Rehabilitating and Upgrading Hydro Power Plants a Hydro Power Technology Round-Up Report, Volume 2 (2)

Rehabilitating and Upgrading Hydropower Plants

A Hydropower Technology Round-Up Report, Volume 2

Effective December 6, 2006, this report has been made publicly available in accordance with Section 734.3(b)(3) and published in accordance with Section 734.7 of the U.S. Export Administration Regulations. As a result of this publication, this report is subject to only copyright protection and does not require any license agreement from EPRI. This notice supersedes the export control restrictions and any proprietary licensed material notices embedded in the document prior to publication.

EPRI Project ManagerM.A. Blanco

EPRI • 3412 Hillview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 94303 • USA800.313.3774 • 650.855.2121 • [email protected] • www.epri.com

Rehabilitating and UpgradingHydropower PlantsA Hydropower Technology Round-Up Report,Volume 2

TR-113584-V2

Final Report, November 1999

DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES

THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS ANACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCHINSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THEORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:

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iii

CITATIONS

This report was prepared by

HCI Publications410 Archibald StreetKansas City, Missouri 64111

Principal InvestigatorsJ.C. Phillips, P.E.C. Vansant, P.E.

This report describes research sponsored by EPRI.

The report is a corporate document that should be cited in the literature in the following manner:

Rehabilitation and Upgrading Hydro Plants: A Hydropower Technology Round-Up Report,Volume 2, EPRI, Palo Alto, CA: 1999. TR-113584-V2.

v

REPORT SUMMARY

Owners of aging hydropower plants are confronted with an array of project and technologyoptions for rehabilitating or upgrading their facilities and are making large capital investmentdecisions at a time of increasing competitive pressures. Ensuring that investments in plant areoptimal requires a thorough understanding of the technologies, approaches and strategiesavailable for rehab and upgrading—as well as the risks associated with these projects. Thisvolume of EPRI’s Hydropower Technology Roundup report presents techniques and practices,lessons learned, and examples of the rehabilitation and upgrading of hydropower plants.

BackgroundHydropower plant owners and operators are rehabilitating and upgrading hydro plants to increasethe value of output, add capacity, improve reliability, reduce operating and maintenance expense,extend plant life, and comply with environmental and safety regulations or voluntarily-imposedstandards. Some owners have adopted formal, comprehensive programs; others employ a plant-by-plant, unit-by-unit, component-by-component approach. Significant funds are being expendedto prepare facilities around the world “for the 21st century”. Although not intended to provideexhaustive coverage of the issues, this second volume of the Technology Roundup Report canhelp hydropower mangers understand the state-of-the-art in rehabilitation and upgrading in theglobal hydropower community and learn from others’ experience. For a comprehensivetreatment of hydropower rehabilitation and upgrading see EPRI report GS-6419, Volumes 1-3,Hydropower Plant Modernization Guide, which is currently being updated.

Objective• To describe the spectrum of contemporary hydropower rehabilitation and upgrade programs

and projects

• To summarize the technologies and methodologies involved in such programs or projects

• To present “lessons learned” and the state-of-the-art

ApproachThe investigators assembled and reviewed recent pertinent conference reports, publications,other literature, and audiotapes of roundtable discussions on hydropower rehabilitation andupgrade programs. They contacted individuals known to have significant experience in theselected areas and invited them to share additional information and perspectives. They choseexample applications and case studies for presentation involving hydro facilities of all ages,types, and sizes, located in North America and worldwide. To the extent appropriate, they madegeneralizations concerning the applicability and benefits of the strategies and technologiesimplemented in these applications.

vi

ResultsNumerous successful improvements to hydro systems, plants, units, and individual componentsare identified and described in the report. Specific plant components rehabilitated or upgradedinclude turbines, water passage and conveyance facilities, generators, governors and controls,and auxiliary systems and equipment. Numerous “lessons learned” gleaned from the literature oroffered by contributors are presented to assist others in the consideration or application of thesestrategies and technologies.

EPRI PerspectiveFaced with cost competition, increasing environmental standards, and on-going licensingrequirements, hydropower plant owners need to know about the technology options available andunder development to make their facilities more compliant, protective of the environment, andcompetitive. They need information about the benefits and costs of alternative technologies andthe successful practices and strategies used for their implementation. EPRI’s HydropowerTechnology Roundup report series will provide a clearinghouse for worldwide information onkey topics and new and emerging technologies, including case studies and contacts. This volumepresents an overview of research, practices, lessons learned, and some examples regarding therehabilitation and upgrading of hydropower plants. Technology Roundup reports are publishedseveral times a year.

TR-113584-V2

KeywordsControlsGenerators/Motor-GeneratorsGovernorsRehabilitating(ion)Turbines/Pump-TurbinesUpgrade(ing)

EPRI Licensed Material

vii

ACKNOWLEDGMENTS

Special thanks and acknowledgment is made to those individuals and organizations whoseassistance and gracious input were key to the development of this report. The followingcontributors provided information and perspectives via personal communication:

Michael Bahleda - American Electric Power Service Corporation, Columbus, Ohio

Martin A. Bauer - U. S. Bureau of Reclamation, Sacramento, California

Paul A. Bernhardt - Niagara Mohawk Power Corporation, Syracuse, New York

Lawrence D. Chapman - Tennessee Valley Authority, Chattanooga, Tennessee

William H. Colwill, Ph.D. - American Hydro Corporation, York, Pennsylvania

Bob D. Foster - Lower Colorado River Authority, Buchanan Dam, Texas

Matthew E. Gass, P.E. - Hetch Hetchy Water and Power, Moccasin, California

Nick M. Hawley, P.E., C.E. - BC Hydro, Burnaby, British Columbia

Dan Jarvis - AmerenUE, Eldon, Missouri

David C. Kee, P.Eng. - Ontario Hydro, Toronto, Ontario

Robert J. Knowlton, P.E. - New York Power Authority, White Plains, New York

Hans F. Naeff - ABB Power Generation, Inc., Littleton, Colorado

Niels M. Nielsen, P.Eng. - BC Hydro, Burnaby, British Columbia

Steven C. Onken, P.E. - Oroville-Wyandotte Irrigation District, Oroville, California

Jiri Spidla, Ph.D. - CKD Blansko Engineering a.s., Blansko, Czech Republic

The assistance of Marla Barnes and Catherine Bennett at HCI Publications for providingreference materials and permitting the use of HCI files was essential to the research for thisreport and is acknowledged, with appreciation.


ix

CONTENTS

1 INTRODUCTION.................................................................................................................. 1-1

Situation ............................................................................................................................. 1-1

Trends in Rehabilitation ...................................................................................................... 1-2

Report Organization............................................................................................................ 1-2

Reference........................................................................................................................... 1-2

2 REHABILITATING AND UPGRADING HYDRO PLANTS ................................................... 2-1

Objectives of Hydro Rehabilitation and Upgrading.............................................................. 2-1

Scope of Rehabilitation and Upgrade Programs and Projects............................................. 2-2

Turbines and Pump-Turbines......................................................................................... 2-2

Generators and Motor-Generators ................................................................................. 2-2

Governors, Controls, and Auxiliary Systems .................................................................. 2-2

Civil Works..................................................................................................................... 2-2

Tennessee Valley Authority (TVA) Hydro Modernization Program...................................... 2-3

1998 Rehabilitation Benchmarking Survey ......................................................................... 2-3

Gains in Capacity and Efficiency......................................................................................... 2-4

Definitions........................................................................................................................... 2-5

Rehabilitation ................................................................................................................. 2-5

Upgrade or Upgrading.................................................................................................... 2-6

Modernization ................................................................................................................ 2-6

Redevelopment.............................................................................................................. 2-6

Refurbishment................................................................................................................ 2-6

Replacement.................................................................................................................. 2-6

Repowering.................................................................................................................... 2-6

Retrofit ........................................................................................................................... 2-6

Uprating ......................................................................................................................... 2-7

Overhaul ........................................................................................................................ 2-7

References ......................................................................................................................... 2-7


x

3 TURBINES AND PUMP-TURBINES.................................................................................... 3-1

Planning for Turbine Rehabilitation or Upgrade .................................................................. 3-1

Model and Acceptance Testing........................................................................................... 3-2

Computational Fluid Dynamics (CFD)................................................................................. 3-3

Reaction Turbines .............................................................................................................. 3-3

Francis Turbines and Pump-Turbines ............................................................................ 3-3

Solving Draft Tube Hydraulic Instability in a High-head Turbine Upgrade .................. 3-3

Pump-Turbine Design................................................................................................ 3-4

Medium-Sized Plant Upgraded for Capacity .............................................................. 3-4

Large Conventional Plant Upgraded for Capacity ...................................................... 3-5

Upgrading a Small, Old Unit ...................................................................................... 3-6

Cylinder Gates........................................................................................................... 3-7

Two Pumped Storage Plant Upgrades ...................................................................... 3-7

Fixed - Blade Propeller and Kaplan Turbines ................................................................. 3-8

Major Plant Upgrade - Kaplan Units .......................................................................... 3-8

Upgrading a Medium-Sized Propeller Turbine ........................................................... 3-9

Rehabilitation of Small Propeller Turbines ................................................................. 3-9

Submersible Replacement Units.............................................................................. 3-10

Upgrading Large Turbines for Fish-Friendliness ...................................................... 3-10

Reaction Turbines - Common Elements....................................................................... 3-11

Draft Tubes ............................................................................................................. 3-11

Vibration and Resonance ........................................................................................ 3-11

Impulse (Pelton) Turbines................................................................................................. 3-11

Upgrading Small Pelton Units...................................................................................... 3-13

Pelton Turbine Upgrade Program................................................................................ 3-13

Civil Works Improvements in Conjunction with Turbine Upgrades .................................... 3-14

Rehabilitation of a Powerhouse Resulting in Improved Turbine.................................... 3-14

Replacement of Penstocks to Improve Turbine Performance....................................... 3-14

Penstock Replacement Integrated with Turbine Rehabilitation..................................... 3-15

Lessons Learned .............................................................................................................. 3-16

References ....................................................................................................................... 3-17

4 GENERATORS AND MOTOR-GENERATORS ................................................................... 4-1

Rehabilitation and Upgrade Practices................................................................................. 4-1

Tennessee Valley Authority (TVA) Approach ................................................................. 4-1


xi

Mechanical Aspects to Generator Upgrade.................................................................... 4-2

Pitfalls of Generator Rehabilitation and Upgrade............................................................ 4-3

Generator Protection...................................................................................................... 4-3

Upgrading Generators at a Major Plant .......................................................................... 4-4

Correcting Generator Rotor Roundness ......................................................................... 4-5

Replacement of Exciters with Generators ...................................................................... 4-5

Thrust Bearing Cooling System Upgrade ....................................................................... 4-6

Experience with Stator Iron ............................................................................................ 4-6

Developing Technologies.................................................................................................... 4-6

Insulation Systems......................................................................................................... 4-6

High Voltage Generators................................................................................................ 4-7

Variable (Adjustable) Speed Machines........................................................................... 4-7

Lessons Learned ................................................................................................................ 4-7

References ......................................................................................................................... 4-8

5 GOVERNORS, CONTROLS, AND AUXILIARIES ............................................................... 5-1

Governors and Controls...................................................................................................... 5-1

Control of a Remote Plant in a Small System................................................................. 5-1

Control of a Major Pumped Storage Plant ...................................................................... 5-2

Automation of a Medium-Sized, Conventional Plant....................................................... 5-2

Control of a Large System ............................................................................................. 5-3

Automation of a Large, Conventional Peaking Plant....................................................... 5-3

Governor Controls Upgrade at a Pumped Storage Plant ................................................ 5-4

Upgrading Controls at a Major, Remotely-Operated Plant.............................................. 5-4

Electric Servomotors ...................................................................................................... 5-5

Wicket Gate Latches ...................................................................................................... 5-5

Auxiliaries ........................................................................................................................... 5-5

Plant Upgrade Focused on Controls and Auxiliaries....................................................... 5-6

Auxiliary Equipment Replacement Program ................................................................... 5-7

Lessons Learned ................................................................................................................ 5-7

References ......................................................................................................................... 5-8

6 EVALUATION, PLANNING, MANAGEMENT, AND IMPLEMENTATION............................ 6-1

Approaches to Strategic Management and Planning .......................................................... 6-1

Overall Asset Management Program ............................................................................. 6-1


xii

Investor-Owned “Utility” Generation Investment Perspective.......................................... 6-1

Economic Evaluation, Planning, and Prioritization .............................................................. 6-2

Risk-Based Analysis of Hydro Improvements................................................................. 6-2

Large System Hydro Improvement Programs ..................................................................... 6-2

Electricité de France (EDF) ............................................................................................ 6-2

Tennessee Valley Authority (TVA) ................................................................................. 6-3

Companhia Energética de São Paulo (CESP)................................................................ 6-3

U.S. Army Corps of Engineers (Corps)........................................................................... 6-4

Small Hydro Upgrade Programs in Predominately Thermal Systems ................................. 6-5

Lower Colorado River Authority (LCRA)......................................................................... 6-5

Duke Power ................................................................................................................... 6-6

American Electric Power Corporation (AEP) .................................................................. 6-6

Project Planning and Management ..................................................................................... 6-6

Hydro-Quebec - Beauharnois Plant................................................................................ 6-6

Small Plant Upgrade - Washington Water Power (WWP)............................................... 6-7

Planning a Comprehensive Plant Rehabilitation - Seattle City Light (SCL)..................... 6-7

Commercial Arrangements, Procurement, “Partnering” ...................................................... 6-8

Sharing Risk between Owner and Supplier .................................................................... 6-9

New Approaches to Funding Government Hydro Improvements (U.S.).......................... 6-9

Tennessee Valley Authority (TVA) ................................................................................. 6-9

BC Hydro ..................................................................................................................... 6-10

U.S. Army Corps of Engineers (Corps)......................................................................... 6-10

Lower Colorado River Authority (LCRA)....................................................................... 6-10

Landsvirkjun - Partnering in an Expedited Repowering ................................................ 6-11

Ontario Hydro (OH)...................................................................................................... 6-11

Lessons Learned .............................................................................................................. 6-12

References ....................................................................................................................... 6-13

A CONTACT-LIST ..................................................................................................................A-1

Owners ...............................................................................................................................A-1

Suppliers - Turbines............................................................................................................A-3

Suppliers - Generators........................................................................................................A-3

Suppliers - Governors and Controls....................................................................................A-3


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LIST OF TABLES

Table 1-1 Rehabilitation and Upgrade Programs and Projects Discussed in this Report ......... 1-3

Table 2-1 Rehabilitation and Upgrade Programs and Projects (in order of mention intext) ................................................................................................................................. 2-8

Table 2-2 Capacity and Efficiency Improvements (in order of decreasing MW prior toupgrade) ........................................................................................................................ 2-14


1-1

1 INTRODUCTION

In 1998, as part of its core program in the hydroelectric generation area, EPRI initiated the“Hydropower Technology Round-Up” project. The objective of the project is to prepare periodic“Tech Round-Up” reports to disseminate useful, world-wide information related to hydro powertechnological advancements.

The scope of the investigation brought to you in this report has been broad, including both U.S.domestic and international utilities and companies having international experience. This reportpresents an overview of research, practices, lessons learned, and some examples regardingenvironmental solutions to lubrication, specifically, utilizing self-lubricating materials andenvironmental lubricants at hydro facilities. Part 2 presents an overview of techniques andpractices, lessons learned, and some typical examples regarding the rehabilitation and upgrade ofhydro plants.

Situation

The onset of the competitive market for generation of electricity in North America and elsewherehas intensified interest in maximizing the economic efficiency of conventional and pumpedstorage hydro plants. Customer choice initiatives, the Kyoto Protocol to reduce greenhouse-gasemissions, and ever-stricter environmental regulations have increased the focus on theenvironmental compatibility of hydro generation. At the same time, market prices for energy andgenerating capacity are relatively low and are projected to remain so for the foreseeable future,as markets move to open pricing.

To sustain hydro’s efficiency and competitiveness requires implementation of improved, morecost-effective maintenance and operating practices and the commitment to applyingtechnological advancements. Furthermore, consideration of plant rehabilitation and upgrading toincrease the value of output, minimize environmental risks, reduce operating expenses, andextend maintenance intervals and overall service life are key to the sustained viability of hydroresources.

Significant investment is often needed to improve many hydro plants—particularly older,conventional plants—to restore or sustain efficiency and competitiveness, and to meetenvironmental objectives. However, economic justification of needed investments is often verydifficult. Recent improvements in technology, particularly in the areas of hydro-turbine andcomponent design and manufacture, control equipment and instrumentation, and improved lifeand maintenance management, have greatly enhanced the prospects for increasing productionand economic efficiency, and extending the life, of existing hydro plants.


Introduction

1-2

Trends in Rehabilitation

An industry benchmarking survey conducted in conjunction with the HydroVision 98 conferenceheld July 1998 in Reno, Nevada, provides a good sampling of general approaches and practicesbeing implemented by hydro owners, primarily in North America, with regard to plant orcomponent rehabilitation. A total of 66 rehabilitation projects were reported. The survey reportpresents statistics on the reasons for rehabilitation, strategies employed, economic andprioritization criteria, contracting arrangements, and quality control and testing methods.Leading the list of project components approved for rehabilitation are turbine runners andmiscellaneous components, generator stator windings and miscellaneous components, excitationsystems, and governors. [1]

Report Organization

The remainder of this report is organized as follows:

Section 2 - Rehabilitating and Upgrading Hydro Plants

Section 3 - Turbines and Pump-Turbines

Section 4 - Generators and Motor-Generators

Section 5 - Governors, Controls, and Auxiliaries

Section 6 - Evaluation, Planning, Management, and Implementation

Many hydro rehabilitation and upgrade programs and projects have been initiated or successfullycompleted, substantially improving the economic efficiency and reliability of hydro plants.Table 1-1 presents the programs and projects discussed in this report.

Each section contains a “lessons learned” subsection, presenting some general guidance based onthe experience of the contributors.

References are listed at the end of each report section. Lists of contacts for various owners,suppliers, and manufacturers involved in programs and projects discussed in this report arecontained in Appendix A of this report.

Reference

1. Hydro Rehabilitation Practices: What’s Working in Rehabilitation. HCI Publications, KansasCity, MO, 1998.


Introduction

1-3

Table 1-1Rehabilitation and Upgrade Programs and Projects Discussed in this Report

Program, Project, orPowerhouse

State (U.S.),Province (Canada),

or Country

Owner SectionNo(s).

Arnprior Ontario Ontario Hydro 4Asset Management British Columbia BC Hydro 6Austin Texas Lower Colorado River Authority 6Auxiliary EquipmentReplacement

Texas Lower Colorado River Authority 5

Beauharnois Québec Hydro-Québec 6Bennetts Bridge New York Niagara Mohawk Power Corp. 3

Berrien Springs Michigan American Electric Power Corp. 3Big Creek 1 California Southern California Edison 3Boundary Washington Seattle City Light 6Bradley Lake Alaska Alaska Industrial Development

and Export Authority5

Buchanan Texas Lower Colorado River Authority 6Búrfell Iceland Landsvirkjun 6California Water Project California California Water Project 5

Castaic California Los Angeles Dept. of Water &Power

5

Chippewa Falls Wisconsin Northern States Power 3

Clam River Wisconsin Northwestern WisconsinElectric Co.

3

Forbestown California Oroville-Wyandotte IrrigationDistrict

3

Fort Peck No. 1 Montana U.S. Army Corps of Engineers 3Great Falls South Carolina Duke Power 3Holm California Hetch Hetchy Water & Power 3Hydro Improvement France Electricité de France 6

Hydro Modernization Tennessee andseveral adjacentstates

Tennessee Valley Authority 2,6

Hydro Modernization Several states ineastern Mid-west

American Electric Power Corp. 6

Hydroelectric Life Extension Texas Lower Colorado River Authority 6Inks Texas Lower Colorado River Authority 6

John Hollis Bankhead Alabama Alabama Power Co. 3Jupiá Brazil Companhia Energética de São

Paulo6

Kirkwood California Hetch Hetchy Water & Power 6Lookout Shoals North Carolina Duke Power 4Major Rehabilitation Many states U.S. Army Corps of Engineers 4,5,6Muddy Run Pennsylvania PECO Energy 3,5

New Moccasin California Hetch Hetchy Water & Power 3


Introduction

1-4

Table 1-1Rehabilitation and Upgrade Programs and Projects Discussed in this Report (continued)

Program, Project, orPowerhouse

State (U.S.),Province (Canada),

or Country

Owner SectionNo(s).

Nine Mile Washington Washington Water Power 6Osage Missouri AmerenUE 5Porjus Sweden Vattenfall 4

Robert Moses Niagara New York New York Power Authority 3Robert S. Kerr Dam Oklahoma Grand River Dam Authority 5Rocky Reach Washington Public Utility District No. 1 of

Chelan County3,4

Säckingen Germany Rheinkraftwerk Sackingen AG 5Shasta California U.S. Bureau of Reclamation 4,6Small Plant Rehabilitation North Carolina,

South CarolinaDuke Power 6

Stechovice Czech Republic Czech Power Company CEZ,a.s.

3

Tafjord K2 Norway Tafjord Power Co. 3

Trängslet Sweden Stora Power AB 5Tuxedo North Carolina Duke Power 3Twin Branch Indiana American Electric Power Corp. 3Wanapum Washington Public Utility District No. 2 of

Grant County3

Yale Washington PacifiCorp 3


2-1

2 REHABILITATING AND UPGRADING HYDRO PLANTS

World-wide, many hydro plants, particularly older plants, are undergoing rehabilitation andupgrading. Plants and facilities being rehabilitated or upgraded are of all types. The reasons forand the scope, objectives, and costs of rehabilitation and upgrade programs and projects arewide-ranging.

