TECHNICAL AND ECONOMIC ASSESSMEPlT OF SOLAR HYBRID 

REPOWERING 

Final Report 

September I 978 

Work Perfwd Under Contract No. EG-77-CO3-1608 

Public Service Company of New Mexico 

Albuquerque, New Mexico 

U.S. Department of Energy 

Solar Energy 
DISCLAIMER 

This report was prepared as an account of work sponsored by an 

agency of the United States Government. Neither the United States 

Government nor any agency Thereof, nor any of their employees, 

makes any warranty, express or implied, or assumes any legal 

liability or responsibility for the accuracy, completeness, or 

usefulness of any information, apparatus, product, or process 

disclosed, or represents that its use would not infringe privately 

owned rights. Reference herein to any specific commercial product, 

process, or service by trade name, trademark, manufacturer, or 

otherwise does not necessarily constitute or imply its endorsement, 

recommendation, or favoring by the United States Government or any 

agency thereof. The views and opinions of authors expressed herein 

do not necessarily state or reflect those of the United States 

Government or any agency thereof. 
DISCLAIMER 

Portions of this document may be illegible in 

electronic image products. Images are produced 

from the best available original document. 
NOTICE 

l%i& wort haL htsfi rap~odussd diced@ from the boat avd&b wpy. 

Ri: Paptr Copy 3 1 6.25 

Rfil~ruT& $3X30 
SAN 11 608-4-1 

Distribution Category UC-62 

TECHNICAL AND ECONOMIC ASSESSMENT 

0 F 

SOLAR HYBRID REPOWERING 

FINAL REPORT 

Prepared for the 

U.S. DEPARTMENT OF ENERGY 

as Part of 

Contract No. EG-77-C-03-1608 

PUBLIC SERVICE COMPANY 

OF KEbi T:IEXICC 

SEPTEI :EER 1978 
ACKNOWLEDGMENTS 

Public Service Company of New Mexico wishes to acknowledge the following persons for their valuable guidance and direction in conducting 

this study: Mr. Bob Hughey, Department of Energy-San Francisco; 

Mr. S. D. Elliott, Department of Energy-San Francisco; Mr. A. C. Skinrood, Sandi'a Livermore; and Mr. L. Radosevich, Sandia Livermore. 

Public Service Company of New Mexico also wishes to acknowledge the 

many Company employees who dedicated time and effort to the successful 

completion of this study, as well as the employees of two major subcontractors: Steanns-Roger Engineering Co., Mr. W. R. Lang - Project 

Manager; and Westinghouse Electric Corporation, Mr. W. G. Parker - 

Project Manager. 
TABLE OF CONTENTS 

Section ' Tit1 e 

1 .O INTRODUCTION AND SUMWRY 

1.1 Market Survey and Cost Benefit Analysis 

1.2 Study Unit Selection 

1.3 Conceptual Design and Cost Estimate 

1.4 Unit Economic Analysis 

1.5 program Planning, Future Phase 

2.0 MARKET SURVEY AND COST BENEFIT ANALYSIS 

2.1 Market Survey Description 

2.2 lltility Interest 

2.3 Solar Repowering Potential in the Southwest 

2.3.1 Overview of Solar Repowering Potential 

2.3.2 Detailed Survey Resul ts on Sol'ar Repowering 

Po ten ti a1 

2.3.3 Extension of Survey to Units Above 200 MWe 

2.4 Candidate Repowering Unit Description 

2.4.1 Candidate Repowering Unit Description Overvjew 

2.4.2 Survey Results for Candidate Repowering Unit 

Description 

2.5 Cos t/Bene fi t Analysis 

2.5.1 Methodology 

2.5.2 Reference Plant Description 

2.5.3 Economic Analysis Basis 

2.5.4 Utility System Assumptions 

2.5.5 PNM System Analysis Results 

2.5.6 APS System Analysis Results 

2.5.7 NPC System Analysis Results 

2.5.8 EPRI Synthetic Utility System E Analysis 

Res ul ts 

Page No. 

1-1 

1-3 

1-9 

1-1 1 

1-14 

1-16 
TABLE OF CONTENTS (Continued) 

Section 

3.0 

Ti tl e 

STUDY UNIT SELECTION 

3.1 Repowering Method Assessment 

3.2 Candidate PNM Units 

3.3 Power Production Considerations 

3.4 Generation Planning Considerations 

3.5 Envi ronmen tal Consi derations . 

3.6 Safety Considerations 

3.7 Study Uni t 

3.8 Site Description 

3.8.1 Insolation 

3.8.2 Precipitation 

3.8.3 Winds 

3.8.4 'Topography, Vegetation and Hydro1 ogy 

3.8.5 Seismic S tabi 1 i ty 

3.8.6 Accessibility 

3.8.7 Arca (Land Availability) 

3.8.8 Zoning and Land Use 

3.8.9 Soils Investigation 

CONCEPTUAL DESI GN 

4.1 Existing Mechanical and Electrical Plant Facil i ties 

4.2 Mechanical Design 

4.2.1 Solar System Design 

4.2.1.1 System Description and Major 

Interfaces 

4.2.1.2 Receiver Descru'iption 

4.2.1 .3 Collectors : Description 

4.2.1 -4 Receiver Feedwater Heaters 

4..2.1.5 Receiver Feed Pumps 

4.2.1.6 condensate Hotwell Pumps 

4.2.1 .7 Piping Design, and Analysis 

4.2.2 Modifications to Existing Equipment 

4.2.2.1 Heat Balances 

Page No. 
TABLE OF CONTENTS (Continued) 

Section Ti tl e 

4.2.2.2 Code Review 

4.2.2.3 Piping Interface. Design 

4.2.2.4 Equipment and Motor List 

4.2.2.5 Auxiliary Power Requirements 

4.2.2.6 Turbine Generator 

4.2.2.7 General Arrangement - EPGS 

4.2.3 Facili,ties Review 

4.2.3.1 Water Treatment 

4.2.3.2 Bearing Cooling Water 

4.2.3.3 Fire Protection 

4.2.3.4 Heating, Ventilation and Air 

Conditioning 

4.2.4 Systems Operation 

4.2.4.1 Integration of Solar Systems with 

Balance of Plant 

4.2.4.2 Solar Receiver/Fossil Fuel Boiler 

Transient Interaction 

4.2.4.3 StartupIShutdown Procedures 

4.2.4.4 Solar Subsystem Maintenance 

4.2.4.5 Present Plant Maintenance 

4.3 Controls and Instrumentation Design 

4.3.1 Solar Control Design 

4.3.1 .1 Control System Design Approach 

4.3.1 .2 Principal Control Systems 

4.3.2 Plant Modifications for Control 

4.3.2.1 Control Room Modifications 

4.3.2.2 Computer Room Addition 

4.3.2.3 Logic Equipment Room Addition 

4.3.2.4 Boiler and Combustion Control, 

Modi fi cations 

4.3.2.5 Turbine Control System 

4.3.2.6 Plant Instrumen tation Addi tions and 

Modi fi cations 

Page No. 

4-70 

4-72 

4-72 

4- 72 

4-80 

4'-82 

4-85 

4m85 

4- 94 

4- 95 

4-96 
TABLE OF CONTENTS (Continued) 

Section Ti tl e Page No. 

4.3.3. Concl usions and Summary 

4.3.3.1 Demonstration Plant Controls Versus 

Commerci a1 Pl ant Control s 

4.3.3.2 Repowering Control System- Conclusions and Summary 

4.4 Electrical Design 

4.4.1 Solar Portion of Design 

4.4.1.1 Puwer to Hellostats 

4.4.1.2 Heliostat Switching Units 

4.4.1.3 He1 iostat Transformers 

4.4.1.4 Heliostat Distribution panels 

' 4.4.2 Modifications to Existing Equipment 

4.4.2.1 480 Volt Load Center 

4.4.2.2 Tie to start Up Transformer 2A 

4.4.2.3 Solar Auxiliary Transformer Primary 

4.4.3 Additions of Electrical Equipment 

4.4.3.1 2.4 KV Metal Clad Switchgear 

4.3 Solar Auxiliar-y Tr-at~sror~~~~er S2 

4.4.3.3 480 Volt Solar Load Center 28 

4.4.3.4 480 Volt Motor Control Center 

4.4.3.5 Emergency Dicscl Ger~et-atsr 

4.4.3.6 Further Considerations on Emergency 

Power 

4.4.3.7 Miscellaneous Lighting Transformers 

and Panels 

4.4.3.8 Miscellaneous reed for Aux,il idries 

4.4.3.9 Cable Tray System 

4.4.3.10 Control 

4.4.3.11 Uninterruptible Power System 

4.4.3.12 Lighting 

4.4.3.13 Grounding 

4.4.3.14 Lightning Protection 

4.4.4 Lead Time Requi rements 

4.4.5 Code and Legal Requirements 
TABLE OF CONTENTS (Continued) 

Section ,Ti tle 

4.5 Civil , Structural , Architectural Design 

4.5.1 Subsoil Considerations 

4.5.1.1 Site Location and Conditions 

4.5.1.2 Subsoil Conditions 

4.5.1.3 General Considerations 

4.5.1.4 Foundations for Operating Units 

4.5.2 Foundation and Structural Design 

4.5.2.1 Heliostat Foundations 

4.5.2.2 Receiver Tower and Foundation 

4.5.3 Field Sizing and Shape 

4.5.4 Civil Site Design 

4.5.4.1 Heliostat Fie1 d Layout 

4.5.4.2 Site Design Considerations 

4.5.4.3 Flood Control 

4.6 Plant Performance--Sol ar ,Performance 

4.6.1 Development of the Conceptual Design 

4.6.2 Parametric Analyses 

4.7 Conceptual Design Cost Estimate 

4.8 Environmental Considerations 

4.8.1 Summary of Environmental Considerations 

4.8.2 Environmental Site Description 

4.8.2.1 Site Location 

4.8.2.2 Physiography 

4.8.2.3 Geology and Mineral Resources 

4.8.2.4 Seismology 

4.8.2.5 Soils 

4.8.2.6 Hydrology 

4.8.2.7 Ecology 

4.8.2.8 Climatology 

4.8.2.9 Land Ownership and Land Use 

4.8.2.10 Transportation 

Page No. 

4-1 95 

4-1 95 

4r.1 95 

4-1 95 

4-1 95 

4-1 96 

4-1 96 

4-1 96 
TABLE OF CONTENTS (Continued) 

Section Title 

4.8.2.11 Historical and Archaeological Sites 

4.8.2.12 Demography and Socioeconomics 

4.8.2.13 Ambient Sound Levels 

4.8.3 Environmental Impacts of Construction 

4.8.3.1 Effects on Air Quality 

4.8.3.2 Effects of Sound 

4.8.3.3 Effects on Land Use 

4.8.3.4 Ecological Effects 

4.8.3.5 Hydrological Effects 

4.8.3.6 Social and Cultural Effects 

4.8.4 Environmental Impacts of Operation 

4.8.4.1 Effects on Air Quality 

4.8.4.2 Effects of Sound 

4.8.4.3 Effects on Land Use 

4.8.4.4 Ecological Effects 

4.8.4.5 Hydrological Effects 

4--8.4.6 Social and Cultural Effects 

4.8.4.7 Aesthetic tffects 

4.9 Safety Considerations 

4.9.1 Objectives 

4.9.2 DesSgii Guide1 i nes 

4.9.3 Safety Hazard Category Definitions 

4.9.4 Solar Refl~ctance Hazards 

4.10 Preliminary Notes on Insolation Prediction for Solar 

Electric Power Plants 

4.10.1 The Need for Look-Ahead Requirements 

4.10.2 Factors Control 1 iny Insolat~ion 

4.1 0.3 Charac,Leristics of Clouds 

4.1 0.4 Short Terin Look-Ahead Systems 

4.10.5 Intermediate Term Look-Ahead Systems 

4.10.6 Long-Range Look-Ahead Systems 

Page No. 

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4-280 

4-281 

4-281 

4-281 

4-282 

4-282 

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4-283 

4-283 

4-285 

4-285 

4-297 

4-297 

4-297 

4--299 

4-302 

4-302 

4-303 

4-307 

4-308 

4-31 1 

4-31 1 

4-31 4 
TABLE OF CONTENTS (Continued) 

Section Title 

5.0 UNIT ECONOMIC ANALYSIS 

5.1 Unit Description 

5.2 Economic Basis 

5.3 PNM System Description 

5.4 Results 

6.0 PROGRAM PLANNING, FUTURE PHASES 

6.1 Objective 

6.2 Project and Major Task Descriptions 

6.3 Management Plan 

6.3.1 Work Breakdown Structure 

6.3.2 Program Plan 

6.3.3 Reporting 

6.3.4 Budgetary Cost Estimates 

6.3.5 Financial Incentives 

APPENDIX A: Survey Letter and Questionnaire 

APPENDIX B: Economic Analysis Methodology 

APPENDIX 'C: References 

Page No. 

5- 1 

5-2 

5-5 

5- 9 

5-1 0 
LIST OF ILLUSTRATIONS 

Figure No. Ti tl e ------. Page No. 

1.5-1 Milestone Schedule for the Proposed Program 1-18 

2.3-1 Candidate Units for Solar Hybrid Repowering (Southwestern 2-12 

United States 

2.5-1 Model Usage Flow 2-30 

2.5-2 Solar Hybrid Repowering Model for Cost/Benefit Analysis 2-31 

2.5-3 PNM Generation Mix and Typical Daily Load Curves 2-45 

2.5-4 APS Generation Mix and Typical Daily Load Curves 2-46 

Solar Feedwater Heating (solar Hybrid Repowering Study) 

Solar Evaporation and Supherheating su oil er Replacement) 

Brayton Cycle Repowering 

Combined Cycl e Repoweri ng 

Location of Candidate Units 

Sf te A1 ternative #1 , Reeves Station 

Site Alternative #2, Person Station 

Albuquerque Support/Person Station Area 

Predicted.U.S. Insolation Variations 

Direct Normal Solar Radiation Observed at Albuquerque, 

New Mexico 

System Powcr Flow (2:OO p.m. Winter Sol stice) 

Sys tem Power Flow (N~CJII, Sur~~~ner. Sul s ti ce) 

Operating Modes, Reeves Station Unit No. 2 

Operating Modes--Reeves Station Unit No. 2 

4.2-5 Control System Functional Analysis (3 pages) 

4.2-6 Reeves Station Unit No. 2 Schematic 

4.2-7 Receiver Weight Comparison 
LIST OF ILLUSTRATIONS (Continued) 

Figure No. 

4.2-8 

4.2-9 

4.2-10 

4.2-1 1 

4.2-1 2 

4.2-13 ' 

4.2- 14 

4.2-15 

4.2-16 

4.2-17 

4.2-1 8 

4.2-19 

4.2-20 

4.2-21 

4.2-22 

4.2-23 

4.2-24 

4.2-25 

4.2-26 

4.2-27 

4.2-28 

4.2-29 

4.2-30 

4.2-31 

4.2-32 

4.2-33 

4.2-34 

4.2-35 

4.2- 36 

4.2-37 

4.2-38 

Title 

Receiver Feedwater Piping Costs 

Receiver Steam Piping Costs 

Stress Analysis - Main Steam Line 

Recommended Con fi guration 

Steam/Feedwa ter Pi ping Desi gn Summary 

Genera tor Losses 

Exhaust and Mechanical Losses 

Tabul ation of Heat Bal ance Computations 

Heat Balance Tabul ation 

Diagram A ( Con tin ued) 

Diagram A (Continued) 

Diagram A (Continued) 

Heat Balance Diagram 

Heat Bal!ance Diagram 

Heat Balance Diagram 

Heat Bal ance Di agram 

Heat Bal ance Di agram 

.Heat Bal ance Diagram 

T/G Sys tem performance 

Water Sampling and Monitoring System 

Fossil Boiler Steam Temperature Droop 

Fossil Boiler Steam Temperature Droop 

Receiver Piping Warmup Analysis Nnde Points 

Receiver Steam Line Warmup Time 

Simp1 i fied Bl ock Diagram 

100 Percent Transient Summer Solstice 

50 Percent Transient Summer Solstice 

10 Percent Transient Summer Solst'ice 

100 Percent Transient. 25 MWe Solar - 25 We Fossil 

50 Percent Transient 25 We Solar - 25 Me Fossil 

10% Transient 25 MWe Solar - 25 MWe Fossil 

Page No. 

4-40 

4-41 

4-46 

4-48 

4-51 

4-53 

4-57 

4- 58 

4-59 

4-60 

4-61 

4-62 

4-63 

4-64 

4-65 

4-66 

4-67 

4-68 

4-69 

4-92 

4-1 04 

4-1 06 

4-1 15 

4- 116 

4-1 23 

4-1 24 

4-1 25 

4-1 26 

4-1 27 

4-1 28 

4-1 29 
LIST OF ILLUSTRATIONS (Continued) 

Figure No. 

4.3-2 

Title 

Solar Hybrid Repowering Control System 

Control and Monitoring Systems Interface 

Solar Power Plant Computer System 

Distributed Analog Control Loop Elements 

El ectroni c-Pneumati c Interface 

Steam Temperature Control 

Throttle Pressure Control 

Receiver Feed Pump Control 

Col lector Subsystem Control Architecture 

Receiver Subsystem Instrumentation and Control 

Architecture 

Recei ver Subsystem Control Schemati c 

Reeves Station Control Room 

Control Panel Addi tions 

Logi c Room 

Demonstration Master Control Sys tern 

Commerci a1 Master Control System 

4.4-1 ~unctional Diagram - Overall Plant Power and 

Distribution 

4.4-2 .He1 iostat Field Power Diagram 

1 ./l .3 Ur1.i rrtei-ruptabl e Power Syste~n 

Page No. 

4-1 46 

4-1 47 

4-1 84 

4-1 54 

4-1 58 

4-1 60 

4-1 61 

4-1 63 

4-1 65 

4-1 67 

4.5- 1 Concrete' Receiving Tower 4-1 39 

4.5-2 100-Year.,, Six Huur- PrSeclpl tatlon 4-2Utl 

4.5-3 Cost Estimate Breakdown by Major Job Cost Account 4-21 3 

4.6-1 McDonnell Douglas He1 iostat Design 4-21 5 

4.6-2 McDonnell Douglas Tower and Receiver Design 4-21 6 

4.6-3 Irlitial Area of Available Land lder~lifiecl fur. the 4-21 8 

He1 iostat Field at Reeves Unit No. 2 

4.6-4 Initial Land Area Used in the Analysis 4-222 

4.6- 5 Heliostat Field with Additional 'Land to the East 4-223 

.4.6-6 Final Area of Ava'ilable Land Identified for the 4-225 

Heliostat Field at Reeves Unit No. 2 
LIST OF ILLUSTRATIONS (Continued) 

Figure No. Title Page No. 

4.6-7 He1 iostat ~rrangement for Conceptual Design 4-226 

4.6-8 2 Energy Flux (MW/m ) on McDonnell Douglas Receiver on 4-228 

Noon Summer Sol stice 

4.6-9 Detailed Plot of Heliostats from 4289 Heliostat Field 4-229 

Showing Interference in Slip Plane Region 

4.6-10 Detailed Heliostat Plot from Updated Design (4185 Helio- 4-231 

stats) Showing Elimination of Interference 

4.6-11 Heliostat Deployment for the Conceptual Design with 4-232 

North-South Access Roads 

4.6-12 2 Energy Fl ux (W/m ) on McDonnell Douglas Receiver at 4-233 

2:00 p.m. Winter Solstice for Conceptual Design with 

North/South Access Road (4086 Heliostats) 

4.6-12 2 Energy Flux (MW/m ) on McDonnell Doug1 as Receiver on 4-234 

Noon Summer Solstice for Conceptual Design with North/ 

South Access Road 

4.6-14 2 Energy Fl ux (M/m ) on McDonnell . Doug1 as Receiver on 4-235 

Noon Vernal Equinox for Conceptual Design with North/ 

South Access Road 

4.6-15 2 Energy Fl ux (MW/~ ) on McDonnell Doug1 as Receiver on 4-236 

Noon Winter Solstice for Conceptual Design with North/ 

South Access Road 

4.6-16 2 Energy Flux (~/m ) on McDonnel 1 Doug1 as Receiver on 4-237 

an Annual Average Basis for Conceptual Design with 

North/South Access Road . 

4,6-17 Change in Average Annual Power Output and Change in 4-244 

Total Cost Versus Tower Location 

4.8-1 Map of New Mexico State 4-256 

4.8-2 Map of Bernal l io county 4-257 

4.8-3 General Location of the Solar Hybrid Repowering Site 4 - 2 58 

4.8-4 Stratigraphic Column of Albuquerque Area 4-259 

4.8-5 Seismic Risk Map of the United States 

4,8-6 Seismic Risk Map for Southwestern United States 

4.8-7 Magnitude of Earthquakes as a Function of Distance from 4-266 

the Epl cer~ ter 

4.8-8 Soil Map of Area 4-268 

4.8-9 Case I - Operation of a 50 MWe Solar/Oil Facility under 4-287 

Normal Conditions 
LIST OF ILLUSTRATIONS (Continued) 

Figure No. Title Page No. 

4.8-10 Case I1 - Operation of a 50 MWe Solar/Oil Facility Under 4-288 

Adverse Conditions (i .e., Several Consecutive Days of 

Overcast Skies) L 

4.8-1 1 Case I11 - Operation of,a 50 MWe Solar/Oil Facility under 4-289 

Normal or Adverse Daytime Conditions and Cold Start-up 0.' 

the Boiler at Nighttime 

4.10-1 Insolation Model Showing: Solar Flux Outside the Atmos- 4-316 

phere, Io, Absorption and Scattering by Various Layers; 

the Direct Normal Term. at the Earth's Surface, IDN; and 

the Downward Scattered Term 

4.10-2 Cloud Forms Classified by Height and Vertical Development, 4-318 

from A. N. Strahler, 1963 

4.10-3 Locations of Reeves Plant and Weather Service Site 4-320 

4.10-4 Direct Normal Solar Radiation (A1 buquerque) 4-322 

4.10-5 Dropout Length Distributions of Direct Normal Insolation '4-323 

at A1 buquerque, New Mexico, Dropout Level = 300 w/m2 

4-1 0-6 Cyclone Tracks for April 1971 4-325 

4.10-7 Cloud Cover, 11 April 1971 4-326 

4. '1 0-8 Cloud Cover, 12 April 1971 

4.10-9 Cloud Cover, 13 April 1971 

4.10-1 0 Cloud Cover, 14 April 1971 

4.10-11 Cloud Cover, 15 April 1971 

4.10-12 Cloud Cover, 16 April 1971 

4.10-13 Plan View of He1 iostat Field Showing Two Exam~les of 4-333 

Clouds Approaching 

6.2-1 Detailed Schedule for Solar Hybrid Repowering Program 6-4 

6.2-2 Number of Collectors vs Power Output 6-9 

6.2-3 Average Annual Heliostat Production Range 

6.2-4 Heliostat Installation Time vs Plant Size 

6.2-5 He1 iostat Installation Durations 6-1 3 

6.3-1 Overall Program Organization 6-1 5 

6.3-2 Program Management and Control Logic 6-1 8 

6.3-3 Anticipated Cumulative Cash Flow 6-36 

6.3-4 Cash Flow as a Function of Time 6-37 . 
LIST OF TABLES 

Table No. Title Page No. 

1 .l-1 Market Eva1 uation Summary 1-4 

1 .l-2 Market Eva1 ua tion Summary for Non-Rheat Steam Turbines 1-4 

1 .l-3 Market Eva1 uation Summary for Reheat Steam Turbines 1-5 

1 .l-4 Market Eva1 uation Summary for Combustion Turbines 1-5 

1 .l-5 Market Eva1 uation Summary for Units Above 200 MWe 1-8 

2.2-1 Results of Uti 1 i ty Survey Questions 

2.2-2 Utility Data Questionnaire Response 

2.3-1 Ranking of Utilities by Total Effective Solar Repower- 2-1 4 

ing (MWe) 

2.3-2 Uti 1 i ty Data Questionnai re Responses by State 2-1 5 

2.3-3 Uti 1 i ty Market Survey Eva1 uation by State 2-1 6 

2.3-4 Repoweri ng Percentage Eva1 uation of Candi date Uni ts 2-1 7 

(Total Number of Units) 

2.3-5 Util i ty Market Survey Resul ts - Eva1 uation of Land 2-1 8 

Avai 1 abi 1 i ty 

2.3-6 Utility Market Survey Results - Evaluation of Land 2-1 9 

Availability for Candidate Units Having >50 Percent. 

Repoweri ng Poten ti a1 

2.3-7 Utility Market Survey Evaluation by State for Units 2-21 

Above 200 MWe 

2.4-1 Typical Candi date Uni t for Sol ar Hybri d Repoweri ng 2-22 

2.4-2 Evaluation of Repowering llnit Type 2-2'. 

2.4-3 Eva1 uation of Repowerable Steam Turbine Uni ts 2-24 

2.4-4 Steam Turbine Uni ts Operating Condtions (Pressure1 2-25 

Temperature) 

2.4-5 Eva1 uation of General Unit Data (Number of Units) 2-26 

2.5-1 Solar Hybrid Repoweri ng Model Di spatch 

2.5-2 Solar Plant Economic Measures 

2.5-3 Operating Val ue Factors 

2.5-4 Solar Hybrid Re.powered Plant Reference Parameter Summary 2-38 

xiii 
LIST OF TABLES (Continued) 

Table No. 

2.5-5 

Ti tl e Page No. 

Reference Solar Hybrid Repowering Plant (50 MWe) Cost 2-42 

Assumptions (1 977 M-$) 

Reference Economic Assumptions (1985 $, Present. Worth 2-43 

Discount Rate 11 Percent) 

Estimated Util i ty Generating Mix 2-48 

Cos t/Benefi t Analyses Resul ts for A1 ternate Solar Plant 2- 49 

Collector Fie1 d Size, Public Service Company of New Mexico, 

50 MWe Snlar Hyhrid Repowered Plant, 1355 Installatiol'~ 

CostIBenefi t Analyses Results for A1 ternate Solar Plant 2- 53 

Cost Models, Publ ic Service Company of New Mexi coy 50 MWe 

Solar Hybrid Repowered Plant, 1985 Instal 1 ation 

PNM System-Fossil Operating Energy Displaced by Solar 2- 54 

Hybrid Repowered Plant 

Cos t/Benefi t Analysis Resul ts for A1 ternate Economic 2-55 

Scenarios, Publ ic Service Company of New Mexico, 50 MWe 

Solar Hybrid Repowered. Plant, 1985 Installation 

Cos t/Benefi t Analysis Resul ts for A1 ternate Fossi 1 Boiler 2-56 

Operating Modes, Publ i c Service Company of New Mexi coy 

50 MWe Solar Hybrid Repowered Plant, 1985 Install ation 

CostIBenefi t Analysis Resul ts for A1 ternate Fossil Boiler 2-58 

Operating Modes, Ar.1 zona Pub1 ic Service, 50 MWe solar 

Hybrid Repowered Plant, 1985 Installation 

Cost/BenefitAnalysis Results forAlternate Fossil Boiler 2-59 

Operating Modes, Nevada Power Company, 50 Me Solar 

Hybrid Repuwered Plant, 1985 lnsta'l'lation 

CostIBenefi t Analysis Resul ts for A1 ternate Fossil Boiler 2-61 

Operating Modes, EPRI Synthetic Util i ty E (Texas, 

Louisiana, .Oklaho~l'la), Insolation - Midland, Texas, 50 MWe 

Solar Hybrid Repowered Plant, 1985 Install ation 

CostIBenefi t Analysis Results for A1 ternate Plant Site 2-62 

Locations, EPRI Synthetic Util- ty E (Texas, Louisiana, 

Oklahoma) , 50 MWe Solar Hybrid Repowered Plant, 1985 

Installation 

Sol ar Hybrid Repowered Plant Penetration Analysis, EPRI 2-63 

Synthetic Utility E, Insolation - Midland, Texas, 1985 

Ins tallation 

Plant Rating and Analysis, EPRI Synthetic Uti1it.y E 2- 64 

(Texas, LoulsSana, Oklahoma), Insolation - Midland, 

Texas, 1 985 Instal 1 ation 

Collector Area Sizing Analysis, EPRI Synthetic Utility E, 2-65 

Insolation - Midland, Texas, 1985 Installation 
LIST OF TABLES (Continued) 

- Table No. Title Page No. 

3.1-1 Solar Hybrid Repowering Method Assessment 3-8 

3.2-1 PNM Candidate Units for Solar Hybrid Repowering 3-1 4 

3.2-2 Solar Hybrid Repowering Project - PNM Candidate Unit 3-1 5 

Technical Selection Criteria 

3.7-1 Typical Candidate Unit Compared to Reeves Unit No. 2 3-31 

Direct Normal Insolation for A1 bu uerque, New Mexico 

Monthly and Annual Val ues 9 , kW/h/m Day 

Central Rio Grande Val ley Region Temperature and 

Preci pi tation 

Mean Speed and Prevailing Direction at A1 buquerque 

Sunport 

.Dust Storms in A1 buquerque (16-Year Period 1945-1960) 

Reeves Station Unit No. 2 Performance Data 

Equipment Design Criteria 

Receiver Desi gn Characteristics 

Receiver Operating Characteristics 

Receiver Heat Losses 

Mi rro r Requi remen ts 

Col lector Operating Modes 

Cul lector Fiel d Power Requi rements 

Re ce i ve r Feed Pumps 

Equipment List (2 pages) 

Motor List (2 pages) 

Auxil i ary Power Requi remen ts (2 pages) 

Combination of Unit Conditions (3 pages) 

Pi ping System Parameters 

Cost Breakdown--Concrete and Steel Towers 

Ini ti a1 MIRVAL Resul ts 

Power Incident on Receiver at Selected Times of the Year 

Power Incident on Receiver at Selected Times of the Year 

Fiel d Performance, Tower Hei ght Variation 
LIST OF TABLES (Continued) 

Table No. Ti tl e Page No. 

4.6-5 Field Performance, Fie1 d Trimming 4- 240 

4.6-6 Field Performance, Tower Re1 ocation 4-264 

4.7-1 Cost Estimate Summary 4-249 

4.8-1 Mercall i Intensity Scal e and Expected Damage for Each 4-264 

Intensity (After C. F. Richter, 1958) 

4.8-2 Richter Magnitude Scale and Approximate Mercall i Intensity 4-267 

Scale Equivalents (After Richter, 1958) 

Discharges or Riu Grande River at Albuquerque, New Mexico 

(U.S.G.S. Station 0833000), cfs 

Summary of Cl imatological Data for A1 buquerque and Vicinity 

Average Daily Traffic at Solar Hybrid Repowering Site 

Fuel and Stack Characteristics Considered in Air Qual i ty 

Impact Calculations 

Case I. The Operation of a 50 MWe Solar/Oil Facility 

Under Normal Conditions 

Case I I. The Operation of a Sol ar/Oi 1 Faci 1 i ty Under 

Adverse Conditions 

Class I1 Significant Deterioration Increments 

Maximum Ground-Level Concentrations for S02, NO2 and 

Particulate Matter under Normal Operating Conditions 

Assuming Unlimited Mixing (Case T) and Appl icablc Air 

Qual i ty. Standards 

Max imum Ground-Level Concent.rations for SO2, NO? and 

Particulate Matter under Adverse Operating Conditions 

Assuming Unlimited Mixing (Case 11) and Applicable Air 

Qual i ty Standards 

4.10-1 Direct Normal (Langl eys/Minute) and Total Horizontal 4-324 

(Langl eys/Day) Observed at A1 buquerque, NM, April 1971 

5.1-1 Reference Reeves Unit No. 2 Plant Parameter Summary 5-3 

5.2-1 Task 14UU Assumption Changes 5-6 

5.2-2 Fuel Cost Assumptions ($/MBtu) 5-7 

5.3-1 Conventional Energy Displacement 5-9 

5.4-1 Task 1400 Cases 5-1 1 

5.4-2 Cost/Value Sensitivity to Repowering Capital cost 5-1 2 
LIST OF TABLES (Continued) 

Table No. Title Page No. 

5.4-3 Cost/Value Sensitivity to Oil Escalation Rates 5-13 

5.4-4 Cost/Value Sensitivity to Repowered Plant Life 5-1 5 

5.4-5 Cost/Value Compairson with Alternate Analysis Methods 5-1 6 

5.4-6 Cost/Value Using Demonstration and Commercial Costs 5-1 7 

6.3-1 Work Breakdown Structure 

6.3-2 Explantion of Account Number System 

6.3-3 Tax Incentive Analysis 

xvi i 
1.0 INTRODUCTION AND SUMMARY 

Publ ic Service Company of New Mexico (PNM) has performed a Technical and Economic 

Assessment of Solar Hybrid Repowering under funding by the Department of Energy 

(DOE), the Electric Power Research Institute (EPRI), Western Energy Supply and 

Transmission (WEST) Associates, and a number of southwestern utilities.* Solar 

hybrid repowering involves placement of solar hardware adjacent t6 and connected 

to existing gas- and oil-fueled electric generation units to displace some of or 

all the fossil fuel normally used during daylight hours. The subject study 

assesses the technical and economic viability of the solar hybrid repowering 

concept within the southwestern United States and the PNM system. This document 

is a final report on the study and its results. 

The study was divided into the six primary tasks to allow a systematic investigation of the concept: 

Task 1100 - Market Survey and CostIBenefit Analysis 

The primary objective of this task was to determine the near-term 

market potential of solar hybrid repowering. This was accomplished 

by conducting a mail survey of Southwestern utilities to identify 

potential candidate units , by identifying typical candidate plant 

characteristics from the results of the survey, and by performing 

a computer simulation of the economic dispatch of a typical candidate plant on four selected utility systems. The data resulting 

from this modeling allowed for the determination of a costlbenefit 

ratio for solar hybrid repowering. 

r Task 1200 - Study Unit selection 

The objective of this task was to select a specific PNM plant/unit 

as a candidate demonstration site for the concept. The selection 

nf t.he unit was based on the typical plant as identified by the 

market survey, its suitability to future needs of the PNM system, 

and its ability to meet the goals of the DOE Solar Hybrid Repowering Program. 

"Arizona Power Authority, Publ ic Service Company of Oklahoma, San Diego Gas and 

Electric Company, and Tucumcari Power and Light. 
a Task 1300 - Conceptual Design and Cost Estimates 

The purpose of this task !;/as. to prepare a canc.eptua1 design and 

detailed cost estimate of a solar hybri'd repowering demonstration 

at the selected study unit site. The solar system design was 

based on the McDonnell Douglas Astronautics Company central 

receiver system as defined in the DOE Phase I Preliminary Design 

Report. This system was selected predicated on PNM analysis, DOE 

guidance, and the Sandia Laboratory recommendations for the Barstow Pilot Plant. The technical feasibility of the concept was 

thoroughly addressed, and approaches were devised for the resolution of probl ems. 

a Task 1400 - Unit Economic Analysis 

This task involved performing a detailed economic analysis of the 

s~lect.~d ~t~~dy unit based on operating conditi~ns and cost estimates developed for the conceptual design. 

Task 1500 - Program Planning, Future Phases 

The gcal of this task was preparation of a work plan for future 

phases of a Solar Hybrid Repowering Demonstration Project. The 

work plan includes a work breakdown structure, a schedule, and a 

management plan. 

a Task 1600 - Program Management 

The final task called for the organization, direction, control 

and reporting of the project within a specified schedule and 

budget. Utility interfacing through Supporting and Advisory 

Programs was also accomplished under this heading. 

Sectlons 1.1 through 1.5 of this Report include summaries of the major results 

of the market survey and costlbenefit analysis, selection of a study unit, 

development of a conceptual design, and results of the study unit economic 

analysis. A summary of the program plan for future phases of the Solar H,ybrid 

Repowerinq Project is also presented. 
1.1 ' MARKET SURVEY AND COST BENEFIT ANALYSIS 

The evaluation of the commercial market potential for solar hybrid repowering 

of existing fossil-fueled electric power generating plants has been completed. 

This evaluation includes a market survey directed toward the potential repowering of oil- and gas-fired plants of less than 200 MWe located in the Southwest. 

Tables 1 .l-1 through 1 .l-4 summarize the results of this evaluation; Table 1 .l-5 

summarizes the results of the market evaluation for units greater than 200 MWe. 

These evaluations are discussed in detail in Section 2.0 of this Report. 

A qiterature survey also was performed using Federal Power Commission Form 12 

data. As shown in Table 1 .l-1, this literature survey identified 755 gas- and 

oil-fueled electric power generating units with ratings less than 200 MWe, 

with more than half rated at 50 MWe or less. These units are located in the 

Southwest, are potential candidates for solar hybrid repowering, and represent 

more than 40,000 MWe of generating capacity. Since most of these units were 

built in the 1950s, they will either have to be repowered or replaced with new 

generating capacity within the next 25 years. 

A questionnaire was distributed to 78 utilities to determine interest in the 

solar hybrid repowering concept, to identify candidate plants for repowering, 

and to determine the availability of land adjacent to the candidate plants. 

Environmental and safety issues were not addressed in the market survey. The 

78 selected utilities represent most of the electric power generating capacity 

in the Southwestern United States, including ~rizona, Cal i fornia, Colorado, 

Louisiana, Nevada, New Mexico, Oklahoma, Texas and Utah. Of the 78 utilities 

that were sent the questionnaire, 61 responded, with approximately 50 indicating an interest in solar repowering of their existing gas- and oil-fired units. 

As indicated in Table 1 .l-1, the survey identified 272 candidate units for solar 

hybrid repowering, representing a total rated capacity of approximately 

19,700 MWe. Considering land availability for solar collector fields, these 

272 units represent a solar repowering potential of %11,200 MWe. Of the 

272 candidate units, 206 have land available within 2500 feet and represent a 

solar repowering capacity of L7200 MWe. Considering a) available land located 
TABLE 1 .I -1 . MARKET EVALUATION SUMMARY* 

Category Number of Units Total MWe 

Potential Market Size (Rated MWe) 

8 Literature Survey 

8 Utility Survey 

Solar Repowering Potential (Effective MW~) 

e Based on Land Availability 27 2 

- and <2500-ft from Plant 206 

- and >50% Repoweri ng 8 2 

- and Utility Interest 82 

*For Units Rated 1200 MWe 

TABLE 1 .l-2. MARKET EVALUATION SUMMARY FOR NON-REHEAT STEAM TURBINE9 

Category Number of Units Total MWe 

Potential Market Size (~ated MWe) 

e Utility Survey - Repowerable Units 152 7,455 

Solar Repowering Potential (Effective MWe) 

e Based on Land Availability 

- and <2500-ft from Plant - 

- and >50% Repowering 

- and Utility Interest 

"Fur Units Rated 1200 MWe 
TABLE 1 .l-3. MARKET EVALUATION SUMMARY FOR REHEAT STEAM TURBINES 

Category Number of Units Total MWe 

/ 

Potential Market Size (Rated MWe) 

e Util ity Survey - Repowerabl e Units 92 11,186 

Solar Repowering Potential (Effective MWe) 

Based on Land Availability 92 6,775 

- and - <2500-ft from Plant 

- and > 50% Repoweri ng 

- and Utility Interest 

*For Units Rated 5200 MWe 

TABLE 1 .l-4. MARKET EVALUATION SUMMARY FOR COMBUSTION TURBINE9 

Category Number of Units Total MWe 

Potential Market Size (Rated MWe) 

e Util ity Survey - Repowerabl e Units 28 1.,108 

Solar Kepowering Potential (Effective MW~) 

e Based on Land Availability 

- and - <2500-ft .. from Pla,nt 

- and >50% Repowering 

- and Utility Interest 

*For Units Rated <ZOO MWe 
at less than 2500 feet from the candidate unit, b) a repowering potential of 

greater than 50 percent of the rated unit output, and c) utility interest, 

82 units representing $5200 MWe of effective repowering potential were identified. Therefore, a large potential market exists for the solar hybrid repowering concept if the approach can be proven to be economically attractive. 

Tables 1 .l-2, 1 .l-3 and 1 .l-4 summarize the market evaluation (similar to 

Tab1 e 1 .l-1) according to non-reheat steam turbine, reheat steam turbine, and 

combustion turbine units, respectively. Of the 272 total candidate units, 

15? nits (56 percent) with a rated capacity of ~7400 MWe and an effective solar 

repowering potential of ~4000 MWe were identified as non-reheat steam turbines 

(see Table 1 .l-2). Of the 152 non-reheat units, 116 have land available within 

2500 feet of the plant, representing a repowering potential of ~2700 MWe. Based 

on both land available within 2500 feet and a repowering level of greater than 

50 percent, 47 units at $2000 MW of solar repowering capacity were identified. 

For the reheat steam turbines summarized in Tabli 1 .l-3, 92 candidate units were 

reported with an effective solar repowering potential of $6800 MWe (based on land 

availabil ity). When both the land distance and repowering percentage restrictions were applied, 29 reheat units at an effective solar power capacity of 

$3100 MWe were identified. 

Of the 272 repowerable units, 28 are combustion turbines that represent an effective solar repowering capacity of ~400 MWe, as shown in Table 1 .I-4, which 4s 

approximately four percent of the total effective solar repoweri.ng potential . Based on available 'land 'located at less than 2500 fcct and a repowering level 

of greater than 50 percent, six units at ~140 MWe of effective solar repowering 

potential were identified In this evaluation. 

A verification of thc land available fnr solar repowering of a few selected 

units has been performed. Of the 82 units having a total of $5200 MWe of solar 

repowering potential (shown in Table 1 .l-1) based on available land at - <2500 feet 

and percent repowering, 23 units from 20 utilities, having an effective solar 
repowering potential of ~1600 MWe, were sel ected for verification by contacting 

the specific utilities involved. The results of the verification show that 

$1560 MWe of solar repowering potential ($98 percent of the $1600 MWe initially 

identified) can be repowered based on the available land. Of these 23 units, 

however, two units have their available land at >2500 feet. Thus, the net solar 

repowering potential of the 21 units at >50 percent repowering and <2500 feet is 

$1420 MWe. 

The characteristics of a typical candidate unit for solar hybrid repowering were 

defined on the basis of the utility survey results. Based on the relatively 

high number of non-reheat steam turbine units to be repowered, and in order to 

be consistent with the first generation solar central receiver technology being 

developed by the Department of Energy, the non-reheat steam turbine was selected 

as the recommended type of unit to be repowered in the initial phase of the program. Therefore, the typical unit is a non-reheat steam turbine with inlet conditions of 850 to 1250 psig/900 to 950°F. The rated power of the typical unit, 

built between 1950 and 1960 and 1 ikely to be retired before the year 2000, is 

between 10 and 50 MWe. In general, the candidate units are in good condition 

and are being used for either intermediate or peaking load service. 

A literature survey and a utility survey that include units rated above 200 MWe 

also have been performed. As shown in Table 1 .l-5, the 1 iterature survey has 

identified an additional 129 oil- or gas-fired units>200 MWe at a total rated 

capacity of ~53,000 MWe. These totals should be compared with and added to the 

755 units and ~41,000 MWe results shown in Tab1 e 1 .l-1. From the util i ty survey, 

61 units at a rated capacity of ~26,000 MWe were identified as possible candidates 

for solar hybrid repowering. All of the 61 units >ZOO MWe are reheat steam turbine 

units. Based on land availability, these 61 units represent an effective solar 

repowering potential of ;15,100 t4We (see Table 1 .l-5). These totals are in addition 

to the 272 units and $11,200 MWe repowering potential shown in Table 1 .l-1. 

Considering available land at - <2500 feet from the plant, 37 units at ~6300 MWe 

of solar repowering capacity were identified. 'A total of 17 units at 2.5700 MWe 

of solar repowering potential have land available at - ~2500 feet and sufficient 

land for repowering at >50 percent. These totals should be compared with and 

added to the 82 units and$5200 MWe of solar repowering potential shown in 

Table 1.1-1. 
TABLE 1.1-5. MARKET EVALUATION SUMMARY FOR UNITS ABOVE 200 MWe 

Category Number of Units Total MWe 

Potential Market Size (Rated Mw~) 

e Literature Survey 129 53,459 

a Utility Survey 61 25,594 

Solar Repowering Potential (~ffective MWe) 

Based on Land Availability 

- and - <2500-ft from Plant 

- and >50% Repowering 

A cost/benef i t analysis has been performed for the solar hybrid repowering concept for four selected Southwestern util ity systems: Arizona Publ ic Service, 

Publ ic Service Company of New Mexico, Nevada Power Company, and the Electric 

Power Research Institute Synthetic Util ity System E, which is representative of 

utility systems in Texas, Oklahoma and Louisiana. A reference 50 MWe Solar 

Hybrid Repowering Plant was defined for performing the cost/benefit analysis 

based on the characteristics of the typical candidate unit discussed above. 

The results of this analysis indicate that the solar hybrid repowering concept 

has the potential to be economically attractive for utility applications when 

compared with conventional methods of el ectric power genera tion (a costlbenef i t 

ratio of approximately 0.9 for a repowered unit operating as part of Synthetic 

Utility System E). 
1.2 STUDY UNIT SELECTION 

Task 1200 of the DOEIPNM Technical and Economic Assessment of Solar Hybrid 

Repowering requires selection of a study unit to represent a typical plant for 

the expected market. The study unit is to reflect data derived from a market 

survey and be well suited to future needs of the PNM system. This will ensure 

optimum use of the study unit for demonstration purposes while maintaining 

system integrity. 

Four potential methods for solar hybrid repowering were evaluated: 

8 Steam Rankine cycle solar feedwater heating 

e Steam Rankine cycle evaporation and superheating (boiler 

displacement) 

e Brayton cycl e (combustion turbines) 

a Combined cycl es (.Brayton/~team an kine) 

It was recommended that the optimum system, in terms of market penetration and 

cost benefit ratio, was solar evaporation and superheating of an existing steam 

Rankine plant. 

It was required that the size and type of a solar system for demonstration of 

evaporation and superheating coincide with current DOE technology in order to 

demonstrate application in the near term. It was determined that a 25 MWe power 

level utilizing an external central receiver was a satisfactory evolution from 

the Barstow Pilot Plant toward a 100 MWe commercial goal for solar plants. This 

power 1 eve1 was confirmed by Rockwell International ,* developer of the external 

central receiver, and by the project review team. 

Based on use of a steam Rankine boiler displacement at a capacity level of 

25 MWe, candidate sites and units were evaluated by seven PNM groups to determine 

which was most suitable to become the study unit. Inputs were provided to 

*Rockwell's design was selected for use at the Barstow Pilot Plant in July 1978. 
Project Management on the suitability of repowering the candidate units in 

terms of the future needs of the PNM system, and the optimum usefulness of 

each unit to the utility and to DOE as a demonstration unit. 

PNM Project Management also carefully evaluated the typical candidate unit 

criteria as established through the market survey and cost/benefi t analysis 

(discussed in detail in Section 2.4). It was concluded that the Reeves Station 

was the ideal site for study of the solar hybrid repowering concept. Based 

upon Power Production recommendations and definition of the candidate repowering unit, the most desirable machine was determined to be Unit No. 2 with its 

50 MWe net output, Considering the requirements for evaporation superheating 

displacement and a 25 MWe power lev,el, it was concluded that a 25 MWe solar 

field would be adequate to demonstrate the concept while remaining within technological limits. This allows for a 50 percent repowering of the unit and 

a1 lowi for demonstration of solar, fossil and solar/fossil operation. 

Section 3.0 of this Report presents detailed information on the study unit 

selection. 
1.3 CONCEPTUAL DESIGN AND COST ESTIMATE 

Reeves Unit No. 2, selected under the preceding task, was established as the 

potential candidate plant for solar hybrid repowering. This plant was investigated under this conceptual design and cost estimate task to provide a 

reasonably definitive design and to identify the required modifications. The 

existing land situation, as well as the particular environmental aspects of 

Reeves Unit No. 2,were investigated. Upon complete definition, a cost estimate 

was prepared that is related to the present configuration of Reeves Unit No. 2. 

All significant changes in the plant necessary to accommodate the solar facilities and control systems were determined and estimated. A heliostat field was 

defined using the MIRVAL* program developed by Sandia Livermore, and the power 

level ava.ilab1 e from a given configuration was establ ished. 

The design point selected for this conceptual design, 2:00 p.m. winter solstice, 

is intended to provide at least a total solar electrical output of 25 MWe gross. 

The solar collector field and the receiver sizes wer.e designed to meet this 

requirement. System component sizes were based on the summer solstice condition at noon, which could produce approximately 39 MWe gross electrical output. 

The summer solstice design point was used to size all the system components and 

to establish steam and feedwater flow rates, pressures, and temperatures. 

The design approach used during the conceptual design for solar repowering is as 

follows: 

0 Reeves Station Unit Nn. 2 was selected for repowering 

The solar system design was to be based on the 10 MWe solar 

central receiver prel irninary design for Barstow, California 

A design goal of 50 percent solar repowering (25 MW~) was 

establ ished 

o ' A collector field layout generated by the DOE/Sandia Ltvermore 

Laboratories, California, from its MIRVAL computer program was 

used 

*The MIRVAL computer code, along with two preprocessor codes, was used to size 

the f-ield and locate the heliostats in order to obtain the desired station 

power output. The MIRVAL program is described in Section 4.6.1 of this Report. 
e Definitions of possible plant operating modes were used as a 

design base 

e Preliminary EPGS general arrangement drawings were to be prepared 

to define the integration of the new solar system equipment with 

existing plant equipment 

Computer modeling of the basic fossil/solar cycles was to be 

prepared to provide heat ba7ance data for system performance and 

equipment sizing 

e Piping interface locations were to be defined 

e Changes to the existing plant were to be minimized 

Water treatment system design was to be based on once-through 

boi 1 er requirements 

The control system design provided for the solar portion of the repowered Reeves 

Unit No. 2 has been optimized to provide the simplest and most straightforward 

design to minimize the impact on exjsting plant equipment. 

The design of the receiver for this solar repowering project is to be based upon 

the receiver used in the Barstow, California Pilot Plant. That receiver is a 

Rocketdyne once-through boiler, fabrjcated of Incoloy 800 tube materials. The 

Barstow design will be scaled-up to meet the capacity requirements of thls 

Project. 

The Reeves Station repowering collector design was based on the use of the MUAC 

collectors, drives, and controls as proposed for the Barstow Pilot Plant. That 

design was modified to comply with the Reeves site conditions. Major changes 

i ncl ude: 

Revising the size and layout of the collector field and number 

of heliostat units to conform to the physical characteristics of 

the Reeves site. This revlslon was based un the design insolation at the Reeve5 hite, the 1-ef1ectivit.y nf thc hcliostat 

mirrors, the absorptance of the receiver, and the general design 

plan of power required. ' 

e Integration of the collector control system into the Master Control System Belng proposed ,fur the repowered Reeves station. 
A design utilizing 4289 heliostats in a field to the south of the existing 

station was conceived. The tower was set in the southern half of a rectangular 

field, and access roads, fencing, relocation of existing facil i ties, and potential 'for maintenance of the solar facil i ties were establ ished. 

Further program revisions and MIRVAL runs to allow for the inclusion o f a l l 

roads and steam piping establ ished the actual number of he1 iostates required; 

the resulting heliostat field contains 4086 heliostats. Further work will be 

performed during the detailed design to establish the exact field position of 

all heliostats. The variance, however, is considered minor relative to the data 

available for insolation, cloud cover and other environmental factors. Use of 

the maximum number of heliostats was considered as a conservative figure in this 

effort. 

Environmental aspects such as rainfall, cloud cover, dust, and traffic, hazards, 

were considered in the conceptual design. 

Potential problems were identified and solutions were defined through trade 

studies and engineering analysis. The conceptual design was developed to a 

level sufficient to establish a construction and program cost estimate. 

The Conceptual Design Study for Solar Repowering Reeves Station Unit No. 2 

reveals no major barriers that would impede detailed design and construction. 

Given a normal anticipation of expected problems associated with a retrofit 

and/or upgrading project, the technical aspects of solar repowering of Reeves 

Station appear to be relatively straiqhtforward. 

Reasonable approaches have been identified as possible solutions for major 

design problems. Areas meeting extended future detailed design investigation 

also are identified. 
1.4 UNIT ECONOMIC ANALYSIS 

A cost/benefit analysis has been performed for the solar hybrid repowering 

concept (Reeves Unit No. 2) for the PNM system. The intent of the analysis is 

to realistically assess the economics of the "first" repowered plant using 

present cost data for a limited production level for the solar hardware. The 

results therefore are not indicative'of the economic potential of solar repowering but rather only of the economics of the "first demonstration" plant. The 

economic potential of solar repowering was presented in Section 1.1 of this 

Report. 

The economic analysis performed for Reeves Unit No. 2 was similar to the analysis 

discussed in Section 1.1 for four selected southwestern utilities (including PNM), 

except that the fol lowing changes were incorporated: 

e The reference plant description has been revised consistent with 

the conceptual design presented in Section 1.3 

e The insolation data base has been updated consistent with the 

1978 version of the Aerospace tapes for Albuquerque, New Mexico 

e The PNM system description has been revised to reflect the 

July 1978 plan for future power generation capability 

'The economic scenario has been modified to approximate PNM 

system changes 

e The cost of the repowered plant has been revised consistent with 

the concept.l.ra1 design 

A reference solar hybrid repowered plant concept has been establi'shed for the 

Reeves Unit No. 2 for the purpose of performing the unit economic analysis. The 

reference plant concept for Reeves Unit No. 2 is based on the solar hardware and 

technology being developed for the 10 MWe solar central receiver pilot plant to 

be built near Barstow, California. The solar subsystem has been sized to provide 25 MWe (50 percent repowering) at 2:00 p.m. winter solstice based on an 

2 insolation level of 950 watts/m . 

For the economic analysis, detailed modeling of the operation of the repowered 

plant and the PNM system was performed for several discrete years, beginning in 
1981. ,The penalty for the loss of the Reeves Unit No. 2 during repowering was 

estimated. The operating strategy was varied from year to year, requiring 

25 MWe of fossil firing any time the solar system was being used in years 1982 

through 1985, and requiring the same operating strategy 50 percent of the time 

in the years 1985 through 1986. Beyond 1986 the repowered plant was allowed to 

operate in the most economical mode. A detailed PNM expansion plan for conventional generation was used for the analysis. 

The cost/benefit of a demonstration program, as viewed from immediate utility 

economic impacts, is substantially higher than might be expected for commercial 

implementation. The higher cost/benefits are due to higher costs for solar 

components (such as heliostats) and restricted plant operation in the early years 

(due to testing and the establ ishment of operating mode confidence/experience) . 

A heavy addition of base-load conventional capacity (nuclear and coal) during the 

early years of operation also decreases the benefit. 

These cost/benefit factors are consistent with other demonstration programs in 

that the real benefits are achieved through the experience and information 

gained, and the benefits result in the commercialization phase. 
1.5 PROGRAM PLANNING, FUTURE PHASES 

Pub1 ic Service Company of New Mexico (PNM) developed the Program Plan out1 ined 

in Section 6.0 of this Report as a means of demonstrating the Solar Hybrid 

Repowering concept. The plan is structured to permit the program to be conducted 

in a manner similar to previous successful utility-oriented, pre-commercialization 

programs. The Program Plan providesappropriate visibility and control of a1 1 

technical effort, schedules and costs. It utilizes the Work Breakdown Structure 

approach and anticipates control documents, such as design requirements and interface control drawings, to ensure a successful demonstration of the Solar Hybrid 

Repowering concept. It recognizes and accommodates the acquisition, analysis and 

reporting of data vital to the repowering proyrndm. 

The principal goal of the PNM Program Plan is to establish the technical viabil ity 

and economic attractiveness of .the Solar Hybrid Repowering concept and widespread 

utility application. The specific objectives are: 

a To prepare a detailed design for a solar repowered plant 

o To construct a solar repowered plant. 

s To start-up and operate a solar repower plant successfully for 

two years 

a To disseminate progrvess I-eports and program results to other 

utilities, industries and government agencies to enhance the 

early commercial izalion of solar repowering 

\ 

The program to implement the Solar Hybrid KepowerTng concept is d4vqded into slx 

principal phases: 

a Phase 1 - Technical /Economic Assessment 

a Phase 2 - Design 

a Phase 3 - Procurement 

a Phase 5 - Checkout 

CJ Phase 6 - Operation 
Figure 1.5-1 presents the schedule for the proposed program. 

The Phase 1 portion of the program is completed with the issuance of this final 

report; the following output will be available to initiate the Phase 2 Design: 

e Market survey and costlbenefit analysis 

Specific site for the solar repowering program 

Conceptual design of the solar repowered unit 

0 Cost estimate for the solar repowering unit 

Phases 2 through 5, Design through Checkout, are scheduled to take place over a 

42-month period. An approximate two-year operating period (phase 6) is also 

planned, but the option for DOE to continue the operations beyong two years 

should be reevaluated when successful operation of the unit has been achieved. 
MONTHS 

2 4 6 8 10 1: 14 16 18 20 22 24 215 28 30 32 34 6 38 40 42 

I. 

DETAILED STUQIES & ENGINEERING 

..mmmmmmmmmmmmmmmmmmm 

PLANT EQUIPMENT PROCUREMENT mmmmmm.ulmmmmmm~~mmmmmmmmammaI 

HELIOSTAT PROCUREMENT 

mmmmmaammmmmmmmm~mmmammmmmmmmmaamma~ 

Z 

0 - 

k 

SOLAR RECEIVER PROCUREMENT Q 

wImmmmmmmmm1m.mmma1.mmmmm.m~mammmm K 

W 

L 

FACILITY CONSTRUCTION & EQUIPMENT ERECTION 

mmmmmmammammmmmmmmamamam~ma~mmamamm 

TURBINE FilODlF 

SOLAR REPOWERING 

REEVES STATION UNIT #2 

PLANNING SCHEDULE 

Figure 1.5-1. Schedule for the Proposed Progrm 
2.0 MARKET SURVEY AND COST BENEFIT ANALYSIS 

This section contains a description of the subject market survey, a discussion of 

utility interest, an evaluation of the solar repowering potential in the Southwest, a descriptio'n of the typical candidate unit for repowering, and the results 

of the costlbenefit analyses that have been performed, 

2.1 MARKET SURVEY DESCRIPTION 

The technical approach used in developing a comprehensive survey of the potential 

market for solar hybrid repowering involved the following: 

a Review of the results of previous PNM surveys 

e A 1 iterature survey of the utilities in the Southwestern United 

States, based primarily on Federal Power Commission Form 12 data (2-1 )* 

a Mailing of a data questionnaire on the PNM Solar Hybrid Repowering Project to 78 utilities in a nine-state area of the Southwest 

The results from the previous PNM surveys and the literature survey were used for: 

a) guidance in developing the util i ty questionnaire, and b) informat'ion purposes 

to supplement the responses to the questionnaire. 

The PNM Solar Hybrid Repoweri'ng Project Utility Questionnai're submitted to the 

Southwestern utilities was transmitted by a cover letter that summarizes the 

PNM Solar Hybrid Repowering Project. Tt emphasizes that the study efforts "will 

identify, from a utility point of view, if a cost-effective approach exists to 

repower existing steam or combustion turbine units with solar energy systems to 

reduce or supplant natural gas and/or oil boiler firing." Additional references 

to the solar hybrid repowering of existing units (as opposed to building new 

solar hybrid power plants) were made in the cover letter and in the questionnaire, both of which are included in Appendix A to th-is Volume. 

*References are provided in Section 7.0 of this Report. 
Included in the utility questionnaire (Appendix A) were the following basic 

questions: 

1) Has your utility considered the possibility of 'solar power 

generation as a future a1 ternative? 

2) Would your company be interested in participating in a solar 

hybrid plant program if financial incentives made it equivalent 

or superior to existing generation a1 ternatives? 

3) Do you have any plans or interest in repowering any units of 

200 MWe or 1 ess? 

The questfonnaire a1 so requested the foll owing general util ity informa tion: 

0 Approximate generation mix (oil/natural gas, coal and nuclear) 

0 Time of system peak 

0 Availabil ity requirements for peaking and intera~ediate units 

For each of the units less than 200 MWe owned and operated by the,util ity, the 

fol 1 owing information was requested (see Appendix A) : 

Rated size (Mw~) 

e Unit type (Steam/reheat, Steam/non-rehea t., Cnmhlrst.ion, Combined 

c y c l e ) 

e Turbine inlet temperature 

0 Year built 

a Unit condition 

Current use (,Base, Intermediate, Peak, Stand-by) 

e Estimated retirement 

e Gcrlcr-a1 plant location (Industrial , Urban, Sulrur-bdr~, ur Rural ) 

0 Land availability (Based on a requirement of approximately six 

acres of land per MWe for the solar collector field, there is 

sufficient vacant land near the platit to repower - percent of 

of the unit.) 

0 Distance from unit to available land 
The market survey questionnaire was mailed to the appropriate investor-owned 

municipal, federal, state, district and cooperative systems/utilities in the 

nine-state area. The survey was limited initially to units of c200 MWe in rated - 

size, consistent with the most recent prior PNM survey conducted in 1976 and discussed in Section 1.3 of the PNM proposal. The program plan in Section 3.4 of 

the proposal, relating to a market cost/benefit analysis, included a statement 

that one of the objectives was to validate the survey presented in Section 1.3. 

During the initial phase of the Solar Hybrid Repowering Project at PNM in 

November 1977, study requirements and guidelines were set forth that included a 

limitation on the unit size to be considered of ~200 MWe. - 

One of the objectives of the PNM project was to make the utility survey consistent 

with the first generation solar central receiver technology being developed by the 

Department of Energy for a 10 MWtl pilot plant (to be constructed at Baustow, 

California) and a 100 MWe commercial plant. An extension of this market survey 

to oil/gas-fired units above 200 MWe also has been performed, and the results are 

included in this Report. The 200 MWe rated size does not represent a restriction 

on the poten'tial for solar hybrid repowering. 

In evaluating the market survey results, as discussed in Section 2.3 of this 

Report, consideration was given to the desirability of having the available land 

at less than 2500 feet from the existing unit. If the land is adjacent to the 

plant, the thermal, pressure and efficiency losses resulting from the horizontal 

lengths of steam and feedwater piping between the base of the central receiver 

tower and the existing turbine generator will be minimized, as will the initial 

cost for this piping. The - <2500 feet restriction does not represent an absolute 

limit. The actual limitation will be determined by the various costs and efficiencies, as well as by the cost for the solar plant as compared to the costs 

for conventional power generation on their system. The 2500 feet restriction is 

consistent with the conceptual design for a solar hybrid repowered plant (see 

Section 4,O). 

Consideration also was given to the desirability of having sufficient land available to repower an existing unit to a level of greater than 50 percent. Again, 

the >50 percent repowering criteria does not represent an absolute restriction. 
The percentage of repowering desired for a specific unit will depend on the site 

and utility system, and will be contingent upon the relative cost and benefit 

the solar plant when compared with conventional power generation. 

Other factors that could influence the selected repowering level for a given unit 

include the following: 

a Fossil boiler efficiency at reduced power 

8 Minimum practical operating point of the fossil boiler 

Maximum ramp rates for increasing and decreasing the fossil 

boiler output as the solar boiler output varies with intermittent cloud cover 

e Required dispatch of the unit to the utility system 

e Time of day and period of year for the utility's system peak, 

coupled with the normal weather conditions for the site during 

those periods 

e Desirability of utilizing all the solar-generated steam from 

the hybrid repowered plant during those days when the solar 

insolation is at a maximum 

An extensive discussion of the cost/benefit analyses for solar hybrid repowered 

plants performed for selected utilities in the Southwest is presented in Section 2.5 of this Report. One of the objectives of these anal.yses was to determine 

the eff@ct, for orle util itj, id vdr'yirlg the percentage of repower-iny uf a 50 MWe 

plant Tran d cust/benefit ratio standpoint. Lower cost benefit ratios were 

achieved for repoweri ng percentages >50 percent. 

This utility survey is 1 imited in scope in several respects. The survey was 

limited initially to units of - <ZOO MWe in size, but data from-a literature survey 

of the oil- and gas-fired units >ZOO MWe in the Southwest have been developed. A 

total of 129 units, at a rated capacity of %53,000 MWe, was tabulated. These 

totals should be compared with and added to the 755 units and %41,000 MWe results 

shown in Table 1 .l-1 (see Section 1 .I). Oil- and gas-fired units >ZOO MWe, which 

are potentially solar hybrid repowerable, also have been surveyed from the 

util itjes by PNM. A summary of this 1 iterature survey extension and the subsequent utility survey follows'. 
As discussed in Section 2.2 of this Report, 61 of the 78 utilities surveyed 

elected to respond to the PNM questionnaire, and these utilities reported data 

on ,394 units. This represents s52 percent of the 755 unit total from the literature survey shown in Table l .l-1. Thus, if the balance of the 78 utilities were 

to respond to the survey, and if all the units had been reported by each of the 

utilities that responded, a significant increase in the number of repowerable 

units and effective solar repowering potential might be real ized. 

Section 2.3.1 , Overview of the Solar Repowering Potential , describes the method 

used for determining the effective solar repowering potential from the util ity 

supplied data of rated power and available land. Although some utilities 

responded with a specific repowering percentage based on land availabil ity, most 

utilities reported their repowering levels in brackets of 0 percent, 1 to 25 percent, 26 to 50 percent, 51 to 75 percent and 76 to 100 percent. By using the 

upper bound of the bracketed repowering level for this latter group'of utilities, 

the results for the repowering potential could be, on the average, s12 percent 

lower than shown in Section 2.3.1. 

This utility survey is also 1 irnited in scope in that only a nine-state area in 

the Southwestern United States was included. A complete survey to encompass the 

- balance of the 50 states may significantly increase the number of repowerabl e 

units, as well as the solar hybrid repowering potential. 

PNM anticipates that as solar technology becomes better known and developed, as 

costs are decreased, as the commercialization of solar hybrid repowering is 

demonstrated, and as the cost/benefit ratios are decreased to make repowering 

of existing units more economically attractive, additional units will be 

identified by the southwestern utilities as repowerable. The available land for 

the solar collector fields for the candidate units also could be increased if it 

could be shown that it was economically attractive to acquire this additional 

lard. 
2.2 UTILITY INTEREST 

The market survey questionnaire was transmitted to 78 utilities in the Southwestern United States, and 61 responses (77 percent) were received. Considering 

the significant efforts required of these utilities to prepare the detailed 

information for their response to the questionnaire, including plant data on 

394 units, the conclusion was drawn /that most of the utilities in the Southwest 

are interested in solar power and, in particular, solar hybrid repowering. 

As discussed in Section 2.1 of this Report, three basic questions were posed to 

the utilities. Table 2.2-1 contains the responses to these questions. 

TABLE 2.2-1. RESULTS OF UTILITY SURVEY QUESTIONS 

Number of Util i ty Responses* 

Quest-Ion - .. - Yes - No 

Has Your Utility Considered the Possibility of 

Solar Power Generation as a Future Alternative? 2 7 2 9 

Would Your Company be Interested in Participating 

in a Solar Hybrid Plant Program if Financial 

Incentives Made it Equivalent or Superior to 

Existing Generation A1 ternatives? 5 1 

Do You Have Any Plans or Interest in Repowering 

Any Units of 200 MWe or Less? 3 9 17 

*Of 61 Utilities responding to the survey, only 56/54/56 elected to answer these 

questions. 

For the first question, related to solar power generation as a future alternative, 

about ha1 f the utilities indicated that they have considered this possibility. 

In answering the second question, 51 of 54 utilities (94 percent) stated that 

their respective companies would be Interested in par~l;icipaLir~y irl a solar. hybrid 

repowering program if financial incentives made it equivalent or superior to 

existing generation a1 ternatives. This high .percentage response was considered 

favorabl e and supportive of the Solar Hybrid Repowering Program. 
Referring to the third question, 39 of 56 utilities (70 percent) indicated that 

they have plans or interest in repowering some of their units of 200 MWe or less. 

This response is indicative of their recognition of the anticipated dwindl ing 

supplies of natural gas and/or fuel oil, cou.pled with the expected rapid escalation in the costs of these fuels. In particular, solar hybrid repowering was 

mentioned by several of the utilities in their questionnaire comments and cover 

letters as an attractive and logical alternative. 

The responses by the u t i l i t i e s t o these t.hree questions are favorable and. 

indicate support of the Solar Hybrid Repowering concept. These responses also 

indicate an encouraging level of utility interest in the program. 

Table 2.2-2 indicates by state the number o f u t i l i t y responses, the number of 

candidate units of - ~200 MWe reported, and the number of candidate units that are 

repowerabl e by solar technology, based on land availabil ity. The majority of 

the utilities are located in the larger size and/or high population states of 

Texas, Louisiana, California, Colorado, New Mexico, Oklahoma and Arizona. 

TABLE 2.2-2. UTILITY DATA QUESTIONNAIRE RESPONSE 

Number of Number of Candidate Number of Candidate 

State Responses Units Reported Repowera bl e Units 

Arizona 

Cal ifornia 

Col orado 

Louisiana 

Nevada 

New Mexico 

Okl a homa 

Texas 

Utah 

Others 

TOTAL 

A total of 394 candidate units of - <ZOO MWe were reported by the 61 utilities. Of 

these 394 units, 372 oil/gas fired units were reported as potentially repowerable 
to some degree by solar energy, based on land availability. As shown in the 

right column in Tab1 e 2.2-2, Texas, California, Louisiana, New Mexico, Arizona 

and Oklahoma [ranked in that order) contain the majority of the units that are 

solar repowerable. As discussed further in Section 2.3 of this Report, the 

effective, solar hybrid repowering potential (in Mw~) and the degree of repowering for each unit, based on land availability, is an important consideration in 

the selection of candidate units for solar repowering. 
2.3 SOLAR REPOWERING POTENTIAL IN THE SOUTHWEST 

The basis for the data in this Report on solar repowering potential is an extensive utility survey of nine states including Arizona, California, Colorado, 

Louisiana, Nevada, New Mexico, Oklahoma, Texas and Utah. In addition, a literature survey of the area was conducted using the following sources: 

Federal Power Commission Form 12 files (2-1 

DOE/RA-0001 "Inventory of Power Plants in the United States" (24 ): 

e Federal Power Commission Regional Re1 iabil ity Council Reports for 

the Southwest 

The literature survey was utilized to supplement the results of the specific 

utility survey where necessary. 

2.3.1 OVERVIEW OF SOLAR REPOWERING POTENTIAL 

A total of 61 utilities in the Southwest responded to the utility survey conducted 

by the Public Service Company of New Mexico. In these responses, 394 units 

- <ZOO MWe were identified. Considering land availability, 272 of these 394 units 

were reported as potentially solar repowerable. Thus, the PNM utility survey 

responses of repowerable units covered approximately 36 percent of all the units 

identified by the literature survey. These 272 units represent 48 percent of the 

total rated generating capacity contained in the literature survey. 

The results of the literature survey and the PNM utility survey (Table 1 .l-1, 

Section 1 .I), coupled with the fact that approximately 78 percent of the utilities 

elected to respond to the survey (61 to 78 utilities), indicate a strong potential 

for, and definite interest in, solar hybrid repowering in the southwestern 

United States. 

The 272 units reported in the utility survey represent 19,749 MWe of rated 

generating capacity. After the reported repowering 1 eve1 s (based on land avail - 

ability) were applied to the rated sizes of the units, 11,171 MWe of effective 

solar repowering potential resulted (see Table 1 .I-]). In some cases, the 

utilities responded with a specific repowering percentage, based on a land 
availability criterion of %6 acres per MWe. In most cases, the utilities reportec 

their repowering levels in brackets of: 0 percent, 1 to 2,5 percent, 26 to 50 percent, 51 to 75 percent, and 76 to 100 percent. In the latter case, the upper 

bound of the bracketed repowering level was applied to the rated size to arrive at 

an effective solar repowering level in MWe. Based on this 11,171 MWe of effective 

solar repowering capacity, a large patential market exists for the solar hybrid 

repowering concept if the approach can be proven to be economically attractive. 

By restricting the distance of the available land to - <2500 feet from the existing 

unit, the number of units is reduced to 206, representing a solar repowering 

potential of 7248 MWe (see Table 1 .l-1). If a further restriction of repowerlng 

percentage (>50 percent) is appl ied to these units, the total potential is 

reduced to 82 units at 5183 MWc of effective solar repowering. It should be noted 

that the latter numbers represent a realistic and practical potential in terms of 

solar repowering because they include: a) only those units the utilities chose 

to report as being candidates for solar repowering, and b) only those units that 

also meet the land distance (<2500-ft) - and repowering percentage (>50 percent) 

restrictions. 

Tables 1 .l-2, 1 .I-3 and 1 .l-4 of Section 1.1 present. a mark~t. ~val~ration sl.lmmary 

(similar to Table 1 .l-1) for non-reheat steam turbine, reheat steam turbine and 

combustion turbine units, respectively. Of the 272 total candidate units, 

152 units (56 percent) with a rated capacity of 7455 MWe and an effective solar 

repowering potential of 3953 MWe were identified as non-reheat steam turbines 

(see Table 1 .l-2). Available land is located within 2500 feet of 116 non-reheat 

units with a repowering potential of 2742 MWe. Based on land available within 

2500 feet of a given unit, a repowering level of greater than 50 percent, and 

utility interest, 47 units at 1983 MWe of solar capacity were identified., 

For the reheat steam turbines summarized in'I'able 1.1-3, 92 carldida1;e units were 

reported with a rated capacity of 11,186 MWe and an effective solar repowering 

potential of 6775 MWe, based on land availability, and 65 units at an effective 

solar repowering capacity of 4138 MWe have land available within 2500 feet. 

When both the land distance and repowering percentage restrictions were applied, 

29 reheat units at an effective solar power capacity of 3068 MWe were identified. 
Of the 272 repowerable units, 28 are combustion turbtnes with 1108 MWe of total 

rated power, representing an effective solar repowering capacity of 443 MWe, as 

shown in Table 1 .l-4. This is approximately four percent of the total effective 

solar repowering potential. Of these units, 25 have available land at <2500 feet - 

and a repowering potential of 368 MWe. Based on available land located at 

- ~2500 feet and a repowering level of >50 percent, six units at 138 MWe of effective solar repowering potential were tabulated in this evaluation. 

A verification of the land available for solar repowering of a few selected units 

has been performed. Of the 82 units at a total of 5189 MWe of solar repowering 

potential (Table 1 .l-I), based on available land at - <2500 feet and >50 percent 

repowering, 23 units with an effective solar repowering potential of 1601 MWe 

were selected from 20 utilities for verification. This was accomplished by 

contacting the specific utilities involved. The results of the verification show 

that 1561 MWe of solar repowering potential (%98 percent of the 1601 MWe initially 

!' 

identified) can be repowered based on the available land. Of these 23 units, 

however, two units have their available land at >2500 feet. Thus, the net solar 

repowering potential of the 21 units at >50 percent repowering and ~2500 feet is 

1421 MWe. 

An evaluation of the size distribution of the units from the literature and 

utility surveys is given in Figure 2.3-1, where the 1 ightly-shaded bars represent 

the number of units from the 1 iterature survey. The concentration of the units 

at the low plant rating levels, particularly in the 0 to 50 MWe categories, is 

obvious from the chart. The darker shaded bars in Figure 2.3-1 represent the 

number of repowerable units reported in the utility survey. A similar concentration of units in the 0 to 50 MWe categories (114 units total) exists. However, it is not as obvious from the figure because the size categories at the 

upper end of the plant rating scale cover a wider band (50 MWe) than the bands 

for those categories at the lower end of the scale (10 MWe, 20 MWe and 30 MW~). 

For equal size band categories, corresponding to the 114 units in the 0 to 

50 MWe range, the following numbers of repowerable units were identified: for 

a plant rating range from 51 to 100 MWe, there are 70 units; for a range from 

101 to 150 MWe, there are 61 units; and for a range from 151 to 200 MWe, there 

are 27 units. 
LITERATURE SURVEY TOTAL - 755 UNITS 

UTILITY QUESTIONNAIRE TOTAL- 272 WITS 

31-59 51-70 71- 190 101-D 151-200 

PLW RATING (PNE) 

Figur? 2.3-1. Cartdidate Units for Solar Hybrid Repowering (Southwestern United States) 
Table 2.3-1 lists the top 20 utilities ranked by effective solar repowering in 

MWe. These utilities have a total effective solar repowering potential of 

9264 MWe, the equivalent of 83 percent of the total effective solar repowering 

potential defined in the survey. Note that the average percentage of repowering for each of these top 20 utilities has.also been shown in Table 2.3-1. 

These results demonstrate that most of the utilities in the southwest have 

sufficient land available for solar hybrid repowering (on the average) at a 

level greater than 50 percent. Conversely, one Louisiana and the three 

California utilities in the top 20, because of the lack of availa,ble land, 

could not repower their units'(on the average) at greater than 50 percent. 

A literature review and a utility (telephone) survey that includes units rated 

above 200 MWe a1 so have been performed. The 1 i terature survey (Table 1.1 -5) 

identified an additional 129 oil- or gas-fired units >200MWe at a total rated 

capacity of 53,459 MWe. These totals should be compared with and added to the 

775 units and 40,954 MWe results (shown in Table 1.1 -1). From the utility" survey, 

61 units at a rated capacity of 25,594 MWe were identified as potentially solar 

hybrid repowerable. All 61 units >200 MWe are reheat steam turbine units. 

Based on land availability, these 61 units represent an effective solar repowering potential of 15,073 MWe (see Tab1 e 1 .l-5). These totals are in addition to 

the 272 units and 11,171 MWe repowering potential (shown in Table 1 .l-1). 

