subsurface drains and catch basins, is estimated. using the drainage system curve from Figure 5-42. Finally, the construction cost for erosion control is estimated using Figure 5-42. This construction cost is e.stimated using the erosion control cost curve and the slope area that is being consi- dered. Drainage systems, and erosion control provisions are not usually signifi- cant cost items on small hydroelectric installations. However, these cost curves are included and should be used only when the area to· be treated is proportionally large with respect to the project_ capacity which may then make these costs a significant construction cost .. Access Road Costs The estimated construction cost p~r mile (1. 6 km) of new paved access I road of single lane:~ width is $125,000, and _of two lane width is $250,000. This cost is based on a 2 in. (51mm) asphalt concrete pave- ment, a 4 in. (102mm) subbase and 4 in. (102mm) base. A single lane un- paved access road has a construction cost of $75,000 per mile (1.6 km). If an existing road requires upgrading, a cost of $53,000 per mile (1.6km) should be used. For a single span access road bridge, con- structed of standard prestressed girders, use $50 per square foot (0.09 m2). This bridge cost includes excavation, substructure on piles and superstructure. (Table 5-4). 5-19 Parking and Miscellaneous Site Features The cost for paving the parking and equipment erection area with two inch (51mm) asphalt concrete pavement and four inch {102mm) each of base and subbase is approximately $7 per square yard (0.8m2) (Table 5-4). Normally the cost for fencing is not an important cost item and will not materially influence the fi na 1 project cost. However, if for some un- usual siting conditions it is required to fence off a m·uch larger area than normal, then the cost for the usual chain 1 ink type fence 8 ft. (2.4m) high with a 1 f~. (0.3m) extension arm may be based on a unit cost of $16 per lineal foot (0.3m) (Table 5-4). Preserving the natural characteristics of the project area is of impor- tance. Consequently, the area should be 1 andscaped in an attempt to re- store the original vegetative condition. The approximate 1 andscaping cost for seeding, planting and fertilizing is $2,800 per acre (0.4 hectare) (Table 5-4). Environmental Control Costs During Construction Costs associated with mitigation of the effects of environmental controls discussed in Section 4 are generally insignificant. Sprinkling for dust control, reseeding of vegetation, spacing of blasting to avoid disturb- ance if recreation areas are nearby, along with other necessary measures, would generally amount to an additional estimated project cost of $10,000 (Table 5-4). Depending on the design of the existing outlet works, cost increases might also result where the releases from the reservoir must be maintained during the construction period. INDIRECT COSTS Genera 1 Indirect costs are those costs which are chargeable to the original total project costs but are not considered directly as an item of construction 5-20 _] :-·~ : I .. J I . _j J ·----1 :~ I J I : --J : I I -__ ) l - ; I ' ~--_: r --. t ~ -,' r l_ -- -, i 1, __ I 1 _____ ./ I l_._j ,..~----' ' ( cost. The indirect costs include interest during construction and de- velopment costs. Interest During Construction Interest during construction (I. D.C.) is the money paid for the capital used during the construction period. It is usual to estimate this as simple interest based on the average expenditure for each annual period during the construction period. As an example of interest--daring construction assume the estimated project cost is to be 8 million dollars and the project will require three years to construct. The interest during construction for an interest rate of 10 percent may be calculated as follows: Year 1 2 3 Total Total Expenditure Annual Expenditure Interest Of Prior Years ----- $2,000,000 $100,000 0 3,000,000 150,000 $2,000,000 3,000,000 150,000 5,000,000 $8,000,000 $400,000 Total I.D.C. = $400,000 + $700,000 = $1,100,000 Completed Cost = $9,100,000 Engineering and Construction Management Interest ----- 0 $200,000 500,000 $700,000 The engineering costs include the cost of preparing a feasibility study, preliminary engineering and final engineering design. For ·an average project these costs could amount to about 2, 3 and 6.5 percent respect- ively of the final construction costs, including contingencies. The construction management cost is generally in the order of 5.5 percent of the total construction cost, including contingencies. These costs are considered to be part of the development costs. 5-21 Miscellaneous Costs Additional items in the development costs include legal fees, bonding fees and administration costs. There are usually both legal fees and permit application costs to obtain licenses and permits. The costs may be in the order of two percent of the total construction costs, including contingencies. These legal fee costs include legal review of any product sales agreement and method of funding project costs. Administration costs vary with the depth of the owners participation in the project but normally one percent of the total construction costs, including contin- gencies, is used as this cost. COST SUMMARY General This section describes the method of updating the costs, as presenteq in this report, from the July 1978 base to the date required for either the preliminary or final feasibility study. Two indices are presented. The first, which is for escalation, is the WPRS index of project component costs. The second is a correction for site location and reflects the variation of construction costs within the continental United States. The first index is given on Figures 5-43 to 5-50 and the second is given on Figure 5-51. The method for obtaining indirect costs, which include engineering, con- struction management, and the operation and maintenance and insurance is also provided in this section. Escalation The WPRS publishes on a quarterly basis the cost indices for thirty-four construction items that are common to irrigation and hydroelectric proj.,.. ects. These are published in L10J and are applicable to the eighteen western states. These indices are included on Figures 5-43 to 5-50 for the last six years and used as follows, (1) extend the curves beyond July 1978 as future indices are published and (2) extrapolate, if necessary, 5-22 ', -' -\ -l I J ,-, I J I '-___ ) l __ ~ __ ! ) I I l I I __ -' r---~ I I I ' t-~-' I L-) ' -i l -' ~ i---; I I to the date required for the economic assessment. The construction item for which an escalated cost is required must be considered to be represented by one of the classifications in Figures 5-43 to 5-50. The escalated construction cost is obtained by determining the index num- ber on the extended curve for the required date. The ratio of the July 1978 index for the date used in the feasibility assessment is the multi- plier by which the July 1978 base cost is multiplied to obtain the es- calated cost. Regional Cost Correction A regional cost adjustment is made to the final cost after all the indi- vidual costs have been escalated. Figure 5-51 shows the regional cost variation. The cost base used in this section represent a regional cost value of one. If the construction site-is in a region having a cost value other than one 3 as shown by Figure 5-51, then this different re- gional value is used as a multiplier to correct the total escalated cost for any regional cost difference. Contingency A contingency allowance is added to the escalated and regionally correct- ed construction costs to cover unknown and omitted items which would nor- mally be included in a more detailed cost estimate. Contingencies also include. an allowance for possible cost increases due to unforeseen condi- tions. Contingencies are normally estimated as 10 to 20 percent of the construction cost. Engineering, Construction Management and Other Costs Once the escalated and regionally corrected construction cost has been determined, it is necessary to estimate, the engineering, construction management and administration costs, sometimes· referred to as development or indirect costs. These costs inc 1 ude expenditures for feasibility study, license and permit applications, preliminary and final design, construction management, and administration. A multiplier of 20 percent 5-23 should be applied to the total final construction cost, including contin- gencies, to estimate these development costs. OPERATION AND MAINTENANCE COSTS General Operation and maintenance costs for small hydroelectric plants are diffi- cult to forecast accurately. The costs are directly related to the site and the owner•s capability to perform the operation and maintenance func- tion. Amounts are suggested in Section 2. Operation and maintenance costs as described herein, 'include the items listed below. Insurance The government is basically a self-insurer_, however, for a commercial in- stallation, coverage is required for fire and storm damage, vandalism, property damage and public liability (cost included with O&M cost section). Routine Maintenance and Operation An amount must be budgeted to cover the costs of manpower, wages, ser- vices, equipment and parts utilized in the normal operation and main- tenance of the hydroelectric plant. General Expenses The final portion of operation and maintenance costs are made up of those expenditures for administration and other miscellaneous costs required during project operation. Operation and Maintenance Cost The cost of operation, maintenance expenses and insurance can be estimated by multiplying the investment cost for the powerplant, 5-24 -\ :I ' J ', -----. I _) ,,, -J ,____ _) ' '---' r -_) . .--' r-- ' including contingencies and development costs, by 1.2 percent. The resulting amount will be the estimated cost for operation, maintenance and insurance of the hydroelectric plant for the first year of operation.-The operation and maintenance costs will increase with time. corresponding to inflationary trends. Section 2 included (Figure 2-1) the results of an industry' survey of small low-head hydroelectric plant operation, maintenance and replacement costs. Figure 2-1 shows the survey results as a function of generating plant capacity rather than plant construction costs. The reader has the option of using either Figure 2-1 or a percentage of the construction costs referred to in the preceding paragraph for the first years annual 0-M-R cost. These costs have in the past escalated at a rate which was not the same as for con- struction costs. Figure 5-52 shows the escalation of the O&M costs for a ten year period ending in 1976. This curve is based on actual costs for larger units l1] but may for the accuracy required be considered repre- sentative for this report. Figure 5-52 also presents two other curves based on government published data [11]. One is the Producer Price Index of Weekly Labor Earnings of Machinery Industry. The second is for the C. P. I. for Commodity Group 11-7, El ectri cal Machinery. In recent years the curve from [1] falls between the [11] curves which is reasonable as the O,M&R costs have both a labor and equipment cost component. It is recommended that any extr~polation reference .[1J data be based on the indices represented by reference [11] . There are two final comments to be observed in determining the operation and maintenance costs of hydroelectr-ic plant facilities. First, the total annual costs for operation and maintenance should never be est i- mated below a certain minimum amount, approximately $20,000 i_n 1978 dollars. Second, the multiplier given previously, 1.2 percent, should be used only if the owner can integrate the operation of the small hydro- power facility with other related operations. If the operating entity will operate and maintain only the small hydroelectric facility under consideration, a multiplier of two to four percent should be used to de- termine annual O&M costs. 5-25 Cost Summary Sheet Completing the Cost Summary Sheet, shown· in the Appendix (Pag~ D), provides a method for determining the cost to be used in the economic assessment estimate. The account numbers used in the Cost Summary Sheet are those designated by the Federal Energy Regulatory Commission for hydroelectric development. 5-26 -~. -' ---..... -J -,, I I --' r-i I ' ___ } ,---, I ---, L I ' _ _j ' ' I , l I L ••. --' Cost Item Slide Gate TABLE 5-1 Miscellaneous Costs (Cost July 1978) Cost Do 11 ars Tunnel, 7ft (2.1m) diameter steel lined Refer to Figure 5-2· 1,300 per linear foe (0.30m) Penstock Bifurcation See Figure 5-28 TABLE 5-2 Steel Penstock Minimum Thickness Thickness Maximum Inside Diameter Inches (mm) Inches (mrn) 0-.125 (3.2) 30 (762) 0.1875 (4.8) 55 ( 1397) 0.25 (6.4) 80 (2032) 0.3125 (7.9) 105 (2667) 0.375 (9.5) 130 (3302) 0.4375 (11.1) 155 (3937) 0.5 ( 12. 7) 180 (4572) 0.5625 (14.3) 205 (5207) 0.825 (15.9) 220 (5588) 5-27 Items Fixed Cost TABLE 5-3 Tailrace Cost (Cost Base July 1978) Additional Cost TABLE 5-4 SITE PREPARATION COSTS (Cost Base July 1978) Cost -Dollars 15,000 200 per linear foot ( 0. 30m) Access Roads Paved Single Lane Paved Two Lanes Unpaved Single Lane Single Span Bridge Cost -Dollars 125,000/mile (1.6km) 255,000/mile· (1.6km) 75,000/mile (1.6km) 50/ft 2 (0.09m2) Parking and Miscellaneous Site Features Parking Lot Paving Fencing Landscaping Environmental Control During Construction Noise, dust and Stream Turbidity Control 5-28 7/yd 2 (0.8m 2 ) 16/ft (0.3m) 2,800/acre (0.4 hectare) 10,000 I I --,, , __ _; • NOTES: 1. Estimated costs are based upon .a typical vertical Francis turbine direct coupled to the generator. 2. Costs include a turbine, synchronous generator, inlet valve, non speed regulating governor and installation. 3. Installation costs are estimated at 15% of the total equip~ent cost. 4. Add $60,000 for speed regulating governor. 5. For horizontal mounting, deduct 7% of cost. 6. Cost base is July 1978 . Figure 5-1 Francis Turbine Costs 5-29 .. NOTES: 1. Estimated costs are based upon a typical vertical Kaplan turbine with a concrete spiral case, direct coupled to the generator. 2. Costs include a turbine with adjustable runner blades and wicket gates, synchronous generator, speed r~gulating governor and installation. 3. Installation costs are estimated at 15% of the total equipment cost. 4. For a fixed blade propeller turbine deduct 10% of cost. 5. For a steel spiral case add 10% of the cost. 6. Cost base is July 1978. Figure 5-2 Vertical Propeller and Kaplan Turbine Costs 5-30 -, ! ! _) -, I I I •, i _, -, I •• --, i L __ .' •• TURBINE EFFECTIVE HEAD NOTES: 1. The estimated costs are .based upon a typical vertical propeller turbine, coupled to the generator through a speed increaser. 2. Costs include a turbine with fixed blade runner and wicket gates, synchronous generator, speed regulating governor, speed increaser and installation. 3. Cost base is July 1978 . Figure 5-3 Open Flume Turbine Costs 5-31 TURBINE NOTES: 1. The estimated costs are based upon a typical horizontal turbine of either the propeller type coupled to the generator through a speed increaser. 2. Costs include a turbine with fixed blade runner and wicket gates, synchronous generator, speed regulating governor, speed increaser, steel spiral case and installation. 3. Installation costs are estimated at 15% of the total equipment cost or $40,000 minimum. 4. For vertical units, add 7% of cost. 5. Cost base is July 1978. Figure 5-4 Closed Flume Turbine Costs 5-32 l '] • r NOTES: 1. The estimated costs are based upon a standardized tubular turbine. coupled to the generator through a speed increaser. 2. Costs include a turbine with adjustable runner blades and fixed guide vanes. inlet butterfly valve. speed increaser. synchronous generator. speed regulating governor and installation. 3. Installation costs are estimated at 15% of the total equipment costs. 4. For fixed blade units. deduct $27,000. 5. Cost base is July 1978. Figure 5-5 Standard Tubular Turbine Costs 5-33 NOTES: 1. The estimated costs are based upon a typical horizontal bulb turbine direct coupled to the generator. 2. Costs include a turbine with adjustable runner blades and adjustable wicket gates, synchronous generator, speed regulating governor and installation. 3. Installation costs are estimated at $250,000 for the large units, to $75,000 for the small units. 4. For fixed blade units, deduct 10% of total cost. 5. The cost of a rim turbine is approximately the same as a bulb turbine. 6. Cost base is July 1978. Figure 5-6 Bulb and Rim Turbine Costs 5-34 --I :-l ' ___ ) -' ' •• I } --- I l -' ... _. NOTES: .. 1. Th~ estimated costs are based upon a typical crossflow turbine coupled to the generator through a. speed increaser. 2. Costs include a turbine, synchronous generator, speed increaser, inlet valve, non speed regulatin-g governor and installation. 3. For speed regulatin~ goverhor, add $60,000. 4. Cost base is July 1978. Figure 5-7 Crossflow Turbine Costs ·. 5-35 TABLE A MW COST 0.2-0.5 25,000 0.5 -I .5 35,000 I .5 -3.0 45,000 3.0-7.0 60,000 7.0 -15.0 95,000 NOTES: 1. The equipment and systems for which costs are included are: a. D-C switchgear and batteries. b. Station service transformer and switchgear. c. Main control switchboard. d. Wire and cable system. e. Conduit system. f. Grounding system. g. Lighting system. 2. Costs include freight and installation. 3. Costs are shown for a single unit plant. 4. To determine costs for a plant with multiple units: a. Determine cost from curve for plant capacity. b. Subtract cost from Table A for plant capacity. c. Add cost from Table A for unit capacity times number of units. 5. Cost base is July 1978. ,I Figure 5-8 Station Electrical Equipment Costs 5-36 •. 0.2 0.3 0.4 0.5 0.6 0.8 1.0 2 3 4 5 6 7 8 9 10 POWER PLANT CAPACITY, M W NOTES: 1. The major miscellaneous power plant equipment is listed below: a. Ventilation equipment b. Fire protection equipment c. Communication equipment d. Turbine/generator bearing cooling water equipment 2. Communication equipment includes supervisory and radio factlities for unattended remote control of unit; further cost figures should be obtained for very remote locations or integration with complex communication networks. 3. All fig·ures shown include 15 percent for freight and installation. 4. Cost base is July, 1978. Figure 5-9 Miscellaneous Power Plant Equipment Costs 5-37 15 NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see figs. 4-18 and 4-29). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse structure. 4. Cost base is July 1978. Figure 5-10 Vertical Francis Turbine-Powerhouse Area and Cost 5-38 --:;~- ,- ,':.., NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see figs. 4-19 and 4-30). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse structure. 4. Cost base is July 1978. Figure 5-11 Horizontal Francis Turbine-Powerhouse Area and Cost 5-39 NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see fig. 4-20). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse structure. 4. Cost base is July 1978. Figure 5-12 Kaplan and Propeller Turbine -Powerhouse Area and Cost 5-40 \ . _ _J ' { .I I. ' 1: ! ; I -: -. ' N!JII:.S: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see fig. 4-21). 2. The cost estimate includes the reinforced concrete structute, concrete masonry superstructure, miscellaneous steelwork,- architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse and headworks structure. 4. Cost base is July 1978. Figure 5-13 Kaplan and Propeller Turbine-Powerhouse Area and Cost, with Headworks 5-41 NOTES: 1. Costs are for a single unit povJerhouse with a typical indoor arrangement (see figs. 4-23 and 4-32). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse and headworks structure. 4. Cost base is July 1978. Figure 5-14 Open Flume Turbine -Powerhouse Area and Cost, with Bypass 5-42 ' l i -I I I J 11 : _j ,-1 : I I __ J \ • •• NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see figs. 4-22 and 4-31). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse structure .. 4. Cost base is July 1978 . Figure 5-15 Open Flume Turbine -Powerhouse Area and Cost, without Bypass 5-43 NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see figs. 4-24 and 4-33). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse structure. 4. Cost base is July 1978. Fiaure 5-16 Tubular Turbine -Powerhouse Area and Cost 5-44 ] I i J i __ I ' -I . I I il I I I I Ill • li I I __ j NOTES: 1. Costs are. for a single unit powerhouse with a typical indoor arrangement (see figs. 4-25 and 4-33). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse and headworks structure. 4. Cost base is July 1978 . Figure 5-17 Tubular Turbine-Powerhouse Area and Cost, with Headworks 5-45 NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see figs. 4-26 and 4-34). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse and headworks structure. 4. Cost base is July 1978. Figure 5-18 Bulb Turbine -Powerhouse Area and Cost, with Headworks . 5-46 I -_) l -J ,· -l ·. j ~-, I I •• I ~~ ; I • NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see figs. 4-27 and 4-35). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous civil work required for construction of the power house. 3. The area shown is the plan area of the powerhouse and headworks structure. 4. Cost base is July 1978 . Figure 5-19 Rim Turbine -· Powerhouse Area and Cost, with Headworks 5-47 NOTES: 1. Costs are for a single unit powerhouse with a typical indoor arrangement (see figs. 4-28 and 4-36). 2. The cost estimate includes the reinforced concrete structure, concrete masonry superstructure, miscellaneous steelwork, architectural and other miscellaneous c iv i 1 work required for construction of the power house. 3. The area shown is the plan area of the powerhouse structure. 4. Cost base is July 1978. Figure 5-20 Crossflow Turbine -Powerhouse Area and Cost 5-48 I l --l :__I :-_ J ,---, . I ' _ _j -· NOTES: TAILWATER ELEVATION - N TURSI NE IMPELLER <t_ ] 1. The excavation costs are based on 50 percent common at $2 per cubic yard and 50 percent rock at $10 per cubic yard. The costs include a 10 percent allowance for backfil.l, compaction and grading. 2. The absolute value of nan, depth of the excavation, is generally more than the value of ndn shown in Figures 4-18 to 4-36, as the original ground elevation is usually higher than the design tail111ater elevation. 3. Cost base is July 1978. Figure 5-21 Powerhouse Excavation Costs 5-49 \ .... ,__. \ \ \• \ \ \ HOLD-DOWN LIPS RESIST SLIDING,UPLIFT AND OVERTURNING '" , I I I I I I I .APRON AND/OR CUTOFF WALL REDUCE SLIDING AND UPLiFT FORCES SHEAR KEY IN BOTTOM SLAB OR EMBANKMENTS RESISTS SLIDING HOLD-DOWN PILES RESIST SLIDING, UPLIFT AND OVERTURNING SUBGRADE DRAINAGE REDUCES SLIDING UPLIFT FORCES AND OVERTURNING :] '-, ; j DEAD-MAN ANCHORS-OR ROCK BOLTS' RESIST SLIDING, UPLIFT AND OVERTURN lNG Figure 5-22 Methods for obtaining stability against Sliding, Uplift and Overturning of the Powerhouse 5-50 NOTES: 1. The cost estimate includes excavation, concrete, reinforcing steel, trash rack, miscellaneous metal. No cost is included for an intake gate and operator. The gate and operator cost is obtained from Figure 5-24. 2. Cost base is July 1978. Figure 5-23 Intake Costs-Type "A" Project Arrangement 5-51 NOTES: 1. The cost curves include gate operators. 2. The estimated cost of the fixed wheel gate includes a 3000 psi hydraulic operating system consisting of a cylinder, pressure set, accumulator and installation. If an accumulator is not required deduct 25% from the installed cost of the gate and operator. For an electric gate operator deduct 40% from the installed cost. 3. Cost base is July 1978. Figure 5-24 Gate Costs 5-52 -, i • •• I NOTES: 1. Costs based upon m1n1mum handling thickness and a maximum net head of 65.6 ft (20m). 2. If the penstock gradient is greater than 15°, add 1% of total cost for each degree greater than 15°. 3. Costs include a steel penstock, supports, site clear1ng and excavation. 4. The cost of valves and bifurcations and anchor blocks are not included. 5. Cost base is July 1978. Figure 5~25 Steel Penstock Costs 5-53 NOTES: 1. The curves give the cost per unit length of a reinforced concrete box section culvert at net heads in the range 10 to 65.6 ft. (3 to 20m). · 2. Cost includes concrete, reinforcing steel, excavation 50% rock, 50% common), compacted backfill, foundation preparation, drains and f i 1 ters. 3. Costs are for a penstock flow velocity of 10 ft/s. 4. Cost base is July 1978. Figure 5-26 Concrete Penstock Costs 5-54 --, I I l - NOTES: 1. Maximum net head is 65.6 ft. (20m). 2. Cost Includes valve and operator. 3. The diameter d of the fixed cone valve should be calculated from: d ( in) = 5. 34 ~/2 H 1/4 ; Q ft 3 Is, H ft. or 4. Cost base is July 1978. Figure 5-27 Valve Costs 5-55 NOTES: 1. Costs based upon a maximum net head of 65.6 ft (20m). 2. The bifurcation cost must be added to the cost of the equivalent length of steel penstock. 3. Cost base is July 1978 . .......................................................................... · :. Figure 5-28 Penstock Bifurcation Costs 5-56 NOTES: 1. Costs include a butterfly valve, a Howell-Bunger valve, pipeline, excavation (assumed 80% rock, 20% common), foundation preparation, reinforced concrete structure, drains and filters, mi·scellaneous architectural features, rock anchors, miscellaneous metal, backfill and compaction. 2. Maximum net head is 65.6 ft (20m). 3. Upstream penstock bufurcation not included. See Fig. 5-28 for costs. 4. Cost base is July 1978. Figure 5-29 Bypass Facilities Cost 5-57 NOTE: Cost base is July 1978. Figure 5-30 Concrete Gravity Dams -Field Cost of Structure 5-58 - Figure 5-31 Earth Dams -Earthfill Volume [1 J 5-59 ' l -· .. NOTE: Cost base is July 1978. Figure 5-32 Earth Dams -Field Cost of Structure 5-60 I , I NOTE: Cost base is July 1978. •, ,.---------------------------------- Figure 5-33 Earth Dams -Field Cost of Spillway 5-61 NOTE: Cost base is July 1978 .. Figure 5-34 Earth Dams -Field Cost of Outlet Works 5-62 ~~ : I ~ --' , ' 1 I NOTE: Cost base is July 1978. I • Figure 5-35 Diversion Dam -Field Cost of Uncontrolled Spillway and Sluiceway 5-63 , I NOTE: Cost base is July 1978. Figure 5-36 Diversion Dam -Field Cost of Gated Spillway and Sluiceway 5-64 r I NOTE: Cost base is July 1978. • I Figure 5-37 Diversion Dam-Field Cost of Canal Headworks, discharging into Open Canal 5-65 NOTE: Cost base is July 1978. Figure 5-38 Switchyard Civil Costs 5-66 •. NOTES: 1. Equipment and material for which costs are included are: a. Generator voltage metal clad circuit breaker. b. Conduit and cable or bus duct from breaker to transformer (45 feet). c. Step-up transformer (except as noted). d. Line disconnect switch and fuses. e. Bus and in st,~lt ators. f. Line voltage potential transformers. g. Lightning arresters. 2. Costs include freight and installation., 3. The costs shown are for a single unit plant. 4. To determine the costs for a single unit plant use the appropriate curve based on the generator voltage, line voltage and capacity. 5. For multiple unit plants add $47,500 times (N-1) where N is the numbe'r of units. 6. For other line voltages, use the cost of the next higher voltage shown. 7. Cost base is July 1978. Figure 5-39 Switchyard Equipment Cost with Generator Voltage Circuit Breakers 5-67 NOTES: 1. Equipment and material for which costs are included are: a. Conduit and cable or bus duct from generator to transformer (45 feet). b. Step up transformer (except as noted). c. Line voltage circuit breaker. d. Line disconnect switch. e. Bus and insulators. f. Line voltage potential transformers. g. Lightning arresters. h. Auxiliary station service transformer and line termination. 2. Costs include freight and installation. 3. The costs shown are for a single unit plant. 4. To determine the costs for single unit plants use the appropriate curve based on the generator voltage, line voltage and capcity. 5. To determine costs for multiple unit plants use Figure 5-39. 6. For other line voltages, use the cost of the next higher voltage shown. 7. Cost base is July 1978. Figure 5-40 Switchyard Equipment Costs with Line Voltage Circuit Breakers 5-68 ,: i I I ' i •• NOTES: o::w O...J IJ...- :E 0:: wo:: -LLJ _JCl.. Cl.. ............ _J(f) ~0 :Eu 1.0 0.75 0_5 " " "" ' -........ """-......... --0 10 20 30 LENGTH OF LINE (MILES) 1. The cost per mile of transmission line should be adfusted according to the length of the line required using the multiplier shown above. 2. The estimated costs include wood poles, hardware, insulators, conductors, and construction roads. No clearing, land or right of way costs are included. 3. The estimated costs are based on single wood poles for the 5, 13.8 and 34.5 kV lines and wood pole H-frames for the 69 and 115 kV lines. 