This report presents techniques and practices, lessons learned, and some typical examplesregarding the rehabilitation and upgrading of hydro plants. Table 2-1 lists the rehabilitation andupgrade programs and projects discussed.

A comprehensive treatment of the subject of hydro plant rehabilitation and upgrading may befound in EPRI’s Hydropower Plant Modernization Guide (three volumes) published in 1989. [1]EPRI plans to replace the 1989 guide with new guidelines for plant life extension andmodernization. The first volume of the new guidelines is expected to be published in 1999. [2]

Objectives of Hydro Rehabilitation and Upgrading

Each hydro rehabilitation or upgrading program or project has its own, sometimes unique,objectives. Among possible objectives are:

• Extending life• Halting or decelerating deterioration• Increasing generating capacity• Improving efficiency• Reducing risk of catastrophic failure• Reducing forced outages or unscheduled down time• Improving ability to control equipment via

– remote control

– automation

• Improving ability to deliver “ancillary services”

• Improving ability to meet river flow or reservoir level requirements

• Matching unit performance characteristics to load or water availability, including removing“bottlenecks” in cascade hydro systems

• Improving plant/personnel safety

• Reducing potential for environmental degradation


Rehabilitating and Upgrading Hydro Plants

2-2

• Enhancing water quality• Reducing fish mortality• Reducing operations or maintenance costs• Reducing frequency of overhauls, scheduled down time• Reducing undesirable running characteristics, such as vibration• Avoiding obsolescence problems such as lack of manufacturer support or unavailability of

replacement parts• Meeting legal/licensing requirements

Scope of Rehabilitation and Upgrade Programs and Projects

Hydropower rehabilitation programs and projects can be directed toward the restoration orimprovement of any or all plant components or equipment. An incomplete list includes:

Turbines and Pump-Turbines

Runners, impeller-runners, nose cones, seals, wearing rings, equalizing lines and valves, shafts,stuffing boxes, wicket and cylinder gates and operating mechanisms, stay vanes, draft tubeliners, bearings, bushings, head covers, spiral or scroll cases, discharge rings, bottom rings,nozzles and needle valves, deflectors, brakes, and seals.

Generators and Motor-Generators

Shafts, stator windings, stator cores, rotor windings, field poles, spiders, brushes, slip rings,bearings, circuit breakers, meters, exciters, amortisseur windings, cooling/ventilation systems,and grounding.

Governors, Controls, and Auxiliary Systems

Hydraulic systems, supervisory control and data acquisition (SCADA) systems, condition andperformance monitoring instruments, meters, alarms, communications, cables, flowmeters,remote terminal units (RTUs), plant and unit programmable logic controllers (PLCs), voltageregulators, synchronizing equipment, servomotors, station electrical service, transformers,switch-gear, buses, circuit breakers, transmission, plant cooling systems, compressed air systems,dewatering systems, heating-ventilation-air conditioning (HVAC) systems, fire protection,potable water supply, sanitary systems, contaminant containment and removal facilities orequipment, and powerhouse cranes and hoists.

Civil Works

Intakes, gates, tunnels, surge tanks, penstocks, turbine or isolation valves, tailraces, dams,spillways, spillway gates, powerhouse structures, trash removal systems, bulkheads, and exteriorcranes and hoists.



2-3

Tennessee Valley Authority (TVA) Hydro Modernization Program

TVA’s “Hydro Modernization Program” is a 15-year program that will involve 88 conventionalhydro units. In TVA’s program, the scope of a hydro improvement is described by the alternativeterms “rehabilitation” or “uprate,” as outlined below. [3] “Rehabilitation” normally includes thefollowing work items:

• Refurbishment of main exciters• Replacement of pilot exciters and field rheostats• Replacement of generator neutral switchgear and reactors• Replacement of generator relaying• Repair of thrust and guide bearings• True-up of generator and turbine shafts• Refurbishment of wicket gates• Replacement of wicket gate bushings• Refurbishment of Kaplan servomotors• Refurbishment of throat ring• Refurbishment of discharge and wear rings

An “uprate” in TVA’s program implies the following work items:

• Replacement of runners on all units• Re-insulation of all field poles• Rewinding of approximately 75% of the units• Replacement of core iron on approximately 15% of the units• Improvement of generator cooling and ventilation• Replacement of approximately 30% of generator leads and buses• Replacement of approximately 60% of the main transformers• Replacement of approximately 20% of the generator switchgear

1998 Rehabilitation Benchmarking Survey

An industry benchmarking survey conducted in conjunction with the HydroVision 98 conferenceheld July 1998 in Reno, Nevada, provides a good sampling of general approaches and practicesbeing implemented by hydro owners, primarily in the United States, with regard to plant orcomponent rehabilitation. For purposes of the survey “rehabilitation” was defined with respect to“major powerhouse equipment, its components, and its auxiliaries” as:

“…the restoration of an item(s) on an infrequent basis, through a process ofrepair/modification or replacement, for the purpose of extending life, improvingreliability, and/or reinstating or improving performance. “Rehabilitation” of majorpowerhouse equipment should include such items as: turbine runner replacement orrunner repair/modification where the runner is removed, generator rotor and/or statorrewinds, circuit breaker and governor replacement, and unit transformer rewind orreplacement.” [4]



2-4

The survey had 29 hydro owner or operator respondents from the following countries: UnitedStates (21), Canada (3), Canada/United States (2), Australia (1), Ghana (1), and United Kingdom(1). A total of 66 rehabilitation projects were reported. [4]

The various project components were approved for rehabilitation in the following percentages(rounded to nearest percent):

Turbine runners 74%

Miscellaneous turbine components 69%

Stator windings 60%

Excitation systems 53%

Miscellaneous generator components 47%

Governors 45%

Station auxiliary electrical systems 43%

Data acquisition and control systems 36%

Switchgear/main unit transformers 35%

Generator rotor 33%

Station auxiliary mechanical systems 33%

Electrical leads or bus 31%

Powerhouse bridge/overhead crane 26%

Stator cores 24%

Main unit transformers 22%

Turbine water passage/penstocks 16%

Gains in Capacity and Efficiency

The HydroVision 98 benchmarking survey report indicates significant improvements incapacities and efficiencies resulting from turbine and generator rehabilitations, as follows:

Percent of Projects WithReported Increases

Percent Increase

Average

Percent Increase

Range

Turbine Capacity 42 23.8 1-230

Generator Capacity 29 20.1 1-67

Turbine Efficiency 22 6.1 3-15

Generator Efficiency 3 1.5 1-2



2-5

The benchmarking survey report also presents statistics on the reasons for rehabilitation,strategies employed, economic and prioritization criteria, contracting arrangements, and qualitycontrol and testing methods. [4]

Table 2-2 presents the capacity and efficiency gains realized or expected as a result of therehabilitation and upgrade programs and projects discussed in this report. For three of theprojects, realized or expected annual energy gains (in lieu of efficiency gains) are known and arepresented. The programs and projects for which capacity, efficiency or annual energy gains areknown represent a total of more than 10,000 MW of capacity. The capacity and efficiency gainspresented on Table 2-2 can be summarized as follows:

• The combined capacity gain is approximately 1400 MW, or nearly 14%

• The largest project capacity gain is 325 MW (Robert Moses Niagara)

• The largest capacity gain per unit is 33 MW (Shasta)

• The maximum efficiency gain is 14%

• The average efficiency gain weighted by capacity is 3.2%

The annual average energy gains known are 13%, 23%, and 61%. The 13% annual averageenergy gain is for a large plant (Beauharnois); the 23% and 61% gains are for small plants.

Definitions

Within the hydropower industry, the terms “rehabilitation” and “upgrade” or “upgrading,”among others, are employed to indicate the nature, extent, or result of an improvement to a hydroplant or component. These several terms often appear to be used interchangeably.

Several of these “improvement” terms are defined, as nouns, below. In this report, those termsare intended to have the meanings given, except when the terms appear in the names of specificprograms or projects, or in the titles of papers or articles. No claim is made that the givendefinitions are generally accepted by the industry, nor that the terms are mutually exclusive. Theterms may not have counterparts in non-English languages.

Rehabilitation

The restoration of an old plant, unit, or component through a process of repair, modification, orreplacement, for any of several purposes including extending life, improving reliability, and/orreinstating or improving performance [definition adapted from Hydro Rehabilitation Practices:What’s Working in Rehabilitation]. [4] “Rehabilitation” suggests restoration to a more or less “asnew” condition, improving on the present performance, capability, or reliability but withoutsignificant change or addition of capacity or capability to the original design.



2-6

Upgrade or Upgrading

The substantial modification of an existing plant for any of several purposes including:increasing capacity or efficiency; improving control, safety, reliability, or environmentalcompatibility; or reducing operation or maintenance cost. “Upgrade” suggests achievement ofsignificant improvement in the performance or capability of features or components compared tothe original design.

Modernization

The act or process of making a plant, unit, or component modern in appearance and capabilityusing existing civil structures; particularly refers to installing up-to-date instrumentation andcontrols, and bringing the facility into compliance with current safety and environmentalstandards.

Redevelopment

New construction of an existing plant, including replacement or substantial modification of civil,mechanical, and electrical components [definition from Hydro Rehabilitation Practices: What’sWorking in Rehabilitation]. [4]

Refurbishment

The overhaul or repair of a unit or a component, including replacement of worn or degradedparts.

Replacement

The substitution of a unit or component for another.

Repowering

The replacement of existing units with new units, normally of greater capacity or higherefficiency.

Retrofit

The act or process of providing a unit or component with parts, devices, or equipment notavailable at the time of original manufacture.



2-7

Two additional definitions follow, which are not necessarily considered to be improvementsper se:

Uprating

The designation of an increased capacity rating of a plant, a unit, a turbine, or a generator for anyreason but typically resulting from the addition or improvement of equipment, a change inoperation, or an increase in available flow.

Overhaul

The planned disassembly, cleaning, repair, lubricating, and reassembly of a unit or component.

References

1. Hydropower Plant Modernization Guide. Electric Power Research Institute, Palo Alto,CA: June 1989. Report GS-6419.

2. “EPRI Plans New Guidelines for Plant Life Extension, Modernization,” Hydro Review,November 1998, p. 80.

3. L. D. Chapman, Tennessee Valley Authority, personal communication, October 1998.

4. Hydro Rehabilitation Practices: What’s Working in Rehabilitation. HCI Publications,Kansas City, MO, 1998.



2-8

Table 2-1Rehabilitation and Upgrade Programs and Projects (in order of mention in text)

Program,Project, or

Powerhouse [a]

State (U.S.),Province

(Canada), orCountry

Owner SectionNo(s).

Scope of Program or Project No. ofUnits

MW [b] Status[c]

Cost$million

[d]

Source[e]

HydroModernization *

Tennesseeand severaladjacentstates

Tennessee ValleyAuthority

2,6 variously: runner replacement, otherturbine modification, generatorrewinding, other generatormodification, controls upgrades

88 inprog.

per com

Forbestown * California Oroville-WyandotteIrrigation District

3 runner replacement, other turbinemodification

1 36 comp.1991

0.64 ASCE 93per com

Yale * Washington PacifiCorp 3 runner replacement, other turbinemodification, generator modification,controls upgrade

2 125 comp.1996

ASCE 97

Robert MosesNiagara *

New York New York PowerAuthority


13 2275 inprog.2006

280 HR 4/98

per com

Bennetts Bridge * New York Niagara MohawkPowerCorporation


1 7.5 comp.1990

1.0 ASCE 93per com

Great Falls * SouthCarolina

Duke Power 3 turbine replacement, generatormodification, controls upgrade

2 6 comp.1992

ASCE 93

Stechovice * CzechRepublic

Czech PowerCompany CEZ,a.s.

3 pump-turbine and motor-generatorreplacement

2->1 42 comp.1997

HV paperper com

Muddy Run * Pennsylvania PECO Energy 3,5 impeller-runner replacement, otherpump-turbine modification, controlsupgrade

8 880 comp.1998

40 ASCE 97

HR 4/96

HR 9/98



2-9

Table 2-1Rehabilitation and Upgrade Programs and Projects (in order of mention in text) (continued)

Program,Project, or

Powerhouse [a]

State (U.S.),Province(Canada),

or Country

Owner SectionNo(s).


MW [b] Status[c]

Cost$million

[d]

Source[e]

Rocky Reach * Washington Chelan CountyPUD

3,4 runner replacement, other turbinemodification, generatormodification, controls upgrade

11 1380 inprog.

116 ASCE 97

HR 4/97

John HollisBankhead *

Alabama Alabama PowerCompany


1 46 comp.1998

4 HR 9/98

Chippewa Falls * Wisconsin Northern StatesPower


6 21.6 comp.1995

ASCE 93

HR 11/98

Twin Branch * Indiana American ElectricPower Corporation

3 turbine and generator replacement 6->8 7.3 comp.1992+

ASCE 93per. com

Berrien Springs * Michigan American ElectricPower Corporation

3 turbine and generator replacement 4->12 7.2 comp.1997+

HR 11/98per.com.

Wanapum * Washington Grant County PUD 3 runner replacement, other turbinemodification

10 900 inprog.

75 ASCE 97

Big Creek 1 * California Southern CaliforniaEdison


2 36 comp.1993?

CF

Tafjord K2 * Norway Tafjord PowerCompany

3 runner replacement, controlsupgrade

2 28 comp. 3 CF

Holm * California Hetch HetchyWater and Power


2 150 comp.1993

1.5± H&D 2/98per com

Kirkwood * California Hetch HetchyWater and Power


2 84 comp.1997

1.3 H&D 2/98per com

New Moccasin * California Hetch HetchyWater and Power

3 runner replacement 2 112 inprog.1999

.9expected

H&D 2/98per com



2-10


Program,Project, or

Powerhouse [a]


or Country

Owner SectionNo(s).


MW [b] Status[c]

Cost$million

[d]

Source[e]

Clam River Wisconsin NorthwesternWisconsin ElectricCompany

3 turbine modification in conjunctionwith powerhouse reconstruction

1 comp.1995

0.3+ ASCE 97

Fort Peck No. 1 Montana U.S. Army Corps ofEngineers

3 penstock replacement, flow meterinstallation

3 105 comp.1992

18.5 ASCE 93

Tuxedo * NorthCarolina

Duke Power 3 runner replacement, penstockreplacement

2 5 comp.1991

ASCE 93

unnamed 4 generator rotor modification andrepair

comp. HV paper

Shasta * California U.S. Bureau ofReclamation

4,6 runner replacement, generatorrewinding, other generatormodification

3 328 inprog.

2002+

21 HR 9/98

per. com

Arnprior Ontario Ontario Hydro 4 generator modification for stiffness 2 70 comp.1993

HR 5/95

Lookout Shoals * NorthCarolina

Duke Power 4 replacement of turbine-drivenexciter with generator

2 0 comp.1996

ASCE 97

MajorRehabilitation

Many states U.S. Army Corps ofEngineers

4,5,6 comprehensive rehabilitation,economic evaluation, stator ironreplacement

450+ ASCE 93,95 and 97

HV audio

Porjus Sweden Vattenfall 4 high-voltage generator(prototype test)

1 11+ comp.1998

HR 11/98

HRW 5/98

per com

Bradley Lake Alaska Alaska IndustrialDevelopment andExport Authority

5 governor control reprogramming 4 120 comp.

1993

HR 12/95



2-11


Program,Project, or

Powerhouse [a]


or Country

Owner SectionNo(s).


MW[b]

Status[c]

Cost$million

[d]

Source[e]

Robert S. KerrDam

Oklahoma Grand River DamAuthority

5 controls upgrade, automation 4 114 comp.

1995

0.6 HR 4/96

California WaterProject

California California WaterProject

5 controls upgrade inprog.

1.0+ HR 4/96

Osage Missouri AmerenUE 5 controls upgrade, automation 10 212 comp.

1992

ASCE 93

HR 4/97

per com

Castaic California Los Angeles Dept.of Water & Power

5 controls upgrade 6 1440 comp.? 0.9 HV paper

Trängslet Sweden Stora Power AB 5 new control system 3 330 comp.

1987

1.5 HRW 8/96

Säckingen Germany RheinkraftwerkSäckingen AG

5 controls upgrade, automation 4 80 comp.

1997

17 HRW 9/97

AuxiliaryEquipmentReplacement

Texas Lower ColoradoRiver Authority

5 replacement and modernization ofvarious auxiliary systems

6plants

270 inprog.

1999

ASCE 97

AssetManagement

BritishColumbia

BC Hydro 6 preparation of asset managementplans, identification of improvementopportunities, prioritization ofprojects

9746 ongoing HR 4/98

per com

HydroImprovement

France Electricité deFrance

6 economic evaluation in identifyingand prioritizing rehabilitationprojects

23100 ongoing HRW

winter 95

Jupiá * Brazil CompanhiaEnergética de SãoPaulo

6 to be determined 14 1411 planned HRW 10/96



2-12


Program,Project, or

Powerhouse [a]


or Country

Owner SectionNo(s).


MW[b]

Status[c]

Cost$million

[d]

Source[e]

Hydroelectric LifeExtension

Texas Lower ColoradoRiver Authority

6 economic evaluation ofrehabilitation and upgrade projects,project planning

6plants

270 inprog.

2005+

HR 2/98

per com

Small PlantRehabilitation

NorthCarolina,SouthCarolina

Duke Power 6 project justification andprioritization

inprog.

HV audio

HydroModernization

Severalstates ineastern Mid-west

American ElectricPower Corporation

6 project planning and prioritization 17plants

900+ inprog.

HV audio

per com

Beauharnois * Québec Hydro-Québec 6 variously: runner replacement,generator rewinding, controlsupgrade

38 1666 inprog.

2002+

C1500 HR 12/97

Nine Mile * Washington Washington WaterPower

6 turbine and generator replacement,controls upgrade

2 6.8 comp.

1995?

ASCE 93

Boundary Washington Seattle City Light 6 comprehensive rehabilitation ofentire plant

6 1051 inprog.

2008

88 ASCE 97

Inks * Texas Lower ColoradoRiver Authority

6 runner replacement, generatorrewinding, controls upgrade

1 11.4 comp.

1997

6.4 HR 2/98

Buchanan * Texas Lower ColoradoRiver Authority


2 25 inprog.

1999

11.5 HR 2/98

Austin * Texas Lower ColoradoRiver Authority


2 15.0 comp.

1994

10.4 HR 2/98

Búrfell * Iceland Landsvirkjun 6 partnering, runner replacement,generator modification, controlsupgrade

6 210 inprog.

HV paper



2-13

Table 2-1 Footnotes:

a. Asterisk (*) indicates program or project is listed in Table 2-2 Capacity and Efficiency Improvements

b. Capacity of units rehabilitated or upgraded (or planned to be rehabilitated or upgraded) prior to the work; capacities are presented for comparison and may be nominal values

c. Status noted as follows: planned - planned or scheduledongoing - continuingin. prog. -in progress, year indicates expected completion date, where knowncomp. - completed; year indicates completion date, where known

d. Cost of program or project in US$ unless otherwise noted

e. Sources noted as follows:ASCE (year) - Proceedings of the International Conference on HydropowerCF - Concepts for the Future (1994), HCI PublicationsH&D (issue/year) - Hydropower & DamsHR (month/year) - Hydro ReviewHRW (month or issue/year) – HRWHV paper - paper presented at HydroVision 98 Conference, Reno, NevadaHV audio - audiotape of session at HydroVision 98 Conference, Reno, Nevadaper com - personal communication



2-14

Table 2-2Capacity and Efficiency Impr ovements (in order of decreasing MW pri or to upgra de)

Program o r Pro ject Owner SectionNo(s).

No. ofUnits

Type ofUnits

CapacityPrior

(MW) [a]

CapacityAfter

(MW) [a]

CapacityGain(MW)

Efficien cyGain [b]

Cost$million

[c]

Robert Moses Niagara New York Power Authority 3 13 Francis 2275 2600 325 1-2% 280

Beauharnois Hydro Québec 6 27

11

Francis

propeller

1666 13% [d] C1500

Jupiá Companhia Energética deSão Paulo

6 14 Kaplan 1411 308

(22/unit)

Rocky Reach Public Utility District No. 1of Chelan County

3,4 7

4

Kaplan

propeller

-> Kaplan

1280 1316 36 116

Wanapum Public Utility District No. 2of Grant County

3 10 Kaplan 900 1125 225 75

Muddy Run PECO Energy 3,5 8 pump-turbine

800* 864* 64* 4% pump

4% gen

40

Hydro Modernization

Completed to date:

Total program:

Tennessee ValleyAuthority

2,6

23

88

varies

700+ 850+ 152 5.7%

Shasta U.S. Bureau ofReclamation

4,6 3 Francis 328 426 98 21

Búrfell Landsvirkjun 6 6 Francis 230 300 70 4%

Holm Hetch Hetchy Water andPower

3 2 Pelton 150 169 19 4% 15±

Yale PacifiCorp 3 2 Francis 100* 140* 40* 9%



2-15

Table 2-2Capacity and Efficiency Impr ovements (in order of decreasing MW pri or to upgra de) (continued)


No. ofUnits

Type ofUnits

CapacityPrior

(MW) [a]

CapacityAfter

(MW) [a]

CapacityGain(MW)

Efficien cyGain [b]

Cost$million

[c]New Moccasin Hetch Hetchy Water and

Power3 2 Pelton 112 115 3 1.2%

expected.9

expectedKirkwood Hetch Hetchy Water and

Power3 2 Pelton 84 86 2 2.5% 1.3

John Hollis Bankhead Alabama PowerCompany

3 1 propeller 46* 52* 6* 4

Stechovice Czech Power CompanyCEZ, a.s.