Considering available land at - <2500 feet from the plant, 37 units at 6294 MWe 

of solar repowering capacity were identified. A total of 17 units at 5728 MWe 

of solar repowering potential have land available at - <2500 feet and sufficient 

land for repowering at >50 percent. These totals should be compared with and 

added to the 82 units and 5189 MWe of solar repowering potential (shown in 

Table 1.1-1). 

2.3.2 DETAILED SURVEY RESULTS ON SOLAR REPOWERING POTENTIAL 

/' 

Table 2,3-2 summarizes by state the number of repowerable units, and the corresponding rated power reported in the survey, From the utility survey, it was 

determined that 272 repowerable units exist with a total rated capacity of 

19,749 MWe. Especially noteworthy is Texas with 8482 MWe of total rated 

capacity and 100 repowerable units. 
TABLE 2.3-1 . RANKING OF UTILITIES BY TOTAL EFFECTIVE SOLAR REPOWERING (MW~) 

Ranking State 

1 TX 

2 TX 

3 T X 

Effective 

Utility Solar MWe 

Houston Lighting & Power 1232 MWe 

West Texas Utilities 922 

San Antonio Public Service 660 

Board 

Tucson Gas & Electric 580 

Pacific Gas & Electric 575 

Southern California Edison 509 

Gulf States Utilities 492 

Texas Electric Service 478 

Western Farmers Electric 42 1 

Cooperative 

Sierra Pacific Power 388 

Texas Power & Light 372 

San Diego Gas & Electric 364 

Garland Municipal Power & 342 

Light 

Public Service Company of 3 34 

Okl a horna 

El Paso Electric 304 

Pub1 ic Service Company of 297 

New Mexico 

Nevada Power 278 

Arizona Public Service 278 

Cajun El ectric Power 

Cooperative 

Southwestern Electric Power 208 

Percentage of 

Repoweri ng (Average) 

TOTAL .... 9264 
TABLE 2.3-2. UTILITY DATA QUESTIONNAIRE* RESPONSES BY STATE 

State 

Ar i zona 

Ca1 i.fornia 

Colorado 

Louisiana 

Nevada 

New Mexico 

0 kl a homa 

Texas 

Utah 

Others 

TOTAL 

Number of 

Utilities 

Number of 

Candidate Units 

Total 

Rated Power (MWe) 

*Questionnaire submitted to 78 utilities; 61 responded. 

Table 2.3-3 shows the same breakdown by state, including the effective solar MWe 

and the repowering percentages for each state. The effective solar repowering 

potential (MWe) for each unit was derived by applying the reported repowering 

percentage, based on a land availability of approximately six acres per MWe, 

to the individual rating of the unit. When reported by the utility, specific 

repowering percentages were applied to the MWe ratings of the units. In most 

cases, however, the effective solar repowering potentials were determined by 

applyjnq the upper bound of the appropriate notation to the following repowering 

levels: 0 percent, 1 to 25 percent, 26 to 50 percent, 51 to 75 percent and 76 to 

100 percent. The effective solar repowering potential for each individual unit 

was totaled for each utility and each utility was likewise included in the overall 

state total. The percent repowering for each state is the total effective solar 

MWe divided by the total rated capacity of the repowerable units. The percent 

repowering is an indication of the general repowering potential of units - <ZOO MWe 

in that state. 

The data in Table 2.3-3 make it apparent that some states have a larger power 

generating capability of units - <ZOO MWe, and therefore a high number of rated We 
and effective solar MWe. California, for example, has 5300 MWe of rated 

capacity of repowerable units. California's effective solar repowering potentia' 

is 1602 MWe. Thus, the overall state repowering percentages indicate that the 

availability of land is a major factor in considering solar repowering. This can 

be seen from the fact that California's effective solar MWe potential is 30 percent of its reported MWe capacity. 

TABLE 2.3-3. UTILITY MARKET SURVEY EVALUATION BY STATE 

Number of Effective Percent of 

Candidate Rated Solar Percent Effective 

State Units MWe MW e Repower Solar 

Arizona 

Cal i fornia 

Colorado 

Louisiana 

Nevada 

New Mexico 

0 kl a homa 

Texas 

Utah 

Others 

TOTAL 56.6 (avg) 

These results become important when the repowering percentages are interpreted as 

a function of rated size of the candidate repowerable units, as presented in 

Table 2.3-4. Two high repowering percentage categories are indicated: 1 to 

25 percent, and 76 to 100 percent. The 1 to 25 percent category is large because 

man.y of these units are 1ocat.erl in or near densely populated areas where sufficient 

land is not generally available for significant percentages of solar repowering. 

There are 109 units that can be repowered in the 76 to 100 percent. catqnry. The 

units in this higher percentage of repowering category are clustered around the 

11 to 50 MWe size (41 units) and the 71 to 100 MWe size (28 units) . 

Table 2.3-5 contains an evaluation of land availability and the distance from a 

given unit to this available land. It is significant that 206 repowerable units 

having an effective solar repowering total of 7248 MWe, have land within 2500 feet. 
TABLE 2.3-4. REPOWERING PERCENTAGE EVALUATION OF CANDIDATE 

UNITS (TOTAL NUMBER OF UNITS) 

Repowering Percentage 

Rated Size (MW~) 1 to 25 26 to 50 51 to 75 76 to 100 Total 

101 to 150 32 10 4 15 6 1 

151 to 200 15 0 2 10 27 

- - - - 

TOTAL 125 29 9 109 272 

When the restriction of >50 percent repowering potential is applied to the 

evaluation of land availability and land distance (Table 2.3-5), as shown in 

Table 2.3-6, the total number of repowerable units at a distance of - <259O feet 

is reduced to 82, and the total effective solar repowering potential is reduced 

to 5189 MWe. With the exception of Texas, the ranking of states by total effective solar MWe changes dramatically. With the restrictions of >50 percent 

repowering and - <2500 feet applied to the repowerable units, the ranking of states 

by effective solar MWe becomes: 

. Texas .......... 2999 MWe 

Nevada ........... 503 MWe 

Arizona .......... 378 MWe 

New Mexico .......... 353 Me 

Oklahoma ........... 286 MWe 

Louisiana .......... 274 MWe 

Others .......... 200 MWe 

Cal i fornia ........... 166 MWe 

Colorado .......... 30 MWe 

Utah .......... ---- 

TOTAL .......... 5189 MWe 
TAELE 2.3-5. UTILITY MARKET SURVEY RESULTS - EVALUATION OF LAND AVAILABILITY 
TABLE 2.3-6. UTILITY MARKET SURVEY RESULTS - EVALUATION OF LAND AVAILABILITY 

FOR CANDIDATE UNITS HAVING >50 PERCENT REPOWERING POTENTIAL 
In the above ranking of states, the restrictions of greater than 50 percent 

repowering and - <2500 feet show that Texas, Nevada, Arizona and New Mexico are 

the major contributors to the total practica,. repowering potential in the Southwest. This ranking reflects the fact that many of the repowerable units in 

these states are located in rural areas that generally have enough available 

land to repower to a relatively high percentage; frequently to 100 percent. The 

"others" listed above is actually one utility, located outside the nine-state 

survey, that requested to be involved in the Solar Hybrid Repowering Program. 

The total of 5189 MWe represents the practical solar repowering potential because 

this total power level includes: a) only those units that the utilities chose 

to report as repowerable candidates, b) only those units that are within a distance of 2500 feet of the available land, and c) only those units that can be 

repowered to >50 percent. 

Of the 11,171 MWe of total effective solar repowering potential , approximately 

9980 MWe ($89 percent) represents units located at plants with mu1 tiple units. 

The concept of multiple units located at a given solar hybrid repowered plant 

lends itself to the possibilities of steam sharing* from other existing units 

to assist in providing a more economic and a more flexible solar repowered plant. 

2.3.3 EXTENSION OF SURVEY TO UNITS ABOVE 200 MWe 

As discussed in Section 2.3.'1, a 'literature survey and a uti'lity survey to 

include units rated above 200 MWe also have been performed (see Table 1.1-5 in 

Section 1.1). The number of units, the rated power, and the solar repowering 

potential based on land availability and the various constraints, from these 

*Steam Sharing: Fossil generated steam is borrowed from an adjacent unit. 

The steam sharing option is attractive from the standpoint of minimizing 

the fossil fuel required to operate the repowered plant or increase or 

maintain the power generated by the multiple unit plant. Further details 

on the costlbenefit aspects of the steam sharing option are discussed in 

Section 2.5 of this Report. 
surveys as presented in Section 2.3.1 will not be repeated here. It should be 

noted, however, that all 61 units >ZOO MWe identified by the utility survey are 

reheat steam turbine units. 

Table 2.3-7 contains a breakdown by state of the utility market survey evaluation 

for the 61 units rated above 200 MWe. The number of units, rated power, and 

effective solar repowering potential are given for the four states that reported 

data for the utility survey. A total of 43 units at an effective solar power of 

9220 MWe are located in Texas. 

TABLE 2.3-7. UTILITY MARKET SURVEY EVALUATION BY STATE 

FOR UNITS ABOVE 200 me 

Number of Rated Effective Solar 

State Candidate Units MW e MW e 

Cal i fornia 2 666 666 

Louisiana 

Oklahoma 

Texas 

TOTAL 
2.4 CANDIDATE REPOWERING UNIT DESCRIPTION 

An overview of the typical candidate repowering unit description and an assessment of the utility survey results for the candidate unit description are presented in the following subsections. 

2.4.1 CANDIDATE REPOWERING UNIT DESCRIPTION OVERVIEW 

Table 2.4-1 shows the characteristics and general data of the typical candidate 

unit for solar hybrid repowering, as determined from the utility and literature 

surveys. The typical candidate unit is a non-reheat steam turbine with an overa1 1 power generating capacity between 10 and 50 MWe (see Figure 2.3-1 and 

Table 2.3-4). The steam turbine in1 et conditions include a throttle pressure 

range of 850 to 1250 psig and a turbine inlet temperature range of 900' to 950°F 

at the nominal unit MWe rating. 

TABLE 2.4-1. TYPICAL CANDIDATE UNIT FOR SOLAR HYBRID REPOWERING 

Unit Characteristics 

Type ....... Non-Reheat Steam Turbine 

Rating ....... 10 to 50 MWe 

~urbir~k Inlet. ....... 850 lu 1250 pb,i/90On Lo 950°F 

General Unit Data 

Y~ar Rl~il t. ........ 1950 to 1960 

Condition ....... Good 

Current Use ....... IntermediateIPeak 

Location ....... Rural 

Estimated Retirement ....... Before 2000 

The general unit data indicate that the typical candidate repowering unit is in 

good condition and was bui l t (or went into initial service) between the years 

1950 and 1960. The typical repowering unit is being used for intermediate or 

peak load service and has an estimated 20 to 25 years of useful service before 

its planncd rctircmcnt. The typical candidate unit is located in a rural area. 
2.4.2 SURVEY RESULTS FOR CANDIDATE REPOWERING UNIT DESCRIPTION 

The selection of the,appropriate characteristics and general data for the 

repowering candidate unit was based on a detailed assessment of the utility 

survey results and the parallel literature survey information. As shown previously, ,272 repowerable units representing 19,749 MWe of total rated capacity 

were identified by the utility survey. Table 2.4-2 shows a breakdown of this 

potential by state and repowering unit type (steam turbine or combustion turbine). A total of 244 steam Rankine cycle units were identified by the survey, 

which represents 18,641 MWe of rated capacity. Table 2.4-2 also shows that 

28 combustion turbine units representing 1108 MWe of rated capacity were identified by the survey. 

TABLE 2.4-2. EVALUATION OF REPOWERING UNIT TYPE 

Steam Turbine Combustion Turbine 

State Number of Units Rated MWe Number of Units Rated MWe 

Arizona 

Cal i fornia 

Colorado 

Louisiana 

Nevada 

New Mexico 

Oklahoma 

Texas 

Utah 

others 

TOTAL 

When the restrictions of available land at a distance - ~2500 feet from the candidate unit and >50 percent repowering based on land availability (see Tables 1.1-1 

and 2.3-6) are appl ied, the number of repowerable candidates (both steam and 

combustion turbines) was reduced to 82 units representing 5189 MWe of effective 

solar repowerable potential. Included in the 82 units are six combustion turbines with a total of 138 MWe of effective solar repowerable potential (see 

Table 1 .l-4). It can be concluded that steam turbines are typical candidate 

units for solar hybrid repowering. 
Tab1 e 2.4-3 categorizes, by state, the repowerabl e steam turbines (244 units 

total) as either reheat or non-reheat. Since the number of non-reheat units 

exceeds the number of reheat units by a factor of 1.65, a non-reheat steam 

turbine was selected for the typical candidate unit. 

TABLE 2.4-3. EVALUATION OE REPOWERABLE STEAM TURBINE UNITS 

Non-Reheat Reheat 

State Number of Units Number of Units State Totals 

Arizona 

Cal i fornia 

Colorado 

Louisiana 

Nevada 

New Mex i co 

0 kl a homa 

Texas 

Utah 

Others 

TOTAL 

Table 7.4-4 categorizestherepowerable steam turbine units by plant rating (MWe) 

and by typical operating condl L lulls. The tab1 c maintains th~ reheatlnon-rehedl 

unit type distinction shown in the prev iuus table. Or the 152 non-reheat units, 

95 units (62 percent) have inlet conditions of 850 to 1250 psig and 900" to 

950°F. A total of 51 of the 92 reheat units (55 percent) have inlet conditions 

of 1800 psig and 1000°F with a 1000°F reheat cycle. 

The selection of the non-reheat steam turbine as the typical candidate unit is 

in line with the first-generation waterlsteam receiver tethnoluyy being developed 

by the Department of Energy. The selection also was based on the fact Lhat a 

reheat cycle unit would require: 

e A more complex solar receiver at the top of the tower 

e Additional extensive lengths of steam piping between the receiver 

at the top of the tower and the existing turbine generator 

(possibly including significant horizontal runs) 
Non-Reheat Units Reheat Units 

Pressure: 350 psi 600 psi 850 psi 1250 psi 1450 psi 1450 psi 1800 psi 2000 psi ToTALs / 

1000°F 1000°F l0OO0F 1 i 

Temperature: 625°F 825°F 900°F 950°F 950°F 1000°F 1000°F 1000°F I 

Plant Ratina (MWe) 

I 0 to 10 12 12. 

I 11 to .25 3 10 

i I - 26 to 50 4 1 

I 51 to 75 

76to100 I 

I 

I 101 to 125 

I 126 to 150 1 151 to 200 

- - 

' TOTALS 19 2 3 

I 
0 A more elaborate interface with the existing fossil boiler 

(intermediate as we1 1 as high pressure sections) 

A.more complex control system 

Reheat cycle steam turbine units are still considered to be excellent candidates 

for solar hybrid repowering, particujarly when the advanced receiver concepts, 

such as those using liquid sodium or molten salt, are developed. These concepts 

are under study by the Department of Energy, and testing is expected to be compl eted by the end of 1980. 

I 

Table 2.4-5 shows the additional features that are typical of the candidate unit. 

It a1 so shows that most of the non-reheat units (81 ) were built between 1951' and 

1960, are generally in good condition (110 units), and have an estimated retirement date before the year 2000, The same conclusion can be drawn on the year 

built, unit condition, and estimated retirement fur the reheat units with one 

exception: most of the reheat units are scheduled to be retired after the year 

2000. Most of t,he non-reheat units are used for intermediate (45 units) and peak 

(46 units) load service, while most of the reheat units are used for intermediate 

and base load service. Data on general plant locatinn indicate that the typical 

candidate unit is located in a rural area. 

Most of the utilities (50 out of the 54 reporting such data) established the time 

of their system peak load demand as occur.ring betwccn 8:00 a.111. and 4:00 p.m. in 

the summer. In the winter, 34 utilities (out of 53 rel~or*Li~~y such data) @stablished the time of their system peak load deliland as also occurring between 

8:00 a.m. and 6:00 p.m. This period corresponds to the period of best solar 

insolation. 
TABLE 2.4-5. 

Steam Turbi,ne -- Steam Turbine -- Combustion 

Non-Reheat Reheat Turbine 

Category : 

Year Bui I t Totals 

Before - 1941 

1941 - 1950 

. 1951 - 1950 

1961 - 1970 

1971 + 

General Unit Condition 

New 

Good 

Fair 

Poor 

Current Use 

Base 

Intermediate 

Peak 

Standby 

Estimated Retirement 

1973 - 1980 

1981 - 1990 

1991 - 2000 

2009 + 

General PI ant Location 

Industri a1 

Suburban 

Urban 

Ru ra 1 
2.5 COSTIBENEFIT ANALYSIS 

The integration of solar hybrid repowering plants into electric utility systems 

raises a number of questions as to the value of the plants, problems they might 

introduce, and requirements that should be placed upon them. A cost/benefit. 

analysis was performed .for selected southwestern utilities to assess the prospective value and impact of solar hybrid repowered plants upon electric utility 

systems. The analysis was performed utilizing the methodology developed by Westinghouse as part of EPRI Contract RP 648-1 entitled "Requirements Definition and 

Impact Analysis of Solar Thermal Power Plants." 

Four southwestern utilities were selected for analysis on the basis of the results 

of the market survey discussed in the previous sections. The utilities selected 

for analysis were: 

a Publ ic Service Company of New Mexico (PNM) 

a Arizona Publ ic Service Company (APS) 

a Nevada Power Company (NPC) 

a EPRI Synthetic Utility System E (Texas, Louisiana and Oklahoma) 

A reference 50 MWe solar hybrid repowering plant was defined for performing the 

costlbenefit analysis based on the characteristics of the typical candidate unit 

defined in Section 2.4 of this Keport. The results of the ~ubllbensrit analysis 

indicate that the solar hybrid repowering concept has the potential to be economically attractive for utility applications when compared with conventional methods 

of electric power generation (a cost/benefit ratio of 0.94 for a repowered unit 

operating as part of Synthetic Utility System E). 

2.5.1 METHODOLOGY 

For the proper assessment of the prospective value and impact of solar hybrid 

repowered plants upon an electric utility system, detailed modeling of the operation of such a plant is required. This modeling must involve the interactive 

dispatch of the solar plant with other generation units on the utility system. 

Through this procedure proper sizing of the solar plant and its subsystems, Such 

as solar collector area, can be ascertained. Solar plant operational strategie: 

involving the use of the fossil boiler also can be evaluated. 
The sophisticated methodology developed for analyzing the solar hybrid repowered 

plant consists of the coordinated use of several computer models and procedures 

for economic evaluation (Figure 2.5-1). The basis of the evaluation models is 

a set of Westinghouse Electric Corporation utility planning computer programs and 

a specially developed solar plant model. The utility models include a production 

costing model that simulates the operation of the balance of the utility system 

in bi-hourly increments. Capacity credit is calculated using a loss-of-load 

probability model capable of accepting a probability distribution for the avail - 

ability of the solar plant. A detailed discussion of the economic analysis 

methods is given in Appendix B; a brief summary is presented below. 

The methodology implemented for economic and reliability system impact assessment relies heavily upon system simulation. The Load Projection, Load Statistical 

Analysis, Reliability Analysis and Detailed Production Cost blocks (Figure 2.5-1) 

are separate existing Westinghouse models (computer programs) that are routinely 

used to analyze utility systems. These models have had minor modifications to 

allow them to interface with the Solar Thermal Plant Model. This latter model 

is a modified version of the one developed by Westinghouse as part of EPRI Contract RP 648-1. The projected hourly system load is input to the solar plant 

model, which simulates the operation of the solar plant and outputs for further 

analysis the remaining load to be served. The solar plant model uses.incrementa1 

operating cost data for the balance of the utility system to guide its dispatch. 

This is particularly important for the optimum conservation of fossil fuel. 

Figure 2.5-2 shows the basic solar hybrid repowering plant model used for the 

costlbenefit analysis, including the assumptions used to develop the model. 

Included in the model is a dispatch routine that recognizes balance o f u t i l i t y 

system incremental costs, turbine efficiency variations, and insolation projections. The dispatch rule that has been implemented is shown in Table 2.5-1. 

The dispatch rule is a daily iterative procedure that relies upon a simple 

preliminary dispatch, which is iteratively i~~~proved. This rule utilizes an 

assumption of foreknowledge of the full day's insolation and load profile at 

the beginning of each day. It also uses information as to the incremental 

operating cost of the utility system at various load levels, along with the 

various snlar plant. efficiencies. 
Figure 2.5-1 . Model Usage Flow 

HISTORICAL LOAD 

~err.r- -0- 7 roo-oooo-o LOAD PROJECTION 

I PENETRATION 

(BASE CASE) I r---------- i 

I I SOLAR THERMAL. OUTAGE 

I 

1 I MODEL 

I I 

+ INSOLATIONQ - -- - 1 

I 

INC COSTS I I 

I I 

I I OUTPUT 1 I 

T v MOD1 FlED LOAD I I 

I I 

I I 

I I 

I I 

I I 

I I 

v 

LOAD STATlSTlCAL 

ANALYSIS 

FUEL 

b. 

COSTS 

v I I 

RELIABILITY BALANCE OF + DETAILED 

I 

+- -J ANALYSIS 

4, 

CAPACITY CREDIT 

4 

OPERATING COSTS 

RELIABIL!TY FUEL CONSUMPTION 

SYSTEM - PRODUCTlON COST 
6 

FOSS! L 

BOILER * 

BOP 

L 

SOLAR 

The solar plant model developed as part of EPRI RP-648 will be 

used in the costlbenefit analysis. 

Plants will be operated to maximize the benefit of the solar 

repowering. 

Plant can operate from either solar, fossil, or a combination of 

solar and fossil. 

Aerospace insolation tapes will be used for the analysis. 

The repowering model will be based on steam turbine plants. 

Wet cooling towers will be used for the heat rejection system. 

The days insolation profile and load demand are known. 

Figure 2.5-2. Solar Hybrid Repowering Model for Cost/Benefit Analysis 

For realism in the modeling of the operation of the hybrid plant, those items 

shown in Table 2.5-1 include fossil fuel consumption to bring the boiler u'p to 

temperature, accounting for both fuel consumption and the time required. Operat-' 

ing scenarios where the boiler heat is maintained (stand-by) is an option' in the 

program. 

Logic requiring fossil boiler energy to buffer the turbine during insolation transients a1 so has been incorporated. The skycover conditions are sampled hourly 

from the insolation tape to determine when insolation transient conditions apply. 

To prevent excessive cycling of the turbine, the plant is fired to run through 

what otherwise would be a brief shutdown period. When wind speeds exceed the 

input design 1 imits, the he1 iostats 'are assumed stowed and no solar energy is 

collected for that hour. Both boiler and turbine generator part-load efficiency 

curves are incorporated ir~ the solar plant model. t 
TABLE 2.5-1. SOLAR HYBRID REPOWERING MODEL DISPATCH 

-- 

- Oil Startup Logic 

- Oil Buffer for Insolation Transients 

- Closeup Potential Shutdown Windows 

- High Wind Speed Solar Shutdown 4 

- Boiler Efficiency Corrections 

- Oil Reocvery of Low Insolation 

- Economic Oil Dispatch 

- Hot Stand-by Oil (Option) 

- Economic Shutdown at End of Day 

- Cost/Benefit of Daily Oil Use 

RECOGNIZING -

- Foreknow1 edge of Day's Insolation Profile 

- Foreknowledge of Day's Load Profile 

- Util i ty System Increrrrental Cost Curve 

- Fossil Boiler Limits and Efficiency 

- Turbine-Generator Limits and Efficiencies 

-- Insolation High Transient. Conditions 

- Operational Wind Limits , . .- .... -. 

When the insolation is not sufficient to operate the lurbit~e at its minimum level 

and a specified insolation threshold is exceeded, the boiler is fired to provide 

enough supplemental energy to salvage the insolation and operate the turbine 

generator. 

The incremental cost of competing conventional plants is tested hourly to establish whether additional fossil firing is justified. A test is made to deterr~rir~e 

whether it is economically advantageous to start the boiler each day, or to leave 

Ltie boiler cold and suffer operating consequences such ac nn electrical output 

during solar transients. The proper boiler shutdown hour is also established on 

an economic dispatch basis. 

The economic methods developed use conventional Revenue Requirements analysis, 

recognizing both the time value of mon.ey and independent escalation of various 

cost elements. ~6ese methods are consistent with electric utility practice and 
provide the needed flexibility. The Revenue Requirements methodology is also 

consistent with the EPRI economic evaluation guidelines stipulated in the 

August 1977 EPRI "Technical Assessment Guide." The principal economic measures 

of solar plants implemented in this methodology are shown in Table 2.5-2. 

TABLE 2.5-2. SOLAR PLANT ECONOMIC MEASURES 

Q Solar Plant Value 

- Operating cost Savings 

- Capital Investment Displacement 

e Solar Plant Busbar Energy Cost 

- Plant Capital Cost 

- Plant Operating Cost 

- Energy Produced 

e Utility System Cost Impact 

- Solar Plant Costs 

- Utility Differential Costs 

e Solar Plant CostIBenefit Ratio 

- Solar Plant Lifetime Costs 

- Solar Plant Lifetime Value 

Because of the uncertainty of the costs of certain portions of the solar plant, 

particularly under mass production conditions, the economic value of the solar 

plant was assessed independent of its costs. The value arises potentially from 

both operating cnst. savings and capital cost savings to the balance of the 

utility system. The operating cost savings are derived from reduction in fuel 

consumption and variable operating and maintenance costs. The capital cost savings arise from reduced conventional capacity requirements and a potential shift 

in the mix of conventional units. 

The operating value of solar repowercd plants results 'Prom d reductlon in energy 

production by the balance.of the electric utility system. The reduction in conventional plant operation saves fuel and variable operating and maintenance (O&M) 

costs on the most costly (operating cost) units that would have been operating at 

the time the solar repowered plant is producing power. Since the solar repowered 
plant operates during different times of the day and throughout the year, the 

highest cost conventional unit being displaced changes. Thus the operating credi 

varies with the utility system chronological load shape and the mix of available 

generation, as well as with many other parameters. The major parameters affecting the operating value of a solar repowered plant are shown in Table 2.5-3. 

TABLE 2.5-3. OPERATING VALUE FACTORS 

Insolation Characteristics 

Utility System Load Shape 

Utility Mix of Generating Units 

Fuel Cost and Escalation Projections 

Conventional Unit Heat Rates 

Variable O&M Cost and Projections 

Plant Collector Area 

Penetration of Solar Hybrid Repowered Plants 

Present Worth Discount Rate 

Capacity credit can be interpreted as the megawatts of conventional generating 

capacity not required to be instal led due to the presence ,of the solar repowered 

plant or in terms of the dollars represented by this saved capacity. The capacity credit can be taken only for those years of operation of the repowered plant 

beyond the normal retirement date. From an analysis standpoint, megawatt savings 

may be considered first and then converted to dollars. In general, for a solar 

hybrid plant, 100 percent capacity credit can be considered for those years of 

operation beyond the normal retirement date due to the presence of the fossil 

boiler. This is not true for solar plants having thermal storage. 

The busbar energy costs, which are consistent with ERDAIEPRI guide1 i nes , are 

functions of solar plant cost and electric energy production. 

The net economic impact of a solar plant upon a utility system is calculated by 

subtracing the solar plant value frui~i its estimated costs. 

The costlbenefit ratio is calculated by dividing the present worth of solar plant 

lifetime costs (revenue requirements) by the present worth of its 1 ifetime value. 
Since the inclusion of plant value (to a specific utility system) as well as 

plant cost is considered in determining the economic choice, the cost/benefit 

ratio was selected as the primary evaluation ceiterion. 

Since the solar repowered plant operates during different times of the day and 

throughout the year, the highest cost conventional unit being displaced is not 

constant. For example, during reduced-load periods of the day, the solar 

repowered plant may displace energy normally provided by a base unit. On the 

other hand, the solar repowered plant will displace a peaking unit on the days 

in which the load is high. The operating credit varies with the utility system 

chronological load shape and the mix of available generation, as well as with 

many other parameters. 

Conventional unit heat rates used to determine the ir~cremental cost of the system 

at various load levels range from approximately 9000 Btu/kWhr for base loaded 

coal units to 14,000 Btu/kWhr for combustion turbines. 

Capacity credit can be interpreted as the megawatts of conventional generati'ng 

capacity not required to be installed due to the presence of the solar power 

plant or in terms of the dollars represented by this saved capacity. Megawatt 

savings may be considered first, and then converted to dollars. In general, for 

a solar hybrid plant, 100 percent inegawatt capacity credit can be considered, 

due to the presence of the fossil boiler. The do1 lar capacity credit is a function of not only capacity displaced, but also of the types of generating units 

being displaced. This is determined by the use of optimal breakpoint analysis 

(defined as the most economic mix of peaking, intermediate and base load units 

required to satisfy a given utility system load) applied to the original and 

adjusted system loads. Although operating as an intermediate unit, hybrid solar 

plants can be cbserved to optimally displace a combination of peaking, intermediate and base load capacity. 
Unlike the solar hybrid plant, a solar stand-alone plant cannot claim 100 percent 

capacity credit. Of major importance to the capacity credit is the ability of 

the solar plant to produce power during the utility system demand peak. The 

correlation of insolation with system demand on both a daily and seasonal basis 

is quite important. Some relaxation in the daily correlation can be accepted 

with major degradation in capacity credit provided adequate solar energy is 

collected on a daily basis and adequate thermal storage exists. Daily load peaks 

that occur after sunset cause decreases in capacity credit, even with sufficient 

energy storage, because of the turbine generator derating when operating from the 

first generation storage subsystems being developed for solar plants. The second 

generation storage subsystems being evaluated may not require a turbine generator 

derating. 

In addition to the daily load correlation with insolation, seasonal correlation 

is also important. If the annual load peak for a system generally occurs in 

August, the quality of the insolation in August can play a dominant role i,n 

establishing the megawatt capacity credit. This is due to the peak demand month 

establishing the system install capacity requirements. 

Penetration and geographic dispersion also impact the capacity credit. As more 

solar capacity is added to the system, the ease is diminished with which the next 

solar plant can further reduce the daflgi load peak. High L~III~! ~ur~r-eldli~~~ or 

insolation among solar plants in a service area reduces the capacity credit, and 

the degree of geographic dispersion for several plants is also important. 

2.5.2 REFERENCE PLANT DESCRIPTION 

A reference solar hybrid repowered plant concept has been established for the 

purpose of performing the costlbenefit analysis. The reference concept consists 

of repowering existing gas- and oil-fueled electric power generating units to 

operate on solar energy when it is available. The concept will displace a large 

portion of or all the fossil fuel normally used during day1 ight hours. The 

ability of the plant to operate on fossil fuel is retained, however, to provlde 

full backup capacity and maximum operational flexibility during the periods of 
inclement weather, as well as the potential for conventional electric power 

generation at night. The basic concept utilizes the solar hardware and technology being developed for the 10 MWe solar central receiver pilot plant to be 

built near Barstow, California. 

The reference solar hybrid repowered plant has been defined utilizing the characteristics of the typical candidate unit resulting from the market survey. 

Table 2.5-4 summarizes the characteristics of the reference plant, a 50 MWe steam 

plant having a non-reheat steam turbine. The solar subsystem has been sized to 

provide 100 percent repowering based on an insolation level of 950 watts/mZ and 

a net solar plant efficiency of 17 percent (the ratio of electric.power outpllt 

to solar insolation available to the heliostat field). The net solar plant 

efficiency of 17 percent is based on analyses performed for similar plants during 

studies under EPRI Contract RP 648-1. The optimum heliostat field size depends \ 

in general on the utility system. Therefore, a parametric analysis of field size 

was performed during the cost/benefit analyses. 

The solar system design is characterized by an external receiver mounted on a 

tower located in a 360" array of two-axis sun-tracking heliostats. These heliostats comprise the collector subsystem. Feedwater from the electrical power 

generation subsystem is pumped through a riser to the receiver and converted to 

superheated steam in a single pass through the tubes of the receiver panels. The 

steam from the receiver is routed through a downcomer to ground level and transported from the tower base through horizontal steam lines to the turbine. 

The collector field has been sized to provide for 100 percent repowering of the 

50 MWe fossil plant; 8160 heliostats having a total mirror area of 310,000 m 

2 

2 

are required to produce 50 MWe at an insolation level of 950 watts/m . The 

2 950 watts/m insolation level assumed for sizing the collector fields is representative of 2:00 p.m. winter solstice conditions, which is the design point for 

the solar t+epower.iny project being used by PNM. Since the insolation level 

varies throughout the year (peak value to about 1100 watt's/m2), there will be 

pcriods when the thermal power producing capability of the heliostat f i e l d w i l l 

exceed the turbine generator 50 MWe rating. During those periods, a portion of 

thc hcliostat field coitld he defocused in order not to exceed the turbine 
TABLE 2.5-4. SOLAR HYBRID REPOWERED PLANT REFERENCE PARAMETER SUMMARY 

Plant Type ................ Steam Turbine/Non-Reheat 

Plant Rating ............... 50 MWe 

Plant Repowering Percentage* ... .,. .. 100% 

Plant Operating Scenario .......... Maximize solar benefit 

Fossil operation only on cloudy days 

Economic dispatch fossil energy 

Collector Subsystem: 

- Field Configuration .......... 360' 

- Field Area ............... 300 Acres 

- Heliostat Area 310,000 m 

2 ............. 

- Number of Heliostats .......... 8160 

Receiver/Tower Subsystem: 

- Receiver Type ............. External (single pass to superheat) 

- Receiver Size ............. 15 m dia by 27 m long 

- Tower Height .............. 175 m 

Electric Power Generation Subsystem: 

- Cycle ................. Steam Rankine 

- Net Plant Efficiency .......... 33% 

- Turbine Inlet ............. 950°F/1250 psi 

- Heat Rejection ............. Wet Coolinq Tower 

Fossil Boiler: 

- Type .................. Oil 

- Rated Load Efficiency ......... 82% 

-Start-up. ............... Cold 

3 

"Based on an insolation level of 950 watts/mL 
generator rating. Turbine generator units can nominally operate in excess of 

their nameplate ratings (15 percent or greater), and a solar repowering level 

at 100 percent of nameplate may allow for complete utilization of available 

insolation throughout the year. This effect will be system and unit dependent 

and is beyond the scope of this evaluation. A subsequent detailed analysis of 

one of PNM's units is planned to evaluate the effect of permitting unit operation in excess of the nameplate rating. 

2 Since the 310,000 m reference collector field may not represent the most cost 

effective size, one of the sensitivities being considered in the cost/benefit 

2 analysis is collector field size. Two collector field sizes - 163,000 m and 

233,000 m2 - have been established in addition to the reference field for the 

cost/benefit analysis. These latter two collector fields represent, on the 

basis of the design insolation level of 950 watts/mZ, a repowering percentage 

of 50 percent and 75 percent, respectively. 

The ability to operate on fossil fuel has been maintained in the repowered plant 

concept. The plant can operate and produce 50 MWe using steam generated from 

the solar subsystem, the fossil boiler, or a combination of both fossil or solar. 

It is assumed that the plant will operate either on fossil fuel alone, or on 

steam produced by a combination of solar and fossil fuel during cloudy days. A 

cloudy day for the purpose of the cost/benefit analysis is defined as a day during which sky cover exceeds 0.5 for two or more consecutive hours. 

In general, any day in which sky cover exceeds 0.3 can be classified as cloudy. 

As part of EPRI Contract RP 648-1, a comparison between insolation transients 

(for various degradation levels and time periods) and sky cover for a range of 

0.3 to 0.7 for Albuquerque, New Mexico indicated that a correlation between 

these variables was not possible from the existing data base. For example, a 

sky cover of 0.3 on the data records may correspond with more insolation transients of greater magnitude and longer duration than a sky cover 0.7 and viceversa. A sky cover value of 0.5 was selected until improved weather records 

and data on sky cover versus insolation transients are available, or until 

planned pilot plant experiments for solar thermal electric plants produce data 

indicating a correlation between sky cover and plant operating capabil i ties on 

"solar only." 
The operation scenario assumed for the fossil boiler is important in determining 

the economic benefit of solar hybrid repowering. In order for the fossil boiler 

to be capable of responding to insolation variations during periods of intermittent cloud cover, the boiler must be operating at a minimum of 25 percent of 

rated thermal output. The boiler response time to achieve 100 percent rated output from an operating level of 25 percent of rated output is approximately 10 to 

15 minutes.* The cost of the fossil fuel required to maintain the boiler at 

25 percent of rated output is high, and it subtracts directly from the economic 

benefit derived from operating the plant on solar energy. A strong incentive 

exists to minimize the amount of fossil fuel consumed in a solar hybrid repowered 

plant. 

Three operating scenarios have been established and simulated for the fossil 

boiler for the purpose of performing the cost/benefit analysis. These scenarios 

use approximate boiler operating parameters and do not necessarily represent any 

specific boiler. These scenarios are: 

e The fossil boiler operated only on cloudy days - The fossil boiler 

is assumed to be started from a cold condition for each cloudy day. 

A ten hour startup period is assumed for the boiler in order to 

reach 25 percent of rated load; the fossil fuel cur~su~ned during 

startup is approximately 750 MBtus. The fossil boiler is maintained in the hot standby condition (25 percent of rated load) 

throughout the cloudy day. The boiler firing is increased If It 

is economical to supplement the steam produced by the solar 

receiver (whcn compared to generating the equivalent power []sing 

units within the balance of the utility system) or if it is 

required in ordet- to overcome severe insolation transients in 

order to maintain steam conditions at the turbine inlet. The 

boiler is shut down at the end of each cloudy day. 

a The fossil boiler is operated every day - This scenario assumes 

the fossil boiler is operated on both clear and cloudy days and 

is shut down for routine or forced maintenance. During those 

periods of the day when the plant is operating from solar generated steam, the fossil boiler is maintained in the hot standby condition similar to the above scenario. At the end of the 

day, however, the boiler is "banked" and maintained in a warm 

standby condition overnight. The boiler is also "banked" during days when it is not economical to operate the plant from 

*Boiler operating characteristics/constraints will be dependent on the specific 

design and may vary significantly from the typical values presented here. 
either solar or fossil energy. The amount of energy required to 

maintain the boiler in a warm standby (banked) condition is 

approximately 7.5 MBtu for 12 hours. The boiler can achieve 

25 percent of rated output from the warm standby condition in 

approximately 1 to 2 hours. In order to account for scheduled 

and forced plant outages throughout the year, three "'coldi' 

starts of the boiler have been included in the costlbenefit 

analysis for this option. 

Steam sharing - This scenario assumes that the repowered unit is 

part of a mu1 tiple unit station. The results of the market survey indicated that approximately 90 percent of the candidate 

units were part of a multiple unit station. A.dedicated boiler, 

in this option, would not be proposed for the repowered unit; 

rather, the repowered unit would use steam produced from a 

boiler dedicated to an adjacent unit at the plant (even if the 

power produced by the adjacent unit had to be reduced to provide 

steam to the repowered unit and the balance of the utility system had to be utilized to offset the loss in power generation by 

the adjacent unit). The amount of fossil fuel required for starting the boiler and maintaining the boiler in a "banked" or hot 

standby condition as required for the options discussed above 

would not be required for the steam sharing option. Steam would 

be supplied to the repowered unit from an adjacent unit only 

when required to maintain the operation of the repowered plant 

during cloudy days. The cost of the fossil fuel to provide the 

steam must be accounted for in establishing the overall economic 

benefit of solar repowering. The steam sharing option, however, 

is attractive from the standpoint of minimizing the fossil fuel 

required to operate the repowered plant. 

Table 2.5-5 defines the capital cost of the reference solar hybrid repowered 

plant. The estimates for the solar subsystem cost for the first and Nth commercial plants are based on Sandia's evaluation of the results of the Phase I 

Central Receiver Program Preliminary Designs. The estimated heliostat costs 

7 for these plants are approximately $160/m and $100/m7, respectively. The 

DOE heliostat cost goal estimate is based on achieving a heliostat cost of 

2 $651111 . The cost estimates for the other plant components are based on the 

results of the conceptual design to date obtained in Task 1500 of the subject 

Assessment Study. 

2.5.3 ECONOMIC ANALYSIS BASIS 

The economics used in the preliminary analysis are an attempt to represent the 

costs and value as viewed directly by the utility. That is, it is somewhat of 
TABLE 2.5-5. REFERENCE SOLAR HYBRID REPOWERING PLANT (50 MW~) 

COST ASSUMPTIONS (1 977 M-$) 

First Nth DOE 

Commercial Commerc i a 1 He1 iostat Goal 

Land 

Structures and Faci 1 i ti es 

He1 iostats 

ReceiverITower 

Turbine Pl ant Equipment 

Electric Plant Equipment 

Mi scel 1 aneous 

TOTAL DIRECT 

Contingency and Spares (1 5%) 10.5 7.6 6.0 

Indirect Costs (1 0%) 7.0 5.1 4.0 

TOTAL CAPITAL INVESTMENT 87.5 63.5 50 -0 

IDC (15%) 

TOTAL CAPITALIZATION 

Escalated to 1985 (@ 7%/yr) 172.8 125.4 98.8 

Annual O&M 1985 (3%) 5.2 3.7 , 3.0 
a microeconomic approach in that it does not consider any potential gains in 

national Balance of Payments conditions, environmental or employment gain benefits, or any other socioeconomic factors. These additional factors might be 

reflected by Federal incentive programs that are not considered in this Report. : 

The basic economic assumptions used in the subject analysis are shown in 

Table 2.5-6. For solar repowering, an 18 percent Fixed Charge Rate was used on 

the new investment. The operating and maintenance costs were assumed to be . 

three percent of the capitalization the first year, with an escalation rate of 

eight percent ann,ually. The operating and maintenance costs may eventually be 

considerably reduced from the values assumed for this analysis as more definitive designs are prepared and more substantial hardware experience obtained. A 

present worth discount rate of 11 percent was used for all analyses. 

TABLE 2.5-6. REFERENCE ECONOMIC ASSUMPTIONS (1 985 $, 

PRESENT WORTH DISCOUNT RATE 11 PERCENT) 

Combustion Combi ned Coal Nucl ear 

Turbine Cyc 1 e Plants Plants -..-- 

Capital Cost ($/kWe) 300 600 1400 1,500 

Capital Escalation Rate (%/yr) 10% 10% 10% 10% 

Carrying Charge Rate (%) 20% 18% 18% 18% 

Fixed O&M ($/kW-yr) 

Variable O&M (mil ls/kW-hr) 

O&M Escalation Rate (%/yr) 

Fuel Cost ($/MBtu) 

Fuel Escalation Rate (%/yr) 

Heat Rate (Btu/kW-hr) 

Schedul ed Maintenance (weeks/hr) 

Forced Outage Rate (%) 

*Nine percent to the year 2000; 13% thereafter. 
The economic methodology (Appendix B) used in the study is based upon Minimum 

Revenue requirement analysis frequently used by electric utilities. This methodo 

logy incorporates the present worth of the lifetime costs and value of the 

repowered plant. A 30-year life from repowering was assumed, with repowered 

operation beginning in 1985. 

For capacity credit calculations, it was assumed the plant to be repowered had a 

life expectancy to 1995 if not repowered. Thus, capacity credit was calculated 

to begin in 1995 and last for 20 years at full nameplate rating. 

The time increment used in the analysis involved hourly modeling of the operation 

of the repowered plant as well as the balance of the utility system. 

Three utility systems were analyzed utilizing actual load and generating unit 

data: Public Service of New Mexico, Arizona public Service Company and Nevada 

Power Company. A fourth synthetic util i ty system, developed by EPRI , characteristic of the Texas-Oklahoma region, also was used. PNM has a moderate amount 

of oillgas-based generation; APS and NPC have more, and the EPRI synthetic 

utility system has a maximum. Number 2 fuel oil prices were used for plants 

burning gas at a cost of $5.50/MBtu (1985). 

2.5.4 UTILITY SYSTEM ASSUMPTIONS 

Load data from PNM, APS and NPC were obtained and adjusted by Westinghouse in 

accordance with the utilities' expected peak loads in 1985. Hourly loads 

created by Westinghouse for the EPRI synthetic utility system were based on 

the information obtained in EPRI Report EM-285. 

Figures 2.5-3 and 2.5-4 shows a relative mix of generating capacity by fuel type 

for PNM and APS. These figures do not reflect the total reserve assumed, but 

rather an approximation to the capacity that would likely be operaliriy dur-illy d 

high load day. The peak load and the generating mix shown in the figurc have 

been altered slightly for the study, but the general shape of the curve is 

representative. 
Figure 2.5-3. PNM Generation Mix and Typical Daily Load C~~rves 
I 1 I 1 I I I I I I 

- 

8-23-85 ' 

----------- 

- 

1-2-85 

COAL 

- 

----------- --------- 

NUCLEAR 

I-- 

2 4 6 8 10 12 14 '16 i8 20 ZZ 24 

HOURS OF DAY 

Figure 2.5-4. APS Generation Mix and Typical Daily Load Curves 
A tabulation of the 1985 generating mix assumed for the four utilities is shown 

in Table 2.5-7 with their expected annual peak load. As indicated for PNM, a 

good percentage of the capacity is base load, and during reduced-load periods, 

the solar powered plants must compete with coal. This is also true to a lesser 

degree with APS and NPC, both of which are more dependent on oil fueled plants. 

The EPRI Utility System E capacity consists primarily of oil- and .gas-fueled 

plants. The value of the repowered plant will be higher on this system as more 

costly generation is displaced. Natural gas is not included in the mixture of 

fuels since it was assumed that combustion turbines or any other gas-burning 

plant will be us'irig Number 2 oil or an equivalent surrogate fuel during the 

period of operation of the hybrid plant. 

2.5.5 PNM SYSTEM ANALYSIS RESULTS 

The performance and cost analysis for operating a 50 MWe solar hybrid repowered 

plant on the PNM system is presented in this section. The results are based on 

the use of the general economic assumptions given in Section 2.5.4 of this 

Report for utilities located in the Southwestern United States. 

Variations in the size of the repowering coliector area were examined to determine the effect of this parameter on the cost benefit ratio. In addition to the 

reference plant collector area, two smaller sizes were assumed. The results are 

shown in Table 2.5-8. The collector area that resulted in the best cost/benefit 

2 ratio was the intermediate collector area of 233,000 m . This area was used as 

the collector area for the'remaining cases shown. A brief explanation of each 

line element shown in Table 2.5-8 follows: 

Direct Plant Cost 

The estimated cost of repowering for three bases is given in Table 2.5-5. The 

direct costs using the DOE heliostat goal assumptions are $40M for a 50 MWe 

plant. This is in 1977 dollars prior to adderis for contingency and spares. 

This represents 800 $/kWe as shown in Table 2.5-8. 
TABLE 2.5-7. ESTIMATED UTILITY GENERATING MIX 

Combustion Turbine 

Oil -Ste~m 

Combined Cycle 

Coa 1 

Nuclear 

Hydro-El ectric 

rU 

I 

P 

03 - Pumped Storage 

- Conv. Hydro. 

TOTAL 

Annual Peak Load 

PNM APS N PC EPRI-E 

- MWe % - MW e % - MWe . % MW e % 

2 0 1 .O 652 12.8 47 0 25.5 500 4.9 

- - - - 4 - - - - - - - - - - 

2084 100. 5099 100 1846 100 10,300 100 

1545 MWe 4432 MWe 1612 MWe 8,078 MWe 
TABLE 2.5-8. COSTIBENEFIT ANALYSIS RESULTS FOR ALTERNATE SOLAR PLANT 

COLLECTOR FIELD SIZE, PUBLIC SERVICE COMPANY OF NEW MEXICO, 

50 MWe SOLAR HYBRID REPOWERED PLANT,* 1985 INSTALLATION 

Direct Plant Cost (1977 M$) - 

($/kWe) 

Plant Cost (PWRR, 1985 M$)** - 

- Capital 

- Operating 

TOTAL 

Value (PWRR, 1985 M$) -- 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 

Energy (GWHIyr) 

Cost (mil ls/kWh, 1985) -- 

Direct Plant Breakeven 

($/kWe, 1977) 

CostIBenefi t Ratio . - .-- - 

2 Collector Area (rn ) 

Reference 

31 0,000 233,000 163;OOO 

40.0 32.8 26.0 

(800) (656) (520) 

*Plant Cost - DOE He1 iostat Goal 

Fossil Boiler Startup Mode - Cold 

Repowering Fraction corresponding to Col 1 ector Area of 31 0,000 m2, 233,000 m 2 

and 163,000 rn2 is approximately 100 percent, 75 percent and 50 percent, 

rcspectively, at the 2:00 p.111. winter solstice design point. 

**PWRR Present worth of revenue requirements. 
Plant Costs 

The Capital item 1 isted under Plant Costs represents the lifetime (30-year) present worth of revenue requirements associated with the capital investment to 

repower the plant. Using the total capitalization, escalated to 1985 dollars as 

shown in Table 2.5-5, a fixed charge rate (18 percent in this case) is applied 

giving the annual revenue requirements to support the investment. This 30-year 

string of revenue requirements is present-worthed (at 11 percent per year) to 

1985 to obtain the Present worth of Revenue Reqiirements (PWRR) shown in 

Ta bl'e 2.5-8. 

The Operating item under Plant Costs is the present worth of the revenue requirements to support the plant operatqng and maintenance costs (except for fuel). It 

was assumed to be three percent of the repowering investment the first year (1985) 

and to escalate at an eight percent rate thereafter. 

The Total is the sum of the capital and operating revenue requirements for the 

repowered plant, given in 1985 millions of dollars. This represents the total 

1 ifetime cost of owning and operating the repowered plant, exclusive of fuel 

costs. 

Value 

The following elements define the total value of the repowering to the electric 

uti l ity system. These are st~uwr~ iri lil'ill Ions sf dolldr-5, over 30 years, prescnt 

worthed to 1985. 

The Fuel Savings item listed under Value is determined by detailed modeling of 

the operation of the utility system with and without the repowering. The fuels 

displaced are assumed to have the costs and escalation rates as shown in 

Table 2.5-6. Start-up, spinning reserve requirements and incremental heat rates 

are considered in the model ing to determine fuel consumptions. 

Fuel Cost is the present worth of the lifetime fuel cost for the fuel consumed 

by the repowered plant. As such, it appears as a negative value. Fuel is consumed by the hybrid plant for boiler start-up, standby, insolation transient 

buffering, to operate through insolation shutdown windows and when economically 

competitive. 
Variable O&M is the credit given for the presence of the solar plant and its displacement of energy on the balance of the utility system since it saves variable 

operating and maintenance costs, in addition to fuel, on the conventional units 

on the system. This was determined by the detailed operational modeling of the 

utility system with and without the repowering. 

Capacity Credit is the revenue requirements associated with the displacement of 

installed generating capacity. It has been assumed that the normal retirement 

date of the plant would have been in 1995; thus, the capacity credit has been 

assumed to occur at that date and to extend for 20 years. Splar/fossil hybrid 

plants, because of their ability of production upon demand, have 100 percent 

megawatt capac-ity credit. For value calculations, the displacement was assumed 

to be combustion turbines as per Table 2.5-6. Both fixed charges and fixed O&M 

were included in calculating the credit. 

'The Total is the sum of the items listed under Value. It can be argued thatthe Fuel Cost might more appropriately belong under Plant Cost, but it is all 

a matter of accounting preference. It is, in fact, a negative fuel savings., 

Energy (GWH/yr> 

The total energy per year generated by the repowered plant is obtained from a 

detailed hybrid plant simulation model. This electric energy includes that 

derived from insolation and the use of oil. 

Cost (mill s/kWhr) - 

This is the levelized annual cost (revenue requirements) of generating energy 

with the repowered plant, over 30 years, divided by the annual energy. The 

cost includes capital , operating and fuel. 

Direct Plant, Breakeven ($/kWe) - 

ThSs r~ui~iber represents what one can afford to pay for the repowering in direct 

costs (see Table 2.5-5) and have its lifetime value exactly equal its costs. 

This is given in 1977 dollars for direct comparison with the first item in this 

table and Table 2.5-5. The analysis is based upon present worth of revenue 

requirement calculations and the econoln'ic assumptions given. 
CostIBenef i t Ratio 

This is the r a t i o o f the total plant cost to the total value, shown in the table. 

It is a reflection of dollar cost per dollar return or benefit. 

The three cost assumptions discussed in Section 2.5-3 and shown in Table 2.5-5 

2 

were adjusted to represent a collector area of 233,000 m2 instead of 31 0,000 m . The effect of these adjusted plant costs on the cost/benefit ratio is shown in 

Table 2.5-9. 

Since the plant value is independent of the plant cost, the value of the solar 

repowered plant remains the saale. Therefore, as can be seen, the lowest. cost 

assumption will produce the best costlbenefit ratio. From the results shown, 

the DOE Heliostat Goal cost assumption will be used as the plant cost in the 

remainder of the analysis. 

A1 so of interest is the type of energy that the hybrid repowered plant displaces. 

Because the plant operates during all load conditions, it displaces energy normally supplied by base and intermediate units, as well as peaking units as shown 

in Table 2.5-10. 

The value of solar repowered plant was also determined using an alternative 

economic scenario. This ditters from the rne.fttr.er~ce scenario only in the carrying 

charge rate (fixed charge rate). The carrying charge rate is changed from '18.0 

to 14.6 percent for the hybrid repowered plant and from 20.0 to 16.0 percent for 

the conventional peaking units on the rest of the system. The differences in 

cost benefit are shown in Table 2.5-11. 

Three different operating modes of the solar hybrid repowered plant were investigated. l hese are cold star.1, wdrrl start and stcam sharing as ~!'ST.IISTP~ in 

Section 2.5.3. 

The cold start operating mode assumes that every time the plant is brought on 

line it is started frnun a cold boiler condition. 
TABLE 2.5-9. COSTIBENEFIT ANALYSIS RESULTS FOR ALTERNATE SOLAR PLANT COST 

MODELS, PUBLIC SERVICE COMPANY OF NEW MEXICO, 50 MWe SOLAR 

HYBRID REPOWERED PLANT," 1985 INSTALLATION 

DOE Nth First 

He1 iostat Commercial Commercial 

Gba 1 Plant Plant 

Direct Plant Cost C1977 M$) 32.8 40.9 55.6 

($/kWe) (656) (818) (1112) 

Plant Cost (PWRR, 1985 M$)** 

- Capital 126.8 158.1 21 4.9 

- Operating 

TOTAL 

Value (PwRR, 1985 M$) 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 

Energy (GWHIyr) 121.1 121.1 121 .1 

Cost (mill s/kWh, 1985) -- 195.4 235.7 309.0 

Direct Plant Breakeven 

($/kWe, 1977) 435,9 435.9 435.9 

CostIBenefit Ratio 1.50 1 .88 2.55 

*Coll ector Area - 233,000 m 

2 

Fossil Boiler Startup Mode - Cold 

**PURR - Present worth of revenue requirements. 
TABLE 2.5-10. PNM SYSTEM-FOSSIL OPERATING ENERGY DISPLACED 

BY SOLAR HYBRID REPOWERED PLANT 

% Energy Di splacement 1985 M$ Value %-$ Value 

Coa 1 66.6 1.8 43.9 

Oi 1 33.4 2.3 56.1 

- 

TOTAL 100.0 4.1 100.0 

Under the warm start operating mode, oil is burned to keep the boiler warm when 

the plant is not being used. As a result, less energy is needed to start the 

plant when it is brought on line. For the analysis it was assumed that the 

plant would require three cold starts over the year to allow for maintenance. 

With the steam sharing operating mode it was assumed that an auxiliary steam 

supply is available for the hybrid plant to use for startup and standby conditions. Therefore, the cost to the hybrid plant of startup and maintaining the 

plant in stand-by condition is very small, if not zero. In the steam sharing 

results shown, these were assumed to be zero. 

Based on these assumptions, Table 2.5-12 indicates that the best operating mode 

is steam sharing using costlbenefit as a criterion. The operating value of the 

steam sharing mode is not as high as the other two modes, but the fucl cost is 

approximately 50 percent less than the others, resulting in a greater net plant 

value. However, the steam sharing concept has not been evaluated in the same 

depth as the other operating modes since a conceptual design for this approach 

has not been prepared. The repoweriny cosl estimate for the steam sharing 

operating modes is most likely somewhat optimistic. In addition, the fossil 

fue'l cost may be shown, with furlher- drldlys is, to be optimistic since the 

present analysis assumed that the neighboring unit from which the steam is 

nbtained to permit operation of the solar repowered plant will always be available. The availability of steam from the neighboring unit will depend on the 

unit capacity, the unit operation mode, and the unit maintenance schedule. 

These factors will tend to increase the cost .of fossil fuel which is required 

for operation of the solar repowered plant. The selection of the steam sharing 

operating mode for a solar repowered plant is.therefore not presently reconmende 

due to the uncertainties in the performance and cost assumptions. 
TABLE 2.5-11. COSTIBENEFIT ANALYSIS RESULTS FOR ALTERNATE ECONOMIC 

SCENARIOS, PUBLIC SERVICE COMPANY OF NEW MEXICO, 

50 MWe SOLAR HYBRID REPOWERED PLANT,* 1985 INSTALLATION 

Reference A1 ternate 

Economic Scenario Economic Scenario 

Direct Plant Cost (1977 M$) 32.8 32,8 

($/kWe) (656) (656) 

Plant Cost (PwRR, 1985 M$)** 

- Capital 126.8 102.8 

- Operating 45.4 45.4 

TOTAL 172.2 148.2 

Value (PURR, 1985 M$) 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 114.4. 109.9 

Energy (GWHlyr ) 121 .I 121.1 

- Cost (mill s/kWh, 1985) 195.4 172.6 

Direct Plant Breakeven ($/k~e, 1977) 435.9 486.4 

Cost/Benefit Ratio --..-- 1.50 1.35 

*Col 1 ec tor Area - 233,000 m 

2 

Plant Cost DOE tleliostat Goal 

Fossil Boiler Startup Mode - Cold 

**PWRR --. Present worth of revenue requirements. 
TABLE 2.5-12. COST/BENEFIT ANALYSIS RESULTS FOR ALTERNATE FOSSIL BOILER 

OPERATING MODES, PUBLIC SERVICE COMPANY OF NEW MEXICO, 

50 MWe SOLAR HYBRID REPOWERED PLANT,* 1985 INSTALLATION 

Fossil Boiler Startup Mode Steam 

Cold Warm Sharing 

Direct Plant cost (1977 M$) 32.8 32.8 32.8 

($/kWe) (656 (656) (656 

Plant Cost (PWRR, 1985 M$)** 

- Capital 126.8 126.8 126.8 

- Operating 45.4 45 .4 45.4 

TOTAL 172.2 172.2 172,2 

Value (PWRR, 1985 M$)* 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 

Cost (mil 1 s/k~h, 1985) -- 195.4 187.6 184.1 

Direct Plant Breakeven 

($/k~e, 1977) 

*Col 1 ec tor Arca - 233,000 m 

2 

Plant Cost - DOE Heliostat Goal 

**PWRR - Present worth of revenue requir*e~nents. 
When the plant is operating under the warm startup mode, the energy output of 

the hybrid plant is greater than that of the cold startup mode because the plant 

is run more often due to economic reasons. This is due to the difference in 

startup cost between the warm and cold startup modes. The fuel cost associated 

with the warm startup scenario is greater than that of the cold startup because 

of the fuel needed to keep the boiler warm. However, the increased energy output of the hybrid plant outweighs the additional fuel cost, giving an improved 

cost/benefit of the warm startup plant. 

2.5.6 APS SYSTEM ANALYSIS RESULTS 

The value of the solar repowered plant using both cold and warm startup operating. 

modes was analyzed on the APS system. The results are shown in Table 2.5-13. 

These results indicate that the costlbenefit ratios of the two operating modes 

are very close with a slightly better costlbenefit using warm startup. The 

difference is not greater since the solar repowered plant does not rely to a 

great extent on the use o f o i l to start the boiler, as can be seen by the relatively small fuel cost. This is due to a relatively good weather year (few 

cloudy days) being used for Phoenix, which precludes the need to operate the 

plant on fossil energy. 

The total value of the hybrid plant is quite high because there i's a relatively 

large percentage (%35 percent) of oil qeneration on the system which the solar 

repowered plant can displace. Note that the APS system model used for the 

analysis was developed in 1976 as part of EPRI Contract RP 648-1. In general, 

utility system models tend to change with time because of, for example, variations in anticipated load demand. The resul ts presented herein may therefore 

not be completely representative of the APS system since most likely the current 

system description for the 1980s and beyond is different from that indicated in 

Table 2.5-7. 

2.5.7 NPC SYSTEM ANALYSIS RESULTS 

The Nevada Power Company system was analyzed using the insolation data obtained 

for Barstow, California. The results of the analysis are shown in Table 2.5-14 

for the two fossil boiler operating scenarios assumed for NPC. These results 
TABLE 2.5-13. COSTIBENEFIT ANALYSIS RESULTS FOR ALTERNATE FOSSIL BOILER 

OPERATING MODES, ARIZONA PUBLIC SERVICE, 50 MWe SOLAR 

HYBRID REPOWERED PLANT,* 1985 INSTALLATION 

Fossil Boiler Startup Mode 

Cold Warm 

Direct Plant Cost (..I977 M$) - 

($7k~e) 

Plant Cost (PWRR, 1985 M$)** 

- Capital 

- Operating 

TOTAL 

Value (PWRR, 1985 M$) -- 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 

Energy (GWH/,yr) 

Cost (mil 1 s/k~h, 1985) -- 

Direct Plant Breakeven ($/kWe, 1977) 

- CostIBenefit Ratio 

- - -.-. 

*Col 1 ector Area - 233,000 m 

2 

Plant Cost -- DOE Heliostat Goal 

**PWRR - Present worth of revenue requirements. 
TABLE 2.5-14. COSTIBENEFIT ANALYSIS RESULTS FOR ALTERNATE FOSSIL BOILER 

OPERATING MODES, NEVADA POWER COMPANY, 50 MWe SOLAR HYBRID 

REPOWERED PLANT," 1985 INSTALLATION 

Fossil Boiler Startup Mode 

Cold Warm 

Direct Plant Cost (,I 977 M$) 

($/kWe) 

Plant Cost (PWRR, 1985 M$)** 

- Capital 

- Operating 

TOTAL 

Value (PWRR, 1985 M$) 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 

Energy (~WHlyr) 105.9 108.0 

Cost (mi 11 s/kWh, 1985) 202 .O 200.7 

Direct Plant --- Breakeven ($/k~e, 1977) 

CostIBenefit Ratio 1 .19 1 .17 

*Collector Area - 233,000 m 

2 

Plant Cost -- DOE Heliostat Goal 

**PWRR - Present worth of revenue requirements. 
are similar to those obtained for the APS system since, as indicated in 

Table 2.5-7 for each of the utility systems considered, the generation mix is 

similar. The costlbenefit ratio for a solar repowered plant operating on the 

NPC system is 1.17 to 1.19 for the two fossil boiler operating scenarios. 

Similar to the previous APS results, a "warm" fossil boiler startup mode yields 

the lower costlbenefi t ratio. 

2.5.8 EPRI SYNTHETIC UTILITY SYSTEM E ANALYSIS RESULTS 

The EPRI Synthetic Utility System E was analyzed for both cold and warm boiler 

startup modes using Midland, Texas insolation data. In addition El Paso, Texas, 

which has better insolation, was analyzed for the cold startup ~~~oile, The 

results are shown in Tables 2.5-15 and 2.5-16, respectively. 

Although the energy output of the solar repowered plant on this system differs 

only slightly from that of the other utility systems considered, the total value 

of the plant is greatly increased, producing a cost/benefit of less than one. 

This is due to the large percentage of oil-based generation (40 percent on the 

system). 

Similar to previous results, a warm startup operating mode has a better cost/ 

benefit than that of the cold startup mode, but unlike previous results the fuel 

cost of the solar repowered plant using the warm startup mode is less than that 'i 

using the cold startup mode. This again is due to the fact that the solar 

repowered plant is displacing high incremental cost conventional plants, such 

as oil plants, As a result, the solar repowered plant is less frequently shut 

down for economic reasons. Since the plant is almost always used, it would be 

more'economic for it to start up using the warm rather than the cold mode for 

the fossil boiler. 

Although it was not invest.igated, it can be expected that a warm startup using 

the El Paso insolation tape would produce a better costlbenefit ratio. Agaln, 

based upon the PNM analysis, a steam sharing operating mode, assuming zero 

startup and stand-by costs, would have .tt~t! best custlbenefit ratio. 
TABLE 2.5-15. COSTIBENEFIT ANALYSIS RESULTS FOR ALTERflATE FOSSIL BOILER 

OPERATING MODES, EPRI SYflTHETIC UTILITY E (TEXAS, 

LOUISIANA, OKLAHOPIA), INSOLATIOII - MIDLAND, TEXAS, 

50 MWe SOLAR HYBRID REPOWERED PLAfIT ,* 1 985 INSTALLATIOti 

Direct Plant Cost (1977 M$) 

(SIkWe) 

Plant Cost (PwRR, 1985 M$)** 

- Capital 

- Operating 

TOTAL 

Value (PWRR, 1985 M$) 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 

Energy (GWHlyr) 

Cost (mills/kWh, 1985) 

Direct Plant Breakeven ($/kWe, 1977) 

CostIBenefit Ratio 

*Col 1 ec tor Area - 233,000 m 2 

Plant Cost - DOE He1,iostat Goal 

Fossil Boiler Startup Plode 

Cold \la rm 

32.8 32.8 

(656) (656) 

**PWRR -. Present worth of revenue requirements. 
TABLE 2.5-16. COSTIBENEFIT ANALYSIS RESULTS FOR ALTERNATE PLANT SITE 

LOCATIONS, EPRI SYNTHETIC UTILITY E (TEXAS, LOUISIANA, 

OKLAHOMA), , 50 MWe SOLAR HYBRID REPOWERED .PLANT ,* 1985 

INSTALLATION 

Direct Plant Cost (1977 M$) 

($/kWe) 

Plant Cost (PWRR, 1985 M$)** 

- Capital 

- Operating 

TOTAL 

Value (PWRR, ,1985 M$) 

- Fuel Savings 

- Fuel Cost 

- Variable O&M 

- Capacity Credit 

TOTAL 

Energy (GWH/~~ 

Cost (mil 1 s/kWh, 1985) 

Direct-Pl-ant Breakeven ($/kWe, 1977) - - -~ . -..- 

, CostIBenefit Ratio 

-. 

*Col 1 ec tor Area - 233,000 m 

2 

Plant Cost - DOE He1 iostat Goal 

Fossil Boiler Startup Mode - Cold 

Insolation Base 

Midland, Texas El Paso, Texas 

32.8 32.8 

(656 (656) 

**PWRR - - Present worth of revenue requirements. 
A penetration analysis for the EPRI Synthetic Utility System E was performed; 

Table 2.5-17 summarizes the results of the analysis. As indicated in 

Table 2.5-17, the costlbenefit ratio increases from 1.02 to 1.51 with increasing penetration levels up to 20 percent. The increase in the costlbenefit 

ratio is primarily due to the solar repowered plant competing with less costly 

fuels (coal) at the higher penetration levels during portions of the year. 

TABLE 2.5-17. SOLAR HYBRID REPOWERED PLANT PENETRATION ANALYSIS,* 

EPRI SYNTHETIC UTILITY E, INSOLATION - MIDLAND, TEXAS, 

1 985 INSTALLATION 

Penetration (%I 

Number of Plants 

Direct Plant Cost (1 977 $/kWe) 

Plant Cost (PWRR, 1985 M$)** 

Plant Value (PwRR, 1985 M$) 

Breakeven Cost (1 977 $/kWe) 

CostIBenefit Ratio 

*Plant Rating - 50 MWe 

Coll ector Areas - 233,000 m 

2 

Plant Cost - DOE He1 iostat Goal 

Fossil Boiler Startup Mode - Cold 

**PWRR - Present worth of revenue requirements 

An analysis of two alternative plant ratings (25 MWe and 100 Mw~) in addition to 

the Refer~nc~ Plant. rating (50 Mw~) was performed for the EPRI Synthetic Util ity 

System E. The results of the analysis are presented in Table 2.5-18. These 

results indicate that similar costlbenefit ratios are achieved for plants rated 

at 50 MWe and 100 MWe and that these plant ratings from a costlbenefit standpoint 

are preferred to a smaller plant (25 Mw~). It should be noted that even though 

the costlbenefit ratio for the 100 MWe plant rating is somewhat lower than for a 

plant rated at 50 MWe, the uncertainties in the repowering cost estimates for 

the 100 MWe plant are great enough to potentially negate the indicated advantage. 

A conceptual design and cost estimate of a repowered plant rated at 100 MWe must 

be performed before a definitive conclusion can be reached in comparison with the 

Reference Plant rating of 50 MWe. 
TABLE 2.5-18. PLANT RATING AND ANALYSIS, EPRI SYNTHETIC UTILITY E 

(TEXAS, LOUISIANA, OKLAHOMA), INSOLATION - 

MIDLAND, TEXAS, 1985 INSTALLATION 

Plant Ratina* 

25 MWe 50 MWe 100 MWe 

2 Coll ector Area (m ) - 

Direct Plant Cost (1977 M$) 21.4 32.8 54.8 

(1977 $/kWe) 8 56 656 548 

Pi?-nt Cost . -.- (PWRR, 1985 M$)** 112.4 172.2 287 -8 

Value (PWRR, 1985 M$) 

Energy (GWHIyr) 

- Cost (mill s/k~h, 1985) 

Direct Plant Breakeven C$k~e, 1977) 643.6 646.6 595.6 

CostIBenef it Ratio 1.33 1,02 0.92 

- 

b *Plant Cost - DOE Heliostat Goal 

Fossil Boiler Startup Mode - Cold 

**PWRR - Present worth of rcvcnuc requirements. 

For synthetic util i ty E, an experiment was perfornled on coll ector area variations 

for a 50 MWc rcpowered plant. The results are stlowr~ ill Tdble 2.5-1 9, The larger 

collector area is shown to have the better costlbenefit ratio. The larger solar 

collector area advantage is due to lesser insolation compared with PSM and the 

greater potential for displacing oil. 

A better costlbenefit potential for solar repowering exists for utility system E 

ttlan for the other systems. However, each company must be modeled using its own 

detailed parameters to determine the best impact and repowering configuration, 

such as collector area. 
TABLE 2.5-1 9. COLLECTOR AREA SIZING ANALYSIS ;k EPRI SYNTHETIC UTILITY E, 

INSOLATION - MIDLAND, TEXAS, 1985 INSTALLATION 

2 Collector Area (m ) 

163,000 233,000 310,000 

Direct Plant Cost (1977 $/kWe) 

Plant Cost (PWRR, 1985 M$)** 

Plant Value (PWRR, 1985 M$) 

Direct Breakeven Cost (1 977 $/k~e) 

Cost/Benefi t Ratio 

*Plant Rating -. 50 MWe 

Plant Cost - DOE Heliostat Goal 

Fossil Boiler Startup Mode - Cold 

**PWRR - Present worth of revenue requirements 
3.0 STUDY UNIT SELECTION 

 ask 1200 of the DOEIPNM Technical and Economic Assessment Phase of the Solar 

Hybrid Repowering Project called for the selection of a study unit. This unit 

was to represent a typical plant for the expected market based on results of the 

market survey. It was to be the unit best suited to future needs of the PNM 

system and ensure optimum use as a demonstration unit while maintaing system 

integrity. During the current phase of the project, the study unit received 

extensive analjrtical treatment from both a technical and economic viewpoint. 

A conceptual design was prepared to determine solar system requirements, interface requirements, and master. control logic. System dispatch computer analyses 

were curnpleted as well as economic studies to determine the required capital 

investment, the net energy cost of the repowered unit, and the energy displacement value of the solar system over the unit operating 1 ife as compared to fuel 

oil firing. This intensive study, in parallel with PNM in-house efforts, allowed 

a decision on the merit of constructing a demonstration facility at the study 

unit site. The following sections discuss the rationale and results of the Study 

Unit Selection Task. 

3.1 REPOWERING METHOD ASSESSMENT 

PNM has evaluated four potential repowering methods for solar hybrid repowering: 

0 Steam Rankine Cycle 

- Feedwater Heating 

- Evaporation and Superheating (Boiler Replacement) . 

e Brayton Cycle (Combustion Turbine) 

ID Combined Cycle (Brayton/St.eam Ranki ne) 

Following are descriptions of the typical candidate cycles considered and the 

method of application of solar repowering to existing oil- and gas-fired plants. 
STEAM RANKINE CYCLE 

Solar Feedwater Heating 

In the solar feedwater heating system, steam generated in the solar thermal 

system is used for boiler feedwater heating in an existing steam turbine regenerative Rankine cycle, therby reducing the fossil fuel requirement for a given 

electrical generation. A schematic of a typical solar feedwater heating cycle 

is shown in Figure 3.1-1. 

As shown in this figure, the first and second extraction point heaters are 

supplied with steam generated in the solar thermal system, rather than by 

extracting steam from t.he turbine. 

Steam is condensed in the existing feedwater heaters and returned to the feedwater cycle through the existing heater drain system. Feedwater is then pusliped 

back to the solar thermal system where heat is added and the process repeated. 

The solar collector/receiver system used for solar feedwater heating could be 

either the di stri buted col 1 ector type or the central receiver type, as econos~~ics 

dictate. The solar heat transport fluid temperature required for feedwater 

heating is in the 400' to 600°F range, depending on the method of application 

and cycle requirements. 

Solar EvaporationISuperheati ng 

Solar evaporationlsuperheating utilizes solar thermal energy for the combined 

evaporation and superheating duty, such as boiler rep1 acement, for an existing 

steam Rankine cycle, and may represent all or a portion of the total energy 

requirement. figure 3.1-2 shows the steam Kankine cycle diagram utjllZlng the 

solar central receiver concept. In this concept, reflected solar radiation is 

absorbed in the receiver which generates $team at. a t.~mperat.~~re and pressure 

matching that of the existing steam cycle and paralleling the existing fossilfired boiler. The existing turbine extraction cycle remains unchanged. Feedwater is then pumped back to the receiver where the process is repeated. 

In this study, only non-reheat steam turbine cycles will be considered due to 

the technical difficulties associated with solar reheating using the current 

first generation central receiver concepts and increased operational problems. 
LEGEND 

SOLAR STEAM 

SOLAR FEEDWATER - -- 

EXIST. STEAM 

EXIST. FEEDWATER ------- 

(EXIST.) 

TYPICAL STEAM RANKINE CYCLE 

Fi.gure 3.1-1 . Solar Feedwater Heating (.Solar Hybrid Repowering Study) 
(EXIST.) 

Figgre 3.1-2. Solar Evaporation and Superheating (Boiler Replacement) 
The system capability is such as to permit different operating modes: solar 

only, solar-fossil mix, or fossil only, without advqrsely affecting the turbinegenerator performance. No thermal storage capacity is required in this concept. 

The solar central receiver system appears best suited to generate the relatively 

high temperature (700" to 1000°F) steam required for the typical existing 

electric power generation system. 

BRAYTON CYCLE 

Brayton cycle plants in the United States utilize the open cycle combustion 

gas turbine, burning natural gas or light oil fuel. Figure 3.1-3 shows a 

typical basic open Brayton Cycle with solar repowering. Solar repowering of 

an existing Brayton Cycle would involve the addition of an air/solar working 

fluid heat exchanger, operating in para1 1 el with the fossil -fired combustor. 

Since a very high solar fluid temperature is required (in the 1300" to 1700°F 

range), an advanced central receiver using sodium or helium for the solar 

working fluid operating in a closed cycle is required. As an alternate, the 

solar receiver may operate at 1000°F and fossil fuel may be used to boost the 

air temperature to the required gas turbine inlet temperature. 

COMBINED CYCLE 

The typical combined cycle plant utilizes both the open Brayton cycle and the 

steam Rankine cycle as shown in Figure 3.1-4. Many variations of combined 

cycle plants exist; however, the basic concept utilizes gas turbine exhaust 

heat in a recovery boiler that may or may not need supplemental fossil-fuel 

firing to generate steam that drives a steam turbine-generator. 

Since the combined cycle includes both Brayton and steam Rankine cycles, the 

solar repowering methods described pr*eviously for these cycles would apply. 

REPOWERING MCTllOD ASSESSMENT 

Table 3.1-1 shows a rating of the various cycle configurations considered for 

solar hyhrid repoweri ng. 
LEGEND 

SOLAR WORKING FLUID 

SOLAR HEATED AIR 11111-1. 

AIR 

NEW EQUIPMENT 

Figure 3.1-3. Brayton Cycl e Repoweri ng 

COMPRESSOR GASTURBINE , 

(EXIST.) . - 

SPEED 

- 

REDUCER 

POWER 

GENERATOR 

(EXIST.) 

(EXIST.) 

AIR 

1 t d 

A- I I 

NEW ISOLATION VALVES 

AIR 

I COMBUSTOR 

(EXIST.) - I 

EXHAUST 

TO I 

REGENERATOR 

ATMOSPHERE (EXIST.) 

.................. ................. .................. ................. .................. 

BASIC OPEN BRAYTON CYCLE 

WITH REGENERATION .................. ................. .................. 

................. 

HEAT 

EXCHANGER 

.ELECTRICAL ,, 
SOLAR WORKING FLUID 

SOLAR HEATED AIR c 

FEEDWATER .-----I

I 

.................. 

................. 

CONDENSER 

BASIC OPEN BRAYTON CYCLE 

PUMP L.P. HEATER 

(EXIST.) (EXIST.) (EXIST.) 