4. The estimated costs are for prairie type terrain with favorable foundation conditions. For foothill terrain add 10% of cost and for mountainous or swampy terrain add 30% of the cost. 5. For other line voltages, use the cost of the next higher voltage shown. 6. Cost base is July 1978 . Figure 5-41 Transmission Line Costs 5-69 NOTES: 1. Drainage systems include surface and subsurface systems. 2. Erosion control includes seeding, terracing, dikes, trenches and pipe spillways. 3. Use site area for grading and drainage. 4. Use area with slopes greater than 4:1 for erosion control. 5. Cost base is July 1978. •• Figure 5-42 Grading, Drainage and Erosion Control Costs 5-70 '--~ ___ ) • 3.00 2.00 1.00 3.00 2.00 1.00 3.00 2.00 1.00 X w 0 z 2.00 (f) a: a..: ~ 1972 73 74 7~ 76 77 78 79 80 81 1982 YEAR NOTES: 1. Water and Power Resources Service Construction Cost Indices for the 18 Western States for earth dam (complete) and components: structures, spillway, outlet works. 2. Cost Index shown is for July 1978 . Figure 5-43 Historical Cost Indices for Earth Dams 5-71 I. 0 0 ............................................................................................................................................................................................. ........ 3 .oo rn+m+1:r-m+mn++n+P~+r:r+:m+r+i+m+1=+m+rn+TI+W+H+I 2.00 1.00 3.00 X w 0 z 2.00 en 0:: a.: ~ 1.00 1972 73 74 75 76 77 76 79 80 81 1982 YEAR NOTES: 1. Water and Power Resources Service Construction Cost Indices for the 18 Western States for canals: earthwork and structures. 2. Cost Index shown is for July 1978; Figure 5-44 Historical Cost Indices-Canals 5-72 NOTES: X w 0 z U') 0:: a..: ~ 3.00 2.00 1.00 3.00 2.00 1.00 3.00 2.00 1.00 1972 73 74 75 76 77 78 79 80 81 1982 YEAR 1. Water and Power Resources Service Construction Cost Indices for the 18 ~~estern States for conduits, 1 aterals and drains, earthwork and structures. 2. Cost Index shown is for July 1978. Figure 5-45 Historical Cost Indices -Miscellaneous 5-73 3.00 2.00 1.00 3.00 2.00 1.00 3.00 X w 0 z 2.00 CJ") 0::: a.: 3: 1.00 1972 73 74 75 76 77 78 79 80 81 1982 YEAR NOTES: 1. Water and Power Resources Service Construction Cost Indices for the 18 Western States for hydroelectric power plants: building and equipment, structure and steel penstocks. Figure 5-46 Historical Cost Indices -Hydroelectric Plant, Structures 5-74 • X w 0 z U) 0: cL ~ NOTES: 3.00 200 ' 1.00 3.00 2.00 1.00 3.00 2.00 1.00 '•. 1972 73 74 75 76 77 78 79 80 81 1982 YEAR 1. Water and Power Resources Service Construction Cost Indices for the 18 Western States for Hydroeletric plants: turbines and generators, accessory electrical and miscellaneous powerhouse equipment and concrete pipelines. ~ 2. Cost Index shown is for July 1978 . Figure 5-47 Historical Cost Indices -Hydroelectric Plants, Equipment 5-75 3.00 2.00 1.0 0 3.00 2.00 1.00 3.00 X w 0 2 2.00 CJ) 0:: a.: ~ 1.00 1972 73 74 75 76 77 78 79 80 81 1982 YEAR NOTES: 1. Water and Power Resources Service Construction Cost Indices for the 18 Western States for electrical equipment: switchyards and substations, wood pole 115 kV transmission lines, poles and fixtures, conductors and devices. 2. Cost Index shown is for July 1978. Figu~e 5-48 Historical Cost Indices -Electrical Equipment and Transmission Facilities 5-76 . -, I '' -f NOTES: X w 0 z (/) 0::: a.. 3.00 1.00 3 . oo P+=~m:::T:=lS-=T=::r.::r::;++:p::p::r.::;:r I. 0 0 L..W...:...:...!.J..w....W..U~W...W...:...i.-'-.W..:...._;,_w.....w..J. 3 . 0 0 ..,..;•y•,..,..,..,c··r·y.,....,..,. 2.00 I. 0 0 J,.i-l-W.....J.,.,.W...L.i..L;...LW .. l-W..W. . .J...:....W...i.i.1.).. 3.00 ~~~~~~~~~~~~~--~~--~----- ~ I .00 ~~~~~~~~~~~~~~~~~~~~~~~ 1972 73 74 75 76 77 78 79 80 81 1982 YEAR 1. Water and Power Resources Service Construction Cost Indices for the 18 Western States for general property, primary roads, secondary roads, steel bridges. 2. Cost Index shown is for July 1978. Figure 5-49 Historical Cost Indices-General Buildings, Roads and Bridges 5-77 3.00 2.00 1.00 3.00 X w 0 z 2.00 Cf) a: a..: 3: 1.00 1972 73 74 75 76 77 78 79 80 81 1982 YEAR NOTES: 1. Water and Power Resources Service Construction Cost Indices for the 18 Western States for concrete dams and diversion dams. 2. Cost Index shown is for July 1978. Figure 5-50 Historical Cost Indices -Dams 5-78 --, I • -[ __ --~, [~-: i : '; I Figure 5-51 Construction Cost Variation .in the United States 1f[]J [J)(Q)~ 5-79 Figure 5-52 Operation, Maintenance and Replacement Cost Index 5-80 _j I j J I I -) I J . I GENERAL SECTION 6 FINANCIAL ANALYSIS Financial feasibility quantifies a project•s ability to obtain funds for implementation and repay these funds on a self-liquidating basis. For a project to be feasible, the anticipated project receipts must exceed the project disbursements, funds must be available, and the project must be able to service the debt. These items depend on the project•s characteristics, the sponsor and purchaser, the requirements of those providing funds, and the overall credit market as it affects the cost of borrowing. An important part of establishing financial feasibility is the anticipated borrowing cost. The cost of capital is the return expected by potential investors and other market and economic costs. The costs are the sum of the real interest rate that compensates the lender for surrendering the use of funds-, the purchasing power risk premium that compensates for expected inflation, the business and financial risk. and the marketability risk associated with low-liquidity of long-term debt. ANNUALIZED COST Genera 1 To compare costs which occur over a period of time and in varying amounts of expenditure it is necessary to have a common time basis. This is ob- tained by reducing each expenditure to an equivalent uniform annual series of payments (debt service). The largest item of the annual cost for the new project is a function of the initial capital cost. The magnitude of this cost is re 1 a ted to the 1 i fe of the project, type of financing, and the interest rate of the money used for the project 6-1 construction. The annual cost for repayment of the construction cost which may be called a capital recovery factor [12], crf. crf = i(l + i)n (6-1) (1 + i)n -1 Where i is the annual interest rate, percent n is the payment life, years It is not necessary for the reader to compute the crf given by equation 6-1 as financial tables are available [13] which include all normal interest rates and for time periods extending over a 100 years. The annual cost for financing the construction cost then becomes: Annual financial cost = Total construction cost x crf As an example, if the original construction cost was a million dollars and the loan or bond repayment period was assumed to be 40 years with financing to be made with money at 6 percent, the annualized cost for this item would become: The crf for 6 percent and 40 years is = 0.06646 Annual financial cost = 1,000,000 x 0.06646 = $66,460 Other items included in the financial cost analysis are operation and maintenance, administration and replacement. The amount of these items are generally estimated at the time of making an economic assessment of the project. Dependent upon the owner 1 s practices, other items may be included such as insurance, taxes, etc. Any of the foregoing items may be assumed in the analysis to be constant or escalated to include effects of inflation dependent upon the owner 1 s practices. 6-2 Each item included in the annual cost analysis is regarded to be either a constant value for the life of the project or treated as an equivalent uniform annual cost by using a uniform series of annual payments reflect- ing the life of the project and the cost of money. If the owner finances the project from internal funds then the annual cost is based on a required rate ~f return rather than the interest rate of borrowed money. GENERAL FINANCING METHODS General An investor-owned project may be financed, but not limited to, bonds preferred stock or common stock. There are many types of bonds which specify the callability and refunding of the bonds. The bond holder does have the first priority on the assets of the· firm in any liquidation action but does not have a vat i ng power on the firm 1 s operation. The cost of the borrowed money, interest on the bond~ is related to the financial strength of the firm and the relative amount of prior bond issues. The interest rate could be as much as fifty percent higher than a public entity would pay for the same type of project. Preferred stock that may _be issued by an investor-owned utility is lower in priority to corporate assets than bonds in a liquidation proceeding. The interest paid may be more or less than the bond inter·est dependent upon the strength of the corporation, the corporation 1 S financial structure and the financial market. Some preferred stock issued have voting power and some don 1 t. Common stock issued by the investor utility has a variable rate of interest and a voting power in the company operation. An investor-owned utility would not issue bonds, preferred stock or common stock for starting construction of any small low-head hydroelectric project. Their request to the money market is made at intervals that the corporate finance managers believe is prudent to augment their cash flow for all current construction and operational 6-3 needs. The type of funding requested, bonds, stock, or short term 1 oan, is based on the corporate financial structure, debt ratio, and financial market conditions. Accordingly, the interest rate used in determining the annual cost of the construction cost is a variable which is a composite of the financial costs of outstanding bonds, stocks and any other financial burden which may be in effect during the construction period. The two most common methods of borrowing by a public entity is by use of either general obligat)on bonds or revenue bonds. The general obligation bond is secured by the taxing power of the entity issuing the bonds. If at any time the revenue from the project is inadequate to cover the bond repayment and all other annual costs, then the entity may take steps by imposing a tax or increasing the taxes to make up the deficiency. As the genera 1 ob 1 i gat ion bond is a 1 ega 1 ob 1 i gat ion on all property owners within the entity, approval of the voters must be obtained for issuance of this type of bond. · Revenue bonds may be restrictive in that their security for bond repayment is dependent upon the revenue of a single project. If the revenue bond is of the general type then the repayment is obtained by marketing revenue of the entity. Revenue bonds must also be approved by the voters in the entity but approval is at a lower rate than obligatory bonds, generally only a simple majority. There are instances whereby revenue bonds may be issued solely on the authority of a governing body, such as a Board of Directors, and property owners approval is not required. As prepayment of the revenue. bonds is not secured by the entities• taxing power, but only by the revenue from the budget, then the margin of safety required for bond repayment is high to insure against unforeseen adverse conditions. It is usual that all public entity bonds are tax free, that is the interest received by the bond holders is exempt from federal income taxes and state income taxes in the state of issuance. There are occasions 6-4 where the energy may be partially or entirely sold to a commercial user. Under these conditions often the tax free status of the bonds will be applicable to only a portion of the bonds sold. The reader must review the laws, regulations and constraints governing the tax free status of an entities bonds prior to estimating the financing cost of the hydroelectric development. This tax exempt feature for those entities having a good credit rating enab 1 es borrowing funds at a lower rate than that obtainable by either the federal government or private enterprise. Debt Service Interest Rate The debt service is the annual cost for repayment of the financial obligation assumed by the owner for the project construction costs. The interest rate on the borrowed money is a function of ·whether the project owner is a public entity or it is an investor-owned project. Financing by a public entity is usually at a lower interest rate than for an investor-owned project. Debt Service Repayment Period The life of a small hydroelectric project may be determined by either the length of time before expiration of the project license or equipment life, which ever is the shortest time. Equipment life may be taken as 50 years un 1 ess the owner 1 s experience indicates another va 1 ue. There may be conditions for the sale of bonds of a public entity which dictate a shorter repayment period. Normally the bond repayment period will vary from 25 to 40 years. The time value used by an investor-utility will generally be either the expiration of the operating license or equipment 1 if e. FINANCIAL ALTERNATIVES. General ---- There are possibly five methods of financing a small hydroelectric development. The developer may have more than one of these methods available for financing dependent upon the status of the developer, that 6-5 is, the type of public entity, a private or investor-owned utility. These financing methods include the following: o DOE Loan -Public Utility Regulatory Policies Act, Public Law 95-617 o WPRS Loan, Small Reclamation Act of 1956, Public Law 984 o Taxable Revenue Bonds o Tax-exempt Revenue Bonds o Internal Cash Flow With the federal government funding a loan the money is granted in the early stage of development and prior to start of construction. This money is available as required throughout the construction period. When bonds are issued for the development the bonds are issued prior to start of construction for the total construction costs. 1The proceeds from the bond issue are then invested on short term basis untii required by the construction progress payments . • DOE Loans The DOE loans are made possible by legislation entitled 11 Public Utility Regulatory Policies Act 11 , Public Law 95-617. Section 403 of this act authorizes the Secretary of Energy to make loans to any municipality. electric cooperative, industrial development agency, nonprofit organization, or other person of up to 75 percent of the project cost of a small hydroelectric power project. One loan requirement is that the project will be constructed in connection with an existing dam or dams. The loan repayment period shall not exceed 30 years with the interest rate being at the prevailing federal discount rate. This rate is currently 6-5/8 percent (FY 78}. This act further defines the size of small hydropower as being not more than 15,000 kW installed capacity. 6-6 WPRS Loans The WPRS loans are made under the 11 Small Reclamatons Act of 1956 11 , Public Law 984 (PL-984). This act provides funding for eligible multiple purpose water resource projects. The loans are long-term and the repayment period can extend to 40 years. Each fiscal year the interest rate is established by the Treasury Department. This loan repayment / interest rate is 6-1/8 percent (FY 78). Repayment that is generally made would be from the project power sale revenues. This particular source of funding has not previously been utilized to fund hydroelectric projects, but the original act plainly authorized such a use as long as the project was multi-purpose with some irrigation benefits. The WPRS has defined such a project as eligible, as long as a minimum of 5 percent of the total project cost is for irrigation. Loans of this type are only applicable for developments west of the Mississippi River. Taxable Revenue Bonds . The use of taxable revenue bonds is a conventional source of funding by many public entities. Federal tax laws currently provide that, if the power 'from the project is purchased by an investor-owned utility, up to $1,000,000 of bonds can be sold that are exempt from federal income tax. Under this condition it is currently estimated that such bonds could be sold at an interest rate of seven percent. Bonds for the amount in excess of $1,000,000 are subject to federal income tax and would carry an interest rate of about ten percent. The term of both the tax-exempt and the taxable bonds may be up to 40 years. To be sold as revenue bonds the power purchaser must pledge to retire the bonds. This pledge could be provided for in the power purchase agreement which is negotiated with a po"wer purchaser pior to the bond sale. Tax-Exempt Revenue Bonds The use of tax-exempt revenue bonds for funding may be used if the power purchaser is a public utility district. Currently bonds of this type 6-7 would have an interest rate of approximately six percent. Normally the repayment period for a bond issue of this type is up to 40 years. Internal Cash Flow A private utility would fund the hydroelectric development by internal construction costs of a small cash either available or made available by short term loans or sale of securities in the money market. FINANCIAL ANNUALIZED COST Genera 1 Each of the previously discussed financial alternatives will result in a different annualized cost which is chargeable to financing the hydroe 1 ect ric deve 1 o pment. the following examples. identical for all cases. For simplification an assumption is made for This assumption is that the loan amount is The total construction cost which must be funded always includes the interest during construction. In the several financial alternatives discussed the interest during construction may not necessarily be the same for all alternatives. The loan amount is assumed to be $5,388,000. If bonds were used as a method of financing, the bond issue would be for this amount. A private utility would consider this amount as required from its cash flow. In this section the term 11 annual cost 11 includes only the financial charges. When an economic assessment is made for the project the project annual cost includes additional indirect and direct costs. 6-8 j ' J DOE Loan A DOE loan can be used for 75 percent of the required funding, tax-exempt bonds are million dollars and the balance of the funding would be by normal revenue bonds. Assume the following interest rates: Government loan, 6-5/8 percent Tax-exempt bonds, 7 percent Revenue bonds, 10 percent Government loan, 30 yr at 6-5/8 percent crf = 0. 07757 Annual Cost = 4,040,000 x 0.07757 = $313,400 Tax-exempt bonds, 40 yr, 7 percent, crf=0.07501 Annual Debt Service = $1,000,000 x 0.07501 = $75,000 Revenue bonds, 40 yr, 10 percent, crf=0.1023 ' Annual Debt Service = 348,000 x 0.1023 = $35,600 Total annual cost of financing = $424,000 For 6 percent discount rate the present worth of this alternative is $5,978,000. Taxable Revenue Bonds Tax-exempt revenue bonds in the amount of one million dollars may be issued and the balance of the funding by taxable revenue bonds. Tax-exempt revenue bonds, 40 yr, 7 percent, crf=0.07501 Annual Debt Service = 1,000,000 x 0.07501 = $75,000 6-9 Revenue bonds, 40 yr, 10 percent, crf=0.1023 Annual Debt Service = 4,388,000 x 0.1023 = $448,900 Total annual cost of financing = $523,900 For a 6 percent discount rate the present worth of this alternative is $7,882,800. Tax-Exempt Revenue Bonds Entire funding may be accomplished by issuance of tax-exempt bonds for a 40 year repayment period. Tax-exempt bonds, 40 yr, 7 percent, crf=0.07501 Annual Debt Service = $5,388,000 x 0.7501 = $404,200 Total cost of financing = $404,200 For a 6 percent discount rate the present worth of this alternative is $6,081,700. WPRS Loan There is a WPRS Small Projects Loan Program for multipurpose projects and if one of the project purposes is power development a government loan may be obtained for the funding. The repayment period for this type of loan can be up to 40 years. Government Loan, 6-1/8 percent, 40 yr, crf=0.06751 Annual Debt Service = $5,388,000 x 0.06751 = $363,700 Total annual cost of financing = $363,700 6-10 For a 6 percent discount rate the present worth of this alternative is $5,472,300. Internal Cash Flow Assume a private developer has a rema1n1ng time of 45 years before the project license expires. The developer elects to have the construction costs funded prior to elapse of license and also requires an 8 percent return on the investment. A 45 year funding period, 8 percent interest crf = 0.08259 Annual Debt Service = $5,388,000 x 0.08259 = $445,000 Total annual cost of financing = $445,000 For a 6 percent discount rate the present worth of this alternative is $6,877,800. Annual Debt Service as Related to Financial Feasibility The debt service payments plus other escalating and constant annual costs are then summed to estimate total annual cost through the project financing period. Total annual cost divided by average energy production yields the expected cost of power generation. A brief example of a municipal utility project is presented to illustrate the method. Assume: o Completed cost equals $6,000,000 o Annual O&M in the first year of operation equals $135,000 o Cost of financing is approximately 6 percent o 30-year financing period 6-11 Then the capital recovery factor is crf = .07265 and annual debt service is aproximately $435,900. Table 6-1 shows the results of the cost-of-service calculations. Over the 30-year financing period used in this example, the cost of service approximately doubles. Over this same period, the value of energy--which was close to the original cost of services and escalated at the same rate as O&M--increased by a factor of .about five. This example illustrates how infla~ion will generally enhance the project 1s long-run annual value. Occasionally, it may be desirable to convert the escalating cost of service into a levelized cost. This can be accomplished by discounting and summing the cost of service stream to the first year of operation and then calculating the constant annual cost, which is equivalent to the summed costs. Since the procedure would only be used to compare the cost of the hydro project to· an alternative available to the power purchaser, the appropriate interest rate to use in these calculations is the weighted average cost of capital to the power purchaser. If the lev- el ized cost of the hydro plant is less than the cost of the pm'ler pur- chaser1S alternatives, it should be possible to negotiate a marketing agreement that allows project implementation. 6-12 YEAR OF BONO OPERATION AMORTIZATION --------------------- 1 $435, '300 2 435, •:KJO 3 435,900 4 435,900 5 435,·:.oo f. 435,•300 7 435,":100 8 435, '300 9 435, ·:;oo 10 435, ':lOJ 11 435,'300 12 435,900 13 435, '?0) 14 435, ·:.oo l5 435,'300 16 435, '300 17 435, ·:.oo 18 435,·300 1'3 '•35, '300 20 435,'300 21 435, ';)00 22 435,·:.oo 23 435, ·;,oo 24 435, ·:;oo 25 435,';)00 2E. 435, '300 27 435,"300 28 435,":.00 '2'3 435,"300 30 435,900 --------------------- TABLE 6-l COST OF SERVICE CALCULATION CONSTRUCTION COST, $6,000,000 FINANCING, 30 YEAR, 6 PERCENT FIRST YEAR 0 & M COST, $135,000 ANNUAL ESCALATION OF 6 PERCENT AVERAGE AI\.'NUAL OPERATION lie TOTAL ANNUAL ENEHGV PRODUCTION rr'.A I NTAt.r.::NCE COST <MILLIOt.J'-3 OF KWH) ----------------------------------------$135,000 $570,'300 22.500 143, 100 57"3,000 22.500 151 '(;.:Jt; 587,58(; 22.500 lE.O, 787 5%,f.87 22.500 170, '•34 f.OE., 334 22.500 180,GE·O E.1E., se.o 22.500 1'31, :iOO (.27' 400 22.500 202,·:;·::o e.:;n, a·3o 22. ~.oo 215, 1E:3 (.51' 06'3 22.500 228,07'3 f.E-3, '37'3 22.500 241. ,.~.4 677, E.E.4 22.500 25•::.~270 E.'32!1 170 22.500 271 "E-45 707!154€. 22.500 287~'345 723,845 22.500 305,222 .741' 122 22.500 323,535 75'3,435 22.500 3Li2, •:,!+7 778,847 22.500 363,524 7';)'3,424 22.500 385,335 821 ,2~;5 22.500 408,455 844,355 22.500 432,'3£.3 8~.8,8<:.3 22.500 458,"3'•1 8'?4, 8Lf1 22.500 486,477 '322,377 22.500 51S,E.E·6 '351, SE·E· 22.500 St..E., 606 '382,506 22.500 57'3,402 1,015,302 22.500 614,1E.G 1, 050, OE.f:. 22.500 651 '01€. 1, osc,-:H6 22. ~.oo €:30,077 !,125,"377 22.500 731,482 1,167,382 22.500 ---------------------------------------- 6-13 I COST OF SERVICE VALUE OF ENERGY (CENTS/KWH) <CENTS/KWH) ------------------------------- 2.537 2.500 2.573 2.E.SO 2. f.ll 2.80'3 2.E.Sl 2.9.77 2.E::t4 3.15Eo 2.740 3.345 2.788 3.54G 2.83'3 3. 75'3 2.8'::.3 3.·:•&4 2. '351 4.223 3.011 4.477 3.076 4.745 3.144 s.o:::o 3.217 5. 33.~. 3.2':!3 5. E.S2 3.375 s.-:.·:.1 3. 4E.l f .• 350 3.552 c .. 731 3. E-4':1 7.135 3.752 7. SE.3 3. SE·l 8.017 3.';)77 8.4'38 4. o·?r3 •;).00"3 4.22'3 ·:..54'3 4. 3f.6 10.122 4.512 10. 72':t 4.f.f.6 11.373 4.830 12.055 5.004 12. 77'3 5.188 13.545 ------------------------------- GENERAL SECTION 7 ECONOMIC ANALYSIS Economic analysis deals primarily with the development and application of quantitative procedures for evaluating project economic feasibility. The most . commonly used procedure is benefit/cost analysis. It is the objective of this section to outline how benefit/cost analysis can be used to perform an economic analysis of a small low-head hydroelectric ·installation. The objective of this type of analysis is to .relate all project economic benefits to all project economic costs. The appropriate scope of the analysis (the benefits and costs that· should be included) depends on the nature of the sponsoring organization. For example, the project•s initial and. annual costs and annual revenues are important components of the economic analysis; however, depending on the nature of the sponsoring organization (private or governmental), other benefits and costs could be included. These include secondary costs and benefits which may result from the project but would not be included in the financial analysis of the project. PROCEDURE The economic evaluation of any power project is basically a comparison of the benefits and costs over the project 1 ife. The benefit/cost ratio becomes the principal item in the economic analysis of the small low-head hydroe 1 ectric projects. . It is necessary to determine each item in the ·benefits and cost in similar units. Benef.its may result from: o The presence of firm capacity and energy which allows other power projects to be deferred, thereby establishing a value for the capacity and energy of the plant 7-1 o By realizing a saving of fuel costs in thermal generating plants: or o By actual replacement of energy that the project owner may be purchasing from others Unless the project conditions meet the dependable capacity_ (firm capac- ity) criteria discusssed in Section 3 then these small low-head hydro- electric projects should be regarded as providing only benefits for ener- gy to replace fuel for thermal plants or for use by the owner. These small plants will not normally contribute to flood control, recreation, fish and wild life or similar non-power production benefits. The costs involved for the typical, single-purpose small hydro project are then only those costs which .are directly associated with power production. However, if there are some unusual factors where there are other benefits which may be associ a ted with cost i terns, then these may be inc 1 uded in the analysis. In this latter case each feature would carry its own costs, including a portion of the construction costs. The benefit portion of the analysis is made up of the present value of future benefits resulting from the project. The cost portion of the analysis is composed of the present value of the original cost and any future cash expenditures which go into the cost of the project, such as costs for rep 1 acement, operating and rna i ntenance. Esc a 1 at ion or inflation may or may not be included in the benefit/cost analysis, dependent upon the project owner•s practice. The comparison of benefits and cost may be made using either an annualized or present value method of cost analysis. 