3 2->1 pump-turbine

42 53/50[e]

8

Forbestown Oroville-WyandotteIrrigation District

3 1 Francis 36.3 40.7 4.4 7.1% 0.64

Big Creek 1 Southern CaliforniaEdison Company

3 2 Peltondbl. runner

36 unkwn unkwn 14%

Tafjord K2 Tafjord Power Company 3 2 Pelton 28 34 6 6% 3Buchanan Lower Colorado River

Authority6 2 Kaplan 25 34 9 11.5

Chippewa Falls Northern States PowerCompany

3 24

KaplanKaplan ->propeller

21.6 24+ 2+ 10%

Austin Lower Colorado RiverAuthority

6 2 Kaplan 15.0 17.3 2.3 10.4

Inks Lower Colorado RiverAuthority

6 1 Francis 11.5 14.9 3.4 6.4

Bennetts Bridge Niagara Mohawk PowerCorporation

3 1 Francisdbl. disch.

7.5 9.9 2.4 10.5% 1.0

Twin Branch American Electric PowerCorporation

3 6 ->8 Francis tosemi-Kaplans

7.3 4.8 (2.5) 61% [d]



2-16

Table 2-2Capacity and Efficiency Impr ovements (in order of decreasing MW pri or to upgra de) (continued)


No. ofUnits

Type ofUnits

CapacityPrior

(MW) [a]

CapacityAfter

(MW) [a]

CapacityGain(MW)

Efficien cyGain [b]

Cost$million

[c]

Berrien Springs American Electric PowerCorporation

3 4->12 Francis tosemi-Kaplans

7.2 7.2 0

Nine Mile Washington WaterPower

6 2 Francis

quad-runner

dbl. draft

6.8 20 13.2 23% [d]

Great Falls Duke Power Company 3 2 Francis 6 8 2

Tuxedo Duke Power Company 3 2 Francis 5 8 3

Lookout Shoals Duke Power Company 4 2 Francis 0 0.8 0.8

Totals (approxi mate) 175 10,300 1400

Table 2-2 Footnotes:

a. Capacity (MW) values do not necessarily represent official plant or unit ratings and should be considered “nominal;” capacity (MW) values given are known or understood torepresent maximum output, except that values noted with an asterisk (*) are known to represent best efficiency output

b. Nominal improvement in maximum (best gate) efficiency except as noted; see [d]

c. Cost of program or project in US$ unless otherwise noted

d. Improvement in annual generation

e. Pump input/turbine output


3-1

3 TURBINES AND PUMP-TURBINES

Many very old hydroturbines are still operating; some of them are more than 100 years old, andsome are virtually unchanged from the originals. Large, reversible pump-turbines first installedin the United States in the 1960s were of relatively primitive design, reflecting the developingtechnology at that time. Most hydro plant rehabilitation and upgrade projects involve the turbines(or pump-turbines) and result in significant improvements in capacity, efficiency, and reliability.

Planning for Turbine Rehabilitation or Upgrade

The scope of a program for turbine (or pump-turbine) rehabilitation or upgrade would normallyinclude: [1]

• Development of specifications

• Specification solicitation

• Bid evaluation

• Award

• Procurement of new equipment

• Disassembly of existing equipment

• Installation of new components

• Re-assembly

• Equipment acceptance testing

• Commercial operation

Existing turbines should be thoroughly tested prior to developing a specification forrehabilitation; such testing should include measurement of: [1]

• Turbine shaft runout

• Head cover vibration

• Wicket gate and gate mechanism vibration

• Guide and thrust bearing temperatures

• Hydraulic performance characteristics determined by index testing



3-2

Visual inspection of the following components and areas of the existing turbines isrecommended: [1]

• Cavitation areas, specifically the runner and the throat or discharge ring

• All water passage surfaces, for surface cracks

• Wicket gate and gate operating linkage clearances

• Rotating and stationary wearing ring clearances

• Main shaft packing box and wicket gate stem packing condition

• Main shaft guide bearing clearances

Model and Acceptance Testing

Homologous model testing is generally recommend for the replacement of turbine runners inlarge turbines or for plants that have numerous identical turbines. While the cost of homologoustesting is high (typically many hundreds of thousands of dollars, or more) small gains inefficiency resulting from model testing will justify the cost of the test where the involvedcapacity is large. EPRI’s Guide for Hydraulic Machinery Model Testing may be a usefulreference. [2]

There are several, alternative approaches to model testing: (1) partnering, where the prototypeguarantee output and efficiency are selected from observation of the manufacturer’s model test;(2) competitive model testing, where the proposed designs of two or more manufacturers aretested and compared at an independent laboratory; and (3) comparative model testing, where amodel of the existing turbine and a model of a new or upgraded turbine are tested at the modeltest stand under the same conditions to ascertain the probable improvement. [3]

Competitive model testing has been used by several major hydro owners. For large installations,competitive model testing can sharpen competition. EPRI’s manual The Value of CompetitiveModel Testing in the Bid Evaluation Process for Hydroelectric Turbomachinery provides anextensive discussion and analysis of competitive model testing. [4]

Several major hydro owners have a policy to conduct absolute efficiency tests to determine theacceptance of rehabilitated, upgraded, or new turbines. Such tests are often problematic becauseaccurate water flow measurement is required. [5,6] It is difficult to perform a code-compliant testin the field. The Tennessee Valley Authority is working with its turbine manufacturing partner totry to resolve this problem. [5]

Ontario Hydro requires acceptance tests using the Gibson or the current meter method,depending on the site. The accuracy of these tests is considered to be +2%. [7]

The New York Power Authority (NYPA) is upgrading all thirteen units at its Robert MosesNiagara Power Plant. NYPA retains the option to test any and all upgraded turbines foracceptance using ultrasonic flowmeters. The turbine supply contract provides that penalties maybe assessed against the supplier for failure of a turbine to meet the performance guarantees.NYPA is also required to test the performance of each upgraded turbine using Gibson and/orindex testing methods; the purpose of these tests is to develop rating tables to determine thedivision of Niagara River flow between NYPA and Ontario Hydro. [8]



3-3

Model testing and prototype acceptance testing are performed under the test codes of theInternational Electrotechnical Commission (IEC) or the American Society of MechanicalEngineers. [9]

Computational Fluid Dynamics (CFD)

CFD is finding more applications in the design of new Francis turbines and pump-turbines toinvestigate flow conditions and to improve flow characteristics in lieu of, prior to, or inconjunction with physical model testing. CFD has been used to simulate and analyze flow inturbine rehabilitation projects, in order to identify opportunities for improving wicket gate andstay vane shapes, for example. Excellent results can be obtained by working CFD together withmodel tests. In a case of a propeller unit upgrade, where (as is typical) draft tube geometrycannot be modified and draft tube losses are a significant part of overall turbine efficiency,numerical analysis can simulate the interaction of the runner and draft tube so as to develop arunner design with maximum efficiency at the correct flow. CFD can accurately predict thepower output of a new runner installed in an existing turbine. However, CFD is limited in itsability to predict performance of the turbine or pump-turbine. Where absolute efficiency isrequired, physical model testing is necessary. The question of whether CFD will eventuallyreplace physical model testing has been raised. [10]

Reaction Turbines

Francis Turbines and Pump-Turbines

Very old turbines are relatively inefficient due to their design. In particular, relatively littleattention was paid to avoiding head loss in water passageways in early plants. Unfortunately,correcting or rebuilding waterways (intakes, penstocks, spiral cases, and draft tubes) is often notcost-effective, so an upgraded unit must frequently be placed in a less than ideal setting. Runnersettings are often too high by modern standards, resulting in excessive cavitation.

In Francis runners, efficiency improvements can often be obtained by reshaping (grinding)runner vane edges. Cutting back runner tips can also increase the runner vent area, admittingmore flow. For existing runners, restoration of runner vane surfaces to original shape can providea dramatic improvement in performance and power; cavitation repairs (overlays) over the life ofthe units can in some instances significantly choke the runner. Frequently, templates of theoriginal runner vane contours no longer exist.

Solving Draft Tube Hydraulic Instability in a High-head Turbine Upgrade

Control of air flow to the draft tube can be an important consideration in a turbine upgrade. TheOroville-Wyandotte Irrigation District’s Forbestown Powerhouse, in California, contains asingle, Francis unit under almost 800 ft (250 m) of net head. The unit was placed into operationin 1963. The upgrade began in 1989 with the installation of a new runner. The new runner didnot meet the efficiency guarantee and experienced hydraulic instability in the draft tube at lowloads, causing rough operation. Air venting through the 6-in. (15-cm) opening in the hollow shaft



3-4

smoothed operation at all loads but reduced power and efficiency. A redesigned nose cone failedto stabilize the draft tube swirl. The hollow shaft was then plugged with a steel plate having a2-in. (5-cm) opening; this admitted sufficient air to stabilize the flow without reducing power orefficiency. Finally, in 1991, the original, mild steel wicket gates were replaced with new stainlesssteel gates of the original design; the original gates were badly eroded and the surfaces distorteddue to welding and grinding. The results of the entire upgrade were that maximum turbine output(in MW equivalents) increased to 40.7 MW from 36.3 MW and peak turbine efficiency increasedto 91.4% from 84.3%. Turbine output was determined by assumed generator efficiency. [11,12]

Pump-Turbine Design

The design of pump-turbines is a more complex process than the design of conventional,one-way Francis turbines. Pump-turbines should be designed with special attention to meetingthe demands of the system. It is essential to combine computer design techniques withhomologous model tests. There are significant conflicts in designing for good performance inboth turbine and pump modes. The challenge frequently is to maximize turbine power asconstrained by motor capacity. Design technique involves special contouring at the blade pumpinlet. Maximum pumping head is higher than maximum turbine head, due to hydraulic losses;suitable blade angles for high pump head cause inefficiencies in turbining, particularly at lowheads. Cavitation in turbining does not normally limit the design, but cavitation is critical at highhead pumping and will affect the blade angles. It is necessary to compensate for fluid-structureinteractions, including penstock pressure rise under full load rejection. Wicket gate vibrationscan be caused by runner pressure pulsations causing resonance; a close gap between wicket gatesand the runner exacerbates this problem. Within these constraints, the designer has some leewayto favor turbine vs. pump performance, or high power vs. high efficiency. [13]

Medium-Sized Plant Upgraded for Capacity

PacifiCorp’s Yale Project, located in Washington State, was a “bottleneck” on its river system.The plant has two Francis units. Output was limited by the turbines to 67 MW; the generatorswere rated at 73 MW. The turbine runners were upgraded to match the generator output. Theowner specified certain efficiencies and capacities to be guaranteed. No model test wasperformed. The upgrade consisted of: replacing the runners with new runners designed byinteractive computer, with lengthened runner bands; modifying stationary wheelcasecomponents; removing and replacing the discharge ring; re-machining the stationary seal rings;re-babbitting and modifying bearing shoes for a new high pressure oil lift system; replacingpacking; refurbishing servomotors; rebuilding bearing oil pumps; re-tubing oil coolers;cleaning/painting generator stator and rotor; upgrading the plant busbar; testing generatorcomponents; replacing insulation; installing new solid-state excitation, electronic speed sensors,and a new PLC control system; and rebuilding breakers. Comparison of the results of indextesting of the upgraded units and the original units indicated an efficiency improvement of about9% at the best efficiency point. The capacity at best efficiency point was increased by over20 MW. [14]



3-5

Large Conventional Plant Upgraded for Capacity

The New York Power Authority (NYPA) is upgrading the 13 Francis units at the Robert MosesNiagara Power Plant. Five units have been upgraded, and the sixth is in progress. NYPA plans tocomplete one unit each year unit all units have been upgraded. The original maximum output ofeach unit was 175 MW at a head of 300 ft (90 m). Earlier studies suggested that output for peakpurposes could be increased by 15 per cent. The main objective was to achieve a significantcapacity increase while balancing among efficiency, output, and cost. NYPA’s special concernwas to maintain efficiency, since the plant provides 10% of the electricity consumed in NewYork State; analysis indicated that a 1% decline in plant efficiency would cost $100 million.[8,15]

NYPA’s upgrade program calls for new runners, modifications to draft tube liners, increasedwicket gate stroke, upgrade of generators and cooling systems, replacement of transformers, andimprovements to other electrical equipment. The generator stators had been rewound in 1980s;the current program includes new field poles on some generators, increasing capacity ofventilation systems, and new stator air coolers and bearing heat exchangers. The originalexcitation system was replaced with digital solid static exciters. Penstocks and scroll cases arebeing repainted. The work scope varies slightly from unit to unit depending on each machine’sspecifications and condition, and problems discovered after disassembly. [15]

NYPA determined to select the turbine manufacturer on the basis of competitive model testingand to pay for the modeling costs of competitive finalists. NYPA established a series of“checkpoints” at which project economics would be re-evaluated before proceeding further.NYPA’s specifications, issued in 1988, allowed turbine manufacturers to propose a replacementrunner with best gate between 168 MW and 183 MW. Bids would be established using NYPA’s“Niagara Project Simulation Model” that simulates the Robert Moses plant’s hourly operation.NYPA modified the simulation model program for use on a personal computer (PC) and gavethe program to manufacturer-bidders for their use in preparing proposals and evaluatingguarantees. Six bids were received in the initial round. Based largely on price and the economicvalue estimated by the simulation, NYPA selected two manufacturers for the competitivemodel test. [15]

An independent laboratory was chosen to test the competing manufacturers’ model turbines. Theindependent laboratory fabricated a homologous model of the intake, penstock, spiral case, stayring, and draft tube. The intake and penstock were included in the model to accurately defineflow conditions entering the turbine because model performance guarantees were based upon theactual inflow conditions to the units. The independent laboratory also built and tested a model ofthe existing turbines for comparison. Testing included: efficiency over a large net head range;wicket-gate torque, including torque with one gate unrestrained; cavitation; hydraulic thrust;runaway speed; pressure pulsations in the penstock, spiral case and draft tube; and shaft torquefluctuations. [8,15]

In 1991, the first turbine was upgraded and tested extensively before a decision was made toproceed with upgrading additional turbines. Absolute efficiency was measured employingfour-path, two plane acoustic flowmeters that had been installed in 1988 for on-line efficiencymonitoring. The upgraded turbines installed to date have efficiencies 1-2% higher than originalmachines and capacities nearly 30 MW higher at the best efficiency points. Inspection of the first



3-6

upgraded unit has shown virtually no cavitation after five years of operation. [15] The turbineand generator ratings of the upgraded units are 200 MW and 215 MVA, respectively. By 2006,NYPA expects to have spent about $280 million upgrading all thirteen units at the Robert Mosesplant. [16]

Upgrading a Small, Old Unit

Unit 2 at Niagara Mohawk Power Corporation’s (NMPC) Bennetts Bridge Hydro Developmentin New York State is a 7.2-MW, horizontal Francis, double discharge turbine with a direct-connected synchronous generator, 1914 vintage, subsequently converted from a frequency of25 Hz to 60 Hz. By the early 1990s, the severely pitted, cracked condition of the runner andseveral other deficiencies in the turbine and generator led to a decision to upgrade the unit. Theprincipal goal was to extend life, but it was hoped also to increase capacity and efficiency. Thestator had been last rewound 20 years ago, and the generator was in need of completerefurbishment. The governor and spiral case were good condition, and the significant leakagethrough wicket gates was not a major concern since minimum downstream flow was needed inany case for the fishery.

Upgrading the turbine consisted of replacing the runner, turbine shaft, wicket gate bushings, andlinkage. Wicket gates and operating ring, governor regulating shafts, packing collars, connectingrod pins, and turbine bearings were refurbished. The new runner had more and longer buckets,and a larger discharge area than the original. The head cover and bottom ring were modified.Replacement of the turbine shaft was necessary to accept the higher horsepower loading of thenew runner. The maximum capacity increased from 7.5 MW to 9.9 MW, and the efficiency atbest gate increased by over 10%.

A few problems that arose during the Unit 2 work are noteworthy. Rebuilding of the distributorwas attempted in the field, but fitting problems led to parts being shipped to the manufacturer’sshop for rework. For the subsequent units, fit-up problems were avoided by performing thedistributor work in the manufacturer’s shop in the first place. A problem with the Unit 2 workwas how to handle the 32-ton (29,000-kg) flywheel; ultimately it was blocked in place andpresented no major problem in reassembly. A piece broke from one of Unit 2’s draft tube elbowsduring disassembly when the elbow, with a bolt left in the mounting flange, was lifted by acrane. A metal-stitching process was used to rejoin the broken piece to the body of the elbow.

The success with the work on Unit 2 led to rehabilitating and upgrading the other three units atBennetts Bridge. The four unit upgrades at Bennetts Bridge resulted in an average capacityincrease of over 33% and an average efficiency increase of over 6%.

NMPC served as the general contractor for all the Bennetts Bridge upgrades and for similarrehabilitation and upgrade projects at other plants. Separate contracts were let for the turbine andthe generator work. The arrangement was satisfactory, although there were occasional instancesof forces called to other jobs, with minor schedule effects. Subsequent downsizing of thecompany’s workforce has reduced NMPC’s ability to complete rehabilitations in a timelymanner while performing normal maintenance activities; consequently, some current jobs arebeing bid out. [17,18]



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Cylinder Gates

In considering upgrading two 3-MW Francis units at its Great Falls plant, Duke Power evaluatedreplacing the existing cylinder gates with more efficient wicket gates. However, conversion towicket gates would have required considerable concrete excavation and could not be justified.Installation of new turbines with cylinder gates was chosen over unit retirement or new unitswith wicket gates. The generator insulation was upgraded, and improved controls were installed.Unit output increased to 4 MW. [19]

Two Pumped Storage Plant Upgrades

The redevelopment of the 42-MW, 210-m head Stechovice Pumped Storage Plant in the CzechRepublic raised the capacity to 50 MW and increased efficiency. One unit (with a single-stagepump-turbine) replaced two units (each with a two-stage pump and turbine on a common shaft),with a drastic increase of submergence to minimize cavitation. This resulted in the need for anunusual, S-shaped pump suction/turbine draft tube. The two original 1.7-m diameter penstockswere joined into a new 2.2-m diameter penstock at approximately the level of the turbinedistributors of the former units. Extensive transient studies indicated the need for a surge tank inthe upper penstock. Ecological requirements included self lubricated housings for the wicketgates and gate operating mechanism, exhaustion of oil vapors from bearings, installation of oilleakage sensors, all stainless water piping, and asbestos-free sealing materials.

Extensive model tests were conducted on the new pump-turbine. The entire S-tube was includedin the homologous hydraulic model because the manufacturer’s performance guarantee includedlosses in the S-tube. Higher than normal values of pressure pulsation occurred in the S-tubeduring low load model turbine operation (below 70%); low-load operation was important to theowner. An air injection solution appeared uneconomic. The solution was the addition of fins inthe S-tube combined with natural air admission. A no-cavitation condition was confirmed by thetests.

A field acceptance test was conducted by an independent contractor. Discharge was measured bypropeller meters in both of the upper penstocks; the accuracy of the prototype flow measurementby propeller meter is considered to be 1.2%. All efficiency guarantees were met. Atcommissioning, problems with rough pressure pulsations and rotor vibrations occurred in thesynchronous condensing operating mode. The solution was to decrease cooling water dischargeto the runner/impeller seals and to open the connecting pipe between the suction cone and thespiral case. Condensing operation is now satisfactory in both directions.

The Stechovice acceptance tests showed significant shifting of the flow and power vs. headrelationships in the pumping mode (some 2-3% greater discharge and power at the same head inthe operating range) than predicted by International Electrotechnical Commission (IEC) 995.[20] This could be a potential problem for the motor-generator if proper allowance is not made.This phenomenon has been observed at other pumped storage plants in the Czech Republic.Other formulae for converting model-to-prototype performance have been developed from modeland field acceptance tests of pump-turbines and are being proposed. [21,22]



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PECO Energy has upgraded the eight pump-turbines (rated 110 MW as turbines) and the plantcontrols at the Muddy Run Pumped Storage Plant, in Pennsylvania. The impeller-runners werereplaced by a new design. The average cycle efficiency has increased by approximately 10%.The project also included replacing the unit main bus, installing static exciters, and upgrading therelay protection system. The project cost was about $40 million. [23]

The Muddy Run impeller-runner vendor was selected by competitive model testing. The ownerspecified how relative value of the rehabilitated pump-turbines would be calculated. [24]

At the start of the job, the anticipated pump-turbine upgrade was limited to impeller-runner andwicket gate replacement; in the end, the head covers, bottom ring, turbine bearing, and bearinghousing all were replaced. Self-lubricating bushings were installed. The runner-impeller crownand band were cast stainless steel, with integral machined upper and lower seals. The bucketswere formed from stainless plate. New, reshaped stainless wicket gates were installed. Thewearing rings were replaced with a labyrinth style. The new head covers provided more rigidityin the bearing housing area; the bearing was lowered for stiffness and is of a new type, allowingeasier access and adjustment. The stay ring was modified for stress reduction. Before-and-afterindex and capacity tests were performed. The upgrade achieved an increase of 4% in pumpingefficiency, a decrease of 3.5% in pumping power, an increase of 4% in turbine efficiency, and anincrease of 8 MW in output at the best efficiency point. [25]

Fixed - Blade Propeller and Kaplan Turbines

Major Plant Upgrade - Kaplan Units

Upgrading the Rocky Reach Plant on the Columbia River in Washington State includes replacingthe runners of all 11 original turbines. The original Units 1-7 turbines were six-bladed Kaplanunits rated at 140,000 hp (104 MW); the original Units 8-11 turbines were five-bladed fixed-blade propeller units rated at 177,000 hp (132 MW). All major components will be replaced,rehabilitated, or upgraded. Transformers, generator breakers, and excitation systems are beingreplaced.