COMBINED CYCLE 

TYPICAL STEAM RANKINE CYCLE 

Figure 3.1-4. Combined Cycle Repowering 
TABLE 3.1-1. SOLAR H'fBRID REPOWERING METHOD ASSESSMENT 

CYCLE 

CONFIGURATION CCWPARISON BASiD ON INDIVIDUAL CYCLES 

COMPARISON BASED ON 

ESTIMATED UNITS AVAILABLE 

IN EACH CONFIGURATION 

POTENTIAL 

CANDIDATE 

MARKET 

HIGH 

HIGH 

LOW 

VERY LOW 

RANKINE CYCLE 

REEDWATER HEATING 

1 

RANKINE CYCLE ! 

EVAPORATION AND 

SUPERHEATING ' 

BRAYTOLV CYCLE 

COMBINED CYCLE 

> 

OVERALL 

BENEFIT TO 

COST RATIO 

VERY LOW 

HIGH 

LOW 

VERY LOW 

RECEIVER 

TEMPERATURE 

LOW 

MEDIUM 

TO 

HIGH 

HIGH 

MEDIUM 

KO 

iIGH 

TECHNlCAL 

RISK 

LOW 

LOW 

MEDIUM 

TO 

HIGH 

MEDIUM 

TO 

HIGH 

COMPLEXI-y 

LOW 

MEDIUM 

MEDIUM 

TO 

HIGH 

HIGH 

DIFFICULTY 

OF OPERATION 

LOW 

MEDIUM 

MEDIUM 

TO 

HIGH 

MEDIUM 

TO 

HIGH 

FUEL 

DISPLACEMENT 

LOW 

HIGH 

MEDIUM 

TO 

HIGH 

MEDIUM 

TO 

HIGH 

COST 

LOW 

MEDIUM 

HIGH 

MEDIUM 

TO 

HIGH 
The various repowering methods considered are compared both relative to each 

other and on an estimated overall market applicability. Each repowered cycle 

configuration has been rated against six evaluation factors; namely, receiver 

temperature, technical risk, complexity, difficulty of operation, fuel displacement and cost. These evaluation factors are discussed in the following pages. 

The receiver temperakure required for the four repowering methods is an important consideration since receiver temperatures above 1000°F have not been 

demonstrated; experience is limited to the DOE water-steam central receiver 

program. Thus, solar repowering of the steam Rankine cycle, either solar 

feedwater heating or solar evaporation and superheating, can be considered 

within the current state-of-the-art. However, for effective solar repowering 

of a Brayton cycle, receiver temperatures in the range of 1300° to 1700°F are 

required. Special high temperature metallurgy and fatigue life of the receiver 

and piping system then become very important considerations which are not 

readily resolved with near-term technology. 

From a technical risk standpoint, solar feedwater heating presents the least 

risk but also produces the least benefits of the four solar repowering methods. 

Solar evaporation and superheating (boiler replacement) utilizing the central 

receiver concept appears at this time to be of low technical risk using current 

water-steam central receiver technology. Brayton cycle repowering involves 

the high temperature design problems previously mentioned, a wide variation in 

existing Brayton cycle configurations (complexity), and potential installation 

and interface problems (for both Brayton and combined cycles); the technical 

risk here IIIUS~ be considered medium to high as compared to steam cycle 

repowering. 

In addition to selecting repowering methods that reduce the technical risk, it 

is also desirable to minimize system complexity, both in design and operation. 

It is judged, therefore, that solar feedwater heating is the least complex 

method following in order of increased complexity by evaporation and superheating, open Brayton cycle and combined cycle. 
The difficulty of operation of the repowered plant must be considered. Of 

primary importance is the ability of the repowering method to provide the 

operational flexibility required for solar operation while interfacing with 

an existing plant. 

In general, solar feedwater heating2hould pose no major operating problems. 

Repowering an open Brayton cycle may lead to operational problems in maintaining gas turbine inlet temperature and in paralleling the fossil-fired combustor, 

particularly during load fluctuations. Gas turbines in use today are normally 

used for peak load service, quick start and short operating periods. Solar 

repowering would involve a change in plant usage and operating philosophy. 

Combined cycle plants on the other hand are normally designed for mid- and 

base-load applications. However, due to the higher complexity of these plants 

compared to the straight gas turbine plant, it is expected that operational 

problems due to solar repowering of a combined cycle plant would increase. 

The difficulty of operation associated with steam Rankine cycle repowering is 

ranked as medium relative to the other repowering methods considered. The 

principal operating problems are expected to be associated with solar steam 

temperature control and fossil boiler stability at low loads (high solar input) 

while operating in parallel with the solar central receiver. 

Fossil fuel conservation is an important objective of solar hybrid repowering. 

The potential fuel displacement offered by solar feedwater heating in a steam 

Rankine plant is deemed low, estimated at less than 10 percent of the rated 

boiler fuel input. 

Solar evaporation and superheat can displace up to 100 percent of the fossil 

fuel requirement at rated load during the peak daylight hours, thus its fuel 

displacement potential is high. 

The Brayton or gas turbine cycle also can be repowered by solar energy up to 

100 percent of its rated output. However, it is likely that some fossil fuel 

firing will be required to maintain rated gas turbine inlet temperature. Also, 

since gas turbine units are normally installed for peaking service, the pot en ti^, 

fuel displacement by solar repowering is further minimized. 
Combined cycle plant solar repowering can result in fuel displacement equal to 

or greater than straight gas turbine plants, depending on whether or not a 

suppl emental fossi 1 -fired heat recovery cycle is used. 

Based on solar repowering plants of equal size, solar feedwater heating can be 

accomplished for the least capital cost of the four repowering methods considered. 

Solar evaporation and superheating is expected to cost less than Brayton cycle 

repowering, primarily due to advanced receiver design (high receiver temperature), 

solar working fluid air/heat exchangers and collector costs (due to lower cycle 

efficiencies). The cost of combined cycle plant repowering is expected to fall 

either between steam Rankine cycle and Brayton cycle repowering, or higher than 

Brayton cycle repowering, depending upon the method and extent of repowering, 

since combined cycle plant configurations are widely varied. 

Table 3.1-1 shows the potential market and estimated overall benefit-to-cost 

ratio for the various solar repoweri ng methods considered . As expected, solar 

feedwater heating has high market potential but relatively low benefits. Solar 

evaporation and. superheating (boiler replacement) has high market potential and 

the highest benefit-to-cost ratio. Brayton cycle plants are judged to have low 

market potential and low benefits compared to steam Rankine cycle repowering,; 

combined cycle plants are judged very low in both catagories. 

SUMMARY AND CONCLUSIONS 

Solar hybrid repowering of existing oil-/gas-fired generating plants has been 

evaluated using four basic repowering methods: steam Rankine cycle solar feedwater heating; steam Rankine cycle evaporation and superheating (boiler replacement) ; Brayton cycles (combustion turbines) ; and combined cycles (Brayton/ 

Steam Rankine). 

Solar repowering of existing steam Rankine cycles, either feedwater heating or 

boiler replacement, is feasible and within current state-of-the-art technology. 

Of the two methods, evaporation and superheating result in the greatest overall 

market benefit. 
Solar repowering of Brayton cycles without fossil fuel assistance fall under 

the advanced central receiver concept because of the high receiver temperatures 

required (1300" to 1700°F) and are considered to be outside of the near-term 

technology required in this study. 

Solar repowering of combined cycles presents the same problems as defined for 

Brayton cycles, with the addition that supplementary fossil-fired heat recovery 

steam boilers may also be required. Combined cycle plant solar repowering 

represents the lowest market potential and lowest benefit-to-cost ratio of all 

repowering methods considered. 

It was recommended that only solar evaporation and superheating (boiler rep1 acement) of existing steam Rankine cycles be considered for Further study in the 

market cost/benefit analysis of solar hybrid repowering. 
3.2 CANDIDATE PNM UNITS 

Solar system size for a demonstration of evaporation/superheating solar repowering (the MWe output of the solar steam Rankine unit) must coincide with the 

current DOE technology in order that applications may be utilized in the near 

term. The technical driver for size, therefore, becomes the solar boiler or 

receiver. 

A DOE objective is to reach a commercial plant size of 100 MWe. However, the 

first unit for the Barstow 10.MWe Pilot Plant has a capacity that will allow, 

for approximately 17 MWe production (the capacity i s i n excess of 10 MWe 

required for charging thermal storage whi 1 e operating the plant in para1 1 el ) . 

Since the solar hybrid demonstration is envisioned as an evolution in size 

toward the 100 MWe commercial goal, 17,MWe is considered a minimum, with a 

maximum power level in the 25 to 30 MWe range. 

The current technical feasibility of this size was agreed to by Rockwell International in a meeting on January 24, 1978. It should be noted that the 

Rockwell design was recommended by DOE in October 1977 as the prime candidate 

for future development work, and selected by DOE in July 1978 as the concept 

to be utilized at the Barstow Pilot Plant. PNM has utilized the MDAC central 

receiver design (which incorporates the Rockwell receiver) as a 'baseline for 

this study. This was based on PNM project management reviews, the Sandia 

Laboratories recommendations for the Barstow Pilot Plant, and guidance received 

from DOE. 

Based on the constraint of steam Rankine boiler displacement utilizing the 

central receiver concept at a capacity level of 17 to 30 MWe, PNM candidate 

sites and units were evaluated by the following eight PNM groups: 

a System Planning (Lead) e Gas- and Oil-Fired Plants 

e Environmental Affairs Production Plant 

e Right-of-way 0 Generation Planning 

o Power Production 

o Revenue Requirements 
The specific PNM units reviewed are listed in Table 3.2-1. 

TABLE 3.2-1. PNM CANDIDATE UNITS FOR SOLAR HYBRID REPOWERING 

Plant 

Person No. 1 & 2 

Person No. 3 & 4 

Reeves No. .l & 2 

Reeves No. 3 

Prager No. 7 

Prager No. 8 

Prager No. 9 

Santa Fe No. 1 & 2 

Valencia Combustion Turbine 

Unit Rating, MWe 

2 2 

3 5 

4 4 

66 

7.5 

6.0 

11.5 

7.5 

21.5 

A demonstration in this capacity range would require as much as 200 acres of 

adjacent land, thus eliminating the Prager and ~anta Fe sites. The Valencia 

Combustion Turbine is a Brayton cycle machine and falls under the second generation hardware, which is not being considered for reasons noted above. Attention was focused on the Person and Reeves units, and the 14 selection criteria 

noted in Table 3.2-2 were addressed by team members in their areas of expertise. 

Sections 3.3 through 3.6 of this Report present the detailed recommendations of 

the PNM functional units providing significant input on the study unit selection. 
TABLE 3.2-2. SOLAR HYBRID REPOWERING PROJECT - PNM CANDIDATE 

UNIT TECHNICAL SELECTION CRITERIA 

Unit Type, Location.and Rating 

Adjacent Land Availability/Surrounding Structures 

Date Constructed 

Unit Condi tion1Remai ni ng Useful Life 

Insolation and ~l imato'logi cal Characteristics 

Fuels UsedIFuel Options 

Turbine Type/Operating Conditions 

Plant OperationIAvailabil i ty Requirement 

SolarIFossi 1 Interfaces 

Current Uselplanned Future Use 

Environmental Impacts 

Site Characteristics/Terrain 

Institutional Impacts 

Proximity to Airports 
3.3 POWER PRODUCTION CONSIDERATIONS 

Items considered during evaluation of the candidate generating units were: 

0 Remaining useful life 

e Maintainability (based upon maintenance histories and projected 

maintenance requirements) 

e Unit Condition (based upon maintenance histories) 

Operational Stability (based upon operational requirements during 

minimum load operation and operation during boiler upset ' 

conditions) 

. Fuel Types 

While none of the Reeves and Person units has maintenance or operational restrictions that would prohibit its participation in the Solar Hybrid Project, the 

Reeves Station Unit No. 2 was recommended as a first. choice by the operation, 

maintenance and engineering groups within the PNM Gas and Oil (G&O) Plants. 

Following are their recommendations: 

FIRST CHOICE: Reeves Station Unit No. 2 

Estimated Retirement Date: 1996 

0 Maintainability: 

- -- Boiler: Present condition is good, tube failure has been 

experienced fn the boiler furnace roof arch section. This 

is thought to be due to a flow deficiency inherent in the 

unit design. The boiler has minimal brick refractory, thus, 

it will endure the expected temperature transients that will 

be experienced as a hybrid unit. 

- Boiler Auxiliaries: Present condition good 

- High-Pressure Turbine: The horizontal joint has had a history 

of leakage; the effect of cycling the unit will accelerate 

this problem. 

- Low-Pressure Turbine: Present condition is good. .Last stage 

bl adi ng rep1 aced February 1 977. 

- Turbineltienerator: Present condition good 
- Operational stability: The location of the unit in the plant 

area is immediately adjacent to the control room, thus making 

operator attention more readily available during times of 

boil er ramping or upset. 

The minimum load the unit may carry with all boiler controls 

in full automatic operation is 20 MW. (Six burners in service; 

for 25 MWe solar input, gross boiler load = 25 MW at maximum 

output. ) 

e Future Boiler Fuels: It is expected that this unit will operate 

on fuel oil as a primary boiler fuel after the year 1981. 

SECOND CHOICE: Reeves Station Unit No. 3 

e Estimated unit retirement date: 2000 

Maintainability: 

- Boiler: Present condition is good. This unit has not experienced failure of the roof arch section although design is 

similar to Reeves Unit No. 2. 

- Boiler Auxiliaries: Present condition good 

- Turbi ne/.Generator: Present condition good 

- High Pressure Turbine: Some modification has 'been made on the 

high pressure turbine inlet valve cam assembly to more readily 

permit cycling of the unit. Thermocouples h.ave been installed 

in the upper and lower halves of the high pressure casing to 

aid in temperature control during unit roll out. 

- Low Pressure Turbine: The low pressure turbine is in good 

condition, however, rebladi ng of the last row of rotating blades 

in the low pressure section will be required during the next 

scheduled unit overhaul (1981 ). 

- Generator: The generator has experienced a history of tape 

separation; corrective maintenance has been done during the 

normal turbine overhauls. The causes of this problem have not 

been satisfactorily determined. 

- Operational Stability: The location of the unit in the plant 

area is immediately adjacent to the Control Room. 

The present minimum load that may be carried by the unit's boiler 

in full automatic operation is 32 MW (six burners in service). 

0 Future Boiler Fuels: Again, it is expected that the primary boiler 

fuel for this unit will be fuel oil after 1981. 
THIRD CHOICE: Person Station Units No. 1 or 2 

a Estimated unit requirement dates: Person No. 1, 1988; 

Person No. 2, 199.2 

e Maintainability: (both units) 

- Boiler: Present condition is fair. Both units have had a 

history of tube failure in the superheater area; these tubes 

were replaced in Unit No. 2 during the major unit inspection 

in February of this year. Person Unit No. 1 will have the 

furnace refractory replaced during the next inspection outage 

and it is expected that some superheater tube replacement will 

a1 so be done. 

Both units have experienced deterioration of the furnace 

refractory; this is felt to be due to the cyclic operation of 

these units. 

- Boiler Auxil iaries: Present condition good 

- Turbine/Generator: The present condition of the turbine/ 

qenerators is felt to be qood. Both units are scheduled for 

major overhauls during 1978 at which time a more detailed 

evaluation will be made. 

- Operational Stability: The location of the unit(s) control 

room with respect to the boil er(s) again provides for immediate 

operator attention. The Control Room is located near the 

boiler front^. 

The present minimum load that may be carried on either boiler 

is 7 MW (three h~,~rner-s in service). 

e Future boiler fuels: Fuel oi'l is expected to be the primary 

boiler fuel after 1981 . 

The primary reason for selecting Reeves Station, Unit No. 2 or Unit No. 3, is the 

maintainability and operational stabil'ity of the units. It was felt that the 

boilers on the recommended Reeves units are more suitable for the cyclic duty 

that would be experienced as a hybrid unit because of the minimal use of refractory in their construction. This is opposed to the Person units whose boilers 

incorporate considerably more refractory and are not well suited for continuous 

cyclic duty and the temperature excursions expected of a hybrid unit, assuming 

some degree of combined firing (fossil fuel and solar). It was also felt that 

sudden loss of turbine load (solar steam flow) may also be more desirable on the 

Reeves units since this 1 oss can be absorbed by the turbine/generator as well as 

the fossil boiler. 
It should be noted that reliability and availability of the recommended Person 

units on fuel oil for start-up and continuous operation is also dependent upon 

cost of conversion studies. These are currently being performed as a part of a 

PNM in-house G&0 Plant fuel oil conversion study due to the age and expected 

retirement dates of these units. 
3.4 GENERATION PLANNING CONSIDERATIONS 

Selection of a unit for solar repowering study purposes must be consistent with 

the overall PNM system expansion plans. Given a high probability that PNM may 

have a demonstration project to follow the feasibility study, it is prudent that 

the study plant be not only feasible for repowering, but also as compatible as 

possi bl e with system needs after repoweri ng. Therefore, the fol 1 owi na areas 

must be recognized in addition to the environmental, location and plant characteristics areas. 

If the repowered unit is not to require significant oil consumption, the solar 

system must be capable of conservatively providing minimum load energy which is 

40 to 50 percent of unit capacity. The 40 to 50 percent is the minimum stable 

operating point that is influenced both by turbine and boiler designs. If this 

was only a boiler constraint, then it would imply that whenever supplemental 

firing is required for transients, etc., oil would be used to supply the 40 to 

50 percent capacity. The boiler minimum can probably be limited through modified 

design and improved control schemes. Given any boiler minimum, oil usage would 

be minimized by designing the solar system so that supplemental firing would be 

1 imited based primarily on exceeding turbine minirnurr~ load and economic dispatch 

nf oil-firing. 

The solar design of the proposed repowering unit is basically the same as Lhe 

sta.nrl-alnne 10 MW plant with regard to collector field and steam supply. Tt~ib 

plant without the storage system is designed for 17 MWe peak conditions. It is 

assumed that an average level would be less than 17 MW. It appears, therefore, 

that 'this solar steam system would be more than adequate to fft a Persur~ uns't 

and conservatively supply well over 50 percent of the unit's steam. However, 

it would appear that the present design would have to be extended even before 

full testing in order to use the solar concept with Reeves Unit,No. 1 or 2 and 

meet minimum load segments. This assumes turbine and boiler minimum loading 

segments are about the same, 40 to 50 percent. 

Similar to our other gas/oil units, Person and Reeves are scheduled for future 

retirement; in the mid to late 1980s and the mid 1990s, respectively. This is 
due to plant age (useful life due to deterioration of major components) and 

economics. Basically, the oil 'unit capaci tylenergy will be displaced by pumped 

storage or other peaking generation. These basic system constraints should be 

recognized in selecting a unit. 
3.5 ENVIRONMENTAL CONSIDERATIONS 

PNM Environmental Affairs performed a candidate site selection of the two 

alternative sites. These sites, as noted in Section 3.2 of this Report, are: 

a Site Alternative 1: Reeves Station 

e Site Alternative 2: Person Station 

Both sites are located in Bernalillio County within the Albuquerque metropolitan 

area. The locations of the two candidate sites are shown in Figures 3.5-1 

through 3.5-3. The sites are located approximately 14 miles apart on a northsouth orientation and are situated to the west of 1-25 within the Rio Grande 

Val 1 ey. 

A study area was defined and a site selection analysis performed based upon the 

assumptions that the site woul d: 

a Require a minimum of 120 acres 

a Be in a square or rectangular configuration 

a Be contiguous or in close proximity to the station 

a Req~rire that the 120-acre site be level or be graded and filled 

s Be covered by gravel or use a chemical means to suppress vegetation (site would not be paved) 

Due to the close proximity of the candidate sites to one another within the 

Rio Grande Valley, many environmental parameters are similar. In order to 

comparatively screen the candida'te sites, Environ~iiental Affairs ' site selection 

investigation was responsive to the following two site selection criteria as 

defined: 

a Site Characteristics/Terrain 

- Slope and Dissection 

- Soils 

- Vegetation 
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Envi ronmental Impacts 

- Erosion and Drainage 

- Vegetation 

- Land Use Patterns 

- Transportation Corridors and Gl int Potential 

- Visual Resources 

The analysis was performed based upon field investigation at the site in 

January 1978, a review of 1 iterature, and in-house knowledge of the area. 

Based on this analysis, Environmental Affairs ranks the a1 ternative sites as 

fol 1 ows : 

1. Reeves Station 

2. Person Station (west site) 

3. Person Station (north site) 

Reeves Statlon sfte is characterized by a 3.6 percent slope with wilq of 

moderate erosion potential. Drainage impacts may be mitigated by channelization. Native vegetation and fauna would be displaced during construction 

activities. The Reeves site would not alter existing land use patterns and 

would not have as negative a visual impact as compared to the two sites at 

Person Station. Glint might prove to be a problem to traffic on 1-25. The 

site would be accessible to the pub1 ic and would have good visibility without 

creating an overwhelming visual impact upon the viewer. 

Person Station (west side) would be the second ranked site. This site offers 

the advantage of being on level ground with low erosion potential. No native 

vegetation or fauna would be removed by development, but agricultural land 

would be taken out of production. The facility would not be a compatible land 

use. The visual intrusion of this site would be greater than at Rccvcs Station. 

Glint might prove a problem to 1-25 traffic. The site would be accessible to the 

public and would have good visibility but, due to closer viewing distances, 

would have a more overwhelming visual impact on the viewer than the Reeves site. 
The least favored site is Person Station (north site) with a 6.3 percent slope, 

greater dissection, and higher erosion potential. The proximity of this site 

to 1-25 would create a glint problem and positive viewing of the site would be 

less than at either of the other two sites due to the sites' location imnediately adjacent to transportation corridors minimizing viewing distances. 
3.6 SAFETY CONSIDERATIONS 

Certain hazards are associated with locating any central receiver solar thermal 

power system stemming from both of the major components; the central tower/ 

boiler and the heliostat field. 

Any structure of over 200 feet height is considered hazardous by the FAA and 

construction must be preceded by fil ing Form 004-ROO01 notifying them of the 

proposed facility. This, of course, would be true of a central tower as its 

height could range from 345 feet to as much as 700 feet. 

The he1 iostat system poses an even greater .safety risk to personnel in a problem 

defined as "glint," or stray reflections from the mirror surfaces. Glint can be 

a severe problem to people operating a motor vehicle, piloting an aircraft, etc. 

The 10 MWe PON (Program Opportunity Notice) states "Location of the pilot plant 

within the control zone of, or adjacent to any state, municipal, or privately 

owned airport must be avoided." This expresses the fact that although na definitive information is available on glint, it is recognized as a problem by ERDA, 

which is severe enough to restrict facility siting. 

A1 though ground-based personnel certainly should and wi 11 be considered with 

respect to safety for solar repowering of Person Station, the proximity of it 

to the Albuquerque Sunport presents rattler severe problems. As shown in Figure 3.6-1, Person Station is slightly more than one mile from the major commercial east/west runway. In addition, it is approximately three-quarters of a 

mil e from the secondary northeast/southwest diagonal runwdy . This runway hand1 es 

a majority of the private and small aircraft which account for 150,OUO out of 

225,000 landings and takeoffs on the runway system each year (per FAA). 

Jerry Jersenovic of Sandia Laboratory, in charge of the central receiver safety 

analysis, stated thaL Tor our location uri the flight path for the ma,jor small aircraft runway at the Sunport, there could be some difficulty in siting a 120- to 

285-acre heliostat field with today's systemsafety design requirements. The 

inclusion of a 400-foot or taller tower adjacent to commercial airline glide 

paths is also a significant issue. These appear to be major problems and could 
Figure 3.6-1. A1 buquerque Sunport/Person Station Area 
expressly excl ude Person from a first-time solar hybrid repowering appl ication. 

Once safety parameters are establ ished, Person could become an excel 1 ent 

candidate. 

Reeves Station has two smaller local airports, Alameda and Coronado, located to 

the northwest and northeast, respecttvely. The approach paths to these facilities could be directed to avoid a solar field flyover much more readily than the 

Albuquerque Sunport when considering proximity, aircraft type and volume usage. 

The Reeves plant, therefore, appears superior with respect to aircraft safety 

considerations. 
3.7 STUDY UNIT 

The selection of a study unit was noted in Section 3.0 of this Report as being 

predicated on two primary considerations: 

The unit was to represent a typical plant as defined in the market 

survey 

The unit was to be one which is best suited to meet future needs 

of the PNM system and ensure optimum use as a demonstration unit 

while assuring system integrity 

Section 2.4 of this Report presented a discussion of the typical candidate 

repowering plant; these results are summarized for reference in Tab1 e 3.7-1 . Many of these criteria can be met by either the Person or the Reeves units. 

TABLE 3.7-1. TYPICAL CANDIDATE UNIT COMPARED TO REEVES UNIT NO. 2 

--- Candidate Unit Reeves No. 2 

Unit Characteristics 

- Type Non-reheat Steam Turbine Non-reheat Steam Turbine 

- Rating 10 to 50 MWe 44 MWe Nameplate 

- Turbine In1 et 850 to 1250 psi/900° to 950°r 1250 psi/950°F 

General Unit Data 

- Year Built 1950 - 1960 

- Condition Good 

- Current Use IntermediateIPeak 

- Location Rural 

- Ectimated Retirement Before 2000 

1958 

Good 

BaseIIntermediate 

Rural 

1997 

An assessment of the information presented in Sections 3.2 through 3.6 of this 

Report was made, and consideration was given to the market survey results. It 

was concluded that the Reeves plant is the most ideal site for the development 

of a conceptual design and for a demonstration of the solar hybrid repowering 

concept. Primarily based on power production recommendations, Unit No. 2 is 

the most desirable machine. A 25 MWe net solar field was recommended to provide 

for an adequate demonstration of the concept whi 1 e remaining within technology 

limits. Should the concept prove successful, the unit could be upgraded to 

100 percent solar capacity at a later date. 
As shown in Tab1 e 3.7-1, comparing the typical candidate unit criteria with that 

of Reeves No. 2, the selected study unit meets a1 1 criteria established for the 

typical candidate unit. 

Section 4.1 .I of this Report contains a detailed description of the engineering 

features of Reeves Unit.No. 2. 
3.8 SITE DESCRIPTION 

Reeves Station, the proposed site for the demonstration solar hybrid repowering 

project, is lo-ated in Bernalillo County within the Albuquerque metropolitan area. 

The site area is characterized by rapid urban development. The following discussion summarizes the physical , biotic and socioeconomic features of the Reeves 

site. 

3.8.1 INSOLATION 

The Reeves Station of the Public Service Company of New Mexico system is an 

excellent choice for the location of a Solar Hybrid Repowering Plant for several 

reasons : 

a The insolation level is relatively high for most of the year 

enhancing the potential for demonstrating economically competi- tive and useful commercialization of solar hybrid repowering. 

a Most of the re1 iable direct normal insolation data available in 

the United States has been accumulated for Albuquerque 

New Mexico and wi 1'1 thus permit a high 1 eve1 of confidence to be 

achieved in the design of and the performance predictions for 

the plant. 

a An instrument pzckage for recording direct normal insolation data 

has been installed at the station as part of the WEST Solar 

Resource Eva1 uation Study, and measurements (every 15 minutes) of 

direct normal insolation has been recorded since June 1977; thus, 

providing a site specific data base for verification of the plant 

design (see Section 4.9). 

Figure 3.8-1 shows the predicted geographic variations in direct normal insolation 

for the United States .* These datd indicate that the yearly average day values 

2 for the direct normal insolation varies from approximately 5.5 kW-h/m -day for the 

2 Texas/Okl ahoma region of the country to 7.2 kW-h/m -day for the Ari zona/Nevada 

2 region. The value for A1 buquerque, New Mexico is approximately 6.6 kW-h/m -day. 

Therefore, it can be expected that the data obtained from a demonstration program 

for solar repowering performed in New Mexico from an insolation level standpoint 

will be representative of what can be achieved through solar repowering of other 

units located in other regions of the Southwestern United States. 

*On the Nature and Distribution of Solar Radiation (UC-59,62,53A) by WATT 

Engi neeri ng . Prepared for Department of Energy, March 1 978, 

Tab1 e 3.8-1 presents the monthly and annual average direct normal insolation 

values for A1 buquerque, New Mexico for the years 1.961 through 1964; the average 

2 annual values range from 6.59 to 7.08 kW-h/m -day for these four years. These 

data were obtained from 10 minute digitized records avai lab1 e for A1 buquerque, 

New Mexico from the National Environmental and Climatic Data Center. The 

variation in direct normal insolation on a day-by-day basis for June 1962 is 

given in Figure 3.8-2. The data presented in this figure indicate that solar 

energy cou.ld be used to displace a significant portion of the fossil fuel 

required to operate a power plant at Albuquerque during every day of June 1962. 

In addition, "cl ear day" insolation profiles were observed for approximately 

50 percent of the time during June indicating the potential of the solar hybrid 

repowered plant to displace in excess of 90 percent of the fossil fuel normally 

used during these days, Likewise, as indicated for the year 1962 (see Section 2.5) solar energy has the potential to displace significant' portirrs of 

the fossil fuel that would normally be consumed during more than 300 days of 

plant operation. 

3.8.2 PRECIPITATION 

Normal precipitation totals for the year average about eight i'nches at 5000 feet 

above mean sea level (MSL), nepartures from the yearly normals can range about 

half to double the normal. Usually such departures are widespread. Droughts, 

which can last months or years, are more persistent than wet periods. Snow cover 

rarely lasts more than a few days below 7000 feet. Winter precipitation is mostly 

associated with polar pacific airmasses and occasionally artice airmasses. The 

onset of the summer thundershower season is a result of a monsoon-type circulation 

that imports a greatly modified tropical maritime air111ass. This occurs regularly 

between July and late September. Temperature and precipitation data are shown 

in Table 3.8-2. 

3.8.3 WINDS 

Winds and wind storms occur mainly in the spring with thunderstorms. Both types 

of winds car1 exceed 60 MPh but most average 25 to 35 MPH. Spring winds usually 

diminish after sunset and blow out of the quadran from south to west. 

Table 3.8-3 shows mean wind speeds and prevailing directions by month. 
TABLE 3.8-1. DIRECT NORMAL INSOLATION FOR ALBU UERQUE, NEW MEXICO 

MONTHLY AND ANNUAL VALUES, kW-h/m 9 DAY 
SOLAR TIME (HRS) 

Figure 3.8-2. Direct Nnrmal Solar Radiation Observed dl; A1 buquerque, NM 

1 
TASLE 3.8-2. CENTRAL RIO GRANDE VALLEY REGION TEMPERATURE AND PRECIPITATION 

Temperature ('F) !I 

- Averdye daily maximui~ 47 5 2 5 9 70 80 89 9 2 90 83 7 2 5 7 48 

- Average daily minimum 24 2 7 32 4 1 51 60 65 63 57 4 5 32 25 

- Daily mean 35 43 4 6 56 65 75 7 9 77 70 5 8 44 37 

- Extreme maximum 68 72 81 89 98 102 104 104 100 98 74 72 

- Extreme minimurr, -I* -5 8 19 28 4 3 54 5 2 37 25 10 3 

Precipitation 

- Average (in~hes) 0.31 0.40 0.47 0.47 0.56 0.53 1.37 1.38 0.83 0.78 0.34 0.52 

- Average d3ys 

0.10-in. -3r more (no.) 1 2 2 2 2 1 4 4 2 2 1 2 

- Average snowfall 1.3 1.7 1.7 0.3 T 0 0 0 T T 1.2 2.6 

T = Trace, less than 1.5-inch 

For period of record .%ugust 1939 through' December 1370. 

Recording Station: Albuquerque Airport, Bernalillo County, New Mexicc. 

'An extreme minimun of -17 was subseqlently recorded on January 7, 1971. 
TABLE 3.8-3. MEAN SPEED AND PREVAILING DIRECTION 

AT ALBUQUERQUE SUNPORT 

Fastest Wind Speed Recorded 

Mean Speed Prevai 1 i ng Speed . . Direction Year 

January 

February 

March 

Apri 1 

May 

June 

July 

August 

September 

October 

~ovember 

December 

YEAR 9 .O S E 90 - SE Dec. 

1943 

*Wind direction divided into sixteen 22.5" sections. 

Source : Weather Servi ce, A1 buquerque Airport 
Dust and dust storms are unattractive features of the arid Southwest. The follov 

ing discussion is taken from the New Mexico State Planning Office publication, 

"The Climate of New Mexico" (Tuan, et a1 .) concerning the nature of such storms 

and thei r occurence i n A1 buquerque : 

The basic conditions for bldwing dust are the presence of wide 

areas of exposed dry topsoil and strong, turbulent wind. In 

New Mexico, dry soil with seantly vegetation cover is widespread 

in areas that average less than ten inches of rain a year (in 

the trough of the Rio G~ande) . The large tracts of sand hills, 

one series to the east of the Pecos River and another on the 

Staked Plains to the south of Clovis, are evidence of the effect 

of wind action on loose soils in the southeastern sector of 

New Mexico. 

Dus t Streams 

Given the presence of loose soil, the severity of blowing dust 

depends on the strength and turbulence of the wind. In the dry 

months of late fall, winter and early spring, a common phenomenon 

(not dignified by the name "dust stormrr) is the swift motion of 

dust and sand in wandering sheets and narrow strems. The dust 

and sand bound and skip along the surface, and the mass of material appcms to be concentrated in a shallow layer less than two 

feet in thickness. Such local dusi nuvements are caused by 

~udden, lzo2~.izo?ztal sweeps of air moz~ing at ~poods of fo?-i.rteen to 

e.iyh.leeri ril.iles per hour. 

In contrast to the ground-hugging dust strsurrls u2.e L?la vertical 

dust devils. The smail vortices of' I~u~.~~ZZLJ rtlovi.ug ai~., ina& 

visible by the dust and loose organic matter they sweep up, are 

especially comrtlon .in sparsely vegetated, f la t and open pur-ts of 

southern New Mexico during the swnmer half of the year. 

hst Storms 

Widespread and thick drifts of dust affecting the entire state 

or a large portion of the state are associated with the passage 

of cyclones,, and in particular, cyclones with sharp, cold fronts. 

Dust stoms caused by general cyclu~ric ~~inds =&?id tc, ~U.LIUZL~ 

gradually, and the 2.i.f~ of the typical cyclonic duster is 

2.tmi.ted l;o daylight hours. 

Sf;nf;i.sticaZ information is lacking as to the seasonal &is Lraibution, intensity, and duration of dust storms for Netl Mexfco us 

a whole. Von Eschen has compiled data for Albuquerque. * The 

*Von Eschen's compiled data are summarized in Table 3.8-4. 
: L TABLE 3.8-4. DUST STORMS IN ALBUQUERQUE* (1 6-YEAR PERIOD 1945-1 960) 

Total Number 

of Days wi th .Storms Classified 

Month Blowing Dust Severe Mode r a t e L i g h t 

January 

Fe br ua ry 

March ' 

April ' 

May 

June 

July 

August 

September 

October 

De cernbe r 

TOTAL 

AVERAGE 

YEAR 

*After Von Eschen 
information is based on 19 years (1954-2960) of hourly weather 

oh:7ervations made at the Municipal Airport (Sunport) in 

Albuquerque. Dust storms are divided into three categories: 

Severe: Continuous blowing dust for three hours or more 

with the visibility restricted to one mile or Zess at some 

time during the storm; 

Moderate: Continuous blowing dust for two hours or more and 

visibility four miles or Zess during the storm (but not 

qualifying as severe); 

e Light: All other dust storms during which the visibility was 

restricted to six miles or Zess (but not qualifying as 

moderate or severe). 

Spring month3 have tho most dzls t sto-ms, with an average of about 

five days in April when some blowing dust will occur. Fall and 

early winter months have the Zeast dust, with September recording 

some dust on an average of every o L?~er year. Althouglz April averages more dust storms than any other month, Mu~dl stixa~~ ?wrmaZly 

last somewhat longer. September has the least nwnber of dust 

storms but those in July and August are usually of shorter 

duration. 

It is not anticipated that any mi ti gation measut.es are required othcr than protective heliostat stowage during periods of high winds. Station personnel will 

notify the project coordinator of any unusual occurences ir~vulv'ir'~y this issue in 

the future. 

3.8.4 TOPOGRAPHY, VEGETATION AND HYDROLOGY 

The sSte lies irl the southern portion of the Basin and Range Physiographic 

Pr'ovi nce in the Mexi can Highland Section, which i S character1 ~erl by isolated 

dissected bl ack mountain ranges separated by aggraded desert plains. The 

Sandia Mountains' crestline lies approximately 10 miles edst, reaching 

10,678-feet above mean sea-level (MSL) at Sandia Crest. Westward from these 

mountains elevations decredse to 5000 feet MSL at the Rio Grande which lies 

approximately three miles west. The site has a surface that slopes gently 

westward from elevation of 5130 feet MSL on the east to 5070 feet MSL on the 

west near the AMAFCA drainage canal. The slope of the 120-acre rectangular 

plot is 3.6 percent. 
VEGETATION 

Native vegetation around the solar hybrid repowering site is low in profile prin-, 

cipally because of low rainfall, 7 to 10 inches annually, and high elevation, 5000 

to 6000 feet above MSL. The plant community at a typical site in this part of the 

county is mainly comprised of grasses mixed with some shrubs and herbaceous plants. 

Vegetation covers only approximately 15 percent of the soil surface. The most 

abundant grass is usually black grama (BouteZova eriopoda), which may comprise 

a.pproximately 35 percent of the total vegetation by weight. Less abundant species 

are sand dropseed (SporoboZus cryptandrus), mesa dropseed (SporoboZus fZexusus), 

gal 1 eta (HiZaria jamesiil , three awn (Aristida glauca) , blue grama (BouteZova 

graciZis) , a1 kal i sa ca ton (Sporobo Zus airoides) , bush muhl y (MuhZenbergia 

porteri), Indian ricegrass (Oqzopsis hymenoides) and fluffgrass (Tridens 

puZcheZZa) . . I n pl aces , there are broom snakeweed (Gutierrezia sarothrae) , broom 

dalea (DaZea, sp.) , pri cklypear cactus (Opuntia, sp.) , small soapweed (Yucca 

gZauea) , chol 1 a cact.us (Optlntia, sp.) and w'i nterfat lEurotia Zanata) . Annua,l 

plants which increase during years of above average precipitation are tansymustard 

(Descurania, sp.) , Indian pai nbrush (CastiZZeja Zeonardi) , wool 1 y Indian-wheat 

(PZantago purslz.i.i), larnbsquarters (Ch.enopodiwn aZbwn) , Russian- thi st1 e (SaZsoZa 

kaZi) and bladderpod .fLesquereZZa intermedia). Woody plants such as Apache plume 

(FaZZugia paradoxa) may occur in the drainage ways. 

The vegetation of the site is characterized principally by black gamma, sand dropseed, three awn, bush muhly, Indian ri cegrass, fl uffgrass, broom snakeweed, 

pri cklypear, choll a cactus, transymustard, Russina-thistle and bl adderpod. When 

such a plant community is disturbed, annual plants increase. Vegetation of the 

sSte has already undergone some disturbance because of the existing power plant 

and is also affected by several small washes which dissect the proposed plot for 

the solar he1 iostat field. 

Of the Federal threatened and endangered plant species arid the plants protected 

by the State of New Mexico, none are known to occur on the site at this time. 

Of those listed only a few species could potentially occur at the site, such as 

grass cactus (Pedioeactus papyrucunthus) and only a more detailed study could 

verify their presence or absence. 
HYDROLOGIC CONDITIONS 

For Embudo gravelly fine sand loam, zero to five percent slopes, runoff is medium 

and the hazard of water erosion is moderate. 

For Wink fine sandy loam, one to five percent slopes, runoff is medium. The 

hazard of water erosion is slight to moderate and the hazard of soil blowing is 

moderate. 

Since the slope of this site is not great and the soil type has moderate absorption qua1 i ties, the erosion potential is moderate. 

The site slopes gradually from east tu west toward the drainage canal to the 

west of the site. Offsi te drainage will be intercepted on the east side of the 

site and a culvert instal led to conduct the flow across the site discharging into 

the drainage canal. The interceptor and the culvert will be sized to handle 

1125 c.f.s. which is the runoff calculated for a 100-year storm. In addition, 

the drainage through the site will be channelized to control erosion. With the 

above featl.rr-es the site and the surrounding area will be adequately protected 

from flooding and erosion. 

3.8.5 SEISMIC STABILITY 

The seisrnir zt.ahil ity discussion below complements and amp1 ifies the preser~ldtion 

given in Section 4.8.2.4. 

ESTIMATE OF SEISMIC RISK IN THE AREA OF STUDY 

The instrumentation data since 1962 indicates that the strongest shock in a 100- 

year period for the entire region (including the 100 km wide buffer zone) should 

not exceed Richter magnitude 4.9. On the other hand, the reports o f f e l t shocks 

for the 94-year period prior to 1962 indicate six shocks had magnitudes greater 

than 5. On the basis of this data, the strongest shock in a 100-year period is 

l i k e l y t o have a magnitude near 6. The discrepancy in these estimates of seismic 

risk can be explained in two ways. Activity during the past 16 years was lower 

than normal or the activity in the 94 years prior to 1962 was higher than normal. 

With the short time history of seismic activity available, one cannot determine 

which of these two interpretations is correct. Therefore, the safest procedure 
at this time is to assume that a magnitude 6 shock is possible somewhere in the 

, region (including the buffer zone) during the next 100 years. 

VARIATIONS OF SEISMIC RISK WITHIN THE AREA OF STUDY 

The vicinity of the Reeves site has been divided into three regions: Region 1 

lies mostly in the Rio Grande Valley south of Bernalillo, Region 2 is mostly in 

the Rio Grande Valley north of Bernalillo, and Region 3 is located to the east 

of the Manzano and Sandia Mountains. 

Seismicity in Region 3 appears very low inasmuch as very few epicenters or recent 

faults 1ie.within or near its boundaries. The strongest shock in this region in 

a 100-year period ic estimated to 4tl su weak eiiat it constitutes no danger whatsoever to we1 1-buil t structures. On the other hand, Regions 1 and 2 do have a 

potential for moderate shocks. Of these two, Region 1 appears to have the 

highest seismic risk because it has had the largest number of shocks within, or 

adjacent to its boundaries. In addition, faults that cut late Tertiary or 

Quaternary rocks in Region 1 appear to be geologically young,er than those in 

Region 2. 

The strongest earthquakes in a 100-year period in Regions 1 and 2 are estimated 

to be of magnitudes 6 and 5.5, respecti'vely. Shocks of this magnitude are considered moderate and will not damage well-buil t structures unless they occur 

beneath or very near these structures. In the latter case, damage is generally 

mi nor to properly designed power distribution equpmen t; e . g., transmission 1 ines 

and substations (Steinbrugge, et a1 . 1970; San Fernando, California Earthquake of 

February 9, 1971 ). 

3.8.6 ACCESSIBILITY 

The accessibility discussion below on air service, highways, and roads complements the presentation giver1 in Section 4.8.2.10 of.this Report. 

RAILROAD 

The existing Reeves Station has a railroad spur served by the Atchison, Topeka 

& Santa Fe line that serves Albuquerque. Amtrak service is also available in 

A1 buquerque. 
AIR SERVICE 

The largest and ~iiost active airport in the state is Albuquerque International. 

In 1969, the FAA reported that it ranked 47th in the United States in terms of 

volume of passengers. Also, the airport ranked 22nd in operations of civilian 

and military aircraft. In the 1972 State Airport System Plan, the north-south 

runway was listed as 8993-feet in length with a 1000-foot overrun. This length 

is sufficient to land almost any commercial aircraft. This airport is within 

10 miles of the Reeves Station. 

HIGHWAYS AND ROADS 

Extensive improvement and expansion of transportation networks are planned for 

northwest A1 buquerque. Within the vicinity of Reeves Station, the Frontage Road 

will be improved, running in a north to south flow west of 1-25, and a south to 

north flow east of 1-25. An 1-25 interchange will be constructed at Los Angeles 

Boulevard. A major improvement will be the construction of a North Val ley River 

Crossing which will fol low the a1 ignment of either Montano Road, Los Angeles 

Boulevard (El Pueblo Road) or Richfield Avenue. At the present time, Montano 

Road is the favored alignment. If Montano is not feasible, Los Ar~yeles Boulevard 

is the 1 i kely a1 ternati ve. All of thesc i~r~proveliients to the circulation system 

will increase the opportunities for large-scale development in the early to mld1980s for this area through increased accessibility and visibility of the area. 

AVAILABILITY OF CONSTRUCTION MATERIALS 

Based on experience on construction projects in New Mexico, no difficulty is 

foreseen in obtaining general materi a1 s for construction purposes of consumable 

supplies from local distributors or suppliers. It is most likely that local 

suppliers will be able to furnish most of the construction equipment such as 

1 ong-boom cranes, compressors, compaction equipment, and other special equi pment 

and materials required for the project OI? a rpnt.31 nr p~~rchase basis. Suppliers 

of most bulk consumables such as fuel, industrial gases, and concrete supplies 

will usually establish satellite depots for their products in or near the project 

site so that adequate supplies will be available at all times. Due to the proximi ty of the project site to A1 buquerque, supply sources are deemed readily 

available with a minimum of hauling distances. 
3.8.7 AREA (LAND AVAILABILITY) 

A search has been conducted as to the availability of lands immediately adjacent 

to the Reeves Station and an effort to determine the approximate val ues of these 

1 ands has a1 so been compl e ted. 

The required additional rectangular area of approximately 120 acres adjacent to 

the Reeves Station appears to be readily available. 

Options to use the l'and for the Solar Hybrid Program are under consideration. 

3.8.8 ZONING AND LAND USE 

The solar hybrid facility will require 120 acres of additional land and would 

preclude use of this acreage for other purposes. 

This site is located in an area of rapid urban development activity. The 

Me tropol i tan Areas and Urbans Centers Pl an of the Ci ty ' s Comprehensi ve Pl an 

classifies the area of the proposed Reeves .site as established urban land. 

Estbblished urban 1 and is land suited for development as there exists financing 

and pub1 i c services which will permit hi gher densities. 

The Reeves site is bounded by two established industrial parks, Academy Industrial 

Park to the south and Loop Industrial Park north of Los Angeles Boulevard. The 

area between these two indus tri a1 parks is vacant 1 and wi th the exception of the 

heavy industry activity of PNM's Reeves Station and American Gypsum, both 

located south of Los Angeles Boulevard. The other principal land use in the area 

is the Coronado Mobile Home Park (Los Angeles and 1-25). To the west of Reeves 

Station, between the AMAFCA North Diversion Channel and North Edi th Boulevard, 

the land is classified as developing urban which is land that has not been 

plotted extensively and is presently acceptable for 1 ow-1 eve1 urban development. 

A1 buquerque Gravel Products occupies most of this land. Small portions of land 

adjacent to Edith Boulevard are designated as semi-urban and rural, with low 

density resi denti a1 development. 
Most of the projected industrialization in this area will be related to Loop 

Industrial Park and a speculative and yet to be designed industrial community 

east and south of Reeves Station. Development of a solar hybrid repowering 

facility is considered compatible with future activities in this area. 

3.8.9 SOILS INVESTIGATION 

The soil types described in the vicinity of the Reeves Station, north of 

Albuquerque, are as follows: 

o EmB - Embudo gravelly fine sandy loam 

e WeB - Wink fine sandy loam 

This description is quite general and was used in the past by the Pub1 ic Roads 

Administration and Highway Research Board, and used for highways, ai rfiel ds and 

dams. Further information is presented in Section 4.8.2.5 of this Report. 

During the desi gn of the proposed structures, an appropriate foundation investigation program will be performed, developing this portion of the design critiera 

for the pro-iect. For t.he purpose of this study, assu~~~pLions were made .that will 

be confirmed prior to the design of the project. 

It is assumed that the EmB type soils are transported or a'lluvial soils overlyiny 

the WEB type soils of undefined thick~~esb. The drainage of the area is to the 

west toward the Rio Grande. The descendi ng-in-el evation con tours and drainage 

paths from east to west a'l so suggest this condition. Accordingly, for the purpose of this study, the EmB, or gravelly fine sandy loam, is assumed to be the 

foundation materials far t,he proposed structures. 

The term "loam," no longer used in geotechnical and foundation engineering, 

suggests a mixture of sand silt and clay and, for the purposr of this study, Lt~c 

following engineering properties are assumed: 

e Allowable bearing capacity of 

compacted materi a1 : 1 to 2 tons per S. F. 
Dry unit weight: 

0 Optimum .moisture: 

a Frost action: 

e Compaction required: 

0 Compaction methods : 

e Drainage characteristics : 

a Shrinkage and expansion 

characerteris tics : 

22 to 30 percent 

Suscepti bl e 

100% Std. Proctor 

ASTM 698 

Tampi n g or Rubber 

Ti re Roll e r 

Relatively impervious 

characteristics 

Hi gh Suscepti bil i ty 

e Value as roadway: Poor, granular base 

and sub-base coarse 

materials probably 

requi red 

Current engineering practice dictates that for the design of any structures: 

sensi ti ve to settlement and loading condi tions, appropriate foundation i nves tigations and analysis must be performed as part of the design. The investigation 

program designed for each project is usually performed by firms knowledgeable in 

the engineering properties of the foundation materi a1 s and experience in cons truction in the immediate vicinity of the proposed project. The results of this 

foundation investigation will provide the designer with basic criteria for site 

preparation, foundation design, construction criteria and related engineering 

tasks. 

For the purpose of this study, assumptions were made with the conclusion that a 

safe and reliable foundation system can be designed for the structures associated 

with the proposed project, based on the results of an appropriate foundation 

i nves ti gation program. 
4.0 CONCEPTUAL DESIGN 

Reeves Unit No. 2, selected under the preceding task, was established as the 

potential candidate plant for solar hybrid repowering. This plant was investigated under this conceptual design and cost estimate task to provide a reasonably 

definitive design and to identify the required modifications. The existing land 

situation, as well as the particular environmental aspects of Reeves Unit No. 2 

were investigated. Upon complete definition, a cost estimate was prepared that 

is related to the present configuration of Reeves Unit No. 2. 

4.1 EXISTING MECHANICAL AND ELECTRICAL PLANT FACILITIES 

The selected plant to be used for the subject solar repowering conceptual design 

is the Public Service Company of New Mexico Reeves Station Unit No. 2 located in 

A1 buquerque, New Mexido at an elevation of 5130-feet. This unit meets the 

criteria for a solar repowered plant developed during the "Market Survey and Cost 

Benefit Analysis," Task 1100. 

These criteria are as follows: 

Plant Characteristics 

- Non-reheat steam turbine 

- 10 to 50 MWe output 

- 850 to 1250 psi/900° to 95f1°F turbine throttle condition 

0 Historic Plant Data 

- Year built: 1950 thru 1960 

- Good unit condition 

- Intermediate/peak current use 

- Rural location 

- Estimated retiretilent before the year 2000 
Table 4.1-1 contains recent Reeves Unit No. 2 test data that verify that this uni 

meets the established repowering design criteria. 

The turbinelgenerator was manufactured by Westinghouse and is in good condition. 

Modifications have already been performed on the turbine to increase its life 

based on Westinghouse recommendation>. These modifications are: 

e Last two rows of blading replaced in 1977 and stainless steel 

liners installed in L.P. turbine 

Partial rotor modification for stress relieving purposes in 1965 

Two segments of nozzle blocks replaced 

A completely modlfied rotor. is scheduled for completion by the 

fall of 1979 

e Barescope of the turbine rotor 

Westinghouse has estimated that when these modifications are completed, load 

5 changes of 10 MW in 20 minutes should produce 8 x 10 cycles to crack formation. 

This asslimes throttle pressure and temperature are constant, and that rotor 

temperature drops 55OF for each cycle. For a boiler lemperature drop of 200°F 

during load change, and a rotor temperature drop of 200°F, the cycles to crack 

4 

are estimated to be 3.5 x 10 . 

These estimates of turbine cycling effects show that the as-modified Reeves 

Unit No. 2 turbine will be well suited for the cyclic operations due to solar 

repowering. The boiler is also well suited for cyclic operation as determined 

by information from Babcock and Wilcox, the manufacturer. 

The boiler and fuel cycle is being studied for modernization from gas/oil operation to oil-only operation due to the anticipated future scarcity.of natural gas. 

As d?scussed ,ir~ Section 4.2.4.1 of this Report, modificatinns to the b~iler and 

fuel oil supply, and control systems would be required for solar repowering of 

this unit. 

The boiler make-up water treating system at the Reeves Station consists of a 

demineralizer, water softening equipment, and a boiler makeup evaporator system 
TABLE 4.1-1. REEVES STATION UNIT NO. 2 PERFORMANCE DATA 

-- lurbine Generator: 

Manufacturer ................. Westinghouse 

Turbine Rated Capacity, kW .......... 44,000 

Turbine Actual Capacity, kW ......... 49,593 

Turbine Type ................. Tandem-Compound Non-reheat 

Throttle Steam Pressure, psia . : ...... 1,250 

Throttle Steam Temperature, OF ........ 950 

Speed, rpm .................. 3,600 

Exhaust Pressure, in Hgk ........... i .5 

Secerator Rating, kVA1p.f. .......... C7,05SjO.35 

Boiler: 

%in:: Factuv-er ................. Babc~ck and Wi 1 cox 

Type ..................... Natural Circulation, Fressurjzsd, grum-type 

St.e;m Capacity, ib/hr ............ 467,530 

Steam Presstire, psia ............. 1,38C 

Steam T~mperature, OF ............ 2150 

Combustion Fuel ................ Gas/Oil 

Efficiency, % ................ 88.24 as) 

Maximum Gas Consumption, cu-ft/hr ...... 539,53C 

Maximum Oil Consumption, gal/hr ....... 3,571 

Heat Rate: 

Uni t-Gross as), Btu/kW-hr ......... 10,851 

Unit-Net as) , Btu/kW-hr .......... 11,431 

Gross Unit Efficiency (including boiler), % . 31.46 

Net Unit Efficiency (including boiler and 

.4uxiliary power) ............... 29.86 
using turbine extraction steam as the heat source. As will be discussed further 

in the Water Treatment.section of this Report, the present evaporator system is 

considered unsatisfactory to supply makeup water of the quality required for the 

solar receiver. Additional water treatment equipment is therefore recommended. 

In general the mechanical equipment & the Reeves Station Unit No. 2 i s i n good 

condition and will meet the criteria as defined for solar repowering. 

The Reeves Station Unit No. 2 electrical system consists of the turbine generator 

(described previously), the 55,000 kVA main transformer 2A, and a 3750 kVA unit 

auxiliary transformer 2A. The unit auxiliary transformer secondary feeds the 

2.4 kV switchgear 2A. The 2.4 kV switchgear feeds the Unit 2 large motor drives 

and a 480V load center via the 1000 KVA auxiliary transformer 2A. The load 

center feeds three motor control centers and provides a tie to Units 1 and 3 

load centers. Units 1, 2, and 3 switchgear are'all tied into a common 5000/ 

6250 KVA, OA/FA start-up transformer 2A. A 175 kW emergency diesel generator 

serves the essential auxiliaries, of all three units. 

The Conceptual Design Study for Solar Repowering Reeves Station Unit No. 2 

reveals no major barriers that would impede detailed design and ultimately 

construction. Given a normal anticipation of expected problems associated with 

a retrofit and/or upgrading project, the technica l aspects of solar repowerirrg 

of Reeves Station appear to be relatively straightforward. 

Reasonable approaches have been identified as possible solutions for najor design 

prh1111s. Areas needing extended future detailed design investigatic~n are also 

pointed out. 
4.2 MECHANICAL DESIGN 

This section describes the mechanical design of the subject solar energy system 

and the major interfaces required for the solar repowering of the Reeves Unit 

No. 2 Station. The conceptual design consists of the integration of a solar 

collector field and the solar receiver, which is a once-through-type boiler 

located on top of a 423-foot'tower with an existing oil-fired plant of a nameplate rating of 44 MWe. 

The solar system consists of approximately 4100 solar collectors (heliostats), 

each with a reflective area of 38 mZ, located on an available land area just 

south of the main plant facility (see Figure 3.5-2). The conceptual mechanical 

design is based on a total of 4289 collectors, which was determined by the Sandia 

Laboratories, Livermore, using the MIRVAL computer program based on an insolation 

2 value of 950 W/m . Further work on the collector field, which includes the addition of an access road and the resolution of a heliostat interference problem, 

has reduced the number of heliostats to 4086. The system design and performance 

changes will be accounted for during the detail design phase of the Project. An 

external central receiver is located on the top of a concrete tower in the center 

of this field. The design of the collectors and the solar receiver is based on 

the work and preliminary design of the 10 MWe pilot plant solar thermal receiver 

system being designed for Barstow, California. A basic design criterion of this 

conceptual design was to use the collectors as designed by McDonnel1 Douglas and 

the receiver as designed by Rocketdyne Corporation for the Barstow Pilot Plant. 

These solar system components will be described in greater detail in later sections of this Report. 

The design point for this conceptual design was selected as 2:00 p.m. winter 

2 solstice (insolation - 950 W/m ) and is intended to provide at least a total 

solar electrical output of 25 MWe gross. The solar collector field and the 

receiver sizes were designed to meet this requirement. System component sizes 

were based on the summer solstice condition at noon, which could produce approximately 39 MWe gross electrical output. The summer solstice design point was used 

to size all of the system components and to establish steam and feedwater flow 

rates, pressures and l;er~~per.atures. 
4.2.1 SOLAR SYSTEM DESIGN 

This subsection describes the overall solar system in terms of the major components and how they interface with one another. The major components are the 

receiver, the collector subsystem, the feedwater heaters, the feed pumps, the 

condensate hotwell pumps, and the associated piping. 

4.2.1.1 SYSTEM DESCRIPTION AND MAJOR INTERFACES 

To integrate the solar system with the existing Reeves Unit No. 2 oil-fired plant, 

flow diagrams were obtained to identify potential interface locations and also to 

define existing mechanical and control systems. The existing flow diagrams, 

together with new repowering design flow diagrms, schematically show the solar 

system equipment that will be added to, and interfaced with, the existing Reeves 

station equipment. The modifications, new equipment, and interfaces are shown on 

Drawing L22929, Sheets P3-1 through'P3-7 (see Appendix). 

The following design approach was used during the conceptual design for solar 

repowering: 

Reeves Station Unit No. 2 was selected for repowering 

0 The solar system design was to be based on the 10 MWe solar central receiver prel imi nar,y design for Barstow, Cal i fnrnia 

A design goal of 50 percent solar repowering (25 MWe) at winter 

solstice was established 

0 A collector field layout as yenerated by the DOEISandia Livermore 

Laboratories, California, from their MIRVAL computer program was 

used 

0 Definitions of possible plant operating modes were used as a 

design base 

Preliminary EPGS general arrangement drawings were to be prepared 

to define the integration of the new solar system equipment with 

existlng plant equipment 

Computer modeling of the basic fossil/solar cycles was to be prepared to provide heat balance data fo,r system performance and 

equipment sizing 

Cl.~dtiyes tu the existing plant were to 5.e minimized 

Water treatment system design was to be based on once-through 

boiler requirements 
Table 4.2-1 includes the design criteria used in the mechanical design of the 

repowered systems and the component and equipment specifications. The collector 

field is designed to produce 25 MWe at 2:00 p.m. winter solstice using 950 W/m 2 

solar insolation. During the summer months, considerably more power will be gen2 erated. Solar insolation was increased to 1045 W/m based on preliminary insolation data in the Albuquerque area. In order not to defocus heliostats during 

months of higher thermal power and to be able to take advantage of all available 

2 solar power, the system was designed to the modified insolation of 1045 W/m as 

shown in Table 4.2-1. 

TABLE 4.2-1. EQUIPMENT DESIGN CRITERIA 

Envl runmental : 

Ambient Pressure .............. 

Ambient Temperature ............ 

Windspeed ................. 

Solar : 

Sol ar Repoweri ng .............. 

Gross Generation .............. 

Number of Heliostats ............ 

Insolation ................. 

Design Receiver Incident Heat: 

Annual Average ............... 

Summer Solstice Noon ax) ......... 

Gross Turbine Cycle Efficiency: 

At 50 MWe ................. 

12.09 psia 

70°F Daytime Annual/lZ°F Minimum 

10 MPH Daytime Annual Average 

50% 

50 MWe 

4289 

1045 w jm2 

105.5 MWth 

125.4 MWth 

Figures 4.2-1 and 4.2-2 show system losses for the 2:00 p.m. winter solstice and 

the noon summer solstice design conditions, respectively. These figures show the 

system power flow, including losses, from the incident thermal energy on the 

eollsclur field thr-uugh the net electric power generating by the solar portion of 

the plant. Figure 4.2-1 shows that the design goal of 25 MWe wi.11 be met or 

exceeded for the winter solstice design point. 
REDUCED BY RECEIVER TOWER SHADOWING N - 

.a 

N 

(MODIFIED BY FIELD COSINE) OG 

b - " 1 

onm 

ZJJS 

-. 0 

ggii 

mrns 

zrw 

- rnO Zns 

N-i rn 0:~ 

iJoO 

 DO 

753 

ZQIA 

gGzG 

s"5, 

DOrrnO 

(n E Z 

om0 

SF 

REDUCED BY HELIOSTAT ABSORBTANCE 1- '" 

REDIRECTED FROM COLLECTOR FIELD 

I 

VICINITY OF RECEIVER 

I INCIDENT ON RECEIVER SURFACE 

ABSORBED ON 

RECEIVER SURFACE 

ABSORBED INTO STEAM Iij 03 

POWER TO TURBINE m Z: PO *- 

GROSS 2 

E LEC iu 

W 
REDUCED BY RECEIVER TOWER SHADOWING 

IF rQ I 

* 

(MODIFIED BY FIELD COSINE) a- ; ?2 

h, I 

(MODIFIED BY HELIOSTAT ABSORBTANCE) 

w REDIRECTED FROM COLLECTOR FIELD 0.G 4 - 

I 

VICINITY OF RECEIVER 

I-. 

I INCIDENT ON RECEIVER SURFACE 

I ABSORBED ON RECEIVER SURFACE 

d 

ABSORBED INTO STEAM ? gi 4 

<I 

- 

I POWER TO TURBINE 

GROSS 

ELEC , - 

rPt ELEC 
To establish a basis for system design, the operating modes for the Reeves Stati 

Unit No. 2 with solar repowering were investigated and are shown in Figures 4.2-d 

and 4.2-4. Figure 4.2-3 depicts the operating modes of the solar-only operating 

condition where the fossil boiler can be either in a cold or a hot standby condition. Consideration was given to night turbine generator shutdown with capability 

for a morning startup, solar insolatton transients, and night operation on fossil 

fuels. 

The hot stand-by condition is the situation during which the fossil boiler is 

maintained at the operating pressure and the corresponding saturated steam temperature. The outlet of the superheater is shut off, thus allowing no steam to 

be suppl ied to the turbine. During some solar insolation transients, electrical 

ouput could be maintained by anticipating the transient and bringing the fossil 

boiler on line from a hot standby condition, simultaneously shutting down the 

solar system. This operation could not be accomplished if the fossil boiler was 

in the cold condition, since it would take approximately six hours to bring the 

boiler up to temperature. 

Figure 4.2-4 shows the solar hybrid repowering mode of operation where the solar 

system and the fossil system are each provl'ding a percentage of the lolal plant 

output. This percentage will be control led by the plant operators in order to 

maximize the contribution of the solar system output, with the fossil system 

providing any deficiency of power required to maintain the plant load. 

Sol ar/Fossil Hybrid operation wi 11 provide day and night continuous operation 

with constant electric power output. Electric power fluctuations due to solar 

insolation transients may be eliminated by increasing the fossil boiler power 

1 eve1 to make up for any reduction in solar power. The question of solar insolation transients will be discussed in further ,detail in Section 4.2.4.2 of this 

Report. 

Figure 4.2-5 is a compilation of the various operating rriodes which may be 

expected, together with the effects on the system and controls and the system 

modifications which will be required. Figure 4.2-5 depicts potential operating 
SOLAR LJ 

I r 

COLD FOSSEL 

BOILER 

I 

I t 

FOSSIL BOILER 

IN HOT STANDBY 

& I 

NIGHTTIME 

TURB./GEN. 

SHUTDOWN 

SOLAR 

INSOLATION 

TRANSIENTS 

MORNING TURBINE 

START UP, 2.0 HRS. r- (12 HR. DOWNTIME) 

NIGHTTIME 

OPERATION ON 

FOSSIL FUEL 

SOLAR 

l NSOLATION 

TRANSIENTS 

SVUITCHOVER TIME, 

FOSSIL FUEL TO 

SOLAR 

LONG 

PLANT SHUTDOWN, 

COLD BOILER 

SHORT 

VARIABLE POWER 

GEN. WITH INSOLATION 

CHANGE' 

I LONG I 

I OPERATION ON 

FOSSll FUEL I 

SHORT 

FOSSIL BOILER ASSISTS 

GEN. TRANSIENTS 

~i~ure 4.2-3. Operating Modes, Reeves Station Unit No. 2 
Figure 4.2-4. Opera tiing Modes--Reeves Station Unit No. 2 

.SOLAR PLUS FOSSIL 

FUEL 

- 

FOSSIL BOILER PROVIDES 

A % OF TOTAL STEAM 

FLOW 

A 

I 

DAYINIG HT 

CONTINUOUS OPERATION 

CONSTANT ELECTRIC 

POWER OUTPUT 

SOLAR INSOLATION 

TRANSIENTS 

I 

I 

SHORT 

CONTINUOUS POWER GEN. 

TRANSFER OPTION TO FULL DEPENDENT ON TRANSIENT I FOSSl L FUEL OPERATION 'ONG 1 1 DURATION 1 

i.e. THUNDERSTORMS, OVERCAST FOSSIL BOILER LOAD INCREASE 

RATE OF 20%/MIN. 
Figure 4.2-5. Control System ~unctional Analysis (Sheet 1 of 3) 

COMMENTS 

- THROTTLE PRESSURE MUSTBE 

CONTROLLED OR ELSE TURBINE 

EXTRACTION FLOWS WlLL VARY 

IN PROPORTION TO THROTTLE 

PRESSURE RESULTING IN VARYING 

FEEDWATER TEMPERATURES AND 

A TOTALLY UNCONTROLLED 

SYSTEM. 

- AUTO.OPERATION OF BOILER COM. 

BUSTION CONTROL DOWN TO 20% 

IS NECESSARY FOR SAFE UNIT 

OPERATION. 

CONTROL SYSTEM 

MOD1 :ICATIONS& ADDITIONS 

- CONTR3LOF TURBINE THROTTLE 

PRESSL8RE BY MODIFICATIONST0 

THE TbROTTLE VALVES AN0 

TURBlilEIGEN. GOVERNOR. 

- AUTO. SOLATION OF THE FOSSIL 

BOILEU; SECTION FROM BF?S ON. 

- CONTFOL TURBINE THROTTLE 

PRESJRE BY MODS. TO THROTTLE 

VALVIS AND GOVERNOR. 

- MOC.IFY COMBUSTION CONTROL 

SYSTEM FOR AUTO. OPERATION 

OF LO, LER DOWN TO 20%. 

EFFECTS ON EXISTING 

CONTROL SYSTEM 

- PRESSURE TRANSMITTER TO 

CC'MBUSTION CONTROL SYSTEM 

INJPERABLE. 

- POSSIBLE TURBINE GOVERNOR 

CONTROL PROBLEMS. 

- FOSSIL BOILER COMBUSTION COW. 

TROL SYSTEM MAY NOT MAINTAW 

CONSTANT THROTTLE PRESSVRE. 

DEPENDING ON SOLAR TRANSIERT. 

- POSSIBLE GOVERNOR CONTROL 

PROBLEM. 

- EFFECTSON FOSSILBOILER DRUU 

LEVEL CONTROL SYSTEM DUE TO 

VARYING THROTTLE PRESSURE 

AND DEAERATOR PRESSURE. 

- EFFECT ON COMBUSTION CONTROL 

SYSTEM DUE TO VARYING FEED. 

WATER TEMPERATURE. 

- MINIMUM AUTO. BOILER CONTROL 

POINT IS 50% LOAD. HAND OPERA. 

TlON < 50% LOAD. 

- p~--p 

OPEFATING MODE 

1. SOLAR ONLY, flOT INCLUDING 

INTERhllTTENl CLOUDS. FOSSIL 

801LER SHUTDOWN. BASE LOADED. 

2. SOLAWFOSSIL FUEL HYBRID 

OPERATlOtl ALL TYPES 3F CLOUDS. 

BASE LOAC,ED OR VARIABLE 

DISPATCH. 

UNMODIFIED 

SYSTEM EFFECTE. 

- VAROABLE TURBINE THROTTLE 

PRESSURE DUE TO FLOW CHANGES 

THROUGi RECEIVER CAUSED BY 

SOLAR IflSOLATlON CHANGES. 

- VlrRlABlE WWER GENERATION 

DUET0 kVAILABLE TURBINE 

POWER. 

- VARYING FEEDWATER TEMPS. 

- OEAERATOR PRESSURESWOULD VARY 

IN PROPC43TION TO EXTRACTION 

FREcSUT(E. 

- POSSIBLE LOW NPSH ON RECEIVER 

PUMP OLE TO CHANGES IN 

OEAERArOR PRESSURE. 

- TURBINE THROTTLE PRESSURE 

CONTRO-LED BY FOSSIL BOILER 

COMBUS-ION CONTROL SYSTEM 

(EXISTING). 

- IF FOSSI- BOILER CANNOT KEEPUP 

WITH SOAR TRANSIENTS. 

THRJTT-E PRESSURE WlLL VARY 

WITH SO-AR INSOLATION. 

- 'JURINGIPERIODSOF HIGH INSOLA. 

T1,JfJ (SLMMERI COLLECTOR FIELD 

CAN DELIVER 25 MWe 1 50% RE. 

CaWERIfJGI. FOSSIL BOILER IS 5(Rb 

LOAD AUO WlLL NOT BE IN AUTO 

UOOE, WT WILL BE HAND 

JPERATZD, THIS IS UNSATISF AC. 

TORY. 

- VARYING FEEDWATER TEMPS. 

- VARYINS DEAERATOR PRESSURES. 

- POSSIBLE LOW NPSH ON RECEIVER 

PULP. 

- VARIABLE POWER GENERATION. 

-- 
Figure '4.2-5. Control System Functional Analysis (Sheet 2 of 3) 

OPERATING MODE LNMODlFlED 

SYSTEM EFFECTS EFFECTS ON EXISTING 

CONTROL SYSTEM 

3. SOLAR ONLY ICOLD CR HC,l RE. 

CEIVES) TURBINE STA3T (COLD OR 

HOTTURBINE) INTER,ITT3IT 

CLOJDS EXCLUDED. 

4. FOSSIL BOILER (COLD SIR HOT1 

CNLY TURBINE PTARTCOW 

CR HOT TURBINEL 

- PRESSUF E TRANSMITTER TO FOZ 

SIL CCMBUSTION CONTROL SYSTEM 

INOPERPBLE. 

- POSSIBLE EFFECTSON ORUM LEVEL 

CONTROL SYSTEM. 

- hONE. 

- PRESSURE TRANSMITTER TO 

FCSSILCOMBUSTION CONTROL SYS. 

TEMWILLCONTROLTO TURBINE 

INLET PRESSURE. 

- IIOAU--3MATIC OPERATION OF 

FOSSIL BOILER <50% LOAD. 

- UNCCNTR0L:ED SOLAR STEAM 

GENERATlOh. 

- OVER TEMPERATURE JF TLRBINE 

COMPONEhTS OURINGSTIIRT UP. 

- POSSIBLE CONTAMINATION OF 

SOLAR BOILEF DUE T3 FEE[-WATER 

IMPURITIES PFTER E>TEN313 

SHUTDOWh. 

- POSS13LE INTERACTIm WIT4 

FOSSIL BOILER BFPSE:Tla\: 

- NORMAL START UP. 

CONTROL SYSTEM 

MODIFICATIONS & ADDITIONS COMMENTS 

- SOLAR STEAM TEMP. ATTEMPERA. 

TOR MUST BE DESIGNED TO CON. 

TROLSTEAM TEMP. FROM 1000'~ 

TO 95ti'~ NORMAL OPERATION 

DOWN TO ABOUT 700'~ FOR COLD 

TURBINE START LIMITATIONS. 

- SELECTIVE DEFOCUSING OF HELIO. 

STATSTO LIMIT SOLAR RECEIVER 

STEAM OUTPUT. 

- POSSlaLE REOUIREMENT FOR 

AUTOMATIC TURBINE START UP. 

- AUTOMATIC ISOLATION OF THE 

FOSSIL BOILER SECTION FROM 

BFP'S. 

- SOLAR PORTION OF SYSTEM MUST 

BE ISOLATED FROM TURBINE1 

FOSSIL BOILER SYSTEM. 

- SOLAF STEAM TEMP. ATTEMPERA. 

TOR MUST BE DESIGNED TO CON. 

TROL STEAM TEMP. FROM 1000~~ 

TO 950'~. NORMAL OPERATION 

DOWN TO 700'~. FOR COLD 

TURBINE START LIMITATIONS. 

- SELECTIVE OEFOCUSING OF 

HELIOSTATS TO UNIT SOLAR RE. 

CEIVER STEAM OUTPUT. 

- POSSIBLE REQUIREMENT FOR 

AUTOMATIC TURBINE START UP. 

- BOILEF. ON AUTOMATIC AT < 50% 

LOAD. . 

5. S MULTANEOUSSOLAWOSSIL 

BJILER TURBINE START IHerOR 

CJLD!. 

- AFTER EXTENDED SHUTD3WN OF 

SOLAR BOILER'SOLAR Oh'LY 

START UP NOT RECOMMENDED. 

REOUIRES FLUSH PROCEDURES. 

- RECEIVER STEAM PIPING WILL 

TAKE EXTENSIVE TIME FOR WARM. 

UP AND SHOULD BE DONE BY 

FOSSIL BOILER STEAM OR SHOULD 

BE KEPT WARM DURING EXTENDED 

RECEIVER DOWN TIME BY FOSSIL 

STEAM. 

- NORMAL TURBINE START. 

- UNCOtJTRO-LED SOLA3 ST:-tu 

GENERATION. 

- POSSleLE O'IER TEMPE3ATURi OF 

TURBlnUE CC,MPONENTS OUF IJG 

START UP. 
Figure 4.2-5. control System Functional Analysis (Sheet 3 of 3) 

OPERATiNG MODE 

6. NORNALIEMERZENCY TURBINE 

SHUTDOWN. SOLAR ONLY OPERA. 

TION. 

7. NORhlP.LIEMEF3ENCY 1URBINE 

SHUTDOWN SO-ARIFOSSL BOILER 

HYBFID OPERATION. 

8. TURBINE O?EFqTION. FdSSlL 

BOILER 0PERfl.TION. SCLAR BOILER 

STAF.1 UP. 

9. TURBINE 0PERATION.SaJLAR 

BOILER ONLY OPERATION. FOSSIL 

BOILER START UP, 

UNMODIFIED 

StSTEM EFFECTS 

- UNCONTEOLLED SOLAR STEAM 

TEMP DURING SHUTDOWN. 

- POSS.BLE EFFECTSON FOSSIL 

BOI LER P3RTION. 

- UNCONTROLLED SOLAR STEAM 

TEMP. DLRING SHUTDOWN 

- POSSlBLC ADVERSE INTERACTION 

OF SJLAR BOILER START UP STEqM 

WITH OP,iRABLE FOSSIL BOILER 

SYSTEM. 

- SOLAR PI)RTION EFFECTSON LN. 

DFERATiVE FOSSIL BOILER 

SYSTEM. 

EFFECTSON EXISTING 

CONTROL SYSTEM 

- PRESSURE TRANSMITTER TO 

FOSSIL COMBUSTION CONTROL 

SYSTEM INOPERABLE. 

- FOSSIL DRUM LEVEL CONTROL 

EFFECTS. 

- COMBUSTION CONTROL SYSTEM 

CONTROL OF THROTTLE PRESSUF;E. 

- NO AUTOMATIC OPERATION OF 

FOSSIL BOILER < 50% LOAD. 

- NO AUTOMATIC OPERATION 

OF FOSSIL BOILER <50% LOAD. 

- EFFECTSON DRUM LEVEL CON. 

TROL SYSTEM. 

CONTROL SYSTEM 

MODIFICATIONS & ADDITIONS 

- SOLARSTEAM ATTEMPERATOR 

MUST BE DESIGNED TO CONTROL . STEAM TEMP. FROM IWO~F TO 

950'~ NORMAL OPERATION DOWN 

TO ~JoOF FOR TURBINE SHUTDOWN 

LIMITATIONS. 

- SELECTIVE DEFOCUSING OF HELIO. 

STATST0 LIMIT SOLAR RECEIVER 

STEAM OUTPUT. 

- AUT3 ISOLATION OF FOSSIL 

BOILER PORTION. 

- SOLAR STEAM ATTEMPERATOR DE. 

SIGNED TO CONTROL TEMP. FOR 

TURBINE SHUTDOWN LIMITATION. 

- SELECTIVE DEFOCUSING OF 

HELIOSTATS. 

- FOSSIL BOILER DESIGNED FOR 

AUTOMATIC OPERATION < 50% 

LOAD. 

- FOSSIL BOILER DESIGNED FOR 

AUTOMATIC < 50% LOAD. 