7-2 ANNUAL OPERATING EXPENSE General The annua, l operating expense consists of the annual cost for operation. maintenance, replacement, taxes and insurance. This expense can vary and is a function of, but not limited to, equipment size and type, labor cost, plant usage, mode of plant operation and plant location. Operation A significant component of the ope rat ion cost can be for labor. Opera- tional labor costs include supervision, engineering, secretarial work for supervisory personnel and other personnel directly involved in the operation of the plant. If the plant is attended, the direct operating labor charges will be higher than for an unattended plant. An unattended plant can either be operated by a roving operator which may operate several plants or by personnel from a nearby plant where the unattended plant is a secondary assignment. Operation costs also include any cost of water used for energy generation. These costs may be· a function of either the license agree- ments or permits from any governmental agency or payments made to the. owners of the water. Occasionally, there may be costs for cloud seeding and headwater benefits payable to others which are all included in the operating costs. Any labor costs involved with the waterways such as removing trash from the intake, patrolling the reservoir, breaking up ice or log jams and operations relating to conservation of fish, forests, etc, are all considered as operating costs for the hydroelectric plant. In addition to labor costs there are many miscellaneous items that are included in the operation cost. These items include, but are not limited to, lubricants, general operating supplies (gaskets, packing, office forms, etc.), first aid supplies and safety equipment. If any of the 7-3 property directly associated with the energy production is rented, then this rent is an operational cost. Maintenance The maintenance includes all the labor costs and expenses for the general supervision, engineering and direct labor for maintaining and repairing the equipment used in the electric energy generation and the structures housing the equipment. On the small hydroelectric plant the maintenance may be assigned to a few individuals for routine type of work and the major overhaul work accomplished by a large maintenance crew. It is usual to have a major overhaul on an annual basis, however, the small low-head hydroelectric plant major overhauls should be at more infrequent periods. The frequency of major overhauls is a function of the operating conditions, condition of water used and equipment design. Conservatively rated equipment operating under non-cavitating conditions on the turbine and water free from silt and sand, will afford the maximum time between major overhauls. G~nerally it is the hydraulic turbine that requires the most maintenance work. Replacement Normally the major components of the main unit, turbine/generator, will not be replaced during the life of the project. Parts of the turbine may be replaced during the turbine life. These parts would include bearings, wicket gates, wear rings and face plates. Generator bearing and windings are items that might be replaced during this period. Many pieces of auxiliary or supporting equipment may have to be replaced at least once during the project life. Frequently, this results from the equipment item becoming obsolete and replacement parts not being available. Replacement is then less costly than fabricating special parts. Normally, a sinking fund is established for the replacement cost of major and costly equipment items. 7-4 Taxes and Insurance Insurance is generally required to protect against damage due to fire and storm, vandalism, and property and public liability. The amount of in- surance coverage taken is a function of the owner•s policy in this matter. The guidelines of the then FPC in a 1978 document entitled 11 Hydroe lectri c Power Eva·l uat ion.. stated the estimated cost of insurance on a hydroelectric dam, expressed as a percentage of the fixed plant in- vestment, was 1/10 of one percent. It is suggested by [14] that for small low-head hydroelectric plants this amount is insuffiGient and believes it is at least ten times this amount. The reader should review the probable liability costs of facilities downstream of the hydroelec- tric development and determine if the commonly used value of 0.2 percent will result in adequate insurance coverage. Public uti 1 it i es are not required to pay property taxes, however, in certain cases payments in lieu of taxes may be provided. Private utilities wi 11 pay annual property taxes based on the projects assessed valuation and the tax rate. Impact of Annual Cost on Load Factor To determine the ef~ect of plant utilization on the various components of annual costs, it is necessary to have the cost components as a function of the same unit. Mills per kilowatt hour is the common production unit that can be used for this determination. Some unit cost items~ for example maintenance labor and material, will increase with a higher utilization factor (load factor) as there is more wear on the equipment, more frequent overhauls and replacements. There are other costs which are fixed regardless of the plant prodUction. For these fixed costs, the greater the utilization factor (larger annual kilowatt hour production), the lower the unit cost becomes. Dependent upon the relative magnitude of the operating costs that increase with an increase load factor and the fixed costs that decrease with an increase in load factor, the total annual cost per unit of production could either increase or decrease. Figure 7-1 illustrates these concepts. 7-5 INFLATION Escalation in the market value of power and project costs will occur over the life of a project. This escalation in price levels is composed of two components: inflation, or generalized price level increases, and the real price increases due to shifts in supply demand relationships for commodities. Real price increases cause some items to escalate more rapidly than others. For examP.le, construction costs have increased at a substantially greater rate than the inflation rate in recent years. This is also true of energy values. In some cases, it may be desirable to escalate various cash inflows and outflows at different rates. This decision must be based on judgment about the project at hand, anticipated changes in the general economy, and the anticipated future real price increase in the value of energy. If inflation is explicitly included in the economic analysis, the future benefit and cost streams must be escalated by the expected inflation rate. This is done by using the formula for calculating the future value of a present sum and replacing the expected inflation rate in the place of the interest rate. This is done by the following manner: CX = CO ( l+e)X · Where Cx = cost or benefit in x years in the future C0 = current cost or benefit x = years in future e = annual inflation rate 7-6 (7-1) ' -, ' ' _) VALUE OF.ENERGY General The economic value of small hydro output is the cost of an alternative energy source. Accordingly, the value of energy is not the same for the developer/energy user as it would be for the utility purchaser. The financial value of the energy is usually determined from negotiations between the developer and the purchaser. In some states, posted purchaser prices may be available thus eliminating negotiations. There are certain fundamental considerations which do affect the value of energy, especially to the purchaser. ../ If the energy is dependable, that is always available, especially during the purchaser•s peak load period, then this energy has a capacity value. The basis for determination of the capacity value to the purchaser, is the purchaser•s cost saving in either not constructing other generation plants or postponing the construction of plants. For plants without capacity, the energy developed by the small hydroelectric plant will replace the energy produced by the purchaser•s most costly fossil fuel unit required to meet the system•s load requirements at the time the energy is available. The selling price of energy is of interest to' the developer· in their financial analysis. The price must be sufficient to meet the developer•s cash flow criteria for viable projects. TYPICAL POWER AND ENERGY DEMANDS Genera 1 A characteristic of any electrical system is the inability of the system to store energy. As a consequence of this, any demand on the system requires that immediately an equal amount of generation must be sustained until the demand ceases. The generating plants must, therefore, provide the required capacity and energy as demanded by the consumer. 7-7 Examination of demand characteristics of most systems shows that the predominant pattern of demand (and generation) is repeated on a daily basis. Imposed on this daily pattern are variations due to weather, season, holidays and industrial events. In most systems, therefore, the daily load curve is the basis of system planning. Useful definitions that may be applied to power systems. are: Load Factor is defined as the ratio of .the actual average load over a period of time (daily, weekly, monthly or yearly) divided by the maximum load occuring during that period. This concept may be applied to the whole system, part of a system, or the load on a plant or .unit. Demand is defined as the load of a system (or part of a system) at a specified time. Diversity Factor . is .defined as the ratio of the sum of the individual maximum demands of the various parts of a system to the maximum demand of the whole system. The demand on an electrical system may be shown in a number of ways suitable for power planning studies: (1) Daily Load Curve This curve is a plot of system load against time, usually over a period of 7 days and indicates the typical variation during the hours of the day and the variation of load between week days and Saturday and Sunday (Fig 7-2). 7-8 i J (2) Load Duration Curve If the above load curve ordinates are rearranged in descending order, the curve shows the variation of load with time without regard for-the sequence of the loads (Fig 7-3). (3) Yearly L~ad and Ener:gy C_urves This curve may be used to illustrate both the load and energy patterns occurring in a particular year or the variations in load over a number of years. Where the system is rapidly expanding, a semi-log plot of the demand will show the exponen- tial growth as a straight line. If required, the monthly load factor can also be plotted as shown in Fig 7-4. The demand for energy has seasonal, temporal, and location components. The seasonal component is affected by climate conditions while the temporal component is affected by both daily and yearly fluctuations in energy needs.. The location component has to do with the wide range of climatic conditions that occur in different regions of the country. The characteristics of these components are explained in greater detail below. Daily Characteristics As previously discussed, most systems show a marked variation in load on a daily basis. The energy habits of the consumers usually results ·in a steady drop in load from about 10 pm to a minimum demand at approximately ( 4 am. The load then starts to increase with increasing steepness to a maximum which may occur any time from 9 am to 9 pm. When domestic heating is a large proportion of the load, the maximum load usually oc- curs· between 5 pm and 7 pm during a winter month. vJhen summer air condi- tioning is a large proportion of the load, the maximum usually occurs between 2 pm and 4 pm. The characteristics of the industrial load may also distort these daily patterns and to some -extent modify the daily load pattern which occurs during Saturday and Sunday. 7-9 Monthly Characteristics Seasonal temperature variations obviously exert a major influence on the electrical load curve. Electrical systems located in the higher latitudes usually show the maximum demand in winter. Those in warmer climates with a l9.rge air conditioning component show a maximum demand in summer. Irrigation pumping during the irrigation season can also markedly influence the peak system demand. Yearly Characteristics. A dominant yearly characteristic in most electrical systems over the last 30 years has been the steady increase of both capacity and energy demand, at rates, in some areas, of up to 10 percent per annum. To meet this increase in capacity demand, power projects must be initiated anywhere from 3 to 10 years in advance of the •on line• date in order to meet system requirements. Regional Characteristics Figure 7-2 shows a plot of daily load curves for the month of August for representative systems in the following areas: Northern California Area Southern California Area Rocky Mountain Area Northwest Pacific Area Southern Central Table 7-1 also shows the time of occurrence of maximum and minimum loads within these systems. The impact agricultural demands may be detected of climatic, industrial and in these load curves. Many companies artificially raise their system load factor by negotiating contracts for dump energy. 7-10 Power Planning Data Sources The main source of data showing generation patterns for the various elec- trical systems in the U.S. is the Federal Energy Regulatory Commission (FERC). Regional offices normally have on file detailed information on the systems within their jurisdiction. Valuable information may be obtained from each utilities annual Power System Statement submitted to the FERC stating their system load characteristics on a monthly basis. Also daily system load data are given for the first full week in April, August and December. BENEFIT/COST ANALYSIS General Benefit/cost analysis is an economic analysis whose, product is a ratio that can be used to determine if a project is economically feasible. A ratio in excess of 1:1 indicates a project will return a 11 profit.11 On the other hand, a ratio less than 1:1 indicates the reverse--the proposed project would lose money. In symbolic form, the benefit/cost ratio is generally expressed as: Where: · B - B B/C -"R+0 present value of a stream of annual benefits. K = dollars of initial cost. 0 = present value of all annual costs that will be required through the project•s life. (7-2) The choice of a discount rate (the rate used to convert future dollar strea~s of benefits and costs into today•s dollars) is influenced by such 7-11 factors as the market rate of interest, risk, price fluctuations, length of life of the project, and source of funds. For Federal projects, the discount rate is set for each fiscal year by the Treasury Department. Figure 7-5 indicates the impact that different discount rates would have on the benefit/cost ratio. Note that as the discount rate increases the benefit/cost ratio declines. The actual rate of decline depends on the magnitude and timing of the benefits and costs associated with a particular project. The fact that the discount rate and benefit/cost ratio are inversely related can be used to test the economic feasibility of a project under different discount rates. Procedure As an example of the application of benefit/cost analysis, assume for a small 4 MW hydroelectric project the following: o Construction cost of $5,388,000. o Annual O&M, replacement, insurance and administrative charges of $58,000. o Energy produced annually of 20.9 x 10 6 kWh o Firm capacity of 2 MW o Developer is now paying $2.85/kW/month for capacity and $0.0207/kWh for energy o Discount rate is 6.5 percent (based on using a 40-year bond for financing issued at 6.5 percent) o An economic life of 40 years Benefit = generation energy benefit + dependable capacity Benefit = (20.9 X 10 6 X 0.0207) + (2,000 X 2.85 X 12) = $501,000. 7-12 Initial Cost = Construction Cost = $5,388,000 Annual Cost = O&M + replacement + insurance + administrative charges = $58,000 Tab 1 e 7-2 presents the present worth streams of costs and benefits for this project. Using the formula 7-2 the cost and benefit streams from Table 7-2, the B/C ratio is: _ B _ $17,535,000 B/C -K+O -$5,388,000 + $2,030,000 = 2.36 The benefit/cost ratio is greater than one; therefore, the project is economically feasible. Two types of sensitivity analysis were done on the above analysis. In the first one, the discount rate was increased until the project showed a benefit/cost ratio of less than one. Table 7-3 presents the streams of benefits and costs associated with a discount rate of 15 percent. This was the discount rate necessary to cause the project to become economically infeasible. This can be interpreted to say that this hypothetical project would be economically feasible even at high (13 per·cent to 14 percent) discount rates. The second sensitivity analysis was done by assuming there was no dependable capacity associated with the project. Table 7-4 presents the results of this analysis. Note that although the benefit stream has been reduced, the project remains economically feasible since the benefit/cost ratio is 2.04. The use of benefit/cost analysis can prove to be a valuable tool for assessing the economic feasibility of small hydroelectric projects. Also, as has been shown above, the discount rates, benefit streams, and costs can each be changed to provide information about the economic feasibility of a single project under a wide spectrum of assumptions. 7-13 TABLE 7-1 Maximum and Minimum Power Demands Northern Southern Rocky North-West 1978 California California Mountain Pacific Arizona Apr Max Thur 6-7pm Tues 9-10pm Wed 1-2pm Thurs 7-8am Thurs 7-8pm Min Sun 3-4am Sun 3-4am Sun 3-4am Sun 3-4am Sun 3-4am Aug Max Tues 3-4pm Man 2-3pm Tues 2-3pm Tues 11-12am Thurs 3-4pm Min Sun 5-6am Sun 5-6am Sun 4-5am Sun 6-7am Sat 5-6am Dec Max Wed 5-6pm Thurs 5-6pm Wed 6-7pm Thurs 8-9am Thurs 8-9am Min Sun 3-4am Sun 3-4am Sun 2-3am Man 3-4am Man 1-2am NOTE: (1) The times shown above are those during which the Maximum and Minimum Power Demands occurred during the first full week of selected months with Sunday as the first day of the week, for typical systems in the following regions: -Northern California -Southern California -Rocky Mountain Region -Pacific Northwest -Arizona (2) The time shown 6-7pm denotes the one hour period beginning at 1800 hours. (3) All times are local times which includes daylight saving where applicable. Arizona does not use daylight saving time. (4) This data was obtained from FERC reports. 7-14 TABLE 7-2 EXAMPLE OF PRESENT WORTH STREAMS OF COSTS AND BENEFITS FOR TEXT EXAMPLE OF SMALL FEASIBLE HYDROELECTRIC PROJECT FOR 6 PERCENT DISCOUNT RATE PRESENT COST STREAMS YEAR CAPITALOM&R BENEFIT STREAM ESCALATING AT{ 6.50) { 6.50) WORTH FACTOR { 6.50) PRESENT WORTHS COST BENEFIT -------------------------------------------------------------------------0 5,388,000 1.00000 1 61,770 533,565 .93897 58,000 501,000 2 65,785 5 68_, 24 7 .88166 58,000 501,000 3 70,061 605,183 .• 82785 58,000 501,000 4 74,615 644,520 • 77732 58,000 501,000 5 79,465 686,413 .72988 58,000 501,000 6 84,630 731,030 .68533 58,000 501,000 7 90,131 778,547 .64351 58,000 501,000 8 95,990 829,153 .60423 58,000 501,000 9 102,229 883,048 .56735 58,000 501,000 10 108,874 940,446 .53273 58,000 501,000 11 115,951 1,001,575 .50021 58,000 501,000 12 123,488 1,066,677 .46968 58,000 501,000 13 131,514 1,136,011 .44102 58,000 501,000 14 140,063 1,209,852 .41410 58,000 501,000 1 5 149,167 1,288,492 .38883 58,000 501,000 16 158,863 1,372,244 .36510 58,000 501,000 17 169,189 1,461,440 .34281 58,000 501,000 18 180,186 1,556,434 .32189 58,000 501,000 19 191,898 1,657,602 .3022•+ 58,000 501,000 20 204,371 1,765,346 .28380 58,000 501,000 21 217,656 1,880,094 .26648 58,000 501,000 22 231,803 2,002,300 .25021 58,000 501,000 23 246,870 2,132,449 .23494 58,000 501,000 24 262,917 2,271,058 .22060 58,000 501,000 25 280,007 2,418,677 .20714 58,000 501,000 26 298,207 2,575,891 .19450 58,000 501,000 27 317,590 2,743,324 .18263 58,000 501,000 28 338,234 2,921,640 .17148 58,000 501,000 29 360,219 3,111,547 .16101 58,000 501,000 30 383,633 3,313,797 .15119 58,000 5,01 ,ooo 31 408,569 3,529,194 .14196 58,000 501,000 32 435,126 3,758,592 .13329 58,000 501,000 33 463,410 4,002,900 .12516 58,000 501,000 34 493,531 4,263,089 .11752 58,000 501,000 35 525,611 4,540,190 .11035 58,000 501,000 ------------------------------------------------------------------------- CAPITAL COST = 5,388,000 TOTALS = 2,030,000 17,535,000 P.V. OF OM&R = 2,030,000 P.V. OF BENEFITS= 17,535,000 ·---------------------------------~ BENEFIT/COST RATIO = 2.3638 NET PRESENT VALUE = 10,116,999 7-15 TABLE 7-3 SENSITIVITY ANALYSIS-SAME PROJECT AS FOR TABLE 7-2 EXCEPT HIGHER DISCOUNT RATE OF 15 PERCENT-INFEASIBLE PROJECT COST STREAMS YEAR CAPITAL Ofll&R BENEFIT STREAM ESCALATING AT ( 6.50) ( 6.50) PRESENT WORTH FACTOR (15.00) PRESENT WORTHS COST BENEFIT --------------------------------------------------·------------------------ 0 5,388,000 1 61,770 2 65,785 3 70,061 4 74,615 5 79,465 6 84,630 7 90,131 8 95,990 9 102,229 10 108,874 11 115,951 12 123,488 13 131,514 14 140,063 15 149,167 16 158,863 17 169,189 18 180,186 19 191,898 20 204,371 21 217,656 22 231,803 23 246,870 24 262,917 25 280,007 26 298,207 27 317,590 28 338,234 29 360,219 30 383,633 31 408,569 32 435,126 33 463,410 34 493,531 35 525,611 533,565 568,247 605,183 644,520 686,413 731,030 778,547 829,153 883,048 940,446 1,001,575 1,066,677 1,136,011 1,209,852 1,288,492 1,372,244 1,461,440 1,556,434 1,657,602 1,765,346 1,880,094 2,002,300 2,132,449 2,271,058 2,418,677 2,575,891 2,743,324 2,921,640 3,111,547 3,313,797 3,529,194 3,758,592 4,002,900 4,263,089 4,540,190 CAPITAL COST = P.V. OF OM&R· = P.V. OF BENEFITS = 1.00000 .86957 .75614 .65752 .57175 .49718 .43233 .37594 .32690 .28426 .24718 .21494 .18691 .16253 .14133 .12289 .10686 .09293 • 08081 .07027 .06110 .05313 .04620 .04017 .03493 .03038 .02642 .02297 .01997 .01737 .01510 .01313 .01142 .00993 .00864 .00751 TOTALS = 5,388,000 677,255 5,850,085 BENEFIT/COST RATIO = .9645 NET PRESENT VALUE = -215,168 7-16 53,713 49,743 46,066 42,661 39,508 36,588 33,884 31,379 29,060 26,912 24,923 23,081 21,375 19,795 18,332 16,977 15,722 14,560 13,484 12,487 11,564 10,709 9,918 9,185 8,506 7,877 7,295 6,756 6,256 5,794 5,366 4,969 4,602 4,262 3,947 463,970 429,676 397,917 368,506 341,269 316,045 292,685 271,052 251,017 232,464 215,282 199,370 184,634 170,987 158,349 146,645 135,806 125,768 116,472 107,863 99,891 92,507 85,670 79,338 73,474 68,043 63,014 58,356 54,043 50,048 46,349 42,923 39,751 36,813 34,092 677,255 5,850,085 ,--... : TABLE 7-4 SENSITIVITY ANALYSIS-SAME PROJECT AS FOR TABLE 7-2 EXCEPT NO DEPENDABLE CAPACITY COST STREAMS YEAR CAPITALOM&R BENEFIT STREAM ESCALATING AT( 6.50) ( 6.50) 0 5,388,000 1 61,770 2 65,785 3 70,061 4 74,615 5 79,465 6 84,630 7 90,131 8 95,990 9 102,229 10 108,874 11 115,951 12 123,488 13 131,514 14 140,063 15 149,167 16 158,863 17 169,189 18 180,186 19 191,898 20 204,371 21 217,656 22 231,803 23 246,870 24 262,917 25 280,007 26 298,207 27 317,590 28 338,234 29 360,219 30 383,633 31 408,569 32 435,126 33 463,410 34 493,531 35 525,611 460,751 490,700 522,595 556,564 592,741 631,269 672,301 716,001 762,541 812,106 864,893 921,111 980,983 1,044,747 1,112,656 1,184,978 1,262,002 1,344,032 1,431,394 1,524,435 1,623,523 1,729,052 1,841,440 1,961,134 2,088,607 2,224,367 2,368,951 2,522,933 2,686,923 2,861,573 3,047,575 3,245,668 3,456,636 3,681,318 3,920,603 PRESENT WORTH FACTOR ( 6.50) 1.00000 .93897 .88166 .82785 • 77732 .72988 .68533 .64351 .60423 .56735 .53273 .50021 .46968 .44102 .41410 .38883 .36510 .34281 .32189 .30224 .28380 .26648 .25021 .23494 .22060 .20714 .19450 .18263 .17148 .16101 .15119 .14196 .13329 .12516 .11752 .11035 PRESENT WORTHS COST BENEFIT 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 58,000 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,63Q 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 .432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 432,630 TOTALS = 2,030,000 15,142,050 CAPITAL COST = 5,388,000 P.V. OF OM&R = 2,030,000 P.V. OF BENEFITS = 15,142,050 BENEFIT/COST RATIO = 2.0413 NET PRESENT VALUE = 7,724,049 /-17 -, • Figure 7-1 Annual Unit Cost Variation with Load Factor 7-18 ~--' Figure 7-2 Typical Daily Load Curves of Representative Systems in 5 Western States 7-19 .. Figure 7-3 Load Duration Curve 7-20 i Figure 7-4 Yearly Load and Energy Curve 7-21 ,, I'' Figure 7-5 Relationship of Benefit/Cost Ratio to Discount Rate \ 7-22 • ·GENERAL SECTION 8 PRIMARY ENERGY REQUIREMENTS AND ENERGY BALANCE Primary energy for the small low-head hydroelectric project is by defini- tion the energy used to construct. equip and operate the project. This includes all the energy required to produce the construction material. equipment used for construction~ energy used by the construction person- nel, energy used by manufacturers to produc~ the equipment installed on ·the project, and energy used for o~eration. maintenance and replacement. Two widely used methods for calculating the primary energy for the vari- ous activities are (1) input-output analysis and (2) process analysis. The input-output analysis uses the total direct and indirect energy re- ·quired to produce energy on a dollar 1 s value of a product. Process anal- ysis determines the energy used in each process in the chain of activi- ties required to produce and deliver a given amount, or unit~ of the product. This procedure evaluates the energy required for each step of the process from the basic resource to the final delivered product. Each method should theoretically yield the same final energy required if a fully disaggregated data base were available. In practice each tech- nique is most useful for a particular type of problem. The input-output analysis is best suited for nationwide problems as there is a data base available for a 368 sector model of the entire U. S. economy. Specific processes, products or manufacturing chains where there is a physical flow of goods or services is best served by the process analysis. The reader is referred to L15J for details on both methods of analysis in ad- dition to the tables required for making an analysis. These energy tables, L15j, have a 1967 dollar base and if used for other than 1967 .an adjustment should be made. 8-1 Ideally, a project should produce more energy during the first few years of operation than the primary energy required to construct and maintain the project. REQUIREMENTS Genera 1 The primary energy requirements for several hydroe 1 ectri c and pumping plants in use by the State of California have been developed L16j. From this work the energy-intensity factors for construction of components which can be considered applicable to small low-head hydroelectric proj- ects are presented in Tables 8-1 and 8-2. The values in Tables 8-1 and 8-2 have been adjusted and use July 1978 as a dollar base. Energy -Intensity for Construction Componenents Table 8-1 lists the energy-intensity factor for construction of compo- nents applicable to low-head hydroelectric projects and has been based on [16] but modified to a July 1978 cost base. Energy Use for Operations, Maintenance and Replacement Table 8-2 lists the estimated annual energy use for O&M and· replacement Ll6 J. These factors are for use when estimates are not available for the O&M costs. Except in isolated cases the use of Table 8-1, energy-intensity factors will provide satisfactory results. If an accuracy of about ~5 percent is required and a cost breakdown is either available or has been estimated in detail, then the energy-intensity factors for all the sub groups com- prising the main classification may be determined following the procedure presented in L15j. Depending on the detail and accuracy required each component in Table 8-1 can be segregated into as many divisions as cost data or estimates are available. Generally it is only required to deter- mine the approximate length of time necessary for a project to replace 8-2 the energy used for its construction and accuracy greater than afforded by Table 8-1 is not warranted. In Table 8-1 the dam classification includes outlet works and spill- ways. The power plant classification includes the plant structure, equipment and switchyard. The method of applying Table 8-1 is as fol- lows: assume a small project having the following July 1978 costs and capable of an annual operation of 22.7 x 10 6 kWh. Power Plant Cost $2,000,000 Asphalt Access Road Cost $ 42,000 Construction Primary Energy = E (Intensity factors x Cost) = (2 X 106 X 22.6) + (42 X 103 X 154) = 51.7 x 10 6 MJ (48.93 x 10 9 BTUJ Time for Project to Replace the Primary Energy= = Primary Energy Used Annual Plant Production x 3.6 = 51.7 X 10 6 22 . 7 X 106 X 3. 6 = 0.63 years The 1967 energy cost of goods and services data is the basis Ll5j of energy-intensity factor determination. Adjustments for construction costs that are not in 1967 dollars (or the base used in Table 8-1 and 8- 2) can be made by using a ratio of the construction cost indices for the two periods L16J. The Engineering News Record Construction Cost Index , Ll7J is used for this adjustment. This construction cost index for July 1978 was 262.59 which is the base index used for Tables 8-1 and 8-2. 