The new Units 1-7 runners are six-bladed Kaplan runners. The blades are stainless, with settingand diameter unchanged. The discharge rings are being overlaid and restored to shape. Thrustbearings are being modified for adequacy under the most adverse operating conditions expected.Generator stator sole plates are being replaced, governor systems refurbished, main pumpsreplaced, the volumes of oil sump and accumulator tanks increased, and regulator and unitcontrols replaced with modern digital technology.

Emphasis in the upgrade is on protection for fish, particularly downstream-migrating juvenilesalmon. Most fish pass through Units 1-3, so these units will be last of Units 1-7 to be upgraded,in order to allow application of the latest “fish friendly” technology. The upgraded Units1-7 turbines were first modeled as standard Kaplans, then remodeled to test a number of fish-friendly features such as closure of hub-blade gaps by a spherical inner blade surface adjoiningthe hub, and matching pockets in the upper cylindrical part of the hub. Attempts were made tosimulate fish movement in the 1:20-scale model using inert plastic particles of slightly lighterthan water materials. [26] Tests of the first unit upgraded indicated a fish mortality rate of only5% compared to the estimated 15% historical rate at Rocky Reach. [27]



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Units 8-11 will have new five-bladed Kaplan runners. Shaft systems will be modified to permitblade control. Stay vanes will be modified, distributors refurbished, new greaseless bushingsinstalled, and discharge rings replaced with larger diameter, stainless steel rings affording alower runner setting. Other work will include replacement of generator stators, thrust bearings,and governor oil systems, and the installation of new digital governors and PLC controls.

The diameters of the Units 8-11 runners will be increased by 5%, and a semi-spherical dischargering will be installed. The runner chamber will be redesigned. The runner will have a fullyspherical upper hub surface. A power increase of 15% is expected. Opening tendency for theblades at all operating conditions is required. The Units 8-11 turbine work was sole-sourced tothe manufacturer of Units 1-7 for practicality and continuity. An independent confirmation of themanufacturer’s model test results will be required. Further work was done to increase efficiencyat full load. CFD analysis led to model testing of stay vane modification. A difficult constructionwill be the tapered extension of the lower head cover to match the top diameter of the hub of thenew runner.

The Units 8-11 runner blades will be single-piece castings each weighing 14 tons; a disadvantageof the single-piece castings is that the runner must be disassembled for shipment to the site. Anew governor system, with higher oil pressures and new servomotors, will be installed. Wicketgates and operating mechanisms will be reused. All bushings will be greaseless. A digitalgovernor and PLC system for unit controls will be installed. Thrust and guide bearings willbe replaced for increased weight and thrust. Removal of the imbedded discharge ring andre-imbedment of a new discharge ring and associated parts will be challenging. To minimizeoutage time, work is planned to occur simultaneously at the draft tube, the turbine and thegenerator levels of the units. [26]

Upgrading a Medium-Sized Propeller Turbine

Alabama Power Company upgraded the single unit at its John Hollis Bankhead Plant. Thesix-bladed propeller runner and the discharge liner were replaced. The wicket gates andservomotors were refurbished. The rated capacity increased from about 46 MW to over 52 MW.The upgrade project cost about $4 million. [28]

Rehabilitation of Small Propeller Turbines

The expense of homologous model testing cannot normally be justified for runner replacementsat small plants. Northern States Power’s Chippewa Falls Plant in Wisconsin had six 3-MWKaplan units, each with an antiquated water passage design. Proposals were obtained frommanufacturers for six new runners that were identical in shape; two of the runners would beKaplans and four would be fixed-blade propellers. The manufacturers provided guaranteedefficiencies based on test results from their “closest” models. The known efficiency of a giventurbine design that has been modeled can be adjusted, within limits, in accordance with thedifferences in model-to-prototype features; e.g., wicket gate height, wicket gate pin circlediameter, stay vanes, intake, draft tube, and runner centerline elevation. The changes inefficiency can be estimated by calculating relative head losses or by the results of model tests ofalternative designs, if available. The manufacturers’ adjustments to the performances of their



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respective models could be verified for reasonableness based upon the model-to-prototypedifferences. The most competitive manufacturers proposed to perform a limited model test of thenew runner and wheelcase with the existing draft tube, in order to demonstrate efficiency prior tomanufacture of the prototypes. In this way, the owner was reasonably assured of a good designand could evaluate bid prices based on expected performance. Also, the two Kaplan units weremanufactured first so that index testing could establish the optimum blade angle for the fourfixed-blade propeller units. [29] The plant is currently rated at 24 MW. [27]

Submersible Replacement Units

American Electric Power (AEP) has installed a total of 20 submersible, adjustable-blade,semi-Kaplan units with cylinder gates, at two old plants. At the Twin Branch Plant in Indiana,AEP replaced six multi-runner, open flume units with eight submersible units. The submersibleunits were selected from among proposals offering a variety of units on the basis of the followingevaluation criteria: minimizing structural modification and need for cofferdams, optimizing useof standard components, simplifying maintenance procedures and access, and optimizing controlof unit operations. The cofferdam required with several options was a critical cost factor. Theadditional efficiency of double-regulated units could not be justified economically; single on-offcontrols provided the best return on investment. The choice of submersibles allowed phasedinstallation, delaying replacement of some units. The scope of supply included the turbine-generators, turbine seats, conical draft tubes, cylinder gates, hydraulic gate activators,accessories, and spare parts. The generators are 600-kW induction types; the use of inductiongenerators required consideration of plant location and capacity with respect to the bulk powersystem. The turbines have planetary speed increasers to match the generator speeds.

The arrangement of two submersible units per bay was tested in a hydraulic model. With theaddition of flow deflector plates behind each cylinder gate, the model indicated good hydraulicswithout modification of the flumes. The main advantages of the submersible units are simplicityand ease of installation; total installation was from above, eliminating the need for cofferdams.The capacity rating of the Twin Branch plant decreased from 7.3 MW to 4.8 MW, but energyproduction increased significantly. [30]

AEP performed a similar upgrade at its Berrien Springs Plant, in Michigan. Twelve 600-kWsubmersible units identical to the Twin Branch replacement units replaced four open-flume,Francis camel-back units with quad runners, with essentially no change in plant capacity. Fishmortality was a concern at Berrien Springs; AEP estimates that the upgraded plant has resulted ina 4 to 5% reduction in mortality, due to the greater distance between runner blades and thereduced plant hydraulic discharge. [27]

Upgrading Large Turbines for Fish-Friendliness

The development of “fish friendly” hydroturbines is proceeding under the joint sponsorship ofthe U.S. Department of Energy, several industry sponsors, and EPRI. Some owners of majorhydro facilities are incorporating “fish friendly” features into designs of replacement units. NewKaplan turbine designs are incorporating features such as smaller clearances, spherical dischargering surfaces, and spherical surfaces at the blade-hub interface (created by pockets in the hub) to



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reduce fish mortality; the hub pockets tend to cause undesirable hydraulic disturbances, however.Wicket gate clearance and configuration relative to the bottom ring in propeller units can bedesigned to reduce fish mortality. An example is the Public Utility District No. 2 of GrantCounty’s Wanapum Project on the Columbia River in Washington State. The design of theKaplan replacement runners being installed at Wanapum includes hub pockets, and the designwas changed from five to six blades in order to reduce the disturbance at the pockets toacceptable levels. The wicket gates were matched to the stay vanes to reduce obstacles andimprove flow characteristics, as well as to reduce the potential for fish strikes. In general,minimizing cavitation also enhances the survival of fish passing through a turbine. [31]

Reaction Turbines - Common Elements

Draft Tubes

Poor draft tube performance is normally of the most concern in optimizing the performance of anupgraded reaction turbine. The most difficult situations involve old, Francis double-runnerdesigns with draft tubes having flow mergers and tight curves. Flow decelerates (expands) in thedraft tube, and the hydraulic problems are exacerbated by sharp turns and irregularities. Newcomputer tools for dealing with draft tube hydraulics are being developed. [32]

Vibration and Resonance

Modern runners are designed and fabricated to eliminate hydraulic and mechanical imbalance.When a new runner causes vibration, resonance is almost always present. Examples arepowerhouse structural vibrations resulting from a change in runner speed or number of blades,penstock vibrations resulting from amplification of the blade pass frequency or from draft tubepressure pulsations, self-excited pressure pulsations in the runner clearance area produced by theseal design, and pounding on the draft tube wall by the runner-produced draft tube vortex. Thereare many modes of vibration. Solutions can be as simple as “de-tuning” a structure by stiffeningits support. Vibrations caused by the draft tube vortex are most difficult to correct; predictivecapabilities are not available for use in design. Treating the problem will require a means ofpredicting flow phenomena in the entire system, including penstocks. [32]

Impulse (Pelton) Turbines

Most impulse turbines are of the Pelton type. Since all impulse turbines referred to by sourcesused for this report are believed to be of the Pelton type, “Pelton” will be used hereinafter.

In Pelton turbine upgrades, a careful examination of the existing design is needed. Poor designsare evident in cracking of buckets and deficient performance. The most important designconsiderations are in the wheel. Design considerations are:

• Proper layout

• Optimum combination of speed, pitch circle diameter (PCD), and net head

• Optimum bucket size



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• Correct inlet position and outlet angles

• Turbine housing space and baffle plate arrangement

• For two-jet turbines, optimum angle between jets

Old Pelton runners often have bolt-on buckets and poor inlet hydraulics. Wear and tear reducesefficiency. A common problem is too high speed as a result of frequency change; runner speedgreatly changes efficiency. The runner design compromises between structural and hydraulicdesigns. Many Pelton wheels must tolerate frequent load cycles.

The rotation of discharge water due to too small a ratio of PCD to bucket size loses efficiency.Turbine housing is critical, especially for horizontal turbines. Space is needed, especially at theupstream end of the housing, so that water (highly aerated) can effectively escape the wheel anddrain to the pit. Proper baffle plate design prevents interference of the discharge water with therunner and the jet. Too close placement of nozzles with respect to the runner circumferencecauses interference. An increase of nozzle spacing from 55° to 75° for a two-jet unit greatlyincreased efficiency. At the Big Creek No. 1 Powerhouse, in California, two double, single-nozzle, Pelton units were upgraded with new runners and replacement nozzles. The PCDs werereduced by 8 in to optimize conditions at the rated net head and speed. The turbine housingswere widened and extended on the upstream end for drainage. The governors had to be relocated.Special baffles were installed in the housings. The efficiency at best power increased by about14%, and the best efficiency point occurred at a higher output. [33]

Upgrading Pelton turbines can often be economic. Most vertical impulse units have peakefficiencies at 65% of full load. Old machines often have lower speeds and larger buckets thanmodern design. Also, bucket shapes often become distorted after years of repair, withouttemplates or experienced personnel. This points to new runners. Commissioning tests of originalequipment often indicate efficiencies higher than supported by runner model performance; thismeans that gains from replacement runners will be greater than expected based on comparisonwith the “tested” performance of existing runners when first commissioned. Older units tend tobe robust (conservative design); this often allows an uprating without changing components dueto size or stress. [34]

A checklist for Pelton turbine upgrades is: [34]

• Turbine/generator shafting and coupling limits

• Needle servomotor design and limits

• Needle and nozzle seat enlargement limits

• Spiral distributor sizing

• Runner pit sizing and venting

• Waterway sizing

• Existing versus upgraded nozzle water speed

Note: increasing turbine discharge will reduce net head, causing a rise in the “phi” ratio ofPCD to nozzle velocity; this can often be beneficial to efficiency.



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• Runner and bucket sizing

• Needle imbalance

• Overspeed, deflectors and governor changes

Note: the position of the deflector must be considered if the jet is enlarged.

• Runner stresses

Upgrading Small Pelton Units

The Tafjord K2 Plant in Norway has two, double-horizontal, two-jet Pelton turbines, ratedoriginally at 14 MW at 375 m net head. Upgrade of the plant involved: replacement of theoriginal bolt-on bucket runners with new stainless monocast runners, with a slight adjustment ofPCD; new shafts redesigned for a more suitable coupling arrangement; increased angle betweenthe jets; new housings; overhaul of gate-type penstock-operated inlet valves; new controlequipment; new, high pressure, digital governor systems; and refurbishment of othercomponents. The output of each unit was raised to 17 MW, and efficiencies increased by about6%. The total cost was about US$3 million. [33]

Pelton Turbine Upgrade Program

Hetch Hetchy Water and Power (HHW&P) has undertaken a program to modernize seven Peltonturbines (all 6-jet vertical machines) in three powerhouses in California. In the HolmPowerhouse, new runners and jet protectors have been installed on the two units, raising the unitratings from about 75 MW to 88 MW. Turbine jet diameters were enlarged by 6%. Based onoriginal commissioning (Gibson) tests, runner replacement could not be justified. Recent testsusing acoustical flowmeters indicated otherwise, however. The purchase order for the new unitswas set to performance at high load, with potential liquidated damages based on performance toassure a favorable project benefit to cost ratio. The expected payback period is less than threeyears at a cost of about $80 per kW.

HHW&P’s Kirkwood Powerhouse has three units. Two were originally installed in 1964. Thethird was added in the late 1980s with the requirement that the runners of all three units beinterchangeable, thus foregoing advantages of state-of-the-art design. The units recently operateat maximum flow about four months of year; this has increased erosion. Two replacementrunners have been installed with nozzle enlargements showing advantages.

Due to foundation problems, rehabilitation of HHW&P’s New Moccasin Plant includesconstruction of a new powerhouse. Each of the two units has its own penstock, with full load lossequal to 12% of head. The units are often equally loaded to reduce head loss, but this is at less-than ideal loads, well below peak efficiency. There is no advantage to nozzle enlargement due tolow load factors. Two new runners will be supplied, possibly to be combined with a project toreduce penstock friction losses. After that, to take advantage of higher head, modification ofoperating speed will be considered to better match rpm and nozzle velocity. [6,34]



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Civil Works Improvements in Conjunction with Turbine Upgrades

At older hydro plants, the rehabilitation or upgrade of civil works, including structures,waterways and related equipment, is most often performed to increase project safety, preventsevere failure, or reduce operating or maintenance cost. Major civil works improvements areusually costly and often have environmental and licensing implications. However, some civilworks improvements, particularly those that involve waterways, can complement turbinerehabilitations and upgrades. In any turbine upgrade, the competency of conduits, valves, andtrashracks under the new flow and pressure conditions must be examined.

Rehabilitation of a Powerhouse Resulting in Improved Turbine

The Unit 3 powerhouse at Northwestern Wisconsin Electric Company’s Clam River project hadbeen added to the original powerhouse in an existing spillway bay in 1967. The Unit 3powerhouse suffered severe substructure cracking and movements; in 1988, Unit 3 was taken outof service for safety reasons. Lack of original construction drawings was a hindrance inevaluating a course of action. Demolition and replacement of the Unit 3 powerhouse wasconsidered. A team approach among the owner, engineer, and construction contractor led to an insitu reinforcement and stabilization plan. The problem was poor substructure concrete on afoundation of compacted silt. The rehabilitation essentially consisted of construction of astructural liner in the turbine pit and reinforcement of the draft tube to support and transfer loadsto the foundation. Included were reshaping of the turbine pit and draft tube to improve hydraulicefficiency; corners were rounded, and U.S. Army Corps of Engineers standards for draft tubedesign were applied. Minor adjustment of the draft tube geometry was made in the field. Ananalysis indicated that temporary bracing would not be required for the construction, thusreducing cost and saving time. The adjacent units continued to operate during construction. [35]

Replacement of Penstocks to Improve Turbine Performance

The penstocks at the U.S. Army Corps of Engineers’ Fort Peck Power Plant No. 1 in Montanawere replaced in 1990-92. Power Plant No. 1 had been placed in service in 1943. Among theseveral purposes of the penstock replacement was to increase plant capacity by increasing flowefficiency. Power Plant No. 1 consists of a low-level intake, a reinforced concrete tunnel750 m long, a surge tank, a riveted steel pressure tunnel 1000 m long trifurcating into threepenstocks, and three Francis turbines and their generators. Each of the penstocks has a surgetank. The units were uprated to their present ratings of 43.5 MW, 18.2 MW, and 43.5 MW in themid 1970s.

Following the uprating of the units, computer model studies indicated that the penstock surgetanks could be overtopped; this led to discharge and loading rate restrictions. Restriction of thesurge tank orifices was considered, but the penstocks first had to be tested for increasedpressures. For a variety of reasons, the penstocks were found inadequate. In 1981, a consultantrecommended that full head operation of the plant could best be achieved by restriction of thesurge tank riser orifices and replacement of the penstocks. In 1989, planning to replace thepenstocks began. In 1990, the plant was taken out of service when settlement readings indicatedan intolerably low safety factor for the penstock rivets. It was decided to replace the unit



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isolation valves as well and to make the small unit’s penstock the same diameter as the othertwo, anticipating installation of a larger unit in the future. The tunnel coal tar lining was removedand the tunnel repainted; the Corps discovered that the most effective way to remove coal tarenamel is ball-peening at 3-4 in. (8-10 cm) intervals. The contractor tried robotic-type equipmentfor painting, but the riveted plate construction made this unsuccessful; however, the test showedthe robotic painting system would work on welded steel. The surge tanks, runners, draft tubes,and scroll cases were repainted. Acoustic flow meters were installed in penstock sections. Theplant was out of service for 2-1/2 years for the upgrade. [36]

Penstock Replacement Integrated with Turbine Rehabilitation

Duke Power’s Tuxedo Plant in North Carolina is a two-unit, 5-MW, 1920s vintage plant with ahead of 287 ft (87 m). The penstocks are of wood stave construction. A section of the mainpenstock was washed out in 1987. Duke replaced the penstocks and turbine runners in the early1990s. The size of the replacement main penstock was dependent upon the characteristics of theupgraded turbines.

The main penstock, originally 8 ft (2.4 m) in diameter, runs about 4700 ft (1400 m) from theproject dam to a concrete surge tank. Two short, 5-ft (1.5-m) diameter penstocks lead from thesurge tank to the powerhouse; these penstocks have concrete anchor blocks. The penstocks reston cast-in-place concrete cradles. The combination of wood stave construction and concretecradles allowed the penstocks to accommodate considerable lateral movement and settling. The5-ft penstocks were replaced in the 1940s with new Douglas Fir wood stave pipe.

In 1987, an embankment slope fill failure ruptured a 75-ft (23-m) length of the main penstock.Fortunately, the headgate had been closed, limiting the release of water. Failure of theembankment may have been caused by leakage. Retirement of the plant was considered as wellas plant rehabilitation or upgrade. Replacement and relining of the main penstock wereconsidered. Duke Power decided to replace the penstocks and to rehabilitate the plant to extendits life. Steel replacement penstocks were considered, but wood stave construction was selectedin consideration of its past performance, the limited access for construction in rugged terrain, theability to accommodate movement, and the proven construction. Hydraulic analysis indicatedthat the diameter of the main penstock could be reduced to 7 ft (2.1 m); this was crucial to theeconomic justification. The new penstocks are creosote-treated Douglas Fir tongue-and-groovestaves girded by steel bands ¾ in. (19 mm) in diameter, supported by heavy timber cradles onpre-cast concrete pads.

The penstocks leaked excessively upon first pressurization. Duke Power began around-the clockmonitoring, and placed plastic sheeting and concrete below the penstock in selected areas todivert water. The leakage declined with gradual swelling of the wood staves. Testing of therehabilitated turbines and new penstock, including load rejection testing, indicated the newpenstocks were more stable and water-tight than the old. The plant now can produce 8 MW.Testing indicates no release of penstock creosote to the water. Penstock leakage has been wellwithin acceptable rates, with only minor sloughing of the bed. Despite limited experience withwood stave construction, the project was successful. The plant rehabilitation was completed at$730 per kW. The life expectancy of the rehabilitated plant is 40 Years. [37]



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Lessons Learned

• Rehabilitating or upgrading hydroturbines using modern, fabricated runners works well.Runners must be custom-designed for the particular site. Custom designing is greatlyenhanced by finite element flow and structural analysis. Use of runners designed for one siteat another site can be disastrous.

• A competent model program can achieve the maximum benefit from a turbine or pump-turbine upgrade over the life of the upgraded units. Physical model testing is necessary toaccurately predict prototype efficiency. CFD cannot account for small changes in efficiencywhich, for large units, have a large effect on value.

• For optimum results in turbine upgrades, attention must be paid to water passages. Wicketgate height and shape, stay vane, and discharge ring modification can have demonstrableeconomic benefits and should be considered.

• In a rehabilitation or upgrade program, each component should be evaluated in detail.

• The draft tube is the most troublesome component in turbine upgrades. Draft tube design andperformance analysis remain as the principal challenges to achieving optimum results.

• A experimental nitrite coating of Pelton runner buckets for erosion protection wasunsuccessful due to the high velocity impacts of pebbles and stones.

• Experience has shown that IEC 995 formulae for converting homologous model performanceto prototype performance may result in too low a discharge and power in the pumping mode.The effect could be excessive load on the motor at low heads.

• Semi-homologous models can often accurately demonstrate flow in portions of the turbine,e.g., the draft tube, saving time and expense compared to development of a fully homologousmodel turbine.

• Original commissioning acceptance tests by the Gibson method often overestimated turbineefficiency; use of the results of such tests could significantly underestimate the potentialimprovement from a turbine upgrade.