- AUTOMATIC ISOLATION CAPA. 

BlLlTY OF SOLAR PORTlMU. 

- AUTOllATlC ISOLATION CF FOSSIL 

BOILER PORTION. 

- FOSSIL BOILER COMBUSTION CON. 

TROL DESIGNED FOR AUTOMATIC 

OPERATION < 50% LOAD. 

- MODIFY TURBINE CONTR3L FOR 

CONSTANT THROTTLE PRESSLIRE 

OPERATION. 

COMMENTS 
problem areas to be expended from during the interfacing of the existing system 

and the solar repowered additions and also gives possible solutions. 

Figure 4.2-6 shows a simp1 ified schematic of the solar repowering system with the 

solar system operating in paral 1 el with the fossi 1 boi 1 er feedwater system. 

Additional details of this schematic %re shown on P and I Diagrams P3-1 and 

P3-6. The condensate system is not shown in Figure 4.2-6 since it is a common 

system. The condensate system is shown in detail on P and I Diagram P3-1. 

The solar receiver feed pumps take feedwater in paral lel from the deaerator with 

the boiler feed pump for the fossil boiler system. This feedwater is raised in 

pressure to 2417 psia and passes through the new No. 7 and No. 6 high pressure 

feedwater heaters . These two feedwater heaters operate in pars1 1 el with the 

No. 1 and No. 2 heaters in the existing fossil boiler system and receivi extraction steam from the No. 1 and No. 2 high pressure extraction points on the 

turbine. The new feedwater heaters are more fully described in the Feedwater 

Specification Section of this Report. 

Drains from the No. 6 heater are cascaded to the No. 7 heater and then to the 

deaerator. Emergency drains for these two heaters will be piped to the protection requirements as defined by the ASME. At the system design point, feedwater 

from the No. 6 heater is at a temperature of 437°F. These feedwater heaters are 

to be located on the operating floor in the Main Turbine Building in the general 

area of the evaporators which will be removed due to the addition of a new 

demi nera'l ization system. 

Receiver feedwater piping is to be routed in an overhead rack approximately 3200 

feet long. The feedwater flows through the receiver preheater panels, through 

the temperature control valves and enters the boiler superheat panels. It is our 

understanding that the steam temperature from the solar rec~iver can vary as much 

as plus or minus 50°F; therefore, a trim on temp~rat~.rre wi 11 be III~~C in J steam 

attemperator to be located in the Turbine Building. The receiver steam piping 

interfaces with the fossil boiler steam piping in the Turbine Building and is 

shown on Drawing L-22929, Sheet No. P4-4. 
Figure 4.2-6. . Reev2s Stati-on Unit No. 2 Schematic 
The receiver feed pumps will be two 100 percent capacity pumps and are described 

more fully in the ,Feed Pump Specification Section. The receiver feed pumps were 

designed to be operated in parallel with the existing boiler feed pumps in order 

to minimize control and installation problems. The control systenis for the solar 

receiver and combustion control syste~r~ of the fossil boiler must operate in parallel with the solar control system. The total head developed across the pump 

is based on the pressure losses of the feedwater piping, heaters No. 6 and No. 7, 

receiver pressure losses, receiver elevation, steam pi ping losses and throttle 

steam pressure requirements. Two 100 percent capacity pumps are recommended 

on the basis of sys ten1 re1 iabil i ty. 

The receiver feed pumps are to be located in the new Solar System Equipment 

Building which is to be located on the west side of the plant at the junction of 

Units 1 and 2. This building will be constructed adjacent to and connected with 

the main Turbine Building. 

The receiver is described in detail in the Receiver Specification of this Report. 

Briefly, the receiver consists of preheat panels and superheat panels. The number 

of panels will be determined during detailed engineering design. A temperature 

control valve is located between each of the preheat and superheat parlels to 

control the receiver out1 et steam temperature to 1000°F. During hybrid operation, 

solar insolation transients could result in a raeduction in solar clcctrical generation. The fossil boiler may he brought up in load to minimize power 

fluctuation. A solar insol ation transient during solar only operation wi 11 result 

in a drop in solar electrical power generation. 

The flash tank system, to be located just below the receiver panels, will be 

used during start-up and shut-down operations of the receiver. Also, steam will 

be routed to the flash tank during periods of solar transients when the receiver 

output drops be1 ow 1 5 percent .of rrlax ill~urii recei vein 1 oad. 

Start-up and shut-down operations are described in Section 4.2.4.3 of this Xeport. 

Uuririg condi t.ior~s u T low receiver stcam pressure, temprlrat.~lre and flow, the discharge of the receiver will be routed to the flash tank through a pressure control 

val ve (PCV-1-6). Depending on the steam conditions (water, saturated steam or 
superheated steam), the flow to the flash tank will be expanded to a predetermined pressure as determi ned by another pressure control valve (PCV-2-6). The 

vapor and drains from the flash tank are routed to the condenser through piping 

to be located on the overhead pipe rack. 

Figure 4.2-7 shows the estimated overall dimensions of the receiver that were 

based on a scaling of the 10 and 100 MWe pilot and commercial plants for Barstow. 

This figure also shows a tabulation of the estimated weights for the receiver. 

Steam attemperature is used to modify the receiver outlet steam temperature to 

maintain the required turbine throttle temperature of 950°F. This involves spraying water from the receiver feedwater pump discharge into the receiver steam. 

The air operated valve at the atteniperator will be specified so as to comply with 

turbine water damage prevention standards. If an upset condition occurs, the 

turbine water damage prevention system will signal the air operated valve to 

close, thus providing a positive shut off of attemperator water flow. 

Additional water induction protection is provided by the moisture separator 

located at the discharge of the steam attemperator. Also five (5) drain pots, 

or drip legs, each with a level control valve, will be installed in the receiver 

steam piping at each low point of the thermal expansion loops as described in 

the Piping Design Section. Drains from the drain pots and from the moisture 

attemperator will be combined and routed to the condenser hotwell. 

The major mechanical interfaces of the solar system to the existing fossil 

boiler system at Reeves repowered unit are as follows: 

e The feedwater interface will be at the receiver feed punips inlet 

and will be from the deaerator exit pipi.ng and in parallel with 

the boiler feed pump. This interface 'location is shown by note 

on Drawing L-22929, Sheet P4-6. 

e ' Extract.ion steam i nterfacing wi 11 be as described previous ly 

from the No. 1 heater pi ping to the No. 6 heater and from the 

No, 2 extraction piping to thc No. 7 heater. These interface 

locations are shown or1 Drawing L-22929, Sheet P4-6. 

a Receiver steam pi ping will interface with the existing - fossi 1 

boiler main steam line supplyir~y the turbine. the routing is 

shown on Drawing L-22929, Sheet P4-4. 
" MDAC PRELIM. DESIGN REPORT, VOL. 4. DOE SAN/I 108- 814, NOV. 1977 

RECEIVER SURFACE THOUSANO FT.~ 

Figure 4.2-7. Receiver Weight Comparison 
e Interfacing of the flash tank vent 'and drain 1 ines is shown on 

Flow Sheets P3-1 and P3-6 and Drawings L-22929, Sheets P4-4 and 

P4-6. 

0 Condensate system interfaces with the condensate polisher are 

shown on Drawing L-22020, Sheet P4-2. 

Control sys tem interfaces between the solar system and the exis ti ng fossi 1 boi 1 er 

combustion control system are described in the Controls Section of this Report. 

The system design described herein for the solar portion of the repowered Reeves 

Unit No. 2 has been optimized to provide the simplest most straightforward design 

to minimize the impact on existing plant equipment. The design is based on data 

from the central receiver 10 MWe pilot pla~~t pr-uyranl tor Harstow. 

The remaining portions of this section describe in greater detail the major solar 

system components and the piping desiyrl and analysis arrived at for the steam:and 

feedwater piping to and from the solar receiver. 

4.2.1.2 RECEIVER DESCRIPTION 

The design of the receiver far this solar repoweriny project is to be based upon 

the receiver used in the Barstow, California Pilot Plant. That receiver is a 

Rocketdyne once-through boiler, fabricated of Incoloy 800 tube materials. The 

Barstow design will be scaled-up to meet the capacity requirements of this 

Project. 

Receiver design characteristics are contained in Tdble 4.2-2, and operating 

conditions are sut~~~r~arizedn Table 4.2-3. Specific design issues to be included 

in this section are as follows: 

Thermal Losses 

Thermal losses from the Pilot Plant were used. Reflected insolation was calcu1 ated from solar alsormptance measuremen1:s obtained during the Solar Research 

Experiment (SRE) . Infrared radiation losses were calculated based on emi ssivi ty 

measurements obtained during the SRE. Convective losses were calculated by a 

fairly complex procedure, the details of which are discussed in Section 2.4.4.1. 

Thermal losses are summarized in Table 4.2-4. 

4-21 
TABLE 4.2-2. RECEIVER DESIGN CHARACTERISTICS 

Total Weight of Receiver (estimated), kips ....... 

Height (feet) ..................... 

Diameter (feet) .................... 

Tube Boiler Material .................. d 

ASME Code for Design .................. 

Absorptivity ...................... 

Emissivi ty ....................... 

Absorber Rated AP (includes TCV) (psi) ......... 

Incoloy 800 

ASME Boiler and 

Pressure Vessel 

Code Section I 

0.95 

Sensitivity to Clouds and Other Heat Flux Disturbanc.es 

Each modular receiver panel, consisting of a preheat and superheat panel with 

i nterconnecti ng water f low/temperature control val ve, is capable of approximately 

6.7 : 1 flow turndown ratio. This design compensates for the power fl uctuations 

caused by some types of clouds moving across part of the heliostat field without 

affecting the other panels. The approach in operations in the presence of passing clouds is discussed more fully in Section 4.2.4.2, but briefly is as follows: 

It is antlclpaled that densc, fast-m~ving rln~~d forxiations will be forecast and 

and the fossi 1 boiler load would be increased to smooth the system transients. 

For i ntermi t.tent small clouds, the receiver wi 11 prwduce somewhat less than rated 

steam flow and power. output wuuld be curtailed ac.sording1.y. If the heat loads 

get sufficiently low due to the cloud cover such that receiver flow is less than 

15 percent of maximum, then the receiver output would be routed to the receiver 

flash, tank, and the solar portion of the system would be shut down. 

A review of predicted heat flux distribution for the receiver has been yerafurmed 

by MDAC and Rocketdyne. AS a resull ul' this review, the following conclusions 

were reached: 

0 Receiver cooling margin will be enhanced due to the increased 

available water/steam flow per unit 0.f heated circumference for 

the repowered system over the Pilot Plant. 

A potential problem of thermal gradients around the circumference 

of the receiver may be experienced. The predfcted data shows a 

maximum gradient of 48 percent between two panels where the Pilot 
TABLE 4.2-3. RECEIVER OPERATING CHARACTERISTICS 

1 (a) Design Flow (lb/hr) ................... 328,900 

1 (b) Minimum Flow (lb/hr) .................. 49,300 

Fluid States: 

2 (a) Maximum Inlet Pressure (psig) . : ............ 2,975 

2 (b) Design Inlet Pressure (psig) .............. 2,138 

2 (c) Design Outlet Pressure (psig) .............. 1,453 

2 (d) Maximum Inlet Temperature (OF) ............. 450 

2 (e) Design Inlet Temperature (OF) .............. 437 

2 (f) Maximum Outlet Temperature (OF) ............. 1,050 

2 (g) Design 011tlet Temperature (Qr) .............. 1,000 

2 (h) Minimum Outlet Temperature (OF) ............. 950 

2 3 (a) Maximum Absorbed Heat Flux (MWt/m ) ........... 0.32 

2 3 (b) Average Absorbed Heat Flux (MWt/m ) ........... 0.14 

4 Design Incident Power (MW~) ............... 125.4 

5 Absorber Efficiency (percent) .............. 

5 (a) At Maxiniurn Insolation (noon summer solstice) ...... 85.4 

5 (b) At Design Insolation (2:OO p.m. winter solstice) .... 84.3 

TABLE 4.2-4. RECEIVER HEAT LOSSES 

Noon 2:00 p.m. 

Summer Solstice Winter Solstice 

IR Radiation (~Wth) 

Convection (~~th) I

Reflected Insola tion (~~th) 

TOTAL (MWe) 

Incident Energy 

Percent LOSS 
Plant and commercial central receiver designs are limited to 20 to 

25 percent. This issue will receive attention during the STTF 

panel test program. 

Hydraulic Stability 

It has been shown recently that intertube hydraulic instability could possibly 

exist, and a static instability problem could develop at flows below 20 percent 

of the rated steam conditions. Orifices installed at the boiler superheat tube 

inlets have been shown analytically, to be a fix to this problem by adding a dampening pressure drop to the system. Tests are scheduled for October 1978 at Sandia, 

A1 buquerque, to determine if this problem exists and to verify its solution. 

Recei ver Thermal Fati gue Li fe 

Recent analyses by Rocketdyne and two other independent con tractors have shown 

that a receiver desi gn based on the Barstow Pilot Plant desi gn will have adequate 

thermal fatigue 1 i fe for the Reeves Station Hybrid Repowering conceptual desi gn. 

Receiver Reflectivity 

Reflectivity for the receiver surface is as follows: 

Wave Letigth Reflectivity 

(Microns) (Percent) 

4.2.1.3 COLLECTOR SUBSYSTEM DESCRIPTION 

The Reeves Station repowering collector design was based on the use of the MDAC 

collectors, drives and controls as proposed for the Barstow Pilot Plant. That 

design was modified to comply with the Reeves site conditions. Major changes 

I ncl uded : 

Revising the size and layout of the collector field and number 

of he1 iostat units to conform to the physical characteristics of 
the Reeves site. This revision was based on the design insolation 

at the Reeves site, the reflectivity of the heliostat mirrors, the 

absorptance of the receiver, and the general design plan of power 

required. The collector field design is described in Section 4.5.3.1. 

o Integrating the collector control system into the Master Control 

System being proposed for the repowered Reeves Station 

a Establishing the most effective foundation for each heliostat 

The design operating environment is as follows: 

a Design wind speeds (with gusts) are: 

Operational Mode 

- Sustainedwinds of 13.5m/s (30mph) 

- Gusts with rms velocity of 18 m/s (40.3 mph) 

Nonoperational Mode 

- Sustained winds of 32 m/s (71.6 mph) 

- Gusts with rms velocity of 44.7 m/s (100 mph) 

e Temperature: -22°F (minimum) to 110°F (maximun~) 

2 a Track the sun at low insolation levels (0.3 kW/M ) 

30year life 

e Earthquake: (see Section 4.5) 

a Precipitation: 

- Snow, average annual : 10 inches 

- Rain, average annual : 8 inches 

- Max. 24 hour rate: 1.92 inches 

The safety requirements are: 

0 Meet OSHA, NFPA, ANSI, and Public Service Company of New Mexico 

requirements . \ 

Control ref1 ected beam. 

- No unsafe reflected beam outside exclusion area. , 
- No unsafe reflected beam on structures or plant personnel 

a Provide for automatic safe stowage in the event of failure 

The operating requirements are functions of: (1 ) interfaces between the coll ector 

and the balance of the central receiver system; and (2) the operating modes. 

The collector interfaces with the receiver through the reflected beams from the 

he1 iostats. The he1 iostats track the sun and direct the reflected beams so that 

the light falls on the receiver with a prescribed flux distribution. Spillage of 

1 ight missing the receiver is minimi zed, consistent with overall system economics. 

The collector receives power from the distribution system to operate the electric 

motors and control system. 

PRELIMINARY DESIGN COLLECTOR CONFIGURATION 

The inverting heliostat configuration is 6.5 meters on a side with an actual 

2 reflective area of 38.03 m . The structural support is a main torque tube with 

four cross beams. The drive unit incorporates separate azimuth and elevation 

drive rotary units. The cylindrical pedestal supports the drive unit through a 

bolted interface and is in turn attached to a reinforced concrete foundation. 

The control sys tem comprises he1 iostat, field control 1 ers and collector control 

computer using an open loop system. 

The inverting orthogonal design has the adaptability of being stored face down, 

vertical, or face up. The choice depends upon safety, dust accumulation and 

cleaning, and heliostat wind loads. The face down position has ttie following 

advantages: 

e Heliostat cannot reflect sunlight in a dangerous manner. 

Under light rain conditions, less dust adheres to mirror. 

8 tlest under hlgh winds w i 111 l~ l owi ng sand or dul; t;, ur~d L'tended 

fields, and for extended periods of time. 

Vertical stowage position has the following characteristics: 

e Self-cleaning due to rain, heavy dew, and frost. 
e Higher wind loads and potential danger of damage due to blowing 

sand. 

Face-up stowage position has the following characteristics: 

e Mi'nimizes the transitional time from the operational position to 

the stowed position, and therefore the duration of exposure to 

wind loads during periods of rapidly rising winds. 

a Minimizes the wind load duration to go from operational position 

to be used face-up in a rapidly rising wind. 

It is recommended that vertical stowage be used (unless safety is critical) to 

minimize dust buildup. 

The details of the he1 iostat components are discussed in the fol lowing subsections. 

REFLECTOR 

Each reflector pane1 is a flat structural sandwich. The front face is a 3.+7 mm 

(1/8-inch) second surface mirror, and the back face is a 0.56 mm (0.022-inch2 

galvanized steel sheet. The faces are adhesively bonded to a 5.08 cm (2-inch) 

core, made from rigid extruded polystyrene foam (STYROFOAM) of 2 lbs per cubic 

foot density. . Each of the six panels measures 2.16 m by 2.9 m (85 inches by. 

11.4 'inches). The panel edge is protected from damage by a small extension of the 

core and is sealed by a polyurethane weatherseal compound. At the four attachment points, the loads are transferred to the cross beams by shallow, formed, 

'circular steel cups. Coll ector mirror characteristics are shown in Table 4.2-5. 

STRUCTURAL SUPPORT 

The support structure consists of a main torque tube attached to the drive system 

and four channel cross beams. Each pair of cross beams supports a group of three 

reflector panels. The slot between these panel groups provides clearance for the 

central pedestal when the assembly is rotated to the face-down stowage position. 

Two drive attachment fittings are rr~achined on the surfaces which mate with the 

drive and welded to the torque tube. Four ring flanges are also welded to the 

tube for attachment of cross beams. 
TABLE 4.2-5. MIRROR REQUIREMENTS 

Requirement Required Val ue Expected Value 

Reflectivity 0.88 0.91 

Specularity 

(% in 4 mr Cone) 

Hail Capability: 

Any Orientation 

Stowed 

Flatness 

(standard Deviation) 

Dura bi 1 i ty 

19 mm (3/4-in.) 

25 mrn (l-in.) 

1.0 mr 

Units must survive Albuquerque, NM 

environment for 30 years without significant permanent degradation (1% 

ref1 e c t i v i t y ) and maintain .structural 

integrity. 

19 mm (3/4-in.) 

25 mm (l-in.) 

1.0 mr 

DRIVE UNITS 

Each heliostat incorporates a drive unit that produces appropriate reflector 

motions for solar tracking, emergency slewing, routine reflector positioning, 

and stowage. The drive unit consists of azimuth and elevator drive mechanisms. 

These drive mechanisms are composed of motors, drive trains, position feedback 

transducers, reflector support bearings, and structural housings. The azimuth 

and elevation drive trains are schematically identical, and each is essential'iy 

a motor with two stages of reduction, capable of producing the high-torque. 

The pedestal is a thin-walled steel column, 50.8 cni (20 inches) in diameter and 

2.74 m (108 inches) long, welded at the lower end to a tapered cone. The upper 

end has a 1.9 cm (0.75-inch) thick steel plate for attachment of the drive unit. 

Attachment of the concrete foundation is done by sliding the pedestal unit 

tapered cone down over a similar cone on the foundation. Foundation design is 

discussed in Section 4.5.2. 

The collector operating modes which the various control systems must address are 

shown in Table 4.2-6. 
TABLE 4.2.6. COLLECTOR OPERATING MODES 

Mode 

Normal Track 

Command Position 

Local Control at 

Field Control 1 er 

Local Control at 

He1 iostat 

Control 1 er 

Field Control 1 er/ 

Heliostat Controller 

Tracks to gimbal axis positions 

supplied by collector control 

computer 

'Tracks to gimbal axis positions 

supplied by collector control 

computer 

Mobile test set controls heliostats 

through fie1 d control 1 er 

Mobile test set controls heliostat 

through heliostat controller 

Coll ector Control 

Computer 

Provides gimbal axis 

positions based on 

solar ephemeris or 

tracking points for 

beam safety 

Provides gimbal axis 

positions based on 

mode ; e .g . , stowage 

cleaning, maintenance, 

etc. 

Locked out 

Locked out 

WE1 GHTS 

The weights of the collector system, 1 ess electronic components, are as follows: 

lb' 1b 

Reflector panels 556 1,227 

9 Structural support 503 1 ,I 08 

e Drive unit 3 04 670 

e Pedestal 231 509 

TOTAL (no foundation) 1,594 3,514 

Foundation 4,423 9,750 

TOTAL (with foundation) 6,017 13,264 

Col 1 ec tor Power Requi remen ts 

Collector field power requirements are shown in Table 4.2-7. The trenching and 

cal ibing costs are minimi zed by: 

,e Primary and secondary feeders direct to the heliostat triac 

swi Lching 
Data buses run from the central computer to groups of field 

controllers. Local data buses run among the fie1 d controllers 

in a group and to the associated heliostat controllers. Decentralization of the controller reduces the wiring costs 

substantially. 

TABLE 4.2- 7. COLLECTQR FIELD POWER REQUIREMENTS 

0 ~ratjcg Power Requi red/ Power Requi red/ 

C&hdi tion He1 iostat Fie1 d Comments 

Tracking 14 W 

Emergency Slew 300 W 31 5 KW Approximately 1050 

heliostats will be 

, slewed (in one axis) 

at a time, outer 

heliostats first. 

4.2.1.4 RECEIVER FEEDWATER HEATERS 

Two receiver feedwater heaters will be required to heat the feedwater from the 

receiver feed pumps to a design temperatuve of 437°F before ft enters the 

receiver. The heaters will be arranged in series with each capable of accepting 

the entire output from the receiver feed pump. These heaters are of the shell 

and tube type with the high pressure feedwater being contained in the tubes. 

The units are heated with high pressure extraction steam from the turbine. No 

redundancy is thought necessary at this time, as this type of heat exchanger 

normally requires little repair or maintenance work. Bypasses around the heaters 

are included in the event that a heater is taken out of service for maintenance. 

For the heater condition out, receiver steam flow will be slightly reduced; also, 

the extraction flow from the turbine will be reduced. During the detailed design 

phase, the turbine manufacturer should be contacted for the effects on the turbine 

of a one or two high pressure t~tidler out condl tiur~. 

The heaters will be designed to conform to the ASME Boiler and Pressure Vessel 

Code, Section VIII, Division 1, and thc Heat Exchanger Tnstitute (HEI) Standards 

for Closed Feedwater Heaters. 
The uni ts wi 11 comply wi th the desi gn condi tions of service as speci fied in the 

Closed Feedwater Heater Design Summary Sheets, No. JD20.2-1, pages 1 and 2. 

4.2.1 .5 RECEIVER FEED PUMPS 

Receiver feed pumps will be required to pump condensate from the existing 

deaerator through the new feedwater heaters to the Solar Receiver. Two pumps, 

each with capacity to supply 100 percent of the receiver demand, will be required. 

This redundancy ensures adequate flow through the receiver should one pump be 

shut down for maintenance or repairs. The pumps are equipped with variable speed 

drive to enable the Receiver Feed Pump Controller to regulate flow to the Solar 

Receiver, as required, during sys tem start-up, shut-down, steady state operation 

and emergencies, 

The pumps will also be equipped with warm-up orifices, minimum flow recirculation 

orifices, and recirculating flow control valves, as shown on Drawing L-22929, 

Sheet P3-6, and discharging to the deaerator. Pump minimum flow requirements 

should be established'during detail design and during pump selection. 

These pumps shall comply with the design conditions of service as specified in 

Table 4.2-8, Receiver Feed Pump Data Sheet. 

I 

4.2.1.6 CONDENSATE HOTWELL PUMPS 

New condensate hotwell pumps will be required to pump the condensate from the 

Unit No. 2 Condenser Hotwell through the condensate polisher. These new pumps 

that will replace existing Hotwell Pumps 2A and 26 are requir-ed because the new 

condensate pol isher will create an additional 70 psi pressure drop in the system, 

and the present puinps cannot maintain flow wi th this addi tional sys tem pressure 

drop. Each pump will have the capacity to supply approximately 60 percent of the 

condensate design load when operating individually. The pumps are to be of the 

vertical turbine type, complete with 480 vol t electric motor and accessories. 
Closed Feedwater Heat Design Summary Sheets (1 of 2) 

DIVISION USAGE Steams -L3over MM] P I PP I SH I FI ( SP INCORPO~AICD d 

ENGINEERING STANDARD 

CLOSED FEEDWATER HEATER DESIGN CRITERIA 

SUMMARY SHEET 

STANDARD t. JMt E : 

JD 20.2-1 

PAGEL OF 2 

ISSUED12/12,'73 

REVISED 

, 

1 

2 

3 

4 

5 

6 

7 

-8- 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

- 19 

20 

21 

22 

23 

24 

2 5 

-26 

, 27 

28 

29 

30 

3 1 

32 

33 

34 

35 

. 36 

37 

38 

79 

40 

41 

42 

43 

- 4 4 

45 

46. 

4 7 

48 

49 

50 

Job NO. C-20266 Customer: l'Nis1 

-- Station: llceves Unit KO. 2 Heater No. 7 .No. of Shells Rea 'd Per-U_z&_t .,-. 

Data Based op S-3 Reference Dwg. 

DESIGN REQ'L'IREEiTS 

Heater ~rrangement :Qliorizontal vertical-channel Up -L1 .- 

Ver-ti~~l:Channel-~D.~~n~~3~rizo.n t~l~ond~~sSer-~ 

Zone- Requirements: m~esup. a~onde~~in~ m.;b-~oolf3~ a Ir.ternalC Zxternal 

-channel: ~~emispherical aslip tic211 j~olts</~lanc,ed I . - 1:ull - Ar-=sc 

Manway Cover Types: (Used with He@.spherical or Elli2tical) 

0 ~olted/FJ.an~e&~~Pressure Seal azbtacied ?lug Ji3rez3=h LoGG3uLLt R:;'f - . .. 

Ple thod of Removal; .a ~undle a~hell - 3ollers: 9 Cha.cne-1 E:yi~e~ - . 

Overall - Length + Withdrawal: Ft. ia-Centerline of Heater Abo-ze 'loor: ir. :?+ - Tube PIaterial: !-lorlel (.30/70, Cu/Ni) kU\S!E SB-!F.i 

Clad . -- Tube -- Sheets: . m~es NO - Tube Attachment: a!iel=ed 3 i:aande? 

Insulation Clips: a yes a Xu - Asse~blca: XI Y2s r? :Lo 

TUBESIDE OPEUTIKG CONDITIOYS 

- Feedwater Flow Lb/Hr 

Feedwater Inlet Temperature OF 

Feedwater Inlet Enthalpy ~~li/~b 

Fssdwkter Outlet Temperature OF 

Feedwater Outlet Enthalpy ~tu/~b 

Operating Pressure . - .. . . . . ?SIG 

Temperature re-~ina1 Difference OF 

Efaximum Possible Feedwater Elov Conditicn Lbs/LLP 

TUBES TDE 1)Es 163 Co!;p~TIoy~ 

Design Pressure/Test Pressure PSIG 

Desi~n Temperature OF 

Piax. Velocity Cd 60'~ 1. @ Average ~emperacure Ft/Sec 

Allowable Tube Pressure Drop PSI 

326 ~;7 

31 0 . - 

2 84 

368 

34 2 

2,3SIj 

3 

2975/246) 

330 

S/S.9 

7 0 

---, 

Sa&SInE O?W;GC.QNDITIOqS 

Steam Flow ~b /Hr. 

Steam Inlet Temperature OF 

Steam Inlet Exhalpv Btu/Lb 

Shell Pressure PSIA 

Shell saturated Temperature OF 

Drain lnet Flow Lb/Hr 

Drain - Inlet Tenperature -- .- .- -- OF 

Drain Inlet Enthalpy Btu/_Lb 

Drain-!utlet-Flol~- L t Lt1-r 

Drain Outlet Temperature OF 

, Drain,Outlet Enthalpy Btu/Lb 

17,frI) 

515 

1,ZS: 

176 

371 

.?4,26.;3 - -. . . .. . 

377 

3513 

r12.053 

3 70 

- 

29 1 

. . . .I . .I.. . -. 

--. sW3-J.. SIDE-Rf SIGN CONDITICSS 

Shell P_e~igr?-~.c~,s sure. /-TestPrcs s.ure PSIG/V~C/P~~G 

-Shell. Design-T.emp.erature 1 Skihtle-sign OF 

Drnins-Csoler-~\~~o0~ch F 

.- -.- 

TOTAL HEAT ESCtttUGED Btu/H-r 

Remarks: 

_ -. 

ISO / :1 /,IS?.? (YO. : 

3SO / 5:) 

10 

18, !)!I0 ,Ul!O 
Closed Feedwater Heater Design Summary Sheets (2 of 2) 

r 

DIV~S~ON USAGE Sfiearrms~~ogea MM( P PP (SH ( FI I SP IMCO~POHA~LD 

Ixi I I I ENGINEERING STANDARD 

APPROVALS 

CLOSED FEEDWATER HEATER DESIGN CRITERIA 

SUMMARY SHEET 

STANDARD NUMBER 

JD 20.2-1 

PAGEL OF- 2 

ISSUED12/ 12/73 

REVISED 

1 

2 

3 

4 

5 

6 

7 -- 

8 

9 

10 

11 

12 

13 

, 

15 

.16 

-. 17 

18 

19 

20 

21 

22 

23 

24 L 

2 5 

26 

27 

' 28 

29 

30 

3 1 

32 

33 

34 

35 

36 

37 

38 

39 

40 

41 

42 

43 

4 4 

45 

4 

47 -.. 

48 

49 

!io 

Jcb No. C-20266 Customer: PNN 

Station: Itccvcs Unit No. 2 Heater No. 6 No. of Shells Req'd Per Uni.t.1- 

Data Based on Heat Balance No. 5/11/78 S-R Reference Dwg. 

DESIGN REQUIFXIW_T_S 

Heater ~rrangement:a~orizontal 0 Vertical-Channel UP 

n vgrt4cal-.Ch-ann.e.l-D-~~ :J_~or-iz-o.n tak~ondenser3r-?;esk 

Zone,- Requirements: E~esu~. a~ondensin~ a sub-=ling a ~nternala ~xternal -. 

Channel: WHemispherical ~~llipticalr l~olted/~laneed 17 Full ws 

Manway CoverTypes: (Used with Hemi_spherical or Elliptical) 

0 ~olted/~l~~~ed~&?ressure Seal ;?zhreaded Plun LI ~reac~~~~ayi~k~

d. 

EIe thod of ~emov&:-~~u~dl-e @%hl~-~o.~.le-r_sd~.h_an.ne~o~ 

Overall Length + Withd-rawal: Ft. in-Centerline of Heater Above Floor: Ftdn, -. Tube Material: bloncl (30/70, Cu/Ni) .ASME SR-163 

Clad Tube Sheets: l%]Yes I o - Tube Attachment: al~elded Eaanded 

Insulation Clips: b-0 No - Assembled: Yes No 

TUBESIDE OPERATING CONDITIONS 

_ Feedwater Flow Lb/Hr 

Feedwater Inlet Tenperat~lre OF 

Feedwater Inlet En thalpy BTu/Lb 

Feedwater Outlet Temperature OF 

Feedwater Outlet Enthalpy Btu/Lb 

Operating Pressure PSIG 

Temperature .?e-qninal Difference IJ F 

PLaximum Poss l? le Feedwater Flow Conditj.0~ Lbs/llR 

._ . _ TUBESIDE DESIGN CONDITIONS 

Design Pressnre/~est Pressure PSIG 

Desipn Temperature OF 

Max. Velocity @ 60"~ / @ A.verage Temperature Ft/Sec 

Allowable Tube Pressure Drop PSI 

326.667 

567 

343 

437 

417 

2,300 

0 

- - 

2075 / -1460 

4 50 

8 / 9.5 

20 

SHELL SIDE OPEmNG CONDITIOXS 

Steam Flow ~b/Hr. 

Steam Inlet -- Tenperature -- OF 

Steam Inlet E~halpv ~tu/~b 

Shell Pressu~ PSIA 

Shell Sa turaJe$.,,:emp,e,r_au~e OF 

Drain inlet Flow - Lb/tIr 

Drain Inlet Tcmperatuse IJF I 

~rai~~~etn'th~~lp~ BtulLb 

Drain Outle c-Flc-w-.- LUdH-r 

Drain Outlet Temperature OF 

Drain Outlet En*lpy Btu/Lb 

- SHELL -. SIDE DESIGN CONDITIONS -_ . -. . -. - - .- -- -. - - - 

Sheil~esign2-~CS su re 1.. -T~st-E~e_s.sur_e PSIG/VAC/PSIG 0 6~hp_l!,~~~~.s~sn:ne~~.~.ratu~e~/Ski~r_t44~Cs ign -. 

Drains-Cooler-,~!p~r_o-~ch - OF 

- TOTAL BEAT EXClLLXGED t)tu/~.~ 

Remarks: 

. - 

670 

1.345 

371 

437 

0 

- -- - - - 

24,265 

377 

350 

390 I 0 / AS~II; COCIC 

440 / 6SO 

10 

-- 

24,200,000 
TABLE 4.2-8. RECEIVER FEED PUMPS 

~ ----- ~-- ~-- -~ ~-~-- ~~ 

;Two - 100% pumps wi th variable speed drive and motor 

Capacity - 740 gpm each 

Total development head - 5800-feet 

Temperature - 300°F 

NPSH available - 52-feet 

Discharge pressure - 2304 psi g 

Suction pressure - 22.5 psig 

~~draulic h.p. - 1181 

Six to 12 stages* 

Speed - 3600 rpm* 

E f fi ci en cy - 55 to 75%* 

BHP - 1574 to 2146* 

NPSH required - 16 to 42 feet* 

Motor HP - 2000 hp 

Vol tage - 2400 vol ts 

*Manufacturer dcpcndcnt 

Hotwell Pump Design Conditions: 

353 gpm/Pump Capacity* 

e 422-17 tdh* 

e 1760 rpm 

Approximately 10 stages 

Column Diameter Length (approximately) 9-1 12-inches/9-112-feet 

4.2.1.7 PIPING DESIGN AND ANALYSIS 

This section describes the feedwater and steam piping design from the receiver to 

the main Turbine Building where the steam line interfaces with the existing fossil 

boiler steam line and the feedwater line interfaces at the receiver feed purrlp 

discharge. 

*Wi th both pumps opera ti ng 
An economic analysis was made to determine the si zes of the steam and feedwater 

piping based on material and thermal insulation costs and the costs of pressure 

heat losses based on plant economic factors as estimated by PNM. 

Based on this economic sizing analysis, a stress analysis was performed on the 

steam line for a number of pipe routings to determine the most acceptable routing 

based on thermal, pressure and weight loadings. These stress.analyses were made 

for the downcomer in the receiver tower, the steam piping routed in 'the overhead 

pipe rack located in the collector fie1 d, and the piping in the main Turbine 

Building where it interfaces with the existing fossil-boiler steam piping. 

The remainder of this section discusses 'in detail the following studies and final 

piping design: 

Feedwater and Steam Piping Economic Analysis 

Steam Piping Stress Analysis 

Final Piping Design 

FEEDWATER AND STEAM PIPING ECONOMIC ANALYSIS 

Due to the lengths of piping required for the solar central receiver concept, 

steam and feedwater piping costs are significant. An economic analysis based 

on preliminary design data was performed in order to: 

Establish the optimum pipe sizes (inside diameters) for the two 

1 ines 

0 Establish the economic thickness for the piping insulation 

Refine the cost estimates for the lines 

Based on engineering judgment of the range of pipe sizes feasible for the steam 

and feedwater flows anticipated, three sizes of pipe were considered for each 

service, speci fi cal ly 8-inch, 10-inch and 12-inch inside diameter steam piping, 

and 6-inch, %inch and 10-inch schedule piping for the feedwater service. A 

range of thermal insulation thicknesses, 4 to 8 inches, was considered for each 

size of pipe. Cost estimates for material and installation 'labor were obtained 

for all sizes of pipe. Cost estimates for material and installation labor were 
obtained for a11 sizes of pipe and insulation under consideration and escalated 

at 10 percent annually to December 31 , 1981. The 1981 present worth cost of a 

1 psi change in receiver feed pump head was developed, as was the 1981 present 

worth cost of a Btu of heat lost through the insulation. Total costs of the 

steam and feedwater piping installations were developed by summing the material 

and installation costs, costs of heat loss and costs of pressure drop for each 

combination of pipe size and insulation thickness. As a result of these calculations, the fol lowing confi gurations are recommended: 

Steam Pi e - 10-inch inside diameter, 1.425-inch wall thickness, 

dA335) alloy steel pipe (2-114 percent chrome, 1 percent molybdenum) with 8 inches of calcium silicate insulation 

with sheet aluminum jacketing 

e ---. Feedwater Pipe-- 8-inch XXS ASTM A106 Grade B carbon steel pipe 

with 6 inches of calcium silicate i n s u l a t i o n w i t h sheet aluminum 

jacketing 

Estimated installed costs of the steam and feedwater piping in current dollars 

are $1 .I02 million and $0.332 million, respectively, for a total of $1 .434 million. 

When escalated to December 31 , 1981 , the instal led cost estimates are 

$1 .576 million for the steam pipe and $0.474 million for the fecdwater pipe; the 

estimated total installed cost for both lines is $2.050 million. 

A tentative receiver steam and feedwater routing was es tab1 ished for the prel imininary collector field layout. Based on the rnliting, the steam linc will be nhniil. 

3850 feet in length; the feedwater line, kecausc nf 4hat.ter ur.pan~iur~ loops bill 

be about 200 feet shorter, at 3650-feet. Receiver steam output temperature setpoint was assumed to be 1000°F, while the turbine inlet temperature is 950°F. 

Since it is anticipated that temperature swings of as much as pl us or minm 50°F 

could occur in the receiver outlet temperature due to solar insolation transients, 

the receiver steam line was designed for a maximum operating temperature of 1000°F, 

plus 50°F, or 1050°F. The conceptual design includes an attemperator at the outlet end of the steamline to reduce the steam temperature to 950°F during normal 

operation and to lower temperatures during start-up. Feedwater line design temperature was set at 439°F based on a preliminary heat balance. 

Design pressures are determined by thc required throttle pressure 

(1265 psia) and by pressure drops in the steam and feedwater lines; these are 
determined by design flow rates. The following are design pressures that were 

used and corresponding minimum calculated wall thicknesses for the steam piping: 

Design Pressure Wall Thi ckness 

1600 1 .260 

1460 1 .385 

1410 1.625 

These desi gn pressures were based on prel iminary estimates of pipe 1 ength and 

design flow rates; piping cost estimates were obtained from a pipe manufacturer 

based on the calculated wall thicknesses given above. Design pressures based on 

the collector field configuration current at the time of this writing (4289 heliostates) would be as follows: 

Si ze Design Pressure Wall Thickness 

Using these desi gn pressures, a consi derably thi cker wall woul d be requi red for 

the 8-inch pipe and a slightly thicker wall in the 10-inch size. Cost estimates 

were not obtained for these pipe sizes, but it is unlikely that small material 

cost changes would affect the conceptual design recommendation for 10-inch steam 

piping. Main steam pipe size and wall thickness should be re-examined during the 

preliminary or detail design phase when the maximum receiver steam outlet temperature is established and the collector field design and consequently the maximum 

steam flow, is fixed. Design temperature for the main streamline should also be 

re-examined; i f the design temperature coul d be reduced by 50°F or more, then it 

is possible that lighter walled schedule piping could be used with resultant 

savings in cost and delivery time. 

Design pressure for the feedwater 1 ine will be determined by the full speed shutoff head of the receiver feed pump. The pipe specification that was chosen is 

suitable for pressures of up to 2995 psig for temperatures of 500°F or 1.ess. 
(The pipe schedules were XXS for the 6-inch and 8-inch pipe and 160 for the 

10-inch pipe .) Since the cal cul ated receiver pump discharge pressure at maximum 

flow is about 2380 psi wi th the recommended feed and s team1 i nes , the selected 

schedule pipe should have adequate strength. 

Insulation material and instal 1 ationucosts were obtained from contractors' quotes 

and escalated to December 31 , 1978, at 10 percent annually; installation price 

quotes obtained froni the contractors varied widely, so medi um val ues were used. 

The calcium silicate insulation priced was of at least two layers in thickness. 

The costs associated with the heat loss through the piping insulation was based on 

an estimate of the 1981 present worth of fuel (levelized cost) provided by PNM. 

This factor of 99.9 mils per KW-hour was divided by the gross turbine cycle heat 

rate of 9333 GTU/KW-HR to obtain a heat loss cost of .0107 Mils/BTU. The total 

cost of heat lost over the life of the plant was obtained by multiplying the heat 

lost through the insulation in BTU/Hr. by a 30 year plant life operating at a 

capacity factor of 23% and by the cost of .0107 Mils/BTU. 

The heat loss for each combination of steam and feedwater line size and insulation 

thickness was determined using the S tearns-Roger program PIPELOSS. A temperature , 

of 70°F and a wind speed of 10 miles per hour were assumed to represent average 

annual envS ronmental condi tions during the hours of sol ar operation and were the , 

ir~puls used In the program. The heat losses were based on an initial feedwater 

temperature of 439°F (derived from the heat balance) and an initial steam temperature of 1000°F. The flow rate used in the heat loss calcula~tions was 

271,800 pounds per hour, which corresponds to 32.2 MW gross electrical generation. 

The gross electrical output was derived from the annual average radiatz'on 

(100.5 MWth) Sandia Livermore calculated as incident on the receiver based on an 

2 annual average insolation of 950 W/m and a 4289 helinstat receiver field. For 

the plrrpnzPs of heat lo&& and frictinn d~op celculetions, Ltle dvurldyu anrlual 

2 2 insulation was assumed to be 105 percent of 950 W/m or approximately 1 kW/m . The following efficiencies were a1 so assu~lied for the computation : 

0 Receiverabsorptance. 0.95 

Radiation and convection-0.883 
@ Pipint heat loss efficiency-0.996 

a Gross turbine cycle efficiency - 0.3657 

The cost of heat lost over the life of the plant for each combination of pipe 

size and insulation thickness was calculated as the product of the heat loss per 

hour and the cost factor developed from the levelized fuel cost. 

The friction heat loss for each size of pipe was calculated based on the average 

annual flow of 271 ,800 pounds per hour. The cost of pumping across an extra psi 

of friction head loss was determined by first calculating the required horsepower 

(0.47). This calculation was based on an annual average flow of 278,500 pounds 

per hour iricl uding attemperator flow, snd a pump efficiency of 75 percent. Based 

on the assumption that electrical motors require approximately 1 kilowatt per 

horsepower output, the cost per psi was developed as the product of 0.47, the 

number of hours of solar operation during the life of the plant (60,500), the 

level ized cost per kilowatt hour for fuel oil (99.9 mils), and one minus the 

gross turbine cycle efficiency (0.6343). This last factor was applied since 

frictional head loss adds heat to the feedwater, a portion of which is converted 

to electrical output. The resulting cost is $1802 per psi over the life of the 

pl ant. 

The following curves, Fi gures 4.2-8 and 4.2-9, show:. the 1981 present wortti costs 

of materials and installation, heat loss, pressure drop and totals for each combination of pipe size and insulation thickness. 

STEAM PIPING STRESS ANALYSIS 

General Phi 1 osophy 

It was decided to divide the steam line into two systems for analysis purposes 

by introducing an anchor at the north end of the collector field. This would 

prevent forces and moments from this large amount of pipe being transmitted onto 

load-sensi ti ve equipment such as the turbine. 

The system from the central receiver area to the north end of the collector field 

was analyzed, utilizing the vertical run up the tower as flexibility for the 
} TOTAL COST 

ly 

I COST 

7- 

6- 

MATERIAL & 

A 

V) 

INSTALLATION 

K COST 

4 5- 

J 

0 

-0 

In 

- 4- 

+ 

3- 

6" 

A 

HEAT LOSS COST 

2- 

PRESURE 

1 - DROP COST 

8 " 

10" 

v 

INSULATION 4- 6" 8" 

THICKNESS RECOMMENDED 

RECEIVER FEEDWATER LINE COSTS 

Figure 4.2-8. Receiver Feedwater Piping Costs 
J 

2- 

MATERIAL & 

INSTALLATION 

COST 

1- 

HEAT LOSS COST 

PRESSURE 

DROP COST 

1U' 

12" 

VAV 1. I 

INSULATION 4- 6" 8" 

THICKNESS RECOMMENDED 

RECEIVER STEAM LINE COSTS 

. . 

Figure 4.2-9. Receiver Steam Piping Costs 
horizontal run along the rack. This resulted in 370-feet 0-inches of pipe and 

loops in the tower to accommodate 1000-feet 0-inches on the rack, but the movemen t of the pipe at the base of the tower was 98-inches, which woul d provide 

problems for dead weight and seismic supports. Therefore, using the flexibi - 

lity of the piping in the tower was deemed to be unacceptable due to the large 

piping movements at the base of the tower. 

Loops were introduced in conjunction with anchors on the pipe rack, to contain 

and control the movement of the pipe. This resulted in two acceptable 

a1 ternati ves : 

e Loops consisting of 70-feet 0 inches of pipe every 200-feet 

0-inches, but contained with the area of the road 

e Loops consisting of 120-feet 0-inches of pipe every 500-feet 

0-inches , but .penetrating the he1 iostat fie1 d by 25-feet 

0-inches. 

The system from the north end of the collector field to the boiler and turbine 

was analyzed using 1 oops, anchors and gui des to reduce the pipe stress to an 

acceptable level. Due to the low allowable reactions on the turbine, an anchor 

had to be located approximately in line with the turbine and 100 percent cold 

spring employed in .the new sectinn of pipe from this anchor to the contie~Liur~ 

of the existing system. 

De tai 1 ed Phi 1 osou -. ~ -. - .1-3- . 

The system from the central receiver area to the north end of the collector field, 

consists of approximately 2200-feet of s trai gh.t pipe. 

A series of piping stress analysis cnmpluter runs were madc on a number df confi gurations to determine the most acceptable desi gn that woul d accommodate the 

thermal expansion 'loads. These runs and their results are shown below for the. 

piping contained in the overhead pipe rack. 

T-MS-01 -A1 -0 

This run incorporated 95-feet 0-inches of pipe vertically in the tower to provide 

fl exi bi 1 i ty for 570- feet 0-i nches horizontal a1 ong the rack. 
e Maximum Pipe Stress = 55,000 psi 

e Allowable Stress = 18,630 psi 

e Resul tant moment (Tower anchor) = 564,000 ft-1 b 

. This routing is obviously not acceptable and more vertical leg would be required 

for fl exi bi 1 i ty. 

T-MS-01 -A1 -1 

This run incorporated 240-feet 0-inches of loops vertically in the tower, pl us 

1000-feet 0-inches horizontal along the rack. 

Maximum Pipe Stress = 35.000 psi 

Allowable Stress = 18,630 psi 

e Resultant Moment (Tower Anchor) = 365,000 ft-lb 

This routing was not acceptable and still more vertical leg would be required 

for flexibility. 

T-MS-01 -A1 -2 I 

This run incorporated 370-feet 0-inches of loops vertically in the tower, plus 

1000-feet O-inches hori zontal along the rack. 

Maximum Pipe Stress = 17,900 psi 

0 Allowable Stress = 18,630 ,psi 

o Resultant moment (Tower Anchor) = 183,000 ft-1 b 

Assuming the tower can support the moment, this routing is acceptable.' Size of 

the tower, dead weight and seismic support in the tower have not been considered 

at this conceptual stage. Large horizontal moments of 98-inches. 

T-MS-01 -B1 -0 

This analysis represents a different concept in which anchors are located along 

the pipe rack and expansion is taken out by loops in line with the rack. This 
routing represents 1000-feet 0-inches between anchors with a 70-foot 0-inch 

expansion loop located half way between anchors. 

Maximum Pipe Stress = 90,329 psi 

r Allowable Stress = 18,630 psi 

Axi a1 Force at Anchors = 49 800 1 b 

This routing is unacceptable. 

T-MS-01 -C1-0 

This routing incorporates 500-feet 0-inches between anchors with a 70-foot 0-inch 

expansion loop. 

0 Maximum Pipe Stress = 45,270 psi 

Allowable Stress = 18,630 psi 

e Axial Force at Anchors = 25,540 1 b 

This routing is unacceptable. 

T-MS-01-Dl--0 

This routing incorporates 250-feet 0-inches between anchors wi th a 70-foot 0-inch 

expansion loop. 

s Maxliilurri P'ipc! Stress - 22,660 psi 

r Allowable Stress = 18,630 psi 

r Axial Force at Anchors = 12,300 lb 

This routing is unacceptable. 

TLMS-01 -Elm0 

This routing incorporates 200-feet 0-inches between anchors with a 70-foot 0-inch 

expansion loop. 

e Maximum Pipe Stress = 18,140 psi 

0 Allowable Stress = 18,630 psi 
8 Axial Force at Anchors = 9840 lb 

e Resultant,moment at Anchor = 14,170 ft-lb 

This routing is. acceptable. 

T-MS-01- F1-0 

This routing is similar to T-MS-01-C1-0 in that there are 500-feet 0-inches between 

anchors, but the expansion loop is 120-feet 0-inches long. 

Maximum Pipe Stress = 18,600 psi 

e Allowable Stress = 18,630 psi 

6 Axial Force on Anct~ors = 5300 1 b 

This routing was satisfactory and is recommended for this conceptual design and 

Is shown on Figure 4.2-10. 

Similarly, pipe stresses and loads on the turbine were analyzed for the piping 

from the anchor point at the north end of the collector field to the fossil 

boiler and turbine. This analysis included the existing steam piping from the 

fossil boiler which is 100 percent cold sprung. The results of these runs are 

shown be1 ow. 

This run was made with no restraints a"d 100 percent cold spring in existing 

1 i ne only. 

e Maximum Pipe Stress = 41,581 psi 

s Allowable Stress =18,630 psi 

The forces and moments on the turbine are too high. This routing was not acceptable, more flexibility is required. 
STEAM 

TRAP 

FORCES & MOMENTS AT AMCHmS 

Fx 5323 LB. 

My :278 FT. kB. 

21 LB. MZ 20 FT. LB 

RESTRAINED IN Y 81 Z DIRECVIOY 

MAX. STRESS. AT ELL - 18,600 PS 

Figure 4.2-10. Stress Analysis - Main Steam Line 
T-MS-02-A1-1 

This run has a 15-foot 0-inch loop added. 

Maximum Pipe Stress = 39,208 psi 

e Allowable Stress = 18,630 psi 

The forces and moments on the turbine are too high. This run was not acceptabl,e, 

more flexibility is required. 

T-MS-02-A1-2 

This run incorporates two loops with anchors and guides. 

e Maximum Pipe Stress = 65,102 psi 

e Allowable Stress = 18,630 psi 

The forces and moments on the turbine are too. high. This run was not acceptable, 

but high stresses were limited to the loop area. 

T-MS-02-A1-3 

In this run, one anchor was removed to a1 low more flexibility in the loop. 

e Maximum Pipe Stress = 46,786 psi 

e Allowable Stress = 18,630 psi 

The forces and moments on the turbine are too high. This run is not acceptable, 

more flexibility in the loop is required. 

T-MS-02-A1-4 

Another anchor was removed to add flexibility in the loop. 

8 Maximum Pipe Stress = 23,656 psi 

e Allowable Stress = 18,630 psi 

The stresses in this run are acceptable by utilizing the additive thermal, pressure weight and stresses. This configuration is recommended and is shown on^ 

Figure 4.2-11. 
Fi gure 4.2-1 1 . Recommended Confi guration 
T-MS-02-A1-5 

'This run was made with the new section at 70°F and the existing section at 1000°F 

to determine the range of reaction on the turbine and boiler. 

0 Maximum Pipe Stress = 7153 psi 

e Allowable Stress = 18,630 psi 

The turbine forces and moments are too high. This run is not acceptable. 

T-MS-02-A1-6 

This was a run at 1000°F using 100 percent cold spring in the new section of the 

system to the first anchor which is located about the same distance from the wye 

as is the turbine. This run supplies only the forces and moments used to determine the reaction range. The reactions on the first anchors on the rack are very 

high but could be reduced by removing some restraints or adding more pipe. 

T-MS-02-A1- 7 

This was the same as A1-6, except it was run at 70°F to determine the forces and 

moments used to determine the reaction range. The reactions on one of the turbine 

loads was over the allowable limits, but this is the maximum condition as it 

incl udes 100 percent cold spring up to the fi rst anchor on the rack. No a1 lowabl e 

reactions are available for the boiler but the actual reactions appeared to be 

quite low. 

T-MS-02-A1-8 ' 

The system was run at 1000°F and no cold spring to determine the actual stresses. 

0 Maximum Pipe Stress = 9781 psi 

Allowable Stress = 18,630 psi 

The system is acceptable as analyzed. 
FINAL PIPING DESIGN 

Figures 4.2-10 and 4.2-1 1 show the routing of the steam piping as contained in 

the pipe rack and to the interface with the existing steam piping at the turbine. 

The feedwater piping was not analyzed during this conceptual design, since thermal 

stresses and pipe routing is not as severe a problem as for the steam piping. 

The analysis of the feedwater pipingshould be made during the detailed design 

engineering phase of the project. 

A typical pipe routing of the steam and feedwater piping contained in the receiver 

tower is shown on Drawing L-22929, Sheet P4-12. A detailed stress analyzis of 

the riser and downcomer in the receiver tower was not performed, and the rokting 

shown on the Drawing is based on the results of the piping design for the 

commer.cia1 plant at Barstow, central receiver design study. 

Figure 4.2-12 is a summary of the major design parameters as selected for the 

receiver steam and feedwater piping. 

4.2.2 MODIFICATIONS TO EXISTING EQUIPMENT 

This subsection describes modifications to existing equipment in several areas: 

heat balances. code review, piping interface design, equipment and motor listj 

auxiliary power requirements, turbine generator, and general arrangement of 

equ i pmeti t . 

4.2.2.1 HEAT BALANCES 

This section presents the results of the heat balances developed by Stearns-Roger 

for the solar hybrid repowering of Reeves Unit No. 2. The heat balances were 

developed in order to : 

Evaluate alternative cycles as theyaffectcycle heat rates 

0 Predi ct the performance and operating characteristics of the 

recommended conceptual desi gn confi guration 

e Determine duties, pressures, tempera.tures , flow rates, and so 

forth, for cycle equipment and piping in order to facilitate the 

sizing and specification of those items 
Fi gure 4.2-12. SteamIFeedwater Piping Design Summary 

FEED WATER 

3650 

450 

2380 

271800 . 

2 1 

8 

E 

XXS 0.875 

ASTM A106 GR.B. 

CARBON STEEL 

6 

CA. SILICATE 

AL. JACKET 

DESIGN PARAMETER 

9 PIPE LENGTH, FT. 

e TEMPERATURE, OF 

9 PRESSURE, PSI 

0 FLOW,LB/HR I 

e FRICTION LOSS,PSI 

e PIPE DIAMETER, IN. 

@ WALL THICKNESS, IN. 

e PIPE MATERIAL 

INSULATION THICKNESS, IN. 

@ INSULATION MATERIAL 

STEAM 

3850 

1050 

1510 

27 1800 

128 

10 I.D. 

1.425 

P22 (ASTM A335) 

2%% CHR./1% MOLY. 

8 

CA. SILICATE 

AL. JACKET 
CALCULATION PROCEDURES 

The Stearns-Roger computer program D-138 was used to calculate the expected performance and operating characteristics of the proposed cycle. This program uses 

a mu1 tivariable partial differentiad convergence technique in which the turbine 

stage pressures are varied to converge on the turbine stage flow. .Turbine expansion line curves were developed from the turbine Vendor's design heat balances and 

input to the program. Auxiliary cycle equipment performance parameters were. 

obtained from design heat balances or Vendor design information. The following 

design data were used to prepare the input for the heat balance calculations: 

e Figure 4.2-1 3, "Generator Losses Curve ," Westinghouse Electric 

Corp., Curve No. ST-227-b, dated 05/22/58. 

s Figure 4.2-14, "Exhaust and Mechanical Losses Curve ," Westinghouse Electric Corp., Curve No. ST-233, dated 12/1 3/48. 

8 Figures4.2-15 through4.2-19, "TabulationofHeatBalance 

Computations ," Stearns-Roger Manufacturing Co., dated 03/07/57. 

Figures 4.2-20 through 4.2-25 are sketches of six of the calculated heat balances. 

All six heat balances were based on 50 MW gross electrical generation, the low 

pressure Heater No. 5 drain routed 'to the condenser, and two additional high 

pressure heaters provided for solar receiver feedwater heating. Figure 4.2-20 

represents the design maximum solar insol ation condition (noon summer solstice 

2 with 1045 W/m direct normal solar insolation) with 78 percent of the steam 

generated by the solar portion and 22 percent by the fossil boiler. Figure 4.2-22 represents desi gn annual average insol atinn condi tions (approximately 

2 1000 W/m direct normal solar insollation) with 64,5 percent of the steam generated 

b.y the solar portion and 35.5 percent by the fossil hailer. Figure 4-3-21 and 

Fi gures 4.2-23 through 4.2-25 represent arbi trary desi qn points of 75 percent 

solar - 25 percent fossil , 50 percent solar - 50 percent fossil , 25 percent 

solar - 75 percent fossil, and 100 percent fossil, respectively. Figure 4.2-26 

summarizes important parameters at several of those design points plus an addi2 tional design point: 2:00 p.m. Winter solstice, 1045 W/m 'dire~t~normal solar 

insolation, and no fossil boiler firing. 

It was noted that the 100 percent boiler load heat balance predicted a gross 

turbine heat rate of 901 7.3 Btu/kW-hr. Test results . . taken on Reeves Unit No. 2 
GENERATOR LOSSES 

' ASME-AIEE STANDARDIZED 

4400 KW 

TURBINE-GENERATOR UNIT 

3 PHASE - 60 CYCLE 

3600 RPM-.64SCR. -85% P.F. 

HYDROGEN PRESSURE - 30 PSI 

0 10 20 30 40 50 

NET GENERATOR LOAD 

Fi gure 4.2-1 3. Generator Losses 
during the years 1975 through 1977 show a gross turbine heat rate of 9333 Btu/kW. 

hr, more than three percent poorer. It is believed that the Vendor design information is more re1 iable and complete for this case than most field test data, 

especially data obtained using station instrumentation. An exception to this 

rule would be where an ASME PTC-6 test has been conducted using test grade, calibrated instrumentation with full documentation o f a l l test and cycle insolation 

procedures. The difference between the heat rates predicted by the heat balance 

and the test value can be explained by degraded turbine or auxiliary performance 

and/or plant instrumentation error. 

Since the predicted electrical power output contribution for each solar insol a- 

.tion condition was based on the test value of the gross turbine heat rate, it is 

likely that the solar contributions will be slightly higher than those shown for 

the noon summer solstice, 2:00 p.m. Winter solstice, and annual average cases. 

EFFECT ON HEAT RATE OF ROUTING OF DRAINS 

It is recommended that the Low Pressure Heater No. 5 drains be cascaded to the 

condenser s:o that the water can be passed through the condensate pol isher. At 

present, the No. 5 Heater drains are pumped into the condensate pipe just upstream 

of the No. 4 Heater to utilize the heat content. It was desired to determine 

how much the heat rate woul d be degraded by cascading the drains to the condenser. 

A base case with 100 percent fossil boiler steam and the No. 5 Heater dralns 

pumped ahead was therefore run; the resul ting gross turbine heat rate was 

8997.8 BtuIkW-hr. Compared to the equivalent heat rate with the drains cascaded, 

9017.3 BtulkW-hr, the difference is 19.50 BtuIkW-hr, or about 0.2 percent. 

EFFECT OF DELETING THE NO. 6 AND NO. 7 HIGH PRESSURE HEATERS 

It is recommended that two new high-pressure heaters be installed to heat the 

receiver feedwater. An investiqation of the effect on the heat rate of not 

employing new high pressure feedwater heaters was made. Following is a summary 

of that study. 
- It was assumed that a 50 MW gross generator output was to be maintained. With 

4289 he1 iostats (38 square meters/hel iostat) employed, it was calculated that 

the annual average power generation contribution from the solar portion would 

be about 32 MWe. 

I Two heat balances were made: the first included the two proposed feedwater 

1 heaters; the second d,i d not incl ude high pressure heaters for the receiver 

feedwater. Steam output from the fossil boiler was held constant for both cases 

implying the same fuel oil flow and fuel cost for either case. . 

The steam flow to the turbine, and therefore the requirement from the solar 

receiver, since fossil boiler flow was held constant, was reduced when the 

receiver high pressure heaters were deleted. This was due to a higher loading 

in the low pressure stages of the turbine because of less extraction steam flow 

for feedwater heating. However, the duty on the solar receiver* portion was 

8 8 i,ncreased (2.987 by 10 Btu/hr versus 2.913 by 10 ) due to an increased temperature di fference between feedwater and receiver steam if high pressure heaters 

are not used. This is a difference in receiver duty of 2.54 percent. 

An additional 109 heliostats (2.54 percent of 4289) would be required to maintain 50 MWe output without increasing the boiler firing. Using. a collector cost 

of $250 per square meter, the additional collector cost would be about 

$1.036 million. The cost estimate for H.P. Heaters No. 6 and 7 is $125,000 with 

an addi tional $30,000 requi red for instal 1 ation ; the estimated instal led cost is 

$155,000 or $0.155 million. The employment of H.P. tfeaters is therefore shown 

to bc cost e fTec'L,i ve . 
DISTRIBUTION: 

HEAT BALANCE COMPUTATIONS 

FOR 

PUBLIC SERVICE COMPANY OF NEW MEXICO 

REEVES STATION 

UNIT 52 

ALBUQUERQUE, NEW MEXICO 

ORDER NO. 9-12500 

BY 

THE STEARNS-ROGER MANUFACTURING CO. 

DLNVER,COLQRADO 

LHG LSMP 

RER (4) 

JSG 

CJ E 

WMH 

REVISION DATE 
ASME-AIEE STANDARDIZED 

40,000 KW 

TURBINE-GENERATOR UNIT 

1250 PSlG - 950°FTT - 1.5 IN. EG. AES. 

TOTAL EXHAUST FLOW - 1000 LB/HR 

Fi gure 4.2-1 4. Exhaust and Mechani cal Losses 
TABULATION OF HEAT BALANCE COMPUTATIONS 

FROM 

PUBLIC SERVICE COMPANY OF NEW MEXICO 

ALBUQUERQUE, NEW MEXICO 

REEVES STATION, UNIT NO. 2 

Job N0.B-12500 

Complied by JSG 

GENERAL INFORMATION Date 3/7/57 

Page 1 of 5 

Turbine Generator 

44,000 KW ASME-AIEE Preferred Standard .Turbine Generator Unit 

1250 PSIG, 9500 FTT Steam Conditions at Turbine Throttle 

1 - 112" HG Abs. Exhaust Pressure 

5 Heater Cycle 

47,058 KVA Generator, 0.85 PF at 1/2" PSIG H2 Pressure 

13,800 volts, 3 phase, 60 cycle 

Steam Generator 

Pressurized Type, 425,000 LB/HR Maximum Continuous Rating 

1280 PSIG, 955" FTT at Superheater Outlet 

8,344 sq. ft. Total Effective Heating Surface 

250,000 LBIH R Anemperation Point 

Regenerative Type Air Heater 

Fuel 

Base - Natural Gas with 1,000 BTUiCU. FT. Heat Value at 14 PSIG - 60" F. 

S~dt.ldby -Fucl Oili 27 + Gravity. 19,100 BTUI* Heat Value 

Surface Type, 35,000 sq. ft., Non-divided Wotcr Box, Twr.1 PASS 

HEAT BALANCE DIAGRAM 

TURBINE 

Fi gure 4.2-15. Tabu1 ation of Heat Balance Computations 
THE STEARNS-ROGER MANUFACTURING CO 

DENVER,COLORADO 

Page 2 of 5 

Date 3/7/57 

Rev. 1 3/28/57 

Job 0-1 2500 

BY 

Rev. 2 811 5/58 

HEAT BALANCE TASULATION 

FOR 

PUBLIC SERVICE COMPANY OF NEW MEXICO1 

REEVES STATION UNIT #2 

ALBUQUERQUE, NEW MEXICO 

44,000 KW PREF-ST0 TURBINE GENERATOR UNIT 

1250 PSIG 950" F.T.T. 1 - 112" HG. ABS. 

DIAGRAM A - EVAPORATOR IN SERVICE 

GENERATOR OUTPUT ,' 

STATION AUX. POWER 

NET SALE ABLE POWER 

TURBINE DATA: 

THR.3TTLE FLOW 

THRDTTLE PRESSURE 

THROTTLE TEMPERATURE 

TH ROTTL: ENTHALPY 

FIRST EXTRACTION STEAM: 

F L9W 

PRESSURE 

TEMPERATURE 

ENTHALPY 

SECOND EXTRACTION STEAM: 

F LOVJ 

PRESSURE 

TEMFERATURE 

ENTHALPY 

THIRD EXTRACTION STEAM: 

FLOW 

PRESSURE 

TEl'tlPERATURE 

ENTHALPY 

FOU!{'rI I CXTt1ACTION STEAM: 

FLOW 

PRESSURE 

TCMPEI\ATURE 

ENTH4LPY 

#/H R 

PSlG 

" F 

B/# 

#/H R 

PSlA 

" F 

BTU/# 

Figure 4.2-16. Heat Balance Tabu1 ation 
DIAGRAM A - EVAPORATOR IN SERVICE [CONT'D.) Page'3 of 5 

Rev. 1 3/28/57 

FIFTH EXTRACTION STEAM: 

FLOW #/kR 4,584 6,573 13.1 73 

PRESSURE PS 1 .A 2.1 3.6 5.3 

TEMPERATURE " F 128 149 165 

ENTHALPY BTW/# 1,065.5 1,054.9 1,06 1.2 

TUR8lNE EXHAUST: 

TURBINE EXHAUST FLOW 

TURBINE EXHAUST PRESSURE 

TURBINE EXHAUST ENTHALPY 

TURBINE EXHAUST 

TEMPERATURE 

TURBINE & CCND. AUXILIARY: ' 

SJAP STE9M FLOW 

CONDENSER TEMP. IN 

CONDENSER TEMP. OUT 

NO. 5 L.P. HEATER: 

SHELL PRESSURE 

SHELL TEMPERATURE 

HEATER DRAIN TEMP. 

HEATER DRAIN FLOW 

CONDENSATE FLOW 

CONDENSATE TEMP. IN 

CONDENSATE TEMP. OUT 

NO. 4 L P. HEPTE.3: 

SHELL PRESSURE 

SHELL TEMPERATURE 

HEATER DRAIN TEMP. 

HEATER DRAIN FLOW 

CONDENSATE FLOW 

CONDENSATE TEMP. IN 

CONDENSATE TEMP. OUT 

DEAE RATOR: 

SHELL PFESSURE 

SHELL TEMPERATURE 

CONDENjATE FLOW IN 

CONDENSATE TEMP. IN 

H. P. HEP.TER DRAIN FLOW IN 

H. P. HEP.TER DRAIN TEMP. IN 

EVAPORATOR VAPOR FLCW IN 

E'JAPORATOR DRAIN FLOW IN 

PSI A 

" F 

" F 

#/M R 

#/H R 

" F 

" F 

'! ,674 11/tiFI tlriviny stcam fron 2nd extraction. 

Figure 4.2-1 7. Diagram A (Continued) 
DIAGRAM A - EVAPORATOR IN SERVICE (CONT'D.) Page 4 of 5 

Rev. 1 8/15/58 

DEAEEATO? (Cont'd.) 

EVAPOqATOR DRAIN TEMP. IN OF 261 .0 303.0 331.1 356.4 362.9 367.2 

FEEDWATER FLOW OUT #/H R 92,400 184,200 276,000 383,100 413,700 434,100 

FEEDWATER TEMP. OUT "F 213.7 246.4 269.8 289.9 295.1 298.5 

EVA?O RAT13 R : 

STEAM FLOW 

SHELLBRESSURE 

SHELLTEMPERATURE 

\'.4PO R FLOW OUT 

MAKEUP FLOW IN 

MAKEUP TEMP. IN 

D'RAINI FLOW OUT 

DRAIN TEMP. OUT 

NO. 2 H.P. HEATER: 

STEAV FLOW 

SHELL PRESSURE 

SHELL TEMPERATURE 

HEATER DRAlN TEMP. 

HEATER DRAlN FLOW 

FEEDVlATER FLOW 

FEEDWATER TEMP. IN 

FEEDWATER TEMP. OUT 

NO. 1 H.P. HEATER: 

SHELL PRESSURE 

SHELL TEMPERATURE 

HEATER DRAlN TEMP. 

HEAT'ER DRAlN FLOW 

FEEDVJATER FLOW 

FEEDWATER TEMP. IN 

FEEDWATER TEMP. OUT 

BOILER: 

MAIN STEAM FLOW 

MAIN STEAM PRESS. 

MAIN STEAM TEMP. 

WAIN STEAM ENTHALPY 

BLOhDOWN FLOW 

0 LOKDOWN EN'THALPY 

#/H R 

PSIA 

"F 

#/H R 

#/H R 

OF 

#/H R 

OF 

#/H R 

PSlP 

OF 

OF 

#/H R 

#/H R 

OF 

OF 

PSlA 

OF 

OF 

#/H R 

#/H R 

OF 

OF 

#/H 3 

PSIA 

OF 

BTU/# 

#/H R 

BTU/rrY 

Fi gure 4.2-1 8. Diagram A (Con ti nued) 
DIAGRAM A - EV4PCRATOR IN SERVICE (CONT'D.) Page 5 of 5 

Rev. 1 811 5/58 

- 

BOl LE H (Cont'd.) 

FEEDWATEF: FLOW 

FEEDWATEF: TEMP. 

FEEDWATEF ENTHALPY 

BOILER EFFICIENCY 

TOTAL HEA- FI3ED 

GAS FIRED 

HT. OUTPUT OF BLR 

PLArJT PERFORMANCE 

'THROTTLE F LOWIKW GROSS 8.35 8.20 8.16 8.36 8.46 8.52 

CONDENSER F LOWIKW GROSS 7.24 6.27 6.00 5.91 5.90 5.91 

CYCLE HEAT RATE (GROSS) BTUJK'IVH 10,574 9,3 24 8,978 8,881 8,883 8,897 

,?LANT HEAT RATE (NET) BTUIW 15,654 12,235 11,411 11,179 11,172 11,183 

Oh 22,058 38,190 53,741 73,591 79,399 83,220 

Figure 3.2-19.. Diagram A (Continued) 
Figure 4.2-20. Heat Balance Diajram 
Figure r.2-21. Heat Balance Diagram 

- 

Figure 4.2-23. Feat Balance Diagram 
j a~n6~ *bz-z*b 3eaH leg a~ue we~Ce&a 

Figure 4.2-26. T/G System Performnce 

I 

I PARAMETER 

DESIGN POINT 

GROSS MWe 

[ 

1OO%SOLAR 

ONLY 

WINTER 

SOLSTICE 

2:00 PM 

31.1 

9067 

2537 10 

1265 

9 50 

0 

1265 

250083 

985 

GROSS TURBINE HEAT RATE BTUIKW-HR 

THROTTLE CONDITIONS 

FLOW, LB/HR 

PRESSURE, PSlA 

TEMPERATURE, OF 

FOSSIL BOILER CONDITIONS 

FLOW, LBIHR 

PRESSURE, PSlA 

TEMPERATURE, OF 

RECEIVER ATTEMPERATOR INLET 

FLOW LIBIHR 

TEMPERATURE, OF 

I 

50% FOSSl L 

50% SOLAR 

50 

9020 

427022 

1265 ' 

950 

21321 1 

1265 

950 

210312 

9847 

22% FOSSl L 

78% SOLAR 

SUMMER 

SOLSTICE 

50 1 

9001 

42721 2 

1265 

950 

93519 

1 265 

840 

3321 38 

987 

100% 

FOSSIL 

50 

901 7 

428561 

1265 

. 950 

428561 

1265 

950 

0 

0 

L 

. 25% FOSSl L 

75% SOLAR 

50 

900 1 

427183 

1265 

95 0 

106346 

1265 

862 

3 14030 

35.5%FOSSI L 

64.5%SOLAR 

ANNUAL 

AVERAGE 

50 

8994 

42643 1 

1265 

950 

150996 

1265 

940 

270639 

986 
4.2.2.2 CODE REVIEW 

The mechanical conceptual design for the solar repowering of Reeves Unit No. 2 

was reviewed on the basis of the appl i cable desi gn codes and standards. The 

codes that apply are: 

ASME Boiler and Pressure Vessel Code, Section I, Part PG-58 

ANSI 831.1, Power Piping Section 122 (Design Requirements Pertaining to Specific Piping Systems), Bailer External Piping 

The code sections that apply to the solar repowering of Reeves Unit No. 2 deal 

with two boiler applications, where the main steam lines are cross connected. 

Cross connecting two boilers such as is required for this solar repowering 

appl ication requires that double isolation valves be instal led at the interface 

points within the area of code jurisdiction. 

Drawing L-22929 Sheets P3-1 and P3-6 show the ASME CodelANSI B31 .1 interfgces. 

On Sheet P3-1 a potential code problem exists with the interfacing of the 

receiver steam line with the existing steam line from the oil-fired boiler. 

The second isolation valve on the oil-fi red boiler, MOV-1-1 ,, can be lvcated in 

two di fferent places as indicated below; the advantages and disadvantages of 

these 1 ocations are di scl.~ssed. 

(a) MOV-1-1 could be located immediately upstream of the interface 

wi 111 the recelver steam piping, in the existing steam pipe from 

Ltie u'il -fired boiler. 

The principal advantage of this location is that during periods 

of solar system only operation, the steam piping between MOV-1-1 

and the oil-fired boiler would bc free of stear11 and could be 

drained dry. 

The problem with this location is that the main steam line from 

the oil -fi red boiler to the outlet of MOV-1-1 would then fall 

under the jurisdiction of the ASMF Code and would require inspection and code stamping. Since this steam piping is approximately 

20 years ol J, the code would require that a complete check of 

the metallurgical and fabrication records be made of this piping 

with the possibility present that this steam piping may have to 

be replaced if the piping material has been derated by the ASME. 
There is a possibility that oxygen could a1 so be introduced into 

this piping resulting in corrosion products if the blowdown valve 

located between the two isolation valves is left open. This 

valve woul d be open i f maintenance work is performed on the oil - 

fired boiler during turbine operation on solar receiver steam. 

(b) MOV-1-1 could be located at the oil-fired boiler superheater outlet adjacent to the existing boiler block val ve. 

This location of MOV-1-1 would move the ASME Section I code 

jurisdiction back to the oil-fired boiler superheater out1,et and 

would remove the existing steam line from ASME code requirement. 

If this location for MOV-1-1 is used, for conditions of solar 

only operation, the length of steam line to the oil-fired boiler 

woul d contain dead steam wi th some probable condensation in the 

line. This should not cause a corrosion problem since the feedwater has been treated to remove oxygen. During overnight shut 

down of the plant with no fossil fuel boiler firing, air would 

most likely enter into this section of pipe and present a potenti a1 corrosion problem. I t is recommended, therefore, that during the initiation of startup of the solar receiver steam generator in the morning, this section of steam line should be blown. 

out through the vent line shown on flow diagram Sheet P3-1. 

This should remove any corrosion products and air that may be in 

the line. 

The recommended location for MOV-1-1 is i tern (b) above, which is locating the 

valve at the superheater outlet of the oil-fired boiler. Sheet P3-1 shows this 

location and the limits of ASME Section I code jurisdiction. 

A drain pot that incl udes a 1 eve1 control val ve and level switches connected to 

the turbine water induction protection system will be installed in the low point 

of the existing steam line from the fossil boiler superheater outlet to the 

interface with the receiver steam 1 ine. The purpose of this drain pot is to 

collect condensate formed in this section of piping during solar-only operation. 

This condensate will be drained to the condenser. This drain pot is shown on 

flow diagram Sheet P3-1 . 

Sheet P3-6 shows the code 1 imi ts at the out1 et of the receiver with a free blow 

to atmosphere located between the two isolation valves. This free blow line 

could also be used to warm up the receiver steam line using oil-fired boiler 

steam. 
It is also recommended that the location of valve MOV-1-1 be studied further 

during the detailed design phase, and the feasibility of ASME coding the existing steam piping should be investigated. 

4.2.2.3 PIPING INTERFACE DESIGN 

The new pi ping for the solar portion of the project wi 11 be interconnected with 

the existing Unit No. 2 piping as both the boilers (Fossil and Solar) will 

del iver steam to the existing turbine/generator. These interconnection points 

are shown on the P4 Series Drawings where the existing plant piping and facil ities have been shown in light tones and the new items shown in bolder tones. 

The same technique of fading the original drawing data and darkening the new 

information has been used on the P and I Diagrams on the P3 Series Drawings. 

Thus, any interface between existing and new piping can be located on either a 

piping detail drawing or a P and I Diagram. 