8-3 Assume in the preceeding example the power plant was constructed for 2 million dollars when the Engineering News Record Construction Index was 283.92. Then the primary energy corrected for this construction period using Table 8-1(as a base) is: Primary Energy = 2 x 106 x 262.59 x 22.6 283.92 = 41.8 x 10 6 MJ (39.6 x 109 BTU) ~· The energy used for 0 & M and replacement, Table 8-2, should be used when cost estimates of these items are not available. Examples of Tables 8-1 and 8-2 Application Assume a small hydroelectric plant is being added to some existing facil- ities and the project data is as follows: Construction cost $3,500,000. (July 1978 dollars) Unit size, 5 MW Construction time, 1.5 years Construction primary energy used, 84 x 10 6 MJ (79.6 x 10 9 btu) Capacity factor 50 percent From this data the following is calculated Operational time to replace the 84 X 106 Construction energy = 7 6 5000 X 8 60 X 0.5 X 3. = 1.06 year Annual energy used for operation maintenance and replacement (Table 8-2) = 0.32 X 3,500,000. = 1.12 x 106 MJ (1.06x 109 btu) 8-4 ··:._._,· These values have been plotted on Figure 8-1. To show the effects of plant capacity, assume a hydroelectric project with the following data. For Construction Cost, $8,000,000 (July 1978 dollars) Unit Size, 12 MW Construction Time, 2 years Primary energy used during construction, 200 X 106 MJ (189.4 X 109 btu) Capacity factor, either 25 percent or 50 percent Annual energy of operation, maintenance and replacement, 1.8 X 106 MJ (1.7 X 109 btu) the condition of 50 percent Capacity Operational time to replace construction energy = 200 X 106 12000 X 8760 X 0.5 X 3.6 = 1.1 years Energy used for construction, 0 & M and replacement for the construction period and 5 years of operation = (200 x 106) + 5(1.8 x 106) = 209 X 106 MJ (197.9 X 109 btu) For the condition of 25 percent capacity Operational time to replace construction 200 X 10 6 energy = ___ _:_·=------'------· 12000 X 8760 X 0.5 X 3.6 = 2.1 years This data has been plotted on Figure 8-2. 8-5 TABLE 8-1 ENERGY -INTENSITY FACTORS FOR CONSTRUCTION OF COMPONENTS OF WATER PROJECTS Energy Use per July 1978 Dollar Component in MJ_(10 3 btul Small eart hf ill dams 27.9 (26.4) Small concrete dams 26.8 (25.4) Reservoirs 26.7 (25.3) Power Plant 22.6 ( 21. 4) Steel pipelines (penstock) 44.1 ( 41.8) Concrete, steel cylinder pipeline 23.2 (22.0) Tunnels 23.5 (22.3) Transmission lines 27.2 (25.8) Steel bridges 24.3 (23.0) Concrete bridges 25.9 (24.5) Asphalt roads 154.0 (146.0) Site development 30.1 (28.5) TABLE 8-2 ANNUAL ENERGY USE FOR 0~~ AND REPLACEMENT Component Dams Power Plant Canal Pipeline (penstock) Tunnel 8-6 Energy Use per July 1978 Dollar in MJ (10 3 btu) 0.07 (0.07) 0.32 (0.30) 0.08 (0.08) 0.06 (0.06) 0.01 (0.01) Figure 8-1 Primary Energy-5 MW Power Plant 8-7 • Figure 8-2 Primary Energy -12 MW Power Plant 8-8 SECTION 9 SMALLEST PRACTICAL SIZE DEVELOPMENT GENERAL Many factors enter the process of establishing the smallest practical size of small low-head hydroelectric installations. These factors may be broadly classified in the following categories: o Economics o Site Conditions o Equipment Each of these items has many sub-classifications. The lower limit is not a discrete number or value but instead is highly dependent upon the interrelationship of these above factors. ECONOMICS Preceding sections of this report have discussed in detail the many items comprising a small low-head hydroelectric development and their associ- ated costs. Application of the principles and method of analysis pre- sented will allow the reader to establish, on an economic basis, the smallest size of the development for each type of hydraulic turbine re- viewed in this report. It is assumed that there are no constraints placed on the development which prohibits the selection from being eco- nomically feasible. Usually, the smallest low-head turbine purchasable is a function of the market place, that is the hydraulic turbine indus- try. When a selection parameter is •practical• than the usual limitation requires, from an economic viewpoint that the equipment be either actu- ally in production or all of the design and model testing costs are not included in the current pricing. 9-1 SITE CONDITIONS The only transmission grid available for the site may be operating at such a high voltage level that a small development could not economically assume the cost of transformation and protection from the grid. Every transmission voltage level has a maximum capacity without excessive transmission losses which limits the distance a development be, for a certain power rating, from the transmission qrid connection. It is very possible that a site near a grid could be economically feasible and another having the same hydraulic and hydrological conditions would not be economically feasible due to costs chargeable to transmission line distance and transmission line voltage level. Site conditions that include existing facilities, as an example, building and waterways, which minimize initial construction costs can at times justify a smaller unit than under the condition of requiring all facili- ties be constructed. Also if the existing facilities or location to the pondage does not require costs of a penstock, then this could result in a smaller size unit being justifiable which if the penstock cost were in- cluded in the project cost the project would not be economically feasible. Sites that are remotely located with respect to transportation and hous- ing facilities require a larger unit for economic feasibility due to higher construction costs than identical sites not remotely located. EQUIPMENT At the time of this report the smallest hydraulic turbine that could be considered to be in production at the low head range of this report is 50 kW. It would only be due to very unusual circumstances that a hydroelec- tric development having this low a capability could be considered to be for commercial use. Table 9-1 summarizes the results of an equipment survey made of over 40 turbine manufacturers. There is no known effort 9-2 : J at this time to commercially produce hydraulic turbines having lower ca- pacities than given in Table 9-1. SUMt~ARY General . During an early stage of an economic assessment of a hydroelectric devel- opment, the probable capacity and potential energy production will have been determined. At this time the developer should also have some know- ledge of the potential marketability of the energy and its value in the marketplace (mills/kWh). There is a relationship between the project unit cost, load factor and energy 'production costs (debt service plus plant operating and maintenance cost) for any project. Figure 9-1 shows this relationship for an annual cost being 9 percent of the project cost. a reasonable value for a public project. Different percentage annual costs will vary the absolute values between these three items. Assume the energy may have a value of 30 mills/kWh and the appraisal op- eration study indicates the development will have a capacity factor of 40 percent. Then from Figure 9-1 it is determined (for the percentage an- nual cost used) that the project cost cannot exceed $1150/kw in order that the first year•s operation be economically feasible. The credit, if any, for. dependable capacity is included in the 30. mills/kWh value. The use of Figure 9-1, or similar graph, can assist early in an appraisal study and determination that a project can reasonably be expected to be a viable project. Figure 9-1, or similar graph, has also another value, which is to determine the maximum cost for some item of the development if all other project costs are known. As an example, using the preceding va 1 ues, assume the project costs for a 11 items except a new· dam total $800/kW. Then for the project to be viable the new dam total project cost cannot exc~ed $350/kW. If the dam cannot be constructed for this unit cost then the project is not economically feasibl~. 9-3 Minimum Load Factor Criteria Experience, based on many feasibility studies of small hydroelectric de- veloments, indicates that at the present time the load factor of a proj- ect must be at least in the 40-50 percent range. It is only under very unusual conditions either of an exceptionally high dependable capacity credit or the market value of the energy is unusually high that a load factor of the small viable hydroelectric development can be below this percentage range. Pdwerhouse Unit Costs Powerhouse cost curves, including the switchyard, have been prepared for several of the most frequently used turbines and arrangements. These curves include the following: o Tubular turbine, penstock and headworks, Figure 9-2 o Kaplan turbine, penstock, Figure 9-3 o Kaplan turbine, headworks, Figure 9-4 o Vertical Francis turbine, penstock, Figure 9-5 o Horizontal Francis turbine, penstock, Figure 9-6 o Open flume turbine, without bypass, Figure 9-7 Tlie cost curves are shown as unit costs, dollars/kW and include all con- struction and equipment costs as noted on the respective curves but do not include indirect, contingency or development costs. Normally the total of the construction and installed equipment costs for the small hy- droelectric development will be about 60 percent of the total project cost. For the average of the three examples in Section 10 this percen- tage is 60.5. The costs shown in Figures 9-2 to 9-7 represent only about 45 percent of the expected total project costs. In the three examples of Section 10 this range is from about 41 to 53 percent, not including the dam costs in the third example, with an average of 45 percent. The ac- tual percentage varies'with the site conditions, that is, addition to an existing development or entirely new development. For the purposes of 9--4 this report, assuming these cost curves represent 45 percent of the total project cost is a reasonable assumption. Smallest Size Project In addition to presenting in this report data and methods to make an eco- nomic appraisal assessment of a small 1 ow-head hydroelectric development, an objective is to determine either the lowest head or smallest plant that may be economically feasible. As stated earlier in this section a discrete number either as to head or size cannot be determined unless many variables are assumed as being constant. Reasonable assumptions may be made and the lowest head and/or smallest unit may be established using these assumptions. Assume the following marketing and operating conditions: o Market value of energy, 30 to 35 mills/kWh o Capacity factor 40 to 50 percent o Powerhouse costs represented by Figures 9-2 to 9-7 represent 45 percent of total project costs o Figure 9-1 is applicable Then from Figure 9-1 the range of unit capital cost, for these assump- tions, varies from $1150 to $1700/kW. The corresponding unit costs for Figures 9-2 to 9-7 are from $518 to $765/kW. On this basis the lowest head and/or sma 11 est unit represented on these seven cost curves are shown in Table 9-2. The lowest head is 21.5 ft (6.6 m) and the smallest unit is 1,000 kW. 9-5 TABLE 9-1 SMALL LOW-HEAD HYDRAULIC TURBINE DATA Lowest Operating Head Unit Output Diameter D3 Turbine Type Feet 1r& kW Feet -~- Propeller 8.2 ( 2. 5) 50 1. 31 (0.40) Kaplan 8.2 (2.5) 50 2.46 (0.75) Francis 14.7 (4.5) 50 0.98 (0.30) Tubular 6.6 (2.0) 50 2.30 (0.70) Bulb 13.1 (4.0) 100 4.10 ( 1. 25) Rim 9.8 (3.0) 1000 6.56 (2.0) Crossfl ow· 6.6 (2.0) 50 0.98 (0.30) TABLE 9-2 MINIMUM TURBINE GENERATOR SIZE AND MINIMUM HEAD BASIS: FIGURE 9-2, ENERGY VALUE, 30-40 MILLS AND 40-50 PERCENT CAPACITY FACTOR FIGURE 9-3 TO 9-8, UNIT COSTS EQUIVALENT TO 45 PERCENT OF TOTAL PROJECT COSTS Turbine Type and Arrangmement Tubular-penstock Tubular-headworks Kaplan-penstock Kaplan-headworks Vertical Francis-penstock Horizontal Francis-pentstock Open flume-without bypass Minimum Turbine/Generator Size-Head Less Than 65.6 ft (20m) kW 2,000 2,000 2,000 2,000 1,500 1,000 2,000 9-6 Maximum Head for Turbine Size Less than 15 MW ft (m) 28.5 28.5 21.5 23 25 47 28 (8. 7) (8. 7) ( 6. 6) (7.0) ( 7. 6) (14.3) (8.5) ',' ' NOTE: Based upon an annual cost equal to 9 percent of the project cost .. Figure 9-1 Unit Cost -Energy Value -Load Factor Curves 9-7 2. 3. 4. 5. July 1978. Figure 9-2 Unit Costs -Tubular Turbine Powerhouse 9-8 above the tailwater ) I ---~ I ' ' ' ' ) : I '; ~ ( I ', ; ' : ...... " -'' NOTES: 1. Costs include the powerhouse structure for a penstock connection (figs. 4-20 and 5-12), excavation (fig. 5-21), foundation treatment, Kaplan turbine/generator (figs 4-10 and 5-2), equipment and electrical (figs. 5-8 and 5-9), switchyard civil and electrical (figs. 5-38 and 5-39). 2. Costs do not include a penstock, turbine shut-off valve, tailrace, flood protection, access roads and other miscellaneous items, contingencies, I.D.C. or development costs. 3. Switchyard voltage: 34.5 kV for 2 MW to 15 MW, 4.16 kV for 1 MW 4. The spiral case centerline is set at the tailwater elevation. 5. Cost base is July 1978. Figure 9-3 Unit Costs -Kaplan Turbine Powerhouse with Penstock Connection 9-9 NOTES: 1. Costs include the powerhouse structure with headworks (figs. 4-21 and 5-13), excavation (fig. 5-21) foundation treatment, Kaplan turbine/generator (figs. 4-10 and 5-2), equip- ment and electrical (figs. 5-8 and 5-9), switchyard civil and electrical (figs. 5-38 and 5-39). 2. Costs do not include a penstock, turbine shut-off valve, tailrace, flood protection, access roads and other miscellaneous items, contingencies, I.D.C. or development costs. 3. Switchyard voltage: 34.5 kV for 2 MW to 15 MW, 4.16 kV for 1 MW 4. The spiral case centerline is set at the tailwater elevation. --, ' I ' I -1 5. Cost base is July 1978. k • Figure 9-4 Unit Costs -Kaplan Turbine Powerhouse with Headworks 9-10 \ ' i : I ' .~.-~·-~· . •' .···~·~ NOT[S: 1. Costs include the powerhouse structure for a penstock connection (figs. 4-18 and 5-10), excavation (fig. 5-21), foundation treatment, vertical Francis turbine/generator with non-speed regulating governor (figs. 4-9 and 5-1), powerhouse equipment and electrical (figs. 5-8 and 5-9), switchyard civil and electrical (figs. 5-38 and 5-39). 2. Costs do not include a penstock, tailrace, flood protection, access roads and other miscellaneous items, contingencies, I.D.C. or development costs. 3. Switchyard voltage : 34.5 kV for 1.5 MW to 15 MW 4.16 kV for 0.5 MW to 1 MW. 4. The spiral case centerline is set at the tailwater elevation. 5. Cost base is Jul 1978. Figure 9-5 Unit Costs -Vertical Francis Turbine Powerhouse 9-11 NOTES: 1. Costs include the powerhouse structure (figs. 4-19 and 5-11), excavation ($16,000), foundation treatment, horizontal Francis turbine/generator (fig. 4-9 and 93% of values on fig. 5-1), powerhouse equipment and electrical (figs. 5-8 and 5-9), switchyard civil and electrical (figs. 5-38 and 5-39). · 2. Costs do not include a penstock, tailrace, flood protection, access roads and other miscellaneous items, contingencies, I.D.C. or development costs. 3. Switchyard voltage is 4.16 kV. 4. The turbine/generator shaft is set at 3.5 x turbine throat diameter, above the ta ilwater. 5. Cost base is July 1978. Figure 9-6 Unit Costs -Horizontal Francis Turbine Powerhouse 9-12 I } -,, i I --_j ___ / ( I -J -l -_j • \ I _j NOTES: 1. Costs include the powerhouse structure without bypass (figs. 4-22 and 5-14), excavation (Fig. 5-21), foundation treatment. open flume turbine/generator (figs. 4-10 and 5-3), powerhouse equipment and electrical (figs. 5-8 and 5-9), switchyard civil and electrical (figs. 5-38 and 5-39). 2. Costs do not include a bypass structure and equipment, tailrace, flood protection, access roads and other miscellaneous items, contingencies, I.D.C. or development costs. 3. Switchyard voltage is 4.16 kV. 4. Cost base is July 1978. Figure 9-7 Unit Costs-Open Flume Turbine Powerhouse 9-13 '-' \_ ', '--~-/ I I [ __ t --_,. l r-\ I L_; GENERAL SECTION 10 DEMONSTRATION OF PROCEDURE Three examples of the step by step procedure for preparing an economic assessment of sma 11 hydroelectric deve 1 opments are shown to i 11 ustrate the data presented in this report. These projects include the following: 0 Site at an existing water canal drop o Site with an existing dam 0 Site requiring construction of a dam Only one turbine size and type is used in each example. To determine the optimum unit size several size units should be reviewed as discussed in Section 3. This refinement is not required in the examples in order to demonstrate the method of arriving at a project cost. References in the examples as to the origin of data used from the text are noted as ( *) with the table, figure or paragraph noted within the parenthesis. 10-1 EXAMPLE CANAL INSTALLATION A site is selected at an existing canal. The canal has the following characteristics as to flow and site conditions. 0 0 0 0 0 Flows up t~ 1900 ft3/s Water available only during months of April through October Site elevation 500 ft Existing bypass facilities available Adequate existing roads for construction and maintenance The following assumptions will be made: o Type A powerhouse with tubular turbine o Penstock length will be 50 feet o Tailrace length will be 50 feet 0 0 0 0 0 0 Penstock velocity, 12 ft/s Head on unit, 50.5 ft Flow-duration curve to be used for power and.energy estimates Normal amount of environmental control expense during construction Generator voltage level to be the same as the transmission voltage level An economic life of 40 years 10-2 ---., J l i i~J ; J ' ., I I ·-_ _j ! ·-J ' ~ -l - J l ! --J . J ---., : -- i \ i I I ' ' 1. Flow-Duration Curve -Year 1969-1976 Inclusive r -' ' i I Class No Times Percent Time Exceeded CFS In Class Sum Class Sum ------ I ,_ ___ 1900 26 26 0.9 r-, i I 1800 62 88 3.06 3.01 I I L-1 1700 133 221 7.7 7.6 ; 1600 147 368. 12.8 12.6 1500 137 505 17.6 17.3 ( -: 1400 128 633 22.0 21.7 : ~ 1300 165 798 27.8 27.3 1200 155 953 33.2 32.6 i : llOO 131 1084 37.7 37.1 L ..... _ c --1000 96 ll80 41.0 40.4 ' I 900 ll1 1291 44.9 44.2 ~--1 I 800 126 1417 49.3 48.5 ~---,, I 700 77 1494 51.98 51.1 600 64 ' 1558 54.2 53.3 l __ 500 60 1618 56.3 55.4 400 26 1644 57.2 56.3 r---~ 300 22 1666 58 57.0 . I ,I I 0 1256 2922 100 ,_ ~ r-----: I Percentage based on year, most flow in Apr-Oct period. I ___ J !-\ I I Flow-Duration Curve ' ----"' Area under curve= 11.75 in sq r--: Base (100%) = 3 15/16 in t__ r. -: Average flow = 11.75 = 2.984 11 or 770 n3;s l __ : 3.9375 ~---' ' : I 2. Power Available & Energy I 10-3 Head = 50.5 ft Assume Eff. = 0.85 Pw. = 0.0846 X Q X Hn X 1l Where Q = flow, cfs Hn = Head, ft 1l = eff, = 0.85 Pw = 0.0846 X 770 X 50.5 X 0.85 = 2796 kW I -1 -_I Energy generation = Power x Time 3. Turbine Operation = 2796 X 8760 24.5 X 106 kWh For turbine rated flow of 770 ft3/s turbine would operate between 115 percent and 30 percent of rated flow. High Flow= 770 x 1.15 = 886 ft3/s Low Flow = 770 x 0.3 = 231 ft3/s Between these flows the average flow on the flow-duration curve (based on 100 percent exceeded base line) is about 460 ft3/s. 10-4 --, -, I _ _I ' -_I I 1 ( i I ' I ' i \_ ---_: '---, PERCENT OF TIME EXCEEDED '-l Example -Flow-Duration Curve for Canal Installation 10-5 Pw = 0.0846 X 460 X 50.5 X 0.85 = 1670 kW Energy = 1670 x 8760 = 14.6 X 106 kWh C . t F t --14 ' 6 -~-l O 6 X 100 59 6 t apac 1 y ac or = • percen 24.5 X 10 6 4. Turbine Selection-Flow This is a canal operation so should follow criteria set up in text for Figure 3-3. On this basis flow would be at 10 percent exceeded value or about 1660 ft 3/s. For this particular flov-J- duration curve this flow of 1660 ft 3/s would result in too large a turbine, as 115 percent of rated flow would be in excess of the canal flow. Accordingly, the turbine rated flow for this example is based on the following: Turbine rated flow = 1900 ~ 1.15 = 1652 n3;s Use 1650 ft3/s Low flow cut off point = 0.30 x 1650 495 n3;s Using a turbine rated flow of 1650 ft 3/s at about 10.5 percent exceeded time, the unit will produce energy in an amount represented by the flow-duration curve between the 1 imits of 1900 n 3/s and 495 n 3;s at about 55.5 percent time exceeded. The average flow from the flow-duration curve is 750 ft3/s. 10-6 "I. \ _j ! ---' I __ ! ' ' i r---' ! ' ' L ___ I : ' --·' I ; -! r--. I r > I ·---! ,_--' '-' : ---' ' ' Pw = 0.0846 X 750 X 50.5 X 0.85 = 2724 kW Energy = 2724 X 8760 = = 23. 9 X 10 6 kWh Capacity Factor 23.9 X 106 X 100 = X 10 6 24.5 = 97.6 Percent 4. Turbine Selectio~ Size (D 3 ) Design: H = 50.5 ft Q = 1650 ft 3/s Pw = 0.0846 X 1650 X 50.5 X 0.85 = 5992 kW Use 6000 kW Plant elevation is elev 500 ft Centerline of turbine is 1ft above tailwater Determine D3 from curve (Fig. 4-10*) ~levation Correction factor is 1500 = -1000 (0.01) = -0.015 Tailwater correction factor (Fig. 4-10*) for centerline setting of 1 ft. above tailwater = 1.02 Tubular (propeller) Uncorrected o3 (Fig. 4-10*) Altitude correction = 8.4 x (-0.015) Tailwater correction = 8.4 x 0.02 Total correction D3 = 8.442 ft Use 8.44 ft 10-7 = 8.4 ft -0.126 = 0.168 = 0.042 5. {Following the method shown in Section 4 11 Turbine Selection 11 results in about the same result 03 = 8.4 x 0.985 x 1.02 = 8.439 or 8.44 ft) Powerhouse Cost -Including Intake & Penstock Based on type A with tubular turbine 50 ft of steel penstock v = 12 ft/s Powerhouse civil cost based on 03 = 8.44 ft {Fig 5-16*) = $233,000 Powerhouse Area, {Fig 5-16*) = 1350 ft 2 Depth of powerhouse, d, from {Fig 4-24*) d = 2.503 + 2 d = {2.5 X 8.44) + 2 d = 23.1 Use 23 ft Excavation depth, assume ground elevation is 7 ft above tai lwater a = d + 7 a = 23 + 7 a = 30 ft Excavation Cost {Fig 5-21*) = $44,000 Penstock Cost {Fig 5-25*)is $1200 per lineal ft for Q = 1650 ft3/s and v = 12 ft/sec Cost for 50 ft is = 50 x 1200 = $60,000 10-8 - J ' I --' --l ' ) I i L __ _: I : ---_j : i 6. ' \ I 1 --) 7. r ---, I. Tailrace cost for 50ft, (Table 5-3*) = 15000 + (50 X 200) = $25,000 Intake structure less gates (Fig 5-23*) = $165,000 Gate and hoisting equipment are not included in (Fig. 5-23*). Assume two slide·gates each of 200 n 2 size are used also a jib crane is used for hoisting gates and costs $10,000. Gates are used only when there is no flow and as required by maintenance operations. Emergency closure devices already exist at the dam intake. Gate cost (Fig. 5-24*) = 2 x 30,000 = $60,000 Hoist Cost (estimated) = $10,000 Total Intake Structure cost = 165,000· + 60,000 + 10,000 = $235,000 Power Plant Equipment Cost Based on plant capacity 6 MW (Fig 5-9*) Cost = $92,000 Station Electrical Equipment Cost (Fig 5-8*) Cost = $330,000 Switchyard-Cost Civil cost (Fig 5-38*) = $23,200 Assuming that generator voltage will be at same level, 4.16 kV, as transmission voltage and line circuit breaker will be Jsed, the switchyard electrical cost from (Fig 5-40*) is= $67,000 10-9 8. Turbine/Generator Cost Tubular Type Turbine o3 = 8.44 ft; Design Head = 50.5 ft; Power = 6 MW (Fig 5-5*) Cost = $1,300,000 9. Environmental Controls (Table 5-4*), 10,000 10. Escalation Factor WPRS** Est. Index WPRS Item July 78 Index Factor Structure Reinforced 2.28 2.65 1.162 Steel Penstock 2.48 2.60 1.048 Turbine Generator 2.38 2.65 1.113 Misc. Elec. Equip. 2.31 2.60 1.126 Switchyard 2.25 2.55 1.133 Canal Intakes 2.30 2.65 1.152 Tai 1 race 2.31 2.65 1.147 Environmental Controls 2.28 2.65 1.162 Item shown or assumed to be the equivalent of index used. ** From (Figures 5-43 to 5-50*) 11. Contingency Take contingency as 20 percent of construction costs (Section 5, paragraph Contingency*) From Summary Sheet construction cost Contingency at 20 percent is Total 10-10 = $2,723,900 544,800 $3,268~700 ' ' - J _, i i J ' -' I... ---- ' __ 1 -' 12. Cost Summary FERC Acct. No. Description Cost* 331 Structures & Improvements Site .11 Environmental Construct i_on 10,000 Controls Powerhouse .21 Structural 233,000 .22 Excavation 44,000 .23 Switchyard 23,200 .24 Subtotal .23 Foundation (2 percent of Subtotal) Total, Account 331 *Cost Base, July 1978. 10-11 Escalation Escalated Factor Cost Total 1.16 11,600 1.16 270,300 1.16 51,000 1.13 26,200 359,100 7,200 366,300 Escalation FERC Acct. No. Description Cost* Factor 332 .01 .02 .03 Reservoirs, Dams & Waterways Intake 235,000 Penstock 60,000 Tailrace 25,000 Total, Account 332 333 Water Wheels, Turbines and 335 Generators 1,300,000 Station Electrical Equip. Station Electrical Switch Yard Electrical Total, Account 333 Misc. Power Plant Equip. Total Construction Cost 330 '000 67,000 92,000 Regional Correction Factor (1) Regional Correction Contingency Engineering & Construction Management and Other Costs Interest During Construction Grand Total *Cost Base, July 1978. 10-12 1.15 1.05 1.15 1.11 1.13 1.13 1.13 Escalated Cost 270,200 63,000 28,800 1,443,000 372 '900 75,700 104,000 Total 362,000 1,891,600 104,000 $2,723,900 None 544,800 653,700 431,500 $4,353,900 13. Development Costs Development or indirect costs (engineering, construction manage- ment and other cost paragraph, Section 5*) suggests multiplier of 20 percent of final cons~ruction costs. Total Construction Cost = $3,268,700 Development Cost, 20 percent = 653,700 = $3,922,400 Total 14. Interest During Construction Assume construct ion money cost will b.e 10 percent and construc- tion period of 2 years with 60 percent spent first year. i ··1 First Year Expenditure = $2,353,400 Second Year Expenditure = $1,569,000 First Year Interest = 0.1 x 0!5 x 2,353,400 = $117,700 Second Year Interest = (0.1x2,3?3,400) + (0.1x0.5x1,569,000) = $313,800 Total I.D.C. =·$117,700 + $313,800 = $431,500 15. Project Financing Project financing loan will be for total project cost of $4,353,900. Items 13 and 14 above (see Cost Summary Sheet). The power developer is a pub 1 i c agency and funding will be by tax-exempt revenue bonds for the ,first one million dollars and the balance by taxable revenue bonds. (Following interest rates are assumed.) 10-13 Tax-Exempt Revenue Bonds, 40 yr., 7 percent, ~rf = 0.07501 Annual Debt Service Cost = 1,000,000 x 0.07501 = $75,000 Revenue Bonds, 40 yr. 10 percent, crf = 0.1023 Annual Debt Service Cost = 3,353,900 x 0.1023 = $343,100 Total Annual Debt Service Cost = $418,100 16. Economic Analysis . . .~ The plant rating is 6 MW. . ' ' The annual energy production is 23.9 x 10 6 kWh '' ' First year O&M costs can be taken as either (I.D.C. not considered): . ' ~ . 1.2 percent* of Plant Cost.= 0.012. x 3,922,460 = $47,000. or from (Fig 2-1*) .= p200 (MW)0.543 _ · = 1noo (6 )0·· 543 x 1.11 ** = $50,500. **Escalation (Fig 5-52*) An average value of the two will be used = $48,800 The First Year Annual Cost = $418,100 + 48', 800 = $466,900 Mills/kWh = 466,900 6 23.9 X 10 = 19.5-mills/kWh · * Includes Insurance Costs. 10-14 :] iJ '. ____ ] ' -l ! ! i] --l :--_.' I I ' I 'l I I ; I \--j ! _j Assume that capacity was worth $20/kW and that the developed energy met the system network requirements to the extent that 90% of the plant capacity could be given a dependable capacity credit. Dependable Capacity Credit = 0.9 x 6000 x 20 = $108,000 The comparative financial and production cost is then = 464,300 -108,000 23.9 X 106 = 14.9 mills/kWh 17. Primary Energy Primary Energy for power plant construction Power plant energy intensity factor (Table 8-1*) Construction Cost Penstock construction cost Net.cost for just power plant = 22.6 MJ/July 1978 Dollar = 2~723,900 + 544,800. = $3,268,700. = 63,000 X 1.2 = $75,600 = 3,268,700 75,600 = $3,193,100. Penstock energy intensity factor (Table 8-1*) = 44.1MJ/July 1978 Dollar Annual Energy use for O&M and Replacement, (Table 8-2*) Power Plant = 0.32 MJ/July 1978 Dollar Penstock= 0.06MJ/July 1978 Dollar 10-15 Assume for time frame being used, Construction Index is 283.92 Then correction factor is = 262 ·59 283.92 Primary energy, power plant = 3,193~100 X 22.6 X 262 ·59 283.92 Primary energy, penstock Total primary energy used = 66. 7 X 10 6 M J = 75,600 X 44.1 X = 3.08 X 10 6 MJ for construction 262.59 283.92 = (66.7 + 3.08) X 10 6 = 69.8 X 106 MJ Annual primary energy = (0.32 X 3,193,100 + 0.06 X 75,600) = 0.9 X 10 6 MJ Time for project to replace the energy used for 69.8 X 10 6 construction =~..:._:___:_:_-=-:c. ___ _ 23.9 X 10 6 X 3.6 = 0.81 years Including the O&M primary energy would mean the plant will take 1 ess than a year to make up for the energy used for construction. 10-16 262.59 283.92 EXISTI-NG DJIM INSTALLATION A site is selected at an existing dam. The dam has an existing con- duit through the dam and water flow is regulated on the upstream face of dam so there is not an existing outlet works for flow regula- tion .. The following conditions exist: o Conduit through the dam is large enough to convey the flows needed by the addition without excessive head loss o Site elevation is 200 feet o Powerhouse site will be about 8 feet above the normal tailwater o A short section of ground between dam and plant site has a 16 percent grade o Access roads are inadequate The following assumptions will be made: o Type A powerhouse with two tubular turbines o Penstock length will be 200 feet o Tailrace length will be 100 feet o Penstock velocity 12 ft/s o 20 feet of penstock will be on the 16 percent grade o A mile of ~ew access road required o Flood protection will be required from the tailrace river stream o Normal amount of environmental control expense during construction o An economic life of 40 years 1. Turbine Runner Diameter 2-Tubular turbines 5.24 MW each, 60 ft. head and 1182.5 ft 3;s flow from operation study. Approximate powerhouse e 1 ev at ion = 200 ft, set turbine b 1 a de centerline at 2 ft ab0ve tailwater elevation. 