• The cost of upgrading Pelton turbines can be as low as $100 per kW. Prioritizing Peltonupgrades in favor of machines with highest head, highest load factor, highest diameter-to-bucket width ratio, and lowest efficiency is suggested.

• Forcing the inter-changeability of Pelton runners is an uneconomic approach.

• Old Pelton runner buckets that appear to have good contours and smooth finish surfaces mayin fact be relatively inefficient due to distortion of surface shape over the years caused byrepairs.

• A thorough supplier quality control program is vital to the success of any rehabilitation orupgrade project. Building the rehabilitated distributor in the manufacturer’s shop cansignificantly reduce fit-up problems in the field.

• A complete field alignment of a rehabilitated unit can be invaluable in terms of ease ofassembly, bearing life, etc.



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References

1. T. W. Clippinger, “Rehabilitation of Existing Hydro, Our Oldest Natural Resource,” sourceand date unknown.

2. Guide for Hydraulic Machinery Model Testing. Electric Power Research Institute, Palo Alto,CA: June 1988. Report AP-5876.

3. B. Mahe and V. De Henau, “Recent Trends in Francis Turbine Uprating,” Concepts for theFuture, HCI Publications, 1994, p. 85.

4. The Value of Competitive Model Testing in the Bid Evaluation Process for HydroelectricTurbomachinery. Electric Power Research Institute, Palo Alto, CA: July 1985. ReportEM-4174.

5. L. D. Chapman, Panel Session (audiotaped): “Great Ideas in Rehab,” HydroVision 98Conference, Reno, NV (July 1998).

6. M. E. Gass, Hetch Hetchy Water and Power, personal communication, October 1998.

7. D. C. Kee, Ontario Hydro, personal communication, October-November 1998.

8. R. J. Knowlton, New York Power Authority, personal communication, October-November1998.

9. ASME Hydro Power Technical Committee, The Guide to Hydropower Mechanical Design.HCI Publications, Kansas City, MO, 1996, pp. 3-2, -21, -24, -26, -29.

10. V. De Henau, M. Sabourin, Y. Labrecque, and B. Papillon, “Hydraulic Turbine Design: WillComputer Simulations Replace Model Testing?,” Hydro Review, September 1998, p. 54.

11. S. C. Onken, “Turbine Uprating and Incremental Gains Made With Each Change,”Proceedings of the International Conference on Hydropower, American Society of CivilEngineers, 1993, Volume 3, p. 2006.

12. S. C. Onken, Oroville-Wyandotte Irrigation District, personal communication, November1998.

13. W. H. Colwill and S. A. Chacour, “Pump-Turbine Upgrades: Measuring the Benefits of NewDesigns,” Hydro Review, November 1996, p. 38.

14. S. M. Murray and F. B. Siebensohn, “Yale Hydroproject Upgrade,” Proceedings of theInternational Conference on Hydropower, American Society of Civil Engineers, 1997,Volume 3, p. 1641.

15. R. J. Knowlton, P. W. Ludewig, and J. H. Phillips, “Ensuring Optimum Performance Fromthe Machines,” Hydro Review, April 1998, p. SR8.



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16. J. L. Ford and J. Grzan, “Challenging Change: NYPA Rehabilitates Robert Moses PowerPlant,” Hydro Review, April 1998, p. SR2.

17. P. A. Bernhardt, Niagara Mohawk Power Corporation, personal communication,October 1998.

18. P. A. Bernhardt, “Rehabilitation of Unit #2 at Bennetts Bridge Hydro,” Proceedings of theInternational Conference on Hydropower, American Society of Civil Engineers, 1993,Volume 3, p. 1607.

19. T. A. Jablonski, “Replacement Of Great Falls Units 1 & 2 Hydro Turbines,” Proceedings ofthe International Conference on Hydropower, American Society of Civil Engineers, 1993,Volume 3, p. 1537.

20. IEC Publication 995, International Electromechanical Commission, Geneva, Switzerland,1991.

21. J. Spidla, “Rehabilitation of Stechovice Pumped Storage Plant,” Paper presented atHydroVision 98 Conference, Reno, NV (July 1998).

22. J. Spidla, CKD Blansko Engineering a.s., personal communication, October-November 1998.

23. “PECO Energy Completes Rehab At Conowingo, Muddy Run,” Hydro Review,September 1998, p. 66.

24. F. R. Harty, Jr., J. Geuther, T. Jenkins, and T. Callahan, “Evaluating and Specifying PumpedStorage Upgrades,” Proceedings of the International Conference on Hydropower, AmericanSociety of Civil Engineers, 1997, Volume 3, p. 1683.

25. J. L. Kepler and T. W. Jenkins, “Case Study for the Upgrade and Rehabilitation of a PumpedStorage Installation - Muddy Run Powerhouse,” Proceedings of the International Conferenceon Hydropower, American Society of Civil Engineers, 1997, Volume 3, p. 1591.

26. J. J. Hron, C. A. McKee, A. Bramati, and G. Rossi, “Rocky Reach Kaplan TurbineReplacement,” Proceedings of the International Conference on Hydropower, AmericanSociety of Civil Engineers, 1997, Volume 2, p. 1428.

27. E. Fulton, “Preparing for the Twentieth-First Century: Environmental Protection,Efficiency,” Hydro Review, November 1998, p. 10.

28. “Alabama Power Completes Upgrade at Bankhead Hydro Plant,” Hydro Review,September 1998, p. 66.

29. M. Holmberg, B. Zawacki, D. R. Froehlich, and J. Singleton, “Upgrade of the ChippewaFalls Hydroelectric Turbines,” Proceedings of the International Conference on Hydropower,American Society of Civil Engineers, 1993, Volume 3, p. 1545.



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30. R. E. Dool and S. M. Abelin, “Upgrading of AEP’s Twin Branch Hydroelectric Plant,”Proceedings of the International Conference on Hydropower, American Society of CivilEngineers, 1993, Volume 3, p. 1659.

31. J. J. Hron, J. B. Strickler, and J. M. Cybularz, “Wanapum Kaplan Turbine Replacement,”Proceedings of the International Conference on Hydropower, American Society of CivilEngineers, 1997, Volume 1, p. 412.

32. W. H. Colwill, American Hydro Corporation, personal communication, October 1998.

33. P. Ligaard, “Modern Technology Successfully Applied in Pelton Turbine Upgrades,”Concepts for the Future, HCI Publications, 1994, p. 77.

34. M. E. Gass, “Modernization and Performance Improvements of Vertical Pelton Turbines,”Hydropower & Dams, Issue Two, 1998, p. 25.

35. J. Dahlberg, W. Forsmark, and J. VanHoven, “Clam River Dam Unit 3 PowerhouseRehabilitation,” Proceedings of the International Conference on Hydropower, AmericanSociety of Civil Engineers, 1997, Volume 2, p. 1351.

36. R. W. Bockerman and D. F. Miller, “Fort Peck - Power Plant No. 1 Penstock Replacement,”Proceedings of the International Conference on Hydropower, American Society of CivilEngineers, 1993, Volume 3, p. 1507.

37. W. A. Maynard, “Replacement of the Wood Stave Penstock and Turbine Runners at TuxedoHydro Plant,” Proceedings of the International Conference on Hydropower, AmericanSociety of Civil Engineers, 1993, Volume 3, p. 1574.


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4 GENERATORS AND MOTOR-GENERATORS

Generators and motor-generators are complex, electromechanical machines that suffer electricaland mechanical stress and deterioration. Windings and cores are especially subject todegradation, resulting in lost efficiency. Generators at old hydro plants often are neglected andmay have operated since the early 1900s with the original windings. The common element ofrehabilitating or upgrading generators and motor-generators is rewinding. The predominatecauses of failure are failure of stator winding insulation, deterioration of stator core pressure andinter-laminate insulation, and field coil insulation problems. The number of engineersexperienced in generator insulation has dwindled. Problems often are not realized until toolate. [1]

Rehabilitation and Upgrade Practices

A proactive approach to rewinds is suggested. For success in rewinds, begin assemblinginformation before there is a problem. Define alternative strategies: continued upkeep;refurbishment to “good as new”; upgrade by refurbishment plus redesign to improve output,efficiency and temperature control; or replacement with a new or reconditioned machine. Keyquestions are:

• What is the machine’s present condition and how much longer can it operate?

• Is existing monitoring adequate to determine the machine’s condition?

• What would be the total cost for repair after a sudden failure vs. a planned repair based onexisting condition?

• Can the unit be operated at a higher output?

• What is the ranking of urgency of this machine among all generators?

A survey of U.S. owners indicates a large majority are unprepared to answer those fivequestions. A comprehensive discussion of tests, recommended contractual and monitoringprocedures, and common pitfalls in generator rewinding is presented in “Hydro GeneratorRewinds: Planning for Success,” Hydro Review, May 1996. [1]

Tennessee Valley Authority (TVA) Approach

In upgrading any hydro unit, the capacities of all power train components, i.e., turbine, generator,shafts, bearings, stator windings, rotor poles, generator cooling systems, bearings, and structuralcomponents should be evaluated. TVA first analyses the upgrade potential from the turbine side,by establishing a maximum output based upon head and flow. Then the remainder of the powertrain is reviewed to identify limitations. [2]



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Several tests are recommended in an assessment of the potential for upgrading a generator. Acontrolled heat run can be used to predict cooling requirements at uprated load. Machine lossescan be segregated into components by speed-no-load, open circuit, and short-circuit tests. Polesaturation tests can determine potential loading of field poles. Historic test reports and outagereports may provide useful information. Testing can accurately measure fixed (windage, friction,and core) and variable (copper and stray) losses. Computer models can provide good assessmentsif sufficient, reliable data are available. Caution is advised that post-commissioningmodifications may have altered “original” values. [2] The standard for generator testing in theUnited States is American National Standards Institute/Institute of Electrical and ElectronicsEngineers (ANSI/IEEE) 115. [3] EPRI’s Hydropower Plant Modernization Guide addresses theapplication of generator test results to rehabilitation and upgrading. [4]

TVA measures heat transfer through generator air coolers, electrical heat within the machine,contribution from bearing friction, and heat conducted through housing to/from the outsideenvironment. The variation of stator and field temperature rise with the square of the respectivecurrent is essentially linear and can be plotted to predict temperature rise at higher loads.However, since the relationship of field temperature rise to the square of the current is less linearthan for the stator, additional margin for field temperature rise is recommended. ANSI codeallows a temperature rise of 90°C for Class F insulation. (TVA limits Class F temperature rise to80°C.) TVA attempts to test at 50% and 100% load, with heavy reactive loading.

Design changes will affect heat losses. For example: rewinding changes copper lossthe effectof changes in copper area can be estimated; changing fan and baffles changes windage loss, noteasily estimated by hand calculation; and changing pole dimensions or configuration changesfield copper loss. To raise the loading limit requires measures such as higher class insulation,upgraded ventilation (which may affect air cooler performance), improvement of air coolers, orshimming behind pole bodies to decrease air gap; this latter measure requires expert adviceconcerning the effect on reactances and other electrical circuits, and potential mechanicalproblems. ANSI standards limit air cooler outlet temperature to 40°C for temperature risepurposes; this may be a consideration during warmer months. [2]

Mechanical Aspects to Generator Upgrade

In addition to the obvious electrical considerations in any upgrade, there are mechanicalconsiderations which are often overlooked due to the general conservative approach to design ofolder units. The most obvious potential problem is the case in which parts are structurallydefective or cracked. In other cases, sound materials may not be capable of assuming higherstresses. When evaluating a unit for upgrading, the following components must be considered:rotor shaft (increased torque from higher loads, increased tension from heavier rotating parts),coupling bolts (increased shear and axial stress), and rotor spider (increased torque, bending, andtension stresses). Older castings were often of relatively poor quality. The weight of pole piecesto be supported is important; the spider suffers tensile stress due to rotation combined withbending. Overspeed stress must be considered, although there is no full-load torque. Rimattachments and pole piece connections must be checked. A thorough material evaluation shouldbe made. Mechanical components are generally re-used. There is a concern for materialuniformity in older steel castings, particularly large castings with highly variable thickness. Thehub-to-spider arm area is particularly vulnerable in old castings.



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In one case, a rotor had been shipped for rehabilitation; severe cracking in the hub-to-spider armarea was noticed after the pole pieces had been removed and sandblasting had occurred. In thiscase, thorough investigation of the rotor spider was undertaken, additional surface cracks werefound, and a detailed stress and fracture mechanics review was performed. Fabrication or castingof a new spider was considered, but, due to time constraints, it was decided to cut out and weldrepair all visible cracks. The repair took about three weeks. [5]

Pitfalls of Generator Rehabilitation and Upgrade

The most commonand costlypitfalls are: being surprised by a failure; rewinding a generatoras-built when an upgrade could have been accomplished for about the same cost; ordering the“maximum output possible” without any idea of other factors (such as turbine capability);requiring insufficient rehabilitation time in order to minimize lost output; and not being aware ofrecent changes in standards, notably revised temperature rise standards. For example, thepermissible rise for Class B insulation is 80°C (75°C above 7000 volts), and a new Class Fstandard has been added. Suggested remedies are:

• Monitor and gather machine condition information in advance

• Allow sufficient time for a quality rehabilitation job (four months for small projects afterbidding; one year for large machines including 3-5 months for bidding and evaluation)

• Match the manufacturer to proven capability for the type and size of machines

• Evaluate quality in bid evaluations

• Pre-qualify bidders based on results of tests

Some owners ask pre-qualified contractors to supply samples of winding materials for tests anddesign checks and to provide references involving the same rewinding materials and insulationsystem. Operating characteristics such as current loading, rated voltage and voltage stress of theinsulation to ground, stator core length, operating temperature, and starts/load cycles of thereference units should match the project units. Less important are rpm, kVA, power factor (PF),and frequency. A good specification is invaluable. Careful handling of materials and windings atthe job site is important. Close inspection is required. Verification testing should not be waivedto hasten restart. Comprehensive monitoring and testing should begin immediately after re-commissioning. [1]

Generator Protection

Generally, older generators have protection shortcomings. There are risks in not providingadequate protection. Hydro generator protection can be enhanced using digital technology.Generators require protection not only from short circuits but also from abnormal electricalconditions, e.g., over-excitation, over-voltage, loss of field, unbalanced currents, reverse power,and abnormal frequency. Multifunctional digital relaying is an ideal way to upgrade protection;required features can be supplied in a single package. Communication with the relays can beinstalled, and metering quantities within the relays can be accessed. [6]



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Upgrading Generators at a Major Plant

The U.S. Bureau of Reclamation is upgrading three of the five units at its Shasta Project, inCalifornia, at a total cost of about $21 million. Upgrade of the first generator has beencompleted; the machine is operating satisfactorily as limited by the existing turbine to 125 MW.The second unit is scheduled for completion in 1999, also to operate with the existing turbine.The third unit is scheduled for completion in 2000. Reclamation’s original plan was to replacethe third unit’s runner during its generator upgrade, then replace the first and second units’runners later, but the first runner replacement (third upgraded generator unit) may be delayed.Prior to the upgrade, the plant was rated at 578 MW; the present rating is 625 MW.

The Shasta units may be loaded at a rate from no-load to maximum as limited only by theallowed rate of wicket gate opening. Cycling is normally twice-per-day, but more often duringemergencies. When water is plentiful, the units may operate at full load for a month or more.

The Shasta generators were installed in 1943 and originally rated 75,000 kVA, 13.8 kV, unityPF, 60 Hz, 138.5 rpm. The generators have direct-connected exciters and are self-ventilated withtop-mounted axial fans and water cooling. The machines were rewound in 1969-71, when theywere re-rated for continuous service at 86,350 kVA, 0.97 PF, 60°C temperature rise. Structuraladditions to the rotor assemblies in 1978-80 allowed operation to 125,000 kVA, but the machineswere limited to slightly lower loads due to electrical and thermal conditions. Reclamationdetermined that with new turbines, the generator outputs of Units 3, 4, and 5 could be increasedto 142,000 kW at unity PF. Reclamation then did a detailed analysis of the frequency of loadingand the absolute limit of the units; unit operation was modeled based on hydrologic and flowdata. Benefits were estimated for three levels of improvement:

Rewind Improvement Annual Benefit

to nameplate capacity $5.3 million

to current operating level 0.5 million (incremental)

to 142 MW (upgraded) 0.8 million (incremental)

Total $6.6 million

Economic justification was based on energy only since the applicable power contracts are limitedto the sale of energy. The upgrade work includes:

• Replacement of armature windings and stator cores for 80°/75°C temperature rise for outputof 142,000 kVA at unity PF

• Replacement or re-insulation of field windings for operation at 100°C temperature rise atrated output

• Installation of redesigned rotor fans and shroud systems, static exciters, and static voltageregulation and excitation control systems

• New turbine coupling bolts

• Addition of dowel pins to the rotor hub key systems

• Installation of segmented main thrust bearings with high-pressure lubrication to allow forrapid restart



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The upgraded generators are required to be capable of (1) charging the transmission line withoutbecoming self-excited or unstable at not less than 107,000 kVAR at zero PF under-excited and(2) absorbing load of 80,000 kVAR at zero PF over-excited without exceeding temperature riselimitations. The guaranteed generator efficiency is 98.70%, to be confirmed by heat run tests.(Reclamation calculates generator efficiencies to 0.01%.) Sensors were installed as part of theupgrade, as were instruments for checking shaft runout and vibration. Reclamation specified thatmaximum efficiency be at full load and rated power factor.

In planning the upgrade, the initial step was to collect data from existing generators includingdimensions, measured temperature rises, field voltage and currents at rated load, open circuitfield characteristics, losses, and reactances. The contractor analyzed the data by a proprietarycomputer program, calibrating output to match the existing machines and calibrating the fluxdistribution in the air gap. In these analyses, the more data gathered, the better the design.The computer simulation achieved a new design with least intervention in the existing machine.Replacement of the stator winding and core provided the best opportunity to maximize efficiencyand output. Analysis included a mechanical analysis. During dismantling, some of the tighteningbolts expected to be reused were found to be broken; this resulted in redesign of the bolts usinghigh-grade steel, thus reducing the number of bolts and the cost of bolt replacement. [7,8]

Correcting Generator Rotor Roundness

Where generator rotors have insufficient stiffness to counteract the stator-rotor magneticattraction, the roundness of rotors can deteriorate, introducing unbalanced forces. At its ArnpriorGenerating Station, Ontario Hydro (OH) had rewound the generator rotors twice since beingplaced in service in 1976. Out-of-roundness of one machine was causing inward movement ofthe stator by 0.005 in. (0.13 mm) at each passing of the high spots of the oval rotor. This in turncaused cracking of the upper generator bracket and galling of the sole plate radial keys. Thevariances of rotor and stator shapes were 0.093 in. (2.4 mm) and 0.138 in. (3.5 mm),respectively. OH decided to shrink the rotor rim to the spider to increase stiffness. Reinforcementof the spider was required to withstand the shrink. The work included removal and modificationof the spider, including repair of cracks. OH’s air gap monitoring system was used to providerotor roundness readings. Two heatings were required to achieve the desired roundness of theshrunk-fit rim. With the modified rotor in service, shaft runout decreased from 0.015 in(0.38 mm) to 0.004 in (0.10 mm). Another unit was similarly modified with a higher shrink.OH has permanently mounted a computer-based air gap reading system onto both units. [9]

Replacement of Exciters with Generators

The Lookout Shoals Plant in North Carolina was the first plant to be rehabilitated under DukePower’s hydro project modernization program. Normal head on the plant is in the 70-75 ft(21-22 m) range. A particular problem at Lookout Shoals was that discharge from any of thethree main turbines could not be reduced to the minimum flow required for downstream fisherypurposes without subjecting the unit to rough operation. The solution was to replace the plant’stwo hydraulic turbine-driven direct-current exciters with two new 500 kVA (600 rpm)alternating-current generators, in order to satisfy the minimum flow requirements whileproviding supplemental generation. The exciters were redundant with the turbine-driven exciteron a main unit. Additional work included upgrading the servomotors, the wicket gate operatingsystem, and the actuators on the penstock isolation valves.