4.2.2.4 EQUIPMENT AND MOTOR LIST 

This section descri bes in tabul ar form the additional equipment required for 

repowering the Reeves Unit 2 Station. Table 4.2-9 shows the equipment list 

developed for this conceptual desi gn and incl udes mechanical equipment, water 

treating equipment and solar system equipment. Table 4.2-10 is the motor list 

that tabul ates horsepower and vol tage requi remen ts for the requi red equi pmen t. 

These llsts are not total plant equipment or motor lists, but are lists of additional required equipment for the Reeves Unit. 

4.2.2.5 AUXILIARY POWER REQUIREMENTS 

This section defines the auxil iary power requirements for the solar rcpowcrcd 

Reeves Unit No. 2. Table 4.2-11 shows the additional equipment power required 

for the solar repowering along with an estimated equipment load factor to account 

for the noncontinuous use of some of the equipment. The table alsn shows the 

auxiliary power requirement as it now exists for the Reeves Unit No. 2 so that 

a total auxiliary power requirement for the repowered plant can be defined. 

The existing Reeves Unit No. 2 auxiliary power of 5.5 percent of gross is based 

on an interpretation of existing plant test data. 
TABLE 4.2-9. EQUIPMENT LIST (1 of 2) 

EQU I PPIENT 

I MECHANICAL EQUIPMENT 

(1 ) Recei ver Feed Pumps 

(2) Variable Speed Coup1 - 

ings 

(3) No. 6 Receiver Feed 

Water Heater 

(4) No. 7 'Receiver Feed 

water heater 

(5) Receiver Steam Attem- Yarway, 33000 Lb/Hr. , 10000~ 

perator down to 400'~ Min. 

(6) Receiver Steam 

Moisture separator 

(7) Receiver steam piping 

drain pots & level 

controls 

(8) Condensate Hotwell 60% capacity, 353 GPM, TDH = 

Pumps 422 Ft. 1760 RPMy 60HP Motor. 

(9) High Qua1 i ty Sump Pumps 100% Capacity, duplex, 20 GPM, 

V50 Ft. TDH = 50 Ft. 

(10) Low Qua1 ity Sump Pumps 100% capacity, duplex, 20 GPM, 

TDH = 50 Ft. 

(11) Acid Sump Pump 100% Capacity , Submersi bl e 

(12) Caustic Sump Pump 100% Capacity, Submersi ble 

(1 3) Emergency Diesel 1600 KVA, 80% P. F. , 240 V. 

Generator 

QUANTITY 

2 

2 

1 

1 

DESCRIPTION 

100% Capacity, 740 GPM, TDH = 

5800FT. Var. Sp.,2000HP Motor. 

American Std., Type vs, Class6, Size 171A 

She1 1 & Tube Type, Monel , Desup. , Condensing, Sub cooling 

sections 

She1 1 & Tube Type, Monel , Desup, Condensing, Sub Cooling 

Sections 
TABLE 4.2-9. EQUIPMENT LIST (2 of 2) 

. EQUIPMENT 

I I WATER TREATMENT EQUIP . 

(1 ) Demineral izer 

(2) Condensate Pol i sher 

(3) Acid Tank 

(4) Caustic Tank 

(5) Acid Feed Pumps 

(6) Caustic teed Pumps 

(7) Ammonia Feed Systcm 

(8) Sample panel 

(9) Cation feed pumps 

I11 SOLAR SYSTEM EQUIPMENT 

- 

(1 ) Col 1 ectors 

(2) Receiver Assembly 

QUANTITY 

1 

2 

1 

1 

2 

2 

1 

1 

4289 

1 

DESCRIPTION 

TWO TRAIN, 3-BED, 376 PM/ 

Train complete with controls 

& Control Panel 

100% capacity Each, 706 GPM, 

including regeneration tanks 

& controls 

5000 Gal. , 66' Be' Sulfuric 

Acid 

5000 Gal, sodium hydroxide 

100% Cap. , positive displ . 

100% Cap., positive displ. 

1 -~UIII~, rni x4ng tank, 

measuring tank 

Compl ete with valves , control s, 

sample cool ers , etc. 

2-100% capacity, each pump 

40 GPM, TDH = 175 Ft. , 3 HP 

2 38 m Each, McDonnell nouqlas 

Includes receiver, flash tank 

2nd controls. Rocketdyne once 

through boiler , external 

receiver I 
DISTRIBUTION: 

MOTOR LIST 

ORDER NO. C-20266 

CUSTOMER PUBLIC SERVICE CO. OF NEW MEXICO 

ISSUE : 

A 

A 

A 

A 

A 

DATE : 
I ORDER NO. C-207.66 MITOR L I'ST PAGE 1 OF 2 I 

TAGLE 4.2-10. MOTOR LIST (1 of 2) 

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- 

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dzg 

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4E0/3!60 

- 

4€.0/3/60 

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4-60/3/60 

4611/3/60 

46;/3/60 

443/3/60 

463/3/60 

463/3/60 

4i3/ 3/60 

460/3/60 

43/3/60 

43/3/60 

4€Qi3/60 

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w 

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Rep1 acements for 

Existing Pumps 

Rep1 acements for 

Existing Pumps 

-- 

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3 

j 1/2 

j 1/2 

1/2 

1/2 

1 /2 

1 /2 

1 /2 

1 /2 

Z 5 E* znv v, 

W 

a 

Condensate Hatwell 

Pump - 2A 

Condensate Hctwell 

Pumo - 28 

Receiver Feec Puml: 2A 

Receiver Feec' Pump 2B 

Pump LA 

Cation Feed Water 

Pump ZB 

Cation Fccd \later 

Pump LA 

Cemineral izer Acid Fee 

r ~117prz-r 

Deminfral izer- Acid Fee 

-eed Pump LA 

Demineral izer Caustic 

--cWPu111p ZIJ 

Demineralizer Caustic 

Acid reed Pump ZA 

Condensat? Polisher 

HCI~ keea rump LB 

Condensate Polisher 

~aust~c reeg rump LA 

Condensate Polisher 

Caustic keel rump zb 

Condensate Poll isher 

;I& 

1800 

1800 

3600 

3600 

1800 

1.300 

TABLE 4.2-11. AUXILIARY POWER REQUIREMENTS (1 of 2) 

REEVES UNIT 2 SOLAR REPOWERING 

Additional Solar System Equipment 

Net 

EOU I PMENT Gross Power, Estimated Aux. Power, 

Watts Load Factor Watts 

1. Rece iver feed pump, one 

full capacity pump (1512 hp) 1,128,000 1.0 1,128,OO 

2. Heliostats 4200 heliostats 

steady state usage 14 W/helio. 58,800 1.0 58,800 

3. Demineralizer cation feed pump 

one full capacity pump (3 hp) 2,237 0.25 

4. Demineralizer acid feed pump 

(1/2 hp) 373 0.25 93 

5. Demineralizer caustic feed 

pump (112 hp) 373 0.25 

6. Condensate polisher acid feed 

Pump (112 hp) 373 0.25 93 

7. Condensate Polisher caustic 

feed pump (i/2 t~p) 37 3 0.25 

8. Amnonia feed pump (1/2 hp) 373 1.0 373 

9. Low quality sump pump 

(1/2 hp) 

10. High quality sump pump 

(1/2 hp) 

Tot a1 Sol ar Sys tems 

Equipment Aux. Power = 
TABLE 4.2-11. AUXILIARY POWER REQUIREMENTS (2 of 2) 

Gross Electrical Output 50 MW 

Existing Plant 4ux. Power (50 MW x 5.5%)* (2.75 MW) 

Additional Power Requirement for Solar 

Equipnent (1.19 MW) 

Net Plant Output 46.06 MW 

Aux. Power as a % of Gross Outpu't 7.9% 

*Test data average 
4.2.2.6 TURBINE GENERATOR 

Reeves Unit No. 2 is a Westinghouse 44 MW capacity, two-casing, tandem, 3600 rpm, 

double flow, AIEE-ASME preferred standard turbine designed for operating steam 

conditions of 1250 psig, 950°F and 1.5 in-Hg-abs exhaust pressure. The turbine 

is guaranteed for 44 MWe with rated steam inlet conditions with 3.5 in-Hg-abs 

exhaust pressure, five stages of feedwater heating and three percent makeup. 

The Reeves Unit No. 2 has two combination stop and throttle valves, one mounted 

on each side of the steam chest that includes the following: 

s Provision for testing each throttle valve while uni,t ,is ir~ 

operation .. 

Solenoid trip device for remotely tripping throttle valves and 

closing control val ves 

e Two signal switches on each throttle valve for remote indication of throttle valve position 

Signal switch on each throttle valve, which connected in series, 

will trip the main circuit breaker when both throttle valves are 

closed 

e Removable steam strainer for each throttle valve body 

A separate over-speed governor will trip the throttle valve in the event of 

10 percent over-speed and a pro;,lsion is i'ncl uded to test the over-speed .lr.ip 

while it is operating without over-speeding or tripping the turbine. The 

steam chest is integral with cylinder cover containing mu1 tiple governor control va.lves. 

A hydraulically operated governing system controls the position of the governor 

control valves. The system has adequate response to prevent over-speed trip in 

the event of a sudden loss of load. The speed regulation is two percent for a 

gradual change in load equal to ha1 f the unit rating. The system is provided 

with a hand-operated steam flow limit device. The speed changer is suitable 

for hand and motor operation; speed changer range is plus or minus five percent 

of rated speed. 
The complete oil system contains an oil reservoir, main oil pump mounted on 

turbine shaft, twin oil coolers, auxiliary oil pumps mounted on oil reservoir, 

and vapor extractor mounted on oil reservoir. 

The thrust bearing is a pivoted shoe-type. Two thermometers are mounted on the 

exhaust hood. The turning gear is 'motor operated. 

Tripping devices are provided for low vacuum and excessive thrust loading. 

Exhaust re1 ief diaphragms are provided in exhaust hoods. 

The Reeves Unit No. 2 performance specification is summarized as follows: . 

The heat consumption, when operating under design conditions, will not exceed 

the quantities specified below. These quantities include steam used and consumed by the turbine, and losses in the generator, incl uding energy required in 

the fie1 d for excitation, and the losses of the exciters. 

kW P- f Heat Rate (BtuIkWh) 

44,000 0.935 8,955 

40,000 0.85 8,964 

30,000 0.85 9,095 

20,000 0.85 9,485 

10,000 0.85 10,618 

The unit has been operated as a base-loaded unit except at night and during the 

noon hour. 

The following repai rs were made during an outage of April 1971 : , 

e Lower pressure blades were modi fied to incl ude stelli te strips 

e Cracks on the high pressure outer casing and main steam connections at horizontal joint were welded 

IB -Magnaflux test performed on the bottom half of low pressure blade 

ring - found no defects 

e Cracks in nozzle chamber were removed by grinding 
One small surface crack from shroud of Row #28 was removed 

The high pressure rotor expansion groove near control stage was 

machined 

PNM plans to modify this unit for cyclic operation in preparation for planned 

intermediate dispatching in 1980. A1T major turbine components will be investigated and upgraded where appropriate .as recommended by the manufacturer for 

optimum thermal cycl ing durabil i ty. PNM plant engineering and operational 

personnel .are continuing to assess requi red modi fi cations and wi 11 complete 

these actions by the end of calendar year 1979. 

4.2.2.7 GENERAL ARRANGEMENT - EPGS 

The additional equipment required for the solar repowering excl uding the receiver 

and heliostats is to be located indoors. The west side of the existing building 

offered the best location for a new building addition at the interface of the 

existing Units No. 1 and 2. This location also offers the most convenient access 

to the existing piping interface points, thereby minimizing the length of new 

pipe runs. The arrangement for this is shown on Drawing L-22929 Sheets GI-1, 

GI-2 and 61-3. 

Consideration was given to locating the new equipment in the existing building. 

This has two major disadvantages: 

Unit No. 2 would have to be completely shut down during the 

entire construction period i f the work were to be done in and 

around the operating equipment, thereby placing addi tional load 

on the PNM system. Construction work can continue while Unit 

No. 2 is operating by constructing a separate building. When 

the new construction is ready, the existing equipment would be 

shut down on a schedule that would minimize operating downtime. 

0 Because of space limitations in the existing building, a much 

less functional equipm~nt layout would resul l, tl~ereby incrcasing operation and maintenance costs over the life of the 

equi pmen t. 

Within the new building addition, there are three levels. In general, equipment 

has been located on the same level as the original equipment was located in the 

existing building. This to further take advantage of the original plant equipment layout. 
GROUND FLOOR 

All water treating equipment is located on the ground floor - the full flow 

Condensate Pol ishers are located close to the Hotwell Pumps, so that pi pint 

runs are minimi zed. 

The Acid and Caustic Storage area is on the outside wall , furthest from the 

existing building, to minimize potential problems in case of leaks and to 

facilitate loading of the tanks. Each tank is located in a separate 6-foot 

high lined concrete enclosure that contains the 1 iquid in case of a tank rupture. The enclosures have indi vi dual sumps with pump-out connections for 

emergency use of portable submersible chemical pumps. Acid fill connections 

penetratc thc west wall bu that raiiker fi l'l hoses remain outside of the buildi.ng. It is planned that tank loading will use air pressure on the supply tanks 

to transport the acid and caustic. A freeze-proof combination eyewash and 

safety shower is located outside within 25 feet of the fill connections (OSHA' 

requi remen ts) . 

All acid and caustic pumps are enclosed by an 8-inch high curb to contain leakage. Equipment drains go to either the high or low quality sumps. High quality 

water from the Condensate Polisher, the demineralizers and the cooling water 

drains from the Receiver Feed Pumps will be piped to the high quality sump and 

from there to a .suitable holding basin for possible reuse. All other drainage 

passes into the 1 ined trench and flows by gravity to the 1 ow qua1 i ty sump for 

disposal in an evaporation pond located west of the plant. Space is avilable 

in the northeast corner of the building addition for a future Condensate 

Polisher for Unit No. 1 should the need arise. 

Solar Receiver Feed Pumps No. 2A and 2B are located close to the existing building wall where the length of the suction lines from the connection points near 

the llnit No. 2 Roilcr Feed Pullips w'ill be minimized. 2400-volt power to these 

pumps will come from the new switchgear located on the operating floor. Space 

is allocated for a third receiver feed pump for future repowering of Unit No. 1. 

A new ammonia feed pu111p and storage tank will be located in the existing chemical 

feed treating area in order to keep all of the chemical treating equipment 

together. 
Existing Hotwell Pumps No. 2A and 2B will be replaced with higher pressure units 

requiring deeper sumps a1 though the locations will be 'the same. The existing 

piping will be modified as needed to connect to the new pumps. 

480-vol t ac Motor Control Center MCC-2A and its associated load center will house 

the control s and starters for the smaf 1 pumps and a1 1 other new equi pmen t in the 

general building area, except the Receiver Feed Pumps which will be fed from the 

new swi tchgear. 

MEZZANINE FLOOR 

Much of the mezzanine area will contain cable trays for power and computer 

applications. Main power cable will connect to and from th~: switchgear located 

on the Operating Floor. Computer interconnecting cable and input data leads 

wi 1 1 be run on thi s 1 eve1 be1 ow the Computer and Logic Rooms. 

A battery room and Uninterruptible Power Supply (UPS) will also be located on 

this level in order to keep them close to the Computer and Logic Rooms. 

An additional Emergency Diesel Generator will be located in the north east 

corner of the existing building immediately adjacent to the existing dlesel 

generator unit. Space is available in this area that will be walled off from 

the remainder of the existlng bu.ildirsy. 

OPERATING FLOOR 

The operating floor level of the solar equipment buil ding addi ti6rI conta'irls Ll~e 

computers and their associated software. In the Computer Room are the Master 

Control System computer, the Collector computer, the Analog/Dl gl tal rrrul li pl exing equipment, the consol es for programming and engineering, and the printing 

and recording equl pmer~ 1. The Log1 c Room cull Ldins: the vorio~rs control s.ystern 

hardware. This equipment is interconnected to the new Solar Systems Master 

Control Console and data display panels located in the existing Station Control 

RUUIII. Because of thc 1 imited space available in the Control Room only operating control equipment can be placed there. 
,-) The new Swi tchgear was located on the operating floor above the mezzanine level 

to allow ample room for cable trays and cable spreading underneath. The Switchgear layout is sized to allow feeds for the two new Receiver Feed Pumps, the 

power supply to the collector fie1 d, the feeder for MCC-2A and its load center 

and a future supply to Unit No. 1 should it be repowered. 

The computer and logic rooms will be protected from fire by Halon 1301 flooding 

systems whose manifolds and cylinders will be located on the operating floor . 

just outside each room. These two rooms will be the only new areas that are 

air conditioned. 

Space is available due to the removal of the evaporator and associated piping in 

the existing Unit No. 2 area for new Feedwater Heaters No. 6 and No. 7. This 

location is immediately adjacent to the turbine that is the source of the extraction steam used for heating the feedwater. 

ROOF 

All air handling equipment for the new building addition will be roof mounted. 

This is an ideal location because all levels require heat and ventilation. 

Supply and return ductwork will extend from the heating. and ventilating units 

on the roof, through the operating floor and mezzanine levels to the ground 

floor. 

Exhaust fans will be roof-mounted with exhaust air being picked up at all three 

1 eve1 s. 

The roof mounted air conditioning unit located directly over the computer and 

logic rooms will supply cooled air to those rooms and will take its return air 

from the same area. 

4.2.3 FACILITIES REVIEW 

4.2.3.1 WATER TREATMENT 

Solar repowering of a fossil-fueled power plant presents some special water 

treatment problems because thc sol ;lr powcrcd portion of the systeni wi 11 cycle 
daily (much as in a peaking unit) and the solar boiler in this case will be a 

once-through design and have small-diameter boiler tubes. A unit subject to 

daily startups and shutdowns is more susceptible to corrosion and deposition than 

one that is continuously operated. 

MAKEUP WATER 

The makeup water for the plant is currently taken from existing wells. One water 

analysis has been provided for each of the two wells. The following design analysis (which is 10 percent higher in each constituent than the worst well water 

analysis obtained) is considered applicable: 

Makeup Water Analysis 

Cons ti tuen t 

Cal ci um 

Magnesi um 

Sodi um 

TOTAL Cations 

Bi carbonate 

S ul fate 

Chl ori de 

TOTAL Anions 

Silica 26.6 (for ion exchange) 

TOTAL Exchangeable Anions 272.6 

Iron 0.10 (as Fe) 

Manganese 0.10 (as Mn) 

Turbi di ty 1.7 JTU 

PH 8.1 

Suspended Solids less than 5 

TOC (TOTAL Organic Carbon) 7 

PRETREATMENT 

Pretreatment might be required upstream of the boiler makeup water treating at 

certain times in order to reduce the load on the equipment. Pretreatment of 
the well water could be required i f the suspended solids, organic matter, or 

col loidal material contents were high in the we1 1s. Pretreatment of we1 1 water 

could also be required if there are relatively large amounts of iron or manganese 

in the well water. However, the quantities of suspended solids, total organic 

carbon, iron and manganese given in the makeup well analysis do not appear to be 

hi gh enough to requi re such pretreatment. 

The Makeup Water Analysis indicates that the hardness and a1 kal ini ty of the well 

water is high enough that the use of 1 ime .softening as a pretreatment method to 

reduce the hardness and a1 kal ini ty and thereby lower the cost of demineral ization 

was considered. The flow rate of demineralized water will be relatively low and 

the deminera1.f zer equipment will be relatively small, therefore the use of 1 ime 

softeners does not appear to be economi cal ly jus ti fied; 

BOILER MAKE UP TREATMENT 

The boiler feedwater and the boiler makeup must be of the very highest quality 

since any dissolved or suspended material entering the boiler will either deposit 

there or carry through to the turbine. . No material can be a1 lowed in the feedwater other than chemical s speci fi cal ly desi gned for once- through boilers. 

Demineralization is required in this case for the production of high quality 

boiler makeup water. 

Based on the given water analysis and the boiler makeup qua1 i.ty requirements of 

this system, a demineral i zer consis ti ng of two demineral i zer trains is recommended. 

Each train will consist of a cation exchange vessel, with conventional cation 

resin ; an anion exchange vessel, with Rohm and Haas IRA-458 anion resin; and a 

mi xed-bed exchange vessel , containing a conventional cation resin wi th a 

strongly basic Type 1 anion resin. 

CONDENSATE POLISHING AND CYCLE CLEANLINESS 

Condensate Polishing 

As indicated above, solIds present in the feedwater to a once-through steam 

generator will be deposited on the boiler surfaces or in the turbine. The 

presence of small quantities of such material in the feedwater is inevitable 
due to corrosion in the condensate feedwater cycle. Even though corrosion is 

reduced to a very low level by deaeration and pH control, it cannot be completely 

eliminated. A unit subject to daily startups and shutdowns is even more suscepti ble to corrosion than a continuously operated unit. Accordingly, full-flow 

condensate polishing is essential in order to maintain feedwater total sol ids 

at the required 20 to 50 ppb level. A condensate polisher is an ion exchange 

unit of sufficient capacity to treat the entire plant condensate stream. 

Two basic types of condensate pol ishers are avail able, deep-bed and powdered 

resin : the deep-bed unit uses bead-form, strongly acidic cation exchange resins 

and strongly basic anion exchange resins in a mixed-bed configuration to remove 

impurities from the water by ion exchange and filtration. The resins are 

regenerated, as required, with acid and sodium hydroxide. The powdered-resin 

unit employs a thin layer of powdered resin deposited on a nylon or stainlesssteel septum; it a1 so removes impurities by ion exchange and filtration. When 

the pressure drop across this unit exceeds a predetermined value, the unit is 

taken out of service, the resin is removed by back flushing, and fresh resin is 

applied; there is no regeneration. 

Both types of condensate polishers remove ionized dissolved solids such as might 

be present from a condenser leak. However, the reserve ion exchange capacity of 

a powdered-resin polisher is very small . Therefore, in the event of a slight. 

condenser leak with its high suspended solids loading, operation could not be 

continued for any significant period of time with a powdered-resin unit. 

Because of the reasonable possibility of slight condenser leaks a deep-bed 

polisher is recommended for this facility. 

Cycl e Cl eanup 

As a result of the types of boiler systems being considered, there are a number 

of speci a1 startup requi remen ts that are requi red. 

When boiler units are subjected to frequent (daily) startups and shutdowns more 

corrosion and sol id parti cl es (suspended solids) are generated. To reduce that 

load of solids, it may be necessary to flush the receiver and feedwater piping 

daily. 
It cannot be determined at this time how often such action would be required, 

but provisions must be made, in any case, to flush water through the solar boiler 

tubes and piping to the condenser so that system impurities and solids can be 

removed in the condensate polisher. 

When both the fossil-fueled boiler and the solar boiler are out of service, the 

fossil-fueled boiler should be started up first - so that the preboiler system 

may be cleaned before the solar boiler started. If the solar boiler must be 

started up without the fossil-fueled boiler, then provisions must be made to 

recycle the preboiler system to the condenser (at least that portion ahead of 

the solar boiler) so that the condensate pol isher may be used to remove suspended 

solids and other impuri tics from the preboiler system. 

It wi 11 be necessary to di rect the low-pressure heater drains to the hotwell , at 

least at times when the system is being started up. These drains are a major 

source of unwanted particles and by directing the drains to the hotwel l , the 

condensate pol isher will be able to remove the contamination before it can get 

into the solar boiler. 

FEEDWATER TREATMENT 

"Volatile" treatment has been well established as the appropriate method of 

treating feedwater for once-through steam generators. With this approach, no 

solid chemicals (such as phosphate or caustic soda) are added to either the 

boiler or the preboiler cycle. Hydrazine is added to the feedwater to remove 

any last traces of dissolved oxygen. Any excess hydrazine will decompose at 

elevated temperature and pressure to produce ni trogen and ammonia. Thus, in 

addition to being volatile i tsel f, hydrazine reaction products are a1 so vola ti1 e. 

The ammoni a thus formed reduces the requi rement for another pH-con trol chemi cal . For systems using a once-through steam generator, ammonia is general l'y added to 

the feedwater to elevate the.pH sufficiently to reduce corrosion to a practical 

minimum. Neutralizing amines are used in some systems (primarily those with 

drum-type boilers) in place of ammonia for pH adjustment. Their chief advantage 

is that, unlike ammonia, amines do not contribute to the corrosion of copperbearing alloys. Ammonia 'is considerably less expensive than neutralizing amines, 
and since a condensate pol isher will remove some of the pH adjusting. chemical, 

the material cost could become a significant operating consideration. 

In general, a deep-bed condensate polisher may be operated in either the 

hydrogen-hydroxi de cycle or the ammonia-hydroxide cycle. Immediately after a 

polisher is regenerated, the cation resin is in the hydrogen cycle and the anion 

resin i s i n the hydroxide cycle. The cation resin will become exhausted rather 

quickly by the ammonia (or amine) in the feedwater. The ammonia (or amine) must 

be replaced downstream of the polisher. 

In systems that use ammonia for pH control, after the cation is exhausted, the 

polishers are said to be operating in the ammonia-hydroxide cycle. In conventional once-through systems, the polishers may operate for ,very long times in 

.the arr~munia-hydroxi de cycle if the impurities load is low or there is no condenser leak. However, special regeneration equipment is required to operate in 

the ammoni a-hydroxi de cycle in order to reduce the sodi um 1 eakage that normal ly 

occurs after the cation resin is converted to the ammonia form. 

In the case of a solar boiler, the impurities load can be expected to be h,igh as 

a result ot the da~ lystartups and shut downs. It is therefore expected that the 

condensate polishing resin will require regeneration frequentl,~, due ,to the high 

Impurltles loading, and no provision will be made for operating in the ammoniahydroxide cycle. 

CONDENSER TUBE MATERIAL 

In general, it is our recommendation that copper alloys and ferrous alloy tube 

material not be mixed in the feedwater .yystem. We recognize that this has been 

and probably is still being done in nnce-through boiler systems. Howevcr, thc 

trend is toward all ferrous or all copper alloy systems. In this installation, 

it is recommended that the existing admiralty tubes In the air removal section 

of the condenser be rep1 aced with 90110 Cu/Ni tubes. 

If copper alloys are used, the pH should be maintained in the range of 8.8 to 

9.2 If ferrous alloys are used, the pH should be in the range of 9.5 to 9.7. 
If both alloys are used in the feedwater system, either the copper will be 

corroded by ammonia or the iron will be corroded by low pH. 

Copper a1 loys can be tolerated as a ma.teria1 for the condenser tubes in oncethrough systems with .full -time condensate pol ishing because the corrosion 

products from the condenser woul d be reduced to a low-level by the condensate 

polisher. 

HIGH-PRESSURE HEATER DRAINS AND DEAERATOR BLOWDOWN 

In addition to di recting the low pressure heater drains to the hotwell , pi ping 

should be- incl uded to cascade the high' pressure heater drains back to the low 

pressure heater drains during the start-up of the feedwa ter sys tem. Provisions 

should also be made to blow down the deaerator back to the hotwell. The hi ghpressure heater drains should be cascaded back to the low-pressure drains until 

the unit load reaches approximately 25 percent. The deaerator storage tank 

would act as a trap for s,uspended contaimination which could be relased during 

subsequent flow changes. Blow-down of the deaerator storage tank should be 

initiated if there are signs that the water there is contaminated. 

BOILER WATER MONITORING 

A considerable amount of instrumentation for monito,ring the boiler water in 

modern high-pressure or once-through boiler systems is required. Boiler feed-. 

water and steam must be monitored. during all phases of start-up and operation 

to ensure that system cleanliness and other parameters are maintained. Figure 4.2-27 is a schematic drawing of a typical water sampling and monitoring 

sys tem. 

DEMINERALI ZER 

(1) Two makeup water demineralizers, three bed trains, automatic 

control s : 

e Rating 37 gpm per train 

e Effluent quality: 

- Total dissol ved solids - 50 ppb max 

- Silica: - 10 ppb max 
(OPTIOPJAL) DEAERATOR C-OSED SOLAR BOILER CONDENSATE (OPTIONAL) 

CONDENSATE HEATER COOLING OUTLET POLISHER COOLING 

STORASE OUTLET VC'AT E R EFFLUENT TOWER 

TANKS CIRCULATING 

HIGH SOLAR BOILER FOSSIL BOILER WATER 

ECONOMIZER 

MAIN PANEL 

P 

a r\) 

NOTES 

1. SAMPLE COOLING PRESSURE REDUCTION, VALVING 

AND BLOWDOWN DETAILS NOT SHOWN 

2. SAMPLE RECLAIM AND ANALYZER WASTE SYSTEMS 

NOT SHOWN 

3. SHARED ANALYZER DETAILS NOT SHCWN 

CE CONDUCTIVITY ELEMENT 

CI CONDUCTIVITY INDICATOR 

AT ANALYZER TRANSMITTER 

IN ANALYZER INDICATOR 

pHE pH ELEMENT 

pH1 pH INDICATOR [I CATION 

EXCHANGER 

Ficjure 4.2,-27. Water Sampling and Monitoring System 
(2) One demineralizer acid tank, 5000 gal 

(3) . Two demineralizer acid pumps (1 spare), 112 hp, 460V ac motor 

(4) One demineral izer caustic soda tank, 5000 gal 

(5) Two demineralizer caustic soda pumps, 112 hp, 460V ac motor 

(6) One control panel 

CONDENSATE POLISHING 

Two full -capacity, mixed-bed pol ishers, 706 gpm per vessel 

o Effluent quality, 30 to40 ppb total dissolved solids, 90 percent suspended sol i ds removed 

a Incl uding regeneration tanks and controls 

AMMONIA FEED 

e One ammonia solution feed tank, 55 gal, including a concentrated 

ammonia sol ution measuring tank 

8 Two ammonia solution feed pumps, 112 hp, 460V ac motor 

SAMPLE PANEL 

Sample 'panel including instruments, coolers, etc., per Figure 4.2-27. 

CATION FEEDWATER PUMPS 

Two 100 percent capaci ty horizontal centri fugal pumps to supply raw water to the 

demi n~ral i zer. 

e Design Data: 

- 40 gpnl 

- 3 hp 

- 175-ft TDH 

- 1760 rpm 
4.2.3.2 BEARING COOLING WATER 

The addition of the solar system equipment for the solar repowering of the 

Reeves Unit No. 2 will add to the heat rejection duty of the existing cooling 

water system. 

Specifically, the additional equipment to be added to the water system (Ref. 

Drawing No. L-22929, Sheet No. P3-2) are: 

a. Receiver feedwater pumps: 

- Hydraulic coupling oil cooler 

- Lube oil cooler 

- Stuffing box cooler 

b. Sample Coolers: 

- Receiver feedwater 

- Receiver steam 

c. Demineralizer feed t 

The receiver feedwater pumps and hydraulic drive coolers are estimated tu require 

200 gpm of cooling water when operated at maximum capacity based on the summer 

solstice design point. The maximum cooling water usage will occur during solar/ 

fossil hybrid operation at a gross output of SU MW. However, the tossil-bo'iler 

feed pumps will be operating at below capacity since the solar portion wii l be 

supplying the major portion of the plant output. The net increase on the water 

system due to the receiver pumps is therefore estimated to be 89 gpm over the 

present operating conditions. 

The sample coolers are estimated to require an additional 4 gpm bringing the 

total additional cooling water requirements to 93 gpm. 

Operating data for Reeves Unit No. 2 indicate that for 38 MW output the cooling 

tower makeup requirement is 703 gpm, or scaled-up to 50 MW output approximately 

925 gpm 
The additional 93 gpm cooling load will therefore be subtriacted from the cooling 

tower makeup which is supplied directly from the raw water storage tanks. This 

additional .cooling water is assumed to act as cooling tower makeup, because after 

being discharged from the coolers it is drained to the b.earing cooling water sump 

and then pumped into the circulating water system and ultimately into the cooling 

t0we.r b a s i n . 

Flow in the 8-inch 602-raw water supply header will increase from a maximum of 

771 gpm to 864 gpm. This flow increase will inc.rease the velocity from 5-feet 

per second to 5.6-feet per second and the pressure loss from 1 .O-feet per 

100 feet to 1.14-feet per 100 feet. This increase in velocity and pressure loss 

does not appeiir at this time to warrant an increase in pipe size; however, this 

area will be studied in more detail during the design phase. 

The new demineral i zer feedwater is also taken from the raw water system at the 

rate of 37 gpm. This should have little impact on the water balance since 

Reeves No. 2 boiler makeup water has been taken from the water supply system and 

through the . p l a n t ' s existing water treatment system. 

The Unit No. 1 bearing cooling water system drains to a common sump with the 

Unit No. 2 system. Apparently, the sump pump located in this sump is presently 

marginal in its capacity with both units operating. It is recommended that during detailed design, this pump be investigated and a determination should be made 

as to the desirability of installing separate sumps and pumps for each unit. 

4.7.3.3 FIRE PROTECTION 

In the new Solar Equipment building addition some fire protection will be required. 

In general, equipment and personnel will be protected because the basic structure 

i s o f nonflammable construction. 

In the computer and logic rooms, Halon 1301 total flooding sys tems are recommended. 

Separate systems for each room are advised with the cylinders and mani fol ds to 

Ire 1ocat.ed outside of the rooms in the switchgear area. 
The switchgear area of the operating floor will have four photoelectric fire 

detectors. As many as 10 additional detectors would be placed ovcr the cable 

trays in the mezzanine area. All detectors and the Halon systems will be connected to a new multi-zone control/alarm panel to be located near the existing 

fire alarm/control panel . 

Hose stations and combination safety.showers will be required on the first floor. 

A hose station with 100 feet of 1-112-inch hose will be located at a central 

location. Combination eyewashlsafety shower stations will be located adjacent 

to the Condensate Polisher, the Acid and Caustic Storage area, and the Demineralizer area. The acid and caustic fill connections wil.1 be located outside the 

building. 

Fifteen pound carbon dioxide fire extinguishers will be located at various points 

throughout the building additions. 

Fire hydrants will be provided in the area of the receiver tower and the 

warehouse. 

4.2.3.4 HEATING, VENTILATION AND AIR CONDITIONING 

Duri ng the warmest weather, the new 'buil ding addition will requi re some air 

conditioning in the computer and logic rooms. The entire addition will need 

heating or ventilation all year. The equipment slzlng Is bdsecl upu~'~ 'tl~e Guilding addition being of an architectural design slmilar to that of the existing 

station building. All HVAC units will be roof-mounted, with the supply and 

return ductwork extending downward through the building. Steam for the heating coils will be supplied from a header near the existing No. 2 condenser. 

Major kqui pment i tems i ncl ude : 

1 . Rooftop ai r conditioning unit complete with power return, 

20 tons of cooling, 200 MBh steam heating coil and controls 

as needed 

2. Rooftop heating and ventilation units complete with power 

return, 25,000 cfm capacity, 370 MBh steam heating coil and 

controls as needed 

3. Rooftop exhaust fans, dome type, 1000 cfm capacity 
4.2.4 SYSTEMS OPERATION 

For the repowered unit, steam may be produced from either the solar or fossil 

boiler or from a combination of both. The unit will be in a condition of both 

boilers shut down and no electrical load being produced, or in a steady-state 

operating mode with the turbine generator on-line producing electricity with 

steam supplied by one or both boilers. The unit transitional states are the 

transition from a unit shutdown mode to an on-line mode (Plant startup) or the 

reverse (Plant Shutdown). In addition, the unit can be in transition from one 

boiler operating to, both boilers operatino (plant Operating with Startup of a 

second boil er, solar or fossil ) or vice-versa (plant Operating with Shutdown of 

one boiler). If the mode of all units being shut down is disregarded, then five 

possible unit operating modes exist: Plant Normal Operation, Plant Startup, 

Plant Shutdown, Plant Operating with Startup of a second boiler, Plant Operating 

with the Shutdown of one of the boilers. 

Within these plant modes each can be in various states. The operating solar 

boiler can be defined in terms of the day's solar insolation condition. Basically, three types of insolation exist: full, a cloudless sunny day; low, an 

overcast or hazy day with constant cloud cover; and intermittent, a cloudy day 

with broken transient clouds causing relatively rapid transition in solar insolation. The starting conditions of the solar boiler are either cold, where the 

boiler has been shut down with.in the past two days and no extra water treatment 

must be done; or ambient, where the unit has been shut down for more than two or 

three days and the feedwater requires extra treatment, which,requires the fossil 

boiler to be running. 

The fossil boiler and steam turbine both have two operating states during 

startup: hot condition or cold condition based upon metal temperature. A 

startup varies in time and method for both depending upon these conditions. 

Two other conditions affecting plant operation must be considered. First, the 

plant can be operated to maintain sorne fixed value of load based on an operator 

set load demand, or it can be responding to demand as received from some remote 

dispatching system (Variable ~is~atch). The plant can also be shutting down 

equipment in a normal fas-hion or in an emergency mode of operation. 
TABLE 4.2-12. C~lMSIf4ATIOM OF UNIT CONDITIONS FOR OPERATION 

Or THE SOLAR HYBRID REPOWERING PLANT (1 of 3) 
-- ,..- . .... -. .-. - - .. .-. - -.--- - -.- -- . _. . - - _- -- -- - . -- .p -_____ _ .---- .--- -- .. X -- - -- - x I I . __ _ .. .- -- ---- --- --- ... . .. . X 111 ,I - - -_-- -- - -.-.- I X .. .-. . .. I - -- .- - -- -- X 

111 11 

X . X . ... .. .... X 

111 11 X 

.... . X 

X I 

X I . . .. x -- -- - -__ __ _ X -- -- - 

IT - - - -- -- -. - - 

___ __ __ ____________ __ -___ -__ -. -. --. - 

_- _- -- - --- .--.. == 1,111 : 5 -- -.'_-. 

I 

- jy: Ollll 

..... I a . ... I... 

___ -- . = :_ 111 

___ 

, ___ __ ._ -_ -- - .-. .- - .-. , -- I Y .... .... 

I ______ - -.__ ... - ---- - X ____, - -- ' 

X . .. I " __ 111 _..1 --- - _ -.- -. .--- - - -_ __ ___._ - - .. x I X . . x . . ... ... -- I _ _, ___ -___..__ __ - - .- - - 

... _. ... - . - . - I I--- -- -- .. X _- __- _ x ....... ........ .............. -- X 

Ill l 

X I 

. . I __ __ ._ ... __ . .. .. ..... I I 

111 , .-.-...- " .--- -- X X . . . ..- .......... X ---. - . . _ __ ___._ __._____ _ ___ -_. I. .--- X 

I111 

X X X - _, ___ - .-_ - ... . -- .. .... -... -- X 

1111 --.- ------- -- 

--- 

111 I 

- .-.-.-..-- . X ...-.---- X -- .-__ X .- .. X 

________ X __ __ __ X __ _. . 

X X 

.. .- .. -. .. - 11 0) .I---_- -----_- I ,--. - -- ..I_-_ .- .. - .. .- ... . - . - - X X X X I 

. I1 ---. It --- --.-- - --. In ---- - - - - - . __ .. - - . _. ........ -- -- - _ X X I X X X -- .- -- -- .. -- -- -- . .. .. .. 11 It "-. I B I u X X - - -- - .- - -- -- ..-- - X X -- --- . .- 11 It 

-.--. -..- 09 

X I X v . ... 

m -- - -- - -. -- - - -- - -- X 

I1 - I1 - - - - . . -- - I X 

I' 

X I I e .. - -- -_ --- -- - -. .. . - -- - . - -. .- -- - . - I ---. I1 $1 

--- - ---I-- - - X I a --.-- a X --- ,- _ - . .. _ -- .. - . - ... -- -. - I IC X I' K X -. --- . -- - - .. - . -- .- . -. -- . 11 11 bJ . - - - - . -- - -. - - - --- -. 

;g 

". rtII ------ 

a 

X -- -, 

a 

X X 

X 

- - 

X 

I x 

X 

.- -. I - 

x - -- . . - --- - -- - -- - - -- - -- .- 

X X 

- -. 35 ICII- I C .---- X x I a - -- . - -. .- - . -. ... - .-. - . - -. - . -- ;i : 11 or 

X I X -. . . _. -_ _- . . - - - - . .- - . .- .- . . - - - _ __ _ . x n I X - 11.11 

-- .- -. xi -. -

X 

- X I X ... - 11 I1 X 

X 

I 

X 

X 

x - 

I 

-- x X -- . .-.. .- ... - ...... .- .... -. - .- .. - - . --- - - - -- -.- --- - -- I1 PI 

X X X x X X 

- 11 51 - -- - - - . - - - -- -- - - - .- .. 11 II X X X X - . - - -- . .- -... I .P X I . 11 

- 11 -- -- - - - .---- -- - . -- -- - .... 11 11 x n X I .--- U3MlOJ 0103 lln4 1 SNINNnW 1IJvls 440 0103 1011 0103 y0: y:z r:! 440 I)NINPI(I\( IUV~S 31315 'It 

NnS ~ISSOJ u311on IMI~H~I nvni UVlOS 831101 

-- - - . -- -. - - - -- - . . - - - - -
TABLE 4.2-1 2. COWBl NATION OF UNIT CONDITIONS FOR OPERATION 

OF THE SOLAR HYBRID REPOWERING PLANT (3 of 3) 

slrlf 

SOLbR lOlltR SUM f OSSll BOlLf R IUAlINt LOAD 

VAAIAYLE 

~spAlclI, lASf 

X -- 

X -- - 

-- 

1 

COtU I101 

- 

I 

X 

X 

X 

- - I X - -- .- IV.5 

off 

-- 

-- 

YO1 SIIUIUOWY A~LOWEO 

I 

- X 

SrARr 

--- 

EYE A. 

GENcV 

.- 

--------- Off RUYYlmG I~AHI 

IV I . X 

5 

5 ; 

t = 

SIIUI 

o~WY 

-.---- 

IV II X 1 I X I I -.-. - , -- . - .- I --- - - _ __ IV I1 I X X -- . - ---- . - I -.-X -- K - X IV.ll X I I - - X X I -.-.----.-----,. X lV ll X I I ---.- I - - -. . X -. I .- --. -- IV 10 I --. - -- . - - ---- - - .- X - - - -.--. X - .-, X - - I X 

IV 11 . X 1 I I 

. . - -- -- 

K 

-. . - - - -.- -.a- -- - X .-- -- --- - ----- .-- IV.11 . -- X -. --- --. - I -- ,- I - K X I -- - -I_ - IV.21 X a I. 1 -.- - --.- _. -- K x ' 

IV 14 X 1 K . - - ---. 

X 

. . .- . .- .. - -, - - -. - - . .-- -. -- ..-.. K ---.._I_ --.- X -I-.-_ _. ..__- .__I, _ , 

v.1 X X I . - _ ---- ._ -. K 

V 1 X I K --.. -- .--- - --. .-- .--. -- I 

v 1 ---- - I X X X 

V 4 

-- -. X .--- 1 . --. X __ . . - ----. - - .^-I. I-_ 

,,-. -.-- - -. A--. -- - --- ----. I I-..-- -__. ---.. 

CE ---. X I a - - I - ----- -_ . ___. - 

!I .. 1 X X --- I ---.--- --.. -- __ .. . - - -- .I.-- -- - 

1: V1 -. . I -- I 

Ed --- ---.- --- _- --- X I( . .-- --- -..-. -- --.- - .-. v I ; g X --- - - X - , - - I( .---. - . . . -. - X 

; g ---..- v.1 X .- . - .... --- ---- a. . ---- - .-.-, I 1 

v I0 I I --- - -- - I - -__ - <. V.ll X a X -..- --- ,---- -- -. .-.-- ..... _" _. ___.__._ X 

v.11 X I -. . --. -. I. ". , 

SHU1. 

OOwY 

-- 

1V.I 

IV,l --- 

IV 4 -- - X 

1 X X -- X t X . 

COLD 1101 

OIERAlIYG 

- - I. X 

- - -- 

X I 

- 

- 

IV 6 -..- 1V.l . 

- IV.1 .- 1V.l 

IV.l@ 

COLOtR 

--- 

- 

- 

- 

UUIE 

X 

I 

X 

X 

I 

I 

- 

.- 

~ 

----- 

rp 

IYrCA Cot0 fUlL %OW CloUU RLYNIIIG 

1 I I 

I 

X 

X 

X 

I I I - I X - X I X I I 

- . -- X I X X -. - - I - I I I - I Il 

X X I -. -- -- -- - K X X I I - .- - . X -- I -- K -. 

Ee 

I 

X 

X 

I I I I X X 

lV ll 

s 

C? 

2: f f 

X -- 

~6 IV I& X 

X 

I 

IVI1 

- ,VI, 

IV'l4 

K 

X -. 

- 

X 

I 

I 

X 
Table 4.2-12 summarizes the probable combinations of unit conditions. Certain 

operating states are not felt to be valid operating states (particu.larly for the 

solar subsystems) and the plant will not be allowed to run in those modes. 

During Plant Normal Operations with only the solar boiler producing steam, the unit will not respond to electrical grid dispatching requests, but will produ'ce whatever electrical energy is 

available based upon available solar thermal power. Therefore, 

Modes 1-4, 1-5 and 1-6 are invalid. Also the plant cannot be 

reliably controlled during solar insolation transients if the 

solar boiler alone is producing steam. Therefore, Mode 1-3, 

Solar Boiler Only on an Intermittent Cloudy day is an invalid 

normal operating mode. 

a During Plant Startup, since operation with solar boiler only on 

an intermittent cloud day is r~ot permitted, then neither will a 

plant startup with solar boiler only on an intermittent cloudy 

day be permitted. Thus, Modes 11-3 and 11-6 are invalid. Also, 

since the solar boiler i s i n the "Colder" mode (having been 

shut down for more than two or three days) extra water treatment 

requiring the fossil boiler to be in operation must be present, 

then Modes 11-7 through 11-12 are not valid since the fossil 

boiler is not running. Also, Modes 11-29 through 11-40 that 

involve the starting of both boilers simultaneously does not 

seen to be practical. 

During Plant Shutdown the only invalid mode is 111-3; a normal 

shut down with only the solar boiler operating on an intermittent cloudy day. If the weather changes while operating the 

solar boiler, the shutdown (if chosen) would be an emergency 

shutdown or Mode 111-6. 

In the Plant Running with Startup of Second Boiler operating state, all modes 

are valid except IV-15 through IV-18. Mode IV-15 represents the starting of the 

cold fossil boiler while the solar boiler is running on an intermittent cloudy 

day. If the solar boiler is on-line and weather conditions c.hange to an intermittently cloudy day then the solar boiler must either be shut down, taking the 

plant off line, or the fossil boiler must be started. However, with a cold 

fossil boiler the startup time of six to nine hours necessitates that the solar 

boiler be shut down. Modes IV-16 through IV-18 would be invalid modes since the 

plant will not run in a variable dispatch mode with only the solar boiler' 

operating. 
Finally, the Plant Running with Shutdown Mode, Modes V-9 through V-12, will not 

be permitted since after shutting down the fossil boiler, the plant will be in 

an invalid operation state. For Mode V-9 the solar boiler would be on-line only 

under intermittent cloudy conditions. In Modes V-10, V-11 and V-12, the solar 

boiler only would be running with variable load dispatch. Both of these conditions represent invalid operating modes. 

4.2.4.1 INTEGRATION OF SOLAR SYSTEMS WITH BALANCE OF PLANT 

This section defines a number of potential problem areas that were considered in 

the design and operation of integrating the solar systems with the existing 

Reeves Unit No. 2 plant. In accordance'with the basic design philosophy of 

minimum change to the existing plant sys tem, certain constraints become evident 

such as : 

Fossil boiler capabilities 

0 Existing condenser heat duty 

Condensate pump capabil i ty 

Existing water treatment equipment 

Receiver steam 1 ine cool down and warmup 

Feedwater heater drains considerations 

During the conceptua'l design, the above six items were exain5~ed to determine .if 

any of these i tems would put serious constraints or cause questions concerning 

the feasibility of solar repowering of Reeves Unit No. 2. 

As a result of preliminary design efforts, it appears that none of the constraint 

items will render the repowering concept infeasible. During the detailed design 

phase of this program further studies may be required of these items, and a'lso 

additional investigation of potential integration problems that may become 

apparent. 

The remaining portion of this section will be devoted to discussion of the studles 

that were conducted on the above six items. 
FOSSIL BOILER' CAPABILITIES 

Several aspects of the fossil boiler capability for the Reeves Unit No. 2 station 

were studied during the Solar Repowering Conceptual Design. These studies were 

necessary to integrate the existing fuel oil-fired fossil boiler with the so'l ar 

system equipment. One i tem that was looked at during this phase of the design 

(discussed further in Section 4.2.4.2) is the rate of load increase and decrease, 

otherwise known as ramp rate of the fossil boiler. The ramp rates are important 

during solar insolation transients such as intermi ttent cloud cover. Recent 

information received from Babcock 81 Wilcox (B&W) , the supplier of the fossil 

boiler, indicate that a maximum ramp rate of approximately 30 percent of maximum 

capability per minute can be used. 

B&W indicate that this ramp rate should be studied in more detail as it may affect 

other components of the boiler. Therefore, for this conceptual design a conservative ramp rate of 20 percent per minute has been used for all transient studies. 

The problem of fossil boiler steam temperature drop below approximately 50 percent 

load was investigated since it would affect the control of the boiler steam temperature in relation to the solar steam temperature. During high insolation 

periods, such as summer solstice, the solar portion of the system can produce up 

to 78 percent of the total gross electrical output of 50 We. During solar/fossil 

operation and for a 50 MWe gross output this would mean that the fossil boiler 

would be operating at about 22 percent of its maximum capability. Based on steam 

temperature versus steam flow data contained in the data books for the Reeves 

unit and modified somewhat by operating experience at the Reeves Station, Figure 1.2-25 shows IKJW secondary superheater outlet s team temperature varies with 

steam ,Flow. 

Figure 4.2-29 shows a plot of mixed throttle steam temperature versus perce'nt 

fossil boiler operation. If no rcceiver steam aLLer!~peratlon is made, the curve 

shows the three data points at the mixed steam conditions of 22 percent fossil, 

25 percent and 35.5 percent fossil boiler operation. The figure also shows that 

the mi xed steam terrrperatures exceed the throttl e steam requi remen t of 950°F. 

This indicates that during periods of h'igh solar insolation and low fossil boiler 
FOSSIL BOILER 

@ % FOSSIL BOILER 

STEAM FLOW, (1000 LB/HR) 

Figure 4.2-28. Fossil Boiler Steam Temperature Droop 
. load operation, throttle steam temperature ca.n be controlled to 950°F by reducing 

the attemperation of the receiver steam. This procedure woul d greatly simp1 i fy 

the overall control system of the fossi 1 /solar combination. 

Another significant fossil boiler limitation is that automatic operation of the 

boiler at loads less than 50 percent is not possible. This is an unacceptable 

condition since, during periods of high .solar insolation, the fossil boiler will 

regularly be operated at less than 50 percent load if the total gross output 

from the Reeves Unit is desired to be at 50 MWe. As mentioned in Section 4.2.1 .l, 

one of the modifications to. the fossil boiler should be to permit operation of 

the boiler in an automatic mode at loads less than 50 percent and preferably down 

to about 20 percent load. This requirement not only necessitates a modification 

to the existing control systems, but also will require modification to the fuel 

oil supply system and a determination of whether or not the existing fuel oil 

nozzles are capable of a turn-down ratio suitable to operate all six nozzles at 

a total load of 20 percent of maximum. Flow Sheet P3-3 shows a modification to 

the fuel oil supply system to handle the reduced fuel oil load. This modification 

consists of another flow control valve in the fuel oil system of a smaller size 

than the existing valve and in parallel to it so that fuel oil supply can be regulated down to the required low flow values. During periods of maximum boiler 

load, the fuel oil will flow through the existing valve; during periods of low 

load operation the larger existing valve will be closed and control will be maintained using the smaller parallel fuel oil valve. 

For operation at 22 percent of maximum fossil boiler load, a turndown ratio of 

4-1 12 to 1 woul d be required on the fuel oil atomizing nozzles. It is well known 

that for operation on No. 6 fuel oil using air or steam atomizing nozzles, turn 

down ratios of 5 or 6 to 1 can be obtained and ratios of 8 to 10 to 1 can be 

obtained if higher fuel and air pressure drops across the nozzle can be tolerated. 

The boiler manufacturer should be contacted during the detailed design phase to 

determine if a tbrndown ratio of approximately 5 to 1 can be obtained using the 

existing nozzles. If it cannot, then new higher turn down ratio nozzles could 

be installed to permit automatic operation at loads down to 22 percent of maximum. 

The fuel oil control system wi 11 a1 so have to be modi fied for this requirement 

and this modification is discussed further in the control section of this report. 
PERCENT FOSSIL BOILER (HYBRID OPERATION) 

1000- 

Fi gure 4.2-29. Fossi 1 Boiler Steam Temperature Droop 

P; 6 NO ATTEMPERATION OF RECEIVER STM. 

k 

J 

2 

a l I 

980 - 

960 - 

THR0TTL.E STM CnNTRnLbECI TO 950"~ 

940 - 

920 - 

I 

.-I I 

31 2 -1 

ki I 

6 I 
CONDENSER HEAT DUTY 

A brief study was made of the existing Reeves Unit No. 2 condenser to determine 

if the condenser has sufficient capacity to handle the additional drain requirements of the solar systems. The result of the study indicated that for steady 

state operation the existing condenser will handle the total drain flow and condensate for a 50 MWe gross output. For the worst heat duty of approximately 

316,000,000 Btu per hour (which corresponds to a 35-112 percent fossil , 

64-112 percent solar hybrid operating point and for a two-inch mercury absolute 

condenser pressure) a margin of about 2.4 percent exists over and above the design 

point of the condenser. The design point for the condenser was determined from 

the Reeves Unit No. 2 data books; with 1.97-inch of mercury absolute condenser 

pressure, 312,000-pounds per hour steam can be condensed for a heat duty of 

323,232,000 Btu ?er hour. This heat duty is based on a circulating inlet water 

temperature of 77°F. 

A potential problem may be experienced in condenser duty during start-up conditions of the solar systems. Specifically, if the Reeves Unit No. 2 is operating 

on the fossil boiler with plant output set to 50 MWe, and it is desired to start 

the solar system, the start-up procedure for the receiver indicates that during 

initial periods of start-up the steam generated by the solar receiver will be 

passed through the flash tank and directly to the condenser. 

The flash tank steam will put a considerable load on the heat transfer capability 

of the condenser and will cause the back pressure on the turbine to increase. 

For this reason it is r.ecolnnlended that during start-up of' the solar system with 

slmul taneous operation of the fossil boiler the unit load should be reduced 

during the start-up period to a point where condenser pressure can be maintained. 

This may mean a reduction in load by as much as 50 percent or more in electrical 

ULU. 11 is also recommended that the condenser pressure be monitored and a 

signal sent to the flash tank to vent steam to atmosphere and close PCV-2-6 if 

condenser pressure rises to unacceptable levels. This control system is shown 

on flow diagram Sheet P3-6. During the detailed design phase of the program a 

more detailed study of condenser capability during solar systems start-up and 

simultaneous fossil boiler operation shn~~ld he conducted. 
CON DENSATE PUMP CAPABILITY 

A study was made to determine the capability of the existing Reeves Unit No. 2 

Condensate Hotwell Pumps when a condensate polisher is added between the pumps 

and the first low pressure heater. A total flow of 706 gpm and an additional 

pressure drop of 50 psi due to the condensate polisher being added to the system 

wi 11 cause the existing Reeves Hotwell Pumps to not meet the design conditions. 

The present Reeves Unit No. 2 Condensate Hotwell Pump design point is based on a 

44 MWe rated condition and 'is 600 gpm with a total developed head of 305 feet. 

It is recommended that two new condensate hotwell pumps be installed, replacing the existing pumps. Several problems may be encountered during the 

installation of these pumps. The pumps are 20 years old with a large diameter 

(approximate1.y two feet) and a hosrt pump pit depth of only 4-112 feet. This 

indicates that the existing pump pit depth should be increased approximately 

4-112 feet. The diameter could be considerably smaller. It may be possible 

to install booster pumps at the condensate polisher to supply the additional 

50 psi pressure; however, for this conceptual design it is recommended that 

the older existing Reeves Unit No. 2 pumps be replaced with more modern pumps. 

During the detailed design of the project, this will be reviewed in greater 

detail. 

FEEDWATER HEATER DRAINS CONS1 DERATIONS 

Due to the addition of two new feedwater heaters in the solar system to heat 

receiver feedwater, additional drains piping will be routed to the condenser. 

Since the original design of the Reeves Station Unit No. 2, the ASME has 

developed detailed recommendations for water induction protection of the turbine 

in design of feedwater heater and drain systems. For the conceptual design of 

the repowering solar portion of the plant these ASME water induction recommendations were followed and Flow Sheets P3-6 and P3-1 reflect the required changes. 

The conceptual designs therefore show cascading drains to the next lowest pressure heater pl us a1 terna te drains to the condenser. Another feedwater heater 

drain problem that was considered during this< conceptual design is the draining 

of the No. 7 heater to the deaerator. 
The location of the No. 7 heater is on the operating floor and in the same location as the evaporator that will be removed. This floor is at an elevation of 

5108 feet. The corresponding heater for the fossil boiler is the No. 2 heater 

which has the same pressure for draining as the No. 7 heater. There is a difference in elevation of 17-feet. 6-inches between the No. 7 and No. 2 heaters. The 

No. 2 heater is higher in elevation, therefore drainage should be a simpler problem to the deaerator. The avail able pressure drop for the No. 7 heater was 

examined at loads from 100 percent load (50 MWe) down to approximately 44 percent 

load (22 MW~). Drains consideration-was given to the No. 7 heater shell pressure, 

the elevation head required and the deaerator pressure at these low levels. 

Calculations indicate that at the 100 percent l o a d p i n t , there should be 96 psi 

avail able from the No. 7 heater to drain to the deaerator. This 96 psi would 

be available for frictional pressure losses in the drain line and also for the 

drain level control valve pressure drop. For the 22 MWe 44 percent load point 

29 psi would be available for draining to the deaerator. It was concluded that 

for the conceptual design, a high pressure heater drain pump for the No. 7 heater 

would not be required since there appears to be sufficient pressure available 

down to a plant load of 44 percent. Below this point a drain pump may be 

required or the a1 ternate drain to the condenser could be used for the low load 

levels. Future study is recommended based on more complete operation requirements to determine if an additional drain pump would be required. 

EXISTING WATER TREATMENT EQUI PMENT 

Based on a study of the water treating requirements for the once- through central 

receiver boiler, it was determined that the present Reeves Unit No. 2 evaporator 

equipment coul d not be used to supply adequate feedwater to the receiver boiler. 

It is recommended that the evaporator plus all the associated piping be removed 

during the solar repowering. The No. 6 and No. 7 receiver feedwater heaters are 

to be located in the area of the removed evaporator. 

It is a1 so reconmended that the condensate system for Unit No. 2 be separated 

from Units No. 1 and 3. These changes are shown on the revised piping drawings 

and flow sheets. The reason for separating these systems is to maintain water 

quality and prevent possible contamination of the Unit No. 2 system from 

Units No. 1 and 3 cundensate. 
RECEIVER STEAM LINE COOLDOWN/WARMP ANALYSIS 

It was considered during the conceptual design phase of the Reeves Sta.tion 

repowering that due to the extreme length, approximately 3800 feet, of the steam 

1 ine a considerable warmup problem prior to admitting steam to the turbine woul G 

occur. A cool down and warmup analysis was made to determine the extent of the 

warmup problem. Two conditions were analyzed: 

The cool down and warmup of the steam line during an overnight 

shut down of approximately 13 hours 

The warmup of the steam line after an extended period of shutdown 

where it was assumed that the steam line and thermal insulation 

systems would be at a steady state temperature of 40°F 

The first analysis was more complex because of the change in phase of the warmup 

steam from superheated steam through saturated steam to saturated water. The 

low initial temperature of the steam piping compared to the desired final temperature made an iterative computer heat transfer solution approach more .desirable than a cruder hand calculation. This section will describe each of the 

analyses that were performed and the results and conclusions of these analyses. 

OVERNIGHT SHUTDOWN 

The purpose of this analysis was to determine the cool down temperature of the 

steam piping during a 13-hour overnight shut. down of the solar systems and the 

length of time it would take to rewarm the piping to a suitable temperature prior 

to admitting steam to the turbine. The length of time assumed for the overnight 

shutdown was 13 hours. Table 4.2-13 describes the piping system parameters 

incl uding the a1 1 oy s tee1 pipe, thermal insulation and convection coefficients 

from the pipe to the air, ancl from the strlam into the pipe which wcrc assumed 

and calculated for both heat transfer problems. This table includes all of 

the necessary dimensional and thermal properties of the piping and thermal 

insulation. A steady-s tate time sharing computer program (PIPEHT) was run to 

determine the steady state temperatures through the pi ping and thermal insulation 

at the tinie of shut down. These steady-state .temperatures are as follows: 

F1 uid bul k temperature - 998°F 

0 Temperature on inside of pipe wall - 997.6"F 
e Outside insulation temperature - 85.4OF with an outside ambient 

air temperature of 70°F 

TABLE 4.2-13. PIPING SYSTEM PARAMETERS 

Pipe 

Length ( feet) 

Inside Diameter (inches) 

Outside Diameter (inches) 

Densi ty (1 b/ft3) 

Speci fic Heat (Btu/l b-OF) 

Conducti vi ty (B tu/hr- ft-OF) 

Total Weight (pounds) 

Insulation 

Insi zle Dian~eter (inches) 

Outside Diameter (inches) 

Density (1 b/ft3) 

Speci fi c Heat (B tu/l b- OF) 

Conducti vi ty (B tu/hr-ft- OF) 

Total Weight (pounds) 

Convection from Pipe to Air 

Wind Speed (mph) 

Ambient Temperature (OF) 

Convection Coefficient (~tu/hr-ft'-'~) 

Convection Coeffi ci en ts from Steam to Pi pe 

Superheated Steam to Pipe Wall (~tulhr-ft'-'~) 68.1 

Condensing Steam (~tu/hr-ftz-OF) 1,287. 

This program calculates both the convection losses to the air and also radiation 

losses that are approximately 10 percent of the total heat loss. During nighttime cooldown it was assumed that the ambient air temperature would drop to 1Z0F 

which is the minimum design point assumed for the study. The wind speed across 

the pipe was assumed to be 10 miles per hour. 

Based on the steady state shutdown temperatures of the piping and thermal insulation, the'heat contained in the pipe, insulation and in the remaining steam, was 

computed based on the physical properties of the system. A second run of PIPEHT 

was made with an outside air temperature of 12°F and with the pipe assumed to be 

radiating to space through a clear sky at night and an assumed receiving temperature of minus 20°F. The computer run was arranged so that an overall heat 
transfer loss could be obtained based on the initial conditions. A stepwise 

calculation was performed using the heat loss in the piping as determined from 

the computer runs. 

These calculations show that for a 13-hour shutdown it is estimated that the pipe 

wall temperature wi 11 decrease from 998°F ini ti a1 temperature to 864°F final 

temperature . 

The next portion of the analysis was an attempt to determine how long it will 

take to warm the pipe to approximately 970°F, which was considered adequate to 

Start the turbine without incurring thermal pmhlems. 

A warmup steam flow of approximate1 y 15 percent of the total receiver steam flow, 

which is 41,000 pounds per hour, was assumed. An average steam temperature 

(based on running the time sharing program called PIPELOSS) was calculated at 

932°F for a 1000°F inlet steam temperature and a heat transfer coefficieni from 

the steam to the pipe wall of 68.1 ~tu/hr-ft'-"~ was determined. Heat input of 

18,977,000 Btu's per hour to the pipe and insulation was estimated to be required 

during the warmup time. Total heat loss of the system during the 13-hour shut 

down was calculated to be 12,730,200 Btu. Dividing the heat loss during the 

overnight shutdown by the net heat gain per hour into the system during warmup 

time, an estimated warmup time of approximately 40 minutes was calculated. 

Two conclusions can be drawn from this analysis: 

For a 13-hour shutdown of the receiver steam line, it is anticipated that a warmup time of approximately 40 to 60 minutes would 

be necessary to bring the piping temperatures close to the steady 

s L;d It! temperature . 

e Since the piping system only cools tu 864°F overnight, it may be 

possible to start the turbine without a prior steal11 Vine warraup. 

Since the turbine also will have cooled down somewhat and will 

require slightly more than one hour to bring the turbine up to 

full rated capacity, both the turbine and the steam pi ping coul d 

be brought up to temperature si mu1 taneousl y wi thout adveirs~e 

effects to the system. 
EXTENDED SHUTDOWN 

A heat transfer analysis was made to determine the warmup times of the receiver 

steam piping during an extended shutdown of possibly several days. This analysis 

assumed that the piping and insulation system would be at an overall ambient 

temperature of 40°F with the outside ambient air temperature at 12OF and a wind 

velocity of 10 miles per hour. The piping system parameters and the convection 

coefficients in Table 4.2-13 were used for the transient warmup analysis. 

A computerized transient analysis was used due to the complexity of the problem. 

Initially it was expected that as warmup steam was introduced into the cold pipe, 

at some point along the pipe length two-phase flow would occur where the superheated steam is reduced in temperature and would start to condense on the pipe 

wall. As the warmup progresses, the heat transfer will be from superheated steam 

with no ch,ange in phase. A low initial temperature of the piping system warmed 

to a rather high temperature will change heat losses to the air at various points 

in time during the warmup period. For this problem, radiation was not considered 

as this would extend the computer run time considerably. 

Heat transfer coefficients from the pipe to the air based on an ai r veloci ty of 

10 miles per hour was calculated to be 2.1 ~tu/hr-ft~-~F. The equation used to 

calculate this coefficient is of the Nussel t type and is as follows: 

where : 

K = Thermal conducti vi ty of the ai r 

D = Insulation outside diameter 

NRe = Reynol ds number over pipe 

NpR = Prandtl number 

The heat transfer coefficient for superheated steam to the pipe at the flow condi tion of 41 ,000 pounds per hour was calculated to be 68.1 ~tu/hr-ft~-'F using 

a conventional turbulent flow heat transfer coefficient correlation. The heat 
transfer coefficient for condensing heat transfer is based on a correl a tion contained in McAdams "Heat Transmission" and includes the effects of vapor velocity. 

This correlation is: 

Condensate 

where : 

c = Specific heat of condensate P 

= Median mass velocity, lblhr-ft 2 

m 

N~~ = Prandtl number of condensate 

L = Density of condensate 

= Density of vapor v 

f = Friction factor 

The condensing heat transfer c o e f f i c i e n t was calculated to be 1287 ~tu/hr-ft'-'~. 

The program used to calculate the transient heat transfer is called ANSYS. This 

program was developed for the CDC computer and is used by Stearns-Roger to 

analyze complex heat transfer and thermal stress problems. The program calculates 

a sol ution as a function of time. A system of connecting thermal nodes based on 

the physical geometry of the system was developed. 

Figure 4.2-30 shows the receiver piping heat transfer analysis node point diagram 

that was used in the cal cul ation procedure. A total of 198 nodes were generated 

for 3200 feet of pipe, which is the approximate pipe length exposed to ambient 

conditions, Based on a given steam flow and initial stcam temperature introduced 

to the pipe, the program iterates a finite element, simultaneous equation solution 

as a function of time for the various nodes using conduction and convection heat 

transfer. The results of this program are showIi on Fi gure 4.2-31. This fi gure 

is a plot of innerwal steam pipe temperature versus hours, for pipe locations of 

500; 1000; 2000; 3200 feet from the piping inlet at the receiver. 
RECEIVER 

STEAM 

CONVECTION ELEMENTS - C 

CONDUCTION ELEMENTS - K 

FLOW ELEMENTS - F 

AMBIENT CONDITIONS 

166 TO 198 

--------- 156 -161 PIPE 

REPEATED ELEMENTS EVERY 100 FT. to 3203 FT. 

Fi gure L.2-30. Receiver Pi ping Warmup Analysis Node Points 
- 

1000 - 

800 - 

GOO - 

RECEIVER STEAM LINE WARMUP TIME 

T Ambient = 1 OF 

T Steam Inlet = 900'~ 

T Pipe Initial = 40'~ 

STEAM FLOW RATE = 41,000 LB/MR 

1 1 I 1 I I 1 I I I I 

1 2 3 4 5 G 

I I 

TIME, HOURS 

Figure 4.2.-31 . Remi ver Steam Line Warmup Time 
The warmup steam flow rate assumed was 41,000 pounds per hour at 900°F. This 

fi gure a1 so shows that .the pi ping sys tem warmup wi 11 take four to fi ve hours 

depending on operating experience as to what is an acceptable steam inlet condition for turbine roll. From this analysis, it appears that using the receiver 

steam to warm up the receiver steam line is an unacceptable procedure due to the 

length of time involved. The better solution may be to borrow steam from 

Units No. 1 or 3, or even Unit No. 2, to keep the steam piping warm when long 

periods of receiver shutdown are anticipated. This borrowed steam would be used 

to pressurize the receiver steam 1 ine and hold it at a saturation temperature 

associated with the pressure. The economics of this procedure, however, woul d 

have to be justified since fuel oil would be burned dl~rina an extended receiver 

shutdown. Economically, it may be more justifiable.to use the receiver steam 

over a five hour period to warm the line. These conclusions are reflected in the 

systems operation and startup procedures contained in Section 4.2.4.3. 

4.2.4.2 SOLAR RECEIVERIFOSSIL FUEL BOILER TRANSIENT INTERACTION 

This section describes the solar transient analysis that was performed to model 

the consequences of cloud shadow passage over the collector field. The underlying assumptions used in the development of the model are described, a simplified 

block diagram of the computer simul ation is presented, and the concl usions of the 

analysis are discussed. 

UNDERLYING ASSUMPTIONS OF COMPUTER SIMULATION MODEL 

~esiqn Cloud ~hadow_~_e!~ci ty 

Since the transient response of the sol arlfossil hybrid is highly dependent on 

the rate of change of the solar insolation, an effort was made to determine a 

representative cloud shadow velocity. Form WBAN 33, Summary of Constant Pressure 

Data, giving wind speed data at various pressure levels, was obtained from the 

Envi ronmenta.1 Data Service, National C1 imati c Center, National Oceanic and 

Atmospheric Administration. Data were obtained for the entire year of 1977, and 

consist of sounding records of twice daily (5:OO a.m. and 5:00 p.m. MST) balloon 

launchings from the Albuquerque, New Mexico Weather Bureau Station. 
Hourly surface weather observations at Albuquerque for the year 1977 were obtair 

from the aanle source. These include cloud type, percent of sky coverage and 

estimated cloud layer height above the field, along with other weather information. The data were correlated to determine cloud speeds for each cloud layer 

twice daily for a six month period, April through September 1977. The period 

examined was 1 imi ted to the spring aiid summer months for two reasons : 1 ) to 

limit the amount of data to correlate, and 2) since the balloon soundings were 

launched at 5:00 a.m. and 5:00 p.m. MST, wind speeds are available only for 

times either well before or after solar operation during fall and winter months. 

These wind speeds may not be characteristic of daytime operation. 

A weighted average (weighted by the fraction of sky coverage for each layer) 

cloud speed for the six month period was then calculated. In the calculation of 

the average, days when the percentage of possible sunshine was less than 50 percent, were not incl uded. In addition, cirrus cloud layers, which are high 

a1 ti tude clouds composed of ice crysta.1~ and are usually trans1 ucent, were not 

included in the summation. Since cirrus clouds are often formed in standing 

waves when strong, high a1 titude i~lnds are present in mountanious regions such 

as the A1 buquergue area, the wind speed does not necessarily correspond with 

cloud speeds. Also, since these clouds are usually wispy edged and semi transparent, they should not cause as severe insolatinn transients as dense, low 

a1 tl tude clouds pushed by 1 ower wind speeds, 

With the above limitations imposed, the calculated average cloud speed was 

.I 7 mph. Monthly resultant wind directions for each pressure level arc given in 

the Summary of Constant Pressure Data and were generally in the southwest quadrant for the period under consideration. To facil i tat.^ computer model ing, the 

design cloud shadow velocity was 17 mph from the south. 

The design clouds were assumed to be sharp-edged and opaque ar~d to have shadows 

that were circular in form. While real clouds obviously do not conform to these 

criteria, these assumptions were made in order to facilitate computer modeling 

and are conservative in that they lead to more severe insolation transients for 
a given wind speed than would occur with real clouds. Three different cloud 

shadow sizes were modeled; one one-mile in diameter causing a 100 percent loss 

of solar insolation incident on the collector field, one 1925-feet in diameter 

causing a 50 percent loss, and one 780-feet in diameter causing a 10 percent 

loss. 

Linear Relationship Between Collector Field Unshaded Area and Receiver Incident 

Heat 

This assumption was also made to facilitate computer modeling. For this si tuation to actually exist, not only would the heliostats have to be uniformly distributed over the collector field, but each heliostat would have to have equal 

blocking and shadowing loss, cosine, transmission loss, and so forth. This is 

obviously not the case, but the assumption of linearity between collector fiel d 

unshaded area and receiver incident heat had to be made to allow for computer 

modeling within budgetary limits. It is not anticipated that the noted assumptions compromise the analytical resul ts. 

Linear Re1 ationship Between Receiver Incident Heat and Steam Flow 

The assumption was made that steam flow would be directly proportional to incident 

heat fl ux for val ues of heat fl ux about 15 pe-rcent of design maximum. Below 

15 percent heat flux the design steam temperature cannot be maintained due to 

1) radiation and convection heat losses that dissipate an increasingly 1 arge 

proportion of the incident energy at lower power levels., 2) a lower effective 

concentration ratio, and 3) 1 imi ts of range of the receiver temperature control 

valves. Receiver steam will have to be diverted to the flash tank if the steam 

temperature cannot be maintained at 1000°F. The heliostats will then have to be 

defocused. When insol ation on the fiel d is re-establ ished, the he1 iostats will 

gradually be refocused until 1000°F steam flow is attained. It is estimated that 

this process will require 15 to 20 minutes to complete. 

For the computer simulation a linear relationship between incident heat and steam 

flow down to 15 percent flow was modeled, with a step decrease to zero steam flow 

at lower insolation levels. While the assumption of linearity is not strictly 

accurate, particularly at -the lower flow rates, it is a good working approximation. 
Linear Relationship Between Throttle Steam Flow and Generator Output 

This assumption was made to simplify the computer simulation model. While not 

perfectly accurate, again it is a close approximation. 

Generator Ramp Rate 

A maximum generator ramp rate of five percen-t- per minute for power increases under 

normal conditions was modeled. The reason for 1 imi ting the rate of change of output is to lengthen turbine rotor life by minimizing thermal stress cracking. Output rates of change during periods of rapidly diminishing solar insolation mdy 

exceed five percent per minute negative. A reduction in solar. receiver steam output requires an increase in fossil boiler steam output if the generator output is 

to be held constant. Since the fossil boiler has a ramp rate itself (see below), 

it is possible for the receiver steam output to be decreasing at a much faster 

rate than the fossil boiler can increase. Thus generator ramp rates will unavoidably exceed five percent per minute negative occasionally. During periods of 

rapidly rising solar insolation, the generator output rate of change may exceed 

five percent per minute positive. 

The recommended retrofit of a DEH turhine control system may permit turbine ~-~IIIC) 

rates that exceed five percent per minute. An improvement in transient response 

characteristics over what the comp~lter simulatinn mnd~ indicates should bc rqcil1 ized if the DEH control system i? implemented, Such mndifir~tions are d i~cusscd 

in detail in Section 4.3. 

Boi 1 e r Ramp Ra te 

A maximum b~ileramp rate of 20 pcrccnt per- miisule for either load increases or 

decreases was modeled. Minor modifications to the drum level control system 

wi l l have to be implemented to a1 low a 2fl percent ramp rat.^. It is post; iblc that 

the boil er manufacturer coul d endorse hi gher than 20 percent maximum ramp rates 

after a detailed study of the unit. Pending combustion and feedwater systems 

analysis, the manufacturer, Babcock & Wil cox Company, indicated that the bniler 

appears to be capable of operating from 15 to 55 MWe output in five minutes, 

which corresponds to a boiler ramp rate of 26 percent per minute. In the event 

of a conflict between the maximum boiler ramp rate and the maximum generator 
ramp rate during periods of rapidly increasing solar i nsol ation, the computer 

model gave precedence to the boiler ramp rate. That is, the boiler output rate 

of decrease was limited to 20 percent per minute and the generator rate of 

increase was allowed to exceed five percent per minute. 

Boiler Steam Temperature 

A constant outlet steam temperature, of 950°F was modeled, a1 though there may be 

a slight temperature droop (20" to 30°F) under worst case (lowest boiler load) 

condi tions . 

Total Power Output 

The computer simulation model was based on a total gross power generation of 

50 MWe under steady state conditions. It was assumed that the solar portion 

would be operated at the maximum possible output for the insol ation conditions 

and the balance of the gross electrical generation would be produced using fossil 

boiler steam. Two different solar insolation conditions were modeled: One 

represented the design maximum solar insolation condition at noon on summer 

solstice with a direct normal solar insolation of 1045 w/m2, resulting in a 

solar receiver steam generation of 335,277 pounds per hour, 78 percent of the 

430,000 pounds per hour of steam generation required for 50 MW gross electrical 

genera tion. The other insol ation condition mod1 ed was one corresponding to ' 

equal contributions of solar receiver and fossil boiler steam: 21 5,000 pounds 

per hour each for a total of 430,000 pounds per hour. 