10-17 Uncorrected 03 (Fig. 4-10*) for 60 ft head and rating 5.24 MW = 7.2 ft. Altitude correction factor for 200 ft elevation (Fig 4-10*) {2000-200) X 0.0 1 1000 = -0.0180 Tailwater correction factor (Fig. 4-10*) for centerline setting 2 ft. above tailwater = 1.06 Tubular (propeller) Uncorrected 03 (Fig. 4-10*) = 7.2 ft Altitude correction 7.2 x (-0.018) = -0.1296 Tailwater correction 7.2 x 0.06 = 0.432 Total correction 03 = 7.2 + 0.3024 = 7.502 Use 7.5 ft. = 0.3024 (Following the method shown in Section 4 "Turbine Selection" results in about the same result 7.495 or 7.5 ft.) 10-18 D3 = 7.2 X 0.982 X 1.06 = ' \ I ' ' ( .f I Hydroelectric Operation Study-Tudor Engineering Company Rw·, # 1 Power Aloorithm - Calculation of power using given flow and EOM W.S. elevation Data File-<WPRS1) Typical hydroelectric site for example in WPRS Report 'Reconnaissance Evaluation of Small, Low-Head Hydroelectric Installations' Turbine File-<SmKpl Se·m i -V.:a.p l.a.n ~ t·~::.= 127, IIi rne·n::. i •Jn 1 e·::.::. Pe·r·f•)r··r~·~.a.nc E CIJr·• . .Je· < Se·c. 4) Turbine Characteristics Ttwbi no:-# Rated Capacity(kWl R.:;.t ed He·aoj (ft.) R.:.t. e·d F 1 c•~.l ( c f:.) Rate-d Eff i c i e-nq.• Gen~rator Efficiency T a i l,,_,.:.t. er· C'Jr·• ... •e· 524(1 6(1 1182.5 9(1 :.; 97 ~·~ 2 524(1 6(1 1182.5 9(1 % ·n% 01.1tfl C•''-'<cfs.) 0 250 '300 170(1 ::::3(1(1 5(H)(1 75~3(1 T.:.i li,J.:.t.e.,-.(ft) 190.(1 1':!1.0 192.0 1 (14(1(1 1::::600 174(10 220(1(1 2400(1 Head Loss Characteristics 1 '33 .~) 194,(1 195 ,(1 196. (1 197. (1 198. (1 199. (1 2(1(1,(1 2(1(1,5 Head loss coefficient(K) is ,(1(1(1(1(105 (head loss=K*QA2) There is a spillway, crest elevation of 258 fe~t. The spillway flows affect the power plant tailwater. There is a bypass. The bypass flows do not cQntribute to the turbine h~· ad 1 .:•:.:.::.. ThE· b~:)p.a.::.::. f 1 c•1.~1:::. d.:• no~. cont.~-· i bt~t.. e t. o 1: he· t: .. :!I. i lt .. J.a.t e·r·. 10-19 Hydroelectric Operation Study-Tudor Engineering Companv t·1on\. h Oct t~ C• • . .J ItE·C J.;;.n FEb t·1.;;.t• Apr· ~1.;;.~) ._TIAn Jtll R1.l•;J ::;.:p t·1ont h Oc\ t~OI.) IIE c J.;;.n F.:b t·1.;;.r· Apt·· t·1.;;. ~) J1An hll R•.l•;J :.::e·p Tot .. ;;. 1 1:::14 604 214 .-, ·-:· .-. 24:3 207:3 16:39 2209 2:360 25•:;.[1 2:3t:E: 24:39 Tot .. ;;. 1 16 ;:4 1 7t: 22'~ :32:30 1528:3 7462 2009 2184 2:~:53 2501 1'~65 1290 Outflow(cfs) Turbine 1814 604 0 0 214 0 222 (1 ~) 207:3 (1 16:39 0 2209 (1 2:360 0 2520 71 2:388 0 24:39 0 Outflow(cfs) Turbine 16:34 1 7•:• I '-' 0 0 (1 243 (1 (1 (1 (1 0 ~3 (1 0 0 0 (1 22'3 (1 2526 2471 2507 2009 2184 .-,.-, C' .-, .::. ·=· ·-' .,:. 2501 1'365 12'3(1 70:::: (1 0 12:::13 (1 4''-'54 0 ~) 0 (1 0 (1 0 0 0 0 0 0 WF'R8 Repo:or·t. F:tm 111 \'E·ar· 1 v Otlt put 1968 Effective Head( ft.) 57.0 59.·~ 61.6 62.:3 6:3.4 58.6 59.7 1:'7 0.:• --·· ...... 56.8 C"C" ., ..... ._ .. ( C" C" C" ._ .. _ .. ·-· 54.7 1969 Effective Head(ft) 56.4 56.2 60.9 56.2 53. 1 I:" C' .-, ·-··-'. ·=· 58.'3 5B. 1 57.2 56. 1 57. 1 5:::·. 4 1970 Outflow(cfs} Effective Unit:::. Po1).1E·r· ( k ~·J) 21 77:::::: 1 25'35 (1 0 ~3 ~::1 ~3 (1 21 90:::::: 21 7305 21 94:::5 21 ·:;::: 17 21100::::2 21 '362~] 21 9597 Unit.::. F'OI,.,IEt'· ( k "l > 21 6'3:~:5 (1 (1 (1 (1 21H1167 21 9J75 21 98'36 21 ::::::65 21 9447 21 985'3 2110078 21 1::426 21 547:3 Efficiency Energy ( t·1k ~·Jh) 89.1 5.79 :::4. ::: 1. :::7 (1,0 0.00 0.0 (1.00 (1,0 0.00 ::::::.4 b. t'b ::::::.:::: 5.26 :::7. ::: 7. ~::h:: E:6.5 7.~37 1::4.5 7.46 t:5. 8 7. 16 85.(1 6.91 Tot..~l 55.34 Effi c i E·nc~) .··~ ::::::. 9 (1,(1 0.0 t:4. 6 :::4. 5 84.4 ::::::. 6 t:7. '3 :::6. 6 t:4. 9 ::::::. ::: 85. ·:;. En E· r· 9 ~:·-' ( t·1k ~·lh >. 5. 16 0.00 (1,(1(1 7.56 6. ::::o 7. :~:6 6. :3::: 7. o:~: 7. 1 (1 7. 5~) 6.27 3.94 Tc•t.al 64.6(1 Units F'ower Efficiency Energy Month Total Turbine Head(ft> O::kW) C%) O::MkWh) Oc~ 481 481 60.0 1 1968 80.7 1.46 Nov 197 0 197 61.:3 0 0 0.0 6.00 Dec 214 0 214 0 62.0 0 0 0.0 0.00 J;;.n 17623 2456 (1 15167 51.7 21 9119 85.0 Feb 11164 248:3 0 8681 54.0 M;;.r 4081 2527 0 1554 Apr 178:3 17B:3 0 0 May 2274 2274 0 0 Jun 224:3 224:3 0 0 Jul 2404 2404 0 0 Rug 2001 2001 0 0 Sep 1776 1776 0 0 56.:3 59.2 57.5 57. 1 56. ~~1 56.6 56.6 10-20 21 9!:1:~~::: 21101:::5 21 7'315 21 9657 1 9474 1 9781 1 8497 21 75t:2 :::4. 1 84.6 ::::::. 7 :::7.3 87.4 85. ::: ::::::. 7 8'3. 1 Tot .. ;, 1 t.. 7::: 6.41 7 t::.-. I • ._1•:• 5. 7(1 7. 18 6. :::2 7 ··:.·:· I • .:.., '-' 6.::::2 5.46 61.(10 <1 ,-l I -=-) _ _I ;-1 ,-1 ! I I 'I ! [] \ _ _j 1·1onth Oct. t·~c· '·-' D.:·c J.an Fo:-b t·1.ar· Apr· ~1a~.· J•Jn Jul A•J•;J S.:·p 1·1onth Oct ~~ 1) I) Dec J.an Feb t·1ar· Apt·· 1•1.ay J•Jn J•J 1 Atlg s~·p t·1onth Oct 1·~0') D;;·c J.:..n Fo:·b 1·1=.t·· Apt·· 1•1.=.:,..o J•.H"a J•.ll All9 S.:·p Hydroelectric Operation Study -Tudor Engineering Company 1612 6:;:6 1042 1380 19:::9 1970 19% 25~:9 2~: 11 223? 2142 Tc•tal 1'305 442 219 215 215 11 01 2113 2473 25~3'3 2158 1465 421 :3(15 265 28'::0 3(12 :3:364 19B4 26:345 2:::[19 2651 2183 14(1:;:: Ollt f 1 '''·•' ( c fs) Tlwb i no:- 1612 [1 ' 636 (1 £1 2:32 1042 (1 1 :::::::o [1 1989 0 1970 0 1996 ~3 2534 (1 2520 291 2237 l'::1 2142 (1 Out f 1 C•I .. J ( c fs) Tur·b in.:· 1 '305 442 0 219 0 215 0 215 1101 (1 2113 0 24 7:~: (1 2475 34 2468 165 2158 0 1465 0 Otlt f 1 C•l.o.l ( ·= f::.) Tut··bi n.:· 0 (1 (1 0 (1 :~:(15 265 2:::·3 0 (1 0 (1 (1 (1 0 (1 (1 (1 (1 (1 (1 (1 (1 (1 (1 0 0 (1 (1 (1 (1 (1 (1 2536 (1 828 1984 0 0 2432 0 23913 2527 2516 21::::3 (1 1:35 (1 [1 28:::: [1 (1 0 1971 Effect. i ,,.,. He.ad ( f ~-> 56.6 59. 1 62.3 61. (1 6(1. 5 58.9 58.9 58.5 56.5 55.9 56.2 55.9 1972 Unit,::. F'oa ... o;;·r· ( k ~·J) 21 6:::55 (1 (1 1 4756 21 6119 21 :::7'31 21 87li 21 8767 21i(125t: 211(1(1:::4 21 9279 21 8';t02 ( ~·~ ) 8:3. ::: 85.6 (1. 0 ::::::. 4 ,-, ,-, .., C•C• • 1' C••:O -, '-''-'• I 84.7 84.6 87.:3 88.0 Total En t· t···;l ~) < r·1k ~·Jh > 5. 1(1 1.% (1. 00 :3.54 4. 11 6.54 6.27 6.52 7.3'3 7.5(1 6. 9(1 6.41 62.25 Effective Units F'ower Efficiency Energy He ad ( f t, ):...._-t-----=-:-----:'(C.::k'-'::~·J:..:::,....• ---=-C:.:-·~ .::..> -:-----'(..:..1'1:.;:k..:..~·J'-'::f·,:..:,.' ) 56.0 21 8035 89.(1 5.98 59.2 1 1731 6(1.7 0 0 60.9 (1 0 61.1 0 (1 5E:. :3 55.4 5::::.9 5:3.3 52.7 52.9 54.2 197::: Eff.:·c f, i • ... •.:· He·.ad ( ft > 5::::.9 57.8 5'~. 9 62.7 56.7 5:::. '3 49.6 56.2 55.E: 56. 1 57.7 10-21 1 477:~: 21 .9727 21 950:~: 21 '342:~: 21 9310 21 8451 21 5'3:37 Unit.:. F'c•l·.IET ( k ~·J) (1 0 0 (1 (1 (1 0 0 0 0 2110315 21 :::765 21 87:::::3 21H1164 211(H):~:[1 21 9(1:::::: 21 5991 '78.1 0.0 0.0 (1. (1 B7.9 88. 1 84.2 :::4. 4 :::4. 6 :::7.4 8E:. 4 T·:o~ .. :..l Ef'fi o: i e·nq.o ( ~·~ ) 0.0 0.0 0.0 (1. (1 0. (1 84.8 ::::::. 7 84.6 84.5 87.7 87.2 1. 25 (1. (1(1 0.00 (1.(1(1 :3.55 6.28 6.7::: 6.93 6.29 4.27 48.40 En.:·r·g:) ( r·1k ~·Jh > 0. (H) 0. (1 (1 0.0~3 (1. 0(1 (1. (1 (1 7.67 6.31 6. 5~~1 7.46 6.76 4.31 To:•~ .. :..l 46.:34 Hydroelectric Operation Study -Tudor Engineering Company Olltfl ov.•(cf::> t·lon~.h Tc•tal Tw··bino:· Oct 611 611 No~..r D.:·c ..T.~n F.: b ~1ar·· Apr· t·la~.o ..Tlln J•J 1 Allg Se·p t·lonth Oct t·~o•.) DE·c J.;,.n F.:·b ~1.;,.r· Apr· t·1.;,. ~) ..Tun .J•.ll Au•;~ St:p t·l•:•nt h Oct Ho• .... IlE·c .J.an Feb t·l.;,.r· Apr· t·1 "''"' ..Tun J•J 1 Au•;~ ~=;E p 220 225 5445 29?2 10799 8275 2428 2851 2504 1764 1077 276 213 234 4256 2641 2724 :30~)6 2921 2725 1 ., 16 646 28~3 28'3 5'32 1344 1514 2:::5 ~~1 :;:(131 2044 1716 220 0 0 2510 225 (1 2491 2505 2428 2533 2524 25(14 1764 0 2935 (1 424 0 8:3(1<:: 0 5770 0 0 0 :317 174 0 0 (1 (1 0 01Jt f 1 Ol.o.l ( C f;:.) T•.lr·bi n.:· 1077 0 276 (1 189 0 21:3 0 2:;:4 2519 (1 254::: ~J 25:3E: 0 2525 0 2519 402 25(17 218 1916 (1 Out .. f l•:•1 ... 1 ( •: f::. > T•.lt··b i no:· 646 (1 2:30 0 2:::9 5'32 [1 1344 0 1514 0 2273 2471 2460 2451 2044 1716 (1 563 3 ., 0 s:::o 0 (1 1737 ''3 1:::6 481 (1 (1 0 (1 0 (1 0 (1 0 (1 (1 0 0 (1 0 Rw·, #1 1974 Effe·ct. i • . .J.:· H.:·ad ( ft) 59.:::: 61.7 62.9 55.5 57.3 54.4 55. 1 57.5 56.4 56.0 55.4 56.9 1975 Eff.:·c t i • ... •o:· H.:·ad (ft.> 58.4 58.2 61.0 61.0 62. (1 55.9 57.:3 56.9 56.2 55.8 1::" t:' .-, ._1._1,.::. 56.3 1976 Eff.:·c~. i <,•o:- Ho:·ad ( f~.) 5':'1. 1 60.8 6(1, 7 s:::. 9 57 .. (1 56.3 53.·:; 52.7 51.1 51.5 10-22 Units Power Efficiency Energy CkW::O ~~-' CMkWhl 2607 85.0 1.94 0 (1 0 (1 21 994 7 211(14<::5 21 9646 21 9837 211(1172 2110242 2110119 21 9925 21 7565 Unit::. Pot•.I€T ( k ~·J) 46<::4 (1 (1 0 (1 0 (1 0 (1 2110075 2110489 2110364 2110150 2110049 21 ·~:::66 21 :::117 Unit. S F'•:••.•.IO:·r· ( k ~·J) 277:~: (1 0 0 0 1 24 21 56 5 21 63 21 :::·;:. 21 9:::: 21 ., 1 21 '30 5 21 7::: 6 21 66 6 (1, 0 (1, 00 0.~3 (1.0(1 84.5 7.40 84.'3 7.(15 :::4.2 7.18 :::4.3 7,(1::: 86.1 7.57 84.7 7.:37 84.6 7.5:3 E:4.5 7.38 :.::9.(1 5.45 Tc•tal 65.95 Effi c i e·nc~) ... ,··~ ) ::::.::. 1 0.0 (1. ~J (1, (1 0.0 84.6 84.9 84. ::: :::4. 6 84.5 B4.3 En e· t···;~ ~) ( t·lk ~·Jh > 3. 4::: (1, 00 0.(10 0.0(1 (1, 00 7.50 '"':' C't:' ... ·-··-· 7. 71 7. 31 7. 4::: 7.34 89.(1 5. 84 Tor .. ;,] 54.21 '·· .··~ ) :::5.9 (1, 0 (1. 0 :::4. 4 ::::::.:::: :::6. 6 B4.6 84. ::: 85. 1 87. ::: En e· t···~ ~:! 0:: t·lk ~·J h) 2.06 0.00 0. ~)0 1. 85 :3.77 4.74 6.46 6. '?:::: 6. 61 6. 71 C' ,-, -, ·-·. ·=·,;;. ~_-1 r--, ( I i____; r--) I I l ! \-l L__) ~--~ ~ J 1-l I ' I J I-, . I I , ~-J L -· 1 I 1 l_, 1/ ) I I--J 1-J L 1--, l_j Mo:•nth Oct Nov DPr. Jan Feb M~ Apr M~ Jun Jul Aug Sep ~1·:-n~. h Oo:t Nov D€c Jan Feb Mar Apr May Jun Jul Aug Sep ~1ont h Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug S€·p Hydroelectric Operation S~udy -Tudor Engineering Company Tc•t al 974 421 :3(18 255 266 9(14 2312 165~) 22:;a~1 240(1 2(148 1318 T•:·~ .. ,. 1 68~~1 ::=:oo 240 12(1 Bt1 100 52t1 228(1 2'34~) 2921 2::a:11 160(1 Outflow(cfs) Turbine 974 0 0 0 0 9(14 2::::12 165(1 223~3 2395 204::: 131~ 30E: 255 266 0 0 (1 0 C' ·-' 0 0 Outflow(cfs) Turbine 6:::o (1 ::::(10 0 24(1 0 12(1 0 Bt1 0 100 52~) 0 2280 0 2475 465 2464 456 2456 :345 1600 0 Otltfl C•i,.l(o:fs) To:•t a 1 . Tw··b in~· '3160 48(1 280 240 120 200 1140 2::::60 2:::oo 2761 252(1 1 '30::: 960 4BO 0 0 ~) (1 1 140 2::::6[1 2461 2453 2442 1 '3 (1::: (1 2:::o 24~) 120 20C1 0 0 ::::::::'3 :;:(17 79 ~) 0 (1 (1 (1 (1 (1 (1 0 (1 (1 0 0 (1 0 (1 (1 0 (1 (1 (1 0 (1 0 0 (1 0 (1 (1 0 0 (1 0 (1 0 WPI<:S R.:·por·t Rw·, Ill 1977 Effeo:tl~e Head(ft) 53.3 53.0 55.5 55.4 55.3 52.8 4B.8 50.0 47.9 46.6 46.9 48.2 1978 Effective Head(ft) 4'3.4 51. 2 51 .. 6 54.2 ~...., ~ ._1 ••• ·-· 5'0!, 4 58.7 54.:3 5:3. :~: 52.6 51.::: 5::::.5 1 '37'01 Effeo:tive Head(ft) 54.7 "" " . .J ·-·. ·-· 56. '3 57. 1 5:::.0 59.0 56.4 52. '3 52.0 51.:::: 5~). 5 51.4 10-23 Un i ~-s Po,,J~-r· ( k ~J) 3'302 (1 0 0 (1 (1 (1 (1 (1 1 ::::6(12 21 :::1 '3'3 21 61n 21 7776 21 B127 21 701:::: 21 4676 Effi •: i ~·n•:y ( ~-~ ) 88.9 0. (1 0. (1 (1, 0 (1, 0 89.2 86.(1 Co() 7 0'-' • I 86. 1 86. (1 86.4 87. (1 Ene·t···;,J~:) (t·1kW·,) 2. 9[1 0. (1(1 0. (10 0.0(1 (1, 0(1 . 2. 68 5.9(1 4.61 5. 6~) 6.05 5.22 3.37 Tc•t.al 36.32 Units Power Effio:ieno:y Energy <kW) (%) <MkWh) 2483 B7.4 1.B5 0 0 0.0 0.00 0 0 0.0 0.00 0 0 0.0 0.00 0 0 0.0 0.00 0 0 0.0 0.00 1 2111 81.7 1.52 21 '3071 86.6 6.75 2~ 9413 84.4 6.7::: 21 9284 84.7 6.'31 21 9145 84.'3 6.BO 21 6464 E:'3.2 4.65 Tota.l ::::5.26 Units Power Effio:ieno:y Energy ( k ~~) .1 3960 1 1744 0 (1 e (1 0 0 0 (1 1 47::4 1 '304 ::: 1 '31:::3 1 '3056 1 :::9(13 1 7337 ( ~-~ ) ::: '3. 1 77.4 0.0 (1.0 ~c1 • o ~). 0 87.0 :::5. 6 :::4.::: :::5. 1 85.3 •:•C• t:' ._, '-' •. _1 ( t·lk ~·Jh) 2.95 1. 26 (1, (10 0.00 (1.0(1 0.00 3. 41 .-..., .-, t:•. I' .;. 6. 61 6.74 6.62 5. 2::: Tot..,.l ·::::·3.60 Average Annual Energy 51.59 2. Turbine/Generator Cost and Powerhouse Size Turbine/Generator Cost of 5.24 MW Tubular turbine for H = 60 ft. From (Fig 5-5*) = $1,000,000 Cost 2 Turbines = $2,000,000 3. Station Electrical Plant Capacity = 2 x 5.24 = 10.48 MW Cost for 10.48 MW (Fig 5-8*) = $415,000 For Multiple Unit Plant Using Table A (Fig 5-8*) Cost = (415,000 -95,000) + 2 x 60,000 = $440,000 4. Miscellaneous Plant Equipment For Plant Capacity 10.48 MW (Fig 5-9*) Cost = $114,000 5. Civil Powerhouse Costs Cost of powerhouse for multiple unit plant, cost per unit (Fig 5-16*) for o3 = 7.5 ft = $173,000 For 2 Unit Plant Cost = $346,000 Plant Area (Fig 5-16*) for 2 Unit Plant = 2 X 1100 = 2200 ft 2 Depth of Powerhouse for Excavation (Fig 4-22*) d = 2.503 + 2 -(2.5 X 7.5) + 2 = 20.75 ft 10-24 I I ) ' - J --l I I I \l : : Turbine is 2 ft above the tailwater. elevation is about 8 ft. above tailwater. a = d - 2 + 8 20.75 - 2 + 8 = 26.75 Use 27 ft. [xisting ground Excavation Cost for a = 27 and 2200 ft2 (Fig. 5-21*) is $50,000. Flood Protection, Take as 10 percent (Excavation and Protection Cost paragraph*) of civil cost, Cost _= 0.10 (.346, 000 + 50,000) = $39,600 Switchyard Civil Cost (Fig 5-38*) = $31,200 Foundation Cost, 2 percent of FERC 331 (Foundation Cost paragraph*)** 6. Penstock Design Flow = 2365 ft3/s Use Design Velocity of 12 ft/s Penstock splits to two sections at 30 ft. from plant. Bypass requires 60 ft. of conduit, but use velocity of 20 ft/s in this section. Requires 2 Bifurcations 20 ft. of penstock is on a 16 degree slope so requires a cost correction of 1 percent (Fig 5-25*). **Omit Until Final Summary Sheet if cost is for any time other than July 1978 10-25 Cost from (Fig 5-25*) Main Penstock v Cost = 12, Q = 2365 = $1680/ft. Turbine Branch Section v = 12, Q = 1182.5 Cost = $875/ft. By-Pass Branch, Use 20 ft/s and flow of 2365. However, on (Fig 5-25*) use v = 10 and half flow to obtain the unit cost. Cost = $1050/ft. Each Bifurcation Cost, v = 12, Q = 2365 (Fig 5-28*), Cost = $102,000 Summary Penstock Costs Tunnel Outlet to Powerhouse Branch = 1680(200-30)+20x0.01x1680 = 285,900 Two Bifurcation = 2 x 102,000 = 204,000 Turbine Branches = 2 x 30 x 875 52,500 Bypass Branch = 60 x 1050 = 63,000 Total = $605,400 7. Bypass Facilities Assume head on Howell-Bunger valve is 58 ft. Q 0.5 Valve diameter= 5.34 (H0 ·5 ) 10-26 r--: i I ! L _.J ~-· i I '-----' ,,~1 I, I i ;-·, , I I ' L __ ..j, ') : f L_j l__j r··· ' I i i, L....J For ·flow of 2365 ft3/s and head = 58 ft. 2365 °·5 d = 5. 34 ( ) 580.5 = 94.1 inch, Use 94 · From (Fig. 5-29)* Bypass Facilities: cost for 94 inch valve diameter= $385,000. 8. Tailrace Length of Tailrace is 100 ft. Cost (Table 5-3*) = 15000 + (100 x 200) =. $35,000 9. Switchyard Transmission Voltage is 34.5 kV, Generator voltage. is 4.16 kV Plant Capacity 10.48 MW, 2 Units Switchyard Electrical Equipment Cost (Fig 5-39*) = 190,000 + (2-1) (47,500) = $237,500 Switchyard Civil Cost was in Item 5 above. 10. Access Road One mile of access road to be constructed. to be a paved two lane road. Cost (Table 5-4*) = $255,000 11. Environmental Control Minimum Dust Control Needed. Cbst (Table 5-4*) = $10,000 10-27 12. Parking 13. Parking area to be paved is 100 ft x 200 ft Area = 100 x 200 = 20000 ft 2 or 2222 sq.yd. Cost (Table 5-4'*) = 7-x 2222 = $15,500 Escalation Factors Item Structure Reinforced Steel Penstock Turbine/Generator Tail race Misc. Electrical Equip. Switchyard Primary Roads Environmental Controls WPRS Index** July 78 2.28 2;48 2.38 2.31 . 2. 31 2.25 2.35 2.28 ** From (Figures 5-43 to 5-50*) 10-28 Est. WPRS Index 2.65 2.60 2.65 2.65 2.60 . 2.55 2.80 2.65 Factor 1.162- 1.048 1.113 1.147 1.126 . 1.133 1.191 1.162 i] :-] -~ __ ) ·J 1-~J ':J :=] ,-] ,_-l ,--l :"' _j :~] [J ·~] ·. _ _] ·] ~-l :_-] :] .---, : ) :.J 14. Cost Summary ,---"': FERC Escalation Escalated Acct. No. Description Cost* Factor Cost Total ------... 331 Structures & Improvements Site .01 Parking 15,500 1.19 18,400 .02 Environmental Construction Controls 10,000 1.16 11,600 ! i Powerhouse ') .21 Structural 346,000 1.16 401,400 .22 Exc av at ion 50,000 1.16 58,000 .24 Switchyard 31,200 1.13 35,300 .25 Flood Protection 39,600 1.16 45,900 Subtotal 570,600 .23 Foundation (2 percent of subtotal) 11,400 Total, Account 331 582,000 332 Reservoirs, Dams & Waterways .01 Penstock 605,400 1.05 635,700 t .02 Bypass Facilities 385,000 1.09* 419,600 .03 Tailrace 35,000 1.15 40,200 ; Total, Account 332 1,095,500 333 Water Wheels, Turbines and Generators 2,000,000 1.11 2,220,000 *In this instance valve cost is about 65 percent of cost --- . so modify structural value of 1.16 accordingly. 10-29 FERC Acct. No. 335 336 Description Station Electrical Equip. Station Electrical Switchyard Electrical Total, Account 333 Misc. Power Plant Equip. Roads Total Construction Cost Regional Factor (1) Regional Correction Contingency Engineering & Construction Management and Other Costs Interest During Construction Grand Total Cost* 440,000 237,500 114,000 255,000 10-30 --, I ·Escalation Escalated Factor Cost Total ----- 1.13 497,200 " _ _} 1.13 268,400 ) i J 2,985,600 --, 1.13 128,800 128,800 1.19 303,400 303,400 5,095,300 0 1,019,000 ·-I --' 1,232,900 1,410,600 $8,757,800 ---, ~I 15. Contingency r--. Take contingency as 20 percent of construction cost (Section 5, I f L_J paragraph Contingency*). L __! r~ ( I I L __ __, fl ! l__J rl I I : I \ __ ) c···. r-""'< I I i l-......J I' I I ' '-----' '.-......, I ; : I ~ I L __ J r-.. , , I L..i From Summary Sheet Construction Cost = $5,095,300 Contingency at 20 percent is = 1,019,000 Total = $6,114,300 16. Development Costs Development or indirect costs (engineering, construction manage- ment and other costs, paragraph Section 5*) suggests multiplier of 20 ·percent of final construction cost. An existing dam is being used for this project. Section 5 in the paragraph enti- tled 11 Existing Dams 11 recommends that an integrity review be made when an existing dam is being used for the first time in a hydroelectric development. The estimated cost for this review is $10,000 and should be considered as beyond the normal costs associ a ted with development costs when the flat 20 percent cost criteria is applied. Total Construction Cost = $6,114,300 Development Cost, 20 percent = $1,222,900 Dam integrity review = $ 10,000 Total = $7,347,200 17. Interest During Construction (I.D.C.) Assume construction money cost will be 12 percent, a construc- tion period of 3 yr. with 30 percent money spent first year, 50 percent spent second year and 20 percent spent 3rd year. 10-31 18. Annual Total Expenditure Year Expenditure Interest Of Prior Year Interest 1 2,204,200 132,200 0 0 2 3,673,600 220,400 2,204,200 264,500 3 1,469,400 88,200 5,877,800 705,300 Total 7,347,200 440,800 969,800 Tat a 1 I. D . C . = 440,800 + 969,800 = $1,410,600 Project Financing Project financing wi 11 be for an amount of $8,757,800, Summary Sheet. (Interest rates are assumed). DOE loan method will be used for financing: 75% will be Govt. Loan, 30 yr, 6-7/8 percent crf = 0.07958 One Million will be tax-exempt bonds 40 yr, 7 percent crf = 0.07501 Balance will be normal revenue bonds, 40 yr, 10% crf = 0.1023 Annual Debt Service on Govt. Loan ($6,568,000) = 6,568,000 X 0.07958 = $522,700 Annual Debt Service on tax-exempt bonds = 1,000,000 X 0.07501 = $75,000 Balance to be ordinary revenue bonds = 8,757,800 -6,568,000 -1,000,000 = $1,189,800 10-32 Cost --, J ' I - -, ' --' i -' • I I I [j I L...J ~~ ) I L_..J \1 L.J ,~) i ; l_) (\ I I I ~, L._.J .-I LJ r~ ; I L__...,l ,--, . I J ! ' I L.-> ~ ' I I I I L __ .J ,-...., I I L _ _j 19. Annual Debt Service on Revenue Bonds = 1,189,800 X 0.1023 = $121,700 -Tot~ Annual D~bt Service = 522,700 + 75,000 + 121,700 = $719,400 Economic Analysis The plant rating is 10.48 MW. The average annual energy product ion for the 12 year operation study is 52 x 10 6kWh. First Year O&M Cost, 1.2 percent of Plant Cost (I.D.C. not considered) = 0.012 X 7,347,200 = $88,200 Using (Fig. 2-1*) = 17200 (10.48)0 ·543 x 1.11**· = $68,400 An Average = $78,300 **Escalation (Fig 5-52*) Product ion Costs = 719,400 + 78,300 52 X 10 6 = 15.3 mills/kWh 20. Primary Energy Primary Energy for Power Plant Construction Penstock and Bypass Facilities Cost= (635,700+419,600) x 1.2 = $1,266,400 Road Cost = 303,400 x 1.2 = $364,100 10-33 Balance of Plant Cost ~ {5,095,300 + 1,019,000) -(1,266,400 + 364,100) ·= $4;483,800 Energy Intensity Factors, MJ/Ju.ly 1978 Dollar {Table 8-1*) Penstock , '44 .1 Roads , 154. Plant , 22.6 Energy used during construction by each item, ,July 1978 Dollar Penstock = 1,266,400 x 44.1 = 55·,8 x. 10 6 MJ Roads = 364,100 x 154 = 56.1 X 10 6 MJ Plant· = 4,483,800 x .22.6 = 101.3 X 10 6 ~1J Total = 213.2 x 106 MJ ,• '. In terms of dollar value at time of construction, assume Engineering 'News Record Index is 283.92. · Energy used = 213 2 X I06 X 26 2 ·59 . 283.92 = 197.2 X 106 MJ Time for Project to Replace Construction Energy= 197.2 x 106 .. 52 X 106 X 3.6 .. = 1.05 Years On basis of prior example the annual primary energy is small and would probably extend the replacement of energy about an additional week of operation. 10-34 :-_] :] ,: _1 ~J ~] ':] -1 '] ~l __ ....J -··l J CJ (j :.J ,-] :] ;~] _] :l r ~ I i . (___) ,---. ' I \ i L._ __ j L -· )/ I i L_) [I i ' L.._j [.J 1. EXAMPLE NEW DAM INSTALLATION A site is selected that will require the construction of a new dam. Fill material is available about a· mile from the site so earth dam will be constructed. Canyon is narrow at the site with an adjacent saddle that can be used for a spillway around the dam. The.following conditions exist: 0 0 0 The 0 0 0 Site elevation is 200 ft Abutment will require normal amount of grouting Primary and secondary roads will be required following assumptions will be made: The operation study will be the same as used dam example Type A powerhouse with two tubular turbines Penstock length will be 200 ft on existing o Tailrace length will be 200 ft 0 0 0 Penstock velocity, 12 ft/s A mile of new road to the powerhouse, 1/4 mile above road powerhouse to dam and 1 mile of haul road Dam will be earth filled, crest length of 2000 ft o Dam will have an outlet works o Normal amount of environmental control expense during construction 0 0 0 0 Parking area at the powerhouse site Construction in a region that has a cost variation index of 0.9 An economic life of 40 years Probable maximum flood flow is 3200 ft 3/s Turbine Runner Diameter 2-Tubular turbines 5.24 MW each, 60 ft. head and 1182.5 ft3/s flow from operation study. 10-35" Approximate powerhouse elevation = 200 ft, set turbine blade centerline at 2 ft above tailwater elevation. Uncorrected o3 (Fig. 4-10*) for 60 ft head and rating 5.24 MW = 7.2 ft. Altitude correction factor for 200 elevation (Fig 4-10*) -_( 2000:..200) 1000 = -0.0180 X 0.01 Tailwater correction factor (Fig 4-10*) for centerline setting 2 ft. above tailwater = 1.06 Tubular (propeller) Uncorrected 03 (Fig 4-10*) Altitude correction= 7.2 x (-0.018) Tailwater correction = 7.2 x 0.06 Total correction 03 = 7.2 + 0.3024 = 7.502 Use 7.5 ft. = 7.2 ft = -0.1296 = 0.432 = 0.3024 (Following the method shown in Section 4 "Turbine Selection" results in about the same result. 03 = 7.2 x 0.982 x 1.06 = 7.495 or 7.5 ft.) 2. Turbine/Generator Cost and Powerhouse Size Turbine/Generator Cost of 5.24 MW Tubular turbine for H = 60 ft. From (Fig 5-5*) = $1,000,000 Cost 2 Turbines = $2,000,000 10-36 --·~ l ;--l ! I I ' , __ j I , i l \ : ~---_1 r-~, I i L.. ____ ) !., --' \--J ,·-·! I l I I 't_ __ _j ! -1 I I ' 3. Station Electrical Plant Capacity = 2 x 5.24 = 10.48 MW Cost for 10.48 MW (Fig 5-8*) = $415,000 For Multiple Unit Plant Using Table A (Fig 5-8*) Cost = (415,000 -95,000) + 2 x 60,000 = $440,000 4. Miscellaneous Plant Equipment For Plant Capacity 10.48 MW (Fig 5-9*) Cost = $114,000 5. Civil Powerhouse Costs Cost of powerhouse for multiple unit plant, cost per unit (Fig 5-16*) for o3 = 7.5 ft = $173,000 For 2 Unit Plant Cost = $346,000 Plant Area (Fig 5-16*) for 2 Unit Plant = 2 X 1100 = 2200 ft 2 Depth of Powerhouse for Excavation (Fig 4-22*) d = 2.503 + 2 = (2.5 X 7.5) + 2 = 20.75 ft Turbine is 2 ft above the tailwater. elevation is about 8 ft. above tailwater a = d - 2 + 8 = 20.75 - 2 + 8 = 26.75 Use 27ft. 10-37 Existing ground Excavation Cost for a·-27 and 2200 ft 2 (Fig 5-21*) is $50,000. Flood Protection, take as 10 percent (Excavation and Protection Cost paragraph*) of civil cost, Cost = 0.10 (346,000 + 50,000) = $39,600 Switchyard Civil Cost (Fig 5-38*) = $31,200 Foundation Cost, 2 percent of FERC 331 (Foundation Cost paragraph*)** 6. Penstock Design flow = 2365 ft3/s Use design velocity = 12 ft/s and 14 ft/s for turbine branches Length Penstock = 200 ft Penstock shifts into two sections about 30 ft ahead of plant. Requires one Bifurcation Cost from (Fig. 5.25*) Main penstock, v = 12, Q = 2365 ft3/s Cost = $1680/ft Turbine branch v = 14, Q = 1182.5 ft3/s (Fig. 5.25*) = $760/ft Penstock and turbine branch cost = = 1680 (200-30) + (2 X 760 X 30) = $331,200. ** Omit Until Final Summary Sheet if cost is for any time other than July 1978. 10-38 ' i J ' ! ' ' _ _j ' I ' I ' r-l I ' I I '"-· j r •, I I I I I I I l Penstock Bifurcation Cost. v = 12. Q = 2365 (Fig. 5.28*) = $102,000. Total Penstock Cost = 331,200 + 102,000 = $433,200. 7. Tail Race 8. Dam -L~ngth of tail race= 200ft Cost (Table 5.3*) = 15000 + (200x200) = $55,000. Earth filled Dam Crest Length is 2000 ft, assume the fo 11 owing 1500 ft average height of 50 ft 500 ft average height of 30 ft Haul of material is one mile. Increase in unit cost is 10 percent (Earth Dam Paragraph*) Structure Volume (fig. 5-31*) = 1500 (260) + 500 (105) = 442,500 yd3 Unit cost (Fig. 5-32*) = $5.20/yd3 Increase for hauling = 0~52 Total unit cost $5.74/yd3 Dam Structure Cost = 442,500 x 5.72 = $2,531,100 Spill Way C.osts Probable maximum flood flow is 3200 ft 3/s and can have site so 20 ft head is used. 10-39 Head x I Capacity = 20 x ~00 = 1131 For this Value (Fig. 5-33*) spillway Cost = $260,000 Field Cost of Outlet Works Assume need to discharge a little over turbine design flow, use 2500 cfs as rating on outlet structure. Head is 20 ft. Cost is based on Head x ;-capacity or 20 X f2500 = 1000. Cost (Fig. 5-34*) = $580,000. Summary of Dam Costs 9. Switchyard Dam structure = $2,531,100 Spillway = $260,000 Outlet Works = $580,000 Transmission Voltage is 34.5 kV, Generator voltage is 4.16 kV Plant Capacity 10.48 MW, 2 Units. Switchyard Electrical Equipment Cost (Fig. 5-39*) = 190,000 + (2-1) (47,500) = $237,500 Switchyard Civil Cost was in Item 5 above. 10-40 ' I J I ! : I ' l { '.._ _ __) I l ' ' ' ! \ L, __ :,.---l ! i ~ --_I r-! I I :._-; ,--, : I I : ~-__ ...} :-"l I 1 I ' ,,J \ : I ) ,--.. : i l \ '--~-_) 10. Access Road One mile of 2 lane paved road to plant and 1/4 mile of single unpaved road to dam outlet works and 1 mile of haul road. Cost (Table 5-4*) = $255,000 Secondary road = 1.25 X 75,000. = $93,800 Unimproved road. 11. Environmental Control Minimum Dust Control Needed (Table 5-4*) at two sites~ Dam and Powerhouse Cost = 2 x 10,000 = $20,000 12. Parking Parking area to be paved is 100 ft x 200 ft Area = 100 x 200 = 20000 ft 2 or 2222 sq.yd. Cost (Table 5-4*) = 7 x 2222 = $15,500 10-41 13. Escalation Factors (2) (3) ill WPRS Est. (2) Index ** WRPS Factor Item July 78 Index ---- Turbine/Generator 2.38 2.65 1.113 Sta. Electrical 2.31 2.60 1.126 Misc. Equipment 2.31 2.60 1.126 Civil Powerhouse 2.28 2.65 1.162 Penstock 2.48 2.60 1.048 Earth Dam Structure 2.11 2.40 1.137 Earth Dam Spillway 2.26 2.75 1. 217 Earth Dam Outlet Works 2.40 2.85 1.188 Tailrace 2.31 2.65 1.147 Switchyard 2.25 2.55 1.133 Environment a 1 Controls 2.28 2.65 1.162 Primary Road 2.35 2.80 1.191 Secondary Roads 2.26 2.75 1. 217 ** Item shown or assumed to be the equivalent of index used. From (Figures 5-43 to 5-50*). 10-42 --, '_j ::._] ' I "---~ ----~ : I ( ' -· ---, ' I ! I I J --, I I I ' ;l '--' .--l I ! 1 I ·--' 14. Cost Summary FERC Escala- Acct. tion Escalated No. Description Cost Factor Cost Total I -, . I I ' 331 Structures and Improvements I '- ;-l Site ! I .01 Parking 15,500 1.19 18,400 : I ' .02 Environmental Con- struction Controls 20,000 1.16 23,200 ; I Powerhouse LJ .21 Structural 346,000 1.16 401,400 .22 Excavation 50,000 1.16 58,000 .23 Flood Protection 39,600 1.16 45,900 . 24 Switchyard 31.200 1.13 35,300 .25 Subtotal 582,200 .26 Foundation (2 percent of Subtotal 11 '600 Total, Account 331 593,800 ,--) I I 332 Reservoirs, Dams and Waterways I '-~ .01 Penstock 433,200 1.05 454,900 .02 Tailrace 55,000 1.15 63,200 .03 Earth Dam Structure 2,531,100 1.14 2 "885 '400 .04 Dam Spill way 260,000 1. 22 317 '200 . 05 Earth Dam Outlet Works 580,000 1.19 690,200 (---I Total, Account 332 4,410,900 : ! I ~--) .·-----) 333 Water Wheels, Tur- : ! bines and Generators 2,000,000 1. 11 2' 220 '000 ''--~ -I Station Electrical Equipment Station Electrical 440,000 1.13 497,200 Switchyard Electrical 237,500 1.13 268,400 I ' Total, Account 332 2,985,600 j ,--1 I ~ **From (Figures 5-43 to 5-50) , _ _) I i _, 10-43 'l . J FERC Escala- -l Acct. tion Escalated No. Description Cost Factor Cost Total ' ' I I 335 Misc. Power Plant Equipment 114,000 1.13 128,800 --1 I ~ __ j Total 128,800 336 Roads Primary 255,000 1.19 303,400 Secondary 93,800 1. 