4-6

The new generators were anchored to the existing sole plates, and their shafts were connected tothe existing turbine shafts. The new generators were connected to the plant’s 480-volt auxiliaryelectrical system. Special attention was paid to possible shaft vibrations and avoidance ofharmonic frequencies in the generators. Testing at the manufacturer’s facility included a 200%speed test (1200 rpm). The work was accomplished during the main plant rehabilitation, and thenew generators are included in the new plant control system. The units were installed by plantsupport forces in 1996. [10]

Thrust Bearing Cooling System Upgrade

At the Rocky Reach Plant, the thrust bearings are cooled by gravity-flow water systems, withflows of 250 gpm (16 liters per second). In the original systems, cooling water flow continued atunit shutdown, stiffening the lubricating oil and subsequently causing excessive wear on thebearings. Furthermore, silt from river water clogged the orifice flow-measuring device. ThePublic Utility District No. 1 of Chelan County installed magnetic flowmeters to eliminate thesilt clogging problem and automatic flow shutoff valves to stop flow at unit shutdown. A10-ft (3-m) length of supply pipe was cut out, and the new shutoff valve, flowmeter, andautomatic flowmeter bypass were inserted. The total cost of materials was less than $5000 perunit. It is intended to apply the same technique to solving identical problems with the high flow,main generator cooling water systems. [11]

Experience with Stator Iron

The U.S. Army Corps of Engineers (Corps) has some 350 hydro generators and has rewoundperhaps one-third of them. There have been problems with brittle, damaged stator iron. Onerewinding project was delayed in progress when the stator iron was unexpectedly found to be inpoor condition. Subsequently, the Corps has included stator iron replacement as an optional itemin the cost estimate and justification of all rehabilitation and upgrade projects; when thegenerator is disassembled, the decision to replace the stator iron can be made without modifyingauthorizations or contracts. [12]

Developing Technologies

Insulation Systems

Hydro generator design always involves a tradeoff between stator insulation thickness (more isbetter for insulation life) and generator size (smaller is less expensive). Development of newinsulation systems using corona-resistant materials and thinner (higher stress) insulation thatwould provide equal protection and reduce generator size has been claimed. A manufacturerpartnered with two utilities to test stator bars; in one test, 40 bars with thinner insulation wereincluded in a rewind to compare to the standard product; the bars were instrumented withtemperature detectors, and partial discharge detectors were inserted. The physical integrity ofinsulation systems is important to resist damage from installation or operating vibrations.Voltage endurance tests are most crucial. The corona-resistant, composite materials tested arereported to be competent and available for use in generator rewind projects. [13]



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High Voltage Generators

The high-voltage generator is a relatively new development now in commercial operation at thePorjus Plant, in Sweden. The Porjus generator output is at transmission voltage, 45 kV,eliminating the need for a step-up transformer. The high-voltage transformer increases unitefficiency and reduces the risks and problems associated with the presence of oil, e.g.,containment and fire. At new plants, elimination of the need for transformer bays reduces civilworks cost. More installations of high-voltage generators are planned. [14,15,16]

Variable (Adjustable) Speed Machines

Improvements in control technology have lead to investigation and trial of variable- oradjustable-speed hydroelectric (ASH) units. ASH has especial promise in pumped storageinstallations, which are usually relatively high-capacity units with large changes in head, andwhich can benefit in particular from the ability to regulate output in the pumping mode withoutsignificant loss of efficiency. Evaluation of ASH would not normally be considered forrehabilitations and upgrades of most hydro plants due to the high cost of specialized convertersystems. While promising for improvement of system power quality and extension of ancillarybenefits, ASH can also enhance system voltage stability and frequency control. Electroniccontrols enhance the feasibility of ASH motor-generators. [17] For a comprehensive discussionof ASH technology, reference to EPRI’s report Application of Adjustable-Speed Machines inConventional and Pumped Storage Hydroelectric Projects is suggested. [18]

Lessons Learned

• Retain a generator specialist for upgrade projects that could affect the generator.

• Focus on reducing generator size (maximum rpm) in Pelton upgrades.

• Be prepared for the need to replace iron in the stator core; much time and cost can be saved ifoptional contractual provisions are made in advance.

• Generator overcooling/over-ventilation is better than under-cooling/under-ventilation.

• Evaluation of each generator component modification should be made to ensure that eachcomponent modification is necessary or cost-effective.

• Examine and analyze mechanical generator parts early; the design or condition of mechanicalcomponents may limit the upgrade potential unless modifications are made. Minimal materialproperties should be assumed, due to the variability of material in castings; destructivetesting may provide misleading results for the same reason. Cracks are hard to see in old,rough-surface castings.



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References

1. H. F. Naeff, “Hydro Generator Rewinds: Planning for Success,” Hydro Review, May 1996,p. 44.

2. M. S. Poteet and G. O. Keith, “Cooling and Uprate Analysis of Hydro Generators,”Proceedings of the International Conference on Hydropower, American Society of CivilEngineers, 1997, Volume 1, p. 740.

3. ANSI/IEEE 115-1983. Test Procedures for Synchronous Machines.

4. Hydropower Plant Modernization Guide. Electric Power Research Institute, Palo Alto,CA: June 1989. Report GS-6419.

5. W. G. Moore, “Mechanical Considerations for Uprate and Rehabilitation of Hydro-Generators,” Paper presented at HydroVision 98 Conference, Reno, NV (July 1998).

6. C. J. Mozina, “Upgrading Hydroelectric Generator Protection Using Digital Technology,”Proceedings of the International Conference on Hydropower, American Society of CivilEngineers, 1997, Volume 1, p. 713.

7. M. A. Bauer and C. Millet, “Project Spotlight: Uprating Generators at Shasta Powerplant,”Hydro Review, August 1998, p. 104.

8. M. A. Bauer, U.S. Bureau of Reclamation, personal communication, October 1998.

9. G. Haines, “Improving the Air Gap Mechanical Stiffness Of a Hydrogenerator,”Hydro Review, May 1995, p. 66.

10. D. N. Summers, B. L. Sigmon, S. G. Powell, J. C. Sigmon, and E. M. Brinson, “Replacementof DC Exciter with AC Generator,” Proceedings of the International Conference onHydropower, American Society of Civil Engineers, 1997, Volume 3, p. 1633.

11. B. M. Bickford and D. H. Garrison, “Creative Problem Solving at Rocky Reach,”Hydro Review, April 1997, p. SR22.

12. J. A. Norlin, Panel Session (audiotaped): “Rehabilitation II - Lessons Learned,”HydroVision 98 Conference, Reno, NV (July 1998).

13. R. E. Draper and R. H. Rehder, “Hydro Generator Insulation Improvements throughExtended Use of Corona Resistant Materials,” Proceedings of the International Conferenceon Hydropower, American Society of Civil Engineers, 1997, Volume 3, p. 2160.

14. K. Isaksson and T. Karisson, “Technology for the Future: Development of a NewGenerator,” HRW, May 1998, p. 23.

15. H. F. Naeff, ABB Power Generation, Inc., personal communication, October 1998.

16. “A New Turbine; A New Generator,” Hydro Review, November 1998, p. 14.

17. E. Kita, Y. Ohno, T. Kuwabara, and A. Bando, “Gaining Flexibility, Value with Adjustable-Speed Hydro,” HRW, Winter 1994, p. 18.

18. Application of Adjustable-Speed Machines in Conventional and Pumped StorageHydroelectric Projects. Electric Power Research Institute, Palo Alto, CA: November 1995.Report TR-105542.


5-1

5 GOVERNORS, CONTROLS, AND AUXILIARIES

Governors and controls are often included in hydro plant rehabilitation or upgrade projects.Properly operating governors and controls are not only important for plant efficiency andreliability but also for plant safety. Modern, digital equipment can greatly reduce the humaneffort in operating and monitoring a hydro plant while enhancing reliability. Some rehabilitationand upgrade projects have focused primarily on governors and controls.

Auxiliary systems are also essential to a well-functioning, safe hydro plant. Unfortunately, thesesystems may often be neglected in favor of power train components. Some hydro owners havespecific programs to upgrade auxiliary systems. Under certain circumstances, considerationshould be given to rehabilitating or upgrading auxiliary systems prior to the rehabilitation orupgrade of the major plant components.

Governors and Controls

Modern governors and electronic controls can enhance the capability of units to operate atmaximum efficiency or to maintain constant discharge, under changing head conditions. [1]

Modern control systems use intelligent electronic devices and microprocessor-based protectiverelays. Deregulation is forcing utilities to increase the degree of automation of hydro plants.Expert automation systems can help and can be installed during the rehabilitation or upgrade ofunits or major components. [2]

Control of a Remote Plant in a Small System

The Bradley Lake Plant in Alaska has two 60-MW Pelton turbines under a head of1085 ft (330 m), supplied by a 3.6-mile (5.8-km) tunnel. The plant is remotely controlled andnormally unmanned. Each unit has six needle valves operated in pairs, depending on load. Speedcontrol is augmented by a deflector on each valve. The digital governor had formerly beenprogrammed to control each needle independently. The turbines suffered power swings whenshifting between two- and four- or between four- and six-valve operation. These power swingsoften exceeded 10% of unit capacity, due to the combination of the long tunnel and the smallload. It was infeasible to install a surge tank to dampen flow changes. What was needed was anew way to control flow, to keep flow constant while valves were opened or closed.

Elimination of the power swings was solved by programming the governor using an “error andequalizing” algorithm in the governor logic. This is believed to be the first time such logic hasbeen applied to governing impulse turbines. Adjustments to the needles keep flow and powernearly constant through the transition period while the needles are being opened or closed.


Governors, Controls, and Auxiliaries

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Common operation now is to block-load power. Sometimes during volatile situations, six needlesare kept open under pure deflector control. Potential limitations to this type of operation are that(1) an even number of jets is needed and (2) machine bearings must be capable of acceptingunbalanced loading. [3]

Control of a Major Pumped Storage Plant

At PECO Energy’s eight-unit, 880-MW Muddy Run Pumped Storage Project in Pennsylvania,the original control system was replaced in order to eliminate parts and service problems with theoriginal system, reduce unit downtime, provide better information, reduce the potential for majorfailures, and improve unit performance and operating results. New unit instrumentation includes:wicket gate position; flow; exciter volts and amps; governor and thrust bearing oil levels;governor accumulator tank level; stator, oil and bearing temperatures; motor-generator phasecurrent; motor-generator voltage; vibration at the motor-generator guide bearing, thrust bearing,and pump-turbine guide bearing; speed in rpm; and motor-generator MW, MVAR, and MWh.Plant instrumentation includes voltage, nitrogen pressure, transformer oil temperature, firesystem header pressures, RTU and host computer temperatures, forebay and tailrace levels,and breaker air pressures. Alarm values are monitored for these variables. There are total of496 analog inputs, 8 analog outputs, 824 digital inputs, and 160 digital outputs. The new systemwas installed in parallel with continued control by the original system; the new system was testedbetween pumping and generating periods. Generator output is controlled to within one MW andplant output to within two MW. Normal unit operating limits are 50% low gate, 90% maximumgate, and 110 MW maximum load. Each unit normally provides 25 MW of system regulationfollowing an area control error signal. [4]

Automation of a Medium-Sized, Conventional Plant

The Robert S. Kerr Dam of the Grand River Dam Authority (GRDA) is a 114-MW plant inOklahoma, with four generators each rated at 30 MVA driven by Kaplan turbines. The plantoperates as a peaking plant. The plant had obsolete excitation equipment, causing poor unit start-up rates. Also, the plant had a history of lightning problems and under-capacity control cables.The need to replace the excitation equipment led to a plan to automate the plant. GRDA decidedto replace existing relay equipment with PLCs and to convert to fiber-optic cable. The PLCs arecapable of recognizing small differences in unit characteristics. Each unit is now connected tocentral supervisory control which automatically and optimally allocates load among the units.Close control of gate and runner blade positions prevents large load swings and is easier on theunits. Output can be kept relatively steady, reducing wear on the blade mechanisms andproblems with foaming in governor oil. Trouble-shooting of the control system can be performedby PC at plant or via modem. An extensive alarm system was added; if trouble occurs, thesystem readily identifies problems, thereby quickening maintenance response and reducing downtime. The total cost was $600,000. The benefits are unlimited load control, elimination of groundfaults, annunciation, and enhanced troubleshooting. New brushless exciters have reduced losses.Startup rates are 97%, with less maintenance. The plant has experienced several lightning strikeswithout effect on the PLCs. [4]



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Control of a Large System

The California Water Project (CWP) annually delivers 3.5 million acre-ft (4.3 x 109 m3) of waterand generates 5.1 million MWh. CWP has 700 miles (1100 km) of aqueduct. Operation of thewater system requires coordination of dozens of gates with pumping and generating units.CWP’s greatest challenge concerned control strategies and centralizing control.

The original control system was installed in 1968-72. By the 1990s, the control system wasobsolete, and CWP had run out of spare parts. The new control system includes 300 RTUs andother components to be connected by fiber-optic networks to digital controls. The system wasinstalled by in-house staff to maximum their exposure to the system, but an important benefitwas that involved CWP personnel also aided with the definition of hardware-software-processorlinks due to their familiarity with the CWP facilities and functions. The new RTUs have highreliability, and spare parts inventories will be minimized; contracts for spare part repair andreplacement were written into the original supply agreements with all suppliers. CWP plans todevelop a system for automatic recognition and response to alarms using “expert system”technology to capture decades of operating and maintenance experience in the new controlsystem. Potential benefits are increased efficiency, more flexibility, lower maintenance, andhigher reliability. The key to the project’s success is considered to have been careful planningand management. [4]

Automation of a Large, Conventional Peaking Plant

Automation of AmerenUE’s Osage plant, a 212 MW conventional peaking plant located inMissouri, was driven by rising operation and maintenance costs and by the need to improveefficiency and flexibility to prepare for competition; the result has been greater efficiency, lowercost, and safer operation. The economics of automation turned largely on wage and benefitsavings. The plant has eight main units and two house units. The main units have pairedgovernor oil systems. Prior to automation, the units were started and stopped by operatorslocally, synchronized from the plant’s central control room, and loaded and controlled by “raise”and “lower” pulses from the remote dispatch center through the plant RTU and PLC. The PLCbalanced load among all main units. Because of the time required for startup, several units werealways kept synchronizing for spinning reserve in case of emergencies.

The comprehensive automation project included: a new digital control system for automatic start,synchronizing, loading, and shutdown; a new PLC-based digital governor system; a staticexcitation system (replacing motor-driven exciters) including automatic voltage regulation;automatic synchronizing equipment; interfaces with the remote dispatch center; a digital, PLC-based control center that allows each unit to be totally started and stopped locally by one-buttonoperation; stand-alone synchronizing control for each unit; a new motor-operated gate locksystem; level switches for automatic starting of plant sump pumps; automatic air pressurizing ofgovernor oil accumulator tanks; comprehensive monitoring and alarm of possible fire conditionsthroughout the plant; and a new SCADA system allowing total control from the plant controlroom by interface with the unit control centers, interfacing with the RTU, balance-of -plant dataacquisition, VAR and voltage control of units, load control, alarms, and data logging andarchiving.



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Presently, the units are normally loaded from central dispatch. River flows govern loading, andplant staff calculate river influences and communicate them to central dispatch. After nearly sixyears, the automation equipment has performed as expected; there has been no lost generationdue to the automation equipment. Now, in emergencies, units are quickly loaded from standstillto 85% gate; normal startup is to 10 MW minimum operating load. Plant staffing has beenreduced from about 60 positions before automation to under 30 positions today. [5,6,7]

Governor Controls Upgrade at a Pumped Storage Plant

The Castaic Pumped Storage Plant of the Los Angeles Department of Water & Power (LADWP)has six reversible units rated at 240 MW and one conventional unit rated at 55 MW. Newcontrols were needed not only to improve operations but also to qualify the units for spinningreserve service. The existing governor system included a mechanically driven actuator andelectrical control circuits utilizing solid state components driven mostly by analog signals. Speedregulation was difficult; the units “hunted” when interfacing with the automatic generation center(AGC), and units sometimes dropped load. Plus, the system required extensive maintenance, andthe original manufacturer advised that some parts may be discontinued.

New digital hydraulic actuator controllers were installed. This improved speed regulation. Speedsensing at low speeds was provided by new zero-velocity pick-ups, and at high speeds by apotential transformer signal from a generator phase. The new speed control is very responsive;two ramp rates can be set. LADWP uses 2 MW per pulse for normal operation and 7 MW perpulse for AGC operation. Automatic dispatch is of high quality; responsiveness and reliabilityare improved. The new system allows automatic transfer from synchronous condensing togeneration when low frequency is detected; this qualifies the plant as spinning reserve. The totalpurchase and installation cost was $150,000 per unit. Installation took 10 weeks for first unit and6 weeks for the second unit. The plant is more competitive in a “deregulated” market. [8]

Upgrading Controls at a Major, Remotely-Operated Plant

Replacing antiquated, mechanical/analog plant controls with digital controls can improveoperating efficiency, permit better coordination with other plants, and produce a range ofinformation. A successful control system requires not only good hardware and software but alsoproject management that understands and designs for the needs of the people that will use it. Atthe 330-MW Trängslet Plant in Sweden, a new control system was necessitated by a flooding ofthe old system and lack of confidence in the reliability and integrity of that system whenrestored. The plant is operated remotely from a dispatch center responsible for operating some25 unmanned power stations and associated bulk power facilities. A new digital system wasdesigned to: optimize load among the plant’s three units; perform water flow calculations foreach unit, including measurement of water levels and head losses; record events and timing;provide information on operating conditions and automatic report printouts of energy values; andadapt to the remote control center. Careful attention was paid to planning and scheduling in viewof the importance of Trängslet’s availability to the power system.

The new control system is “distributed,” i.e., one in which the hardware and functions aredivided among the units and located as close to the process as possible. There are sixcomputers—one for each unit, and one each for water level sensors, station service, andman-machine interface. Operators in the remote control center can stop and start units, close with



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synchronizing, trip breakers, and load active and reactive power. Wicket gate positions, voltages,power, indications, fault signals, and energy metering pulses are transmitted to the remote center.In 1992, the equipment was upgraded in several ways, including addition of instrumentation fortunnel outlet water level measurement and equipment for dam failure, with separate equipmentfor alarm sending. Overall, station efficiency improved 0.5% beyond expectations. The cost ofthe upgrade was about US$1.5 million. [9]

Electric Servomotors

In Japan, electric servomotor systems have been developed and implemented to replace oil-basedgate operating systems; over 60 systems have been installed on small and medium-sized Francisturbines. Electric servomotors up to 55 kW are available; this is sufficient for a 5-second gateclosure of a 60-MW turbine under a head of 100 m or a 90-MW turbine under a head of 200 m.The advantages of electric servomotor systems are freedom from dealing with hydraulic oil, easymaintenance, and relative compactness. Reliability has been high, reducing the need forredundant systems; today’s systems have a DC battery bank standby only. The basic design wasdeveloped in the 1980s and has not changed significantly, but features have been improved withexperience.

Application of electric servomotor systems is being extended to Kaplan and Pelton turbines.Problems with the complexity of Kaplan blade control have been solved; electric servomotorshave been installed at Kaplan units as large as 20 MW. Application to Pelton turbines has beenrelatively difficult due to the fast deflector closing speed required in an emergency; this calls fora very large capacity servomotor. A system equipped with a energy storage spring arrangementhas been devised and installed at both horizontal and vertical Pelton turbines.

The need for fast, emergency shutdown is a significant limitation to the application of electricservomotor systems. Wider application seems to require development of a more powerful andcompact energy storage system. [10]

Wicket Gate Latches

The Tennessee Valley Authority (TVA) has developed a new type of wicket gate “latch” systemto hold the gate operating ring closed during shutoff. Customarily, such devices are designed towithstand the force due not only to the opening torque on the closed gates caused by waterpressure but also to opening servomotor thrust. TVA’s latch is designed to withstand only thewater force. Thus, it is much smaller and can be installed on the head cover withoutdisassembling the unit. TVA plans to patent the device. [11]

Auxiliaries

Auxiliary systems include cranes and hoists, fire protection, grounding, compressed air, HVAC,sump/drainage, potable water supply, sanitary, station electrical, lighting, and others. All thesesystems are important in a well-maintained plant. Antiquated or faulty auxiliaries can behazardous and cause disproportionate maintenance attention. Any hydro plant improvementprogram should consider the rehabilitation or upgrade of auxiliary systems. Auxiliaries that are



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essential to a rehabilitation or upgrade project—e.g., powerhouse crane and station electrical,compressed air, water, and sanitary systems—should be thoroughly tested and, if necessary,repaired, rehabilitated, or upgraded prior to the primary project. [12,13]

Plant Upgrade Focused on Controls and Auxiliaries

Modernization of the 30-year old 80-MW Säckingen Plant in Germany was driven bycompetition and the need to produce at lower cost as a competitive electricity market emerges inEurope. A rehabilitation and modernization program considered every aspect of plant operations.The result was a change in equipment, operating methods, personnel, and management designedto meet cost targets. Control upgrades were needed to maximize generation from available riverflow. Other problems to be corrected were: the risk of fire in the auxiliary power supply; theshutting down of units caused by erratic control of air volume in governor accumulators;inefficient trashrack cleaning machines; and insufficient information in the control center toanalyze failures.

An extensive upgrade was selected not only to correct deficiencies but to provide for fullautomation. Each element was evaluated and re-evaluated for economic value. Major work onturbine runners or generator primary components was not required. The primary work itemswere:

• Replacement of most of the low-voltage auxiliary supply system with a fully redundant DCsupply system

• Replacement of rotating exciters with static exciters

• Installation of digital generator and transformer protection systems

• Replacement of turbine governors, start-stop controls, and monitoring systems with digitalequipment

• Minor improvement of turbine hydraulic controls

• Replacement of turbine monitoring sensors

• Installation of new trashrake systems

• Replacement of central control and monitoring with digital equipment

• Implementation of a level controller system for automatic operation

The owner considered not only price and quality but also customer service and communicationsvariables in selecting equipment suppliers; quality control requirements were adjustedcommensurate with the reputation and experience of each supplier.

Worker input, ideas and incentives were considered in the designing and planning program; aworker whose idea saved over US$500,000 was awarded US$6000. Workers have been awardedover US$35,000 for ideas saving some US$1.5 million during the project. The plant began with39 staff; the target is now 15. The station is fully automated and attaining envisionedefficiencies. The actual cost was US$17 million (60% of budget). The owner expects full costrecovery in seven years. [14]



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Auxiliary Equipment Replacement Program

The Lower Colorado River Authority has adopted an auxiliary equipment replacement programfor its six hydro plants. The plants’ reciprocating air compressors have been replaced with rotaryscrew compressors, manually-lubricated pumps are being replaced with self-lubricating pumps,and unit remote controls have been upgraded. [15]

Lessons Learned

• Make sure that powerhouse cranes, crane systems, and all other auxiliaries are ready for theoutage. Cranes, or crane rails or supports, may need to be rehabilitated or upgraded prior tothe unit upgrade, to remedy deficiencies or to increase capacity.