No Thermal Storage System 

Since a thermal storage system would be incompatible with the existing turbine, 

thermal storage is not envisioned. For this reason, a thermal storage system 

was not modeled. 

COMPUTER SIMULATION MODEL 

The solar/fossil hybrid transient analysis was performed using ANASIM, a BASIC 

language program that simulates an analog computer on a high-speed digital 

machine. The program solves set of simultaneous differential and algebraic 
differential equations using numerical techniques. Forty-ei ght separate blocks 

including summers, integrators, clippers "and" gates, and so forth, are available. The patch board interconnections employed in the operation of a standard 

analog computer are simul'ated by speci fying the interconnections between those 

blocks. About 40 blocks were required for the simulation of the solar insolation transient. 

The time rate of change of solar insolation shown in Figure 4.2-32 was input, 

and then integrated with appropriate initial conditions and mu1 tip1 ied by a 

scaling factor to represent the receiver steam flow. A relay block was used 

to set receiver steam output flow to zero if receiver output dropped below 

15 percent of maximum. Receiver steam flow and boiler steam were summed to 

obtain total steam flow, which was mu1 tiplied by a scaling factor to obtain 

the gross electrical output. Total steam flow was also compared to the set 

point (430,000 pounds per hour) by a summer. The resulting error was multiplied by a gain constant (3). 

A network of blocks limited the error signal to an absolute value of 0.2 of the 

boil cr steam flow. The resul ting boiler ramp rate was summed wi th the receiver 

ramp rate to determine a tentative total steam ramp rate, That rate was cumpared with a rate equal to five percent of the total steam flow in a minimum 

value Llvck to select the lesser of the two rates. The rrlceiver ramp rate waq 

sultr-dcted from the total steam ramp rate in a sumrnpr to determinc the badler. 

ramp rate. The boiler ramp rate was limited to a minimum of minus 20 percent 

per minute of boiler output by a maximum value block. The boiler ramp rate was 

integrated (with appropriate initial conditions) to determine the boiler steam 

flow. Block outputs plotted (see Figures 4.2-33 through 4.2-38) were incident 

radiation, MWth, receiver steam flow in pounds per hour, boiler steam flow in 

pounds per hour, total steam flow in pounds per hour, and gross genera ti or^, MWe. 

CONCLUSIONS 

Z 

Under conditions of maximum solar insolation (noon summer sol stice, 1045 W/m 

direct normal insolation), the model indicates a 34.2 megawatt power droop 

resulting from the design 100 percent solar insolation transient. Furthermore, 
d :INSOLATION1 

d (TIME) 

VALUE INTEGRATOR 

INTEGRATOR 

TENTATIVE BOILER RAMP 

RATE llbhrlmin) 

SUMMER 

P 

INSOLATION - 

(mwthl 

STEAM 

FLOW 

SET 

POINT 

SCALE 

5% X TOTAL STEAM FLOW - SCALE 

F TOTAL STEAM FLOW 

llblhr) 

- 

RECEIVER RAMP RATE 

Ilb/hr/minl I t SCALE 

'TOTAL STEAM RAbP 

RATE (Iblhrlninl 

RELAY 

- 

'TENTATIVE TOTAL 

STEAM RAMP RATE (Ib!hrlmin) 

\ 

Figure 4.2-32. Simplified Blocl.: Diagram 

RECEIVER 

STEAM 

FLOW + 

(Iblhrl f 

\ 

SUMMER . 

SUMMER 

- 

- +_ 

c 

TOTAL STEAM FLOW 

Ilblhrl 

- - MINIMUM 

VALUE 

r 

SCALE 

CONOlTlONEO 

+ LIMITER ERROR SIGNAL SCALE 

SUMMER - NETWORK (GAINCON. 

STANT = 3) 

ELECTRICAL OUTPUT 

- ImWeJ 

- 
I LEGEND I - - m -- GENERATOR OUTPUT MWE 

TOTAL STEAM F(PW 105 LBIHR. 

####~n##~~~~*@ BOKER STEAM FLOW 105 LBIHR. 

I WflflflH- RECEIYER STEAM FLOW 105 LBIHR. 

9 I @ = RECEIVER INCIDENT RADIATION MWTH 

Figure 4.2-33. 100 Percent Transient Summer Solstice 
LEGEND 

E - s m sr cxmaaroR OUTPVT MWE 

TOtAl.STEAM FLOW 106 LBIHR. 

88888I@@m@@t**@@ BOILER FIEAWFLOW 105 LBIHR. 

IflfldH- RECHYER STEAM FLOW 105 LBIHR. L = 8 t m 8 a RECEIVER.INCIDENT RADIATION MWTH 
11 - 11 1 QENERATOR OUTPUT MWE 

TOTAL STEAM FLOW 105 LBIHCI. 

@##I##I#I#@I#I## BOILER STEAM FLOW 105 LBIHR. 

WHM'H- RECEIVER STEAM FLOW 105 LBIHR. r I I r r RECEIVER INCIDENT RADIATION MWTH 

TIME, 

MINUTES 

Figure "1.2-35. 10 ?erc?nt Transient Summr Solstice - 
l - m e l GENERATOR OUTPUT 

TOTAL STEAM 

LEGEND 

FLOW 105 

MWE 

LBIHR. 

1 0~~8818888888118 BOILER STEAM FLOW 105 LBIHR. 

wH..H- RECEIVER STEAM FLOW 108 LBIHR. - 8 I I RECEIVER INCIDENT RADIATION MWTH 

Figure 4.2-36. 100 Percent Transient 25 MWe Solar - 25 MWe Fossil 
I - I m I I GENERATOR OUTPUT MWE 

TOTAL STEAM FLOW 105 LRIHR. 

1111111111111111 BOILER STEAM FLOW 105 LBIHII. 

-1HHfl- RECEIVER STEAM FLOW 105 LBIHR. 

FigJre 4.2-37. 511 'ercent Transient 25 MWe Solar - 25 MWe Fossil 
-I 

I 

- LPI - GENERATOR OUTPUT MWE 

TOTAL STEAM FLOW 105 LBIHR. 

1111111111811111 BOILER STEAM FLOW 105 LBIHR. 

wm- RECEIVER STEAM FLOW 105 LBIHR. 

= 8 m 8 .I 1 = RECEIVER INCIDENT RADIATION MWTH 

TIME. 

MINUTES 
the model indicates it will take about six minutes for the fossil boiler to 

bring the turbine generator back up to the initial output of 50 megawatts. The 

performance is based upon boiler steam and g.enerator ramp rates of 20 percent 

per minute. If the generator ramp rate is limited to five percent, about 

25 minutes will be required to recover the full 50 megawatt output. 

The model indi cates qui te good system response to the 50 percent and 10 percent 

insolation transient, a1 though in the cases of the 10 percent transients, there 

are minor power overshoots (1.2 megawatts at noon summer solstice insolation 

conditions). The maximum power droop for the 50 percent transient during maximum 

insolation conditions is about 16.7 megawatts. In general, ,the initial output 

was re-established within five minutes of the beginning of the transient. 

While the overshoots and the magnitudes of the maximum droop are certainly significant, they do not pose problems that would jeopardize the successful operation 

of the solar/fossil hybrid power plant. Magnitudes of the droop and overshoot 

can be reduced or their effects made more tolerable by implementation of one or 

more of the following procedures: 

Undershoot 

Reliance is on the spinning reserve in the grid. It is expected that PNM will 

have about 100 megawatts of capacity available by the time the Reeves Unit No. 2 

solar/fossil hybrid plant is operational. A 34.2 megawatt drnnp w0111d not have 

serious detrimental effects. 

It is expected that higher boiler ramp rates will be allowed. This will' improve 

the system's transient response and reduce the magnitude of the power droop. 

With some solar/fossil hybrid plants it. may he necessary to use rcmotc sensors 

to anticipate cloud shadow passage in order to increase boiler firing with an 

acceptable ramp rate and simultaneously defocus heliostats prior to the incidence 

of the cloud shadow on the collector field. In this manner, the power droop 

could be reduced or even eliminated. This concept is discussed in Section 4.9 

of this Report. 
Overshoot 

A motor operated steam dump valve will be provided for Reeves Unit No. 2 in order \ 

to prevent steam overpressure and/or generator overload. 

I 

I Higher allowable boiler and turbine ramp rates will improve the transient response I 

of the system and reduce the power overshoot. , 

1 The unit could be operated at slightly reduced load during periods of cloud cover 

in order to prevent operation of the steam dump valve. 

With some hybrid units, it may be benefi'tial to anticipate cloud shadow passage 

and defocus he1 iostats (sirnul taneously increasing the boiler fi ring rate) prior 

to actual shadowing of the fie1 d. When the cloud shadow has passed, the boiler 

firing rate would be reduced simultaneous with a refocusing of heliostats. In 

this manner the power overshoot could be reduced or eliminated. 

4.2.4.3 STARTUPISHUTDOWN PROCEDURES 

This section describes typical startup and shutdown procedures that woul d be 

required for the several modes of operation of the solar/fossil boiler portions 

of the repowered Reeves. Unit No. 2. 

The valve numbers mentioned in the procedures are those used on flow diagrams 

P3-1 and P3-6. 

It is expected that information developed during the detail design phase of the 

project will add greatly to the details of these p.rocedures. 

(a) Operating Mode-: Solar only start, overnight shutdown 

-- References - -. --, 

(1) Reeves Unit No. 2, Plant Data Book, Volume 4, "Turbine Generator 

(2) Central Receiver Solar Thermal Power System, Pi lot Plant Preliminary 

Design Report, Volume 4, Receiver Subsystem, SANl1108-814 
Procedure 

(1 ) S t a r t : c i r c u l a t i n g water pumps and circulate water through .the condenser 

(2) Open a1 1 turbine drains 

(3) Close motor operated val ves (MOV) 

MOV-1-1 

MOV-2-1 

MOV-2-6 

MOV- 3-6 

MOV-6-6 

MOV-10-6 

MOV-11-6 

MOV-12-6 

Fossil boiler steam block valve 

Receiver steam to auxiliary steam system 

Receiver feed pump 2B shutoff valve 

H. P. Heater No. 7 bypass val ve 

H.P. Heater No. 6 bypass val ve 

Receiver steam downcomer block val ve 

Recei ver ,steam hl nck val ve 

Receiver warmup 1 ine block val ve 

(4) Open motor operated valves 

MOV-1-6 Receiver feed pump 2A shutoff valve 

MOV-4-6 H.P. Heater No. 7 block valve 

MOV-5-6 H.P. Heater No. 7 block valve 

MOV-7-6 H.P. Heater No. 6 block valve 

MOV-8-6 H.P. Heater No. 6 block valve 

MOV-9-6 Receiver feedwater in1 et bl ock val ve 

(5) Start receiver feed pump 2A to minimum flow of pump; 15 percent of 

design flow must flow through the receiver. If it is elected to run 

on pump 2B, then open MOV-2-6 and close MOV-1-6. 

Circulate feedwater through receiver to receiver flash tank through 

PCV-1-6 gnd back to condenser through LCV-1-6. Set PCV-1-6 back 

pressure control valve to 425 psia. 

(6) Start condensate hotwell pumps and ci rculate cold condensate through 

L.P. heaters, deaerator and to receiver feed pump. Block valves at 

inlets to boiler feed pumps are closed to isolate fossil boiler feedwa t~r s ys tem 

(7) Gradually focus heliostats and increase heat flux to receiver. As 

feedwater turns to steam from the boiler/superheat panels limit steam 

temperature to about 500°F during the first 20 minutes of sunlight. 

This will provide approximately 50 degrees of superheat at 425 psia 

out of the receiver to the flash tank. 

(8) When steam temperature of a1 1 the boil erlsuperheat panels has reached 

500°F the recei ver control 1 er commands the steam temperature setpoint 

to change to 660°F. Focus additional he1 iostats to provide this 'hciat. 

PCV-5-6 Pressure control valve from flash tank to No. 6 H.P. 

Heater set to 55 psia 
PCV-4-6 Pressure control val ve from flash tank to No. 7 H.P. 

Heater set to 30 psia 

PCV-2-6 Back pressure control valve from flash tank to condenser 

set to 250 psia (flash tank pressure) plus line losses as: 

determined from operating experience 

(9) When 660°F steam has been reached at the exit of all the boiler/superheat panels, set the back pressure valve PCV-1-6 to the nominal 

operating pressure of approximately 1458 psia. 

(10) Set steam temperature to 800°F at a pressure of 1458 psia and gradually start opening MOV-10-6 to pressurize the receiver steam line. 

Focus additional he1 iostats to meet this requi remen t. 

(11) During overnight shutdown of the receiver, it should not be necessary 

to warm up the receiver steam 1 ine prior to admitting steam to turbine. It has been estimated that the receiver steam line will be at 

864°F after a 13-hour shutdown, 12°F ambient temperature and a 10 mph 

wind velocity. Initial testing will be required to verify steam line 

temperature after shut down and, if it is necessary to warm up the 

1 ine MOV-12-6 to the condenser can be opened. until receiver steam 

flow warms 1 ine to acceptable temperature. Close MOV-12-6 after 

steam line is warmed. 

(12) Open MOV-2-1, receiver steam to auxiliary steam system, after 800°F, 

1458 psia steam is established. This will allow receiver steam to 

'enter the Unit No. 2 auxiliary steam system for 'turbine seal steam 

condenser ai r removal and deaerator peggi rig. 

(1 3) Turn on turbine seal steam to the No. 1 gland and regulate to maintain 20 psig. 

(14) Turn on seal water to L.P. turbine glands only. Seal water to H.P. 

turbine seal glands is turned on when approximately 70 percent of 

normal operating speed has been reached. 

(15) S.tdr.1 d.ir ~'e~lluviil equipment and establish a 10- to 20-inch ot mercury 

vacuum in the condenser. 

(16) Start steam driven auxiliary oil pump and shut down five H.P. motor 

driven oil pump. 

(17) Check that a1 1 turbine drains are open and steam 1 ines are free from 

wa lti r-. 

(18) When a vacuum of 18-inches Hg has been obtained, open throttle valves 

just enough to get turbine speed above turning gear speed. 

(19) Keep turbine rolling at low speed (approximately 100 to 400 rpm) with 

the vacuum 20-inches or better for about 20 minutes to a1 low turbine 

parts to bec-ome. partly heated. 
(20) Close drains from pressure zones when it is assured that a1 1 water 

has been removed. 

(21 ) Check governing val ves for operation. 

(22) Bring unit up to speed slowly. During this time a1 low the vacuum to 

increase gradually so as to obtain full vacuum when turbine reaches 

full speed. 

(23) At 70 percent normal speed, turn on seal water to high pressure glands. 

(24) Turn on water to oil and generator gas coolers. 

(25) Change set point on receiver outlet steam to 1000°F and set 950°F for 

outlet of receiver steam attemperator. Gradual ly focus additional 

heliostats to bring receiver steam temperature up to design. 

(26) Synchronize and add three to five percent load. Hold at this load 

until thro-ttl e temperature is stable at 950°F or approximately 

18 minutes for 13-hour shutdown, whichever is longer. Limit exhaust 

casing temperature to 175OF. At ttlis point approximately half of 

receiver steam flow will be flowing through the turbine, the other 

ha1 f will be passing through the receiver flash tank. 

(27) Bring turbine up to full capability (52 minutes for 13-hour shutc!own)'. 

At this point no steam will be going through the flash tank and 

PCV-1-6 is signaled to close as turbine throttle valves control 

throttle pressure to 1250 psia. 

Start-Up Time After Overnight Shut Down 

Start Fur~ction 

Events 1 to 6 

Event 7 

Events 8 to 11 

Events 12 to 18 

Event 19 

Evnets 20 to 24 

 vent= 25 

Event 26 

Evcnt 27 

(Prior to Dawn) 

20 

45 

2 5 

2 0 

2 0 

15 

18 

52 

- 

TOTAL . . .. .. . . 215 
(b) Operating Mode: Normal shutdown, solar only 

Procedure 

(1) The steam temperature set point of 1000°F is maintained and the flow 

to each of the receiver panels decreases as the heliostats are sequential ly slewed away from the receiver and the energy level decreases. 

(2) As turbine throttle flow decreases, 1 oad on turbine will decrease. 

(3) Below approximately 15 percent of design maximum receiver flow steam, 

temperature will be come unstable. Throttle valves to turbine will 

be signaled to close. 

(4) Open a1 1 turbine drains. 

(5) Put turbine on turning gear. 

(6) Automati cal ly c1 ose MOV-11-6 and 10-6 ; whenever receiver out1 et temperature becomes less than 950°F, PCV-1-6 will start to open through the 

flash tank 

(7) Reduce receiver pressure to 425 psia. 

(8) As insol ation energy continues to drop, all receiver boiler panel tempera ture control val ves wi 11 reach minimum flow posi tion and recei ver 

will fill wi.th sub-cooled water. 

(9) Shut down receiver feed pumps, condensate hotwell pumps and ci rcul ating water pumps. 

(c) Operating Mode: Solar system start after overnight shut down; turbine 

operation on fossil boiler 

References 

(1) Reeves Unit No. 2, Plant Data Book, Volume 4, "Turbine Generator 

(2) Central Receiver Solar Thermal Power Sys tem, Pilot Plant Preliminary 

Design Report, Volume 4, Receiver Subsystem, SAN/1108-814. 

(3) Systems Startup/Shutdown Procedures ; solar only start. 
Procedure 

(1) Close Motor Operated Valves 

MOV-2- 1 Recei ver steam to auxi 1 i ary steam sys tem 

MOV-2-6 Receiver feed pump 2B shutoff valve 

MOV-3-6 t1.P. Heater No. 7 bypass val ve 

MOV-6-6 H.P. Heater No. 6 bypass valve 

MOV-10-6 Recei ver steam downcomer block val ve 

MOV-11-6 Receiver steam block val ve 

MOV- 12-6 Recei ver warmup 1 i ne bl ock val ve 

(2) Open motor operated valves 

MUV-1-6 Kecelver feed pump 2A shutoff valve 

MOV-4-6 H.P. Heater No. 7 block. val ve 

MOV-5-6 H.P. Heater No. 7 block valve 

MOV-7-6 H. P. Heater No. 6 block val ve 

MOV-8-6 H.P. Heater No. 6 block valve 

MOV-9-6 Receiver feedwater inlet block valve 

(3) Start receiver feed pump 2A to minimum flow of pump; 15 percent to 

2U percent of design flow must flow through the receiver. If it is 

elected to run on pump 2B, then MOV-2-6 is open and MOV-1-6 is closed. 

Circulate feedwater through receiver to receiver flash tank through 

PCV-1-6 and back to condenser through LCV-1-6. Set PCV-1-6 back pressure control va1 ve to 550 psia. 

(4) Reduce load on turbine'i f turbine is at 100 percent load to about 

80 percent load to accommodate minimum flow through the receiver. 

(5j Gradually focus he1 iostats and increase heat fl ux to receiver. As 

feedwa ter turns to steam from the boi 1 er/s uperhea t panel s 1 i mi t steam 

temperature to about 500°F during the first 20 minutes of sunlight. 

This will provide approximately 22°F of superheat at 550 psia out 

of the receiver to the flash tank. 

(6) When steam temperature of a1 1 the boil erlsuperheat panels has reached 

500°F the receiver controller commands the steam temperature set point 

to change to 660°F. Focus additional heliostats to provide this heat. 

PCV-3-6 Prcssure control valve from flash tank No. 6 H.P. Heater 

set to match the numher one high pressure t.~lrbine extraction steam point. This could be a maximum of 80 percent 

turbine load or about 320 psia. 

PCV-4-6 Pressure control valve from flash tank to No. 7 H.P. 

Heater set to match maximum turbine extraction steam 

pressure about 160 psia at 80 percent turbine load. 

PCV-2-6 Back pressure control valve from flash tank to condenser 

set to approximately 350 psia. 
(7) When 660°F steam has been reached at the exit of a1 1 the boiler/superheat panels, set the back pressure val ve PCV-1-6 to the nominal 

operating pressure of approximately 1458 psia at 15 percent to 

20 percent receiver steam flows. 

(8) Set steam temperature to 800°F, at a pressure of 1458 psia and gradually start opening MOV-10-6 to pressurize the receiver steam line. 

(9) Set steam temperature to 1000°F at outlet of receiver and operate 

until steam temperature is s tab1 e. Focus additional he1 iostats to 

provi de heat. 

(10) Open MOV-12-6 to warm steam line up from 864°F to about 950°F if 

required based on initial operating experience. Close MOV-12-6 after 

receiver steam line is sufficiently warmed. 

(1 1 ) Set re~ei ver attemperator control to 950°F. 

(1 2) Gradual ly' open MOV-11-6 to a1 1 ow receiver steam to mix wi th fossi 1 

boiler steam, PCV-1-6 will gradually close, shutting off flow to the 

flash tank. 

(13) At this point the receiver will be supplying 15 percent to 20 percent 

of the total steam fl ow and the fossi 1 boil e r w i l l be supply.ing a 

maximum of 85 percent to 80 percent flow. 

(14) Gradually focus more heliostats on the receiver to increase receiver 

steam flow to its maximum, dependent on the current solar insolation. 

The fossil boiler combustion control system will decrease oil flow to 

the burners to maintain throttle pressure at 1250 psia. At maximum 

design receiver flow, receiver steam pressure will be approximately 

1458 psi g. 

(15) Set desired turbine load based on maximum receiver steam flow and 

parall el fossil boiler operation. 

Start-Up Time After Overnight Shut Down 

Start Function Time (minutes) 

(1) Events 1 to 4 

(2) [vent 5 

(3) Events 6 to 8 

(4) Event 9 

(5) Event 10 

(6) Events 11 to 13 

(7) Events 14 and 15 

(Just prior to dawn) 

2 0 

TOTAL 
(d) Operating Mode: Solar only shutdown, fossil fuel operation continuing 

Procedure 

(1) The receiver steam temperature set point of 1000°F is maintained and 

the flow to each of the receiver panels decreases as the he1 iostats 

are sequential ly slewed away from the receiver and the energy level 

decreases. 

(2) As receiver flow decreases, the turbine throttle valves will close 

reducing l o a d o r , depending on Toad requi rement, the fossil boiler 

will increase steam flow. 

(3) At 15 percent receiver steam flow MOV-11-6 and 10-6 will close and 

PCV-1-6 will open dlrectlng receiver steam through the flash tank. 

I 

(4) Reduce receiver pressure to 425 psia. 

(5) As incnlation energy continues to drop, a1 1 receive!. builtlr. pilrwl 

control valves wi l l reach minimum flow position and receiver will 

fill with subcooled water. 

(6) Shutdown receive,r feed pump 2A and close MOV-1-6. 

Operating Mode: Solar systems start after long shut down. Fossil boiler 

shutdown. 

References 

(1) Reeves Unit No. 2, Plant Data Book, Volume 4, "Turbine Generator." 

i2) Central Receiver Solar Thermal Power System, Pilot Plant Prsl iminary 

Design Report, Volume 4. Remi ver Subs,ys tern, SAN/1188-R/4. 

( 3) Systems Startup/Shutdown Procedures ; solar only start. 

(4) Receiver cool down/warmup, Section 4.2.4.1 (f) of this Report. 

Procedure 

1 ) -through- 

(6) Events 1 to 6 identical t.n Reference (3). 

(7) Ci rcul ate condensate through system and throuyh condensate polishing 

equipment, 1 ocated between the hotwell pumps and the No. 5 L.P. 

Heater, until water quality is acceptable for receiver operation. 

(8) -through- 

(11) Events 8 to 11 identical to Reference (3) Events 7 to 10. 
(12) Slowly open MOV-12-6 to the condenser for warm up of tl-ris steam line 

to approximately 800°F. This shoul d take approximately five hours 

when ambient temperature is 12°F and wind speed is 10 mph, based on 

the analysis of Reference (4). A better solution to this warmup 

problem would be to keep. the steam 1 ine warm during extensive shutdown using auxiliary steam from the Units No. 1 , 2 or 3. This sol ution may adversely affect the economic analyses since oil would be 

expended during any shut down except for an overnight shut down. 

(1 3) Close MOV-12-6 after steam line is warmed. 

(29) Events 14 to 29 identical to Reference (3) Events 12 to 27. 

Startup Time After Long Shut Down of Solar System 

Start Funcelon Tiine (minutes) -.- 

(1 ) Events 1 to 6 (Prior to Dawn) 

(2) Event 7 (Prior to dawn) 

(3) Events 8 to 11 20+ 

(4) Event 12 30 0 

(5) Events 14 to 29 90+ 

- 

TOTAL . . . . . . . . 410 

4.2.4.4 SOLAR SUBSYSTEM MAINTENANCE 

This section describes the general maintenance plan required for the solar systems 

equi pmen t . 

RECEIVER 

It. is anticipated that a detailed receiver maintenance plan wi r 1 be developed by 

the receiver manufacturer during the construction of the receiver. 

This plan will basically consist of: 

(R Maintenance of the high absorbi tivi ty of the receiver face by a 

scheduled repainting of the panels. 

Replacement of individual pane'ls as required for necessary repair. 

e Mechanical and electronic repair of control systems. This would 

i ncl ude rep1 acement of el ectroni c ci rcui t boards and servi ci ng of 

control valve actuators. Also replacement of filters at inlet of 

absorber panel s . 
e Structural maintenance consisting of repainting for rust 

prevention. 

HELIOSTATS 

The maintenance program for the he1 iostats will consist of the following i tems: 

a~ Mirror Washing - The washing procedure will be based on the 

cri teria as developed by the Sandia Laboratories in A1 buquerque 

during the heliostat testing program. 

Drive Units - Periodic 1 ubrication and inspection for wear and 

corrosion. 

Maintai nabil i ty for the controls and instrumentation is achieved by designing a 

high degree of standardization and modularity throughout the control systems. 

Iden tical hardware components and types of hardware are used wherever practical 

such as cables, connectors, controllers , instruments, etc., incl uding instrument 

and control signal types. This design allows for easy maintenance. Electronic 

modules can be easily replaced and elements subject to wear such as pneumat'ic 

control lers, ac.tuat.ors and pri nterqs can be conveniently servi ced or rep1 aced. 

4 .?.4.5 PRESENT PLANT MAINTENANCE 

The Reeves Unit No. 2 is approximately 30 years old atid has been under a planned 

mhin tenance program during this time, The currmt 11lai n tenance program has been 

satisfactory as evidenced by the good overall condition of the plant. 

It is ex~ected that this maintenance program will be continued during the solar 

repoweri ng opera tion of this uni t together wi th the addi tiona.1 requi relllents as 

defined in Sectlon 4.2.4.4. 

The resul ting overill 1 pl ant maintenance program will integrate the solar portiorl 

of the pl ant wi th the existing equipment maintenance pl ant to provide a maintenance schedule compatible wi th comporlen t and sys tem requi remen ts and to mi ni mi ze 

pl ant down ti me. 
4.3 CONTROLS AND INSTRUMENTATION DESIGN 

A control system desi gn for solar hybrid repowering applications differ from a 

design for conventional plant control systems in two ways. First, it is not an 

entirely new system, and second it is not simply a retrofit of an old system. 

A repowering control system design calls for an integration of an existing system 

with a new technology. 

Controls and instrumentation design is present in two parts: Section 4.3.1 builds 

the control system archi tecture and discusses its components. Section 4.3.2 

appl ies this system to pl ants that are candidates for repowering,rrand parti cularly to the Reeves Station Unit No. 2. 

REPOWERING CONTROL SYSTEM DESIGN REQUIREMENTS 

Figure .4.3-1 is a simplified process and instrumentation diagram (P & ID) for 

control system purposes. This diagram may be referred to throughout the controls and instrumentation design report. It shows the principle control systems, 

instrumentation, control led process variables, and control devices. 

Solar hybrid repowering control sys tem desi gn requi remen ts provide for the safe 

and econo~r~ic production of electricity under a1 1 plant operating modes: 

o Fossil Boiler Only 

e Combined Solar and Fossil 

The plant should first be able to operate on fossil fuel as it now does as though 

no changes had been made. The system must be able to meet the generation needs 

of the utility. Second, it should be able to produce electricity on solar power 

alone. Third, and most important, it should operate and produce electricity in 

a combined solar and fossil or hybrid operating mode; thereby providing for the 

continuous and stable produc.tion of electricity, night or day, fully utilizing 

solar energy when it is available. 

Inherent in all solar hybrid repowering control system designs will be the requirement 'lo coi1Lru1 the plant in a1 1 of the above described operating modes under a1 1 

condi tions of startup, shutdown, transient, steady state and emergency operation. 
COLLECTOR FIELD 

CONTROL SYSTEM 

CONTROL 

SYSTEMS 

Figure 4.3-1. Simp1 i fied P&I Diagram for Control Systems 
CONTROL SYSTEM DESIGN PHILOSOPHY 

During control system conceptual design several philosophies or design cri teria 

were used: 

e Generate Electricity 

The control system must provide for the safe and economic production of electricity. 

0 Automatic with Operator Override 

Basic plant operation should be automatic with operator override 

capabil i ty. 

0 Maintain Existing Plant Control Philosophy 

Certain control philosophies' exist in virtual ly a1 1 power plants. 

Red indicating lights indicate equipment or process in operation, 

green indicating 1 ights indicate equipment or process not in 

operation, etc. These control phi1 osophies are power industry 

standards and should be maintained in accordance with those in 

effect at the station to be repowered. 

@ Minimize New Control Technology 

An effort should be made to utilize 'existing contro-1 technology 

and conventional power pl ant control sys terns. New control technologies should be added only if necessary to provide control of 

new solar technologies. 

Mini mi ze Existing R1 an t Modi fi cations 

The existing control systems is a candidate plant for solar 

repowering work. They provide for the generation needs of the 

utility; their integrity should not be compromised. 

e Simplicity . . 

A control system design must be free from over-complication, It 

must provide for plant operation by plant operating personnel 

without requiring excessive training beyond that normal ly 

requi red. Only the degree of sophis tication absol utely necessary 

for plant operation should be provided in a control system. The 

opportuni ty for sol ar electric power generation success shoul d 

not be compromised by overly compl i cated control systems that do 

not work we1 1, or do not work. 

4.3.1 SOLAR CONTROL DESIGN 

Thi's subsection describes the solar control system in terms of the basic design 

approach and the principal subsystems within the overall control system. 
4.3.1.1 CONTROL SYSTEM DESIGN APPROACH 

The solar hybri d repowering control sys tem desi gn approach incorporates the 

fol 1 owing features : 

e Single operator control from a single control room 

e Integrated Supervisory Con tm1 of all subsystems (Master Control ) 

s Coordinated control of a1 1 subsystems (distributed anal ong control ) 

~ndependent subsystem control allows plant operation without 

master control 

e Prirnt! operating mode is automatic with operator override 

Minimize the cascade effects of single point failure 

The general design approach is the utilization of a microprocessor based analog 

control system in con junction with a standard, proven, off-the-she1 f power plant 

computer. In recogni zing the problems experienced by the util i ty industry with 

the re1 iabil i ty of the man-machine int~rface structure of computcri zed sys terns, 

it is considered that an analog control system architecture with a microprocessor base provides the best integration of the plant computer, solar subsystems 

and existing plant subsystems. Solar repowering control systelll architecture Is 

shown in Figure 4.5-2. It is considered that this b.asic approach to an overall 

control system design will be amenable to all the fossil plant candidates for 

solar repowering, A morc compl cte picture sf co~~tvol and niu11 i Lur-iriy sys terrls 

interfacjng js portrayed in Figure 4.3-3. The task of a detailed plant design 

will be to completely identif,~ and specify in detail a1 1 of the system 

interconnections. 

Control systems hierarchy will be as follows : 

Fully Automatic Master Cnnt.ro1 (MCS) 

e Seml-Automatic Loordinated Control 

e Independent Subsystem Automatic Control 

Manual Control 

e Safety Interlock and Emergency Trip 
Master Control is provided through the digital plant computer. Should the 

computer fail , semi automa tic control is provided in the microprocessor based 

analog control . In this mode, coordinated control between the independent subsystems is done by the distributed analog system. Independent subsystem controls enable each subsystem to operate in an automatic mode. However, coordination of the subsystems could be accomplished manually by the plant operator. 

Additional ly each system is provided with manual controls from the control room 

and, in some cases, locally. Operator manual override capability will be provided at each level of control. Emergency trip and interlock systems will be 

implemented automatically in all cases where it is necessary to insure plant 

operating safety and to prevent equipment damage. This system basi ca11y conforms 

eo power industry standards. 

4.3.1.2 PRINCIPAL CONTROL SYSTEMS 

Conceptual design of the principal control systems is divided into two parts. 

Section 4.3.1.2 discusses the Master Control Computer, Distributed Analog Control * 

System, Collector Control System and Receiver Control System. These are the new 

control systems that must be added to a power plant for solar hybrid repowering. 

Section 4.3.2 discusses existing principal control systems including Boiler and 

Combus tion controls and Turbine-Generator controls. 

MASTER CONTROL COMPUTER 

Hardware confi guration for the master control computer is shown in Fi gure' 4.3-4. 

This basic hardware configuration is a typical power plant computer and is identical to plant computers currently in widespread use across the nation. Power 

plant computers are commercially avail able from any one of several manufacturers 

and feature software and hardware designs that are both proven and accepted by 

the utility industry. 

Functions performed by the master control computer are: 

e Supervisory Pl ant Control 

e Integrate Control of all Subsystems 

e Process Data Acquisition 

e Di s pl aylMoni tor/Al arm 
------ - r ---- 

I COLLECTOR FIELD 1 

I . HELIOSTATS 1 I RECEIVER 1 

I 

-- 1 

DISTRIBUTED 

* MASTER CONTROL 

DATA ACQUISITIC~N 

,START-UP I TURBlNElGENERATOR I 

PROCESS 

CONTROL 

DATA 

PATHS 

PATHS 

mis-a~t 

- 

Fi gure 4.3-2. Solar Hybrid Repowering Control System 
COLLECTOR D RECEIVER GENERATOR 

F l E t D 

INPUTS 

(ALARMS) 

(PLANT AUXILIARY 

PNEUMATIC 

CONTROLS 

DISTRIBUTED 

COMPUTER 

ANNUNCIATOR 

SUPERVISORY 

RECORDERS 

GENERATORITRANSFORMER 

PROTECTION 

Figure 4.3-3. Control and Monitoring Systems [nterface 
Fi gure 4.3-4. Soler ?ower Plant Computer System 

AN4LOG TI3END RECORDERS 
Software 

A1 though data acquisi tior software for power plant applications is commercially 

available, the master ipntrol system and heliostat control system software will 

be enti rely developmental . It shoul d be noted that developmental software, 

especially that requiring untried control a1 gori thms is iterative 'in nature, 

difficult to produce, and can be the critical path on a project. 

Hardware 

The basic equipment supplied for a Solar Power Plant Computer System consists of 

the following: 

e A central processor 

e An engineer's console, which includes an engineer's printer and 

a CRT 

8 An operator's console, which Sr~cl udes a set of function pushbuttons and a set of display pushbuttons called a matrix (A CRT 

is included with the operator's console) 

e Three CRT' s on the BTG panel : one for a1 arms, one for uti 1 i ty 

messages, and one for graphic displays 

e Strip chart or analog trend recorders that are dri,ven by the 

plant computer 

Printers: one for alarms and one for general or utility messages, plus a 1 ine printer for large amounts of output. as when 

programming work is being done 

e A bulk memorysystem, which could be either discor drummemory, 

or a combination of both 

e A programmer's console, which includes a printer and a magnetic 

tape system for off-line memory 

Hardware for reading analog inputs such as flows, temperature, 

pressure levels and electrical inputs. These are processed 

through the analog to digital converter for use by the cnmp1.1t.er 

syrtern. The necessary di gi tal inputs, such as contact closures, 

and pulses. 
Functions 

The function- of the engineer's console is to provide the plant engineer with the 

capability of communicating with the computer system in a location remote to the 

main control room so that there is no interference of the engineering personnel 

with the operation of the plant. 

The functions available to the engineer on his console are: 

0 The abi 1 i ty to add or change analog and di gi tal inputs 

e Cali bration of inputs 

Ability to build special logs 

The facility to initiate the running of special calculation sets 

Interface with the computer a1 gori thms such as : 

- Steam tables 

- Ari thmeti c functions 

e All other functions normally available to the operator 

The operator console functions are as follows: 

e Printing and display of all computer inputs and outputs in various 

modes 

e Irer~d per1 dlbpldy~ ut' all analoy .illputs 

Printing or displays of summaries such as all analog inputs and 

all digital inputs 

e Group displays or prints of inputs to the system grouped by equipment. ar function 

e Calling of graphic displays that represent various equipment 

groups or plant systems 

e Any control functicns that may be associated with the computer 

sys tem 

The function of the programmer's console is to provide for maintenance of the 

program in the system plus providing facility for adding programs to the computer 

system and the abil i ty for maintaining and updating a1 1 the data files in the 

sys tem. 
Another function available on a computer system is a historical data, storage and 

retrieval system. This is a system that gathers data continually throughout the 

system operation and stores it for 1 ater retrieval by engineering personnel . This system is useful in determining changes of operating parameters over a long 

period of time or for recall of information during previous periods of abnormal 

operation. 

CRT Di spl ays 

The three CRT's in the control room that display information to the operator are 

as fol lows : 

e The a1 arm CRT - displ ays a1 arms to the operator as they occur, 

wJ LR fl aShlng val ues so th'at the operator knows whi ch a1 arms have 

not been acknowledged 

e The utility CRT - displays messages to the operator, pl us group 

displays and trending of inputs 

e The graphic CRT - displays graphics that represent pieces of 

equipment or systems or bar charts or graphic of various system 

pa ramete rs 

Automatic Functions 

Automatic functions that normally occur without any operator requests or intervention are as follows: 

e Scanning of all inputs 

e Alarming of any inputs that go beyond prescribed bounds 

a Automatic calculations; averages of several inputs or temperature 

di fferences 

Sequence of events summaries. involving printing of a series of 

events in the order in which they occur with up to one mill isecond resolution so that technical staff can determine : 

- That events happen in the proper order 

- Which events caused an outage 

e Hourly, daily and monthly periodic logs that are used both by the 

opera ti ng personnel and the engineering personnel 
A post trip review that provides information concerning the 

status of inputs for a period before and after a trip 

o Automatic monitoring of pieces of equipment, which provides 

information as to amounts of time the equipment has run, number 

of starts, any a1 arms about that equipment, possible permissi ves 

before start of equipment 

Alarm Philosophy - 

The basic alarm philosophy of a computer system is: 

e To provide instant information to an operator in a format that 

is easily understandable by him 

Q To provide hard copy of all alarms for later diagnosis 

To provide for further discrimination of information on alarms 

for those alarms normally on an annunciator system 

DISTRIBUTED ANALOG CONTROL SYSTEM 

The requi re'ment for the addition of a distributed analog control system. results 

from the need to provide control for new control loops as well as the need to 

provide an interface between existing piant control systems and new solar subsystem control . Functions performed by the analog sys tem incl ude : 

e Semiautomatic coordinated control 

e Control sol ar/fossil process interfaces 

Interface new solar and existing fossil control systems with the 

master control computer 

System cabinets for the distributed analog control system will be located in the 

logic room addition as shown on Stearns-Roger Drawing No. L-22929, Sheet No. 61-3. 

A control console and CRT interface will be located on the BTG addition section. 

m Distributed Analog Control Definition 

Analog control systems have always existed in power plants and presently exist in the form of both pneumatic system and hardwired 

electronic systems. The term "distributed" denotes that a1 1 

elements of the system are not physically located together. Basic 

components of the analog control system incl ude : 
- Process Transmitter (PT, TE, LT, etc.) 

- PID Controller (Proportional , Integral , Deviative) 

- HandIAuto Station (Operator Interface) 

- Actuator (Control valve, dampers, drives, etc.) 

These elements are schematically shown in Figure 4.3-5. The process transmitter is typically locally mounted at the process 

measurement point. The actuator is also mounted locally on the 

control device, typically a control val ve, damper, etc. 

For simple control loops such as feedwater heater level controls, 

set point adjustments and controllers are also mounted locally. 

Typical val ve control1 ers incl ude gain and reset adjustments 

(proportional and integral ) . 

Set point controls and PID controllers for major control loops 

(such as boiler drum level ) are generally centrally located in a 

re1 ay room (pneumatic) or logic room (electronic) . Opera tor interface controls (HandIAuto stations) are located on the operator 

control panel (BTG board - Boiler Turbine Generator Control Panel ). 

Set point changes are in some cases made at the BTG board and in 

other cases are changeable only in the system cabinets or relay 

racks. 

Control algorithms or control transfer functions in conventional 

power.plant analog systems are provided in the PID controller. 

Gain control (proportional ) and reset rate control (integral ) are 

normally adjusted' during plant start up. Derivative action and 

other compl icated control transfer functions are sel dom used, or 

required in power plants. Controller reset rates and gains are 

adjusted at some time during plant start up. Once the control 

system is tuned, calibrated and performs its functions, the settings are not likely to be changed. 

State-of-the-art process plants are util i zing microprocessor based 

el ectroni c analog control systems. Such systen~s are currently 

avail able from several manufacturers and new suppl iers are appearing on the market with increasing frequency. 

The use of a microprocessor based analog control system in a 

solar hybrid repowered power pl ant offers many advantages. The 

fi rst important advantage is control loop desi gn flexi bil i ty. 

Because a solar hybrid repowering plant of this design is a firstof-a-kind, requi rcmcn ts for control sys tern desi yn chanyes will 

inevitably be i den ti fled during start up and subsequent operation. 

The microprocessor base will a1 low most of these changes to be 

made through software rather than requi ring hardware modi fi cations. Secondly, the microprocessor base a1 lows di rect interface 

with the plant computer over a computer data bus. This is described in more detail in Section 4.3.1 -2. 
TYPICAL CONTROL LOOP (Single Element) 

6h PRESSURE TRANSMITTER 

~cs --- --- - - --- - 4-1 CONTROLLER 

MCS P 

Operator 

--------- MCS HAND AUTO STATION 

Fl PRESSURE CONTROL VALVE 

Operator SET POINT 

Figure 4.3-5. DSstri buted Analog Control Loop Elements 

Fixed 

A 
Thirdly, the microprocessor based analog system can be purchased 

in a conventional power plant configuration. This will a1 low 

conventional operator interface with the control sys tem and wi 11 

provide conventional hardware interfaces with existing plant 

systems as described in more detail in Section 5.3.1.2. 

Master Control Interface 

Conventional analog system control in the automatic mode provides 

for plant control through preset control transforms and a1 gori thms. As mentioned earl ier, these usually consist of proportional and integral control action. These settings are typically 

fi xed and not changeable from the control room. 

The combination of the microprocessor based analog system with 

the master control computer provides the potential for much 

better overall plant control because the computer has the ability 

to automatically change set points, control transfer functions 

and gain coefficients in the analog system based on an on-line 

knowledge of plant operating conditions. This is the essence of 

so called "Master Control" or supervisory control. 

8 Interface With Collector Subsystem 

The analog control system will develop a solar energy demand 

signal that will tell the collector control computer what the 

requirement is for solar insol ation on the receiver. This solar 

energy demand signal will be based upon receiver steam outlet 

temperature and the requirement for electrical generation. 

During combined solar and fossil boiler operation, the analog 

control sys tem wi 11 coordinate the sol ar energy demand wi th the 

boiler firing rate. This coordination in control will help to 

minimize or eliminate many plant operation transients. 

a Interface With Receiver Subsystem 

Receiver control consi ts of val ves that will be both electrically 

and pneumatically operated. Therefore, the analog control system 

and the receiver control system will both be electronic analog 

systems. It would be highly desirable for both systems to be 

purchased from the same manufacturer so that hardware interfaces 

could virtually be elimizlted. If the receiver subsystem is provi ded with a microprocessor based analog system, then software 

interfaces would also be eliminated. 

Tt~r analog control system wi 11 coordinate and interface the 

receiver subsystem wi th the turbine-generator. During hyt rsi d 

operation the analog control wi 11 coordinate both the turbinegenerator and the fossil boiler with the receiver. Since only 

steam temperature can be controlled by the receiver, the normal 

pl ant operating mode will be turbine throttle pressure control 

(see Section 4.3.1.2(7) during solar-only operation. During 

combined sol ar/fossil operation the fossil boiler wi 11 be used 

to stabilize plant generation output during solar transients. 
9 Exis tinq Combus tion Control Interface 

Existing combustion controls at Reeves Station Unit No. 2 are 

pneumatic. They are "Mini-Line Series" controls manufactured by 

the Bailey Meter Company (now Bailey Controls Company). The combustion control system is typical for most systems installed in 

power plants of this size and vintage. It consists of a "unit 

master station" that controls fuel and air flows based on steam 

pressure (boiler foll ow system), a three-el emen t drum level control, a steam temperature control , a deaerator level and pressure 

control, a hotwell level control and a cooling tower blowdown 

flow control . 

The existing penumatic controls at the Reeves Station Unit No. 2 

offer several advantages and disadvantages that have to be considered. For the conceptual design, a course of action was 

chosen from a 1 ist of a1 ternatives that ranged from leaving the 

present systern intact wi th no interfaces to completely replacing 

the en ti re system. 

Chief among the advantages of the present controls is that they 

work. The plant operates and produces electricity. Pneumatic and 

e l e c t r i c interfaces are easy with commerci a1 1 y avai 1 able, ec0nomi.c , and re1 iabl e hardware. 

A major disadvantage of the existing system is that the Bailey 

Meter Company Mini-Line Controls are no longer manufactured and 

that some repair parts are nu longer available. (This is not to 

say that pneumatic controls are no longer manufactured.) The 

existing relay racks are crowded and do not lend themselves to 

system modifications or additions. It is foreseen that thc 

entire system could require replacement before the 30-year design 

1 ife of the solar/fossil hybrid plant is expended. 

It first appeared dc?sira.ble to rep1 a.ce the existing system with a 

modern electronic system when solar hybrid repowering is added to 

the plant. However, a primary objective of the solar hybrid 

repowering design is to minimize all changes to the existing 

plant. Also from the utility point of view, it is a reasonable 

and justifiable objective to be able to operate the existing 

plant in its present condition as though there were no changes 

to the plant. The existing controls rr1ee.t these objectives, as 

well as providing for subsystem autonomy. 

The cur~ceptual design is configured on the baqis nf utilizing the 

existing pneumatic combustion controls and interfacing only as 

required. Conceptual desi gn has revealed three interfaces . First, the boiler demand signal , which presently comes from a 

steani throttle pressure transmitter, must come from the distributed ar~dlor~y control system during hybrid operation. Second, 

steam temperature control during hybri d operation becomes more 
compl i cated and the existing set point must be provided by the 

distributed analog system steam temperature control . [This is 

explained further in Section 4.3.1.2(7). 1 Third, receiver feedwater flow and condensate flow changes must be measured and added 

back into the DA level . control signal . 

A typical electronic-pneumati c interface is seen in Figure 4.3-6. 

The transfer element in a very simple interface could be a threeway solenoid val ve. When energized the combustion c o n t r o l s woul d 

receive a signal from distributed analog control via the electric 

to pneumati c converter. When de-energi zed, or upon power fai 1 ure 

to the control system, the boiler receives its signal directly 

from the pressure transmi tter. To provide bump1 ess transfer i t 

wi 11 be necessary to " tee-i n" to the pressure transmitter signal 

with a pneumatic to electric converter. The distributed analog 

control will then balance the control signals prior to transfer. 

Turbin~ Control Interface -- 

The existing turbine control systems will be replaced with a 

di gi tal el ectrohydraul i c control sys tern (a Wes tinghouse DEH System is discussed under Section 4.3.2.5). During solar-only plant, 

operation, the turbine throttle will be used to control stea;? 

pressure. The distributed analog control sys tem measures steam 

pressure and transmits a signal to the turbine controls. During 

hybrid operation the distributed analog control attempts to maintain throttle pressure by ramping the fossil boiler, but uses 

the turbine controls to maintain outside limits for steam pressure. 

This is discussed in detail in Section 4.3.1.2(7). Fossi ly-only 

operation may be done with the boiler maintaining throttle pressure (boiler fol lowing) with the existing .pneumatic control s, or 

the dis tri buted analog control system can provi de coordinated 

control. Under coordinated control the analog system would ramp 

the turbine controls and boiler simultaneously in response to load 

change demands that may be from the operator or from a dispatch 

si gnal . 

@ Solar Fossil Prncess Tnt~rfaces 

The addi tian of solar collector and receiver subsystems to an 

existing fossil power plant resul ts in several process interfaces 

that must be controlled. These interfaces require a new control 

system because they are not incl uded in any of the independent 

subsystem control sys tems. The distributed analog control system 

will provide for the control of these new control loops. 

The major prncess interface control loops arc throttle steam ternperature control , throttle steam pressure control , and receiver 

feed pump control . Detailed plant design may reveal other new 

control loops in addition to these. Conceptual design for these 

interfaces indicate that they should be control led as described 

below; however, it must be real ized that an actual design coul d 

be considerably different. 
ANALOG CONTROL SYSTEM 

STEAM 

PRESSURE 

TRANSMITTER MASTER CONTROL 

PNEUMATIC TO ELECTRIC 

---- 

----- DISTRIBUTED 

EXISTING 

FOSSIL BOILER 

COIVIBUS'TION CONTROL 

OPERATOR 

CONSOLE 

LEGEND 

CONTROL SYSTEM INTERFACE 

--;L/+ PNEUMATIC SIGNAL 

--- ELECTRIC SIGNAL 

Fi.gurs 4.3-6. Electronic-Pneumatic Interface 
Steam Temperature Control 

Steam temperature control is shown schemati cal.1~ in Figure 4.3-7. 

This system is designed to maintain the steam temperature at the 

inlet to the turbine at 950°F. .Since both' the solar receiver and 

the boiler supply steam to the turbine at various flows and temperatures the main controlled variable for this system is turbine 

in1 e t temperature . Turbine in1 et temperature is compared to i ts 

set point (950°F) and the error signal is acted upon by controller 

action to establish a set point for the boiler and solar attemperator outlet temperatures. 

For the boiler superheater outlet temperature control , this set 

point is compared to superheater .outlet temperature and any error 

is corrected through controller action to produce a boiler 

attemperator spray val ve control signal . 

The solar attemperator outl et temperature con'trol util i zes a feed 

forward receiver outlet steam temperature signal in addition to 

the turbine inlet temperature set point signal to produce a solar 

attemperator spray val ve control si gnal . Sol ar attemperator outlet temperature is compared to the turbine inlet temperature set 

poir1.L; si gnal . This produces a solar attempera tor temperature 

error signal that is acted on by controller action and added to 

the receiver outlet temperature feed forward signal. The feed 

forward signal is delayed in time by an amount proportional to 

steam flow to correct for the distance between the receiver and 

the solar attemperator. Handlautomati c stations provide for 

direct operator interface on both the solar attemperator spray 

val ve and the boi 1 er a ttemperator spray val ve. 

With the system as described above, it is possible to have the 

boiler superheater outlet temperature greater than 950°F and the 

sol ar receiver attemperator outl et temperature less than 950°F, 

the combination of the two temperatures when mixed equaling 950°F 

at the turbine. It is therefore necessary, in order to prevent 

any boiler damage from an over-.firing condition, to limit the 

boiler superheater outlet temperat~~re to about 975°F through 

the use of a high temperature limit in the boiler attemperator 

spray val ve control loop. This condition does not apply to the 

solar attempera tor because receiver steam temperature is controlled and limited by an independent control loop; i .e., the 

recei ver subsys tern control . 

Throttle Pressure Control -- 

Throttle pressure control is shown schematically in Figure 4.3-8. 

Throttle pressure control is designed for the simul taneous operation of the solar receiver and boiler. Changes in throttle pressure will be corrected for by the boiler controls when the boiler 

is in pperation. The system is designed to accept all of the 
RECEIVER SOLAR r--- 

OUTLET RECEIVER ATTETdlPERATOR TURBINE INLET SUPERHEATER OUTLET 

TEMP STEAM FLOW OUTLET TEMPERATURE TEMPERATURE 

C0N:BARATOR 

COMTROLLER 

-- 

SUMMATION 

OPERATOR . 

SOLAR AWEMPERATOR I BOILER ATTEMPERATOR 

SPRP Y VALVE SPRAY VALVE I 

LJ 

Fi #;ure 4.3-7'. Steam Temperature Control 
Figure 4.3-8. Throttle Pressure Control 

TURB'INE 

FIRST STAGE 

PRESSURE BOILER RECEIVER STEAM THRCiTTLE 

(STEAM FLOW) STEAM FLOW FLOW PRESSURE 

. RATIO 

4 b 

- 

SET POINT SET POINT 

LOW 

LIMIT 

1 

K+S 

SET POlNT 

HIGH 

LIMIT 

,j- THROTTLE PRESS 

GAIN ERROR LIMIT c/- 

4# 

Y 

TI TRANSFER 

SOLAR ONLY 

OPERATION 

PULSER 

I I 

I 

Y - INCREASE DECREASE 

BOILER DEMAND TO TURBINE 

TO EXISTING L'ONTROU CONTROL 
steam flow made available from the solar receiver. Turbine first 

stage pressure (steam flow) creates the initial feed forward 

demand. This feed forward demand is then characterized by the 

ratio of the boiler steam flow and receiver steam flow. If the 

boiler is contributing more to the total steam flow than the 

receiver, the system will provide for the correct amount of feed 

forward demand signal to the boiler controls thus minimizing any 

over and under firing from a-n unequal ratio of boiler versus 

recei ver steam fl ow. 

Throttle pressure is then compared to set point (1250 psig) and 

corrected through proportional and integral control action to 

vary the amount of firing rate required to maintain steam pressure at set point. Should the boiler be unable to maintain 

throttle pressure, a backup system utilizing a 100 psig deadband 

will control the turbine control valves if the throttle pressure 

drops to 1200 pounds or exceeds 1300 pounds. The boiler controls 

will continue to operate to bring the throttle pressure back to 

set point. During sol ar-only operation the turbine control a1 one 

will maintain throttle pressure. A transfer will shift the control signal to the turbine from the throttle pressure limit si gnal directly to the throttle pressure control signal. 

e Receiver Feed Pump Control 

Receiver feed pump control is shown schematically in Figure 4.3-9. 

Receiver feedwater is supplied hy two pumps, each capable of 

supplying 100 percent of the required feedwater flow. The control led variable is receiver feedwater inlet pressure at the hase 

of the receiver. 

Recei ver outlet temperature is control led through temperature 

control va'l ves on the receiver panels. The t o t a l i z a t i o n of these 

temperature control va'l ve posi tions generates a si gnal that 

represents receiver flow demand. Receiver flow demand is characterized with a function generator f(x) to match the pump and 

hydraul ic coup1 ing curve, and becomes the feed forward si gnal for 

the pump speed control. 

Receiver inlet pressure is compared to the receiver inlet pressure 

set point and an error signal is created. Controller action is 

applied to the error signal and it is then added .to the feed forward demand signal to correct the pump speed signal for any changes 

in receiver pressure. 

Gain changes in the control system correct control signals for 

sytem response changes during one or two pump operations. Additionally, when both Gumps are on automatic at the same time, the 

operator has the ability to bias one pump with respect to the 

other without creating any receiver inlet pressure changes. 
RECEIVER INLET 

PRESSURE RECEIVER FLOW 

TCV DEMAND 

OTHER VALVE 

#OF PUMPS.ON AU 

STATIONS 

COUPLING SPEED CONTROL 

Figure 4.3-9. Receiver Feed Pump Contaol 
COLLECTOR CONTROL SYSTEM 

The collector and heliostat control system architecture is shown in Figure 4.3-10. 

The final desi gn of the control hardware will depend on the system manufacturer's 

design, but will basically consist of a digital computer for collector subsystem 

control , mi cro.processor fie1 d .controllers , and he1 iostat controllers. 

The col 1 ector control computer must be an independent di gi tal computer separate 

from the master control computer. It must be provided with its own central 

processing unit, power suppl ies, and peripheral devices. This will ensure 

i ndependen t subsys tem autonomy as we1 1 as provi de i ncreased re1 i abi 1 i ty for 

plant operation. 

The purpose of the collector cqntrol system is to provide for positioning of the 

he1 iostats. During normal operation the computer synthetically tracks the sun 

using a control a1 gori thm based on accurate astronomical data. The computer 

makes corrections for atmospheri c conditions that affect sol ar insol a tion index 

of refraction through the atmosphere. The computer then calculates positioning 

requirements for the he'liostats and sends this information to the field controllers over a computer data highway. The field control lers will direct the 

position of the individual heliostats. He1 iostat control will be "open loop" ; 

that is, he1 iostat reflected insolation beam direction is not detected and sent 

back to the collector computer. 

A solar energy demand signal can be generated either by the master control computer or by the distributed analog control system [see Section 4.3.1.2.(3)]. . 

This control signal will provide feed-forward demand to the collector control 

computer indicating what the unit requirements are for solar insol ation on the 

receiver. The collector control computer will selectively focus and defocus 

the required number of he1 iostats in response to solar energy demand while 

giving overall consideration for receiver metal temperature conditions. 

Additional design requirements for the collector control system incl ude emergency 

heliostat defocusing, automatic stowing, and manual control. Operator ccntrol 

of the collector subsystem will be from a computer control console located in 
DISTRIBUTED ANALOG OFERATOR CONTROL CONSOLE 

MASTER CONTROL COORDINATED CONTROL e INDEPENDENT SUBSYSTEM 

' ENERGY DEMAND SIGNAL AUTO MANUAL CONTROL 

COLLECTOR CONTROL 

DIGITAL COMPUTER 

e SYNTHETIC TRACKING 

e EMERGENCY DEFOCUS 

STOW COMMAND 

INTERFACE WITH MASTER 

CONTROL 

ENERGY DEMAND CONTROL 

i 

4 WEATIiER 

INSTRUMENTATION 

i 

I b------( WWVTIME BASE I 

POWER 

SOURCE TRlAC 

SWITCHING I k-- ""'4 

-- 1, 1 

HELlosTAT 1 r --- 

OONTROLLER POSITION 

8 DATA SENSOR 

INTERFACE I 1 - POSlTlONER I - 

A 

FIELD CONTROLLER 

PRECISION TRACKING 

POSITION COORDINATE ------- 

TRANSFORMATION LOCAL D4TA 

BUS HELIOSTAT ALIGNMENT BUS 

I HELIOSTAT DIRECTOR 

1 TO OTHER FIELD 

CONTROLLERS 

AS REQUIRED 

TO OTHER 

HELIOSTATS 

r-7 

ttt 

Ill 

Ill 

Ill 

Ill 

J.-L--l 

Figure 4.3-10. Col lector Subsystem Control Architecture 
the control room. From this control console, the operator will have the 

capabi 1 i ty of independent subsystem automati c control or manual control of 

the en ti re collector fiel d. 

Col lector control system hardware incl uding the digital computer, fiel d con- 

' trol 1 ers , he1 iostat controllers , control console, preassembled interconnecting 

cab1 es, etc., wi 11 be purchased from a manufacturer experienced in the assembly 

of 1 arge computer based control systems and control apparatus. Addi tional ly, 

a1 1 sys tem software and computer programming wi 11 be purchased from the hardware 

supplier. The collector system supplier will be responsible for all control 

system interfaces with the heliostat hardware and will be responsible for the 

correct and proper operation of the collector subsystem. 

RECEIVER CONTROL SYSTEM 

The receiver instrumentation and control archi tecture is shown in Figure 4.3-11 . Recei ver instrumentation and c o n t r o l s will be purchased with the recei ver and 

will consist of an independent electronic analog control system, control vaives 

and instruments , and recei ver moni toring instruments. 

The purpose of the receiver control system during normal operation is to maintain 

receiver steam outlet temperature within a specified tolerance band. Receiver 

steam out1 et temperature is controlled by varying 'receiver feedwater flow rate 

In the indivi dual panels in accordance with measured steam out let temperature 

and incident energy on the panel . Flow coritrol val ves , temperature sensors, 

controllers, etc.~, should be of a design tested and proven by the receiver 

manufacturer. Receiver subsystem control schematic diagram is shown in 

Figure 4.3-12. 

During startup, shutdown, mode transition and emergencies, the receiver control 

system must respond to and interface with commands from the plant operator and 

from the analog control or master computer controls. 

The receiver system control console located on the BTG panel addition in the 

control room will provide the operator with both independent automatic and 
RECEIVER CONTROL ANALOG CONTROL OPERATOR COMPUTER ANNUNCIATOR 

CONSOLE CONSOLE 

PLANT COMPUTER 

DISTRIBUTED ANALOG MASTER CONTROL 

COO3DINATED CONTROL 0 DATA ACQUlSlTlDN 

RECEIVER ANALOG PROCESS INTERFACE 

DIGITAL INPUTSIOUTPUTS ANNUNCIATOR 

CONTROL SYSTEM 

TERMINATION TERMINATION TERMINATION 

RECEIVER SUBSYSTEM INPUTS AND OUTPUTS 

Figure 4.3-1 1 . Receiver Subsystem Instrumentation and Contr~l Architecture 
TO FLASH TANK 

A 

TYPICAL BOILER 

FEEDWATER 

I Ni RECEIVER CONTROL PANEL RECEIVER 

s 

CONSOLE CONTROL SYSTEM 

Fi gure 4.3-1 2. Recei uer Subsys tem Control Schema ti c 

MASTER CONITROL 

COMPUTER 

1 * 

TO/FFEOM 

4 

TCIFROM ANALOG CONTROL 

SYSTEM 
manual control of the recei ver subsystem. Conventional HandIAuto stations 

located on the console will provide conventional power plant opera.tor interface with the receiver system. 

4.3.2 PLANT MODIFICATIONS FOR CONTROL 

An important objective for a solar hybrid repowering control system is to keep 

modifications to the existing control equipment at an absol ute minimum. This 

objective can be accomplished only to a certain degree. Computer control and 

monitoring equipment impose a distinct change in operating and maintenance 

requirements for power plants such as the Reeves Station. Such plants typically 

have pneumatic combus tion controls. Electronic instrumentation usually exists 

In Such plants on a Simited basis. Systems such as the col!ector field and heliostats are not practically controlled without computers and microprocessors. 

Master control for fi rst-of-a-kind plants require flexibility for design changes 

that can only be provided with computer control. The addition of electronic 

control s and instrumentation is vi rtual ly unavoidable. A solar repowered power 

plant makes it a modern and state-of-the-art power plant. Such a plant demands 

modern and state-of- the-art control s and instrumentation. 

4.3.2.1 CONTROL ROOM MOD1 FICATIONS 

An objective of the control system design is to provide both solar and fossil 

plant operation by a single operator from a central control room. For most 

solar hybrid repowering appl ications this woul d require the addition of a new 

control room. Existing pl ant control panels woul d have to be relocated to the 

new control rooni or another a1 ternati ve would be completely new control panels. 

This a1 ternative coul d greatly enhance the integration of solar fossil plant 

operation as we1 1 as upgrade some of the existing equipment. 

The existing control room design at the Reeves Station, shown in Figure 4.3-1 3, 

provided space for a fourth unit, so a new control room is not required. A 

control cutisole ar~d vertical panel will be added to the existing contro'l room 

in the same general configuration as the existing panels. These are shown on 

Stearns-Roger Drawing No. L-22929, Sheet GI-3. All new solar controls will be 

1 oca ted on these panel addi tions . 
UNIT #2 1 1 UNIT #3 / . 

Fi gur~ 4.3-1 3. Reeves St.ation Control Room 

I I I 

I 

- - - I I 

----- ---- 

ION i! &t' -,' ', 

\ I TVI 

EXISTING ipANEi EXISTING 

\ 

\ 

\ ,/-- 

I 7 I 

EXISTING 

I 

CONTROL 

CONS0 LE 

ADDITION 
Two significant problems are solved by using the existing control room. First, 

the pneumatic combustion control console wi th a1 1 of i ts tubing requi rements 

will remain intact in its present location directly above the re1 ay room. 

Second, the station will still have the potential for operation by a single 

operator in the control room for all three units as it now does. 

Conceptually, the control console and vertical addition panels may appear as 

shown in Figure 4.3-14. Subsystem control consoles will be located ,on the 

horizontal or slanted section of the panel for easy operator access. The 

vertical section of the control console may house operator control system interface CRT's as well as additional controls and indicators. 

Alarm, utility and graphic CRTs will be located on the larger vertical panel 

addition. CRTs will be provided with shields and non-gl'are screens to aid 

visibility in the highly lighted Reeves Station Control Room. There will be a 

small annunciator addition as we1 1 as instrument indicators and recorders on 

the vertical panel. The purpose of the vertical panel is display and indication. No controls should be mounted there. 

Sizing of equipment located on the panel additions is not feasible in a conceptual desi gn since these types of equipment vary si gni ficantly between di fferent 

manufacturcers. Therefore, actual panel arrangements may have to be a1 together 

different than shown in the accompanying figure. Panel size is expected to be 

adequate, however. The existing control room will house a console addition 

up to 14 feet long and a vertical panel addition up to 12 feet long. 

HVAC in the existing control room 'has been determined to be adequate for 

personnel comfort and therefore is expected to be adequate for the addition of 

several computer control consoles. Shoul d this expectation prove incorrect or 

shoul d additional heat loads overload the present sys tem, addi tional HVAC. equipment would be required to maintain control room temperature at an acceptable 

level . j 
Fl ALARM F] UTILITY Fl GRAPHIC 0 ANNUNCIATOR 

RECORDERS INDICATORS I 

IlRpr'] OPERATOR OPERATOR 

I 

CONTROL CONSOLE 

PANEL 

VERTICAL ' I 

PANEL 

Fi glare 4.3-14. Control Panel Additions 
4.3.2.2 COMPUTER ROOM ADDITION 

Computer systems and computer electronic hardware call for a space that is 

envi ronmental ly di fferent from the usual power plant envi ronment. Computers 

demand a space that is quiet, clean, dry and held within close temperature and 

humidity tolerance bands. Computer spaces must be free from large machinery 

. and any electromagnetic interference such as might be produced by motors or 

swi tchgear. 

Typically, therefore, power plants that are repowered with solar collectors 

and heliostat fields will require the addition of a computer room to house 

the computer systems. The Reeves Station Unit No. 2 computer room will be 

added on the operating floor in the solar equipment building addition (see 

General Arrangement Drawing No. L-22929, Sheet GI-3). 

The computer r,,,,i will house the MCS computer and the collector computer. Computer mainframes, analog to digital conversion units, mu1 tiplexing equipment and 

magnetic tape units will be housed in the computer room. Computer termination 

cabinets for field wiring will be housed in the adjacent log equipment room and 

interconnected to the computer system with preassembled plug-in connector cables. 

The computer rcm will also ,on iain programmer's consoles and printers for the 

two computers as we1 1 as the p1an.t computer er,ji neer's console, printer and 

recorders. The computer room will provide a dork space. for the plant engineer 

and the computer programmer that is segregated from all other plant activities. 

Special heating, ventilating and ai r conditioning systems required to maintain 

temperatures and humidity as required by the computers will be mounted on the 

roof above the computer room. 

4.3.2.3 LUG1C tUUlPMENT ROOM ADDITION 

I'he addi t: on of new and sophis ti cated electronic control sys tems and ins trumentation lead to the requirement to provide a space for these systems. A1 though 

the space environmental conditions are not as demanding as those in the computer 

room, they must be suitable for electronic eduipment. 
Conceptually, the logic equipment room might appear as seen in Figure 4.3-15. 

Typical electronic control sys tem cabinets are 24-inches wi de, 24-i nches deep 

and 90-inches high. They may be arranged in bays as long as the space will 

a1 low. Systems cabinets are provided with both front and rear access doors. 

For the Reeves Station Unit No. 2 Solar Repowering, the logic room addition is 

located on the operating floor in the solar equipment building addition as shown 

on Stearns-Roger Drawing No. L-22929, Sheet GI-3. 

A requirement for approximately 80 feet of system cabinets, four bays 20-feet 

long, has been identified. It must be realized, however, that an actual final 

design could be considerably different. Estimates for total cabinet sizes has 

been based on similar systems in other power plants. 

4.3.2.4 BOILER AND COMBUSTION CONTROL MODIFICATIONS 

Two potential problems were studied during conceptual design for repoweririg the 

Reeves Station Unit No. 2 existing fossil boiler. Neither of these present 

insurmountable technical di fficul ty. The first problem was the requirement for 

operating boiler burners at very low loads. The other problem, identified by 

plant operating personnel , was the inabi 1 i ty of the combus tion control sys tem 

to operate automatically below ..O percent load. 

During combined solar and fossil operation, the fossil boiler nus st operate at 

relatively low loads. Since the boiler is equipped with a total of six burners, 

low load operation is normally accomplished by shutting down all but two 

burners. Burner light-off and shut down is a manual operation performed locally 

at the burner. During severe solar transient operation, the boiler must be able 

to ramp from as low as 25 percent to 100 percent load in a short time. Additional burners cannot be put on 1 ine in a short time. 

Two courses of action were considered. First, the burners could be replaced with 

new, automatic burners as part of furnace safety and fuel supervision (FSFS). 

This would provide for automatic control of the burners from the control room. 

A second choice is to operate at low loads with all six burners in operation. 
I I I I I I I I I 

MCS COMPUTER COLLECTOR COMPUTER ANNUNTERMINAL C.r?@!NFTS TFRMINAL CABINETS CIATOR 

I I I 1 I I I 

I I 

INTERFACE I 1 

LOGIC SYSTEM TURBINE DEH 

I I I 1 

Figure 4.3-15. Logic Room 
This is feasible if adequate turndown capability exists on the burners and if 

adequate fuel atomization will occur with the burners turned down for low load 

operation. Discussions with the boiler manufacturer indicate that adequate 

turn down (10:l with 5:l required) does exist and that proper fuel atomization 

will occur. Therefore, at Reeves Station.Unit No. 2 the conceptual design 

uti 1 i zes the existing burners. 

The inability of the existing combustion controls to operate in an automatic 

mode below 50 percent load has been identified by plant operating personnel as 

a problem with the fuel oil control valve. At low loads, the control val ve 

operates close to the seat and cannot maintain stable oil flow. In this case, 

the plant operator places the controller in manual and manually sets fuel oil 

fl ow. 

The correction for this problem is to provide a smaller control valve for low 

load operation. This is shown on Drawing No. L-22929, Sheet P3-3. The smaller 

control valve will provide stable fuel oil control at low loads and the existing 

valve will operate at high loads. In a parallel control valve arrangement such 

as this , both val ves operate off the same 3 to 27 psi g control si gnal . The 

valve positioner on the smaller control valve is set to provide 100 percent 

valve.stroke over a 3 to 16 psig signal while the other valve posit.inner strokes 

the 1 arger 'control val ve over an 14 to 27 psi g control si gnal . SIJC~ para1 lel 

control valve arrangements have proven 'successful in many power plant applications. 

At the conceptual design level , no other problems were encountered. For an 

actual design, however, boiler testing is warranted to ensure that oxher problems do not exist and to ensure that the known problems are corrected. 

4.3*2.5 TURBINE CONTROL SYSTEM MOD1 FICATIONS 

The foll owing control sys tem modi fications are pl annea: 

o Rep1 ace the exis ti ng 150-1 b mechanism Hydraul i c Contro'l Sys tern 

with a Digital Electro-Hydraulic (DEH) Control System 

e Replace the existing Turbine Supervisory instruments (TS) with a 

Bent1 y Nevada desi gn 
e Add all turbine generator sensors required by the DEH for 

Automati c Turbine Control (ATC) 

e Provide necessary sensors for the Steam & Metal Temperature 

Recorder 

The above recommendations are. based on the fol lowing: 

@J The DEH Sys tem provi des val ve management that wi 11 permi t greater 

capability for handl ing load cycling with minimum rotor stress. 

s The DEH System provides Automatic Turbine Control that will permit startup and load changing while automati,cally controlling 

rotor stresses as well as considering all significant T-G conditions. This provides the capability of handl ing unexpected main 

steam conditions that can occur i'n any plant using new technology. 

e The DEH is a proven state-of- the-art system that is both es thetically and functionally most compatib1.e with the Digital Plant 

Control System. A data Link can be provided for DEH/Plant 

Control communication. 

m The DEH System provides maximum flexibility for modifying control 

fiunc tions as opera tion phi 1 osophy evol ves during the desi gn and 

early operation stages. 

o The DEH System with Remote and Operator Adjustable Throttle 

Pressure Control option provides maximum turbine protection 

against water carry-over. Throttle pressure variation will be a 

normal operating condi tion. 

o The DEH provides faster response than the existing mechanical control sys tem as we1 1 as response to sys tem frequency fl uctuations . 

e The DEH includes an over-speed protectiorl control (PC) function 

in addition to the centri fugal trip weight presently provided. 

e New Supervisnry Instruments are provided as well as other primary 

rr~easurement devices to insure that the DEH as we1 1 as the operator 

has reliable data to base operating decisions on. 

A comparison between the DEH control sys tem (recommended for the repowered plant) 

and an AEH system was performed. The advantages of a DEH over an AEH are: 

e More flexible interfaces --.. with other plant controls - 

Many modern power plants have central computers for information 

gathering, control and alarming. With the use of a data link, all 

1 ocations in DEH core are avail able to central computer for reading or setting values. With an AEH only limited information is 

available due to physical wiring limitations. 
e Easier changes to settings, interlocks, operating procedures - 

In that most changes can be accomplished in software rather than 

hardware, changes can be made by feeding in new instructions by 

punched tape, operator en try for certain i tems or at the controller maintenance panel . Simi 1 ar changes to an AEH wou1 d general ly require physically modi fying printed circuit cards or 

wiring. 

e Less impact on turbine availability for most control changes that 

may be necessary 

Again because the controller is a digital computer-based sys tem 

there are advantages to the customer. If changes in programs are 

required for the operation of the .unit, these changes can be 

engineered with new types produced while the customer's urii t is 

still on the 1 ine producing power. Since these programs can be 

checked at Westinghouse, there is a high level of assurance that 

the new operation wi 11 work the fi rs t time. The new .programs 

could then be read into the DEH while the unit 'is in the manual 

mode still producing power. Since the loading of new tapes takes 

no more than two hours, minimal operator inconvenience would 

occur and no load reduction need occur. This advantage is not 

speculation. We have actually used 'this procedure on several of. 

the more than 40 DEH units in operation. 

For the most part, changes to AEH. units wou1 d require the u n i t t o 

be shut down. 

. r Safe Operation 

With the availability of the ATC (Automatic Turbine Control) with 

the DEH, safe, consistent operation of the unit can be assured. 

The ATC continually moni burs rso'tur stress and many other variables 

ar~d Ltrus allows Par safe uper-rlliui~ or thc unit. This featurs ir, 

especially vaulable on a unit subjected to cycling duty. 

4.3.2.6 PLANT INSTRUMENTATION ADDITIONS AND MODIFICATIONS 

Additional instrumentation must be added to the existing plant to provide the 

plant computer with enough process information to perform plarlt moni toring and 

master control, Generation of a computer 1/0 (Input/Output) list is the task 

of a detailed design. 

For purposes of conceptual design, the P and I' Diagrams (Stearns-Roger Drawing 

No. L-22929, Sheets P3-1 through P3-6) have been drawn wi th necessary computer 

instrumentation. A great deal more instrumentation is utilized by the plant 

computer to monitor everything. from boiler tube temperature to circulating 
water pump onloff status. A tremendous amount of plant monitoring capability 

exists in the plant computer and perhaps only approximately 20 percent is shown 

on P and I diagrams. 

For the solar repowered demonstration plant it is anticipated that the total 

110 List will contain approximately 1000 analog inputs and 1000 digital inputs. 

For further discussion see Section 4.3.1.2, Master Control Computer. 

4.3.3 CONCLUSIONS AND SUMMARY 

4.3.3.1 DEMONSTRATION PLANT CONTROLS VERSUS COMMERCIAL PLANT CONTROLS 

In c0nsiderin.g the possibility of repowering many units, it is worth noting that 

the nth -commercial plant may have some si gni ficant control sys tem simp1 i fi cation. 

The first solar repowered plant, or demonstration plant, will probably require 

a si gni ficant amount of monitoring, performance testing and data collection that 

should not be required on a commercial plant. This will require that the plant 

computer have a plant performance and backup central processing unit (see Figure 4.3-16). The commercial plant should not require this (see Figure 4;3-17). 

In the same line of thinking, automatic turbine startup would probably not be 

necessary on all solar repowered units. Solar transient operation may prove 

controllable by the automatic control systems and the plant operator. 

Conceptual design cannot determine with certainty what changes will be acceptable. 

Tl1trs.e will only be determined after a detall design, construction and operation 

of a solar repowered power plant. 

4.3.3,2 REPOWERING CONTROL SYSTEM - CONCLUSIONS AND SUMMARY 

A control system has been presented and discussed that meets the basic needs for 

solar hybrid repowering appl ications. The implementa tion of this system on existing power plants was discussed .with particular emphasis on Reeves Station Unit 

No. 2. From a controls and instrumentation point of view, solar hybrid repowering 

of existing power plants is feasible, reasonable and presents no unusual difficul ty for a project of this rnagni tude. [ 
CClNTROUSUPERVlSlON 

DATA ACQUISITION 

PLANT MONITOR 

DISTRIBUTED GENER.ATOR 

Fi gure 4.31 6. Demonstration Master Control Sys tem 
CONTROL/SUPE RVISION 

DATA ACQUISITION 

PLANT MONITOR 

DISTRIBUTED 

FREQUENCY 

Figure 4.3-1 7. Commercial Master Control .System 
4.4 ELECTRICAL DESIGN 

Figure 4.4-1 is a functional diagram showing the overall plant electrical power 

and distribution system. This diagram depicts the primary solar elements of the 

power system and also the tie-in to the existing plant primary components. 