22 114,400 Total 417,800 .---, : i Total Construction Cost 8,536,900 ---.... I j REGIONAL CORRECTION FACTOR (0.9) (853,700) Regional Corrected Cost 7,683,200 --) ) I - Contingency 1;536,600 i--l Engineering & Construction Management and Other Costs 1,844,000 Interest During Construction 1,606,200 GRAND TOTAL $12,670,000 *Cost Base, July 1978. 10-44 :_] \.._~--' r ~---. : I ___ ) 15. Contingency Take contingency as 20 percent of Construction Cost (Section 5, Paragraph Contingency*) From Summary Cost Sheet, Construction Cost = $7,683,200 Contingency at 20 percent = 1,536,600 Total = $9,219,800 16. Development Costs Development or indirect costs (Engineering Construction Management and other cost, paragraph, Section 5*) suggests multiplier of 20 percent of final Construction Costs Total Construction Costs = $9,219,800 Development Cost, 20 percent = 1,844,000 Total = $11,063,800 17. Interest During Construction Assume construction money cost will be 11.5 percent, a construction period of ·3.5 year with 10 percent being spent first year, 25 percent each the second and 1 ast 6 months and 40 percent spent the third year. 10-45 Annua 1 Total Expenditure Year Expenditure Interest of Prior Year Interest ----------- 1 1' 106 '400 63,600 0 0 2 2,766,000 159,000 1,106,400 127,200 3 4,425,500 254,500 3,872,400 445,300 3 1/2 2,765,900 79,500 8,297,900 477' 100 TOTAL $l1,063,800 556,600 1,049,600 Total I.D.C. = 556,600 + 1,049,600 = $1,606,200 18. Project Financing Project financing will be for $12,670,000 as shown on Cost Summary. Assume financing can be by a WPRS loan. Entire funding can be a government loan over a 40-year period. Assume rate of 6-7/8 percent, crf = 0.07392 Total Annual Debt Service = 12,670,000 x 0.07392 = $936,600 19. Economic Analysis The plant rating is 10.48 MW The average annual energy production for the 12-year operation study is 52 X 10 6 kWh First year O&M Cost, 1.2 percent of Plant Cost (I.D.C. not used) = 0.012 X 11,063,800 = $132,800 10-46 (/ : ! _) l I I --, I ' ' I 1 I I __ _) I i ' -~ Based o~ (Fig 2-1*) O&M = 17,200 (MW)O.S43 = 17,200 (10.48)0 ·543 X 1.11** -= $68,400 **Escalation ·(Fig 5-52*) Figure 2-1 was based on-actu~l-experience in power plant opera- tion as noted in Section 2. The total project cost includes costs associated with dam construction which is about 46 percent of the project cost. Modifying the above annual cost to reflect only power plant cost results in a lower O~M. First Year O&M = 0.54 x 132,800 = $71,700 Using an average O&M value = 72,700 + 68,400 2 = $70,600 for the first year -Production Costs· = 936,600 + 70,600 ·52 X 10 6 = 19 mills/kWh 20. Primary Energy ·Primary Energy for Power Plant Construct ion Road Cost= 303,400 x 1.2: x 0.9 = 327,700 Penst6ck Cost = 454,900 x 1.2 x 0.9 = 491,300 Site Work, Parking, Tailrace = (18,400 + 23,200 + 63,200) X 1.2 X 0.9 = 113,200 10-47 Dam Cost= (2,885,400 + 317,200+690,200 + 114,400)x1.2x0.9 = 4,327,800. Plant Cost= (7,683,200 + 1,536,600) -(327,700 + 491,300 + 113,200 + 4,327,800) = $3,959,800. Energy Intensity Factors, MJ/July 1978 Dollar (Table 8-1*) Roads, 154. Penstock, 44.1 Site Work, 30.1 Dam, 27.9 P 1 ant, 22.6 Energy used during construction by each item in July 1978 Dollars Roads = 327,700 x 154 = 50.5 X 10 6 MJ Penstock Site Work = 491,300 X 44.1 = 21. 7 X 10 6 M J = 113, 200 X 30 .1 = 3.4 X 10 6 t~J " Dam = 4,327,800 X 27.9 = 120.7 X 106 MJ Power Plant = -3,959,800 x 22.6 = 89.5 X 106 MJ Total = 285.8 x 10 6 MJ In terms of dollar value at time of construction, assume Engineering News Record Index is 283.92 Energy Used During Construction = 285.8 x 106 262 ·59 283.92 = 264.3 X 10 6 MJ Time for project to replace Construction Energy = 26 4~~~~---52 X 10 X 3.6 = 1.4 Years 10-48 i i : j ' i ' I i ! ' ! I ,---, ' I I I : i : i I , I r -· I i I I i I Annual Energy Use, Intensity Factors (Table 8-2*) Dams, 0.07 MJ/July 1978 Dollar Power Plant, 0.32 MJ/July 1978 Dollar . Penstock, 0.06 MJ/July 1978 Dollar Consider site work and roads with power plant for this part of analysis, then Annual Energy Dam Penstock Power Plant Total = 4,327,800 X 0.07 = 302,900 MJ = 491,300 X 0.06 = 29,500 MJ = (3,959,800·+ 327,700 + 113,200) X 0.32 = 1 .408 X 10 6 M J = 1. 74 X 106 MJ In terms of dollars of time at time of Construction = 1. 7 4 X 106 X 262. 59 283.92 = 1.61 X 10 6 t~J This can be made up by the plant in about 3 days operation so does not materially change the time to replace the construction energy. 10-49 GENERAL SECTION 11 FEASIBILITY STUDY PROCEDURE The preparation of a feasibility study for a small low-head hydroelectric deve 1 opment is not inc 1 uded as a purpose of this report. This section outlines the next logical step, after an appraisal study has been approved, in a project development study. Many of the same appraisal study procedural steps occur in a feasibility study. A feasibility study, however, is a higher level study based on preliminary plans, better cost and technical data being a few of the upgraded input items over the basis of the appraisal study. PROCEDURE General After an appraisal study has identified and selected a potential small hydroelectric project for a feasibility study, several procedures are followed to determine the projects potential feasibility. The steps that must be taken for this analysis are reviewed here to provide an overview of the process and indicate the interrelationship of the various steps. Figure 11-1 shows the sequence of steps followed in making the feasi- bility study. Method The following steps are followed for the feasibility study and shown on Figure 11-1. 1.) Project Identification: This identification includes knowing the location and source of the projects main features, that is, addition to existing facilities, new dam and reservoir, possible interconnection points to electrical transmission networks and 11-1 any other feature which might appear to have an impact on the project•s cost or acceptance. 2.) Site Conditions: After a site (or sites) has been identified it is necessary to evaluate the existing site conditions which pro- cedure will include the following: o Procurement of site plans for any existing developments. o Obtain local topography map. o Determine the legal access to the site for both project construction and operation. o Obtain any existing data on site geology and determine the need for additional geologic exploration. · o Review the history of prior developments at or near the site to determine any possible constraints on this or future developments. o Determine the current status of water rights for hydroelectric development. 3.) Project Layout and Operational Criteria The preliminary project layout is made after evaluating the site conditions. The preliminary layout should include those evaluations required to determine the expected head on the generating unit. It is also necessary to establish if the water releases from the project are to be dictated by non-hydroelectric requirements. If water users govern the plant operation the power production can be significantly different if there is operational flexi·- bility permitting optimization of the power output. At this stage of the assessment both the project layout and determina- tion of operation criteria are preliminary and subject to later modification as the study proceeds. 11-2 I I '. 4.) Environmental Factors: In parallel with preparing the pre- liminary layout is-the in~estigation of the major environmental factors which include the following: o Effects of the project on fish and wildlife resources o Changes in the water quality o Increase or decrease in recreational benefits o Determine if an archaeological investigation is required o Impact on visual appearances A determination should be made on which of the above items could be significant in the project development. 5.) Institutional Factors: Also parallel with the preliminary lay- out preparation is the investigation of the institutional factors which include the following: o Plan development for accomplishment of the institutional factors o Application process for various required Federal and State 0 permits and licenses Negotiations with those governmental agencies that may maintain rights at the proposed site o Preliminary negotiations for the sale or transmission of the electric energy 6.) Power and Energy Generation: A determination should be made on the potentia 1 projects power and energy generation. The hydro- logic study is a key element of this portion of the study, since it is the basis for determining the project output, benefits and therefore its economic suitability. A first step is the deter- mination of the average monthly stream flows for a location on the river, near the dam site, and for the longest period poss i b 1 e. Data can be obtai ned from USGS pub 1 i cations, sup- 11-3 plemented, when available, by data from State, local agencies or private sources such as utility companies. Where records do not exist, are for short periods, or are inadequate it may be ne- cessary to synthesize records for the site by corre 1 at ion with nearby stream gaging or precipitation stations. The Corps of Engineers' program (HEC 4) is available to do this by computer. Before using the historic streamflow records, it is necessary to determine if there have been changes in the river system as a result of construction of regulating reservoirs, or of stream depletions for consumptive uses. If so, the historic streamflows should be modified to represent the present develop- ment level. Such data are sometimes available as a result of prior work by agencies interested in the watershed. If not, the process can be lengthy and complicated and subject to contro- versy. A simpler alternative, that may be applicable, is to endeavor to select a recent period of streamflows which will have the same averages as the long term record, wi 11 illustrate the variability of the monthly and yearly data, and will repre- sent the critical dry period. The streamflows adopted can then be used to eva 1 uate the power and energy output of the project and the size and effectiveness of any reservoir storage which can be provided by a dam. Where a new reservoir and dam are shown to be feasible and effective a cost/benefit analysis will be required to determine the reservoir volume and dam height. The second aspect of the hydrologic study is the determination of flood volumes, peak discharges, and their frequency of occurrence. From these data are developed the spillway desing flood and the lesser floods for planning the construction diversion works. A further requirement is to determine the tailwater curve for the dam or power plant site. This is used generally in its lower range for determining the operating head for the power plant, and in its upper range, which covers flood 11-4 flows, for the design of the project structures especially the powerhouse and any outlet works. 7.) Review Preliminary Project Layout: A cursory rev·iew should be made of the flow data and power production based on the given flow. A refinement should be made of the preliminary project layout dimensions or sizes of those project features which affect power generation wich would include: o Penstock length and diameter o Size of tailrace excavation o Preliminary estimate of the optimal turbine size and type o Head loss through the waterways o Tailwater calculated as a function of turbine flow 8.) Alternate Energy Source: It is necessary to identify where the energy is to be used in order to determine the expected cost of power that wi 11 be rep 1 aced by the proposed project. If the expected user is a non-generating utility (or commercia 1 com- pany) the alternate energy will come from power and energy purchases. If the expected power user is a generating utility then the alternate energy wi 11 1 ikely come from either proposed plant facilities or replacement energy from older less efficient generating facilities. In either case the expected cost of the alternate energy should be evaluated for use in estimating the value of power and energy from the proposed development. 9.) Major .Environmental Factors: On the basis of the refined project layout a review should be made of the environmental factors. An assessment should be made to determine which items could cause significant problems. resolve these problem areas. 11-5 A plan is developed to 10.) Initial Power and Energy Sales and Project Financing: When the estimated project capacity has been determined an initial evaluation for the prospects of power and energy sales and project financing can be started. This will include the following items: o If the project power and energy is to be used by the developer then the manner in which the power and energy will fit into the developers demand curves is reviewed o Identify the various potential power and energy purchases if any or all of the output is to be sold o If feasible make preliminary contacts with potential pur- chaser to determine the value (order of magnitude) of the energy for use in preparation of an economic assessment o Determine if probable project financing will be general obligation or revenue bonds o Determine if there are currently any government programs to assist in project financing, loans or grants for hydroelectric development o Determine the suitability for each method of financing and on a preliminary basis the best option to use 11.) Expected Power and Energy: Estimates should be made of the expected project power and energy output for a range of plant capacities in a band around the estimated optimal capacity. A minimum of four estimates should be made to establish the relationship between the operation and plant capacity. If it appears suitable to use more than one type of turbine, then power and energy estimates should be made for each type, including multiple turbines. The possibility for developing more power and energy by use of a l anger penstock to lower the 11-6 powerhouse (and afterbay) elevation to obtain a higher operating head should be reviewed. 12.) Estimated Project Costs: Estimated project costs should be made for each plant configuration and total plant capacity. The estimates need only be approximate as it will be the differences between the estimates which will determine the optimal capacity in the economic analysis. The project estimated costs should include costs for all remedial measures to be taken for environ- mental effects and any annua 1 operation costs of these items should be included. If detrimental environmental effects occur which cannot be remedied, if at all possible, an annual cost should be assigned to the environmental change and added to the annual operating cost. For each plant configuration (and unit size) a value of energy can be determined on the basis of the estimated energy outpu_t. If there is dependable capacity this credit should be accounted for with the energy value. 13.) Optimal Plant Capacity: Having the total project cost and estimated energy values for each plant .configuration, the optimal plant capacity can be determined by the following steps: o Evaluate the ·annual costs and benefits over the entire project life o Estimate the debt service, on basis of estimated capital 0 costs and method of financing, for each year for 30 to 40 year period Estimate annual first years operation, cost and rna i nten ance escalate estimated rate of escalation and replacement, future years by o Power and · energy benefits are estimated throughout the analysis in a similar manner 11-7 o Convert the future values of costs to present worth values using the assumed discount rate cost of money to the developer; then o For each configuration and capacity determine the ratio of present worth benefits to present worth costs, the overalT project benefit/cost ratio The optimal project is the one having the greatest difference between the total project benefits and the total project costs. If the benefit/cost ratio is less than one for all proposed configurations (and capacities), then the project is not a feasible one. 14.) Final Arrangement: On the basis of the optimal project con- figuration and capacity the final project layout drawings are prepared. These drawings will be much less detailed than the final design drawings but should be in sufficient detail to allow resolution of all space allocations or construction difficulties. A design specification should be prepared which establishes equipment, building and facility criteria and includes a project design and construction schedule. 15.) Final Environmental Requirements: A final determination should be made of all environmental requirements. All required remedial measures should be identified and associated costs estimated. All expected adverse environmental effects should be specified for later inclusion in the environmental impact statement. 16.) Final Institutional Requirements: A final plan for satisfying the institutional requirements should be prepared. Milestones should be established for all institutional requirements and a schedule established to meet the institutional requirements. 11-8 17.) Final Output: A final estimate of the project power and energy output is made. This estimate is prepared in a similar manner as earlier estimates, however, new data on project layout or operating criteria affecting the power output is included in the analysis. This power and energy output estimate should be con- sidered the definitive estimate for all further work. 18.) Final Cost Estimate: A final cost estimate is prepared based on the final project layout. This estimate includes all project costs, construction, development and other indirect costs. The bond issue or loan requirements can be determined from this total project cost estimate. An annual cost of operation is also made. 19.) Definitive Economic Analysis: A definitive economic analysis is made based on the final power and energy output estimate and the final cost estimate. This analysis is made in the same manner as the previously described economic analysis in determination of the optimal plant capacity. 20.) Financial Analysis: A review is made of the project on comple- tion of the final economic analysis. The review includes the following: o Financing of the project development o Costs associated with sale or transmission of the energy o Suitability of both the project and the developer for the assumed type of financing o Cash flow analysis during both the development period and the initial years of plant operation It is not unusual for a project that is economically feasible to have cash flow requirements that precludes project development. 11-9 21.) Project Schedule: A comprehensive project schedule should be prepared. The schedule should include significant milestones for design, purchasing of major equipment items, having a long lead time, construction activities and the process of meeting institutional requirements. 22.) Recommendation and Report: A final report and recommendations are made on the basis of the foregoing analysis. The recom- mendations should include any decision to continue the project and further studies that should be performed. Often special studies have to be made on items of environmental concern. 11-10 POWER ANALYSIS & OBTAIN FLOW DATA AND POWER CRITERIA + 11 COMPUTE POWER OUTPUT FOR RANGE OF CAPACITIES I + 170BTAIN FINAL POWER OUTPUT I I ANA YSIS 1 2 OBTAIN PROJECT COSTS FOR RANGE OF CAPACITIES .I • .. + .. 1 I PREPARE FINAL COST ESTIMATE .. * ~ Figure 11-1 ~ TIFY 11DEN PROJ ECT N 2EVAL EX IS CONDI UATE TING TIONS ~ MINE SCHEME, ONS AND l 3 DETER GENERAL ELEVATI OPERATION j CRITERIA I I DETERMINE 7MAKE ALTERNATIVE PROJECT POWER SOURCES LAYOUT 1 0 DETEtMINE PROJECT FINANCING AND VALUE OF POWER ... 1 3 MAKE E!ONOMIC ANALYSIS TO SIZE POWER PLANT SELECT CAPACITY I ~ + 14 DETERMINE FINAL ARRANGEMENT .. * • 19 MAKE FINAL ECONOMIC ANALYSIS I ... .. • 20MAKE 21 PROJECT FINANCIAL ANALYSIS SCHEDULE I 1,. • ... 2 2 RECOMMENDATIONS AND REPORT r----'+----, I REVIEW REPORT FINDINGS I + CONDUCT I SPECIAL STUDY ... I • PROCEED OR NOT PROCEED WITH PROJECT I Generalized Study Flow Chart 11-11 ~ ... .. NV ON EN A ANALYSIS + 4DELINEATE MAJOR ENVIRONMENTAL FACTORS 9 PROVIDE MITIGATION ~ FOR ENVIRONMENTAL EFFECTS + DETERMINE ENVIRONMENTAL COSTS ..__ I l + I ~ ~ 1 5 DETER MINE ENVIRONMENTAL REQUIREMENTS * .. INSTITUTIONAL ANALYSIS + 5DELINEATE INSTITUTIONAL FACTORS EVALUATE REGULATORY/OTHER INSTITUTIONAL FACTORS + + 16DEFINE INSTITUTIONAL REQUIREMENTS ,. SECTION 12 · SLMMARY The following is a brief summary of this Report. 1. A survey of existing small low-head hydroelectric plants indicated that an approximation to their average annual operation, maintenance and replacement cost, in July 1978 dollars, would be equal to 17,200 x (MW)0 ·543 . Replacement costs averaged about 23 to 24 percent of the annual operation and maintenance costs. 2. A survey of turbine manufacturers determined that several types of reaction type turbines are available in sizes as small as 50 kW and capable of operation on heads as low as 6.6 ft (2.0 m). 3. Methods of selection turbine size., determination of power and energy and suggested powerhouse arrangements were presented in Sections 3 and 4 of the Report. 4. Costs of turbine/generators and other equipment with all major cost items for a small hydroelectric development are presented in Section 5 of the Report. 5. Methods of making an economic assessment and methods of financing a hydroelectric development are presented in Sections 6 and 7 of the Report. 6. Method to determine the primary energy was presented in Section 8 of the Report. Generally the small hydroelectric development will replace the energy used during construction in one to two years of operation. 12-1 7. Using reasonable assumptions regarding site conditions, oper- ating conditions and the marketability of the electric energy it would be unusual if the small hydroelectric unit can be either smaller than 1000 kW or operated on heads less than 21.5 ft (6.6 m) and still be a viable project. 12-2 APPENDIX Item Computer Printout of Small Hydroelectric Plant Data Equipment Manufacturers Oat a Equipment Size Data Cost Summary Sheet Paqe A B c 0 i. I SMALL HYDROELECTRIC PLANT DATA 1. F'LAtn HAI·1E F'LAIH Ol~t~EF.: F'LAHT CAf'AC1TY <MW~ HO. OF LltHTS 1H1TIAL OPE RAT I Otl 2. TLIRE: 1 H'E I• AT H HO,, OF Lit~ IT~. ~1AtWFAC TLIF'E F: HF'E RATEI• HF' HEAD <FT) SF'E E I• ( F' F·r·D SF·ECIFJC SF'EEil 3. GENERATOR DATA HO. OF UHJT£. MAtWFACTUF:EF: CAPACITY (K\IA) AT F·F C·; \ VOLTAGE ( t:'·/ :o 4. GOVEF.·HOF.: !IFtTA t~O. OF Lltl IT::;: MANUFACTUF;EF.: TVF·E F'F;E~:~.UF:E <F"~.I ;o Htt~t:HERI• ALAE:AI·1A F'CII~EF.: COt1F'AilY 45. 1 I 1%3 1 ALL 1 ~. CHAU1EF·~. F I >o:E I• f'F.:OF'EL LEF: ~ ~ "' bt· ..... 10~.E: 136. 1 1 ALL 1 ~: C:HALMERS 475(1(1 C."" ...... 13. e: WOOI•I·lAF.:I• CA:F.: I tlET 35(1 5. GEHERATJOH DATA <AVERAGE 1974-1978) GEt~EF:ATIOtl (I::I·JH.,IO··£.) 1~:9,(, PLAtH FACT OF. · • • 4::: f'LRIH tl(•. £.. OFEF'AT I 01~ e ~1A I tlTEtlRtiCE C:O~:T I•ATR OPEFRTIOH COST CHILLS/KWH) MAINTENANCE COST CHILLS/KWH> (JULY 19~8 AVEF.:AGE !974-197~ • : E:"? .55 0 & M COST <MILLS/KWH' I. 44 7. REPLACEMENT COST < ~: OF MA I tHEHAtlCE CO~:T) E:. A\IA I LAI: ILl T ·.,· FACT OF.· (A\IERAGE 1974-197:::) 95.34 0:.. 11AitHENAtlCE FF:EOUEtlCY ( F =H:E OUE tn, I= I NF F.:E (!LIE IH, A=A'..-'E F'AGE.' F.:UtlllEF ~-I•I':.CHAF·GE FEATUF·E~. A TUF:I:ItlE GUJIIE t:EAF lNG~: t ~:EAL I GEtlE F.: AT OF: T HF:U ~. T :;. GU JIIE t:E AF: l t~G~. I STATOF POLES I l tlS T f':LI11Etn AT I Oil I GOVEF:NOF:. I (IT HEF.· I 0. I·JAT E F: OUALI T ·,· :; OF TIME WATEF: C.OtHAit~:. !;:ILT, SAtli• OF: OTHEF MATEF:IALS WHICH CAUSE WEAF: UNUSUAL CONDITIONS A-1 Pf1GE 1 1 • F·LAtn I~AI·lE F'LAtn OLJtlEF: F'LAin CAF'ACIT'o' (IH·J) NO. OF LlllllS· IlliTIAL OF'EF:AT I 011 .. TLIRI· I I~E IIATA ... tlO. OF Lilli H· ~lAilUFACT UF·EF T','F'E f<·f1TEI• HF HE A !I (FT) ~:F·E E I• ( F:F·r·l • ~.F'EC IF IC SF'EEI1 :;:, GENEF:ATOF: IIATA NO. OF Lilli H. ~1Ail LIF A C:T LIF:E F: CAF'ACITV <I<VH) AT F·F ( ~·~ ) '.,i(IL TAGE • .. t .. '•/ .• 4. GO'.,.' E F: ll 0 F IIHTH 110. OF Llll I T ·:. MAtlUFAC TUF EF: T ','F'E F' F' E ~. ::.u F: E ' F' ·:. I > HEI~R'r' H. tlEEL 'o' ALA~AMA POWER COMPANY ~: 1966 3 HEI·JPOF:T I~EI·JS: FIX Ell F·ROF'ELLEF: 335(10 35. (1 E: 1. 8 17S.9 CEHERAL ELECTRIC 270M 9(1 11.5 ~: WOOIIIJAF:II CAB I I~ET 33(1 ':·. G E tlE F·AT I Oil I1ATA ( A'.,.'EF:AGE 1974-197 ~: :·· GEIIE f'·AT I Orl ( I.I·JH'* 1 (1····6 :• F'LFtllT FFtC TOF: F'LAilT IW. f. N·EFhTIOt~ :~. MAIIlTEI~AIKE co::T I1FtTFt <.TUL\' 0 F·EF: 11 T I 0 ll C. 0 ~. T n1 ILL~: .-·t:~JH > 1973 AVERAGE 1974-1978• 1·111 I tn E llAIIC E CO::n 0·1 ILL ~:/I(I·JH':o 0 t M COST tMILLS/KWHj 7. F:EF·LAC.E11EilT CO~:T 0:: :·; (IF MR I llTE11ANC'E (:(1ST) :::. A'.,.'RILAI:ILITY FACTO!'· CAVEFRGE 1~7~-1978) ·~. l·lR I IHEI~AtlC E FF·EC•UEilC'l o: F =F F·E C•U E rJT, I= I liFF:E OUEIH, A~:.AVEF:RGE.> F'Ut<tlEF. :; I1 I ·:.c HAF:GE FEATUF·E::. R HIF' I:! tl E.G 1.1 I I•E lE RF· ltlG ·:. t ~:E AL I GENEFATOF THF'UST t GUIDE ~EAFINGS I STATOF F'GLES I Jti':.TF'U11EtlTATIOtl I GO'·/EF'tiN· A OTHEF 1 (1 • L·J R T E F· 0 1_1 Hi... I T ',' ~ OF TIME WATER CONTAINS SILT, SAND OF OTHEF MATERIALS WHICH CAUSE WEAF Ullli'::UAL c OIHI IT I OilS· A-2 ~I:' • _ . .,_1 1. 62 96.44 F't=IGE 1 1 -J '] 1 • f·LAtlT HAtlE PLAtH OWt~EF: PLAtH CAPAC lTV (MI~) NO. OF UNITS J I~ lT J AL OF'Eii:AT JON ~, .... TUii:l:JHE NHA NO: OF UtUTS ~lA tW FA C:T UF: E F: n'PE li:ATEII HP HE Ail (FT:O SPE£II ( F:Pt·D SPECIFIC SPEEI' ~ . .:-. GENERATOii: IIATA HO. OF UIHH: MANUFACTUF·ER CAF'AC I TY <KVA) FIT F'F ( •,.· \ VOLTAGE (I':: \I) 4. G OVE F· t~ OF: IIATA 1~0. OF UtHH: MAtWFACTUF:EF: T'I'F'E F'F:E::::UF:E (PSI) HOLT ALA~AMA POWER COMPANY 4(l. (l 1 14168 1 I:ALitl~ I N-L I t·lA-HAf'l I L TOt< F J XEir PF:OF'ELLEF: ~560(1 58. (l 100. (l 147.~ 1 GENERAL ELECTRIC 4500(1 E;9 13. e: 1 EALDWIN-LIMA-HAf'liLTON CAI: I tlET 3~·(1 5. GENE!': AT I Otl IrATA ( AVEF:AGE 1974 -197E:) GENERATION CKWH~10A6) 167.7 • 4E: f'LAtH FACTOF· PLAin tW. 6. OPERATION t MAINTENANCE COST DATA <JUL'I' 1978 AVERAGE 1974-197E' OPERATION COST <MILLS/KWH:O ~9~ MAINTENANCE COST <MILLS/KWH) .63 0 t M COST <MILLS/KWH> 1.59 7. REPLACEMEtlT co::T <% OF MAINTENANCE COST> E:. AVA I LAI: ILl TY FAC:TO.F: <AVERAGE 1974-19~8> 9. MAINTENAtlCE FF:E(ILIEtK',· <F=FF:EOUEIH, J .. J t~FF.:EC1 LIEIH, A=AVEF.:AGE > F:UWIEF: -~ I1 I ~:C:HAF:GE FEAT UF:E S. A TUF:EINE Gu;DE ~EAF'INGS ~ SEAL I GENEF'ATOP THF'UST t GUIDE EEAF:INGS I STATOR POLES I lNS.H:Ut·lEtlTAT IOH I GO\IEF:tiOF: A OTHEF· 10. WATER QUALITY % OF TIME WATER CONTAINS SILT, SAND OR OTHER MATERIALS WHICH CAUSE WEAF UNUSUAL CONDITIONS A-3 94.90 1 • f'LAIH IH11'1E MITCHEL F'LAIIT OlmEF· ALAtAMFt f'OWER COMF'ftll\' f'LAIH UtF·ACI n· ( Ml~) NO, (IF UIIIH- Wl.TlftL OF'ERAT I 011 ~ . .TLtiU: lt~E IrATft .... NO •. OF utn r:. MAIIUFACTUF EF T \'F'E I':ATElr HF' HEAI• (FT> ~-F·EEI• ( F;F·r-L· H·ECIFIC SF'E E I• IW. OF UIIIH· ~1AHUFACTUF:EF.: n'F'E I':FtTEir HF' HEAl• ( FT::• ~-F'EEit ( F:F·t·1 :• ~-F'ECIFIC ~-F'E Eit .,:;. GE HE F·FtT OF: l•F<Ht 110. OF Uti IT~- 11AtiUFFtC TUF.EF: CFtF'FtC In· ( t: VFt.! AT F·F (\) \o'OLTFtGE (1..\-') tW. (IF UtilE 1·111 tiUF FtC T U F: E F: CFtF·FtC I TY (.J'::',.'A · .. AT F'F ( \:.1 VOLTAGE ( t: ...... ::. 4. G 0 '·.IE F: tiOF: l•Ftl A 110. OF Lttll r::: MAt~ UF ACT U F: E F: T'o'F·E F·f': E.S ~: L1 F: E (F·~. I ' 110. OF Uti! H. 11FttWFAC TUF·EF T'o'FE f'F· E ::. ·:.u F E •. F·~-1 , 72.5 4 1923 3 ALLIS CHALMEF:~: FRAIKIS 254(1(1 70. (1 1 ee. c1 76.7 1 ALLIS CHAU1ER~: FRFti~C IS 31eee 70.0 9(1. (1 ~: GEHEF:AL ELECTRIC 20(H)(l e:e: 6. €- 1 GEHEF:FtL ELECTF:IC 25B~)C1 e:e 6.6 3 ALLIS C:HALMH:~: ACTUATOF: 2BC, WOOirWFtF:I• CAE:ItiET 3(1(1 ~-• G E H EF· F< T I 0 t l I• Ft T A 0:: A'.,.' EF: AGE 1 9 7 4-1 9 7 E: ) GEtiEF'FtT I Oil •.II·IH• 10 t· • f'LFtiiT Ft1C T OF • 6(1 f'LAIIT IICI. t. OFEF:Ftl lOt~ ' 1·1PltHEIIFttiCE CO~-T IrFtTFt (JULY 197'E: A'·.·'EF·AGE !o:-7'4-1~7'::: • OF'EF't1Tl0tl CO~-T (MILL~-'l;j.JH> .E:O !·1Ft lilT EllA tiC E co:. T <111 LL~: .. -·I<I·IH o , 4 E: (I ~ 1·1 co:.l 011LL~-'l:t-JH • 1. ZSo 4 F'HGE 1 7. REPLACEMENT COST (% OF MAJHTEHANCE COST> e. AVAJLA~ILITY FACTOR ~AVERAGE 1974-1978> ~. MAIHTEHAHCE FREQUENCY ~FKFREQUENT, IEINFREPUENT, A=AYERAGE) RUNNER & DISCHAPGE FEATURES A TUR~INE GUIDE ~EAPINGS l SEAL I GENERATOR THRUST t GUIDE EEAPINGS I STATOR POLES I IHSTIW~IENTRTIOt~ I GOVERNOR A OTHER 1e. WATER QUALITY % OF TIME WATER CONTAINS SILT, SAND OR OTHER MATERIALS WHICH CRUSE WEAP ut~u::uAL COHII IT I 01~·:. A-5 F'LRtll tW. 4 F'AGE ~ / 1 • f'LAIH NAI·1E WE Iss. f'LAIH (lt.Jt~EF-: ALA:E:AI·1A f' OI·J E F~ (:(11·1F·Atr,· PLANT CAF·AC I TV na~) E:i'. 8 NO. OF UNIH: ~. ~ JHI.TIAL OF'ERAT I 01~ 1%1 .., ... TUR:E: I I~E I1ATA NO •. (IF UNITS. .