• Think ahead when rehabilitating systems. Failure to take advantage of an opportunity touprate the voltage on a powerhouse crane caused much additional cost and inconveniencewhen the station service voltage was raised later.

• Dealing with the effect of automation on plant personnel is critical. Valued employees shouldbe given as much notice as possible of planned changes affecting them. The automationplanning process should take personnel into consideration. The participation of plantpersonnel in the planning process is very important and may provide cost-saving ideas.

• Drawings and prints at plants are often not up-to-date. Major renovations provide the impetusand opportunity to upgrade the blueprint system.

• Choose software that can be supported for at least five years.

• Select standard (“off-the-shelf”) hardware whenever possible.

• An in-house person proficient in the hardware and software should be on-site or readilyavailable for the first year. Small “glitches” and minor irritations can be dispensed with asthey occur.

• Use in-house personnel whenever practical during the installation of a control system tofamiliarize them with the equipment.

• Keep the system as simple as possible. Minimize the input and output points. Don’t merelytry to duplicate the prior system.

• Consider being aggressive with control upgrades. It may be economical to upgrade controlson a system basis in advance of turbine rehabilitations and upgrades; this advanced timetablecould result in realization of enhanced flow control and increased production at the earliestopportunity.



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References

1. O. Moeller, Panel Session (audiotaped): “Rehabilitation II - Lessons Learned,” HydroVision98 Conference, Reno, NV (July 1998).

2. D. J. Dolezilek, “Innovative Instrumentation and Control System Designs OptimizeHydropower Operations,” Paper presented at HydroVision 98 Conference, Reno, NV(July 1998).

3. T. A. Bauman and D. P. Stead, “Software-Based Governor Control Helps Manage PowerSwings,” Hydro Review, December 1995, p. 44.

4. C. S. Rogers, J. Webb, and J. Gant, “Hydro Automation: Finding the Right Approach,”Hydro Review, April 1996, p. 16.

5. S. Duxbury and R. W. Ferguson, “Automation of the Osage Hydroelectric Plant,”Proceedings of the International Conference on Hydropower, American Society of CivilEngineers, 1993, Volume 3, p. 1841.

6. R. A. Spicer, D. Dunlop, D. Jarvis, and W. Byers, “Managing the ‘People Part’ of HydroAutomation,” Hydro Review, April 1997, p. 18.

7. D. Jarvis, AmerenUE, personal communication, October 1998.

8. M. Moulay and M. Schoof, “Governor Control Upgrades - Castaic Pumped Storage PowerPlant - Los Angeles Department of Water & Power,” Paper presented at HydroVision 98Conference, Reno, NV (July 1998).

9. S. Andersson, “A Retrofit That Worked: Upgrading Trängslet Station’s Controls,” HRW,August 1996, p. 16.

10. H. Tanaka, S. Sugimoto, and H. Tomiyasha, “Experiences and Developments of ElectricServomotor Systems for Hydraulic Turbine Control,” Paper presented at HydroVision 98Conference, Reno, NV (July 19980.

11. “TVA Develops New Wicket Gate Latches,” Hydro Review, November 1998, p. 68.

12. J. A. Norlin, Panel Session (audiotaped): “Rehabilitation II - Lessons Learned,” HydroVision98 Conference, Reno, NV (July 1998).

13. G. Lewis, Panel Session (audiotaped): “Great Ideas in Rehab,” HydroVision 98 Conference,Reno, NV (July 1998).

14. B. Lorenz and U. Baum, “Hydro Modernization: Optimizing Economics at an ExistingPlant,” HRW, September 1997, p. 10.

15. B. D. Foster, “Strategic Hydropower System Rehabilitation,” Proceedings of theInternational Conference on Hydropower, American Society of Civil Engineers, 1997,Volume 2, p. 1507.


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6 EVALUATION, PLANNING, MANAGEMENT, ANDIMPLEMENTATION

Owners of systems having many hydro plants have developed a variety of programs andprocedures for evaluating, planning, managing, and implementing rehabilitations and upgrades.Selected examples are presented.

Approaches to Strategic Management and Planning

Overall Asset Management Program

BC Hydro has developed and is implementing an integrated asset management program. BCHydro’s Asset Management Group has prepared asset management plans for all of BC Hydro’sgenerating facilities. In developing the plant asset plans, management strategies for maintenance,operations, risk, and improvement are documented. The plans identify the improvementopportunities that are most important to profitable operation. The “risk” factors include suchissues as dam safety, lost opportunity, oil spills, seismic damage, and fire. Plant managementteams become the “owners” of—and advocates for—the asset plans. The plant asset plans areintegrated into a “fleet” asset management plan for BC Hydro’s Generation Business Unit.

Improvement projects are prioritized, generally according to economics, but other factors such associal and environmental values are considered as well. The goal is to optimize investmentamong all generation facilities. BC Hydro has identified the energy gains potential from eachcategory of plant improvement, i.e., efficiency improvement, operations improvement, plantredevelopment, reduction of hydraulic losses, increased head, and additional capacity. BC Hydrois working on identifying the costs of “ancillary services” in order that total power services canbe “unbundled” for marketing and sale on the most economically-sound basis possible. [1,2]

Investor-Owned “Utility” Generation Investment Perspective

Competitiveness in generation requires alternative strategies for economic evaluation ofalternative courses of action. Investment is being scrutinized and challenged in the face of largeuncertainty in the future market values of energy, capacity, and ancillary services. Particularly inthe United States, uncertainty concerning the effects of future regulation (licensing) must beaddressed, as well. There are no longer long-term power contracts or guaranteed rates.Disposition of assets must be considered. Conservatism in valuing future benefits, and long-term,life-cycle analyses tied to license expiration or remaining equipment or facility life, are required.


Evaluation, Planning, Management, and Implementation

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A generating asset such as a hydro plant can be categorized as competitive, marginal oruneconomic. A project is “competitive” when anticipated future revenues exceed the total offuture costs plus any unrecovered sunk costs. Continued operation of an “uncompetitive” projectis “economic” when future revenues exceed future costs. For “uneconomic” projects, investmentshould be minimized or avoided, and aggressive cost recovery schemes—including divestitureand decommissioning—should be pursued.

Since there is little certainty of the future, analyses need to be done from a sensitivity or rangeperspective. Facility replacement plans should identify the costs of major equipment andcomponents over the near term. Either future power service values need to be veryconservatively projected or a very short-term capital recovery period should be imposed. Mostattention should be paid to marginal and uneconomic projects, for which the least-cost or least-risk option should be identified. Putting a value on a possible sale or divestiture can be verychallenging, particularly because potential buyers may have entirely different financial structuresand ownership advantages or disadvantages than the present owner. Political and socialconsiderations often influence project disposition. In the United States, the range of possiblelicensing outcomes is a major factor in deciding whether to pursue a new license; approaches toresolve contentious issues early in the relicensing process can be very worthwhile. [3]

Economic Evaluation, Planning, and Prioritization

Risk-Based Analysis of Hydro Improvements

Risk-based analyses are often applied in asset management programs to evaluate unit orcomponent continued maintenance, refurbishment, or replacement. These methods use failure-probability curves where probability of failure is related to component life. Such curves aredeveloped from industry experience. For a specific, existing facility, a condition assessment isperformed. Actual age, remaining life span, and condition are then used to determine currentprobability of failure. Risk and consequence costs are multiplied to estimate the expected cost offailure. An annual cash flow of costs and benefits can then be developed for alternativestrategies, for comparison. Usual alternatives to consider are continued operation as is, focusedor preventative maintenance, instrumentation and condition monitoring, rehabilitation, upgrade,and replacement. [4]

Large System Hydro Improvement Programs

Electricité de France (EDF)

EDF is the largest producer of electricity in the world. Hydro represents about 1/5 of EDF’scapacity. The reliability and flexibility of EDF’s hydro resources are very important. Failure andpoor performance can result in notable operation and economic problems. Half of EDF’s hydrois over 20 years old. EDF has a continuous program of major maintenance and rehabilitation.The technical aspects are effective and straightforward. The challenge is economic—how to dealwith the growing emphasis on competition and cost-effectiveness as well as social responsibility.



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For any proposed rehabilitation, the first step is a thorough evaluation of the effect of the projecton the plant and its operations, costs, and benefits. EDF has identified the following variables:

• Project expenses - external contractors, internal resources, procurement

• Increases in operating expense

• Additional taxes and other derivative expenses

• Expenses from loss of generation

• Increased energy production

• Improved plant efficiency

• Enhanced provision of system services

• Expense savings - reduced maintenance costs, reduced downtime, reduced personnel costs,improved reliability

• Secondary economic gains - improved system reliability, socioeconomic benefits at site,increased downstream water sales

EDF discounts the time series of all costs and benefits (present worth analysis). A rehabilitationor upgrade project is profitable when discounted costs are less than discounted benefits. Thisallows EDF not only to choose among alternatives but also to optimize the timing of a project;postponement in expectation of future increased energy values has been shown in some cases tobe the preferred solution even when “engineering” analysis indicates immediate rehabilitation iswarranted. This approach provides an orderly, consistent way of evaluating and prioritizing themany possible rehabilitation projects at EDF’s hydro facilities in order to maximize the overalleconomic benefit. [5]

Tennessee Valley Authority (TVA)

TVA’s Hydro Modernization Program has designated 88 units for rehabilitation or upgrade, ofwhich 23 units have been completed. The average age of the units in the program is over50 years. The combined capacity of the completed units has increased by a total of 152 MW(average 22% increase), and a 5.7% increase in efficiency has been achieved. All these unitsreceived new runners. The program is re-evaluated annually. Funding for hydro improvementscompetes against funding for thermal generation.

Prioritization of projects within the TVA system is based on equipment condition and upgradepossibilities, as well as economics. TVA relies heavily on model tests in the early phases of aproject to support the economics before committing; the model can then be “tweaked” forimprovements. A “Hydro Modernization Team” plans and designs modernization projects, andan “Outage Management Team” implements and manages the outage. [6,7]

Companhia Energética de São Paulo (CESP)

CESP is a state-controlled, predominately hydro utility in Brazil. CESP has developed acomprehensive approach to evaluating prospective rehabilitation and upgrade projects.Considered are load growth and shape, hydrology, alternative power costs, and trends in



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generating technologies. The product is an investment strategy that cost-effectively determinesthe appropriate level of strategic and peak-load capability for the utility, addresses majormaintenance and upgrade opportunities, and evaluates expansion alternatives. Attributes ofCESP’s system that are important factors in evaluating hydro improvements are that (1) most ofthe utility’s hydro is cascaded, so that events at one plant often affect other plants and (2) floodcontrol and water supply are important functions of the hydro reservoirs.

The 1411-MW Jupiá Plant accounts for 15% of CESP’s capacity. The plant has 14 Kaplan unitsof late 1960s-early 1970s vintage. Due to extensive use, the plant has suffered increasedbreakdowns, primarily in the generators. Outages at Jupiá constrain the operations of upstreamplants with higher hydraulic capacities, increasing the frequency of choosing betweencurtailment or spilling water; these operational constraints have implications for flood control, aswell.

CESP recently evaluated refurbishment, upgrade, and additional units at Jupiá. Economic valueswere assigned to the direct and indirect costs and benefits of the various options. A reservoirmodel with monthly time-step simulations was used in the evaluation. Firm energy was valued atthe cost of system-wide marginal expansion, including long-term and short-term investment, andoperation and maintenance costs. Secondary energy was valued against the price of energy thatcan be obtained from CESP’s federal supplier; this price is less than 10% of the long-term cost.In this way, the value of additional capability and the cost of upgrade outages were determined.The selected option was to upgrade two units per year to gain 22 MW per unit This will help torelieve limitations on upstream plants, increasing the firm energy value. Details of the upgradeare to be determined. [8]

U.S. Army Corps of Engineers (Corps)

The Corps has undertaken numerous rehabilitations and upgrades of its hydro facilities. Each ofthese projects requires a specific appropriation from Congress. Typical projects includerebuilding or replacing turbine runners and rewinding generators; of some 350 generators, theCorps has rewound approximately one-third. The Corps employs extensive risk-based analysis toevaluate potential plant improvements. The risk-based analyses are based on component survivalcurves. [9]

The Corps’ current Major Rehabilitation Program places great emphasis on maintaining andimproving reliability. Projects to improve efficiency are given relatively low priority. The Corpsdefines “hydropower equipment reliability” as

“…the extent to which the generating equipment can be counted on to perform asoriginally intended. This encompasses 1) the confidence in soundness or integrity of theequipment based on maintenance costs and forced outage experience, 2) the output of theequipment in terms of measured energy, power, efficiency, and availability, and 3) thedependability of the equipment in terms of remaining service life (retirement of theequipment).” [10]



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Rehabilitation projects compete for scarce funds and require a uniform method of documentationand justification considering economic, environmental and engineering aspects. Projects arecategorized as: (1) restoring lost efficiency, (2) restoring lost capacity, (3) restoring lostavailability, (4) increasing remaining service life, and (5) improving efficiency. The life cyclebenefits of a major rehabilitation project must exceed the cost, and each component must beincrementally justified. [11] The cost of the Major Rehabilitation Program is expected to reach orexceed $450 million. [9]

The Corps has developed standard techniques to evaluate equipment degradation or deteriorationin order to prioritize repairs and replacements. The rate of change of actual labor and materialscosts (relative to inflation) is an indicator of reliability. Trends for future costs are determinedfrom project records. Replacement of low cost items necessary for production is usually justifiedon this basis alone. Evaluation of efficiency and capacity requires analysis of performance, bytesting. Original and current performance levels are compared to establish degradation.Degradation of availability can be determined from records; continued degradation can be treatedas an objective risk with sufficient supportive information.

The Corps attempts to quantify risk for an objective analysis by estimating annual probabilitiesthat equipment will need to be replaced or rebuilt; this is akin to insurance mortality analyses.Curves based upon “average” experience are adjusted up or down in accordance with a specificcomponent’s Condition Indicator (CI). CI values are assigned to each component based oninspection and test data. CI values in mid-range require no adjustment. A low CI value,indicating “poor condition or worse,” would increase the probability of retirement. The Corps isworking with other large utilities to increase its database for stator windings and turbine runnersand to locate or develop databases for other kinds of equipment, e.g., transformers and circuitbreakers. [10,12]

The Corps continues to review its methods. A risk-based “Major Maintenance andRehabilitation” program for reliability and efficiency improvements at hydro plants has beendeveloped and recommended. [11]

Small Hydro Upgrade Programs in Predominately Thermal Systems

Lower Colorado River Authority (LCRA)

LCRA has an approved, 10-year Hydroelectric Life Extension Program, but requires anextensive evaluation of any individual project before that project is funded. The evaluation ismade on the basis of economic comparison to gas turbines, since LCRA’s hydro plants performthe same peaking role as gas turbines. LCRA works with suppliers to develop 10%+ project costestimates before requesting funding. In general, project payback periods are five years or less.

LCRA reservoir and hydro operations provide water for municipal, agricultural, and industrialuse; in estimating the energy gains from prospective rehabilitation or upgrade projects, wateravailability for hydro generation is modeled from a 50-year record, but “good” water years arediscounted so as to produce a conservative result. Most generation is peaking; water is accountedfor by system controllers as fuel. LCRA is investing in improving the river basin gauging systemin order to improve flow predictability.



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LCRA develops a comprehensive “Project Configuration Document” that identifies all workpackages for each improvement project and assigns responsibilities. This document identifies theroles of all involved personnel and is especially helpful in the frequent event of personnelchangeover. There are significant advantages to having plant operating and maintenancepersonnel heavily involved in hydro rehabilitations or upgrades. [13,14]

Duke Power

Duke Power initiated an upgrade program to transform its fleet of small hydro plants into anefficient, reliable, remotely controlled system that would enhance peaking and ancillary services.Hydro upgrade projects are prioritized on the basis of condition, potential improvement, and theneed to effect river (flow) management. Each hydro improvement project is evaluated andeconomically justified on a unit-by-unit basis before final approval and commitment offunds. [15]

American Electric Power Corporation (AEP)

AEP is a large, predominately fossil-based system with 16 conventional hydro plants and onecombined pumped storage/conventional plant. Most of the conventional plants are small, oldplants that operate essentially run-of-river; a few have limited peaking capability. AEP’s hydromodernization program consists of some 70 capital projects over a 10-year period, prioritized onthe basis of return on investment, payback period, and regulatory requirements. Improvementsimplemented at various plants include: complete replacement of the turbines and generators withpackaged submersible units for reliability, reduction of operating cost, and life extension;replacement of runners at the combined plant for improved performance and additional capacity;and improved controls for remote operation and for meeting environmental and licenserequirements such as run of river operation.

AEP plans ahead five years, with continuing reassessment of its plan; new projects are added tothe list and others are re-prioritized. AEP’s Hydro Group has a budget that complies withcorporate objectives; within the hydro budget, hydro managers determine where resources can bemost effectively applied. The objective is to improve the “hydro system.” The Hydro Group ispart of the Fossil and Hydro Operations organization within Power Production. Thisadministrative arrangement has given the hydro program more visibility within AEP, whileheightening competition for resources. [16,17]

Project Planning and Management

Hydro-Quebec - Beauharnois Plant

The 38-unit, 1666-MW Beauharnois Plant is a very important generating asset to Hydro-Québec.The plant produces approximately 12 million MWh per year, with all available units generatingmost of the time. In the early 1990s, Beauharnois began a C$1,500,000,000 extendedmodernization program that is expected to continue for more than a decade. The emphasis of theprogram is on improving efficiency (more MWh) and safety, and reducing maintenance cost.



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Careful planning is required, with particular attention given to minimizing the loss of generationdue to scheduled outages. The program is reviewed and adjusted annually. Maximum use ismade of in-house forces, with work intensifying during low-flow periods. Design staff areintegrated with field upgrade staff; proximity reduces cost considerably. Beauharnoismanagement has open purchase orders with suppliers up to C$1 million. Thus far, the plant’sannual generation has increased by about 13%, and plant operation and maintenance cost hasbeen reduced by about 35%. [18,19]

Small Plant Upgrade - Washington Water Power (WWP)

WWP’s Nine Mile Hydroelectric Development in Washington State contained four 3.4-MWquad-runner, double draft tube, horizontal Francis units, constructed in 1910. WWP evaluatedsome 200 alternatives for plant rehabilitation and upgrade. The selected scheme was to replacetwo units and to install new or upgraded controls, a new substation, and related equipment. Thecapacity of each replacement unit is about 10 MW. Other improvements were new trashracksand intake gates, replacement of the common gate hoist with individual unit fixed gate hoists forquicker operation of the intake gates, and extension and stabilization of the intake structure.

Economic screening criteria were based on discounted cash flow over a 35-year period.Economic indicators were: Net Present Value (NPV - the total of after-tax cash flows discountedback to present-day dollars using the owner’s weighted average cost of capital); Internal Rate ofReturn (IRR - the discount rate that brings a cash flow back to a zero NPV); and the ProfitabilityIndex (PI - a benefit-cost ratio calculated by dividing the present value of benefits by the presentvalue of the capital costs). IRR and PI are considered the most useful indicators to prioritizeprojects where capital is limited. Total replacement of two units equaled the highest NPV ofalternatives and had the highest IRR.

A detailed schedule was developed identifying over 300 activities, grouped by contract. Theschedule is to be updated at least quarterly. Attention was paid to maintaining existing units online and to consideration of projected river flows. The benefit of a detailed schedule is to betterdefine and identify critical cost items.

WWP served as construction manager; the project involved eight procurement and sixconstruction contracts. The advantages to WWP were to accommodate long lead time equipmentpurchase, to permit in-house forces to install equipment where appropriate, to expand the cross-section of contractors, to increase flexibility, and to enhance application of value engineeringtechniques at different project stages. The result was the economical extension of the life of anold project, with an annual energy increases of about 23%. [20]

Planning a Comprehensive Plant Rehabilitation - Seattle City Light (SCL)

SCL has begun a comprehensive rehabilitation of its Boundary Hydroelectric Project. Theoriginal project, completed in 1967, included four Francis units; two units were added in 1986for a total rated plant capacity of 1051 MW. The plant provides 30 to 45% of the utility’s needsfor generation and has the lowest costs of any SCL generating facility. The BoundaryRehabilitation Program has a estimated cost of $88 million and is scheduled for completionin 2008.



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An SCL task force developed a plan for the comprehensive rehabilitation of the entire project.Planning began with a detailed inspection and assessment of every component of the plant (some1400 in all), complemented by discussions with operation and maintenance staff and review ofdrawings. Basic information and design data, and inspection and testing information andassessments were compiled in an extensive database. A focused, intensive testing and monitoringprogram to complement the information on hand was implemented in 1996; additional detailedtesting will be carried out during the design process as appropriate. The result was a conclusionthat, while the condition of components was acceptable overall, condition was marginal incritical cases and rehabilitation was justified.

Specific maintenance, repair, modification, replacement or upgrade measures wererecommended for 800 of the 1400 items. Redesign of critical systems was required becausecurrent standards were not met; for example, there was insufficient redundancy in station electricservice. Issues were identified that needed to be addressed globally throughout the project(e.g. oil containment, safety lockout, and tagging provisions, and development of as-builtinformation). From these elements was developed a conceptual plan for rehabilitation of theproject.

The Boundary Rehabilitation Program was developed under the City of Seattle’s CapitalImprovement Project (CIP) Program. CIP narratives and budget sheets were developed toconform with the CIP process, including an overall budget through 2008 and a detailed budgetfor the initial 2-year cycle 1997-98. Ultimately, the Program was approved by SCL managementand the City Council.