The following is a brief description of the solar repowering of the existing 

plant facilities. 

MAIN ELECTRICAL SYSTEM 

The main electrical system for Unit No. 2 and the Swi tchyard will be effectively 

unchanged with the solar addition, except fgr providing the extra auxiliary power 

as described in the next section. 

AUXI.LIARY SYSTEM 

A voltage of 2400 volts will be retained for the main auxiliary solar bus that 

wi l l feed the 2000 horsepower receiver pump motors and distribution system for 

the he1 iostat field. This therefore enables startup power to be obtained from 

the existing startup transformer. Normal auxil iar,y power will be obtained from 

an additional unit auxiliary transformer. These two sources of power will feed 

separate auxiliary buses having a tie breaker between them. This bus arrangement facilitates the application of the reserve receiver feed pump to either 

Unit No. 1 or Ilni t. No, 2, with the future addition of solar to Unit No. 1. This 

arrangement a1 so provi des redundancy to the he1 iostat distribution system to 

enable full plant operation in the event of a fault on the main solar auxiliary 

bus. 

Since the existing plant emergency diesel generator is not automatic starting, 

and since it does not have sufficient capacity for the additional emergency load, 

i L is rlecessary to add an additional 480 volt system capable of receiving 

emergency power from the new diesel generator. This will be arranged by feeding 

a new 1000 KVA 1 oad center from the 2400 vol t solar bus, The new 1 oad center 

would be tied to the existing load center to form a double end load center. 
START SIGNAL 

r ----- -1 

I I 

GENERATOR 

AUXILIARIES 

FOR STARTUP 

81 AUXILIARIES 

MONITORING 

EXISTING 

NEW 

COLLECTOR 

----- 

EMERGENCY 

I INSTRUMENTATION AND CONTROL 

P POWER 

EP EMERGENCY POWER 

UP UNIMTERRUPTIBLE POWER SUPPLY 

Figure 4.4-1. Functional Diagram - Overall Plant Power and Distribution 
On both the 2400 volt and 480 volt systems, automatic bus transfer would be provided to enable a controlled shutdown to be accomplished following a unit trip. 

A diesel generator is provided to enable controlled unit shutdown to take place 

following system blackout. 

4.4.1 SOLAR PORTION OF DESIGN 

4.4.1.1 POWER TO HELIOSTATS 

As shown on Drawing L-22929, Sheet E2-1 and Figure 4.4-2, approximately 145 KVA 

power at 2400 volts will be furnished to the heliostat field during normal daylight plant operation. This will be accomplish@d using a loop 5 kV, 3/C cable 

routed from the new 2.4 kV solar switchgear. 

A cost study was made to determine whether the cable should be routed via cable 

tray or conduit. Means of supporting either raceway, ambient temperatures versus 

cable size.and cable ampacities were taken into consideration. 

It was determined that the least costly method would be to route the cable in 

.conduit supported from the pipe rack that terminates at the receiver. The conduit will also function as an equipment grounding conductor. 

4.4.9.2 HELIOSTAT SWITCHING UNITS 

20 three-pole switching units will be installed. The switching units wi 11 be 

fed from the 2.4 kV loop and will permit partial isolation of the heliostat 

field in the event of a fault in the cable. A number of switching units will 

be located adjacent to the pipe rack, actual locations to be dictated by the 

heliostat requirements. The remainder of the units will be located in the 

vicinity of the recel ver tower for convenient access. Each of the 20 switching 

unl ts wlll feed a 225 KVA transformer. 

4.4 .l .3 HELIOSTAT TRANSFORMERS 

20 225 KVA, 2400-240 vol t, three-phase, pad-mounted trans formers, each located 

central to a group of approximately 216 he1 iostats, will be provided. The 
/ 2400V PRIMARY DISTRIBUTION 

FEEDER LOOP 

TRANSFORMER 

2.4 KV S\'VGR. 

PER DISTR. PNL.) HELIOSTAT 

WITH FIELD 

CONTROLLER 

(20 REQ'D.) 

COLLECTOR COI'APUTER HELIOSTAT 

24 

LOCAL DATA 

POWER 

BUS 

BUS 

HELIOSTAT 

-a 

HELIOSTAT 

-'. 

:: ) 

Figure 4.4-2. He1 iostat Fie1 d Power Diagram 
transformer(s) primary circuit will be 5 kV, 3lC cable routed in buried conduit. 

The transformer(s) secondary will consist of a 600 volt, 600 ampere, threephase bus each routed to a distribution panel. 

4.4.1.4 HELIOSTAT DISTRIBUTION PANELS 

20 240 vol t, three-phase distribution panels will be furnished, each one being 

located adjacent to a transformer. Each distribution panel will provide nine, 

three-pole branch circuits to feed approximately 24 heliostats per ci rcui t. 

The branch circuits will be direct buried type CLX, 600 volts, 3/C No. 6 AWG. 

Type CLX was chosen on the basis of reliability; i.e., physical protection, 

incl uding rodent protection. Economics dictate that the sable wi 11 be plowcd 

in, using predetermined lengths. Terminations at each heliostat will use ringtype crimp connections on to terminal bl ocks . 

The heliostat control cables will be a twisted pair, PVC insulated, aluminum 

armor wi th a thermoplastic jacket. This will provide physical protection, since 

the cable between heliostats will be direct buried using the plowing-in method. 

Spade and tongue terminations are being considered at each heliostat to a1 low 

for fie1 d breakable connections requi red for individual testing. An assembly 

line approach in the field utilizing available equipment would provide a cost 

savings in crimping these terminations to the cable. The control cables from 

each heliostat field controller to the collector control computer would be direct 

buried back to the receiver tower, and at that point would be routed in cable 

tray(s) supported from the available pipe rack. 

4.4.2 MODIFICATIONS TO EXISTING EQUIPMENT 

4.4.2.1 480 VOLT LOAD CENTER 

As shown on Drawing L-22929, Sheet E2-1, the existing brcakcr No. IC will be 

reconnected to provide a tie to the new solar load center bux. 

4.4.2.2 TIE TO START UP TRANSFORMER 2A 

The 2.4 kV solar switchgear will be tied into the existing startup transformer 

2A secondary bus, using 5-kV cable. The tie location has not been determined 

pending further information on existing configuration or visual inspection. 
4.4.2.3 SOLAR AUXILIARY TRANS FORMER PRIMARY 

It will be necessary to tap into the existing generator No. 2 Main Transformer 

2A isolated phase bus for the solar auxiliary transformer primary feed. This 

will be accomplished by replacing the existing three-pole, interrupted swi tch 

with a double unit interrupter switch, including necessary internal busing, to 

serve both the existing unit auxiliary transformer 2A and the solar auxiliary 

transformer. Visual inspection, for avail able physical space, wi 11 determine 

whether this concept is feasible. 

4.4.3 ADDITIONS OF ELECTRICAL EQUIPMENT 

4.4.3.1 2.4 KV METAL CLAD SWITCHGEAR 

It has been determined that the existing 2.4 KV switchgear was not suitable for 

solar extension due to the 1200 ampere bus rating and physical space limitations. 

A new line up of 2.4 KV switchgear will be installed (refer to Drawing L-22929, 

Sheet E2-1 ) for the Unit No. 2 solar repowering, with floor space being provided 

for the future Unit No. 1 solar repowering switchgear. 

4.4.3.2 SOLAR AUXILIARY TRANSFORMER S2 

Auxiliary power will be supplied by a solar auxiliary transformer. The transformer will be rated 3750 KVA, 13.2-2.4 kV, OA. The primary will be Delta and 

the secondary will be resistance grounded wye. The primary will be fed 'from 

generator No. 2 main bus via an interrupter switch (see Section 4.4.2.3). The 

transformer secondary will feed the 2.4 kV bus (see Section 4.4.3.1) with a bus 

tie between sections. The secondary connection will be cable or bus duct. 

The rating of this transformer is based not on the solar plant continuous load 

demand, but upon the starting requirement of the 2000 horsepower receiver pump 

motors. The transformer KVA rating and impedance is chosen to maintain more than 

80 percent system voltage when starting this motor. 

4.4.3.3 480 VOLT SOLAR LOAD CENTER 28 

The 1 oad center transformer will be rated 1000 KVA, 2400-480 vol ts. The primary 

will be Delta and the secondary will be grounded wye. The secondary of the 
transformer will feed the 480 volt load center bus through a 1600 amp main 

breaker. An additional 1600 amp breaker will be used as a bus tie breaker to 

the existing plant 480 volt bus. The existing bus, together with the new solar 

load center bus, will form a double ended load center. Due to the relatively 

long cable connection to the existing load center bus, two tie breakers will be 

used, one at each end of the cable, to improve the plant integrity. 

4.4.3.4 480 VOLT MOTOR CONTROL CENTER 

The solar motor control center will be adjacent to and fed as an extension of 

the new 480 vol t 1 oad center bus 26. The motor control center will uti 1 i ze 

molded breaker combination starters for motor drives, up to 100 horsepower, 

and mol ded case breakers for 1 i ghting transformers and miscellaneous scrvf ces. 

4.4.3.5 EMERGENCY DIESEL GENERATOR 

An emergency power diesel engine generator will provide power for safe solar 

shut down and emergency service. The generator will be rated 1600 KVA, 80 percent power factor, 2400 volts, with regulator and rotating exciter. The 

generator will be connected to a 2400 volt switchgear bus section. The diesel 

will be automatic start'ing In the event of loss of primary power from the 

turbine-generator or the grid distribution system. Emergency power will be 

provided for the heliostat field and all other new and existing essential loads 

of Unit No. 2. 

It is eslilr~ated that the heliostat field will require a total of approximately 

2100 kW when operating all drive motors simultaneously, such as could occur during an emergency slew condition. However, the engine generator is sized to provide power to one-quarter the fie1 d, and then only to 1.5 motors per heliostat, 

based on elevation drive mot.ors and parti a1 azimuth drive tnu.tors. This reduces 

the emergency power demand to approximately 31 5 kW. This is based on information 

provi ded by McDonnel 1 Doug1 as. 

The 1600 KVA rating of the generator is based .on two considerations: 

c The heliostat loading of 315 kW has a power factor of 0.4 that 

represents a KVAR loading of 722 KVAR. When expressing this in 

terms of a 0.8 pf machine, a 1203 KVA generator rating is required 

to obtain the 722 KVAR. 
Power factor correction has not been considered since the next 

condition requi res an even 1 arger emergency generator. 

Since the heliostat motors are sequentially started, a starting 

duty of this 31 5 kW steady state load does not have to be 

considered. 

a Other essential loads require 170 kW of power, this being mainly 

motor load. Assuming the locked rotor currents are six times 

the full load current, these additional loads will require 

1020 KVA. This would be a momentary starting condition, and 

therefore the data contained in Beeman's "Industrial Power 

Systems Handbook,'' Figure 4.39, has been used to establish generator rating. This indicates that for a 600 to 1800 rpm generator with generator terminal voltage maintained above 85 percent of nominal , the motor starting KVA should not exceed 

65 percent of machine rating when the yenerator has a high speed 

voltage regulator. Hence, Machine Rating = 'IO2UlU.bS = IS69 KVA. 

4.4.3.6 FURTHER CONSIDERATIONS ON EMERGENCY POWER 

The inclusion of the above generator is required for system blackout conditions 

on the assumption that the solar boiler (receiver) is not capable of taking a 

100 percent load rejection down to 3tixiliary power of approximately 6.5 percent. 

If the boiler is capable of sustaining this load rejection, power system instabil i ty problems could be relayed. Detection of these conditions could trip the 

generator main breakers, leaving the plant sel f-sustaining and the need for 

emergency. generators would be el iminqted. This woul d also facil i tate fast 

reinstatement of the main power system. 

Assuming diesel generators are installed, with the solar addition to both 

Units No. 1 and No. 2, there would be sufficient capacity to black start the 

plant following the completion of a complete solar shut down. If this capabil i ty is requi red, some additional switching facil i ties woul d be required to 

enable both emergency generators to be connected to a single unit. 

4.4.3.7 MISCELLANEOUS LIGHTING TRANSFORMERS AND PANELS 

Lighting will be provided for all outdoor and indoor locations. The lighting 

transformers primary feed will be 480 volts ac from the motor control center. 

The transformer's secondaries (vol tages as required) wi 11 feed 1 i ghting panel s 
at readily accessible locations. Lighting panel branch circuits will be designed 

to be switched at the panel utilizing the breakers, except for circuits with automatic controls or li ghting circuits for areas with minimal personnel traffic. 

The latter will be controlled by swttches in the area. 

Aircraft obstruction. warning 1 i ghting will be provided for the receiver tower. 

4.4.3.8 MISCELLANEOUS FEED FOR AUXILIARIES 

The 480 volt motor control center will provide power for solar auxiliaries (see 

Section 4.4.3.3), chernical puiiips, sump pumps, HVAC, 1 i ghting transformers, etc. 

The 480 volt bus will hc! split into nonessential and csscntiill serviees irtili zing a tie breaker. The essential portion of the bus wi 11 be provided with a 

feed from the, existing plant emergency diesel generator. This will provide an 

alternate power source in the event of loss of primary source. 

4.4.3.9 CABLE TRAY SYSTEM 

A cable tray system will. be provided utilizing 1 adder-type tray for power ci rcuits and solid bottom-type tray with solid covers for control and instrumentation circuits. 

A cable spreading room will be ~rovided below the swi tchgear and the computer 

and relay rack room to provide easy and isolated circuit access into the cable 

tray system. 

4.4.3.1 0 CONTROL 

The instrumentation and control wiring will start at the various master control 

cabinets, located in the solar plant control building, and be distributed to 

the various locations of the subsystem interfaces. Control and instrumen tation 

field wiring for a1 1 subsystems except the collector fie1 ds is routed in' cable 

tray. Collector subsystem wiring will be direct buried, twised pair, PVC insulated with a1 urninurn armor for physical protection and a thermoplastic jacket. 
4.4.3.1 1 UNINTERRUPTIBLE POWER SYSTEM 

The uninterrupti ble power system (UPS) will be imp1 emented to provide protection 

to the solar master control subsystem. This system, illustrated in Figure 4.4-3, 

will provide power to the computers and control system hardware. 

Under normal operating conditions, the battery charger will operate as a rectifier 

to provide dc to the inverter from the normal ac incoming line. The battery bank 

will be connected in parallel to the dc being supplied from the charger so that 

if any failure or voltage drop occurs in the ac line, the batteries will provide 

dc to the inverter. Thus, no break will occur in power to the load. An automatic bypass switch will be supplied to provide automatic bypass of the inverter 

of an alternate ac source in .the event of UPS malfunetio~l ur. overload. 

4.4.3.12 LIGHTING 

Outdonr 1 i ghting will be provided along access road, parking areas, operating 

areas, operating area perimeter and the collector fie1 d. Mercury vapor. fixtures 

will be used with photocell control. The de'si gn will be based on an approximate 

average horizontal foot candlre level of 1.5. Outdoor 1 ighting will also be provided for a1 1 buil clir~g entrances, loading docks and equipment locations outside 

the buildings. 

Indoor lighting will be provided in all building rooms, offices and stairwells. 

The design will be based on foot candle levels for the various area functions as 

recommended by the I1 1 umi nati ng Engineering Society (.IEs). 

Emergency lighting will be provided as required for the safety of personnel and 

equi pment. 

4.4.3.1 3 GROUNDING 

A dcpcndabl e grounding system wi 11 be desi gned and furnished to provide requi red 

protection to personnel and equipment as fu1 lows : 

e Provide a low impedance path to ground for personnel and equipment 

protection and effective circuit relaying 

e Withstand and dissipate repeated faul t and surge currents 
AC ~ICBO~BP~~B~QPPIPP~~~B~IB~~CBO~~~I~

INPUT 

ALTERNATE 

I 

BATTERIES 

* 

AC INPUT 1 

I I 

1 

I 

I (ALTIIRNATE SOURCE) 

1 0 AUTOMATIC 

81 BY-PASS 

so SWITCH 

REGULATOR 

1 

CRITICAL 

AC 

LOADS 

I b 

Fi gum 4.4-3. Unin terruptabl e Power System 
@ Proper grounding of metallic equipment enclosures and supporting 

structures that are part of the electrical system and may be contacted by personnel. 

e Provide grounds for electric process control , instrumentation and 

communications ci rcui ts 

4.4.3.14 LIGHTNING PROTECTION 

The factors that will be considered during the design of the lightning protection 

system are as follows: 

a The number of thunderstorm days or the number of lightning flashes 

per ~rn2 per annum for the site area from available data 

e The cone of protection area provided by protecting the RS tower 

r No direct strike protection planned for he1 iostats in the collector field since the risk taken involves the possible repair or 

rep'lacement of a struck he1 iostat 

r Protection against direct 1 i ghtning strokes 

e Protection against 1 i yh'tnir~y induced voltages 

The design of an effective lightning protection system will: 

@ Provide a means by which a lightning discharge may enter or leave 

the earth without passing through a nonconducting part of the 

receiver tower or building 

Provi de a grounding electrode and grounding electrode conductor 

for each heliostat in the collector field 

4.4.4 LEAD TIME REQUIREMENTS 

Lead times, estimated in weeks, are as follows: 

e. Auxiliary Transformer ........ 15 to 20 

r Switchgear ................... .18 to 45 

r Load Centers ................. 25 to 30 

r Motor Coiitroi Lenters ........ 10 to 24 
4.4.5 CODE AND LEGAL REQUIREMENTS 

The equipment, materials, design and construction of the plant will comply with 

all Federal, State, Local and user standards, regulations, codes, laws and 

ordinances that are applicable for the site and using utility. These will 

include, but not be limited to, the following: 

e Regulations of the Occupational Safety and Heal th Administration 

(OSHA )

0 IEEE - Switchgear and transformers 

0 NEMA Standards - Motors, starters, distribution panels, lighting 

and el ectri cal ma teri a1 s 

e Uniform Building Code 

e National Electrical Code (NEC) 

0 National Fire Protection ~ssociation (NEPA) Standards , 

Lightning Protection Code, NFPA No. 78 (ANSI C5.1-1969) 

a IEEE Recommended Practice for Grounding of Industrial and 

Commerci a1 Power Systems 

Pub1 ic Service Company of New Mexico Power Plant Standards 
4.5 CIVIL, STRUCTURAL, ARCHITECTURAL DESIGN 

4.5.1 SUBSOIL CONSIDERATIONS 

4.5.1.1 SITE LOCATION AND CONDITIONS 

Reeves Station is located on approximately 60 acres north of the Albuquerque city 

1 imits, south of Los Angeles Boulevard, west of Interstate 70, and east of the 

northern diversion channel of the Albuquerque Metropolitan Arroyo Flood Control 

Authority. The plant site is' in the foothills of the Sandia Crest, between the 

Crest and the Rio Grande River. The site slopes gently toward the north and 

west, to the Rio Grande about three miles from the site. Vegetation is sparse 

and there are no nearby bodies of water, the nearest being the Rio Grande. 

4.5.1.2 SUBSOIL CONDITIONS 

The entire area is overlaid with a thick layer containing lensatic strata of dry, 

sometimes porous, silty sand or.sandly silt. This material generally has sufficient fines to have a low plasticity binder. This layer ranges in depth from six 

to twenty-six feet occasionally containing some small gravel. It is subject to 

small to moderate aniounts of .consol idation when wetted since the materials are 

all very frictional. Settlement conditions are control 1 iny. 

Underlying the near-surface layer is a thin stratum (one to four feet thick) of 

a very fine'uniform sand. The sand layer is clean and.generally in a medium 

dense state. Below this is a thick, dense sand and gravel layer. The sand and 

gravel is fairly well graded, and sub-angular, with a .predominance of the smaller 

sand-sized particles and with a maximum gravel size of about three inches. The 

sand contained in this sand and gravel bed appears to be essentially the same as 

to particle size and shape as the thin sand bed immediately above. No ground 

water is evident to a depth of 50 feet. 

4.5.1.3 GENERAL CONSIDERATIONS 

To adequately support an.y structure, it is necessary that the soils beneath the 

foundations be safe against settlement in excess of the amount permissible for the 

particular structure and shear displacement of soils from beneath the foundations. 

For the sandy foundation soils in question, there is no danger of shear displacement of the soils under any practicable pressures in the design of the three 
units at Reeves Station. It is expected that the information is re1 iable, for 

the entire site due to the highly uniform nature of the soils in the area. 

However, in design for final construction purposes, a full scale soils investigation will have to be made to confirm r e l i a b i l i t y o f this information, particularly where major structures are concerned. 

The previous soils information was extracted and extrapolated from the "Foundation 

Investigation for the Proposed Reeves Power Plant" by Woodward, Clyde and 

Associates, March 26, 1957. 

4.5.1.4 FOUNDATIONS FOR OPERATING UNITS 

Previous experience wi th material s of these types causes Stearns-Roger to recommend several general foundation a1 ternatives . Final selection should be based 

upon comparative cost s tudi es . 

e Foundations of heavy structures (receiver tower) to rest on well 

compacted fill extending down to the dense sand and gravel stratum. The upper si 1 ty sand would be removed and rep1 aced with 

required sandy backf ill . 

Foundations of lesser structures, wiiich are not critical with 

respect to settlement, should be founded on the undisturbed 

upper s i 1 t.y ssands 

Drilled pier foundations should be considered for heliostat 

foundations because loading is 1 argely lateral and substantial 

economies may be achieved. 

4.5.2 FOUNDATION AND STRUCTURAL DESIGN 

4.5: 2.1 HEL IOSTAT FOUNDATIONS 

He1 iostat foundations should be given careful scrutiny before final selection 

because of their possible high impact on overall cost of the heliostat field. 

Review of previous foundation studies indicates two candidate foundation types 

subject to final review based on heliostat type and size, plus complete soils 

data : 

DRILLED PIER 

A 24-inch diameter drilled pier embedded about 22 feet in the recommended 
he1 iostat foundation. In situ testing is recommended to determine if pier 

length can be reduced. 

Cast-in-place concrete pier foundations can be used with a variety of soil conditions. The pier hole can be excavated by drilling an open hole, if the sidewalls 

do not cave, placing the required reinforcing, and placing concrete as required 

to fill the hole. The pier can also be placed by the Intrusion-Prepakt method, 

regardless of the sidewalls standing or not. In this method, a hollow auger is 

rotated into the soil the required depth and sand cement mortar placed through 

the auger to the hole bottom, the auger displaces the soil as it is withdrawn 

from the hole in a single operation. Reinforcing must be forced into the grouted 

hole before tt!e mortar hardens. 

The length of the drilled pier foundations can be varied as required by differing 

soil conditions to attain the required foundation stiffness. 

CONICAL PRECAST CONCRETE FOUNDATION 

This foundation is inherently very stab1 e. Some unaccountable deviation rotation 

will vccur at the eSme of placement as the material upon which the foundation 

rests will not make complete intimate contact with the foundation without excessive fine grading. Also as this particular site has soils which are moisture 

sensitive, this is not recommended foundation. 

FOUNDATION PEDESTAL JOINT 

The large number of he1 iostat pedestal/foundation joints makes them very cost 

sensitive. Design simplification studies should be included in the Detailed 

Engineering phase to optimize expenditures and joint integrity. 

A complete detailed study capnot be made until selection of a heliostat type; 

however, one method to be considered is as follows: 

The pedestal of the he1 iostat would be constructed of structural tapered tube 

and the foundation extension constructed of structural reinforced concrete formed 

by light gage tapered tube. The foundation extension form is to be placed over 

reinforcing extended from the drilled pier concrete. The extension is then 
filled with concrete to provide the structural connection to the foundation. The 

tapered heliostat pedestal would then be force mounted over the foundation 

ex tens i on. 

FOUNDATION DESIGN CRITERIA 

The prel iminary criteria resul ting in the recommended drill pier foundation are 

as follows : 1 imitation of allowable total rotation of the foundation/pedestal 

system was based on a 36 mph wind on a 520 square foot surface. Rotation was 

limited to 2.3 milliradians. Soil conditions were based on a southwest desert 

site. ~nalysis assumed no passive restraint by the top 5 feet of soil. Values 

of the coefficient of hori zor~tal subgrade reaction were obtai r~ed ,from "Dri 1 'I ed 

Pier Foundations" by Woodward, Gardner, and Greer. 

4.5.2.2 RECEIVER TOWER AND FOUNDATION 

A comparative study was made to decide if a reinforced concrete .receiver tower 

or a structural steel receiver tower would be the most economical and satisfactory. For this height, weight, and wind and seismic conditions, the reinforced 

concrete tower proved to be the most eco.nomica1. It was also more satisfactory 

for providing she1 tered- i nterior work space as an adjurlct to the method of 

construction. 

CONCRETE RECEIVER TOWER AND FOUNDATION 

The concrete tower developed in the preliminary conceptual design, shown in 

Figure 4.5-1, extends 413 feet above grade. The top of the tower has an outside 

diameter of 33 feet with a nominal 9-inch wall .thickness. The base of the tower, 

measured at the top of the foundation mat, has an outside diameter of 50 feet 

with wa1.l thickness of 12 inches. The slope of the vertical face of the tower 

is approxirr~ately 1 H to 50 V. The foundation, which is located 10 feet below the 

finished grade, is a sol id concrete mat of 85. feet dlameter wi ti1 a ur~i ror.iii thickness of 8 feet. 

Design references: 

e Uniform Building Code 

e Bui 1 ding Code Requirements for Reinforced Concrete (ACI 31 8-71 ) 
CONCRETE SOLAR RECEIVER TOWER 

DESIGN DATA 

1. WT. Or IlCCElVER 1500K 

2 WIND LOADS = OPERATIONAL 36 MPH 

SURVIVAL 90 MPH 

3. SEISMIC LOADS = GROUND ACCELERATION 0.125 G 

4. SOIL BEARING PRESSURE = 4 KSF ON COMPACTED FILL 

5. CONCRETE STRENGTH = fCg=4000 PSI 

6. REINFORCEMENT - INTERMEDIATE GRADE \=6O,OOO PSI 

MATERIAL QUANTITIES 

1. CONCRETE TOWER 

CONCRETE 1855 CY 

REBAR 75 TONS 

2 FOUNDATION MAT 

CONCRETE 1765 CY 

REBAR 93 TONS 

WALL 

Figure 4.5-1. Concrete Receiving Tower 
Specification for khe Design and Construction of Reinforced 

Concrete Chimneys (AC.1 307-69) 

Design Response Spectra for Seismic Design of Nuclear Power 

Plants (NRC Regulatory Guide 1.60) 

e Damping Values for Seismic Design of Nuclear Power Plants (NRC 

Regulator Guide 1.61 ) 

r Building Code Requirements for Minimum Design Loads in Buildings 

and Other Structures (ANSI A58.1-72) 

The concrete tower was designed to resist stresses resulting from the weight of 

the receiver, the weight of the tower, and the effect of wind or earthquake, 

whichever is critical. The design loads are as follows: 

Receiver weight 1 ,500,000 pounds 

Seismic 1 oads 0.125 g maximum ground acceleration in both 

the vertical and horizontal directions at 

survival condition 

Operation wind 36 mph 

Vortex shedding 48 mph 

Survival wind 90 mph 

The effective wind veioci ty pressures were obtained trom AN51 A58.1-72. A gust 

factor of 1 .062 was appl i ed. 

Stresses: The strength design provisions of ACI 318-71 were employed for design 

of the reinforcement in the concrete tower. A load factor of 0.9 was applied tu 

dead load and a factor of 1.43 to seismic loads. Vertical seismic loads were 

conservatively assumed to oppose the tower and receiver dead 1 oad; i . e. , tu 

cause uplift, 

Analysis Studies: The Stearns-Roger 6163 computer program was used to perform 

the analysis and reinforcing steel design of the concrete tower. A fixed base 

mndel was employed and the r e c e i v e r s u p p o r t structure was considered to be 

infinitely rigid due to the lack of information on the nature of the support 

structure. Dead load combined with the survival seismic loads governs the design 
. . Lateral deflection of the receiver center1 i ne under survival earthquake conditions 

is 7.25 inches which ensures that the deflection under operational wind (36 mph) 

will be less than the allowable 1 imi t of 7 inches. Lateral acceleration at the 

receiver centerline is 0.227 g's. Vertical acceleration at the receiver center1 ine is 0.434 g's. Fundamental frequencies are 0.378 cps in the lateral direction 

and 5.69 cps in the vertical direction. 

Materials: The concrete used for constructing the tower shall conform to ACI 

Code and shall have a minimum ultimate conipressive strength of 4000 psi at 28 

days. Concrete for the foundation mat shall be 3000 psi minimum ultimate conipressive strength at 28 days. Reinforcing bars shall be intermediate grade 

conforming to ASTM A615, Grade 60. 

Allowable Soil Pressure: The Soil Report for Reeves Power Plant, prepared by 

Woodward-Clyde, dated March 1957, was referenced for the foundation design. 

A 4000 psf maximum allowable bearing pressure was assumed, allowing a one-third 

i ncrease for dead load combined with earthquake. 

STEEL RECEIVER TOWER 

The steel tower developed in the preliminary conceptual design extends 423 feet 

above grade. An octagonal structure was selected because this shape provides 

great stiffness of the tower. The top of the tower is 33 feet diagonally to 

30 feet-6 inches between the two opposite faces. The base of the tower is 

measured 75 feet diagonally or 70 feet between the two opposite faces. The 

slope of the vertical face of the tower is approximately 1 H' to 21 V. The legs 

uf the s tee1 tower wi l l be supported by a concrete ring wall which wi 11 rest on 

a 10 foot thick ring mat foundation with 110 feet outside and 40 feet inside 

diameters respectively. The top of the mat wi 11 be 10 feet below the grade. 

Design References: 

a Uniform Building Code 

e AISC Manual of Steel Construction 

e Design Response Spectra for Seismic Design of Nuclear.Power 

Plants (NRC Regulatory Guide 1.60) 
e Damping Values for Seismic Design of Nuclear Power Plants 

(NRC Regulatory Guide 1.61 ) 

e Building Code Requirements for Minimum Design Loads in Buildings 

and Other Sturctures (ANSI A58.1-72) 

e Guide for Design of Steel Transmission Towers (ASCE Manuals & 

Reports on Engineering Practice No. 52) 

The structural members of the steel tower were designed to resist the stresses 

resulting from the weight of the receiver, the weight of the tower, and the 

effect of wind or earthquake, whichever is crucial. The design loads are as 

fol 1 ows : 

Receiver weight 1 ,500,000 pounds 

Sei smi c 1 oads 0.125 g, maximum ground acceleration in both 

the vertical and horizontal directions at 

survival conditions. Use response spectra 

froti] NRC Reg. Guide 1.60 with 7 percent damping 

Opera ti onal wi nd 36 mph 

Survival wind 90 mph 

The effective wind velocity pressures were calculated in accordance with the 

provisions p.rovided by ANSI A58.1-72. In calculating the so'lid exposed area 

of the structural member, the actual exposed area of one face has been increased 

by 100 percent to allow for -the pressure on the opposite face. 

Stresses: Structural members of the steel tower were sized conforming to AISC 

requirements. ~ea-d load combined with survival wind load of 90 nlph governs the 

design. The a1 1owab.l e stresses were increased one-third for that load conbination in selecting the member sections. 

Analysis Studies: The STARDYNE computer program was used to perform the analysis 

of the s tee1 tower for dead 1 oad combined wi th wind 1 oad condl tions. For the 

analysis of dead load combined with seismic load condition, the Stearns-Roger 

6163 computer program has been employed. A fixed base model was assumed and the 

receiver support structure was considered to be infinitely rigid due to a lack 

of information on the nature of the. support structure. Lateral deflection of 
the receiver centerl ine under survival earthquake condition is 7.10 inches and 

that under operational wind (36 mph) condition is 2.88 inches which is less than 

the allowable 1 imit of 7 inches. Lateral acceleration at the receiver centerl ine 

is 0.063 g's and the vertical acceleration at the receiver centerine is 0.337 g's. 

The fundamental frequencies are 0.303. cps in the lateral 'direction and 3.670 cps 

in the vertical direction. 

Flaterial s: A1 1 structural steel members for the solar receiver tower shall be 

ASTM A36 steel., A1 1 primary field connections shall be made with 7/8-inch 

diameter ASTM A325 high-strength bolts. Concrete for the foundation ring wall 

and mat shall be 3000 psi minimum ultimate compressive strength at 28 days. 

Reinforcing tars shall be intermediate grade conforming to ASTM A615, Grade 60. 

Allowable Soil Pressure: The Woodward-Clyde Soil Report fpr Reeves Power Plant, 

dated March 26, 1957, was referenced for the foundation design. A 4000 psf maximum allowable bearing pressure was used, allowing a one-third increase for dead 

load combined with wind or earthqake load conditions. 

TOWER ECONOMIC STUDY 

The cost breakdown in Table 4.5-1 shows the concrete tower to be more economical 

than the structural stee'l tower in direct field cost by nearly .$360,000. 

BUILDING EXTENSION 

The main building wil.1. be extended as shown on the General Arrangement drawings 

in order to house the majority of the new solar repowering equipment. The 

structure will be approximately 80 by 50 feet and be three stories high. Construction will match that of the existing plant, will consist of a structural 

steel frame supported on spread concrete footings; the building will abut the 

existing structure, but will not be attached to it. 

Architectural treatment will match the existing structure with walls being of 

concrete block and fluted metal siding. The roof will be constructed of metal 

decking with insulated built-up roofing placed over it. 
TABLE 4.5-1. TRADE STUDY--CONCRETE VERSUS STEEL TOWERS 

CONCRETE TOWER 

Unit Menhours 

QU a 6Fitfl-ilT C m t UCK76faT$-aG-M3FrTaTaIh-aT- -- 25 MW sol zr re.)owerins station 

A Exczvation and 

OocLf 1; 1 2U00 G't 

B Concrete 

~oundat i on 

Mat 1765 CY 55 5 8,825 12 105,900 88,250 

Fc~undation 

Rehar 9 3 T 4013 Inc'l 

Tower Concrete 1855 CI 50 27 50,085 12 601,020 92,750 693,770 

Tc.wer Rebar 75 7 400 inc'l 3~3,000 30,000 

TOTALS 706,920 23,8200 9,800 964,920 

-- - 

STEEL TOWER 

Unit Manhours 

Steel Tower Quantity Uiit Cost Unit Total $/MH Labor Marerial Other Total 

25 MW sol a-- rlpcwering stat ion 

A Excz~ation and 

Back'i 11 4600 13' 

8 Conci-ete 

Concrete 3054 CY 50 5 15,270 12 183,240 152,700 335,940 

Rebar 168 T 400 inc'l 67,200 67,200 

C Steel 

Structural 660 T 1100 18 11,880 15 178,200 726,000 904,200 

TOTALS 361,440 945,900 16,100 1,323,440 
The floor supporting the control equipment will consist of metal decking with a 

concrete wearing surface. This floor shoul d be designed wi th vibration dampeners 

and isolation equipment in order to protect the control equipment from the heavy 

rotating equipment housed on the ground floor. 

Receiver feed pump foundations wi 11 be spread footings on structural backf i 11 . 

4.5.3 FIELD SIZING AND SHAPE 

The size and shape of the heliostat field have an overriding effect on site 

design. A field modified to meet site requirements was chosen. The field was 

extended as far north as possible in order to limit process and electrical runs 

and also to utilize land current'ly owned by PNM but used only as pole storage. 

Western field limits were established by the large physical barrier of the flood 

control drainage structure. 

The heliostat field requires .acquisition of about 130 acres of land south of 

the existing plant. Purchase of an additional strip of land of equal length on 

the eastern edge of the field is contemplated for use as a construction contractor's Saydown area. 

The MIRVAL computer code, along with two preprocessor codes, was used to size the 

field and locate the heliostats in order to obtain the desired station power 

output. A deployment of 4289 heliostats met this requirement. The field is 

shown on drawings Y1-1 and Y1-2. The MIRVAL program is described in Section 4.6.1 

as are subsequent parametric analyses of the he1 iostat fie1 d. 

4.5.4 CIVIL SITE DESIGN 

A pervasive design feature of the solar-repowering at Reeves Station is the 

retrofit aspect of the work. This particular feature has a sustained impact 

on the Civil Engineering efforts often forcing solutions that are at best only 

compromises. .The compromises, while not a1 together acceptable for a new plant 

site, are solutions which become palatable when adding new equipment not anticipated in the original plant design. 
4.5.4.1 HELIOSTAT FIELD LAYOUT 

The size and shape of the heliostat field have an overriding effect on site 

design. An idealized he1 iostat field such as that planned for Barstow would 

be unwieldy and inefficient on this site. Such a field placed as close as 

possible to the south fence line (to limit steam lines) would spread across the 

drainage structure to the west and create access problems within the field. 

Fortunately, other major physical i terns that could affect the he1 iostat field 

(cool i ng towers, oi 1 tanks, subs tations , maintenance and storage structures) 

were located in a relatively convenient sit.~rat.ion at Reeves Station. This 

cannot be expected at a majority of repowering sites. As it is; relocation of 

the transmission line is a requirement of the Reeves Site since it would divide. 

the field. 

A surrounding field modified to meet site requirements was chosen. The field was 

located as far north as possible in order to 1 irni t process and electrical' runs 

and also to utilize land currently owned by PNM but used only as pole storage. 

Western field limits were establ ished by the large physical barrier of the flood 

control drainage structure. As the field was to be symmetrical, this also 

es tab1 ished the eastern boundary. 

The MIRVAL computer program, along with two preprocessor codes, was used to size 

the field and locate the helimtats in order to obtain the desired unit power 

output. The programs were used to establish the site results in an array of 

4289 heliostats. This field was intentionally sized roughly 10 percent higher 

than necessary to allow for interferences with existing fuel storage tanks, 

steam line runs, roads and other obstacles to heliostat placement. This field 

is shown on Drawings Y1-1 and Y1-2. The heliostat field for the solar subsystem 

and the MIRVAL program are described in Section 4.6.1.a~ are subsequent parametric analyses and program runs that take into account heliostats deleted from 

earlier results. The field requires acquisition of about 110 acres of land south 

of the existing plant. Purchase of an additiqnal strip of land of equal length 

on the eastern edge of the field is cont~mp1at.er-l for use as a construction contractor's laydown area. 
4.5..4.2 SITE DESIGN CONSIDERATIONS 

The layout of the heliostat field should provide for ready access to the tower 

and heliostat field for maintenance and safety purposes. The field should slope 

sufficiently for drainage so that there will be no standing water about the 

heliostat foundations. If possible the field should be essentially in the same 

plane to avoid complications in heliostat siting. 

Each site will dictate the best solution to that site's drainage problems; 

crowning slopes, one-way slopes, varying slopes, as we1 1 as 1 differing levels for 

various heliostat areas. This site allows a nearly ideal approach. 

Crowning the site with a center ridge was considered but abandoned for a uniform 

slope of 1 percent in the direction of the natural slope of the land. The laydown area was sloped at 2 percent. This system provided a closely balanced cut 

and fill. A drainage ditch was provided running south to north on the western 

boundary in order to protect the con~rete lining of th'e flood control structure. 

4.5.4.3 FLOOD CONTROL 

In the past decade, Albuquerque experienced severe flooding in the plan below 

the Sandia Crest. As a result, the A1 buquerque Municipal Arroyo Flood Control 

Authority was formed. Through it the Corps of ~ngineers designed and constructed 

an extensive flood control sys tem. The Authority now administers .this system 

and controls all planning and development in the area which could effect storm 

water runoff in periods .of high intensity storm. Any work on the site which 

could affect flooding will need approval by the Authority. Figure 4.5-2 shows 

design storm i ntensi ty for the A1 buquerque area. 

As noted previously, one of the two main flood control channels forms the western 

boundary of the site; A large concrete and stone inlet to that channel drains 

the Arroyo Domingo Baca and Arroyo Del Pino North across the center of the proposed heliostat field just south of the existing plant boundary. A second 

similar inlet structure exists immediately south of the proposed site draining 

the Pino Arroyo into the flood control system. See drawing Y4-3. 
Figure 4.5-2. 100-Year, Six Hour Precipitation 
Three concepts were explored to cope with the drainage problem. In order to 

distinguish the concepts, they have been arbitrarily assigned the various titles: 

8 Concept ( I ) Underground Diversion. (Drawings Y4-1 and Y4-2) 

8 Concept (2) Northerly Diversion (Drawings Y4-3 and Y4-4) 

8 Concept (3) Southerly Division (Drawings Y4-5 and Y4-6) 

The following design parameters are common to all three diversion schemes; 9100 

equals 1,300 cfs and a freeboard of at least 1.75 feet. The concepts are ranked 

in their order of preference and construction mert as follows: 

, 

Concept (I)--:\ twin, 10 foot-0 inch wide b.y 8 foot-0 inch high reinforced concrete box culvert with attendant inlet and outlet structures. The culvert 

will transverse the proposed site in a northwesterly direction. The inlet 

structure will be placed in the deeper portion of the flood pool formed by an 

earthen embankment. The earthen embankment will sever to collect and funnel the 

storm waters to the inlet structure of the box culvert, which in turn will 

transport the storm waters underground to the outlet structure, where the waters 

are shunted into the existing North Pino Arroyo inletworks of the North Diversi~n 

Channel. 

This Concept (1) is feasible and aesthetically pleasing as the majority of the 

construction is buried and will not be visible from the ground. There will be 

no loss of acreage from the Solar Power Unit Site Area to accommodate the underground culvert. In addition, there will be a minimal of interference and reconstruction of the North Pino Arroyo inletworks to the North Diversion Channel. 

It is our understanding that the inlet works mentioned above is capable of 

accepting the design Q of 1300 cfs. 

Concept (2)--A trapezoidal open channel (3900 feet plus or minus lonq) CIJ~ into 

the existing ground along the eastern and northern periphery of the site, at a 

constant slope and bottom width with side slopes of 2:l. The bottom width has 

been set at 14 feet-Oinches. The bottom of the channel and the side slopes up 

to a vertical height of 8 feet-0 inches are to be constructed of Soil-Cement. 

The remaining channel ,height wi 11 be constructed with suitable in si tu soils. 
It will cross under two access roads between the existing plant and the Solar 

Power Unit Site. At each of these crossings it will require a twin 10-foot, 

0-inch-wide by 8-foot 0-inch reinforced concrete box culvery with necessary 

transitions. The culverts will be approximately 50-feet 0-inches in length at 

the westerly access road and 100-feet 0-inches in length at the easterly access 

road. 

Concept (2) entails a major portion of the construction to be visible from the 

surface. Since the Site i s i n an area of historically low rainfall precipitation the wind blown debris collected in the open ditch may not be flushed clean 

duri ng annual storms and it may become aesthetically unacceptable unless frequent 

cleaning and maintenance are provided. Another disadvantage with this concept 

is that the trapezoidal channel will require approximately 5 acres of land area. 

In addition, this concept will entail more cbnstruction at the intertie with the 

North Pi no Arroyo i nl etworks than Concept (1 ) . 

This Concept (2) would displace approximately 60 south-facing he1 iostats. 

Concept (3)--A trapezoidal open channel (4500-feet plus or minus long) with the 

same typical channel cross section as in Concept (Z), except it will be alonq 

the eastern and southern boundaries of the site and connecting to the existing 

Pfno Arroyo inletworks. 

Concept (3) wi 11 have similar aesthetic disadvantages as discussed in Concept (2) 

In addition, there are two more disadvantages for this concept: First, since the 

channel will run out of the County boundary, approval and a permit from the City 

of A1 buquerque will be requi red; second, the existing Pino Arroyo inletworks 'has 

to be enlarged to carry the diverted storm inflow as required. 

This Concept (3) will involve purchase. of additional expensive 1 and to the south 

of the site. 

The following total site quantities were estimated for each nf the concepts: 
Concept No.. 1 ,- Underground Diversion 

I tem No. 

1 

2 

3 (a) 

4 (b) 

I tem No. 

1 

2 

3 (a) 

4 (c) 

5 (b) 

- I tem NQ, 

1 

Description Quan ti ty 

Excavation 646,000 

Embankment 593,000 

Structural Concrete 6,750 

Concrete emo oval 100 

Concept No. 2 - Northerly Diversion 

Description Quanti ty 

Excavation 1,158,000 

Cmlank~-iie~i 1 600,000 

Structural Concrete 5 30 

Soil Cement 6,000 

Concre 1;e Removal 200 

Concept No. 3 - Southerly Diversion 

Description Qua11 Li ly 

Excava ti on 1,186,400 

2 Ewbankmen t 

3 (d) Concrete Paving 

4 (4 Soil Cement 

5 (b) Concrete' Removal 

Unit 

CY 

C Y 

C Y 

S Y 

- Unit 

CY 

CY 

C Y 

C Y 

SY 

(a) Formed structural concrete 

(b) Paved invert and .Side walls of 2:l - 8-inches pl us or minus thickness 

(c) 9-inch plastic soil cement, side slopes of 2:l 

(d) Same as (b) only this is new' rock 

Total cut and fill are bal anced in Concept (1 ) but this was not possi ble in the 

other two concepts. 
Relative costs based only on the quantities shown are: 

a Concept 1 .......... $3,140,000.00 

e Concept 2 .......... $1,802,000.00 

e Concept 3 .......... $1,753,000.00 

Figure 4.5-3 shows a cost estimate breakdown by major job cost accounts for the 

project. 

No allnwance for additional land acquisition requirements has been made in 

Concept (3). 

Operating and engineering v4ewpoints recommended Concept (1 ) . It is the best 

solution. Two-thirds of its cost is caused by the concrete structure. Phis 

cost may be dramatical ly reduced after further hydrological studies. 

At this point, the reliability of the basis for the design limited further study. 

The flows used were provided by the Authority but were based upon dated hydrology 

studies. Much of the land involved has since beer1 developed and flows seriously 

changed. This conceptual work shows that the flood control problem Is solvable. 

However, extended hydrology investigation will be necessary before further 

decisions can be reached as to the most fea'si ble and economl'cal concept. 
SOLAR HYBRID REPOWERING 

REEVES UNIT 2 

51% 

SOLAR COLLECTORS 

Figure 4.5-3. Cost Estimate Breakdown by Major Job Cost Account 

'4-21 3 
4.6 PLANT PERFORMANCE--SOLAR SUBSY STE!4 

The development of the conceptual design and the sizing and layout of the heliostat collector field to produce 25 MWe for the Solar Hybrid Repowered Plant at 

Reeves Station No. 2 necessitated the selection of several specific design parameters, incl uding tower height, receiver 1 ength and diameter, solar insolation ,. 

and the size and shape of the available land area. The characteristics of the 

final conceptual design of the heliostat fie1 d, as well as pertinent information 

relating to the choice of the design parameters utilized, are described herein. 

1.n addition, the results of the heliostat field parametric analyses are also 

gi ven . 

Section 4.6.1 details the development of the conceptual design, including the 

assumptions relevant to the ahalysis and the initial choice of design parameters. 

Section 4.6.2 presents a discussion of the.parametric analyses performed .to 

yi el d a more cost e t'fec ti ve sys tem. 

4.6.1 DEVELOPMENT OF THE CONCEPTUAL DESI GN 

DESIGN PARAMETERS AND ASSUMPTIONS 

The following design parameters and assumptions are relevant to the analyses: 

The design power level far the solar subsystem is 25 MWc at 

2:00 p.m. .winter solstice 

e The solar insolation has been assumed to be 950 W/m 2 

The MIRVAL computer code, which has been developed by Sandia 

Livermore, along with two preprocessor codes, has been used to 

size and analyze the various heliostat field configurations 

0 The heliostat and central 'receiver employed i n . t h e analyses are 

the Mcnnnn~ll nouqlas Astronautics Company (MDAC) designs , as 

shown in Figures 4.6-1 and 4.6-2. It should be noted that the 

heliostat as modeled by MIRVAL is a square with a side length of 

6.5 m (21.3-ft). Account was taken. for 1 ight rays falling 

between facets, and hence, the total mirror area of each heliost.at is 38 m2 (455-ft.2). 

o The heliostats have been placed in a radial stagger arrangement 

so as to minimize the effects of blocking and shading 
Figure 4.6-1. He1 iostat Design (McDonnell Douglas) Mnd~led by MIRVAL 
Fig~re 4.6-2. Tower and Receiver Design (McDonnell Douglas) Mcdel ed by FIIRVAL 
AVAILABLE LAND 

The initial area of available land identified by PNM for the solar collector 

(heliostat) field at Reeves Unit No. 2 is shown in Figure 4.6-3. In general, 

the land area to the north of a central receiver tower is more efficient in 

terms of solar energy collected. Moreover, the square area to the east, 

609.6111 x 609.6m (2000-ft x 2000-'ft), would not be used unless the electric 

power requirement of the plant could not be met with the remaining land available. This would insure the use. of a symmetric solar collector fie1 d, and hence 

would tend to more evenly distribute the energy incident on the receiver. However, an analysis was made utilizing some land to the east, so as to given an 

indication of the power produced with this configuration. 

MI RVAL 

The evaluation of the heliostat fields considered was accomplished with the MIRVAL 

computer code. MIRVAL is a Monte Car10 program in which the interaction of light 

rays from the sun with an arbitrary array of mirrors and a solar energy receiver 

is simulated. Several different types of mirrors and receivers can be analyzed. 

Phenomena whose effects are simulated include shading, blocking, mirror tracking, 

detailed opt'ics of the reflective surfaces, insol ation and the angular distri bution of i ncomi n.g sun rays. 

RECEIVER AND TOWER SIZING 

In order to size and make a layout of the heliostat collector field for a 25 MWe 

Solar Hybrid Repower Plant at PNM Reeves Unit No. 2, preliminary sizes for the 

diameter and length of the receiver and for the tower height at the centerline 

of the receiver were required. Basically, the external receiver and tower 

designs for this analysis can be scaled from the McDonnell Douglas Astronautics 

Company (MDAC) design for the 10 MWe Solar Central Receiver Pilot Plant. 

Calculations indicated that a thermal power of approximately 92 MW would be 

required to yield the proper level of electrical generation. In addition, 

initial values for receiver diameter and length, as well as tower height, were 

computed. These were a receiver diameter of 12m (39.4-ft) , a length of 21m 

(68.9-ft) and a height to the center1 ine of the receiver of 135m (443ift). 
NORTH 

121.9 m - 

(400 ft. ) 

609.6 m 

(q000 ft.) 

1 It - 609.6 m - 4 

I- (2000 ft . ) 

--- -- 1219.2111 - 

(4000 ft,) 

d 

Figure 4.6-3. Initial Area of Available Land Identified for 

the Heliostat Field at Reeves Unit No. 2 

4-218 
The following discussion illustrates the calculational methodology by which the 

receiver and tower sizing was accomplished. 

THERMAL POWER ABSORBED INTO STEAM 

The thermal power absorbed into the steam at the solar receiver for Reeves Unit 

No. 2 is a function of the turbine heat rate and the auxiliary (parasitic) power 

losses. The percent auxiliary power for the Reeves Unit No. 2 as it exists 

today was derived from two sources. Using primarily heat balance computations 

dated August 15, 1958, the auxiliary power requirements at full load were 

evaluated as 5.82 percent. Based on the past performance tests for Reeves Unit 

No. 2 at full load for the 197511977 time period, an auxiliary power of 5.08 percent was quoted. A nominal value of 5.4 percent was taken for this analysis. 

Also, an additional auxiliary power requirement of 4.6 percent was estimated to 

convert the unit to a solar plant and to cover the thermal and pressure losses 

in the piping run from the base of the tower to the existing turbinelgenerator 

at Reeves Unit No. 2. Combining these auxiliary power losses yields an estimated value of 10 percent, or an auxiliary "efficiency," nay of 0.90. 

The turbine heat rate, HRT, for Reeves Unit No. 2 to be used for this analysis is 

9333 Btu/kW-hr. Thus, the net turbine efficiency, qT, is: 

For an electrical power output, Pe, of the solar portion of a hybrid repowered 

plant of 25 MWe, the thermal power, Pt, absorbed into the steam is: 

I 

- e - 76.0 MWt 

Pt -FTHERMAL POWER INCIUENI' UN THE KECETVEK SUKFACE 

The required thermal power incident on the receiver surface is based on the above 

thermal power absorbed lnto the steam, the losses that account for re-radiation 

and convection from the receiver, and the,loss due to the absorptivity of the 

receiver surface. The efficiency that accounts for most of the re-radiation and 
convection losses from the receiver, qrAc, was taken as 0.887 and was based on 

the MDAC efficiency chart for the 10 MWe Pilot Plant design. Additional losses 

from the receiver were taken into account by an efficiency, qr, of 0.98 to cover 

the balance of the re-radiation and convection losses from the external surface 

of the receiver. The efficiency due to the absorptivity of the receiver 

surface, qa, was taken as 0.95. 

Thus, the required thermal power incident on the receiver surface for the 25 MWe 

plant, Pt,r,25, is: 

- L = 92.0 MWt Pt,r,25 (qr&C) (nr) ha) 

This value is comparable to the thermal power incident on the receiver surface 

for the MDAC 10 MWe Pilot Plant Design, Pt,r,lO, of 38.7 MWt. 

TOWER HEIGHT AT THE CENTERLINE OF THE RECEIVER 

The height of the tower at the centerline of the receiver for a solar central 

receiver varies approximately as the square root of the thermal power incident 

on the receiver surface. This tower height for the MDAC 10 MWe Pilot Plant, 

HI0, e, is 80.0m (262-ft). Therefore, the tower height at the receiver centerline for the 25 MWe Reeves Unit No. 2 solar hybrid repowered unit is 

approximately: 

The diameter, DlO, and length, L10 , 0.1 the exlerr~al receiver for the MDAC 10 MWe 

Pilot Plant Design are 7.0 m (23.0-ft) and 12.5 m (41 .O-ft), respectively. 

In order to retain an approximate maximum thermal flux on the outside surface of 

2 the receiver of about 0.30 MW/m (corresponding to the 10 MWe Pilot Plant) for 

the 25 MWe Solar Hybrid Repowering Plant at Reeves Unit No. 2, the diameter and 

length need to be increased. Preliminary sizing of this 25 Me receiver suggestec 
that each of these dimensions be increased in equal proportions. Thus, the 

receiver diameter for the 25 MWe plant, DZ5, is approximately: 

1 /2 

= 10.8m (35.4 ft) 

and receiver length, LZ5, is: 

1 /2 

= 19.3m (63.3 ft) 

ANALYSIS 

Three MIRVAL analyses were initially made in an attempt to bound the required 

design parameters. The first case employed the aforementioned values for 

receiver diameter [12m (39.4 ft)] and length [21m (68.9 ft)] and tower height 

[135m (443 ft)]. The land area utilized is shown in Figure 4.6-4. Note that 

this is a symmetric collector field. The number of heliostats placed in the 

field is 4153, and the thermal power incident on the receiver at 2:00 p.m'. 

winter solstice is 87 MW. 

The second case run was identical to the first, except that an additional strip 

of land .~150m (492 ft) wide was added to the east. This land area is shown 

in Figure 4.6-5. The number of heliostats in this configuration is 4730, and 

the power into the receiver at 2:00 p.m. winter solstice is 102 MWt. 

The third case in the initial series of computer runs was also identical to 

the first, except that the height to the centerline of the receiver is 155m 

(508 ft). At 2:00 p.m. winter solstice the power into the receiver is 93 MWt. 

The 4488 heliostats are deployed in the same area shown in Figure 4.6-4. 

A summary table of the above results is given in rable 4.6-1. 
NORTH 

ft.) 

Fi gure 4.6-4. Initial Land Area Used in the Analysis 
NORTH I I 

-- -- 759.6 rn - - - 

(2492 ft.) 

-- 4 

Figure 4.6-5. Asymmetric Heliostat Field with Additional Land to the East 
TABLE 4.6-1 . INITIAL MIRVAL RESULTS 

The rma 1 Power 

Into Receiver at 

Recei ver Diameter Number of 2:00 p.m. Winter 

- Case Ce'n terl i ne (ml and Length (ti) Helios tats Sols ti ce (MW) 

1 135 (443 ft) D = 12 (39.4 ft) 41 53 8 7 

L = 21 (68.9 ft) 

2 135 (443 ft) D = 12 (39.4 ft) 4 730 

L = 21 (68.9 ft) 

3 155 (508 ft) D = 12 (39.4 ft) 44 88 

L = 21 (68.9 ft) 

The above results indicated that a thermal power incident on the receiver of 92 MW 

would be achievable. Only the combination of design parameters remained to be 

chosen. 

Consultation with PNM indicated that an additional parcel of land to the north 

was also available for the Solar Hyhrid Repowered Plant, as shown in Figure 4.6-6. Therefore, the decision was made to utilize only the symmetric portion of the field illustrated in the figure. Th-i~ would have the affect of 

distributing the reflected solar insolation on the receiver more cvenly dur-illy 

the course of a day. In addition. the height to thc center1 ill@ of the receiver 

was chosen to be 150m (492 ft). Receiver dimtrrsions r%e~~~;lined the same; i .e., 

length = 21m (69 ft) and diameter = 12m (39 ft). 

The final MIRVAL run yielded a thermal power incident. on the rcceiver oP 92.2 MW 

2 at 2:00 p.m. winter solstice at a design insolation value of 950 W/m . 

The initial conceptual design of the t~ellostat field is shown in Figure 4.6-7, 

The numbcr of heliustats requiraed is 4289. The circular exclusion area at the 

2 5 2 base of the tower is approximately 38,000 m (4.09 x 10 ft ), corresponding to 

a radius of llOrn (361 ft). 

Table 4.6-2 is the thermal power incident on the receiver at various times of 

the year. 
NORTH 

--- 

403.9 m 

9 m 

ft. 

I 609.6 m -4 

k --- -- (2000 ft.) 

1219.2 m - - - 4 

(4000 ft. ) 

m 

ft.) 

Figure 4.6-6. Final Area of Available Land Identified for 

the He1 ios ta t Fi el d at Reeves Uni t No. 2 
.- ';, 7,. . ..:'+,. 

. $2. --d -- I., 811. If, . ,,-~ 'n,',, ,I.. , 

Figure 4.6-7. Heliostat Arrangement for Initial Baseline Conceptual 

Design (Total Number of He1 iostats : 4289) 
TABLE 4.6-2. POWER INCIDENT ON RECEIVER AT SELECTED TIMES OF THE YEAR 

FOR INITIAL BASELINE CONCEPTUAL DESIGN WITHOUT ROADS 

(4289 HELIOSTATS) 

Time of Year 

2:00 p.m. Winter Solstice 

Noon Winter Sol stice 

Noon Vernal Equinox 

Noon Summer Sol stice 

Annual Average 

Power (MW) 

92.2 

102.8 

112..8 

114.0 

100.5 

Figure 4.6-8 is a detailed (1,000,000 Monte Carlo trials) flux map on the 

r-e~eiver. at noon summer S6lstice based on the initial baseline conceptual 

design with 4289 heliostats. 

UPDATED CONCEPTUAL DESIGN 

The preprocessor code originally utilized to lay out the collector field for the 

conceptual design described above was found to not completely eliminate possible 

heliostat interference. Figure 4.6-9 illustrates the potential interference 

problem. For example, note the potential interference problem between row #8 

(a slip plane) and rows #7 and #9; e.g., between he1 iostats #411 and #353, and 

heliostats #411 and #469. This problem persists between slip planes and the 

rows preceding and following the slip plane rows until such time that the 

heliostats are placed far enough apart to completely avoid interference, as is 

the case when heliostat blocking causes adjacent rows to be widely separated. 

Addittonal interference problems were noted at slip plane rows #16 and #27 with 

their adjacent rows, respectively (see Figure 4.6-9). 

The design as given initially was considered to be undesirable and work was 

geared toward correcting the preprocessor code. This was accomplfshed by a 

trial and error procedure that produced a satisfactory heliostat configuration. 

A more rigorous correction of the code is expected from Sandia Livermore in the 

near future. 
-- TOP 

I- BOTTOM 

l- I I I I I li I I I I I I I I I I I I 

-18.85 -16 -1 2 -8 4 0 4 

I 

8 12 16 18.85 

I (m) 

SOUTH 

P NORTH 

2 

B 

.Figure 4.5-8. Flux (MW/rn ) on klonnell Douglas Receiver at Noon Summer Solstice for 

Initial Base1 ine Conceptual Design (4289 He1 iostats) 
RGW. 

TYPICAL HELIOSTAT 

DlMENSIONS 

20 

:7 

o 20 40 SO 80 I~O 120 ~eo 160 

Figure 4.6-9. Detailed Plot of the Heliostats from 4289 Heliostat Field Showing 

Interference in Slip Plane Regions (Initfal Basellne Conceptual 

Design) 
The updated conceptual design of the solar hybrid repowered plant utilizes 

4185 heliostats. The heliostats are deployed in the same area as before (see 

Figure 4.6-7). An enlargement of a sector of the field is shown in Figure 4.6-10, which shows that the heliostat interference problem has been corrected. . This heliostat configuration produces 91.8 MWt incident on the 

receiver at 2:00 p.m. winter solstice. 

NORTH-SOUTH ACCESS ROADS 

Access to all heliostats in the field is required to perform routine maintenance 

and repair. Thls is accmplished by the inclusi~n of north and south access 

roads. A 50-ft wide south road was sel eeted. A1 1owdI'lce for steam and ftaedwater 

lines along the north road necessitates an overall width of 68-ft for this road. 

The resulting heliostat field, shown in Figure 4.6-11, contains 4086 heliostats. 

The deployment produces 89.5 MWt incident on the receiver at 2:00 p.m. winter 

solstice. Util izing an overall conversion efficiency of ~0.28 calculated by 

Stearns-Roger, 25.0 MWe will result from this configuration. Table 4.6-3 is 

the thermal power incident on the receiver at various tiiires of the year, and 

Figures 4.6-12 through 4.6-16 are flux maps on the receiver at these times. 

TARLE 4.6-3, POWER INCIDENT ON RECEIVER AT SELECTED TIMES OF THE YEAR 

FOR rINAL BASELINE UWNCEPTIJAL DESIGN WITll ROADS 

(4086 H~LIOSTATS) 

Time of Year2r00 p.111. Winter Solstice 

Noon Winter Solstice 

Noon Vernal Equinox 

Noon Sumner Sol stice 

Annual Average 

Power (MW) 

It should be noted that the receiver as modeled by MIRVAL is a right circular 

cylinder. The aim point for a mirror 1 ies ori the cylindrical surface and in a 

vertical plane through the center of the mirror and the receiver centerline. 

The aim point for the mirrors 1 ies 114, 112 or 314 of the way up the cylindrical 
Figure 4.6-10. Detailed Heliostat Plot from Updated Conceptual Design 

(41 85 He1 iostats) Showing El imination of Interfcrcncc 

ROW: I 
NORTH 

Figure 4.6-11. Heliostat Deployment for the Final Baseline Conceptual 

Design with North-South Access Roads 

(Total Number of He1 iostats: 4086) 
- - TOP 

- - BOTTOM 

I I 

UORTH 

2 Figure 4.6-12. Flux (W/m ) on McDonnell Dougl~s Receiver at 2:00 p.m. Winter Solstice for 

Final Conceptual Design with North and South Access Roads (4086 He1 iostats) 
- TOP 

- BOTTOM 

I I I I I 1 I I I I I I I 1 I I 1 I I 

-18.85 -16 -1 2 .-. j 4. 0 4 8 12 16 18.85 

I 

I (m) 

I 

SOUTH NORTH 

2 Figure 4.6-13. Flux (MN/m ) on McDonnell Douglas Recefver at Noon Summer Solstice for 

Flnal Conceptual Qeslgn wfth North and South Access Roads (4086 Heliostats) 
I I I I I I I I I I I I I I I I I I I 

-18.85 -16 -1 2 -8 4 0 4 8 12 ' 16 18.85 

1 

I (m) 

SOUTH NORTH 

E 

2 

e 

Figure 4.6-14. Flux (Mw/~ ) on McDonnell D,~uglas Receiver at Ncon Vernal Equinox for 

Final Conceptual Design wit5 North and South Access Roads (4086 Heliostats) 

1,- TOP 

.- - BOTTOM 
SOUTH IllORTH 

e 

2 

E 

Figure 4.6-15. Flux. (MW!m ) on McDonnell Doug'las Receiver at Noon Winter Solstice for 

Final Conceptual Design wlth North and South Access Roads (4086 He1 iostats) 

TOP 

BOTTOM 
-- BOTTOM 

a 1 I I I I I I 11 

-18.85 -1P -1 2 .-8 4. 0 4 8 12 16 18-,85 

I 

1 (ml 

SOUTH YORTH 

2 Figure 4.6-16. Flux (MN/rn ) on McDonnell Docglas Receiver on an .Annual Average Basis for 

Final Conceptual Design with North and South Acce;s Roads (4086 He1 iostats) 
surface in this plane, representing an overall three-point aiming strategy; 

every third heliostat is aimed at one of these locations. This aiming strategy 

serves to distribute the thermal power incident on the receiver surface more 

evenly and thereby avoid any local hot spots on the receiver. 

4.6. 2 PARAMETRIC ANALYSES 

Various parametric analyses have been performed in an attempt to produce a more 

cost effective system. Tower location and tower height, as well as selective 

field trimmings, have been analyzed with respect to savings in total plant cost 

and net electric power output. The analyses have been keyed to the final conceptual desiqn with access roads included (4086 haliostats), and with a tower 

height to the centerline of the receiver of 150m, which produces a net electric 

output of 25.0 MW. 

TOWER HEIGHT 

Two cases were considered in which the height to the receiver center-line could 

be evaluated with regard to its impact on the system at the design point of 

2:00 p.m. winter so'lstice. First, a height to the centerline of the receiver 

of 135m (443 ft) was investigated, while the land area was held fixed. Then a 

height to the centerline of the receiver of 165m (541 ft) was examined. Both 

situations resulted in a net reduction in field performance, based on the percent changes in cost and power output, as shown in Table 4.6-4. 

HEIGHT TO RECEIVER CENTERLINE = 135m 

For a height to the receiver centerline of 135111, the number of heliostats placed 

in the same field area is 3910, and 85.6 MWt is incident on the receiver at 

2:00 p.m. winter solstice. This is equivalent to 23.9 MWe electrical output. 

In this example, a net luss in fleld pet-.loi.l.~tdr~ct! of 2.2 percent (see Table 4.6-4) 

results when the height to the centerline of the receiver is reduced from 150m 

to 135m. In other words, the decrease in net electric power output (4.4 percent) 

is not ... .- accompanied by a greater decrease in the pcrcentage of tol;al plant cost 

(only 2.2 percent). Hence, this method of improving plant performance is deemed 

to be unacceptable. (Note that it has been assumed for this ana.lysis . . that the 

effects of a reduction in plant cost due to a shorter tower are minimal .) 
TABLE 4.6-4. FIELD PERFORMANCE, TOWER HEIGHT VARIATION 

Reference Case* 

(4086 

He1 iostats) 

Total Plant Cost** 

(Millions of 80.0 

Do1 1 ars) 

Net Electric 

Output (MWe) 25.0 

Net Change in 

Performance 

(Percent) 

Hei ght to 

Centerline 

= 135m 

Net 

Savings/ 

Change in 

Power 

Output 

(Percent) 

Net 

Savings/ 

Change in 

Power 

Output 

(Percent) 

+2.2 

-4.4 

-2.2 

*Height to center1 ine of receiver = 150m 

**Cost estimates were based on data given in Section 4.7 of this Report 

Height to 

Centerline 

= 165m 

81.2 

25.4 

HEIGHT TO RECEIVER CENTERLINE = 165m 

The number of he1 iostats deployed in the (fixed) available land area when the 

height to the centerline of the receiver is increased to 165m is 4212. Note 

that the number of heliostats utilized has increased because the higher receiver 

height allows the heliostats to be deployed with a higher overall packing fraction. In this instance, 90.9 MWt is incident on the receiver surface at 

2:00 p.m. winter solstice, which leads to a net electrical output of 25.4 MWe, 

as shown in Table 4.6-4. 

No net change occurs when the height to the receiver centerline is increased to 

165111. Since this net change is zero, some optimum height to the receiver centerline between the reference value of 150m and 165m may yield a very slight overall 

net increase in field performance. These effects are expected to be marginal, 

however. As before, it has been assumed that the additional cost of a higher 

tower does not significantly change the results derived. 

FIELD TRIMMING 

Two examples of field trimming were evaluated to determine the effect on field 

performance. First, an analysis was done wherein the southern corners of the 
field were "clipped," yielding a small reduction in heliostats. Next, a realtively large clipping of the southern corners of the field was examined. Both 

situations resulted in a net loss in field performance at 2:00 p.m. winter 

solstice, as is shown in Table 4.6-5. 

TABLE 4.6-5. FIELD PERFORMANCE, FIELD TRIMMING 

Reference Case 

(408G 

He1 iostats) 

Total Plant Cost* 

(Mill ions of 80.0 

Do1 lars) 

Net Electric 

Output (MWe) 25.0 

Net Change in 

Performance 

( Percent) 

Sma 1 1 

Field Trim 

78.1 

24.1 

Net 

Savings/ 

Change in 

Power 

Output 

(Percent) 

+10.8 

-17.4 

-6.6 

' Net 

Savings/ 

Change in 

Power 

Output 

(Percent) 

+2.3 

-3.7 

-. 

-1.4 

*Cost estimates were based on data given in Section 4.7. 

Small Field Trim 

Large 

Field Trim 

71 .4 

20.6 

When the southern cor'ners of the he1 iostat field are removed, tho numbel- of he1 iustats in the configuration is 3904, which in' turn produc'e 86.2 MWt incident on 

the receiver at 2:00 p.m. winter solstice. This leads to a net output of , 

24.9 Mkie. As can be seen, the overall field perfohance is reduced by ~1 .4 percent with respect to the design point of 2:00 p.m. solstice. 

Large Field Trim -.-a -....- 

When Lt~e southern corners of the he1 iostat field are grossly clipped, only 

3226 heliostats are deployed and 73.9 MWt are incident on the receiver at 

2:00 p.m. winter solstice. The net electric output is 20.6 MWe. Clearly this 

example illustrates that gross trimming of the southern heliostat field results 

in a large net loss (%7 percent) in field performance. Comparison of the field 
trimming cases above indicates that selective trimming of the extreme southern 

corners of the field may lead to a slight net increase in performance at the 

design point. 

TOWER LOCATION 

Several tower locations were considered in the parametric analyses of the conceptual design of the heliostat field for 2:00 p.m. winter solstice. Tower locations of 30, 40, 50, 75 and lOOm south of the original location and a location 

50m north of the conceptual design location were examined. Indications are that 

an improvement in the field performance can be obtained by relocating the tower 

south of the reference position. This is illustrated by Table 4.6-6. 

Tower 30m South 

With the tower relocated 30m south of the final baseline conceptual design location, the number of heliostats deployed is 4032, yielding 89.3 MWt on the receiver 

at 2:00 p.m. winter solstice, which in turn produces 24.9 MWe. Note that a 

relatively modest improvement in field performance results. 

lower 40m South .-.- 

In this case, 4006 heliostats are located in the field; 90.2 MWt are incident on 

the receiver at 2:00 p.m. winter solstice, resulting in 25.2 MWe. A more significant improvement in field cost effectiveness is provided. 

Tower 50m South 

The number of he1 iastats is 3986 and the power incident on the receiver is 

90.2 MWt, which again yields 25.2 MWe. Note that this heliostat field is more 

efficient in its production of electricity, and hence, compared to the reference 

configuration, this field also performs significantly better. 

Tower 75m South 

The heliostat field is comprised of 3916 heliostats. The power incident on the 

receiver is 89.0 MWt at 2:00 p.m. winter solstice, and this yields 24.9 MWe. 

This deployment also outperforms the reference case. 
TA3LE 4.6-6, FIELD PERFORMANCE, TOWER RELOCATION 

**Cost estimates were based on cata given in Section 4.7. 

! Total 

i i Plant 

i Cost** 

1 (Millions 

of 

I Dollars) 

j 

Net. I 

I I Electric 

P i Output. I 

N 1 (MWe) 

P i N I Net 1 Change 

I in 

Per- I i formance 1 (Percent) 

Reference 

Case 

(4086 

Heliostats) 

80.0 

25,-0 

I i 

TOWER SOUTH I 

*Net Savings/Change in Power O~tput (~ercent) 

+0.3 

i i i 

Net 

Savings* 

30m Percent 

79.4 +0.7 

! 

24.9 -0.4 

- 

~1.8 ; +2.0 

i 

! 

i 

Net I Net 

Savings*! Savings* 

4C1m Percent 50m Percent 

75.2 +1.0 79.0 +1.2 

. . 

I 

25.2 10.8 25.2 +0.8 

- - 

+1 .5 

! 

+2.0 1 -2.8 

TOWER NORTH 1 

Net I .Net i I

savlngs*l Savings*. Savings* 

75m Percent 

78.3 +2.l 

24.9 -0.6 

i 

10Om percent! 50m Percent 

I 

77.5 +3.1 j80.5 -0.6 

i 

I 

I 

I 

24.7 -1.1 24.4 -2.2 I 

I 

1 
Tower 1 OOm South 

In this case, 3838 heliostats are deployed. The power incident on the receiver 

at 2:00 p.m. winter solstice is 88.5 MWt and the electric output is 24.7 MWe. 

This configuration is more cost effective than the reference case, and in fact 

is virtually as efficient as the case where the tower is located 50m south of 

the original position. Hence, in this sense, both deployments appear to be 

equally attractive. However, the thermal flux incident on the receiver in this 

2 case tends to exceed by a relatively large degree the desired 0.3 MW/m maximum 

flux levels, specifically on the panels facing the northern part of the field. 

This is to be expected, since most of the field is north of the receiver. 

Hence, receiver design requirements may impose a limit on how far south the 

tower may be moved, and therefore the situation where the tower is 5011 south 

of the reference position may be a more suitable a1 ternativ.e. 

Tower 5Qm North 

In this arrangement the tower has been relocated 50m north of the original 

position. The number of heliostats deployed in the land area ava'ilable is 

4134; the power incident on the receiver is 87.5 MWt, yielding 24.4 MWe net 

output. Obviously, this is not a cost effective system. It is clear that 

moving the tower north degrades the overall cost effectiveness of the plant. 

DESIGN POINT CONSIDERATION 

If the design requirement was to maximize the amount of solar energy collected 

on an annual basis, then the conceptual design as it now stands would be very 

close to the most cost effective systcm, as is shown in Figure 4.6-17. Note 

that this design stipulation might lead to a tower location approximately 10 to 

20m south of the reference position. 

CONCLUSIONS 

The parametric analyses of the PNM conceptual design demonstrate that a better 

performing, more cost effective plant can be designed with the proper heliostat 

deployment. . Indications are that moving the tower 40m to lOOm south of the 

reference position yields the highest performing plant (see Table 4-6-61. 
CHANGES FROM BASELINE CONCEPTUAL DESIGN (PERCENT), IN OUTPUT POWER 
Changing the receiver height appears to produce no significant benefits. In 

fact, the two situations considered, both increasing and decreasing the receiver 

height, actually tended to degrade the performance of the plant. Trimming the 

southern corners of the field also appears not to yeild significant improvement 

in cost effectiveness of the plant, although selected trimmings of the extreme 

southern corners may lead to a slight improvement in performance. 

It should be noted that the MIRVAL code is a Monte Carlo code and as such the 

results presented are subject to statistical uncertainties. Hence, it is not 

practical to identify any one given heliostat field configuration as the "best." 

However, inasmuch as certain inferences can be made from the results of the 

analyses, it is probably a valid statement that moving the tower south will 

tend to result in a more cost effective system. It also should be pointed out 

that fairly small percentage changes from the conceptual design result from 

the southern relocations of the tower. From an absol ute point of view, the 

performance of the various he1 iostat fie1 ds where the tower has been re1 ocated 

toward the south actually does not change significantly. This is a rather 

important observation, since it indicates that, all other things being equal, 

per.lur~bdliur~s of the conceptual design considered here do not have an extreme 

effect on the performance of the solar subsystem. 
4.7 CONCEPTUAL DESIGN COST ESTIMATE 

The conceptual design cost estimate covers those costs that can be reasonably 

anticipated for the solar hybrid repowering of Reeves Station Unit No. 2 in 

Albuquerque, New Mexico. (See Appendix for the Cost Estimate printout.) / 

Because the technical design of the Project has not proceeded beyond the 

conceptual stage, which covers the major concepts but does not address all of 

the particulars, detailed estimating information is not, available. Thus, a 

cost estimate derived from a conceptual design must be expected to be somewhat 

broad in nature. In general, it is assumed that the accuracy of this cost . 

estimate is within + 25 percent. In certain areas where the design is more 

detailed, or the technology dictates the design, the cost estimate will 

reflect that exactness. This includes the following: 

a Earthwork 2 15 percent 

e Few changes are anticipated as long as Conceptual Design 1 is 

used 

Pipinq + 15 percent - - 

The estimate addresses those costs that are reasonably expected to be incurred 

in this project. Management, contingency and escalation are not included at 

this time; such costs will be added when definite program dates, and government 

and other management policies are established. New Mexico use tax is not 

included as a separate line item at this time. Since Government funding is 

anticipated, when that level of participation is established, this tax account 

will provide for such visibility. 