-. ~ I'IAI~UFA C T UF' E F: ALLH. CHAL ME F·S: TVF·E F I >:EII F"F.: OF' ELL E F· RATE I• HF" 39 11)0 HEAI• (FT:> 49. (, Sf'EEII ( RF'i·1 > 9(1. (, SF'ECIFIC SPEED 137. ~: 3. GEHEii:ATCIF~ I1ATA HO. OF UNITS 3 I'IAIWFACTUF~EF~ WESTINGHOUSE CAPAC In' O<VFi) 32~·(,(, AT F'F (\) 90 VOLTAGE <•::v:.. 11. ~. 4. GCIVERIWF: II ATA NO. OF UIUH 3 MAIIUFACTUF:ER W(I(I!II·JAF:I• TYF"E C:A:E: I NET F'RES·S·UF:E (f'S.I> 3CIC, 5. GEt~EF:ATIOtl I!F1TA (AVEF:AGE 1974-197.::> GEHEF'ATlCIN <KWH•10A6) F'LAIH FACTOF: 254.9 . ~:~: t.. OF"EF:RT I Oil t ~1A IIHEt~RrlCE CO:::·i OF' Eli: AT I Oil (:(I~:T 0'11 LL s. ··'U·JH > MH I IH E NA IKE COS: T ( 1'11 L L S: .. ·'I·::I~H > 0 t M COST <MILLS/KWH> DATA <JULY 197~ AVER~~E 1974-197S• .79 7. REPLACEMENT COST C% OF MAINTENANCE COST> 8. AVAILAtiLITY FACTOR <AVERAGE 1974-1978) 9. 11AIIHEilAHC'E FF:EC!UEIK\' < F o:FJ;·E(IUE tll, I= I t~F F:E NtEtlT, A= R'..."EF·AGE :·· RUNNER t DISCHARGE FEATURES TLIF::E:JNE.GUliiE :E:EAF:IIiG·::. ~ ::EAL. GENERATOR THRUST l GUIDE tEAPIHGS STATOR F'OLES INSH:UI1EIHAT I Oil GOVERNOR A (ITHEF: 10. WATER QUALITY ::.-; OF TIME WATEF: C:OinAII~~: SIL 1, ~:All!! OF OTHEF MATERIALS WHICH CAUSE WEAR UIWSUAL CON!1 IT I OilS: A-6 ·~·-· • ·-1~ 1 • ~: 1 · F·AGE 1 F'LAtH HO. 10 1. PLAtH t·~AI·1E BUCK PLAtH O~·Jt·~EF.: AMEF.:ICAH ELECTPIC POWER COMPAHY PLAtH CAPAC IT\' ( 1·1 ~·J > t~O. OF ut~ n::: I tH TIAL OPEF.:AT I Ot·~ 2. TUF:I: I ~~E !lATA t~O. OF UtHTS 1·1AHUFACTUPEF.: T\'F'E RATE II HP HE Ail <FT> SPEEII ( PPI·1 > SPECIFIC :::PEEII ::::. GEt·~EPATOF.: !lATA t~O. OF Ut·~ IT::: I~ At·W FACT U F.: E 1': CAPAC IT\' ( K··.·'A) AT PF ( ~-~ ) 'v'OL TAGE ( K··.··) 4. GOiiEF.:t-lOF: !lATA tW. OF LitH r::: 1·1 At·~ UF ACT U F: E F.: T'r'PE PF.:Es:::uF.:E <P:::I > 10. (1 ~: I. P. 1·10F.:F.: IS F I :'O:EII PPOF'ELLEF: 35(H) 34.0 97. (1 6':1. 9 :=: GEt~EI':AL EL ECTF.: I C ~: 150 13.2 :::: ~·J 0 Oil ~·J A F.: II 5. GEHEPATIOH DATA tAiiERAGE 1974-1978) GEHEF.:ATIOH <KWH*10A6) PLAtH FACTOF: 4 7. 1 .54 .6. OPEPATIOt-l & MAIHTENAHCE COST !lATA (JULY 1978 AVERAGE 1974-1978' OF'EF.:AT I Ot·l CO:::T ( 1·1 ILL::: ···fn·JH) 1. 19 MAIHTEHAHCE COST <MILLS/KWH> .97 0 & M COST <MILLS/KWH) 7. REF'LACEMEHT COST C% OF MAIHTEHAHCE COST) 8. AVAILABILITY FACTOR tAiiERAGE 1974-1978) 9. MAIHTENAHCE FF.:EQUEHCY < F=FF.:EG'UEtH, I= I t·lFF.:EQUEtH, A=A'·iEF.'AGE·) RUt-lt-lEF.: & DISCHARGE FEATURES TUF.:B I t~E GUIDE I: EAR I t·~G::: t., :::EAL. A GEHERATOR THRUST & GUIDE I:EARIHGS A STATOR PbLES I IHSTRUMEHTATIOH I GOiiERHOP A OTHEF: 1 (1. ~·JATEF.: C!UAL I T'"i' % OF TIME WATER COHTAIHS SILT, SAHD OR OTHER MATERIALS WHICH CAUSE WEAR UHUSUAL COHDITIOHS A-7 2. 16 PAGE 1 PLAtH t·W. 11 1. PLAtH tlAt·lE B\'LLESB\' PLAtH O~·ltiEF: At·1EF.: I C:Atl ELECTF: I C F·O~·JEF.: COt·lF'Htl'r' PLAtH CAPAC IT'/ ( t·l ~·J ) t·W. OF Ut·lJH; ItHTIAL OPEF~AT I Otl 2. TUF:B I t·lE DATA t·lO. OF Ut·ll T ::; t·l li tl U FACT U F: E F: T'/F'E F.: A TED HF' HEAD O::FT) SPEED ( f':F·t·l) SPECIFIC ::;F·EED 3. GEHEF:ATOF: DATA t·lO. OF Utl IT::; t·l A tW FACT U F~ E F: CAPAC I T'l (KVA> AT PF ( ~·~ ) '·/OL TAGE ( K!·,·· > 4. G 0 ',' E F.: tl 0 F.: DATA tW. OF UHITS t·l A tl U FACT U F: E F: T'r'F'E P F~ E ::; ::; 1_1 F~ E (F'::;I) 20.0 4 4 I. P. t·lOF~F: I::; Fl:'O:ED PF.:OF'ELLEF.: 6(1(10 4'3. (1 116. (1 69.:3 4 GEt·lEF:AL ELE CTF: I C 600(1 9(1 1 .,, . ., ...... .:.. 4 ~·J 0 0 D ~·J AF.:D A 5. GEHEF.:ATION DATA <AVEF.:AGE 1974-1978) G EtlE F.: AT I Otl < fn·JH* 1 O··· 6) PLAtH FACTOF: 6. OPEF.:ATIOH & MAIHTEHAHCE COST DATA (JULY 1978 AVEF.:AGE 1974-1978' OPEF.:ATIOH COST <MILLS/KWH> 1.06 MAIHTENANCE COST <MILLS/KWH) 1.20 0 & M COST CMILLS•KWH) 2.27 7. F:EPLRCEMENT COST 0:: :-~ OF t1A I tHEtlAtlCE CO:O;T) 8. AVAILABILITY FACTOR <AVERAGE 1974-1978) ·~. t·1A I tHEt·lAt·lCE FF.:ECOUEt-iC'/ < F =F REOUEtH, I= I t·lF PE OUE tH, A=A '·/EF:AGE·) 50 F.'UtmEF.: :: .. D I ::;CHAF.:GE FEATURE::; A TURBIHE GUIDE BEARIHGS & SEAL F GEtlERATOR THF.:UST ::., GUIDE BE A F.: I tlG::: A STATOR POLES I I tl::. TF:U t·1EtH AT I Otl A GOVERNOR I OTHEF: 10. WATEF.' OUHLITY % OF TIME WATER CONTAINS SILT, SAND OR OTHER MATEF.'IALS WHICH CAUSE WEAR UNU:::UAL COtlD IT I Ot-l::: MUDDY WATEF.: ONLY DUPING FLOODS A-8 PAGE 1 I '' PLAtH tW. LEE::;'·iiLLE 1. PLAtH tlAt·1E PLAtH O~·H-lEF: AMERICAN ELECTRIC POWER COMPANY PLANT CAPACITY CMW) tW. OF Utl IT::; INITIAL OPERATION 2. TURB I tlE DATA t-Hl. OF Ut·l IT::; t·1AtlUFACT UREF: T'r'PE f':ATED HP HEAD CFT) SPEED ( F:Pt·1) SPECIFIC ::;PEED 3. GENERATOR DATA tW. OF UtHT:3 ~1At·l U FACT U F:E F: CAPAC I T'f' ( K'·iA) AT PF (\) VOLTAGE (f<'·/) 4. GO\·'ERt·lOF: DAH1 t·lO. OF UNIT::; t·1AtWFACTUF:ER TVPE PF:E::;::;;URE ( p:;:; I) 4(1, (1 2 1962 .-, "' BALDWIN-LIMA-HAMILTON F I ::·::ED BLADE 323(H) 65. (1 13E:. 5 2 ELLIOTT 25(1(H) 13.8 2 ~·J 0 0 D ~·J A F.: D ELECTRICALLY DRIVEN :3(1(1 5. GENERATION DATA (AVEF.:AGE 1974-1978) GENERATION (f<WH*10A6) 5:::. 9 PLAtH FACTOF: . 17 1 -, ~ 6. OF'ERATIOt·i :~, t·1AitHErlAtlCE co::;T DATA OPEF.:ATION COST (MILLS/f<WH> MAINTENANCE COST <MILLS/KWH) (JULY 1978 AVERAGE 19~4-1978~ "77 . '' 1. 49 0 & M COST (MILLS•KWH) 2.26 7. REPLACEMENT COST (\ OF MAINTENANCE COST) 5(1 :::. A\IAILABILIT'r' FACTOF: <AVERAGE 1974-1978) 9. MAINTENANCE FREQUENCY ( F=FREQUEtH, I= I t·1FF:EOUEtH, A=A'·iERAGE) RUNNER & DISCHARGE FEATURES TURBINE GUIDE BEARINGS & SEAL A GENERATOR THRUST & GUIDE BEARINGS A STATOR POLES I INSTRUMENTATION A GOVERNOR A OTHEF: 10. ~·JATEF.: OUAL I T'r' \ OF TIME WATER CONTAINS SILT, SAND OR OTHER MATERIALS WHICH CAUSE WEAR UNUSUAL CONDITIONS A-9 f''AGE 1 PLAtH tlO. 1:::: 1. PLAtH tlAt·lE t·l I AGAF.:A PLAtH 0 ~.Jtl E F.: A t·l E F: I C A tl E L E CTF.: I C PO ~·J E F: C 0 t·l P A tl\' PLAtH CAF'AC IT'/ < t·1 ~·J ) 3.0 t·lO. OF U t~ IT::: .-, .::. ItHTIAL OPEF.:ATIOH 1954 2. TUF.:B I tlE DATA t·lO. OF Ut·l IT::: 2 t·l A t·W FACT U F.: E F~ .JAt·lE:.:; LEFFEL TYPE \o'EF.:TICAL FIXED BLADE F.:ATED HF' HEAD <FT> SPEED ( F~Pt·l > SPECIFIC :::PEED 3. GEt·lEF.:ATOF.: DATA tW. OF UtHTS MANUFACTUF.:EF.: CAPAC I T'l' (~<VA> AT PF ( ~-~ ) VOLTAGE ( ~::: '•,•') 4. GO\·'ERHOF.: DATA HO. OF UtHH: ~1 A t·WFA C T U F.: E 1': T'I'PE F'F.:ES~:UF.:E <P:::r) 2200 6(1. (1 277. (1 77.8 2 ELLIOTT 15(10 80 2.4 2 ~·J 0 0 D ~·J A F.: D 5. GEHEF.:ATIOH DATA CA\o'EF:AGE 1974-1978) GEHEF.:ATIOH CKWH*10A6) PLAtH FACTOF.: 9.:::: .-.~ .. ;.. ·-' 6. OPEF.:ATIOH & MA}HTENANCE COST DATA <.JULY 1978 AVERAGE 1974-1978J OPEF.:ATIOH COST <MILLS/KWH) 5.60 MAIHTEHAHCE COST (MILLS/KWH) ::0:.48 0 & M COST <MILLS-KWH> 9.08 7. REPLACEMEHT COST (% OF MAIHTEHAHCE COST> :::. A'•/A I LAl::I L I T'l FACTOF.: CAVEF.:AGE 1974-1978) 9. MAIHTEHAHCE FF.:EQUEHCY C F=FF.:E QUEtH, I= I t·lFF.:EC•UEtH, A=A'·l E F.:AGE·) F.:UHHEF.: & DISCHARGE FEATUF.:ES TUF.:BIHE GUIDE BEAF.:INGS & SEAL GENEF.:ATOF: THF.:UST & GUIDE BEAF.:IHGS :HATOF.: POLE::; I NSH:Ut·lEtHAT I Otl GOVEF.:t·lOF~ OTHEF.: 1 i). ~~ATEF.: QUALI T\' % OF TIME WATER COHTAIHS SILT, SAHD OR OTHEF: MATEF.:IALS WHICH CAUSE WEAR UHUSUAL COHDITIOHS SILT DUPING FLOODS OHLY 4(1 A-10 F'AGE 1 ~·LAtH tW. 1 4 1 F'LAtH t-IAt·lE REU::;Etl::; FLAtH Ol·JHEF.: AMEF.:ICAt-1 ELECTF.:IC POWEF.: COMPAt-IY PLAtH CAPAC IT\' ( t·ll·J) t·lO. OF UtUT::; ItUTIAL OPEF.:AT I Ot·l 2. TUF.:B I tlE DATA t·lO. OF Utl IT::; t·1AtWFACTUF.:EF.: T'r'PE F.:ATED HP HEAD O::FT:O ::;PEED (F.: p t·l) ::;PECIFIC ::;F'EED ::::. G E tl E F.: AT 0 F.: DATA tw. OF UtUTS t·1AtlUFACTUF.:EF.: CAPAC IT\' ( t:::•·.··A) AT PF ( \) '·/OL TAGE ( ~::: •.,.• ) t·JO. OF UHITS t·1 A tW F ACT U F.: E F.: CAPAC IT\' ( ~::: • ... • A) AT PF • .. ,··~ ) '·/OL TAGE ( ~::: •.,.• ) 4. GOVEF.:t·lOF.: DATA t·lO. OF Ut·l IT::; t·l A tlU FACT U F.: E F.: T\'PE PF.:E::;::;UF.:E 0:: P ::; I > 12.5 5 19:31 "" ·-' .JAt·1E::; LEFFEL FJ:o<ED PI':OPELLEF.: 164.0 GEt·lEF.:AL ELECTF.: I C ~: 125 E:(1 4.2 2 :3125 :::o 4.2 5 l·JOODl·JAF.:D 5. GEt-IEF.:ATIOt-1 DATA <AVEF.:AGE 1974-1978> GEt-IEF.:ATIOt-1 <KWH*10A6) PLAtH FACTOF.: 40.6 6. OPEF.:ATIOt-1 & MAit-ITEHAt-ICE COST DATA O::.JULY 1978 AVEF.:AGE 1974-1978) OPEF.:ATIOt-1 COST (MILLS/KWH) 1.76 MAit-ITEt-IAt-ICE COST O::MILLS/KWH) 1.94 0 & M COST <MILLS/KWH) :~:. 70 7. F.:EPLACEMEt-IT COST (% OF MAINTENAHCE COST> 8. AVAILABILITY FACTOF.: CAVEF.:AGE 1974-1978> 9. MAit-ITEt-IANCE FF.:EQUEt-ICY ( F=F F.:EC!UE tH, I= I t·WF.:EQUEtH, A=ft'·/EF.:AGE > RUt-lt-IER & DISCHAF.:GE FEATUF.:ES A TUF.:BIHE GUIDE BEARit-IGS & SEAL F GEt-IEF.:ATOR THRUST & GUIDE BEARit-IGS F STATOR POLES A It-ISTRUMEt-ITATIOH I GOVEF.:t-IOR I OTHEF.: A-ll PAGE 1 1 (1, l•lATH: OUALI n· :·: OF Tlt'1E l~ATER COtHAHIS SILT, ::;AttD OR OTHER MATERIALS WHICH CAUSE WEAR UNUSUAL CONDITIONS A-12 PLAtH ItO. 14 PAGE 2 1. PLAtH t·lAt·1E t·lDlF'OF.:T t·lO. 11 PLAtH O~·ltlEF: CITIZENS UTILITIES COMPANY PLAtH CAPAC I T'l ( t·1 ~·l) tW. OF Utl ITS ItHTIAL OPEF.:AT I OH 2. TUF.:B I tlE DATA tlO. OF Ut·l ITS t·1At·WFACTUF.:EF.: T'r'PE F.:ATED HP HEAD (FT> :o;PEED ( RPt·1) ::;F·EC IF I C ::;PEED :~:. GEtlEF.:AT OF.: DATA tlO. OF Utl IT::; t·1A t~ UF ACT U F.: E F~ CAPAC IT\' ( K•·,··A) AT PF ( ~·~ ) '·/OL TAGE ( ~::: ..... > 4. GOI/EF.:t·lOF.: DATA HO. OF UtlJE; t·1 A t·l U FACTURE F.: r,'PE PF.:Es::.uF.:E (F·~;J) 1.6 1 1957 VEF:T I CAL F RAt·lC I::. 2400 57 I (1 400. (1 125. 1 GEtlEF.:AL ELECTF: I C 20(10 \> ~·J 0 0 D ~·J A F: D HR 2(1(1 5. GEHEF.:ATIOH DATA (A\o'EF.:AGE 1974-1978) GEHERATION (KWH*10A6) PLAtH FACTOF: 5.7 .40 PLAtH tlO. 4::: 6. OPEPATIOH & MAIHTEHAHCE COST DATA OPEF.:ATIOH COST (MILLS/KWH) MAIHTEHAHCE COST CMILLS/KWH) (JULY 1978 AVERAGE 1974-1978) ,-, .-. 1 o:..;,o 2.88 0 & M COST <MILLS/KWH) :~:. 72 7. F.:EPLACEMEHT COST C% OF MAIHTEHAHCE COST) 65 8. AVAILABILITY FACTOR CAVEF.:AGE 1974-1978) 9. MAIHTEHAHCE FREQUEHCY ( F =FF.:E G•U E t·H, I= I t·lF F:EC!UEt·H, A=A'·..'EPAGE ). RUHHER & DISCHAF.:GE FEATUF.:ES A TURBIHE GUIDE BEAF.:IHGS & SEAL A GENEF.:ATOF.: THRUST & GUIDE BEAF.:IHGS A STATOF.: POLES A IHSTF.:UMEHTATIOH A GOVEF.:NOP A OTHER 1 ~:1. ~·lATER G1UAL I T'l % OF TIME WATEF.: COHTAIHS SILT, SAHD ';! 1. 51 OF.: OTHEF.: MATEF.:IALS WHICH CAUSE WEAF.: 16 UHUSUAL COHDITIOHS A-13 PAI~E 1 F'LAtH t·W. 4·=< !. PLAtH tlAt·1E FOOTHILL PLAtH O~·JtlEF: PLAtH CAPAC I T'i < t·1 ~·l :;, CITY OF L.A. DEPT OF WATER t POWEP 1 0. [1 tW. OF Utl ITS 1 IHITIAL OPEF.:AT I Otl 1972 2. TUPBitlE DATA tlO. OF Ut·l IT::: t·1 A tl U F A C T U F.: E F.: E :::CHEF.: ~~ '/ ::.::: T'r'PE '·/EF.:T I CAL I r·1PUL ::.E F.:RTED HF' 14570, HEAD <FT> 5:35. (1 :::F·EED < F~ P t·1) '327 1 :::: :::PECIFIC :::PEED 15. 4 3. GEHEF.:fiTOF~ DATA tW. OF Ut·liT::: t·1 A tlU FACT U F.: E F.: BRO~~t·l B O'.,.'ER I CAPACIT'r' ( K'·/R) 11 0[1(1 AT F'F ( ~·~ > '·/OL TRGE ( K'·.·') 4. ::: 4. GOVEF.:t·lOF.: DATA HO. OF Utl IT::: t·1 A tlU FACT U F.: E F.: ESCHE F.: ~·J 'i :::::: T\'PE PF.:E:3:::URE <P:::I-:. ELECTRICALLY DRIVEN :300 5. GEHERRTIOH DATA <AVERAGE 1974-1978~ GEHERRTIOH <KWH+10A6) 60.8 PLAtH FRCTOF.: .6'3 6. OPERRTIOH & MAIHTEHAHCE COST DATA (JULY 1978 AVEF.:AGE 1974-1978) OPERATIOH COST (MILLS/KWH) MAINTENANCE COST <MILLS/KWH) 0 & M COST CMILLS/KWH) 7. REPLACEMENT COST (% OF MAINTENANCE COST) 8. AVAILABILITY FACTOR (AVERAGE 1974-1978) 9. MAINTENANCE FREQUENCY ( F=FF.:EQUEtH, I= I tlFF.:EQUEtH, R=A'·/EF.:AGE) RUNNER & DISCHARGE FEATURES TURBINE GUIDE BEARINGS & SEAL GENERATOR THRUST & GUIDE BEARINGS ::::TATOF.: POLE::: I t·l:::TF.:Ut•1EtHRT I ON G 0 VE F.: t·l 0 F~ OTHEF: CONTF.:OL S\'STEt·1S 10. ~JATER C!UALIT'l % OF TIME WATER CONTAINS SILT, SAND OR OTHER MATERIALS WHICH CAUSE WEAR UHUSUAL CONDITIONS A A A 93. 15 POLYMERS USED TO CONTROL TURBIDITY OCCASIOtlALLY CRUSE PLUGGING OF COOLIHG WATER SCREENS. A-14 PAGE 1 I i i I L- 1. PLAtH HAt·1E PLAtH O~·lt~EF.: PLAtH CAPAC IT\' o::tm> tW. OF UHIT::; ItHTIAL OPEF.:AT I Ot·l 2. TUIU:ItlE DATA t·lO. OF UtHH; t·1A t·lUFA C T UF: E F.: T\'PE ·F.:ATED HF' HEAD O::FT> :::PEED ( F:F't·1) 8PECIFIC :::PEED :::::. G E t·~E F: AT OF.: DATA tlO. OF UtHT::: t·1Atl U FACTURE F~ CAF'AC IT\' ( K•·,··A) AT PF ( ~·~ ) \.'OL TAGE <KV) 4. GO'..iEf':t·lOF.: DATA t·lO. OF Ut·liT~: t·1 At·l U FACT UF.: E F.: T'lPE PRES:::UF.:E o::P::;I > ESCAt·lABA CLEVELAND-CLIFFS IROH COMPAHY 2. (1 1 1929 1 ALLIS CHAU1Ef':::: HO~IZOHTAL FRAHCIS 2700 65.0 257. (1 72.4 l·JEST I tlGHOU:::E 250(1 2.4 ~·JOODl·JAF:D Ll': 2(1(1 5. GEHEF:ATIOH DATA O::AVEF:AGE 1974-1978) GEHERATION O::KWH*10A6) PLAtH FACTOR .22 PLAtH ~W. 50 6. OPERATION & MAIHTEHANCE COST DATA (JULY 1978 AVERAGE 1974-1978) OPERATIOH COST O::MILLS/KWH::O 7.30 MAIHTEHANCE COST <MILLS/KWH> 0 & M COST tMILLS/KWH) 7.30 7. F:EPLACEMEHT COST (% OF MAIHTEHAHCE COST) 8. AVAILABILITY FACTOF: (AVERAGE 1974-1978) 9. MAIHTENAHCE FREQUEHCY ( F=FF.:EGtUEtH, I= I t·lFF.:EGtUEtH, A=A'·/EF.:AGE) RUNNER & DISCHARGE FEATURES TURBINE GUIDE BEARINGS & SEAL GENERATOR THRUST & GUIDE BEARIHGS STATOF: POLE::: I t·l::. TF:Ut·1EtH AT I Otl GO '·i E l<:t·l 0 F: OTHEF: DAt·1 t1A I tHEI·~AI·~CE 10. ~·JATEF.: G!UAL IT\' % OF TIME WATEF: COHTAINS SILT, SAHD (1 1(1(1. (1(1 A OR OTHER MATERIALS WHICH CAUSE WEAF: 0 UHUSUAL CONDITIONS PRACTICALLY NO SILT OF: SAND FLOWS THROUGH THE TURBINE. A-15 PAGE 1 1. PLAtH tiAt·lE PLAtH O~lt-lER PLAtH CAPAC IT'.' <fol~D NO. OF UtHTS HUTIAL OPEF;AT I Ot~ 2. TURB I t~E DATA NO. OF UtHTS MAt~UFACTUREI': T'·I'PE RATED HP HEAD CFT> SPEED ( I<:Pt·l) SPECIFIC SPEED 3. GENERATOR DATA t~O. OF UtHTS t·1At-WFACTUREF; CAPACITY (I( VA> AT PF (:-;) VOLTAGE ( K•·,··) 4. GO '·/E F; tlO F; DATA t·lO. OF UtHTS t·l Atl U FACTURE R T\'PE PF;E::;SUF;E <PS l) HARD\' CONSUMERS POWER COMPANY 3(1.0 3 1931 ~: I. P. t•lOF.'F.:I::; VEF;T I CAL FF.:AtK IS l(H), (1 163.6 62.9 GEt·lEF.:AL ELECTRIC 125(1(1 7.5 3 ~WOD~·lAF.:D A 175 5. GENERATION DATA (AVERAGE 1974-1978) GENERATION (I<WH*10A6) 86.0 PLAtH FACTOF.: PLAtH t·W. 63 6. OPEF.:ATION & MAINTENANCE COST DATA (JULY 1978 AVEF.:AGE 1974-1978) OPEF.:ATIOtl COST <MILLS/KWH> .68 MAINTEtiANCE COST CMILLS/KWH> 0 :$, t·l COST. ( t·l I LL::; . ...-fnm) . 6::: 7. REPLACEMENT COST (% OF MAINTENANCE COST) "' ·-' :::. AVA I LAB I L I Tl' FACTOf;: <AVERAGE 1974-1978) 97.26 9. MAINTENANCE FREQUENCY C F=FF.:EG!UEtH, I= I t·lFF:ECOUEtH, A=A'..IEF.:AGE) F.:UNNEF.: & DISCHAF.:GE FEATUF.:ES A TURBINE GUIDE BEARINGS & SEAL I GENERATOF.: THF.:UST & GUIDE BEAF.:INGS I STATOR POLES A INSTRUMENTATION A GOVERNOF.: A OTHEJ;: 10. ~·lATE!': G!UALIT\' % OF TIME WATER CONTAINS SILT, SAND OR OTHER MATEF.:IALS WHICH CAUSE WEAR 0 UtiUSUAL CONDITIONS A-16 PAGE 1 1. PLAtH t~At·1E HODEt·lP'r'L PLAtH Ol~tlEF.: CONSUMERS POWER COMPANY PLAtH CAPAC IT'/ (to11~ > t~O. OF UNITS INITIAL OPH:AT I ON 2. TUI':E: It~E DATA tW. OF Ut·l I T3 ~1AtlUFACTUF:EF.: T'r'PE RATED HP HEAD CFT> :3PEED ( F.:P t·1) SPECIFIC SPEED :3. . GE~lEI':ATOF.: DATA t~O. OF UtHTS ~1At~UFACTURER CAPAC IT\' ( K'·iA) AT PF ( :.; ) \,iOL TAGE < K\·') 4. GO'"'EF.:NOR DATA NO. OF Ut·liTS t·1At·lU FACT U F.: E F.: T'I'PE PRESSURE ( P ::; I ) 18. (1 2 1925 2 ALL I::; CHAU1EF.:::; VEF.:T I CAL FF.:At·lC I::; 12(1(1(1 67.5 67.9 2 ALLIS CHAU1ERt; 96 7.5 2 ALL I::; CHAU1EF.:S ::n ZE :;: SPECIAL 12(1 5. GENERATION DATA (AVERAGE 1974-1978) GENERATION <KWH*10A6) PLAtH FACTOF.: ~:6. :::: PLAtH t·lO. 64 6. OPEF.:ATIOt·l 2., t·1AitHEt·lAtlCE co::;T DATA OPERATION COST <MILLS/KWH) MAINTENANCE COST O::MILLS/KWH> (JULY 1978 AVE~AGE 1974-1978) 2.91 0 t M COST CMILLS/KWH) 7. REPLACEMENT COST C% OF MAINTENANCE COST) e. A'v'A I LAE: I L I T'r' FACTOR CA'v'ERAGE 1974-1978) 9. MAINTENANCE FF.:EQUENCY ( F=FF.:EQUEtH, I= I t·lFF.:EOUEtH, A=A'..IEF.:AGE) RUNNER ~ DISCHARGE FEATURES A TURBINE GUIDE BEARINGS & SEAL GENERATOR THF.:UST & GUIDE BEARINGS STATOR POLES A INSTRUMENTATION .A GOVERt·WF: OTHEr<: 10. WATER C!UAL IT\' % OF TIME WATER CONTAINS SILT, SAND OR OTHER MATERIALS WHICH CAUSE WEAR UNUSUAL CONDITIONS A-17 A A-17 2. '=!1 96. 16 10 PAGE 1 1. PLAtH ~lAt·1E PLAtH 0 ~·J tl E F.: PLAtH CAPAC IT\' ( t·1 ~·J ) tW. OF Utl IT::. INITIAL OPH~AT I Ot·l 2. TU~:E: I NE DATA tlO. OF UtHH: t·1 At~ U FACT UF.: E F.: T'/F'E F.:ATED HF' HEAD O::FT> :::PEED <F.: F' t·1) :::PECIFIC :::PEED :3. GnlERRTOR DRTR t·lO. OF UtHTS t·1A tlUF ACT U F.: EF.: CAPACITY < K'·,·'A > AT PF ( ~-~ > VOLTAGE ( K'·,•') 4. GO'•/ERt·lOF.: DATA t·lO. OF Ut·l IT::; t·1AtWFACTUF.:EF.: T\'PE F' F.: E :::::: U RE ( p::; I) TIPP'I' C. ~.J. CONSUMEF.:S POWEF.: COMPANY 20. (1 3 191f: 3 WELLMAN-SEAVEF.:-MOF.:GAN VEF.:T I CAL FF.:At·lC I::; 75(1(1 6(1, (1 1 (1•;:<. 1 56.6 3 I·JEST I NGHOI_I:o:E 7(15(1 95 7.5 ~·J 0 0 D ~~A F.: D ,-c· ,_,._. 2(1(1 5. GENEF.:ATION DATA CAVEF.:RGE 1974-1978) GENERATION CKWH•10A6) 56.9 PLAtH FACTOF.: PLAtH t·W. 65 6. OPEF.:ATION t MAINTENANCE COST DATA (JULY 1978 AVEF.:AGE 1974-1978) OPEF.:ATION COST (MILLS/KWH) 1.73 MAINTENANCE COST CMILLS/KWH) 0 t M COST <MILLS/KWH) 1 . 7:~: 7. F.:EPLACEMENT COST 0::% OF MAINTENANCE COST) C' ·-' :::. A\·'AILAE:ILIT\' FACTOF.: ( A'·/EF.:AGE 1 ':!74-197:::) 9E .. 16 9. MAINTENANCE FF.:EQUENCY o:: F=F REG!UEtH, I= I tlFF.:E G!UEtH, A= A'·/EF.:AGE) F.:Ut-HJEF.: t, D I :::CHAF~GE F EATUF.:E::: A TUF.:E:INE GUIDE BEARINGS & SEAL I GENERATOF.: THF.:UST & GUIDE E:EAF.:INGS I STATOR POLES A INSTRUMENTATION A GOVEF.:NOF.: A OTHEF: 10. ~·JATEF.: G!UAL I H % OF TIME WATEF.: CONTAINS SILT, SAND OR OTHER MATEF.:IALS WHICH CAUSE WEAF.: UNUSUAL CONDITIONS A-18 PAGE 1 INDEX OF MANUFACTURERS -HYDROELECTRIC EQU~_Hii_!:_NT Turbi.nRs Valves ~ ~ ell 0 r-1 .,.., 0.. +-' ell ell ! ' Manufacturer -Country ::.:::· 0.. Representative .,.., a::! rn Address i;: rn H H :>. r-1 .,.., Q) 0 H 0 r-1 ell Cl r-1 rn H r-1 Q) 0 +-' 'H 0 r-1 .,.., ell 'H rn ~ ell H .,.., :>. Q) 0 r-1 rn r-1 H H Q) H b.O rn < 0.. $:l ;j ,D rn ;j 0.. Q) Q) '+-' Q) H Q) 0 ell .0 rl s 0 0.. s :> ~ +-' .s:l Q) +-' H H ;j ;::::s .,.., H s ;j 0 Q) ;::::s 0.. ~ C\l AI r.:r.. E-; r:o 0:::: UIH AI ~ ~ r:o r:n I'Ll ~ ALLIS-CHAlMERS -USA B B c B T c B B Allis-Chalmers Hydro-Turbine Division P.O. Box 712 York" PA 17405 ALSTH<l\1 -ATLANTIQUE/NEYRPIC -c B c c B B B c c B B c FRANCE Alsthom-Atlantic, Inc. i 50 Rockerfeller Plaza Suite 916 New·York. NY 10022 ARMCO -USA c c Armco Inc. Metal Products Division Middletown-, Ohio 45043 ASEA -SWEDEN B c c A sea Inc. I 4 New King Street White Plains. N Y. 10604 ' I ATELIERS BOUVIER -FRANCE B B A c c B B Anchor Darling Industries.Inc 1 Belmont Avenue Bala Cynwyd. PA 19004 BELOIT -USA A Beloit Power Systems ... 555 Lawton Avenue Beloit, Wisconsin 53511 Symbols A -Standard Design B -Custom Design c -Both Standard & Custom Designs B-1 Turbines Valves I lc:l Cl lro 0 r-i """" 0. ~ Manufacturer Country ro ro -~ 0. Representative """" ~ rn Address rn r... i:': r... :>, r-i """" (j) 0 r... 0 r-i ro Q r-i rn r... r-i (j) 0 ....., 'H C) r-i """" ro 'H rn Cl ro r... """" :>, (j) C) r-i rn r-i r... r... (j) r... b.O rn 0. Cl ;:J .n rn ;:J 0. (j) (j) ~ (j) r... (j) 0 ro .n r-i s 0 0. s > Cl ....., .c (j) ....., r... r... ;:J ;:J """" r... s ;:J 0 (j) ;:J ~o. Cl ro P-! ~ E-l 1=0 0:: C) H P-! 0 0 1=0 Cl) ~ 0 BOFORS NOHAB -SWEDEN c A B B Axel Johnson Corp. One Market Plaza San Francisco. CA 94105 BOVING -ENGLAND B B B B B I c c B!B Axel Johnson Corp I One Market Plaza I I ! San Francisco, CA 94105 CHARM ILLES -SW ITZ ERLAND B B B B B A c B Euro-USA Co. 779 Barbara Avenue I Solana Beach, CA 92075 CMEC -CHINA B B B B A B c Oriental Engineering and Supply Company 670 Newell Rd Palo Alto, CA 94303 DCXvl INION -CANADA B B B B c B Dominion Engineering P.O. Box 220 Montreal, Quebec EMMC -USA A Electric Machinery Manufacturing Company 800 Central Avenue Minneapolis, MN 55413 Symbols A -Standard Design B -Custom Design c -Both Standard & Custom Designs B-2 INDEX OF MANUFACTURERS -HYDROELECTRIC. EQUI~_~NT Turbines Valves c c ell 0 ,..., ·.-i 0. +J Manufacturer Country ell ell -~ 0.. Representative ·.-i ~ en Address en ~ j3:: ~ >. ,..., ·.-i Q) 0 ~ 0 ,..., ell Q ,..., en ~ ,..., Q) 0 +J 'H C) ,..., ·.-i ell 'H en c ell ~ ·.-i >. Q) C) ,..., en ,..., ~ ~ Q) ~ bO en 0. c ;::::s .0 en ;::::s 0.. Q) Q) +J Q) ~ Q) i 0 ell .0 ,..., s 0 0. s :> c +J .0 Q) +J ~ ~ ;::::s ;::::s ·.-i ~ s ;::::s 0 Q) ;::::s 0. c ell P-t ~ E--l 1!:1 ~ C) H P-t c.J c.J 1!:1 r:tJ. ~ c.J ) FUJI ELECTRIC -JAPAN B B B c B B A c c B B c Nissho-Iwai American Corp ! 700 s. Flower St. ' 1 I I Los Angeles. CA 90017 GENERAL ELECTRIC -USA c I General Electric Co. 1 River Road I Schenectady. NY 12345 GILKES -ENGLAND B B McKay Water Power Ltd. P.O. Box 488 Port Col borne. Ont. L3K5X7 HITACHI -JAPAN B B B B c B Hitachi American Ltd. 100 California Street San Francisco, CA 94111 HTI -JAPAN/USA B \ Hydraulic Turbines Inc. One River Road Schenectady. NY 12345 IDEAL -USA A Ideal Electric 330 East First Street Mansfield, Ohio 44903 Symbols A -Standard Design B -Custom Design c -Both Standard & Custom Designs B-3 Turbines Valves c: c: ell 0 r-i ·..-! 0.. +J Manufacturer ell ell -Country :::.:: 0.. Representative •..-! ckl rJJ. Address rJJ. 1-<. ~ ;.... >. r-i •..-! Q)l 0 ;.... 0 r-i ell Q r-ilrJJ. ;.... r-i Q) 0 +J '1-1 C) r-i ·..-! ell '1-1 rJJ. c: ell ;.... •..-! >. Q) C) r-i rJJ. r-i ;.... ;.... Q) ;.... b.O rJJ. 0.. c: ;j ,Q rJJ. ;j 0.. Q) Q) +J Q) ;.... Q) 0 ell ,Q r-i El 0 0.. El :> c: +J ..c: Q) +J H ;.... ;j ;j ·..-! H a ;j 0 Q) ;j 0.. c: ell P-! ~ ~ p:j 0::: u H P-! 0 0 p:j C/1 ~ 0 INDEPENDENT -USA B B Independent Power Developers Route 3 Box 285 Sandpoint Idaho 83864 I KATO -USA A Kato Engineering Co. I 1415 First Avenue Mankato. MN 56001 KMW -SWEDEN B B c B B B B Axel Johnson Corp. One Market Plaza San Francisco. CA 94105 KOSSLER -AUSTRIA c c c c A I c Kossler Ltd. 1923 Magellan Drive Oakland, CA 94611 KV AER NER -BR UG -NORWAY c B c B c c c c c c c Kvaerner-M oss Inc. 800 3rd Avenue New York, NY 10022 LEFFEL-TAM PELLA -USA/FINLAND c c c B c The James Leffel & Co. 426 East St. Springfield, Ohio 44501 Symbols A -Standard Design B -Custom Design c -Both Standard & Custom Designs B-4 INDEX OF MANUFACTURERS -HYDRO~LECTR I~ EQU_l~ ENT_ t:: ro r-i 0.. ro ~ -Country Manufacturer Represe Address ntative ~ LIMA -USA The Lima Electr 200 East Chapma Lima, Ohio 458 LITOSTROJ -YUGOSLA Arbanas Industr 24 Hill Street Xenia, Ohio 45 MITSUBUSHI -JAPAN M i tsubushi Inte 50 California S San Francisco, NEBB -NORWAY Brown Boveri Co 1460 Livingston North Brunswick NOBLE -USA Noble Automated 226 Phelan Ave San Jose, CA 9 . OSSBERGER -GERM ANY F.W.E. Stapenho 285 Labrosse Av Pointe Claire, Symbols A -Standard Des1 B -Custom Design C -Both Standard ------·--- ~ (]) r-i r-i (]) 0.. 0 ~ AI 1 ic Co. n Road 02 VIA B ies 385 B rnational Cor:t: t. CA 94111 l rp Ave. I ~ NJ 08902 Systems 5112 I rst Inc. e. Que H9R1A3 gn & Custom Designs B-5 Turbines i:!: ~ 0 ~ 0 UJ. ~ r-i (]) 0 ~ ·r-i ro 'H UJ. t:: ro C) r-i UJ. r-i ~ ~ t:: ;::J .0 UJ. ;::J 0.. (]) (]) ro .0 r-i s 0 0.. s > t:: ~ ;::J ;:::l ·r-i ~ s ;::J 0 (]) l'r.. E-l ~ 0:: C) H AI c.!J c.!J A B B B B B c c B B B B c B c B c Valves t:: 0 ·r-i ~ ro 0.. •r-i UJ. UJ. :>. r-i ·r-i r-i ro Cl 'H C) ~ ·r-i :>. (]) ~ b.O UJ. ~ (]) ~ (]) ~ ..c (]) ~ ;::J 0.. t:: ro ~ C/1 r:LI c.!J B B B c B B B I INDEX OF MANUFACTURERS -HYDROEL~CTRIC EQU_I~EN! Turbines Valves ,--. c c ro 0 ,...., . ..., 0. .j-) Manufacturer -Country ro ro ::.:::: 0. Representa.tive . ..., cl<3 Ul Address Ul ..... =:;:: ..... :>. ,...., ...., (]) 0 ..... 0 ,...., ro Cl ,...., Ul ..... ,...., (]) 0 .j-) 'H 0 ,...., . ..., ro 'H Ul c ro ..... . ..., :>. (]) 0 ,...., Ul ,...., ..... ..... (]) ..... bOI w 0. c ;::j .0 Ul ;::j 0. (]) (]) .j-) (]) >-<,(]) 0 ro .0 ,...., s 0 0. s > c .j-) ..c (]) .j-) ..... ..... ;::j ;::j . ..., ..... s ;::j 0 (]) ;::j 0. c ro ~ ~ E-4 t:Q 0:: u H ~ CJ CJ t:Q U) ~ CJ RADE KONCAR-YUGOSLAVIA c Arbanas Industries 24 Hill Street Xenia. Ohio 45385 SIEMENS-ALLIS -USA c Siemens-Allis Inc. L.A.R. Division Box 2168 Milwaukee, WI 53201 SORUM SAND -NORWAY c c c c Kvaerner-M oss Inc. 800 3rd ave. New York, NY 10022 SULZER -ESCHER WYSS -SW ITZ ERLAND B B c B c B B B B B B Sulzer Bros. Inc 1255 Post Street San Francisco, CA . 94109 VOEST-ALPINE -AUSTRIA c c c B c B c B B B c Voest-Alpine International Corp Lincoln Building 60 East 42nd Street New York, NY 10017 VOITH -WEST GERM ANY B B B B B B B B B B B Krupp International Inc. 550 Marnaronek Avenue Harison, NY 10528 Symbols A -Standard Design B -Custom Design C -Both Standard & Custom Designs B-6 INDEX OF MANUFACTURERS -HYDROELECTRIC E<;gn~ENT Turbines Valves Q Q ro 0 ..--1 .,...; 0. ~ ro ro Manufacturer -Country :::.:: 0. .,...; Representative a:3 I {/1 Address {/1 r... i3: r... » ..--1 .,...; (j.) 0 r... 0 ..--1 ro Ci ..--1 {/1 r... ..--1 (j.) 0 ~ 'H C) ..--1 .,...; ro 'H {/1 Q ro r... .,...; » (j.) C) ..--1 {/1 ..--1 r... r... (j.) r... bll {/1 0. c: ;:::s ..0 {/1 ;:::s 0. (j.) (j.) ~ (j.) r... (j.) 0 ro ..0 ..--1 a 0 0. a > Q ~ ..c: (j.) ~ r... r... ;:::s ;:::s .,...; r... a ;:::s 0 (j.) ;::.1 0. Q ro Pol ~ ~ t:Q 0:: u H Pol 0 0 t:Q en r.:Ll 0 WESTINGHOUSE -USA c Westinghouse Eletric Corp Hydro Generator Department 700 Braddock Avenue East Pittsburgh, PA 15112 WOODWARD -USA c Woodward Governor Co. 5001 North Second Street Rockford, IL 61101 WORTHINGTON-NEYRPIC -USA/FRANCE A Worthington-Neyrpic Inc. 270 Sheffield Street Mountainside, NJ 07092 I I I I I I Symbols A -Standard Design B -Custom Design c -Both Standard & Custom Designs B-7 ('"") I - RATED HEAD ft m 32.81 10.00 GENERATOR OUTPUT kW 100 250 500 1,000 1,500 2,000 3,000 4,000 5,000 10,000 15,000 SIZE AND RANGE: VERTICAL & HORIZONTAL FRANCIS, CLOSED FLUME, DIRECT COUPLED TURBINE TURBINE VERTICAL GENERATOR HORIZONTAL GENERATOR OUTPUT D3 DIAMETER HEIGHT LENGTH WIDTH HEIGHT 0 HP ft m ft m ft m ft m ft m ft m n3 /s m3/s 135 1.57 .48 2.56 .78 3.54 1.08 3.54 1.08 2.56 .78 2.56 .78 43 1.2 335 1. 97 .60 3.67 1.12 4.27 1.30 4.27 1.30 3.67 1.12 3.67 1.12 106 3.0 675 2.89 .88 4.13 1.26 6.66 2.03 6.33 1. 93 4.13 1.26 -4.13 1.26 212 fi.O 1,350 3.94 1.20 6.04 1.84 6.99 2.13 6.66 2.03 6.04 1.84 6.04 1.84 424 12.0 2,025 4.76 1.45 7.74 2.36 7.35 2.24 7.51 2.29 7.74 2.36 7.74 2.36 636 18.0 2,700 5.58 1. 70 9.58 2. 92 7.84 2.39 7. 51 2. 29 9.58 2.92 10.40 3.17 848 24.0 4,025 6.40 1. 95 11.94 3.64 8.23 2.51 7. 91 2.41 11.94 3.64 12.76 3.89 1,270 36.0 5,365 7.22 2. 20 14.01 4.27 8.23 2. 51 7.91 2.41 14.01 4.27 14.83 4.5? 1,695 48.0 6,700 8.86 2.70 14.63 4.46 8.23 2.51 7.91 2.41 14.63 4.46 15.45 4.71 2,120 60.0 13,415 12.14 3. 70 22.21 6. 77 7.32 2.29 8.20 2.50 22.21 fi. 77 23.03 7 .(12 4,240 120.0 20,120 14.76 4.50 29.17 8.89 8.66 2.64 8.66 2.64 29.17 8.89 29.99 9.14 fi,36(1 180.0 (} I N I i I I I RATED HEAD ft m 32.81 10.00 GENERATOR OUTPUT kW 100 250 500 1,000 1,500 2,000 3,000 4,000 5,000 10,000 I 15,000 TURBINE OUTPUT HP 135 335 675 1,350 2,025 2,700 4,025 5,365 6,700 13,415 20,120 I s LENGTH SIZE AND RANGE: VERTICAL CLOSED FLUME FRANCIS W/SPEED INCREASER TURBINE D3 ft m 1. 57 .48 1. 97 .60 2.89 .88 3.94 1.20 4.76 1. 45 5.58 1. 70 6.40 1. 95 7.22 2.20 8.86 2.70 12.14 3. 70 14.76 4.50 J GENERATOR SPEED INCREASER DIAMETER HEIGHT LENGTH WIDTH HEIGHT SHAFT CL TO CL ft m ft 1. 80 .55 3.54 2.33 .71 4.27 2.99 .91 6. 33 3.35 1.02 6.66 4.69 1.43 6.99 5.41 1.65 7.35 7.09 2.16 8.23 7.68 2.34 8.23 8. 50 2.59 8.66 12.01 3.66 7.51 14.17 4.32 8.66 n m ft m ft m ft m ft 1. 08 1. 41 .43 1. 35 .41 2.00 .61 .46 1. 30 1.77 .54 1. 64 .50 2.33 .71 .59 1. 93 2.40 .73 2.13 .65 2.92 .89 .82 2.03 3.67 1.12 3.28 1.00 3.84 1.17 1.35 2.13 4.56 1. 39 3.90 1.19 4.43 1. 35 1. 67 2.24 4.95 1.51 4'.23 1.29 4.89 1.49 1.84 2.51 5.81 1.77 4.82 1.47 5.28 1. 61 2.17 2.51 7.22 2.20 5.87 1. 79 6.36 1. 94 2.76 2.64 7.84 2.39 6.30 1. 92 6.89 2.10 2.99 2.29 2.64 NOTES 1. Turbine dimensions are estimated from USER Francis turbine throat diameter curves. 2. Generator dimensions are based on Ideal Electric and Lima Electric units. 3. Speed increaser dimensions are based on Western Gear 8000 series units. 4. Practical o 3 limit for smallest Francis turbine is 1 foot (0.3 metres). m .14 .18 .25 .41 .51 .56 .66 .84 .91 ("") I w RATED HEAD ft m 32.Bl 10.00 ----., -----') -----~----~ ,--~1 r·--I -- J I ---l I I J ----~ SIZE AND RANGE: HORIZONTAL FRANCIS AND HORIZONTAL CLOSED FLUME WITH SPEED INCREASER GENERATOR TURBINE TURBINE GENERATOR OUTPUT OUTPUT D3 LENGTH WIDTH kW HP ft m ft m ft m ,- 100 135 1. 57 .48 3.54 1.08 1. 80 .55 250 335 1. 97 .60 4.27 1.30 2.33 .71 500 675 2.89 .88 6.00 1. 83 2.99 .91 1,000 1,350 3.94 1.20 6.33 1. 93 3.35 1.02 1,500 2,025 4.76 1. 45 6.99 2.13 4.46 1. 36 2,000 2,700 5.58 1. 70 6.99 2.13 5.41 1.65 3,000 4,025 6.40 1. 95 7.91 2.41 7.09 2.16 4,000 5,365 7.22 2.20 7.91 2.41 7.68 2.34 5,000 6,700 8.86 2.70 8.33 2.54 8.50 2.59 10,000 13,415 12.14 3. 70 8.20 2.50 12.01 3.66 15,000 20,120 14.76 4.50 8.66 2.64 14.17 4.32 SHAFT ro CL ~ CL ~ I I -e-T ! LENGTH WIDTH SPEEO INCREASER (in 1 in e) HEIGHT LENGTH WIDTH HEIGHT SHAFT CL TO CL ft m ft m ft m ft m ft 2.36 .72 1. 41 .43 2.00 .61 1. 35 .41 .46 3.02 .92 1.77 .54 2.33 .71 1.64 .50 .59 2.99 .91 2.40 .73 2.92 .89 2.13 .65 .82 3.35 1.02 3.67 1.12 3.84 1.17 3.28 1.00 1.35 4.46 1. 36 4. 56 1. 39 4.43 1. 35 3.90 1.19 1. 67 5.41 1.65 4.95 1.51 4.89 1.49 4.23 1.29 1.84 7.35 2. 24 5.81 1.77 5.28 1. 61 4.82 1. 4 7 2.17 8.33 2.54 7.22 2.20 6.36 1. 94 5.87 1. 79 2.76 9.32 2.84 7.84 2.39 6.89 2.10 6.30 1. 92 2.99 12.83 3.91 15.00 4.57 NOTES l. Turbine dimensions are estimated from USBR Francis turbine throat diameter curves. 2. Generator dimensions are based on Ideal Electric and Lima Electric units. 