A project Concept Plan for planning and design was developed by first assessing the 800 workitems and grouping them into some 300 tasks in consideration of optimum work packaging fordesign, procurement, and construction. These tasks were incorporated into the database anddescribed. Among key principles embodied in development of the Concept Plan were that: workwas to be organized by area, i.e., by equipment or system rather than by engineering discipline(39 areas defined); work had to be coordinated with scheduled unit outages; and significantscheduling and design efforts were required at the beginning of the program. The Concept Planallows tasks to be assigned to either SCL, the consultant, or both. The focus is on an extensivedatabase for labor scheduling and costs. As new tasks are defined, the database is updated. [21]

Commercial Arrangements, Procurement, “Partnering”

Many owners of hydro systems are adopting “partnering” arrangements with manufacturers,suppliers and consultants for the procurement and installation of new equipment or for the designor management of modernization projects, in lieu of traditional “arms-length” contracts.Partnering approaches are particularly attractive where the work is non-standard and may entailhidden risk.

Equipment leases can be employed in rehabilitations and upgrades. Typically, an equipmentsupplier (say a generator manufacturer) will install and lease its equipment to the hydro plantowner for a fixed period of time, with ownership to transfer to the owner at the expiration of thelease period. This amounts to a supplier-financing arrangement, in which the supplier rather thanthe owner puts up money up-front.



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Engineering-procurement-construction (EPC) contracts are being used for rehabilitation andupgrades. In EPC, a single entity performs the functions under one agreement. The agreementcould be a standard “arms-length” contract, or the EPC could proceed under a “partnering” typeof arrangement.

Whatever contractual form is employed to provide design, supply, installation, or constructionservices for plant rehabilitation or upgrading, advance planning is advised for the turnover of theequipment from the contractor/supplier to the owner. The owner should have in place therequisite operating and maintenance procedures and be prepared to assume full responsibility forthe unit or component at the agreed-to time. Depending upon the nature of the work, the agreed-to-scope of work should include supplier or manufacturer training of the owner’s operations andmaintenance staff. The article “Q&A: Returning a Unit to Service after Overhaul” in theNovember 1998 issue of Hydro Review may be of relevant interest. [22]

Some owners are requiring suppliers of control or other computer-based equipment to certify thattheir equipment is free of any potential “Y2K” problem. [9]

Sharing Risk between Owner and Supplier

The value of many large rehabilitation or upgrade projects far exceeds the cost of the work.Specifications with large evaluations for efficiency and power drive competing suppliers tostretch guarantees. Some owners will seek to recover lost revenues if equipment fails to meetguarantees, while suppliers need to limit risk in accordance with the value of their contracts. Therelative inaccuracy of prototype acceptance tests further exacerbates the problem. Much effort isnecessary and warranted to develop a specification and contract that is tailored to the specificproject and acceptable to both owner and supplier. Experience with prior projects is the key tocontracting for and executing a successful project. [23]

New Approaches to Funding Government Hydro Improvements (U.S.)

A 1995 policy change by the Bureau of Reclamation regarding its interpretation of existinglegislation allows the agency to accept contributions from its customers to fund hydroimprovements. In Reclamation’s Central Valley Project (CVP), the Shasta Project upgrade isbeing funded through an agreement among Reclamation and its local CVP customer utilities.Reclamation and its CVP customers have also entered into an agreement for customer funding ofCVP operation and maintenance.[24,25] The Corps of Engineers is seeking to establisharrangements with the federal power marketing agencies to fund hydro improvementprojects. [26]

Tennessee Valley Authority (TVA)

TVA has had a favorable experience partnering with key suppliers in hydro rehabilitations andupgrades. Partnering allows the parties to adopt and commit to common goals and strategies, forthe mutual good. Partnering agreements are initially competed for by a bidding process, and ratesand prices for individual work packages are negotiated. There are provisions for monetarybonuses and penalties for the supplier. Benefits are shared when an improvement target isexceeded. A long-time problem has been agreement on turbine acceptance criteria and testing;TVA is making progress negotiating this issue with its turbine manufacturer partner. [7]



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BC Hydro

Since 1995, BC Hydro has had a partnering arrangement with a major supplier of hydro turbinesand generators for an expected 1995 value of C$150 million of improvement work. Thearrangement includes 70% of all work related to turbines in upgrades and to turbines andgenerators in additions. BC Hydro selected its partner following negotiations with threemanufacturers who were invited to submit proposals based on expressions of interest. BC Hydrobelieves that the arrangement thus far has proven beneficial; they have been able to negotiatesome very fair prices. The arrangement does not provide for bonuses or incentives to thesupplier. [2,27]

U.S. Army Corps of Engineers (Corps)

The Corps frequently partners with its construction contractors. This approach has been verysuccessful; as of 1995, partnering had been employed some 150 times with no resultinglitigation. Partnering is also suggested with respect to the participation of interest groups in theCorps’ waterpower development projects and has been used to resolve environmental conflicts,and in technology transfer programs.

The Corps views “partnering” as:

“…the creation of a relationship that promotes achievement of mutually beneficial goals.It involves an agreement in principle to share the risks involved in completing a project,and to establish and promote a nurturing partnership environment. … [Partnering] doesnot create any legally enforceable rights or duties.” [28]

Partnering success depends upon cooperation and teamwork, and upon the personalcommitments of the individuals comprising the project management team. Partners shoulddevelop a joint statement of goals and common objectives. Processes to resolve disputes, headoff problems, and evaluate performance should be identified. [28]

Lower Colorado River Authority (LCRA)

LCRA partners with its major suppliers, including its hydroturbine supplier. The partneringarrangements are under service agreements. LCRA and its partners share the risk involved ineach project. LCRA is very pleased with partnering, believing that partnering results in reducedcost to LCRA in the long run, including consideration of “down time.” Terms and conditions arenegotiated before proceeding. Typically, penalties (liquidated damages) are assessed for failureto meet deadlines, and bonuses are awarded for exceeding guaranteed performance. [13]

LCRA’s partnership agreement with its turbine supplier has applied to the upgrading of the Inksand Buchanan projects. Inks Unit 1 was upgraded during 1992-1997; the work included a turbinerunner replacement, generator rewinding, and replacement of the governor, switchgear, and theplant lighting system, at a cost of $6.4 million. The upgrade increased the capacity of Unit 1 to14.9 MW, from 11.5 MW. The Buchanan upgrade is underway, scheduled for completion in1999; the planned work elements include the replacement of the turbine runners, generatorrewinding, and replacement of the governors for Units 1 and 2, and the replacement of plant



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switchgear and the lighting system. The estimated cost of the Buchanan work is $11.5 million;the capacities of Units 1 and 2 are expected to increase to 16.9 MW, from 12.5 MW. LCRA hadaccomplished a similar upgrading of its Austin project Units 1 and 2 in 1988-1994, prior to thepartnership agreement; the combined capacity of the two units increased to 17.3 MW, from15.0 MW. The Austin upgrade cost $10.4 million. [14]

Landsvirkjun - Partnering in an Expedited Repowering

Landsvirkjun provides 93% of Iceland’s generation, most of it from hydro. The utility faces arapidly growing power demand due to industrial load growth, and so repowered the BúrfellHydro Plant on a fast-track schedule. The Búrfell upgrade was challenging with respect both totime and hydraulic constraints.

The Búrfell Plant was constructed in 1969-72 with six units and a total initial capacity of210 MW. With increased flow diverted into the river, Búrfell had become a bottleneck. In 1990,a planned 100-MW expansion was postponed in favor of a plan for a major upgrading. In 1991,the six generator stators were rewound to a rating of 46 MVA. The process of upgrading the sixturbines began in 1995. The upgrade included new runners, with the existing casings to be used.Study indicated that maximum power and flow would be limited by penstock transient pressuresand the generator ratings, so it was decided to further increase generator output to 50 MW.

The turbine manufacturer has developed loss analysis software based on a large model data base;combining the results of this program with CFD allows development of a “’virtual’ prototype hillcurve” without homologous modeling. When Landsvirkjun’s rising power demand dictated ashorter implementation time for the project, it was decided to forgo the homologous model infavor of design solely by CFD, with the constraints that wicket gate height, length of runnerband, and runner diameter could not be altered. The existing draft tubes were not optimum, sothe runner and draft tube interaction had to be modeled together with CFD. Manufacturingengineering was begun before completion of the CFD analyses. Then, it became obvious thatmodification of the draft tube would be beneficial. In order to determine the effects of draft tubemodification on efficiency, it was decided to perform a model test focusing on the low pressureside of the turbine. The model was homologous with respect to the runner and draft tube but notwith respect to upstream components. Many engineering steps continued in parallel with the“semi-homologous” model tests. The tests confirmed the CFD runner design and fixed the drafttube modification. Combining the use of CFD with the semi-homologous model test savedcritical time in the schedule. The pressure of time was met by a trustful, extremely cooperative,flexible relationship between owner and supplier. [29]

Ontario Hydro (OH)

OH typically contracts for hydro equipment in the traditional way. Contracts with turbinesuppliers provide for penalties for failure to (1) meet model development or runner deliveryschedule or (2) achieve specific model or prototype performance. Bonuses are paid if modelperformance exceeds the guaranteed weighted mean efficiency; the formula for weighted meanefficiency is specified in the contracts. [30]



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Lessons Learned

• There are many instances where rehabilitation or upgrade seems to make engineering sensebut cannot be justified economically. In such cases, the optimum course may be to continueroutine operation and maintenance; the merits of rehabilitation or upgrading may beevaluated at a future date if and when there is an increase in forecasted energy and capacityvalues. In some cases, the economic course may be to continue operation with minimalmaintenance until equipment fails, followed by abandonment or decommissioning.

• Future uncertainty should be recognized in hydro planning and economic analysis byadopting a life cycle economic approach with considerable sensitivity analysis.

• In today’s changing market for generation and related services, owners of generationfacilities need to be very flexible and to deal with uncertainty in managing assets and assetinvestment. Significant risk must be assumed. It is not a “given” that investing or spending toincrease hydro energy production is the optimum action.

• The cost of lost generation and capacity during hydro rehabilitation and upgrade projects canbe considerable and should be taken into account in project justification and planning.

• Adoption of a system approach to hydro upgrades focused on optimizing the “use ofresources” can avoid some of the competition for funding with other “company” programs.Viewing rivers as subsystems should be encouraged, in order to optimize the use of theresource within license and good stewardship constraints.

• Particularly for upgrades designed to increase capacity (power), a complete system analysisshould be made, checking each component for “weak links.” The resulting plant or unitcapacity will be determined by the “weakest” component and could be limited by acomponent or device that would have been relatively inexpensive to upgrade or replace at thetime of the capacity upgrade.

• Each step of a project should be thoroughly thought through, with attention to detail. Beprepared for anything to go wrong. Experience has shown that seemingly insignificant itemscan cause delay and cost.

• Specifications should provide for the testing, removal, and proper disposal of lead paint “justin case;” don’t assume that all the lead paint on the original equipment has been erodedaway.

• Many references and contributors stressed the advantages of involving regular operations andmaintenance staff in the planning and execution of rehabilitations and upgrades. This willenhance the staff’s acceptance and understanding. If operations and maintenance personnelhave time to study the equipment, they can often be very effective at finding solutions andimprovements. Employee recognition or awards programs for offering ideas and suggestionshave proven to be beneficial.

• Large organizations should involve their procurement staff in improvement projects veryearly in the planning process, in order to ensure that quality is adequately valued inprocurement.

• Up-to-date drawings of plant structures, equipment, and systems should be assembled andmade available at the onset of a rehabilitation or upgrade project.



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• Documents pertinent to a rehabilitation or upgrade should be centrally located and secured.Make sure that someone on the project team is responsible for document management.Develop a uniform file system, preferably electronic, that applies to all projects.

• Think about data management; an infinite amount of data can be obtained, but the amount ofdata can be overwhelming and is not all needed.

• Involve dispatching people in rehabilitation and upgrade projects, so that they understand thecapabilities of the equipment and the special requirements that may exist as to river (flow)management.

• Integrate design and field staffs for maximum effectiveness and efficiency.

• Provide adequate operator training before an upgraded unit or component is returned toservice.

• Celebrate success with all involved personnel.

• An owner acting as its own “general contractor” is responsible for and must pay specialattention to staffing and scheduling.

• Supplier proposals and bids should be thoroughly evaluated by an owner representativeproficient in the type of work and familiar with the equipment; eliminating misunderstandingor uncertainty before the work is awarded will minimize the need for costly post-awardchanges.

• Resolve any potential problems with suppliers regarding equipment performance verificationas early as possible.

• The use of liquidated damages (but not bonuses) in Pelton turbine rehabilitations is sufficientto get the best result.

• Include provisions in supply contracts for protection from “Y2K” problems.

• Teamwork among consultant, owner, and contractor or supplier is extremely important.

• Designate a single individual (project manager) as the focal point for all parties; theindividual should be dedicated to keeping the job moving smoothly and on schedule andbudget.

• Where there is “customer participation” or other outside interest in a project, keeping allparties informed of progress and direction is very important to sustain their support.

• Pay attention to the disconnection and reconnection of “common” systems that serve otherunits or components.

• Be wary of repairing or retrofitting parts of systems. The cost of a few such repairs canexceed the cost to replace the entire system.

References

1. N. M. Nielsen and N. M. Hawley, “Developing a Strategy for Meeting Competition’sChallenges,” Hydro Review, April 1998, p. 26.

2. N. M. Hawley and N. M. Nielsen, BC Hydro, personal communication, October 1998.



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3. S. C. Lubben, “Hydro Economics in Light of Industry Restructuring,” Proceedings of theInternational Conference on Hydropower, American Society of Civil Engineers, 1997,Volume 1, p. 321.

4. H. W. de Meel, “Risk-Based Asset Management,” Paper presented at HydroVision 98Conference, Reno, NV (July 1998).

5. M. Dupuy, “Hydro Refurbishments: Making the Economic Choice,” HRW, Winter 1995,p. 10.

6. L. D. Chapman, “Lessons Learned and the Rehabilitation of the Historic Norris HydroPlant,” Proceedings of the International Conference on Hydropower, American Society ofCivil Engineers, 1997, Volume 3, p. 1704.

7. L. D. Chapman, Tennessee Valley Authority, personal communication, October 1998.

8. D. S. Ramos, P. H. Marques, and J. G. Mazzon, “Finding Economically Sound HydroUpgrade Opportunities,” HRW, October 1996, p. 10.

9. J. A. Norlin, Panel Session (audiotaped): “Rehabilitation II - Lessons Learned,”Hydro Vision 98 Conference, Reno, NV (July 1998).

10. J. A. Norlin, “Reliability Analysis of Hydropower Equipment,” Proceedings of theInternational Conference on Hydropower, American Society of Civil Engineers, 1993,Volume 1, p. 47.

11. T. Vo, J. Norlin, B. Mahan, and D. Moser, “Risk-based Applications for Maintenance andRehabilitation at Hydroelectric Generating Stations,” Proceedings of the InternationalConference on Hydropower, American Society of Civil Engineers, 1997, Volume 3, p. 1659.

12. J. A. Norlin, “Hydropower Major Rehabilitation Projects,” Proceedings of the InternationalConference on Hydropower, American Society of Civil Engineers, 1995, Volume 3, p. 2129.

13. B. D. Foster, Lower Colorado River Authority, personal communication, October 1998.

14. B. D. Foster, “Hydro Rehab: Committing to the Future,” Hydro Review, February 1998,p. 10.

15. G. Lewis, Panel Session (audiotaped): “Great Ideas in Rehab.” HydroVision 98 Conference,Reno, NV (July 1998).

16. M. Bahleda, Panel Session (audiotaped): “Great Ideas in Rehab,” HydroVision 98Conference, Reno, NV (July 1998).

17. M. Bahleda, American Electric Power Service Corporation, personal communication,October-November 1998.

18. G. Leroux, “Preserving the Past, Securing the Future at Beauharnois,” Hydro Review,December 1997, p. SR2.



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19. G. Leroux, Panel Session (audiotaped): “Rehabilitation II - Lessons Learned,” HydroVision 98 Conference, Reno, NV (July 1998).

20. J. A. Kurras, R. Zilar, E. Schlect, R. A. Hokenson, and J. H. Rutherford, “Re-powering NineMile Hydroelectric Project,” Proceedings of the International Conference on Hydropower,American Society of Civil Engineers, 1993, Volume 3, p. 1584.

21. S. J. Hayes and V. M. Kobayashi, “Conceptual Planning for Rehabilitation of the BoundaryHydroelectric Project,” Proceedings of the International Conference on Hydropower,American Society of Civil Engineers, 1997, Volume 3, p. 1694.

22. “Q&A: Returning a Unit to Service after Overhaul,” Hydro Review, November 1998, p. 82.

23. W. H. Colwill, American Hydro Corporation, personal communication, October 1998.

24. M. A. Bauer and C. Millet, “Project Spotlight: Uprating Generators at Shasta Powerplant,”Hydro Review, August 1998, p. 104.

25. M. A. Bauer, U.S. Bureau of Reclamation, personal communication, October 1998.

26. C. L. Chapman, Panel Session (audiotaped): “Rehabilitation II - Lessons Learned,”HydroVision 98 Conference, Reno, NV (July 1998).

27. N. M. Nielsen, “Upgrades and Additions to BC Hydro’s Powerplants with a ManufacturingPartner?,” Concepts for the Future, HCI Publications, 1994, p. 113.

28. B. S. Price, “A Case for Partnering to Maximize Waterpower Development,” Proceedings ofthe International Conference on Hydropower, American Society of Civil Engineers, 1993,Volume 1, p. 613.

29. G. Gislason, M. Haas and M. Sallaberger, “Upgrading of Búrfell Hydro Powerplant: SuccessBased on Flexibility and Cooperation,” Paper presented at HydroVision 98 Conference,Reno, NV (July 1998).

30. D. C. Kee, Ontario Hydro, personal communication, October-November 1998.


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A CONTACT-LIST

Owners

Alabama Power Co. Birmingham, Alabama 205-250-1000

Alaska Industrial Development Anchorage, Alaska 907-269-3000and Export Authority

AmerenUE St. Louis, Missouri 314-554-2873

American Electric Power Corp. Columbus, Ohio 614-223-1000

BC Hydro Burnaby, British Columbia 604-528-1600

California Water Project Sacramento, California 916-653-4313

Companhia Energética de BrazilSão Paulo

Czech Power Company CEZ, a.s. Czech Republic

Duke Power Charlotte, North Carolina 704-594-0887

Electricité de France France

Grand River Dam Authority Vinita, Oklahoma 918-256-5545

Hetch Hetchy Water and Power Moccasin, California 209-989-2130

Hydro-Québec Montreal, Québec 514-289-2211

Landsvirkjun Iceland

Los Angeles Dept. of Water & Los Angeles, California 213-481-4211Power

Lower Colorado River Authority Austin, Texas 512-473-3200

New York Power Authority White Plains, New York 212-468-6000


Contact-List

A-2

Niagara Mohawk Power Corp. Syracuse, New York 315-474-1511

Northern States Power Eau Claire, Wisconsin 715-839-2962

Northwestern Wisconsin Grantsburg, Wisconsin 715-463-5371Electric Co.

Ontario Hydro Toronto, Ontario 416-592-5711

Oroville-Wyandotte Irrigation Oroville, California 916-534-1221District

PacifiCorp Portland, Oregon 503-731-2000

PECO Energy Darlington, Maryland 410-457-2700

Public Utility District No. 1 Wenatchee, Washington 509-663-8121of Chelan County

Public Utility District No. 2 Ephrata, Washington 509-754-3541of Grant County

Rheinkraftwerk Säckingen AG Germany

Seattle City Light Seattle, Washington 206-625-3000

Southern California Edison Co. Rosemead, California 818-302-1212

Stora Power AB Sweden

Tafjord Power Co. Norway

Tennessee Valley Authority Chattanooga, Tennessee 423-751-0011

U.S. Army Corps of Engineers, Portland, Oregon 503-808-4200Hydroelectric Design Center

U.S. Bureau of Reclamation Denver, Colorado 303-236-3292

Vattenfall Sweden

Washington Water Power Spokane, Washington 509-489-0500


Contact-List

A-3

Suppliers - Turbines

Alstom Electromechanical Aurora, Colorado 888-342-5522(formerly GEC Alsthom)

American Hydro Corp. York, Pennsylvania 717-755-5300

CKD Blansko Engineering, a.s. Blansko, Czech Republic

General Electric Canada Inc. Québec, Québec 514-485-4049

Hitachi America, LTD. Tarrytown, New York 914-524-6640

Kvaener Hydro Power, Inc. San Francisco, California 415-392-6461

Sulzer USA Inc. San Francisco, California 415-441-7230

Voest-Alpine M.C.E. Salisbury, North Carolina 704-647-9276

Voith Hydro, Inc. York, Pennsylvania 717-792-7000

Suppliers - Generators

ABB Power Generation Inc. Littleton, Colorado 303-730-4000

Alstom Electromechanical Aurora, Colorado 888-342-5522(formerly GEC Alsthom)

General Electric Canada Inc. Québec, Québec 514-485-4049

Hitachi America LTD. Tarrytown, New York 914-524-6640

National Electric Coil Columbus, Ohio 614-488-1151

Siemens Westinghouse Milwaukee, Wisconsin 414-475-3358

Suppliers - Governors and Controls

ABB Power Generation, Inc. Denver, Colorado 303-730-4000

Hitachi America, LTD. Tarrytown, New York 914-524-6640

Sulzer Hydro Ltd. Switzerland

Toshiba International Corp. San Francisco, California 650-737-6672

Woodward Governor Co. Loveland, Colorado 970-962-7518