3. Speed increaser dimensions are based on Western Gear 8000 series units. 4. Practical D3 limit for smallest Francis turbine is l foot (0.3 metres). m .14 .18 .25 .41 .51 .56 .66 .84 .91 ("") I .j:::o __ _j RATED HEAD ft m 6.56 2.00 6.56 6.56 7.05 7.22 7 0 71 65.62 20.00 GENERATOR OUTPUT kW 100 250 500 1,000 1,500 2,000 100 250 500 1,000 1,500 2,000 3,000 4,000 5,000 SIZE AND RANGE: VERTICAL KAPLAN -DIRECT DRIVE TURBINE TURBINE GENERATOR OUTPUT D3 DIAMETER HEIGHT HP ft m ft m ft m. 135 3.25 .99 3.84 1.17 3.54 1.08 335 5.41 1.65 6.36 1.94 4.27 1.30 675 7 0 71 2.35 7.02 2.14 6.66 2.03 1,350 9.84 3.00 9.94 3.03 6.99 2.13 2,025 11.15 3.40 12.86 3.92 7.32 2.23 2,700 13.29 4.05 15.35 4.68 7.84 2.39 135 1.35 .41 2.20 .67 3.54 1.08 335 1.80 .55 3.28 1.00 1. 30 1.30 675 2.23 .68 3.48 1.06 6.66 2.03 1,350 3.08 .94 5.05 1. 54 6.99 2.13 2,025 3.77 1.15 6.33 1. 93 7.32 2.23 2,700 4.43 1.35 8.10 2.47 7.84 2.39 4,025 5.12 1.56 10.01 3.05 8.23 2.51 I 5,365 I 5.81 1.77 11.29 3.44 8.23 2 0 51 6,700 6.73 2.05 12.07 3.68 8.23 2.51 :.._ ___ .J Q n 3/s m3/s 212 6.00 530 15.00 1,060 30.00 1,978 56.00 2,896 82.00 3,602 102.00 23 .65 53 1.50 106 3.00 212 6.00 318 9.00 424 12.00 636 18.00 848 24.00 1,060 30.00 I L _____ _ I c_ -l__j n I (J1 RATED HEAD ft m 6. 56 2.00 2.00 7.05 2.15 7. 22 2.20 7. 71 2.35 65.62 20.00 GENERATOR TURBINE · OUTPUT OUTPUT kW HP 100 135 250 335 500 675 1,000 1,350 1,500 2,025 2,000 2, 700 100 135 250 335 500 675 1,000 1,350 1,500 2,025 2,000 2, 700 3,000 4,025 4,000 5. 365 5,000 6, 700 ;----1 i --__ j GENERATOR DIAMETER HEIGHT ft m ft m 1.80 .55 3. 54 1. 08 2. 33 .71 4.27 1.30 3.84 1.17 6.66 2.03 5.41 1.65 6.99 2.13 6. 33 1. 93 7.35 2. 24 6.33 I. 93 7.84 2.39 1.80 . 55 3.54 1.08 2.33 .71 4.27 1.30 2.99 . 91 6.33 I. 93 3.84 1.17 7.15 2.18 4.46 1.36 7.35 2.24 4. 69 I. 43 7.84 2. 39 7.09 2.16 8.23 2. 51 7.68 2.34 8.23 2. 51 9.35 2.85 8.23 2.51 SHA 1- l - TURBINE D3 ft m 3. 25 . 99 5.41 1.65 7. 71 2. 35 9.84 3.00 11.15 3.40 13.29 4.05 1.35 .41 I. 80 .55 2.23 .68 3.08 .94 3.77 1.15 4. 33 I. 35 5.12 !.56 5.81 1.77 6. 73 2.05 T~L~ CL [· I LENGTH '-- f-----.. I i ~----~ r ----~ l ___ _I SIZE AND RANGE: VERTICAL KAPLAN WITH SPEED INCREASER SPEED INCREASER (in 1 ine) 0 LENGTH WIDTH HEIGHT SHAFT CL TO CL ft3/s m3/s ft m ft m ft m ft m 212 6.00 1. 57 .48 1. 51 .46 2.1 7 .66 . 52 .16 530 15.00 2.66 .81 . 2.30 . 70 3.15 .96 .9? .28 1,060 30.00 3.54 1.08 3.15 . 96 3. 67 1.12 1.25 .38 I, 978 56.00 4. 95 1. 51 4.23 1.29 4.89 1.49 1.84 . 56 2,896 82.00 6. 27 1. 91 5.12 I. 56 5.51 1. 68 2. 33 .71 3,602 102.00 7.22 2.20 5.87 I. 79 4. 72 1.44 2. 76 .84 23 .65 1.41 .43 1.35 .41 2.00 .61 .46 .14 53 !.50 1.77 . 54 I. 64 .so 2. 33 . 71 .59 .18 106 3.00 2.20 .67 I. 97 .60 2.69 .82 . 75 .23 212 6.00 3.15 .96 2.85 .87 3.38 I. 03 1.08 .33 318 9.00 4.95 !.51 4.23 1.29 4.89 1.49 l.B4 .56 424 12.00 4. 95 1. 51 4. 23 1. 29 4.89 I. 43 I. 84 .56 636 18.00 5.35 1.63 4.49 1.37 4.99 !.52 2.00 .61 848 24.00 6.27 1. 91 5.12 1. 56 5. 51 1. 68 2. 33 .71 1,060 30.00 6.63 2.02 5.41 I. 65 5.87 I. 79 2.49 . 76 r-:--:--- ....__ OL DIAMETER ft m 2.26 .69 2.26 .69 2.49 . 76 3.38 1.03 3.38 1.03 4.00 1.22 2.26 .69 2.26 .69 2.49 . 76 2.49 . 76 2.92 .89 3. 67 1.12 4.00 1.22 4.33 I. 32 4. 33 1.3? I, r ' HEIGHT ft 3. 81 3.81 4. 72 s. 91 5.91 6.86 3.81 3.81 4.72 4. 72 5.25 6.63 6.86 6.86 7.19 SPEED INCREASER (90' ANGLE) OH OL m ft m ft m 1.16 2.10 .64 1. 87 .57 1.16 2.10 .64 1.87 .57 1.44 2. 36 .72 2.00 . 61 1.80 3.18 . 97 2.59 . 79 1. 80 3.18 • 97 2. 59 . 79 2.09 3. 74 1.14 2. 99 . 91 1.16 2.10 .64 1.87 .57 1.16 2.10 .64 1. 87 .57 1.44 2.36 .72 2.00 . 61 1.44 2. 36 .72 2.00 .61 1.60 2. 76 .84 2.20 .67 2. 02 3.41 1.04 2. 92 .89 2.09 3. 74 1.14 2. 99 .91 2.09 3. 74 1.14 2. 99 .91 2.19 4.07 1.24 3.12 .95 ('"') I m RATED HEAD ft m 6.56 2.00 11.15 3.40 14.44 4.40 17.39 5.30 24.61 7.50 49.21 15.00 49.21 15.00 GENERATOR TURBINE OUTPUT OUTPUT kW HP i 100 135 250 335 500 675 1000 1350 1500 2025 2000 2700 100 135 250 335 500 675 1000 1350 1500 2025 2000 2700 100 135 I 250 335 500 675 1000 1350 1500 2025 2000 2700 3000 4025 4000 5365 5000 6700 SIZE AND RANGE: TUBLAR TURBINE TURBINE GENERATOR D3 LENGTH WIDTH ft m ft m ft m 4.92 1. 50 3.54 1. 08 1. 80 .55 7.38 2.25 4.27 1.30 2.33 .71 9.84 3.00 6.00 1. 83 2.99 .91 9.84 3.00 6.86 2.09 3.84 1.17 9.84 3.00 6.99 2.13 5.41 1. 65 9.84 3.00 7.51 2.29 6.33 1. 93 2.46 .75 3.54 1.08 1.80 .55 3.28 1.00 4. 27 1. 30 2.33 .71 4.10 1.25 6.00 1. 83 2.99 .91 5.74 1. 75 6.86 2.09 3.84 1.17 7.38 2.25 6.99 2.13 5.41 1. 65 8.20 2.50 7.51 2. 29 6.33 1. 93 2.46 .75 3.54 1. 08 1. 80 .55 2.46 .75 4.27 1.30 2.33 .71 2.46 .75 6.00 1. 83 2.99 .91 4.10 1.25 6.86 2.09 3.84 1.71 4.92 1. 50 6.99 2.13 5.41 1. 65 5.74 1. 75 7.51 2.29 6.33 1. 93 7.38 2.25 7.92 2.41 7.08 2.16 9.02 2.75 7.92 2.41 7.67 2.34 9.84 3.00 8.33 2.54 8.50 2.59 L __ _; HEIGHT I 0 ft m I n3/ s m3/s 2.36 .72 212 6.00 3.02 .92 530 15.00 2.99 .91 1060 30.00 3.84 1.17 1245 35.30 5.41 1. 65 1447 41.00 6.33 1. 93 1600 45.30 2.36 .72 57 1.60 2.95 .90 142 4.00 2.99 .91 283 8.00 3.84 1.17 565 16.00 5.41 1.65 848 24.00 6.33 1. 93 1412 40.00 2.36 .72 29 .82 3.02 .92 71 2.00 2.99 .91 142 4.00 3.84 1.17 283 8.00 5.41 1. 65 424 12.00 6.33 1. 93 565 16.00 7.33 2.23 848 24.00 . 8.33 2.54 1130 32.00 9.35 2.85 1412 40.00 I_-----' n I ........ RATED HEAD ft m 6.56 2.00 11.15 3.40 14.44 4.40 17.39 5.30 24.61 7.50 49.21 15.00 ~---~ r -----~ \, ____ J DIMENSIONS: TUBLAR TURBINE SPEED INCREASER LENGTH WIDTH HEIGHT ft m ft m ft m 1.57 .48 2.17 .66 1.51 .46 2.40 .73 2.92 .89 2.13 .65 3.67 1.12 3.84 1.17 3.28 1.00 4.95 1. 51 4.89 1.49 4.23 1. 29 5.35 1.63 4.99 1.52 4.49 1.37 6.27 1. 91 5.51 1. 68 5.12 1. 56 1.41 .43 2.00 .61 1. 35 .41 1.97 .60 2.46 .75 1.80 .55 2.85 .87 3.18 .97 2.53 .77 4.07 1.24 4.13 1.26 3.61 1.10 4.95 1. 51 4.89 1.49 4.23 1. 29 5.35 1.63 4.99 1.52 4.49 1.37 1.41 .43 2.00 .61 1.35 .41 1. 57 .48 2.17 .66 1. 51 .46 2.20 .67 2.69 .82 1.97 .60 2.85 .87 3.18 .97 2.53 .77 4.23 1.29 4.13 1.26 3.61 1.10 4.56 1. 39 4.43 1.35 3.90 1.19 5.35 1.63 4.99 1.52 4.49 1.37 6.73 2.02 5.87 1. 79 5.41 1. 65 7.22 2.20 6.36 1.94 5.87 1. 79 '. ·' r -._ ,---· r --~ I~ i l_ I SHAFT CL TO CL S~T CL '1 0 CL ft m .52 .16 .82 .25 1.35 .41 1. 84 .56 4--I -T-! 2.00 .61 2.33 .71 .46 .14 .66 .20 .98 .30 1.51 .46 l LENGTH I --1 WIDTH 1. 84 .56 2.00 .61 .46 .14 .52 .16 .75 .23 .98 .30 1.51 .46 1. 67 .51 2.00 .61 2. 49 .76 2.76 .84 -- n I o:> ! _I RATED HEAD ft m 9.84 3.00 22.97 7.00 39.37 12.00 39.37 12.00 ------· GENERATOR OUTPUT kW 100 250 500 1000 1500 2000 100 250 500 1000 1500 2000 100 250 500 1000 1500 2000 3000 4000 5000 SIZE AND RANGE: OPEN FLUME -DIRECT DRIV~ TURBINE TURBINE GENERATOR OUTPUT D3 DIAMETER HEIGHT Q HP ft m ft m ft m n3/s m3/s 135 3.61 1.10 3.38 1. 03 3.54 1.08 282 8.00 335 5.09 1.55 5.45 1.66 4.27 1.30 353 10.00 675 6.23 1. 90 6.27 1. 91 6.66 2.03 706 20.00 1350 8.20 2.50 8.99 2. 74 6.99 2.13 1412 40.00 2025 9.84 3.00 11.65 3.55 7.32 2.23 2118 60.00 2700 11.81 3.60 14.27 4.35 ?.84 2.39 2825 80.00 135 1. 97 .60 2.56 . 78 3.54 1.08 60 1. 70 335 3.28 1.00 4.36 1.33 4.27 1. 30 152 4.30 675 4.60 1.40 4. 70 1.43 6.66 2.03 304 8.60 1350 5.25 1. 60 6.89 2.10 6.99 2.13 608 17.20 2025 6.56 2.00 8.92 2.72 7.32 2.23 908 25.70 2700 7.55 2.30 10.86 3.31 7.84 2. 39 1247 35.30 135 1. 48 .45 2.20 .67 3. 54 1.08 35 1.00 335 2.30 . 70 3.67 1.12 4.27 1. 30 88 2.50 675 2.95 .90 4.13 1. 26 6.66 2.03 176 5.00 1350 4.10 1.25 5.74 1. 75 6.99 2.13 353 10.00 2025 4.92 1. 50 7.42 2. 26 7.32 2.23 529 15.00 2700 5.74 1. 75 9.22 2.81 7.84 2.39 706 20.00 4025 6.73 2.05 11.58 3.53 8.23 2. 51 848 24~ 5365 7.55 2.30 13.29 4.05 8.23 2.51 1130 32.00 6700 9.02 2.75 13.94 4.25 8.23 2.51 1412 40.00 Uneconomical above 40' of head I _I "---_ __) ___ J L ___ _ Cl I 1.0 ' ' '- ---, -_J RATED HEAD ft m 9.84 3.00 22.97 7.00 39.37 12.00 39.37 12.00 -~· GENERATOR OUTPUT' kW 100 250 500 1000 1500 2000 100 250 500 1000 1500 2000 100 250 500 1000 1500 2000 3000 4000 5000 i ~, ' ' L -- TURBINE TURBINE OUTPUT D3 HP ft m 135 3. 61 1.10 335 5.09 1. 55 675 6.23 1. 90 1350 8.20 2. so 2025 9.84 3.00 2700 11.81 3.60 135 !. 97 .60 335 3.28 1.00 675 4.60 1.40 1350 5.25 1.60 2025 6. 56 2.00 2700 7. 55 2.30 135 1.48 .45 335 2. 30 .70 675 2. 95 .90 1350 4.10 1. 25 2025 4. 92 !. so 2700 5. 74 1. 75 4025 6. 73 2.05 5365 7. 55 2.30 6700 9.02 2. 75 SHl! [;L'CLTOCL ~ - m I J I .. .I LENGTH j <, ,--- SIZE AND RANGE: OPEN FLLME WITH SPEED INCREASER GENERATOR DIAMETER HEIGHT Q ft m ft m ft3 /s m3 /s 1.80 .55 3. 54 1.08 282 8.00 2.33 .71 4. 27 1. 30 353 10.00 3.00 '91 6. 33 1. 93 706 20.00 3.84 1.17 7.15 2.18 1412 40.00 5.41 1.65 7.35 2.24 2118 60.00 6.33 1. 93 7.81 2.38 2825 80.00 !. 80 .55 3. 54 1.08 60 !. 70 2.33 .71 4.27 1.30 152 4.30 3.00 .91 6.33 1. 93 304 8.60 3.84 1.17 7.15 2.18 608 17.20 5.41 1. 65 7. 35 2. 24 908 25. 70 6.33 1. 93 7.81 2.38 1247 35.3Q 1.80 .55 3. 54 LOR 35 1.00 2. 33 .71 4. 27 !. 30 88 2. 50 3.00 .91 6.33 1.93 176 5.00 3.84 1.17 7.15 2.18 353 10.00 5.41 1.65 7.35 2.24 529 15.00 6.33 1. 93 7.81 2.38 706 20.00 7.09 2.16 8.23 2.51 848 24.00 7.68 2.34 8.23 2.51 1130 32.00 8. 50 2. 59 8.66 2. 64 1412 40.00 n i ~--~ ~----~ r ~ --, . I l -------· l ---· SPEED INCREASER LENGTH WIDTH HEIGHT SHAFT CL TO CL ft m ft m ft m ft m 1.41 .43 1.35 .41 ?..00 . 61 .46 .14 2.40 '73 2.13 .65 2.92 .89 .~2 .?5 3.31 1.01 2. 99 .91 3.48 1.06 1.18 .3n 4. 95 1. 51 4. 23 1. 29 4.89 1.49 !. 84 . 56 5.35 1.63 4.49 1.37 4. 99 1.52 2.00 . 61 6. 63 2.02 5.41 !. 65 5.R7 !. 79 2.49 . 76 !. 41 .43 !. 35 .41 2.00 .61 .46 .14 1. 97 .60 1.80 .55 2.46 . 75 .61i .?0 2. 85 .87 2. 53 .77 ? .n4 . 97 • OR .3Q 4.23 1.29 3.61 1.10 4.13 1.21i 1. 51 .41i 4. 56 1. 39 3. 90 1.19 4.43 1. 35 1 .li7 . 51 5.35 1.63 4.49 1.37 4. gq 1.5? ?..Qn .nl 1.41 .43 \.35 .41 2.00 .61 .46 .]4 1.77 . 54 !. 64 .50 2. 33 . 71 .59 .lR 2.40 . 73 ? .13 .65 2. 92 .P9 .8? .25 3. 31 1.01 2. 99 .91 3.48 1.06 !. lR .31i 4.56 1.39 3. 90 1.19 4.43 1.35 1.67 . 51 4. 95 !. 51· 4.07 1. 24 4.89 !. 49 !. R4 . 56 5.81 1.77 4. 82 1.4 7 5.28 !. 61 ? • 17 .66 6.63 2.02 5.41 1.65 S.Bl 1. 79 ? .49 . 76 7. 84 2.39 6. 30 1. 92 6.R9 2. 10 7. 99 .91 ("""') I ...... 0 RATED HEAD ft m 16.40 5.00 32.81 10.00 65.62 20.00 GENERATOR OUTPUT kW 500 1,000 1,500 2,000 3,000 500 1,000 1,500 2,000 3,000 500 1,000 1,500 2,000 3,000 _I TURBINE OUTPUT HP 675 1,350 2,025 2,700 4,025 675 1,350 2,025 2,700 4,025 675 1,350 2,025 2,700 I 4,025 I SIZE AND RANGE: VERTICAL AND HORIZONTAL CLOSED FLUME WITH DIRECT DRIVE TURBINE ft 4.76 6.37 7.61 9.02 10.83 2.89 3.94 4.76 5.58 6.40 1. 97 2.76 3.35 3.84 4.53 D3 m 1.45 1. 94 2.32 2.75 3.30 .88 1.80 1.45 1. 70 1. 95 .60 .84 1.02 1.17 1.38 I J VERTICAL GENERATOR DIAMETER HEIGHT ft m ft m 5.41 1. 65 6.66 2.03 7.64 2.33 6.99 ?. .13 10.01 3.05 7.35 2.24 12.27 3.74 7.84 2.39 15.62 4.76 8.24 2.51 4.13 1.26 6.66 2.03 6.04 1.84 6.99 2.13 7.74 2.36 7.35 2.24 9.58 2.92 7.84 2.39 11.94 3.64 8.24 2.51 3.51 1.07 6.66 2.03 5.05 1.54 6.99 2.13 6.33 1. 93 7.35 2.24 7.68 ?..34 7.84 2.39 9.58 2.92 8.24 2. 51 HORIZONTAL GENERATOR LENGTH WIDTH ft m ft m 6.33 1. 93 5.41 1.65 6.66 2.03 7.64 ?..33 7.51 2.29 10.01 3.05 7.51 2.29 1?.27 3. 74 7.91 2.41 15.62 4.76 6.33. 1. 93 4.13 1.26 6.66 2.03 6.04 1.84 7.51 2.29 7.74 2.36 7.51 2.29 9.58 2.92 7.91 2.41 11.94 3.64 6.33 1. 93 3. 51 1.07 6.66 2.03 5.05 1.54 7.51 2.29 6.33 1. 93 7.51 2.29 7.68 2.34 7.91 2.41 9.58 2.92 ~--~-. HEIGHT 0 ft m n3 /s m3/s 5.41 1.65 4?0 12 7.64 ?.33 840 24 10.01 3.05 1260 36 13.09 3.99 1700 48 16.44 5.01 2520 7? 4.13 1.26 210 (i fi.04 1.84 4?0 12 7.74 2.36 630 18 10.40 3.17 840 24 12.76 3.89 1260 36 3.51 1.07 106 3 5.05 1.54 212 6 6.33 1. 93 318 9 8.50 2.59 424 12 10.40 3.17 63fi 18 .._ ----_J l _ __J n I ...... ...... I -' RATED HEAD ft m 16.40 5.00 32.81 10.00 65.62 20.00 SIZE AND RANGE: VERTICAL CLOSED FLUME WITH SPEED INCREASER GENERATOR TURBINE TURBINE GENERATOR OUTPUT OUTPUT 03 DIAMETER HEIGHT LENGTH kW HP ft m ft m ft m ft m 500 675 4.76 1.45 2.97 .91 6.33 1.93 2.85 .87 1,000 1,350 6.37 1.94 3.35 1.02 6.66 2.03 4.56 1.39 1,500 2,025 7.61 2.32 4.69 1.43 6.99 2.13 5.35 1.63 2,000 2,700 9.02 2.75 5.41 1.65 7.35 2.24 6.63 2.02 3,000 4,025 10.83 3.30 7.09 2.16 8.24 2.51 7.84 2.39 500 675 2.89 .88 2.97 .91 6.33 1.93 2.40 .73 1,000 1,350 3.94 1.80 3.35 1.02 6.66 2.03 3.68 1.12 1,500 2,025 4.76 1.45 4.69 1.43 6.99 2.13 4.56 1.39 2,000 2,700 5.58 1. 70 5.41 1.65 7.35 2.24 4.95 1.51 3,000 4,025 6.40 1.95 7.09 2.16 8.24 2.51 5.81 1.77 500 675 1. 97 .60 2.97 .91 6.33 1. 93 2.20 .67 1,000 1,350 2.76 . 84 3.35 . 1.02 6.66 2.03 3.15 .96 1,500 2,025 3.35 1.02 4.69 1.43 6.99 2.13 4.23 1.29 2,000 2,700 3.84 1.17 5.41 1.65 7.35 2.24 4.56 1.39 3,000 4,025 4.53 1.38 I 7.09 2.16 8.24 2.51 5.35 1.63 SPEED INCREASER DIMENSIONS n I~ LENGTH .I L!J SPEED INCREASER WIDTH HEIGHT SHAFT CL TO CL ft m ft m ft m 2.53 .77 3.18 .97 .98 .30 3.90 1.19 4.43 1.35 l.67 .51 4.49 1.37 4.49 1. 52 2.00 .61 5.41 1.65 5.87 1.79 2.49 • 7F, 6.30 1. 92 6.89 2.10 2.99 .91 2.13 .65 2.92 .89 .82 .25 3.28 1.00 3.84 1.17 1.35 .41 3.90 1.19 4.43 1.35 1. 67 .51 4.23 1.29 4.89 1.49 1.84 .56 4.82 1.47 5.28 1.61 2.17 .66 1.97 .60 2.69 .82 .76 .23 2.85 .87 3.38 1.03 1.08 .33 3.61 1.10 4.13 1.26 1. 51 .46 3.90 1.19 4.43 1.35 1. F7 .51 4.49 1.37 4.99 1. 52 2.00 .61 n I ~ N RATED HEAD ft m 16.40 5.00 32.81 10.00 65.62 20.00 GENERATOR OUTPUT kW 500 1,000 1,500 2,000 3,000 500 1,DOO 1,500 2,000 3,000 5DO 1 ,ODO 1,500 2,000 3,000 SIZE AND RANGE: HORIZONTAL CLOSED FLUME WITH SPEED INCREASER TURBINE TURBINE GENERATOR OUTPUT D3 LENGTH WIDTH HEIGHT LENGTH HP ft m ft m ft m ft m ft m 675 4.76 1.45 6.00 1.83 2.99 . 91 2.99 . 91 2.85 .87 1,350 6.37 1. 94 6.33 1. 93 3.35 1.02 3.35 1.02 4.56 1.39 2,025 7.61 2.32 6.99 2.13 4.46 1.36 4.46 1. 36 5.35 1.63 2,700 9.02 2.75 6.99 2.13 5.41 1.65 5.41 1.65 6.63 2.02 4,025 1D.83 3.30 7.91 2.41 7.09 2.16 7.35 2.24 7.84 2.39 675 2.89 .88 6.00 1.83 2.99 .91 2.99 .91 2.40 .73 1,350 3.94 1.80 6.33 1.93 3.35 1.02 3.35 1.02 3.67 1.12 2,025 4.76 1.45 6.99 2.13 4.46 1.36 4.46 1.36 4.56 1.39 2,7DO 5.58 1.70 6.99 2.13 5.41 1.65 5.41 1.65 4.95 1.51 4,025 6.40 1. 95 7.91 2.41 7.09 2.16 7.35 2.24 5.R1 ].77 675 1. 97 .60 6.00 1.83 2.99 . 91 2.99 . 91 2.20 .67 1,350 2.76 .84 6.33 1.93 3.35 1.02 3.35 l.O? 3.15 .96 2,025 3.35 1.02 I 6.99 2.13 4.46 1.36 4.46 1.36 4.23 1. 29 2,70D 3.84 1.17 6.99 2.13 5.41 1.65 5.41 1.65 4.56 1.39 4,025 4.53 1.38 7.91 2.41 7.09 2.16 7.31 2. 24 5.35 1.63 ro CL SHAfT CL ~ -4---I -T I I LENGTH t WIDTH _, IN LINE SPEEIJ INCREASER WIDTH HEIGHT SHAFT CL TO CL ft m ft m ft rn 3.18 . 97 2.53 .77 .98 .30 4.43 1.35 3.90 1.19 1.67 .51 4.49 1. 52 4.49 1. 37 2.00 .61 5.87 1. 79 5.41 1.65 2.49 . 76 6.89 2.10 6.30 Ln 2.Q9 .Gl 2.92 .89 2.13 .65 .82 .25 3.84 1.17 3.28 1.00 1.35 .4] 9.43 1. 35 3.90 1.1 Q 1.67 .51 4.89 1.49 4.23 1.29 1.!14 .56 5.28 1. 61 4.82 1.117 2. 17 .F.6 2.69 .82 2.1 7 .6fi .75 .2 3 3.38 1.03 2.85 .87 l.OR .33 4.13 1. 26 3.61 1.] 0 1.51 .46 4.43 1.35 3.90 1.19 l.h7 . 51 4.99 1. 52 4 .llG 1. 3 7 2.00 .61 n I 1--' w RATED HEAD ft m 6.56 2.00 6.56 2.00 6.56 2.00 6.56 2.00 6.89 2.10 8.37 2.55 12.80 3.90 17.06 5.20 23.46 7.15 59.05 18.00 59.05 18.00 59.05 18.00 59.05 18.00 59.05 18.00 59.05 18.00 59.05 18.00 59.05 18.00 59.05 18.00 GENERATOR OUTPUT kW 1,000 1,500 2,000 3,000 4,000 5,000 7,500 10,000 15,000 1,000 1,500 2,000 3,000 4,000 5,000 7,500 10,000 15,000 TURBINE OUTPUT HP 1,350 2,025 2,700 4,025 5,365 6,700 10,060 13,415 20,120 1,350 2,025 2,700 4,025 5,365 6,700 10,060 13,415 20,120 ~---., I i --~J TURBINE D3 ft m 10.17 3.10 12.47 3.80 14.27 4.35 17.55 5.35 19.68 6.00 19.68 6.00 19.68 6,00 19.68 6.00 19.68 6.00 3.28 1.00 3.94 1.20 4.76 1.45 5.48 1.67 6.30 1. 92 7.05 2.15 8.69 2.65 10.01 3.05 11.98 3.65 ft 14.63 17.95 20.54 23.20 28.35 28.35 28.35 28.35 28.35 4.72 5.68 6.86 7.87 9.06 10.17 12.53 14.40 17.26 TYPICAL DIMENSIONS F D w ----) SIZE AND RANGE: BULB TURBINE B c D m ft m ft m 4.46 8.46 27.76 40 .. 68 12.40 5.47 10.37 34.02 49.87 15.20 6.26 11.88 39.98 57.09 17.40 7.07 14.61 47.93 70.21 21.40 8.64 16.38 53.74 78.74 24.00 8.64 16.38 53.74 78.74 24.00 8.64 16.38 53.74 78.74 24.00 8.64 16.38 53.74 78.74 24.00 8.64 16.38 53.74 78.74 24.00 1.44 2.73 8.96 13.12 4.00 1. 73 3.28 10.76 15.75 4.80 2.09 3. 96 12.99 19.03 5.80 2.40 4.56 14.96 21.92 6.68 2.76 5.24 17.19 25.20 7.68 3.10 5.87 19.26 28.22 8.60 3.82 I 7.23 23.72 34.78 10.60 4.39 8.33 27.33 40.03 12.20 5.26 9.96 32.68 47.90 14.60 G I DIMENSIONS E ft m 23.39 7.13 28.67 8.74 32.84 10.01 40.39 12.31 45.28 13.80 45.28 13.80 45.28 13.80 45.28 13.80 45.28 13.80 7.55 2.30 9.06 2.76 10.96 3.34 12.60 3.84 14.50 4.42 16.24 4.95 20.01 6.10 23.03 7.02 I 27.56 8.40 ' ft 51.87 r-~~ '... --.J F m 15.81 63.58 19.38 72.80 22.19 85.53 27.29 100.39 30.60 100.39 30.60 100.39 30.60 100.39 30.60 100.39 30.60 16.73 5.10 20.08 6. J 2 24.28 7 .4(1 27.95 P.52 32.12 9.79 35.99 10.97 44.36 13.52 51.05 15.56 61.09 18.62 G ft 18.31 22.44 25.69 31.59 35.43 35.43 35.43 35.43 35.43 5.91 7.09 8.56 9.88 11.35 12.70 15.65 18.01 21.56 i I I I ~---..J H 0 m ft m f 3 Is m3/s . 5.58 14.63 4.46 2,119 60.00 6.84 17.95 5.47 3,178 90.00 7.83 20.44 6.26 4,238 120.00 9.63 23.20 7.70 fi,357 180.00 10.80 28.35 8.64 8,122 230.00 10.80 28.35 8.64 8,300 23~ .00 10.80 28.35 8.64 8,122 230.00 10.80 28.35 8.64 8,122 230.00 10.80 28.35 8.64 8,830 250.00 1.80 4.72 1.44 237 6. 70 2.16 5.68 1. 73 353 10.00 2.61 6.86 2.09 470 13.30 3 .ll1 7.87 ?.40 7(16 ?0.00 3.46 9.06 2.76 943 ?6. 70 3.?7 10.17 3.10 1.176 33.30 4. 77 12.53 3.82 1,766 50.00 5.49 14.40 4.39 2,350 fi6.60 6.57 17.26 5.26 3,530 100.00 d n I ...... .,J::. I I RATED HEAD ft m 32.81 10.00 49.21 15.00 65.62 20.00 GENERATOR OUTPUT kW 1,000 1,500 2,000 3,000 4,000 5,000 7,500 10,000 15,000 1,000 1,500 2,000 3,000 4,000 5,000 7,500 10,000 15,000 i,ooo 1,500 2,000 3,000 4,000 5,000 7,500 10,000 15,000 TURBINE TURBINE OUTPUT D3 HP ft m 1,350 4.43 l. 35 2,025 5.31 1.62 2, 700 6.33 l. 93 4,025 7.84 2.39 5,365 8.63 2.63 6,700 9.68 2. 95 10,060 11.81 3.60 13,415 13.78 4.20 20,120 16.40 5.00 1,350 3. 94 l. 20 2,025 4.27 1.30 2, 700 5.15 1.57 4,025 6.07 1.85 5,365 6.96 2.12 6, 700 7. 74 2.36 10,060 9.51 2. 90 13,415 11.09 3.38 20,120 13.12 4.00 1,350 3.08 . 94 2,025 3.67 1.12 2' 700 4.49 l. 37 4,025 5.18 1. 58 5,365 5. 97 l. 82 6,700 6. 73 2.05 10,060 8.20 2.50 13,415 9.51 2. 90 20,120 11.15 3.40 w SIZE AND RANGE: BULB TURBINE B c D ft m ft m ft m 6.36 1.94 12.11 3.69 17.72 5.40 7.64 2.33 13.85 4.22 21.26 6.48 9.12 2. 78 17.29 5.27 25.33 7. 72 11.29 3.44 21.39 6.52 31.36 9.56 12.43 3. 79 23.56 7.18 34.51 10.52 13.94 4.25 26.41 8.05 30.71 11.80 16.99 5.18 32.25 9.83 47.24 14.40 19.85 6.05 37.63 11.47 55.12 16.80 23.62 7.20 44.78 13.65 65.62 20.00 5.68 l. 73 10.76 3.28 15.75 4.80 6.14 1.87 11.65 3.55 17.06 5.20 7.41 2.26 14.07 4.29 20.60 6.28 8. 73 2.66 16.57 5.05 24.28 7.40 10.01 3.05 19.00 5. 79 27.82 8.48 11.15 3.40 21.13 6.44 30.97 9.44 13.71 4.18 25.98 7. 92 38.06 11.60 15.98 4.87 30.28 9.23 44.36 13.52 18.90 5. 76 35.83 10.62 52.49 16.00 4.43 l. 35 8.43 2. 57 12.34 3. 76 5.28 1.61 10.04 3.06 14.70 4.48 6:46 l. 97 12.27 3. 74 17.98 5.48 7.48 2.28 14.14 4.31 20.73 6.32 8.60 2. 62 16.31 4. 97 23.88 7.28 9.68 2. 95 18.37 5.60 26.90 8.20 11.81 3.60 22.41 6.83 32.81 10.00 13.71 4.18 25.98 7. 92 38.06 11.60 16.08 4.90 30.45 9.28 44.62 13.60 F D I ~ DIMENSIONS E F G H ft m ft m ft m ft m 10.20 3.11 22.60 6.89 7. 97 2.43 6.36 l. 94 12.24 3. 73 27.10 8.26 9.58 2.92 7.64 2.33 14.57 4.44 32.28 9.84 11.38 3.4 7 9.12 2. 78 18.07 5.50 39.99 12.19 14.11 4.30 11.29 3.44 19.85 6.05 44.00 13.41 15.52 4. 73 13.43 3. 79 22.28 6. 79 49.38 15.05 17.42 5.31 13.94 4.25 27.17 8.28 60.24 18.36 21.26 6.48 16.99 5.18 31.69 9.66 70.28 21.42 24.80 7 .!'6 19.05 6.05 37.73 11.50 73.82 22.50 29.23 9.00 23.62 7.20 9.06 2. 76 20.08 6.12 7.09 2.16 5.68 l. 73 9.81 2.99 21.75 6.63 7.68 2.34 6.14 1.87 11.84 3.61 26.28 8.01 9.28 2.83 7.41 2.26 13.98 4.26 30.97 9.44 10.93 3.33 8.73 2.66 16.01 4.88 35.47 10.81 12.53 3.82 10.01 3.05 17.81 5.43 39.50 12 .D4 13.94 4.25 11.15 3.40 21.88 6.67 48.52 14.79 17.13 5.22 13.71 4.18 25.49 7.77 56.56 17.24 19.95 6.08 15.98 4.87 30.18 9.20 66.93 20.40 23.62 7.20 18.90 5. 76 7.09 2.16 15.72 4. 79 5.54 1.69 4.43 l. 35 8.46 2.58 18.73 5. 71 6.63 2.02 5.28 1.61 10.33 3.15 22.93 6. 99 8.10 2.47 6.46 l. 97 11.91 3.63 26.44 8.06 Q .32 2.84 7.48 2.28 13.75 4.19 30.45 9.28 10.76 3.28 8.60 2.02 15.49 4. 72 34.32 10.46 12'.11 3.69 9.68 ? . 95 18.B6 5. 75 41.83 12.75 14.76 4.50 11.81 3.60 21.88 6.67 48.52 14.79 17.13 5.22 13.71 4.18 25.66 7.82 56.89 17 .. 34 20.08 6.12 16.08 4. 90 G :r: I l~ ---.... --' L__j n I 1--' tTl r ---~l ' .__ __ ) RATED HEAD ft m 9.84 3.00 9.84 3.00 9.84 3.00 19.68 6.00 19.68 6.00 19. 6B 6.00 19.68 6.00 19.68 6.00 19.68 6.00 29.35 9.00 29.35 9.00 29.35 9.00 29.35 9.00 29.35 9.00 29.35 9.00 29.35 9.00 29.35 9.00 29.35 9.00 ---I I l.__.._ _ _., GENERATOR TURBINE OUTPUT OUTPUT kW HP 1,000 1,350 1,500 2,025 2,000 2. 700 1,000 1,350 1, 500 2,025 2,000 2. 700 3,000 4,025 4,000 5, 365 5,000 6,700 1,000 1,350 1, 500 2,025 2,000 2, 700 3,000 4,025 4,000 5,365 5,000 6, 700 6,000 8,050 7,000 9,400 8,000 10,750 r--·---' f ---,----, r - I I l ) 'L-'---~ ---'-__ , SIZE AND RANGE: RIM TURBINE TURBINE MAIN DIMENSIONS -03 Q A ft m ft3/s m3/s ft m ft B.60 2. 62 1,412 40 19.95 6.08 20.28 10.30 3.14 2,120 60 23.88 7.28 24.31 12.24 3. 73 2,825 80 2B.38 8.65 28.87 5.38 l. 64 706 20 12.47 3.80 12.70 6.56 2.00 1,060 30 15.22 4.64 15.49 7.48 2. 2B 1,412 40 17.36 5.29 17.65 9.58 2. 92 2,120 60 22.21 6. 77 22.60 10.99 3. 35 2,825 80 25.49 7. 77 25.95 12.37 3. 77 3,530 100 27.95 R.52 24.74 4.36 l. 33 494 14 10.14 3.09 10.30 5.05 1. 54 706 20 11.71 3. 57 11.91 6.00 1.83 954 27 13.94 4.25 14.17 7. 55 2.30 1,412 40 17.52 5. 34 17.82 8.66 2.64 1, 907 54 20.08 6.12 20.44 9. 71 2. 96 2,366 67 21.95 6.69 19.42 10.83 3.30 2,825 80 23.92 7.29 21.65 11.61 3. 54 3,320 94 25.10 7. 65 23.23 12.43 3. 79 3,780 107 26.12 7. 96 24.87 c --~.., (" -~--, :-l ~~--~~ :------; r ---1 -------1 ' ' I j l __ j l_ ' ' '-------__ j , __ ,_ __, --' TYPICAL DIMENSION B c D ' m ft m ft m 6.18 17.19 5.24 12.37 3. 77 7.41 21.33 6.50 14.83 4.52 8.80 25.33 7. 72 17.62 5. 37 3. 87 11.12 3.39 7. 74 2.36 4. 72 13.58 4.14 9.45 2.8B 5. 38 15.49 4. 72 10.76 3.28 6.89 19.82 6.04 13.78 4.20 7. 91 22.74 6. 93 15.81 4.82 8 7. 54 20.41 6.22 17.81 5.43 3.14 9.02 2. 75 6.30 l. 92 3. 63 10.4 7 3.19 7. 2R 2. 22 4.82 12.43 3. 79 R.66 2.64 5.43 15.62 4. 76 10.86 3. 31 6.23 17.91 5.46 12.47 3.80 5. 92 16.01 4.88 13.98 4.26 6.60 17.88 5.45 15.58 4. 75 7. 08 19.16 5.84 16.73 5.10 7. 58 20.51 6.25 17.91 5.46 ('""') I ........ 0'1 RATED HEAD ft m 19.68 6.00 39.37 12.00 59.05 18.00 GENERATOR TURBINE OUTPUT OUTPUT D3 kW HP ft 250 335 3.12 500 675 3.12 750 1,010 4.10 250 335 2.30 500 675 3.12 750 1,010 4.10 1,000 1,350 3.12 1,500 2,025 4.10 250 335 2.30 500 675 3.12 750 1,010 4.10 1,000 1,350 4.10 1,500 2,025 4.10 2,000 2,700 4.10 s 1-LENGTH J SIZE AND RANGE: CROSS FLOW TURBINE WITH SPEED INCREASER TURBINE b LENGTH m ft m ft m .95 2.96 9. 71 4.27 1.30 .95 2.96 9.71 6.00 1.83 1.25 3.89 12.76 6.33 1.93 0 70 1.30 4.27 4.27 1.30 .95 1. 74 5.71 6.00 1.83 1.25 2.30 7.55 6.33 l. 93 .95 1.74 5.71 6.33 1.93 1.25 2.30 7 0 55 6.99 2.13 .70 .96 3.15 4.27 1.30 .95 1.31 4.30 6.00 1.83 1.25 1. 73 5.68 6.33 l. 93 1.25 1.73 5.68 6.33 1.93 1.25 1. 73 5.68 6.99 2.13 1.25 1.73 5.68 6.99 2.13 GENERATOR SPEED INCREASER (in line) WIDTH HEIGHT LENGTH WIDTH HEIGHT SHAFT CL TO CL ft m ft m m ft ft m ft m ft 2.33 0 71 3.02 .92 4.27 1.30 3.18 .97 2. 76 .84 2.26 2.99 .91 2.99 .91 4.99 1.52 3.71 1.13 3.18 .97 2.66 3.15 .96 3.15 .96 6.56 2.00 6.20 1.89 4.07 1.24 3.58 2.33 .71 3.02 .92 3.84 1.17 2.89 .88 2.49 .76 2.00 2.99 .91 2.99 .91 4.79 1.46 3.58 1.09 3.08 .94 2.49 3.15 .96 3.15 .96 5.61 l. 71 4.30 1.31 3.58 1.09 2.99 3.35 1.02 3.35 1.02 6.23 ).90 5.87 1.79 3.90 1.19 3.35 4.46 1.36 4.46 1.36 8.50 2.59 7.91 2.41 5.35 1.63 4.59 2.33 0 71 3.02 .92 3.84 1.17 2.89 .88 2.49 .76 2.00 2.99 .91 2.99 .91 4.79 1.46 3.58 1.09 3.08 .94 2.49 3.15 .96 3.15 .96 5.61 1.71 4.30 1.31 3.58 1.09 2.99 3.35 1.02 3.35 1.02 6.23 1.90 5.87 l. 79 3.90 1.19 3.35 4.46 1.36 4.46 1.36 8.50 2.59 7.91 2.41 5.35 1.63 4.59 5.41 1.65 5.41 1.65 9.25 2.82 8.10 2.47 5.84 1.78 4.99 NOTES 1. Turbine dimensions are estimated from theoretical equations and F. W. E. Stapenhorst literature. 2. Generator dimensions are based on Ideal Electric and Lima Electric units. 3. Speed increaser dimensions are based on Western Gear 7000 series units. m .69 .81 . 1.09 .61 .76 .91 1.02 1.40 .61 .76 .91 1.02 1.40 1.52 ' i , __ _) COST SUMMARY SHEET ~-, I I I , --" PROJECT --------------PLANT CAPACITY _____ MW JOB NO. ____________________ __ AVG. ANNUAL ENERGY MWh DATE _____________________ ___ BY ---------------------- FERC ) ACCT. Escalation Escalated L ___ ; NO. Description Cost* Factor Cost Total (--, ! I I , L __ j 330 LAND & LAND RIGHTS 331 STRUCTURES & IMPROVEMENTS Site .11 Drainage System .12 Erosion Control .13 Final Grading ·.14 Access Road .15 Parking & Misc. Site ,---, LJ Features .16 Environmental Construction Controls .17 .18 Powerhouse .21 Str'uctural .22 Excavation .23 Switch yard Subtotal .24 Foundation (2 Percent of Subtotal) Total, Account 331 *Cost base July 1978. L _) D-1 FERC ACCT. NO. Description 332 RESERVOIRS, DAMS & WATERWAYS .01 Dam .02 Penstock .03 Valves .04 Bifurcation & Slide Gates. .05 Tailrace .06 Intake Structure .07 Total, Account 332 333 WATER WHEELS, TURBINES, AND GENERATORS STATION ELECTRICAL EQUIPMENT Station Electrical Switchyard Electrical Total, Account 333 335 MISC. POWER PLANT EQUIPMENT 336 ROADS & BRIDGES * Cost Base July 1978. Escalation Escalated Cost* Factor Cost D-2 Total l ._j _J --, : f] FERC ACCT. Escalation Escalated NO. Description Cost* Factor Cost Total 335 TRANSMISSION LINE TOTAL CONSTRUCTION COST REGIONAL CORRECTION FACTOR ( ) Regional Correction r --~ I ___ .J Contingency Engineering & Construction Management and Other Costs Interest During Construction GRAND TOTAL *Cost Base _July 1978 \] D-3 ----I -I "---' 1. .. ·. '\. -,, . . ~ i) t ' • \ ~*". ( • l '•' ' ' .. LIST OF 'REFERENCES ' '. · Estimating Handbook, Series 150 Estimating and Appendix 150A, United States Department of Interior, Bureau of Reclamation, Engineering and Research Center, Denver Federal Center, Denver, Colorado 80225. · 2. Inadequate Hydrologic Data and Reservoir Capacity in Decisions with Inadequate Hydrologic Data by Thomas A. McMahon and Gary P. Codner, Proceedings of the Second International Symposium in Hydrology, September 1972, Fort Collins, Colorado. 3. Selecting Hydraulic Turbines, United States Department of the Interior, Bureau of Reclamation, Engineering Monograph No. 20, U. S. Government Printing Office, Stock Number 024-003-001007, 1976. 4. Handbook of Applied Hydraulics, by Calvin V. Davis and Kenneth E. Sorenson, Third Edition, McGraw-Hill Book Company. 5. Design of Small Dams, United States Department of the Interior~ U. S. Government Printing Office, Stock Number 024-003-00119-8, Second Edition, Revised Reprint, 1977. 6. Hydroelectric Handbook by William P. Creager and Joel D. Justin, John Wiley & Sons, Inc.; 2nd Edition, 1950. 7. Welded Steel Penstocks, United States Department of the Interior, Bureau of Reclamation, Engineering Monograph No. 3, U. S. Government Printing Office, 1977. 8. 9. Friction Factors for Large Conduits Flowing Full, United States Department of the Interior, Bureau of Reclamation, Engineering Monograph No. 7, Uni~·~d State~.~Government _Printi.~g Office, 1977.:· ';;.: .-.-:··': .-~. • . .. :~ '. . ·~ ·.: .~ ·: i ;tJ: '• ' 1 : ~.' ~ \ -~· :-"-- f ,. _:•' Engineering Fluid Mechanics by Charles Jaeger, Blackie and Son Limited, 16118 Williamson IV Street, Charing Cross, London W.E.2. ,. ·~·. ; . .. ' PROPERTY OF: Alaska Power Authority 334 W. 5th Ave. Anchorage, Alaska 99501 10. Engineering News-Record, McGraw-Hill 1 s Construction Weekly, McGraw-Hill Inc., McGraw-Hill Building, 1221 Avenue of the Americas, New York, N.Y. 10020; March 22, 1979 page 107; June 21, 1979 page 101 ~ September 20, 1979 page 93; December 20, 1979 page 86. 11. Monthly Labor Review, Superintendent of Documents, Government Printing Office, Washington, D.C. 20402. 12. Principals of Engineering Economy by Eugene L. Grant, Ronald Press Company, New York, 3rd Edition, 1950. 13. Financial Compound Interest and Annuity Tables, Publication No. 276, Financial Publishing Company, Boston, Mass. 14. Problems of Hydroelectric Development at Existing Dams. The Johns Hopkins University/Applied Physics Laboratory, John Hopkins Road, Laurel, Md. 20810, HE-003, QM-78-243, November 1978. 15. Net Energy Analysis: Handbook for Combining Process and Input-Output Analysis by Clark W. Bullard, Peter S. Penner and David A. Pilati, University of IlJinois at Urbana-Champaign, Urbana, Illinois 61801, CAC Document 214, October 1976. 16. Energy Requirements for Ca 1 iforni a Water Projects, SRI Intern at i ana 1 333 Ravenswood Avenue, Menlo Park, California 94025, January 1979. 17. Engineering News Record, McGraw-Hill 1 s Construction Weekly, McGraw-Hill Inc., McGraw-Hill Building, 1221 Avenue of the Americas, New York, N.Y. 10020; Page 38, July 6, 1978. LIB Y .l ,.,'i ·. '