EQUIPMENT 

Except for the Receiver and Collectors, many of the mechanical equipment items 

are relatively standard for power plants. For these "standard" components, an . 

accuracy of + 15 percent is expected. For the most costly items, the Receiver 

and the Collectors, accuracy is questionable due to state of the art technology 

and the 1 imi ted sources of procurement. As an examp ley the Cvllectors were 

initially priced on a capital cost basis of $250.00 per square meter, excluding 

field wiring. That figure comes from the Barstow Pilot Plant estimate. A 
later figure obtained by PNM was lower. This lower quotation appeared to leave 

certain questions unanswered, however, so a revision of the original price was 

used in the cost estimate. The Receiver price was obtained by PNM and does not 

include escalation. 

CONCRETE 

In the tower, an accuracy - +15 percent can be anticipated because the basic design 

is quite refined. For the underground diversion box culvert, an accuracy of 

+10 percent, -25 percent seems probable. Due to the length of the culvert 

(2800-feet), we believe that production line methods would be developed that 

could save substantial costs when compared to more conventional methods of 

concrete placement for small er quanti ti gs . 

In this estimate all costs are based on 1978 dollars and no allowances for escalation has been made. Certain construction items are generally estimated and contracted for as a package. That is, the labor, material, equipment and mark-up are 

included in one Contract package. Much of this cost estimate is based upon an 

approach wherein the printout shows the entire Contract amount in the "other" 

column with no costs indicated in th~ labor and mater5idl columns. 

Although a column has been left on the printout for labnr hours, no hours are 

shown. These figures can be inserted when that jnformaticn is complete, but at 

present, hours are known for items totaling only minor percentages of the total 

cost . 

The format. of the cstimate wlth a revision column included will increase the 

flexibility and traceability of the inevitable cost changes that occur. For 

example, when a change to the estimate is necessary, the revision number of 

that change would then print next to the changed item at the base level as well 

as next to all other figures that were modified by that.-change. 

The attached summary, Table 4.7-1, has been extrapolated from the detailed cost 

breakdown to show the major areas of expenditure. It is noteworthy that the 

collector and receiver systems, accounting for more than 80 percent of the total 
Project cost, are the areas where the greatest variables in cost data occur. 

Thus, the accuracy of the total cost estimate cannot be more exact than those 

estimates. A cost estimate graphical presentation is given in Figure 4.7-1. 
TABLE 4.7-1. COST ESTIMATE SUMMARY 

COST ESTIMATE BREAKDOWN 

1. Solar Collectors 

Engineering coordination of 

collectors with remainder of 

Project 

Furnish and install solar 

col 1 ectors and associated 

control s 

Installation of solar 

collector control and power 

wiring 

Checkout coll ector system 

2. Receiver 

Engineering coordination of 

receiver wi th remainder of 

Project design of tower, 

tower piping and electrical 

up to existing building 

Furnish and install solar 

recei ver and receiver ' controls 

Tower for Receiver - includes 

earthwork, concrete, foundation and tower, elevator, 

platforms and painting 

Piping from receiver to existing building 

Electrical from receiver to 

exi sting bui 1 ding 

Checkout Receiver System 

Thermal Storage 

% OF TOTAL SUBTOTALS TOTALS 
TABLE 4.7-1 (Cont'd) 

COST ESTIMATE ' BREAKDOWN 

4. Contrr3ls and Instruments 

Engineering and integration 

of controls, instrumentation 

and master control system 

Purchase and install controls 

and instrumentation 

Checkout controls and 

instrumentation 

5. Balance of Plant 

Engineering and integration 

of these components that are 

not part of the electrical 

power generating system 

% OF TOTAL SUBTOTALS 

4% 

Civil/structur.al work including underground diversion 

culvert site grading, warehouse and new buSldlng, 

co1iip1 ete 

Equipment - purchase and 

install 

Piping - purchase and install 

Electrical - purchase and 

instal 1 

Other construction work 

Checkout bal ance of pl ant 

TOTALS 

$ 3,530,800 
TABLE 4.7-1 (Cont'd) 

COST ESTIMATE BREAKDOWN % OF TOTAL SUBTOTALS TOTALS 

6. Electric Power Generating 

Sys tem (EPGS) 

Engineering and integration of 

the EPGS components with the 

remainder of the system 

Equipment - purchase and 

install 

Piping construction work 

Electrical construction 

Other construction work 

Checkout EPGS 

Di stri butabl es 

Fie1 d expense, a1 1 risk 

insurance, payroll taxes, 

bonds 

Construction supplies and 

temporary faci 1 i ti es 472,300 

100% $79,835,750 $79,835,750 
SOLAR HYBRID REPOWERING 

REEVES UNIT 2 

ELECTRIC POWER 

/GENERATING SYSTEM 

/ RECEIVER / /. 

ONTROLS AND 

NSTRUMENTS 

DlSTR IBUTABLES 

t 

\ SOLAR COLLECTORS 

COST ESTIMATE BREAKDOWN BY MAJOR JOB COST ACCOUNTS 

Figure 4.7-1. Cost Estimate Breakdown 

4-252 
4.8 ENVIRONMENTAL CONSIDERATIONS 

A summary of the major environmental considerations for the solar hybrid repowering facility at Reeves Unit No. 2 is presented in Section 4.8.1. Section 4.8.2 

below describes the site as it pertains to these environmental considerations. 

Discussions of the environmental impacts of construction and of the environmental 

impacts of operation are covered in Sections 4.8.3 and 4.8.4, respectively. The 

references cited in Section 4.8 are listed in Appendix C of this Report; 

4.8.1 SUMMARY OF MAJOR ENVIRONMENTAL CONSIDERATIONS 

Based upon a preliminary assessment of the major environmental considerations, it 

appears that there will be no major environmental impacts resulting from construction and operation of the Solar Hybrid Repowered Reeves Station (Unit No. 2) at 

Albuquerque, New Mexico. 

The major potential environmental impacts on air are: 

e For both normal and adverse operating conditions, the maximum 

calculated ground-level concentrations of pollutants will be due 

to the oil-fired operation of the facility and are expected to 

be well below the State of New Mexico and National Ambient Air 

Quality Standards. 

e The emissions produced by the solar/oil facility are approximately 40 percent lower than the emissions produced by a facility 

operating on oil alone. 

The major environmental impacts on water are: 

e Water Use - Water needs for this facility are expressed in the 

need for approximately 15 gallons of water per heliostat per 

month (approximately 800,000 gallons of water per year) for 

washing and rinsing the heliostats during the operation phase 

and drinking water for the construction crew during the construction phase. Water needs are anticipated to be met without 

affecting existing local water users. Conservation and recycling 

wS!! be practiced wherever feasible, 

Water Quality - Operation of the solar hybrid repowering facil.ity 

will produce discharges of cooling waters and discharges of the 

heliostat washing solutions. Neither are expected to have a significant effect on local surface or groundwater resources. 

During construction, runoff could have a temporary effect on the 

local streams. 
The major environmental impacts on the terrestrial resources, human resources 

and ecology are: 

Vegetation - No significant loss of grassland 

Wildlife - No significant habitat loss 

e Endangered Species- Based upon a literature survey, no endangered 

plants are known to be present on-site; some endanqered animals 

may mi grate through the' area 

- 

Land Use - Land in this area could be used for power generation, 

industrial park or housing, but is generally unfit for other 

uses. Proximity of two small locally used airports may pose 

solne lla~ard to pilots due to glint, glare and tower height. 

This would be worked out with FAA authorities. 

e Mineral Resources - There will be no impact to existing mineral 

resources. 

s Seismology - Slight to moderate damage could occur, depending on 

location of epicenter of earthquake. 

r Demographic-Socioeconomic - No significant demands on schools, 

housing or municipal services are anticipated for the construction and operation phases of the proposed project. Some 

temporary increase in traffic congestion and increased demands 

on retail services in the immediate site vicinity may occur 

during the construction period. 

4.8.2 ENVIRONMENTAL SITE DESCRIPTION 

This section provides a description of the solar hybrid repoweriny site in terms 

of relevant environmental considerations. Included are discussions of the site 

location (Section 4.8.2.1 ) , physiography (Section 4.8.2.2), geology and mineral 

resources (Section 4.8.2.3), seismology (Section 4.8.2.4), soils (Section 4.8.2.5), 

and hydrology (Section 4.8.2.6). Ecology and climatology are reviewed in Sections 4.8.2.7 and 4.8.2.8, respectively. Also included are discussions of land 

ownership and use (Section 4.8.2.9), transportation (Section 4.8.2.1 0) , historical 

and arehaelogicdl sites (Section 4.8.2.11), demography and socioeconomics (Section 4.8,2.12), and ambient sound levels (Section 4.8.2.13). 

4.8.2.1 SITE LnCATTON 

The solar hybrid repowering site is located on the south side of the Reeves 

power plant which lies approximately two miles north of Albuquerque's city 
limits in Bernalillo County, New Mexico. Figures 4.8-1 through 4.8-3 depict 

the proposed facility in relation to the state, the county and the city of 

Albuquerque. As evidenced in Figure 4.8-3, the site lies approximately 

one-half mile west of Interstate 25 and is bounded on the south by Osuna Road I 

and on the west by the Albuquerque Metropolitan Arroyo Flood Control Authority 

(AMAFCA) North Diversion channel, and to the north by Los Angeles Boulevard. 

4.8.2.2 PHYSIOGRAPHY 

The site lies in the southern portion of the Basin and Range Physiographic 

Province in the Mexican Highland Section, which is characterized by isolated 

dissected block mountain ranges separated by aggraded desert plants. The 

Sandia Mountains' crestline lies ap~roximately 111 miles east, reaching 

10,678 feet above sea-level (MSL) at Sandia Crest. Westward from these mountains elevations decrease to 5000 feet MSL at the Rio Grande River which lies 

approximately three miles west. The site has a surface that slopes gently westward from an elevation of 5130-feet MSL on the east to 5070-feet MSL on the 

west near the AMAFCA drainage canal. Topography at the site is shown in 

Figure 4.6-1 . 

4.8.2.3 GEOLOGY AND MINERAL RESOURCES 

The site is located in the Albuquerque-Belen Basin, that is a north-trending 

basin 90-miles long and 30-miles wide in the Rio Grande trough. The area is 

covered mainly with Quaternary alluvium and with rocks of the Santa-Fe formation. (I) Figure 4.8-4 depicts a stratigraphic column of the A1 buquerque 

area. (2 

On site there are no known: (3,4,5,6) 

Oi 1 , gas or coal resources 

Oil or gas pipelines 

a Metal or non-metal resources 

Figure 4.8-2 indicates that the closest coal field, the Rio Puerco coal field, 

is located approximately 13 miles west of the site and the small Tijeras coal 

field is located approximately 15 miles east of the site. (4) 
Figure 4.8-1. Map of New Mexico State 
Figure 4.8-2. Map of Bernalillo County 
Figure 4.8-3. General Location of the Solar Hybrfid Repowering Site 
AGE 

SYSTEM SERIES (M.Y. )* FORMATIONS THICKNESS s 

Holocene 

PI ei stocene 1 

0 

N 

0 

Pl i ocene 12 

Z 

W 

0 

Tertiary Eocene 

Gravel , sand, mud in 1 owlands , arroyos, l ow terraces 5-1 00 

and alluvial fans 

Gravel , sand, cal iche; 1 ava 10-50 

f 1 ows 

Santa Fe Fomnation:sand , clay 10,000+ - 

and gravel 

GaZistea Formation:red and 1000+ - 

buff sandstone and mudstone 

Cretaceous 

Mesaverde Formation:shale, sandUpper 9 0 stone, and coal 1500 

Mancos ShaZe:shale with thin 

limestone and sandstone beds 1500 

Lower 125 Dakota Fomation:sandstone~ 

congl omerate, shale 5-1 00 

Jurassic Upper 

Morrison Fomation;variegated 

mudstone and sandstone 400-800 

165 SwmnerviZZe Formation:red and 200 

buff mudstone and sandstone 

TodiZto Formation:gypsum and 

1 imestone 100-200 

Entrada Sandstone:red and buff -3 

sands tone 150-200 ,: 

ChinZe Fomation:red and tan 

Triassic Upper 185 mudstone and cl aystone 1500 

Santa Rosa Formation:sandstone 

and conglomerate 200-400 

Upper 21 5 BernaZ Fomation:sandstone, siltstone, and 1 imestone 100 

San Andres Fomnation:limestone 30-100 

Mi ddl e 225 GZorieta Sandstone 50-1 00 

- Permian Yeso Fomnation:red and tan sand0 

N 

0 stone, 1 imestone, and gypsum 600-800 

W 

-I Lower 235 Abo .E'ormation:red sandstone and 

2 mudstone 600-900 

I-\ 

Figure 4.8-4. Stratigraphic Column of A1 buquerque Area''] 
U - Pennsyl vanian O 

N 

0 

Mississippian 

270 ladera Foundation: 1 imestone , s ha1 e, and sandstone 1 OC+ 

- 

Sandia Foundation:sandstone, 100-200 

shale, and 1 imestone 

300 Terrero Formation 0-1 00 

Precambrian 1400- Sandia Granite:gneiss, quartzite 

3000 greenstone, and schist 

*M.Y. = millions of years from the beginning of the system or series. 

A formationis a number of beds that are distinguishable from others above and 

below because of di fferences in composition, col or, or other features. Series 

and systems are larger groupings of formations based on fossils, age, etc. 

Definitions of rocks comprising the formations may be found in any standard 

dictionary. 

Stratigraphic Column of A1 buquerque Area (2 
The closest prospects for uranium mines are located approximately 18 miles 

southwest of the siteyapproximately 17 miles northeast of the site, or approximately 13 miles southeast of the site,(4) as indicated in Figure 4.8-2. 

4.8.2.4 SEISMOLOGY 

The site is located in Zone 2 of the U.S. Seismic Risk map,(7) as shown in Figures 4.8-5 and 4.8-6. This indicates that earthquakes of intensity VII on the 

Modified Mercall i Scale (Tab1 e 4.8-2), which corresponds to an earthquake of 

the magnitude of five to six on the Richter scale, could occur on the site or 

its vicinity. This was confirmed by a recent detailed study(8) that tabulated 

the recorded earthquakes in the general vicinity of the site. 

Seismic events are rated according to the maximum intensity in the area of the 

epicenter (originating 1 ocation) . The intensity follows the Modified Mercall i 

Intensity Scale and is a measure of the damage caused by the event. Table 4.8-1 

gives the Mercalli Intensity Scale and the expected damage for each intensity. 

Damage done by an earthquake is related to the energy released at the epicenter 

and the distance from the epicenter. Other important factors include the 

geologic setting of the area, the frequency of the seismic waves, the depth of 

the epicenter and the amount of earthquake resistance built into man-made structures. The more commonly known Richter Magnitude Scale is a measure of energy 

released at the epicenter of the earthquake. Table 4.8-2 gives a comparison 

between the Mercalli Intensity Scale and the Richter Magnitude Scale. Figure 4.8-7 gives the magnitude of an earthquake as a function of the maximum 

distance from the epicenter to observed structural or ground damage. 

A detailed tabulation and graphical depiction of earthquakes felt prior to 

1962 and instrumentally recorded earthquakes from January 1, 1962 through 

June 30, 1976 in the Albuquerque area is provided in the Western Area Survey, 

Public Service Company of New Mexico, 1978. Data in this study indicate that 

earthquakes nf magnitude 5 on the Richter scale could occur at the site or 

its vicinity. Damage from such an earthquake at the epicenter may result in 

broken masonry, small lands1 ides and col lapse of tall weak structures. 

(Table 4.8-1) within 10 to 50 km or 6 to 31 miles. 
Figure 4.8-5. Seismic Risk Map of the United States (7) 
NOTE: Roman Numerals indicate earthquake intensity levels on the Modified 

Mercalli Scale. For instance, Mercalli Scale VII corresponds to an 

earthquake of magnitude 5 to 6 on Richter Scale. 

Figure 4.8-6. Seismic Risk Map for Southwestern United States (7) 

t 
TABLE 4.8-1. MERCALLI INTENSITY SCALE AND EXPECTED,DAMAGE FOR EACH 

INTENSITY (AFTER C. F. RICHTER, 1958)(9) 

I. None felt. Marginal and long-period effects of large earthquake. 

11. Felt by persons at rest, on upper floors, or favorably placed. 

111. Felt indoors. Hanging objects swing. Vibration 1 ike passing of 1 ight 

trucks. Duration estimated. -May not be recognized as an earthquake. 

IV. Hanging objects swing. vibration like passing of heavy trucks; or , sensation of a jolt like a heavy ball striking the walls. Standing 

motor cars rock. Windows, dishes, doors rattle. Glasses clink. 

Crockery clashes. In the upper range of IV wooden walls and frame 

creak. 

V.' Felt outdoors; direction estimated. Sleepers wakened. Liquids 

disturbed, some spilled. Small unstable objects displaced or upset. 

Doors swing, close, open. Shutters, pictures move. Pendulum clocks 

stop, start,' change rate. 

VI. Felt by all. Many frightened and run outdoors. Persons walk unsteadily. 

Windows, dishes, glassware broken. Knickknacks, books, etc., off shelves. 

Pictures off walls. Furniture moved or overturned. Weak plaster and 

masonry D cracked. Small bells ring (ch~rrch, school). Trees, bushcs 

shaken. 

VII. Difficult to stand. Noticed by drivers of motor cars. Hanging objects 

quiver. Furniture broken. Damage to masonry D, including cracks. 

Weak chimneys broken at roof line. Fall of plaster, loose bricks, 

stones, ti les , cornices (a1 so unbraced parapets and architectural 

ornaments). Some cracks in masonry C. Waves on ponds; water turbid 

with mud. Small slides and cav5ny in a1 ong sand nr gravel banks. 

Largc bells ring. Concrete irriydL.iun ditches damaged. 

VIII. Steering of motor cars affected. Damage to masonry C; partial collapse. 

Some damage to masonry B; none to masonry A. Fall of stucco and some 

masonry walls. Twisting, fall of chimneys, factory stacks, monuments, 

tower, elevated tanks. Frame houses nioved on foundations if not bolted 

down; loose panel walls thrown out. Decayed piling broken off. 

Branches broken from trees. Changes in flow or temperature of springs 

and we l l s. Cracks in wet ground on steep slopes. 

:X. General panic. Masonry D destroyed; masonry C heavily damaged, sometimes with complete collapse; rl'lasonr-y B serioltSly damaged. (General 

damage to foundations). Frame structures, if not bolted, shifted off 

foundations. Frames racked. Serious damage to reservoirs. Underground 

pipes broken. Conspicuous cracks in ground. In alluviated areas sand 

and mud ejected, earthquake fountains, sand crater. 

X. Most masonry and frame structures destroyed with their foundations. 

Some well-built wooden structures and bridges destroyed. Serious 

damage to dams, dikes, embankments. La.rge landslides. Water thrown 
TABLE 4.8-1 (Continued) 

on banks of canals, rivers, lakes, etc. Sand and mud shifted 

horizontally on beaches and flat land, Rails bent slightly. 

XI. Rails bent greatly. Underground pipelines completely out of service. 

XII. Damage nearly total. Large rock masses displaced. Lines of sight 

and level distorted. Objects thrown into the air. 

Masonry A, B, C, D are specified by Richter as follows: 

Masonry A. Good workmanship mortar and design; reinforced, especially 

laterally, and bound together by using steel, concrete, etc.; designed to 

resist lateral forces. 

Masonry B. Good workmanship and mortar; reinforced, but not designed in 

detail to resist lateral forces. 

Masonry C. Ordinary workmanship and mortar; no extreme weaknesses like 

failing t o t i e in at corners, but neither reinforced nor designed against 

horizontal forces. 

Masonry C. Weak materials, such as adobe; poor mortar; low standards of 

workmanship; weak horizontally. 
Figure 4.8-i. Magnitude of Earthquakes as a Function of the Maximum Distance from the Epicenter 

I 

* 

0 100 200 3CO 400 500 800 700 

DIST4NCE. km 

1. Ko~r Darn. Mo~~larn-A~r~l 20. 1971 7. Rnmpnrl. Alnska-Oclobar 20. lbGO 

2. Wh~lbcc. Cnl~lo~n~a-July 8. 1929 8. klc.;~t)on I ;lko. Monlano-Scploml~or 17. 1959 

3. I'h~ll~~sbury Morl3na - Ma: 20. IL&b 9. Lllvv:~ Day. Alnska - Auotrsl 9. ID58 

4. P;~rklicld. C:nltlor~~~a.- June :??. IOG3 10. CIII:IIIKMI!. PI!IU. oIt!.hor~:- May 37, I070 

5. SJII Fc.fn.lrxIt). Cabl(~r~l~~- (FC~JIIIJI~ !I. 1071 11. C;I{..C Y;I~:I~,III~I, AI~I~~~-~OCIOIJ~I 9, 19CK 

6. Scalllc. W;lsn~nylur-Al)r~l ?3. I065 12. PIIIBC~ W~ll~;~nr Sound. Alaska-.M;\~ch 27'. 1964 

A 
4-267 4-268
LEGEND TO FIGURE 4.8-9 

BKD--Bluepoint-Kokan Association, hilly. Runoff is slow, and the hazard of 

water erosion is moderate or severe. 

EmB--Embudo gravelly fine sandy loam, 0 to 5 percent slopes. Runoff is 

medium, and the hazard of water erosion is moderate. 

EtC--Embudo-Tijeras complex, 0 to 9 percen.t slopes. Runoff is medium and 

the hazard of water erosion is moderate. 

WeB--Wink fine sandy loam, 0 to 5 percent slopes. Runoff is medium and the 

hazard of water erosion is moderate. 
SURFACE WATER HYDROLOGY 

Surface water supplies in the A1 buquerque area are largely confined to the 

Rio Grande River and include the water flowing through irrigation and drainage 

ditches or standing in low areas on the floodplain. A small quantity of ephemeral surface flow occurs in several arroyos draining from the mountains. (2 

The U.S. Geological Survey has been measuring the flow of the Rio Grande River 

at A1 buquerque (Station 08330000) since October 1941. Table 4.8-3 1 ists the 

daily flow at this station in cubic feet per second (cfs) for the water year 1976 

(October 1, 1975 through September 31, 1976) as we1 1 'as total maximum and minim~.rm 

monthly flows. The extremes for the period of record are: maximum discharge of 

-25,000 cfs, which occurred on April 24, 1942, and minimum flows of "no flow," 

which occur at times. Since November 1973 the flow is completely regulated by 

Cochiti Dam located approximately 50 miles upstream. 

Measurements of suspended sediment loads, temperatures and concentrations, of 

total dissolved solids are taken at this station. It appears that the n~ajor 

water quality concern at this location is in the area of the inflowing suspended 

s o l i d s . 

AII arroyo passes through the southern part of the solar hybrid repowering site. 

.4 playa (a shallow central basin of a desert plain in which water gathers after 

a rain arid is evaporated) is located rledr the eastern boundary of the site. 

GROUNDWATER HYDROLOGY 

Musl of Albilquerque's water comes from the subsurface at or beneath a level of 

soaked sand and gravel known as a water table (.see Figure 4.8-3). In the 

Riu Grande trough, nearly all the subsurface beds are fairly porous and 

permeable enough to a1 low slow' movement of groundwaler-. Since a1 i the rocks 

in the trough ari? permeable, thc ground water. is unconfined and the groundwater 

level may fluctuate up and down, depending upon the amount of rainfall, the 

river flow, or the use of water from wells and ditches. Being uncorifined, 

the subsurface ground water has complete connection , or- f reedurn of movement, 

with the river surface water. Thus, with sufficient rain, the water table 

can rise to coincide with the surface of the earth. (2) 
TABLE 4.8-3. DISCHARGES OF RIO GRANDE RIVER AT ALBUQUERQUE, NEW MEXICO 

(U.S.G.S. STATION 08330000), cfs(l3) 

* 

011 OCt WV DCC JAN VCR llaq APP MAT UM NL AUG SCP 

1 Zbb BOO 1670 1660 333 820 174 1950 1170 b63 51b a 242 036 1650 1550 200 174 74 ZllU I290 543 1179 3 2bS 862 1660 1500 288 8OI 653 2160 I250 bZV 1330 Sb 1 

'I7 555 

b 262 RP3 0 lbA0 2.9 8 38 700 ZZZO , 01. bJS 848 06b , S 12 1120 lbbO 1550 b5b 93U b2b 2490 brI3 Sb9 666 699 

6 3 1670 I**O 1590 1190 Oh7 37 2550 570 bSl 3 35 659 I 326 60 1680 I520 1030 969 705 2710 926 *I1 258 782 8 27 7 1730 1510 170 (152 188 ZR50 lZL0 452 123 721 0 208 1670 1440 ' 1550 742 760 lob0 2040 950 556 b5 669 10 205 1710 1710 1620 73r( 615 1080 2930 1050 51I 15 048 

11 229 5 l7bO 1760 680 901 IOAO 2900 1310 462 IS 399 1Z 259 hb80 1410 1820 716 832 1190 ZblO 1190 521 b 0 647 13 2 1670 1900 la80 779 I 1270 25MO 1070 770 25 1 610 1 b 279 1450 1730 19ZC 842 3 1290 3620 999 b* 1 228 500 19 235 1350 1710 1880 800 908 1430 2580 855 1550 180 4 78 

.I6 237 I400 I720 1770 9 30 872 1480 2b90 731 65 1 515 488 

87 2bb lb5O 1630 :3b3 833 7 1400 2450 579 773 81 J 523 

18 279 1730 1680 1160 815 7 1070 2390 5db 922 600 

1'4 /I1 1110 lh40 llFO 821 bo1 98b 2bZO 54 3 b00 88 1 b?b 

20 306 1660 I690 Ill0 I)bO 620 911 31b0 5#9 625 1760 626 

I1 315 1690 1740 00) r( 35 670 130 3170 460 582 1210 532 z2 3Zb 1660 1150 779 853 724 629 2000 385 8YS 797 672 23 32b lb50 In70 708 889 7U1 489 2600 35 1370 625 b0b a* 0 I710 l*bO 645 826 610 1 1910 510 I090 1230 478 a 2 1550 la80 63 1 769 615 87 1940 b23 1360 1320 a00 

Zb 3b? 1440 I780 626 76% 710 . I110 la80 556 107U 1230 370 27 35 0 1790 613 780 593 1110 1210 bb9 bb? lbb0 3bO ?a 33 1370 1010 61s 830 502 1100 818 621 LO 754 606 2+ 3.0 IA<~ 1710 ~bl lZ+ 5 1309 7 Qb 8.5 14% b>? bob M 5 0 IbPO 107 -- b98 1660 a10 558 596 590 580 3 1 bb I --- I180 460 --- 111 --- 971 --- b94 519 --. :OVAL 0977 bb.91 I )*ne.o z17eo z3eo8 29229 7orno 23515 18 ZI~ZZ 16757 

@CAM 290 lael 1 1254 151 lbfl 91. 2216 766 704 701 559 a41 bb1 1 l9IO 1920 1190 919 1 3170 I310 1550 1740 182 BIN ZO* COO IbbO 611 269 582 15 1 794 3b5 411 IS I*q AC'It 11010 0 lOb4OO 77000 43200 61210 519*0 139IJO bAb.0' b1)&0 43090 33210 

<1) 1kb)O 1k)O 1180 981 01 6110 LC200 1b120 llC8O 19100 1)lbO 1bb10 

C 1 0 5 -clr 1557 -4% 5600 *Ir 160 rc-ri ~~zrooo (0 111500 UlulR 1916 101.~ 315281 c 0 *rr 3110 WIN 13 rc-ri 744400 (0 lllluo 
Before large water .usage occurred and before the digging of drainage ditches, 

the water table in the valley bottom coincided with the surface in many places 

to niake water-logged soils or rose above the surface in lower areas to cause 

swamps,and lakes. The drainage ditches did away with these conditions by lowering the water table. It continues to be lowered, especially near Albuquerque 

where we1 1 withdrawals are 1 arge. (2) 

The Rio Grande trough is filled with at least several thousand feet of sand 

and gravel very much 1 ike that seen at the surface (Figure 4.8-4). Sand, 

gravel and mud brought into the trough by water, along with part of the water 

itself, were deposited and buried. 

There is little' chance of a water shortage in the Albuquerque area. Probably 

no other large city in the arid Southwest has such a bountiful supply of good 

water as Albuquerque has. Water everywhere in the trough is no more than a 

few hundred feet beneath the surface. With population projections of nearly 

1,000,000 by the year 2000, hydrologists estimate that the water table around 

Albuquerque would be lowered no more than 80 feet. (2) 

WATER USE 

Surface and groundwater resources are uti 1 ized by municipalities and for 

induslrial and agricultural purposes. The New Mexisn ctate ~nbinccr regul ntes 

but11 surface'and groundwater uses and limits tha amount of watcr rights on 

the basis of purpose of use, location and nature of the surface or groundwater availability and the demonstrated or established need or use of the 

wa It! rs. (7) 

4.8.2.7 ECOLOGY 

Local terrestrial flora and fauna as well as aquatic ecology are described in 

this sec.Liur~ as they apply to 1t1.i~ Tacllity. 

TERRESTRIAL FLORA 

Nat-ivr vegetation around the solar hybrid repowering site is low in profile 

principally because of low rainfall, 7 to 10 inches annually, and high elevation 
5000 to 6000 feet above MSL. The plant community at a typical site in this part 

of the county is mainly comprised of grasses mixed with some shrubs and herbaceous 

plants. Vegetation covers only approximately 15 percent of the soil surface. The 

most abundant grass is usally .black grama (BouteZoua eriopoda), which may comprise 

approximately 35 percent of the total vegetation by weight. Less abundant species 

are sand dropseed (SporoboZus cryptandrusl , mesa dropseed (SporoboZus f Zexuosus) , 

gal 1 eta (Hilaria jamesii) , three awn (Aristida gZauca) , bl ue grama CBouteZoua 

graciZis) , a1 kal i sacaton (SporoboZus airoides) , bush mu hly (MuhZenbergia porteri) , 

Indian ricegrass (Oryzopsis hymenoides), and fluffgrass (Tridens puZcheZZus). In 

places, there are broom snakeweed (Gutierrezia sarothrae), broom dalea (DaZea, 

sp.) , pricklypear cactus (Opuntia, sp. ) , small soapweed (Yucca gZauca), chol la 

cactus (Opuntia, sp.), and winterfat (Eurotia Zanata). Annual plants which 

increase during years of above average precipitation are tansymustard (Uescurania, 

sp.), Ind.ian paintbrush (CastiZZeja Zeonardi), woolly Indian-wheat (PZantago 

purshii) , lambsquarters (Chenopodiwn albwn) , and Russian-thistl e (SaZsoZa kaZi) . 

Woody plants such as Apache plume (FaZZugia paradoxa) may occur in the draina.ge 

ways. (11 

The v~g~tat~inn nf the site is characterized principally by black grama, sand 

dropseed, three awn, bush muhly, Indian ricegrass, fluffgrass, broom snakeweed, 

pricklypear, cholla cactus, tansymustard, Russian-thistle and bladderpod. (1 2) 

When such a plant community is disturbed, annual plants increase. Vegetation of 

the site has already undergone some disturbance because of the existing power 

plant and is also affected by several small washes that dissect the proposed plot 

for the solar collector field. 

Of the Federal threatened and endangered plant ~~ecies('~"~) and the plants 

protected by the State of New Mexico, (I6) none are known to occur on the site 

at this time. Of those listed, only a few species could potentially occur at 

the site, such as grass cactus (Pediocactus papyracantus), (I9) and only a more 

detailed study could verify their presence or absence. Should these species 

be present, they would be moved away from the site prior to construction. 
TERRESTRIAL FAUNA 

The faunal components of the area around the solar hybrid repowering site have 

been strongly influenced by man's activities; interstate highways, drainage 

canals, etc. The area is considered poor to very poor for potential habitat 

elements required by wild1 ife and thus for wild1 ife itself. (11) 

Mamalina species residing in the site potentially include several small mammals 

such as the ord kangaroo rat (Dipodomys ordii), silky pocket mouse (Perognathus 

fZavus) , desert cottontail (SyZviZagus auduboni) , blacktail jackrabbit (Lepus 

caZifornieusl or 'least chipmunk (Eutamia rni,tinno~~). Laryer mammals are likely to 

occur at the site only during forays for food. Predators such as the raccoon 

(Procyon Zotor) , skunk (Mephitis mephitis) or coyote (Canis Zatrans) may pass 

through nccasional 1 y but most 1argei- mammsl s , su~h as deer (Odooo.il~uo izemionus) 

would be inclined to avoid man's activity and remain closer to the Rio Grande 

River floodplain. 

Bird activ'ity at this site would be limited to those few song birds that make 

this type of habitat home. Species such as the raven (Corvus corm), horned lar 

(Eremophila aZpestris), western meadowlark (StwrzeZla neglecta) or vesper 

sparrow (Poecetes gramineus) may be seen in this area and raptors such as the 

marsh hawk (Circus cyaneus) may hunt here. Waterfowl may be observed nearby 

because of the proximit,y to the Rio Granrl~ River, but no habitat is nvnilnl~le 

for these species on the site. 

Reptiles comprise another component of the fauna of the site. Several dp~prt 

species could potentially occur here. 

Within the proposed site no rare, threatened or endangered species are known to 

occur at this tim,e. Severa4 Federally or state endangered species that may 

migrate thtbuuyt~ the Rlo Grande Valley but are unlikely to use the site are the 

whooping crane (Gms mericarza), bald eagle (HaZiaetus ZeucocephaZusl, little 

blue heron (FZorido: cczerz~l.ea), and American peregine falcon (Pal.co peregrinus 

anatm? . (I7 '18" The presence or absence of addi tiunal endangered or 

threatened species on the state list would have to be confirmed by on-site 

studies. The site is not located in the direct path of migratory birds. 
4.8.2.8 CLIMATOLOGY 

Monthly mean and annual climatological data for a 29-year period are available 

for A1 buquerque and temperature and precipitation for Los Lunas ('l) and 

Bernalilli. (*') . The climatological data from these cities should more than 

adequately characterize the climate in the vicinity of the proposed site. A 

summary of relevant climatological data for the three locations mentioned is 

provided in Table 4.8-4. 

Monthly mean temperature and relative humidity data depict the climate of 

the site as arid continental. Temperatures around the area are those characteristic of high altitude, dry climate. The average daily range of temperatures is relatively high, with the daytime summer maxima averaging higher 

than 90°F and the nights are cool. The demands for energy to heat during 

the winter and cool during the summer can be evaluated by degree days. These 

values are presented in Table 4.8-4. 

The annual average wind speed for the proposed site is approximately nine miles 

per hour with the prevailing direction from the southeast. The average monthly 

precipitation in the vicinity of the site varies from less than one-half inch 

during the winter months to over an inch and a quarter during July and August. 

Snow rarely remains on the ground in the valleys for more than 24 hours. The 

July-September period furnishes almost half of the annual moiiture with most of 

it due to heavy thundershowers. Thunderstorms occur on the average of 43 days 

per year. Severe weather such as tornadoes rarely occur in the area but occasional dust storms occur. 

Another feature of the climate is the high percentage of sunshine. Monthly and 

annual solar radiation data, expressed as percentage of possible sunshine, are 

available for Albuquerque and are listed in Table 4.8-4. Sunshine is recorded 

during more than three-fourths of the hours from sunrise to sunset and this 

high percentage carries through the winter months. Frequencies of fractional 

cloud cover from sunrise to sunset are also available on a monthly and annual 

basis for A1 buquerque (Table 4.8-4). These frequencies, along with the possible 

percentages of sunshine, serve as a valuable estimate of the solar input at the 

proposed site of the solar hybrid repowering facility. 
TABLE 4.8-4. SUMMARY OF CLIMATOLOGICAL DATA FOR 

ALBUQUERQUE AND VICINITY 

Meteor01 ogical Stations 

Parameter ~lbu~uer~ue"~) Los ~unas"') ~ernalilli"~~ 

Temperature, OF 

Annual Average 

Maximum 

Minimum 

Degree Days - Heating 

Degree Days - Cooling 

Precipitation, inches 

Annual Average 

Monthly Maximum 

Monthly Minimum 

24-hour Maximum 

Snowfall , inches 

Annual Average 

Monthly Maximum 

24-hour Maximum 

Wind,. rnph 

Annual Average Speed 

Prevailing Direction 

Fastest: 

Speed, rnph 

Dl rectl~n 

Re1 ative HUIII id.i.ty, % 

Annual Average at: 

0500 hour 

11 00 hour 

Solar Radiation 

Annual Percentage 

of Possible Sunshine 

Maxi mum 

Mi n i tlltiiu 
Parameter 

TABLE 4.7-4 (Continued 

Meteorological Stations 

~l buquerque(20) LosLunas(21 ) ~ernal i 11 o(22) 

Mean Annual--No. of Days 

Precipitation > .O1 in. 5 9 

Snow, sleet, hzil p - 1.0 in.)** 4 

Thunders torms 43 

Heavy Fog 5 

Maxirr~um Temperatures > 90°F 6 1 

Minimum Temperature - >-32" F 121 

*Data not available 

AATul.dl Ps~c i pi Ld 1 i~i~ 
4.8.2.9 LAND OWNERSHIP AND LAND USE , 

Much of the following discussion on land use is based on a study conducted by 

the Environmental Affairs Department of the Public Service Company of 

New Mexico. (12) 

This site is located in an area of rapid urban development activity. The 

Metropol i tan. re as and Urbans Center. Plan of the A1 buquerque/Bernal i 1 lo County 

Comprehensive classifies the area of the proposed solar hybrid repowering site as established urban land. Established urban land is land suited for 

development as there exists financing and public services that would permit 

higher densities. 

The solar hybrid repowering site is bounded by two established industrial parks, 

Academy Industrial Park to the south .and Loop Industrial Park north of 

Los Angeles Boulevard. The area between these two industrial parks is vacant 

land with the exception of the heavy industry activity of the Public Service 

Company of New Mexico (PNM) Reeves Station and American Gypsum, both located 

south of Los Angeles Boulevard. Albuquerque's suburbs have been rapidly spreading northward, and several new housing plans and trailer parks lie within two 

miles of the site'on the northeast, east and southeast. 

West of the site, between the AMAFCA North Diversion Channel and North Edith 

Boulevard, the land is'classified as developing urban which is land t.hat. ha5 

not been platted extensively and is presently acceptable for low level urban 

development. Albuquerque Gravel Products occupies most of this land. Small 

portions of land adjacent to Edith Boulevard are designated as semi-urban and 

rural , suitable for low density residential development. 

Most of the projected ind'ustrialization in the vicinity of the site will be 

related to Loop Industrial Park and a speculal.ive ar~d yet ,tu be designed 

industrial community east and south. 

4.8.2.10 TRANSPORTATION 

As shown in Figures 4.8-1 through 4.8-3, the site is bounded by Los Angeles 

Boulevard to the north, 1-25 and the Frontage Road that parallels the interstate 
to the east, Osuna Road to the south and the AMAFCA North Division Channel to 

the west. Edith Boulevard lies west of the drainage channel. 

Daily traffic flow statistics for 1976 and projected for 1995 are given in 

Table 4.8-5. Traffic flow statistics were obtained from the Middle Rio Grande 

Council of Government. (24y25) Projected increases in traffic flow over the 

next 20 years will be greatest for Los Angeles Boulevard, 3200 vehicles per day 

in 1976 to 10,700 vehicles per day in 1995. Increases in traffic flow will also 

be substantial for 1-25. Current traffic statistics are not available for the 

Frontage Road, but 1995 projections estimate average daily traffic flow at about 

5000 vehicles . 

TABLE 4.8-5. AVERAGE DAILY TRAFFIC (24,25) 

AT SOLAR HYBRID REPOWERING SITE 

Corridor 1976 Projected 1995 

Los Angeles Boulevard 3,200 10,700 

1-25 17,556 44,000 

Osunil Road 12,9111) 17,300 

North Edith Boulevard 6,700 4,100 

Extensive improvement and expansion of transportation networks are planned 

for northwest Albuquerque. Within the vicinity of the site, Frontage Road 

will be improved, running in a north to south flow west of 1-25, and a south 

to north flow east of 1-25 and an 1-25 interchange will be constructed at 

Los Angeles Boulevard. A major improvement will be the construction uT d 

North Valley River Crossing which will follow the alignment of either Montano 

Road, Los Angeles Boulevard or Richfield Avenue. At the present time Montano 

Road is the favored alignment. If Montano Road is not feasible, Los Angeles 

Bnulevard is the likelay alternative. All of these improvements to the circulation system will increase the opportunities for large scale development in 

the early to mid-1980's for this area through increased accessibility arid 

visibility of the area. 
There are four airports in and around Albuquerque, as shown in Figures 4.8-1 

through 4.8-3. The city's Sunport International Airport lies eight miles south, 

adjacent to the Kirtland Air Force Base. Closer to the site there are two 

smaller local airports; Coronado Airport, which lies two miles north north-east, 

and Alameda Airport, which lies four miles northwest. 

4.8.2.11 HISTORICAL AND ARCHAEOLOGICAL SITES 

There are eight historical sites listed in the National Reqister of Historic - 

Places for Bernal i 11 o County as of December 31 , 1977. (26) Three additional 

sites were added as of March 7, 1978. (27) None of these historical places are 

located on or near the proposed solar hybrid repowering site. It is not known 

whether archaeological artifacts are located within the proposed site boundaries. 

Prior to construction of this facility an on-site survey will be performed. 

4.8.2.12 DEMOGRAPHY AND SOCIOECONOMICS 

The solar hybrid repowering site lies within the Albuquerque Standai-d Metropol i tan Statistical Area (SMSA) which coincides with Dernal il lo County's boundary. 

The county's population has grown steadily from a population of 316,800 in 1970 

to 365,200 ir~ 1975, and is by far the most populated county in the state. (28 

It is a highly urbanized county (94.2 percent in 1970) with a 1970 pnpl.llation 

den5 i ly oT 27U persons per square mile. The City of A1 buquerque, Bernal illo 

Ccunty area had in 1974, a population nf 286,300, which is uver six times larger 

than either SarlCa Fe or Las Cruces, New Mexico's second and third larqcst 

~ilies, re~pectlvely. The population of this city is expanding rapidly: during 

an eight-year period, from 1970 through 1978, there was an increase of over 

35 percent, from 243,751 to 330,242. A recent July 1978 pub1 ication (29) of the 

Albuquerque Urban Qbs~rvatory, University of New Mexico, contains projected 

demographic changes to 1980 based on past demographic changes in the Albuquerque/ 

Bernallio County area. The population growth in the Albuquerque/Bcrnalillo 

County is expected to continue for the period hrtween 1975 lhrough 1905; it is 

expected to increase by 23 percent. (29) During the same period the nunlber of 

households is forecasted to increase in this 'area by 38 percent. (29) 

The 1976 annual average size of the civilian labor force in the Albuquerque SMSA 

was 171,815, with 154,971 persons employed and 16,844 unemploye'd giving 
an average unemployment rate of 9.8 percent of 1976. (30) contract construction 

employment accounted for 9800 jobs out of the total (%155,500) non-agricultural 

jobs in the A1 buquerque SMSA in 1976. (31) Construction employment is expected 

to reach 13,779 by 1980 and 15,069 by 1985. Housing units are expected to grow 

from 126,400 units in 1975 to 150,OO units by 1980 and reach 174,000 units by 

1985. (29) 

4.8.2.13 AMBIENT SOUND LEVELS 

Noise levels at the site are affected by various existing activities that contribute to the total noise level. These activities include: (1) mobile sources 

on the nearby roads and Interstate 25, (2) the two small nearby airports, 

(3) the existing PNM Reeves Station, and (4) the gypsum plant. 

Noise levels at this site are typical of those occurring at other industrial 

sites. 

4.8.3 ENVIRONMENTAL IMPACTS OF CONSTRUCTION 

In this section the environmental affects during the construction phase are 

described. A1 1 applicable Federal , statc and local law and regulations will 

be followed to minimize and to avoid undesirable environmental effects. 

Included are discussions of air quality effects (section 4.8.3.1), effects of sound 

(Section 4.8.3.2), effects on land use (Section 4.8.3.3). ecological effects (Section 4.8.3.4), hydrological effects (Section 4.8.3.5), and social and cultural 

effects (Section 4.8.3.6). 

4.8,3.1 EFFECTS ON AIR QUAL1l.Y 

Dust formation and motor machinery emissions are the major dotential impact 

to the local air quality during the construction phase. Clearing and regrading the heliostat field could cause the dust formation and machinery employed 

for construction would emi t lome ydbes and particulate matter. Levels of 

fugitive dust formed will be comparable to those associdted with the construction of similar size projects. Dust suppression techniques (such as frequent 

surface wetting) may need to be employed to reduce dust levels. 
4.8.3.2 EFFECTS OF SOUND 

Machinery,employed during construction could increase noise levels at the 

construction site; however, the heliostats will be prefabricated and will only 

be assembled on site. In addition, noise levels at the site are presently * 

influenced by a variety of noise causing functions as described in Section 4.8.2.13. 

4.8.3.3 EFFECTS ON LAND USE 

The area designated for the solar hybrid repowering site is presently vacant 

land, and no hori~es or other buildings would have tn be relocated, purchased 

or destroyed. 

During construction, there probably will be increased traffic volume and 

congestion in the immediate vicinity of the site during morning and afternoon 

rush hours. Increased congestion may occur at the Osuna Road interchange 

of 1-25, along Los Angeles Boulevard in the vicinity of Osuna Road and 

Los Angeles Boulevard. 

Traffic congestion may be mitigated by staggering the starting and quitting 

times of the construction workforce. 

,Construction activiti'es wiil r.esult in Ll~c removal of vcg~tation from the site 

prior to installation of the heliostats. The removal of the existing vegetation 

during construction will promote the growth of annual plants and perennials such 

as sand dropseed, cactus, and catclaw mimosa. These species and various grasses 

may thrive under the shade of the heliostats. Control of these shaded area micro 

communities through various techniques such as cutting or spraying may prove 

necessary. If seeding is not utii ized to reestablish vegetation on disturbed 

sites, then dormant perennials may be expected to eventually revegetate thcsc 

sites. (32) 
The removal of vegetation will result. in increased siltation during construction. This runoff could affect the aquatic communities in local water bodies 

off site. However, collection of runoff and sediments in a retention pond 

could allow the'sediments to settle prior to allowing excess water to be discharged into the natural drainage system. Construction of such a pond would 

be considered if found necessary. High sediment loads are a naturally occurring phenomenon in the local small streams and in the Rio Grande River Wildlife 

habitat will be destroyed with the removal of the vegetation. Many wildlife 

species will move to surrounding areas. The less,mobile and burrowing species . . are likely to experience some mortality. 

The potential .for impacts to endangered flora or fauna must be determined, by 

additional studies conducted on site prior to construction. These studies 

will be conducted on a seasonal basis by experts to determine the presence 

or absence of endangered or threatened flora or fauna on the site. The 

presence of migratory birds could be determined at the same during the 

appropriate season. Should floral endangered species be found on-site, they 

will be relocated to another site in the general vicinity without affecting 

the construction of the facility. 

4.8.3.5 HYDROLOGICAL EFFECTS 

Degradation of the quality of the local water resources through increased 

siltation and runoff over construction areas is of environmental concern.. 

Construction of a retention pond could help mitigate this potential Impact. 

Drinking watcr for the work force and waters needed for construction will 

probably be supplied by the wells that supply the potable water needs of the 

existing power plant. Should the yields of these wells not suffice, an additional well could be dug after obtaining approval from the New Mexico State 

Engineer. 

4.8.3.6 SOCIAL AND CULTURAL EFFECTS 

The construction force is anticipated to range between 250 and 350 persons. 
Construction of the solar facility at the proposed location should not create 

any long-term adverse social, economic or cultural impacts. This conclusion 

is based on several factors, which relate to the following: (1.) the overall 

population of A1 buquerque, (2) the size of the civilian labor force, (3) percentage of the local unemployment, (4) size of the construction force required, 

and (5) duration of the. constr~ction~period. 

Generally speaking, a large city with a growing population such as Albuquerque 

does not experience the typical social-economic "boom-town" effects associated 

with construction projects in small isolated communities. With Albuquerque's 

average size of its civilian labor force of about 170,000 people, and a near 

10 percent or close to 17,000 unemployed people, it is possible to conclude 

that most of the 250 to 350 construction workers will be local inhabitants. 

Therefore, there will not be a large influx of people from outside the 

Albuquerque SMSA. Some specialized construction workers, technical pesp1,e 

and project managers will move into Albuquerque from outside areas, but their 

numbers will be small, and they will not cause any adverse impact to schools, 

housing, or utility systems, since Albuquerque will easily he able to absorb 

these people. There may be some increased demands placed on local restaurants, 

gas01 ine service stations' and shops in .the immediate vicinity of the site 

during construction. Also, the existing package sanitary waste system at 

the existing power plant niay have to be increased during construction tu 

accommodate the work force. 

Positive socioeconomic benefits would be increased tax revenues through wages 

and salaries, employment for several hundred workers in an area where unemployment is rather high (10 percent), and additional jobs created through a 

mu1 tip1 ier effect during construction. 

An archaeological survey of the site, performed p r i o r to cons Lr.uction, wi 11 

ensure no loss of potential archaeological infarmation. 
4.8.4 ENVIRONMENTAL IMPACTS OF OPERATION 

The environmental effects during the operation of the solar hybrid repowered site 

are described in this section. Included are discussions of the air qua1,ity 

effects (Section 4.8.4.1 ) , sound effects (section 4.8.4.2), land use effects 

(Section 4.8.4.3), ecological effects (Section 4.8.4.4), hydrological effects 

(Section 4.8.4.5), social and cultural effects (Section ,4.8.4.6), and visual 

impacts (section 4.8.4.7). 

4.8.4.1 EFFECTS ON AIR QUALITY 

Air quality impacts of the solar portion of the proposed f a c i l i t y w i l l be minimal. 

Potential air qual ity effects could result from the conventional equipment associ- 

. ated with power generation. 

In assessing the air quality effects of the proposed facility for this study, 

assumed emissions and assumed adverse meterological conditions were used. When 

the actual evaluation of the environmental impacts will be done, it would be 

more accurate to use actual on-site meteorological data. Results of this assessment were compared to Class I1 PSD (Prevention of Significant Deterioration) 

increments for inforrnatin~ only and not because the proposed facility will 

necessarily be subject to the PSD provisions of the Clean Air Act amendments 

of 1977. 

Fuel and stack characteristics are required to assess the potential impact of a 

new or modified facility on air qual ity. In this' particular case, th'e maximum 

continuous rating of the power plant is 50 MWe. The power plant i's currently 

operating 01.1 r~atural gas but has a backup fuel of residual oil number 6 or 

number 5. In the future, the facility will use residual oil which will most 

likely be number 6 blended with number 2 in .some proportion. 

In this section the following three cases are discussed: 

0 Power plant operation for peaking requircrnents - normal conditions - spinning reserve mode at nighttime 

Power plant operation under adverse conditions and spinning 

reserve. mode at nighttime 
Power plant operation - normal/adverse conditions and cold 

start-up mode at nighttime 

Figures 4.8-9 through 4.8-11 represent schematically these three cases and the 

following three paragraphs describe them in detail. 

The first case deals with the power plant operating for peaking requirements 

under what will be termed normal conditions. Thus, for twelve hours during 

the day, 25 MWe of power is assumed to be generated by solar energy and 25 MWe 

is oil fired. 

In the second case, the,operation of the power plant under adverse conditions 

is discussed. An example of such adverse conditions could be several consecutive days of overcast skies in which the power plant would be forced to generate 

the total 50 MWe by oil firing. In both cases, one and two, the boiler is assumed 

- 

to be in a spinning reserve mode at 5 to 25 percent of full power at nighttime. 

Case 3 considers the situation in which the boiler. must undergo a cold start-up 

period for twelve hours previous to daytime use. For case three, the boiler 

is assumed to operate at 25 percent of full power. This third case would be 

responsible for greatest emissions of SO2, NO2 and particulates under adverse 

daytime conditions and correspondingly, higher ground-level concentrations 

than maintaining the boi ler in a splnnir~y reserve mode. A range of ~a'l~r~ts 

SOp, NO2 and pnrtin~rlatc emissions given in later tables for the nighttime 

case should provide a conservative estimate for both the spinning reserve and 

cold start mode. 

Parameters used in the air quality assessment along with an explanation of 

their characteristics are summarized in Table 4.8-6. The percentages of 

emission for SO2, NO2 a~~d particulate matter are also presented in this 

table. Regardless of the residud'l oil type or blcr~d, the proposrd snlarjoil 

facility is assumed to comply with the maximum allowable State of New Mexico 

emission standards presented in Table 4.8-6. .Should the facility use only 

this oil, it st~rjuld meet the State of New Mexico ambient air quality standards 
Daytime (12 hours) 

Opera ti on 

i-1 50 MWe 

oil fired 

Nighttime (1 2 hours) 

Operation 

Mode -- oil fired 

at 5 to 252 full power 

Figure 4.8-9. Case I - Operation of a 50 MWe Solar/Oil 

Facility under Normal Conditions 

4-287 
Day t i me 

Operation (1 2 hours) 

50 MWe generated 

by oil firing 

Ni ght.t.ime 

Operation (1 2 hours) 

Spinning Reserve 

Piode -- oil fired 

at 5 .to 25%. full power 

Figure 4.8-10. Case I1 - Operation of a 5U MWe Solar/oil 

Faci 1 i ty Under Adverse Condi ti ons ,(i . e. , Several Consecutive Days of Overcast Skies) 
Daytime Dayt i me 

Normal Conditions (1 2 Hours) 

1 50 MWe 1 

25 MWe 

Oil Fired 

Nighttime Uperation 

(12 Hours) 

Adverse Conditions (1 2 Hours) 

50 Mwe Generated 1 

I by Oil Firing I - 

Nighttime Operation 

(12 Hours) . 

Cold Start-Up 

of Boiler at 

Cold Start-Up 

of Boiler at 

I 25% Full Power I 

Figure 4.8-11. Case I11 - Operation of a 50 MWe Solarloil Facility 

under Normal or Adverse Daytime Conditions and Cold 

Start-up of the.Boiler at Nighttime 
TABLE 4.8-6. FUEL AND STACK CHARACTERISTICS CONSIDERED 

IN AIR QUALITY IMPACT CALCULATIONS 

Power Plant Characteristics 

Fuel Types 

Fuel Consumpti on 

Stack Height 

Exi t Di ameter' 

Effluent Flow Rate 

-. 

Exit Temperatures 

Fuel Characteri stics 

Heat Input , 

State of New Mexico Sulfur 

Dioxide EmIssion Standard 

State of New Mexico Particulate 

Emission Sta~~dard 

State of Mew Mexico Nitrogen 

Dioxide Emission Standard 

Description 

No. 2 residual oil 

No. 6 residual oil 

120 feet 

10.5 feet 

5 ' 1.174 x 10 cfm 

545 x lo6 Btu/hr 

~0.34 lb/106 Btu A 

- c0.0-05 lb/106 Btu 

<0.3 lb/106 Btu A 
The modified facility will be classified as a fossil-fuel plant and will be 

responsible for an increased amount of pollutants emitted. This increase is 

a result of the conversion from natural gas to residual oil which has characteristically higher emission factors for SO2 and particulates. This modified 

source is defined as a major point source since it causes emissions in excess 

of 100 tons per year of any pollutant for which there is a national standard. (33) 

It is evident from the calculated emission values presented in Table 4.8-7 

and Table 4.8-8 that this solarloil facility can be considered a major point 

source. Since this facility will emit more than 100 tons per year of any 

6 pollutant and will operate a fossil-fuel boiler of more than 250 x 10 Btu 

thermal per hour, it may also require a prevention of significant deteriorati~n 

(PSD) per~nit.(~~) However, at this time it is not clear that the facility will 

definitely be subject to the PSD provisions of the Clean Air Act amendments 

of 1977. 

Table 4.E-7 presents the emissions (pounds per day) of SO2, NO2 and particulate matter from the solar/oil facility under normal operating, daytime and 

nighttime conditions (Case I). Two values are presented under nighttime 

operation and each were calculated based on a different reduced,percentage of 

full power to simulate either the spinning reserve or cold start-up mode. 

The total 'emissions for normal conditions are thus presented as a range of 

values; 2376 to 3239 1 blday of SO2, 1078 to 1469 1 blday of NO2 and 18 to 24 

1 b/day of particulate matter. 

Table 4.8-8 presents sirr~ilar emissions for the power plant under adverse 

meteor01 ogi cal conditions (Case I I ) such as several consecutive days of overcast skies. In this case, the total 50 MWe is generated by oil firing during 

the daytime while the nighttime power output remains at the same reduced 

percentage as in the normal operating conditions. 

Emissions under adverse conditions are approximately 40 percent higher than 

those emissions produced under normal conditions. The emissions produced 
TABLE 4.8-7. .CASE I. THE OPERATION OF A 50 MME SOLAR/OIL FACILITY 

UNDER NORMAL CONDITIONS* 

Emissions (pounds per day) . . Niqhttime (12 hours) 

Pol 1 utant Daytime (12 hours) 5% ... . 25% Total Range** 

Particulate 

Matter 

*Case I assumes 25 MWe generated by solar energy and 25 MWe oil fired 

**Total Range - lower limit = daytime + 5% full power value at night 

upper 1 imi t = daytime + 25% full power value at night 

TABLE 4.8-8. CASE 11. THE OPERATION OF A SOLAR/OIL FACILITY 

UNDER ADVERSE CONDITIONS* 

(i .e. Several Consecutive Days of Overcast Skies) 

Emissions (pounds per day) 

Niqt~lli~~le (12 ~IUUI'S) 

 PO^ 1 utant Daytime (12 hours) 5% 25% TU,L~~ Rdflyes'* 

Particulate 

Matter 

*Case I1 assumes the total 50 MWe generated by oil firing 

**Total Range - lower limit = daytime + 52 full powcr valuc at night 

upper limit = daytime + 25% full power value at night 
under adverse conditions and a cold start-up of the boiler during the nighttime are therefore good estimates of the worst possible emissions. It is 

important to note once again, that the emissions obtained in Tables 4.8-7 and 

4.8-8 were calculated using the maximum allowable emission factors for SO2, 

NO2 and particulate 111atter that the State of New Mexico permits. For further 

information, Class I1 significant deterioration increments are presented in 

Table 4.8-9. 

TABLE 4.8-9. CLASS I1 SIGNIFICANT DETERIORATION INCREMENTS'~) 

Maximum Allowable Increase 

Pol 1 utant 

Sulfur Dioxide: 

Annual arithmetic mean 2 0 

24-hour maximum 9'1 

3-hour maximum 51 2 

Particulate Matter: 

Annual geometric III~~II 

24-hour maxi mum 

Maximum ground-level concentrations for SO2, NO2 and particulates and applicable 

ambient air qua1 ity standards are presented for both cases (Case I and 11) in 

Tables 4.7-10 and 4.7-11. These maxirnum calculated values are based upon conservative considerations including meteroloqical conditinns conducive to high 

ground-level concentrations and were obtained by using a Gaussian formulation 

as discussed by Turner. (35) The terrain was assumed to be flat from the stack 

to the downwind distance of the predicted maximum ground-level concentration. 

The distance to the maximum was determined from the graphs presented by Turner (35) 

and an effective plume height calculated from Briggs' equation. This terrain 

consideration along with the assumptions that a given atmospheric stability and 

wind speed will exist for approximately six hours serve as the basis for the 

calculatior~s of SO2, NO2 and particulate concentrations shown in Tables 4.8-1 0 

and 4.8-11. .For comparison, 'the State of New Mexico ambient air quality standards 
TABLE 4.3-10. MAXIMUM GROUYD-LEVEL C.ONCEPITRAT1ONSk FOR S02, NO2 AND PARTICULATE 

MATTER UN3ER NORMAL OPERATING CONDITIONS ASSUMING UNLIMITED MIXING (CASE I) AND 

APPLICAELE AIR QUALITY STANDARDS 

State of New Mexico EPA-National Primary 

Maximum Calc~lzted Standards Standards 

24-hour 24- hour Annual t 24- hour Annual t 

dm3 pp:nl pg/n3 ppm ug/ PP~ ug/m3 PP~ yg/m3 PP~ 

A Stability, 3m/s** 24 'o 32 0.009 to 0.01 261 0.10 52 0.02 365 0.14 80 0.03 

E Stability, .2.5m/s' i7 to 23 0.006 to 0.009 

A Stability, 3m/s 11 to 15 0.006 to 0.008 188 0.07 94 0.04 --- --- 100 0.04 

P 

I EStabilityY2.5m/s 8to11 0.004to0.006 

ru 

10 

P 

Particul zte Matter 

(rcg/m3) 24- h'our 24-hour 7-day 30-day Annual t 24- hour Annual t 

A Stability, 3m/s 0.18 to 0.23 150 110 90 6 0 75 6 0 

E Stability, 2.5m/s 0.83 to 0.17 

*Maximum ground-l'evel concentration calc~lated assuming persistancy of the stability class and wind speed 

for six out of 24 hours. Ca1:ulations 3ssumed flat terrain which is 8 km of the stack. 

**These wind speeds were assumed and wsrl? not b3sed on actual on-site data 

tAnnual arithmetic mean for SO2 and Pl13~ and ge~metric mean for particulate matter 
TABLE 4.8-11. MAXIMUM GROUND-LEVEL CONCENTRATIONS* FOR S02, NO2 AND PARTICULATE 

MATTER UNDER ADVEFSE OPERATING COND1T:ONS ASSUMING UNLIMITED MIXING (CASE 11) 

AND APPLICABLE AIR QUALITY STANDARDS 

State of New Mexico EPA-National Primary 

Maximum Calculated Standards Standards 

24- hour 24-hour Annual t 24- hour Annual t 

ug/m3 P pm ~g/m3 PP~ ~g/m3 PP~ ~q/m3 PP~ vg/m3 PP~ 

A Stability, 3m/s** 45 to 53 0.009 to 0.02 261 0.10 52 0.02 365 0.14 8 0 0.03 

E Stability, 2.5m/s 34 to 40 0.013 to 0.015 

A Stability, 3m/s 20 to 24 0.001 to 0.013 188 0.07 94 0.04 --- ---- 100 0.04 

E Stability, 2.51111s 

Particulate Matter 

(ug/m3) 24- hour 24-hour 7-day 30-day Annual? 24- hour Annual t 

A Stability, 3m/s 0.30 to 0.5 150 110 90 6 0 7 5 60 

E Stability, 2.5m/s 0.25 to 0.3 

*Maximum ground-level concentration calculated assuming persistancy of the stability class and wind speed 

for six out of 24 hours. Calculations assumed f'at terrain within 8 km of the stack 

**These wind speeds were assumed and were not based on actual on-site data 

tAnnual arithmetic mean for SC2 and NO2 and geometric mean for particulate matter 
for SO2, NO2 and particulate matter (36) as well as the ~nvironmental Protection 

Agency (EPA) Regulations on national ambient air qua1 i ty standards (37) are 

presented in the same tables. 

A comparison of the short-term (24-hour) calculated averages and applicable 

ambient air quality standards indicate that the concentrations of pollutants 

produced by this modified facility would be expected to be in compliance with 

the State of New Mexico and national air quality standards. Even when the 

existing 24-hour background concentration of 15 pg/m 3(38) for both SO2 and NO2 

are added to these values, the standards would be met with a large margin of 

Since concentrations also decrease with sampling time, annual calculated 

ground-level concentrations will be less than the short-term 24-hour values 

and will also be less than annual national and state standards. 

As well as meeting national and state air quality standards, this proposed 

solar/oil facility may be expected to comply with Class I1 significant 

deteoriation increments for SO2 Under normal conditions, the maximum calcu3 lated 24-hour SO2 concentration will be less than 91 ug/m above the background 

24-hour SO, concentration thus complying with Class I1 significant deteoriation L 

increments (see Table 4.8-9 for reference). Since the proposed site is in 

a non-attainment area for particulates, Class I I slgnif icant deteriora.l;.ior~ 

increments cannot be applied to this pollutant. It should be noted that the 

Albuquerque area is also a non-attainment area for oxidants and carbon monoxide.' 

Should this facility be subject to PSD requirements, emission offsets might have 

to be obtained for oxidants, carbon monoxide and TSP (total suspended particulates). 

In summary, it is clear that the proposed stack emissions and resulting concentrations of concern (SO2, NOZ and particulates) are less than the national 

and state standards with .a large margin of safety. Furthermore, based on 

this assessment, the calculated 24-hour SO2 concentrations under normal or 

adverse conditions wi 11 comply with Class 11 ' significant deteoriation 

increments. 
4.8.4.2 EFFECTS OF SOUND 

Sound levels at the solar hybrid repowering site are anticipated to be the 

same as present ambient sound levels. The low levels of noise generated by 

the boilers, the turbogenerators and the cooling towers that are presently 

at the site are not expected to change significantly with the introduction 

of the solar modification. The solar heliostat field will not generate any 

sounds. 

4.8.4.3 EFFECTS OF LAND USE 

There are several advantages or positive land use aspects of locating the 

solar facility on the proposed site. Suburban residential development has 

been concentrated cast of IntcrstaLe 25. The area already has several industrial facilities around it that would be compatible with the solar facility. 

These include the Reeves power plant, two industrial parks, American Gypsum 

and Albuquerque Gravel Products. In addition, since the facility would be 

used for educational and research purposes, proximity to the interstate would 

allow good access to the site from downtown Albuquerque. 

Thc 130 acres to be ubed fur the solar taci 1 i ty wi l l be precluded from being 

used for other purposes for which this land is fit such as expansion of existing industrial parks. Since some type of buffer zone is usually required 

around this type of facility, a total of more than 130 acres may be affected 

directly and indirectly. Since this area has been designated as "established 

urban area" in A1 buquerque/Bernal i 1 lo County's Coniprel~ensive Plan, and two 

industrial parks are already in this area with speculation for a third industrial park, the potential for a land use conflict may exist between these 

industrial uses: industrial parks and power production. 

This land is not fit for agricultural purposes but could be used for industrial 

purposes. 

4.8.4.4 ECOLOGICAL EFFECTS 

As described in Section 4.8.2.7, the terrestrial ecology at the solar hybrid 

repowering site is typical to the local desert conditions: only approximately 
15 percent is covered with flora, which provides relatively little habitat to 

the local desert fauna. A1 though approximately 130 acres will be affected 

directly by the solar heliostat field, the disruption of the local ecosystem 

on these 130 acres in this location (Section 4.8.29, Land Use) cannot be considered significant. This is especially true considering that the land has 

been designated for industrial purposes (Section 4.8.2.9), and the disruption 

of this ecosystem has been designated to occur by the local inhabitants. 

In addition to the affect of the local existing terrestrial flora and fauna, 

operation of this could affect nearby communities through: (1) emissions to 

the air, (2) cooling tower drift and (3) impacts caused by the heliostat field. 

TERRESTRIAL EFFECTS CAUSED BY AIR EMISSIONS 

Since the site will have been significantly altered during construction, the 

operational impacts to vegetation will be to the surrounding area. Emissions 

to the atmosphere will meet all local and Federal standards, and the use o'f 

the solar portion would reduce emissions by 40 percent as compared to using 

oi 1. In addition, levels of emi tted pol 1 utants wi 11 be below those that are 

known to cause harm to the local flora and fauna. Thus, impacts should be 

insignificant. 

IMPACTS FROM COOLING TOWER DRIFT 

Drift from cooling towers is being deposited in the surrounding vicinity and 

whether this deposited material could have an impact on the local soils, 

vegetation and waters is of environmental concern. 

Since groundwater is used in the cooling towers, the major ionic constituents 

consist probably of bicarbonate, calcium and magnesium, and the drift probably 

consists mainly of calcium and magnesium carbonates. 

Cooling towers are presently employed at the existing power plant and no 

change in the quantity of waters used, in the number of cycles of concentration applied, nor the amount or type of chemical additives should occur. Thus, 

no change in impact of the cooling tower drift to the local soils should occur. 
Cooling tower drift may affect vegetation in two main ways: (1) any affect on d the local soils may affect the vegetation these soils support, and (2) deposits 

on the leaves may reduce photosynthesis and/or cause burns to leaves. Since 

the soils will not be affected and since the drift will be mainly composed of 

calcium and magnesium carbonate, no har~n to the local vegetation should be 

caused by the cooling tower drift. 

HELIOSTAT FIELD IMPACTS 

Operational effects to terrestrial wildlife will relate primarily to birds and 

particularly during migratory periods. It is expected that some birds could 

die from impact with the heliostats and the tower. Birds and other flying 

creatures such as moths and butterflies may be attracted to the reflective 

surfaces and rrlay be killed on impact or they may be burned as a result of such 

contacts. It must be noted at this point, as mentioned in Section 4.8.2.7, 

Terrestrial Fauna, that this solar hybrid repowering site is not located 

directly in the path of the majority of migratory birds. 

To prevent the entrance of wandering larger animals into the collector field; 

the field will probably need to be fenced. This precaution will also avoid 

the possibility of animal-caused accidents. Impacts to most animals will be 

limited because of the current lack of adequate habitat. However, rodents may 

increase with an increase of forbs and grasses under the shaded heliostat. (40) 

The potential for impacts to endangered flora or fauna can be determined by 

on-site studies. At this time no'aquatic or terrestrial endangered species 

are known to be present 011 lt~e site lior in the vicinity of the site. 

4.8.4.5 HYDROLOGICAL EFFECTS 

Local water resources could be affected by the operation of the solar hybrid 

repowering system throuqh six majnr qnllrres: 

0 Flooding due to increased runoff a Oil spills 

r Cooling tower blowdown e Sewage discharges 

e HeS lostat washi ng/ri nsi ng r Impact onwater availability 
Since no paving is planned on the heliostat field, the quantity of runoff 

over this field should not increase significantly in comparison to present 

conditions. Some increase in erosion may occur as a.result of soil manipulation and removal of the local vegetation cover. Should mitigation of this 

occurrence be required, a collecting pond could be constructed to collect 

the runoff that will drain the field. 

EFFECTS OF COOLING TOWER BLOWDOWN 

Blowdown from the solar hybrid repowerlng statiur~ cvul ing tower wi 11 contain 

chemicals that serve to prevent scaling, corrosion and biological fouling 

and will be of the same type presently used at the existing power plant cooling 

system. Blowdown will be combined with other discharges and treated, if needed, 

to meet NPDES (National Pol 1 ution Discharge El imination System) requirements prior 

to discharge. All discharges would comply with current EPA regulations and 

would be discharged to the Alameda Drain of the Middle Rio Grande Conservancy 

District. Effluent waters that would not comply with EPA discharge regulations 

would be contained ir~ an evaporation pond. 

EFFECTS OF HELIOSTAT WASHING/RINSING FLUIDS 

Periodically the heliostats will be washed prwbably with a diluted weak ammonia 

solution and then rinsed wl tR deiurli ~ecl water-. A total ot approxlmarely 15 

gallons of water would be required per heliostat per washing of which approxlmately five gallons are the wash solution and 10 gallons are deionized water. (11) 

Washing of heliostats is expected to take place at a frequency of one washing 

per month. For the 4289 heliostats expected for this solar hybrid repowering 

site, approximately a total of 800,000 gallons of water per year could be 

required of which two-thirds will be deionized water. Collection and recycling 

of washing and rinsing solutions will probably be done if found to be practical 

and feasible. 

Ammonia is found in equilibrium in water as shown in the following equation: 
The equilibrium is driven to the right with the increase in pH. Since the 

make-up water has a basic pH (Section 4.8.2.6, Groundwater ~~drology), some 

of the ammonia will dissipate as gaseous ammonia (NH3). (The concentration 

entering the atmosphere should be too small for environmental concern.) 

Conservation methods will be employed and it is expected that no wash water 

from this facility will be discharged into surface or groundwater bodies. 

EFFECTS OF OIL STORAGE AND SPILLS 

Oil will be stored on site in accordance with the December 1973, Environmental 

Protection Agency Regulations on Oi 1 Pollution Prevention (43) which wi 11 

minimize the potential inlpacts of oil contamination on the local surface and 

groundwater resources. 

EFFECTS OF SEWAGE DISCHARGES 

Approximately 25 to 35 people will comprise the operational work force of the 

solar hybrid repowering site (Section 4.8.4.6). Sewage effluents from such a 

work force will be absorbed by the existing package sewage facility with no 

difficulty. The existing system, as described in Section 4.8.3, meets 

regul atory requirements. 

IMPACT OF WATER AVAILABILITY 

Water requirements for the operation of the solar hybrid repowering system 

should reduce or equal water requi re~~erlts of presently used systems (Section 4) 

and therefore no impact on local water availability should ncclrr. Water needs 

for operating personnel (approximately 25 to 35 people) should also not pose 

a hardship on the potable water availability at the site. As described in 

Section 4.8.2.6, groundwater is available in the Albuquerque area, and should 

there be a total net increase in water requirements, those should be met 

wi thc?l.rt affecting existing local water users. 
4.8.4.6 SOCIAL AND CULTURAL EFFECTS 

The operating force for the solar plant will range between approximately 25 

and 35 employees. This is a small number of people when comparing to the 

overall population of Albuquerque, to the total labor force, and when considering the growth rate of the area. Thus, this small operating force will 

not cause any noticeable adverse soci~economic effects. 

Positive socioeconomic benefits from this faci 1 i ty wi 11 be increased tax 

revenues through .taxes on the facility, wages and salaries, personal property 

tax, sales tax and other similar taxes. In addition, this facility will allow 

PNM to provide the electric power to the increasing number of residents in the 

A1 buquerque/Bernal i 1 lo County area (see Section 4.8.2.12). 

4.8.4.7 AESTHETIC EFFECTS 

It is generally accepted that industrial intrusions that interefere with the 

far-reaching natural landscape are considered unattractive and constitute an 

adverse impact. 

Visibility of the heliostat field would be from Los Anyeles Boulevard to the 

north, and 1-25, the Frontage Road and the planrled extension of Jefferson 

Road to the east. Visibility from Osuna Road would generally be impaired by 

deve lopment, and frv111 Nur.tli Edith Boulevard visi bi 1 i ty would he nhstructed 

by the rise in elevation and the drainage channel. Travelers vlewlng ,the site 

from Los Angeles Boulevard would have their view intermittently obstructed by 

the Reeves Station and the Gypsu~rl Plant. Viewing of the site from 1-25 and 

the Frontage Road with present developments wobld be relatively ul~ubsti-ucted 

due to the higher elevation to the east of the site and lack of development. 

Future development may obstruct this line of sight. Slnce the r-eceiver tower 

will rise approximately 530 feet (160 meters), it will be visible from 

several miles dWdy and fvom rcsidur~ces and highw9.y~ that have long viewing 

ranges. This will be a dominant visual element in the Albuquerque area and 

will require further evaluation as to Its impact. 
4.9 SAFETY CONSIDERATIONS 

One of the developmental areas in the conceptual design of a 25 MWe solar 

hybrid repowered plant at PNM Reeves Unit No. 2 is the investigation of safety 

aspects associated with the application of a solar central receiver design. some 

of these health and safety considerations are unique to a solar central receiver 

design while others are relevant to the existing power plant. Section 3.6, 

Safety considerations, discusses some of the safety aspects evaluated in selecting a specific unit to be repowered on the PNM system. This section reviews 

certain hazards that are associated with locating a solar central receiver system 

at an existing facility and these hazards are primarily related to the use of a 

tall central receiver tower and a 1 arge he1 iostat (col 1 ector) field. Specific 

restrictions are imposed by FAA regulations on the construction of a tall 

(receiver) tower. The he1 iostat coll ector field poses a significant safety consideration with respect to both the general public and to the operating personnel 

when one considers the potential solar reflectance hazards resulting from the 

operation of such a facility. 

A number of reports have been issued that address the safety aspects that are 

unique to the application of a solar central receiver system. Among these are 

three reports that deal with the 5 MWt Solar Thermal Test Facility (STTF) 

which has been constructed at the Sandia ~aboratories in A1 buquerque, 

New Mexico. (44y 45y 46) The tower, heliostat field and control building 

for this test facility covers approximately 10 acres of land. The height of the 

tower is 60m (%ZOO-feet) and the he1 iostat collector field contains q.,366 he1 iostat foundations. Several prototype heliostats and types of central receivers 

located at the top of thc tower will be evaluated at the facility. 

Several safety aspects were discussed in the MITRE Report. These included: 

a) the requirements for fire protection, and b) the potential glare from the 

heliostat mirrors and its effect on the pilots that take-off and land aircraft 

at the two airports that border the Sandia facility; Kirtland Air Force Base 

and the ~l h~r~uer~ue Municipal Airpurt. Because the STFF he1 iostats are indiv-idually focused onto the receiver at the top of the tower, each one at a different 

angle, their effect on a pilot's vision was expected to be slight, similar to 
flying across the choppy water of a lake. The Martin-Marietta heliostat design 

2 for the STTF consists of 25 individual facets or mirrors to produce the 37 m of 

reflective surface and each of these facets are slightly dished and can be 

individually focused. 

An additional consideration with regard to air traffic in the Sandia area is 

the 200 foot tall tower. Since this tower needed to conform to FAA regulations 

for aircraft safety, any danger was expected to be minimal. Moreover, the 

tower location needed to be noted on the pilot's instrument approach plates 

(Jepson Charts) for Albuquerque so that all aircraft can avoid it. Some 

thermal turbulence will also be created by the heat plume rising from the tower. 

The combination of these three potential safety impacts (glare, obstruction, 

and turbulence) on air traffic may necessitate slight modifications in the 

flight paths over the Sandia Laboratories area. Similar solar reflectance/ 

tower height/heat plume assessments will be required in the development of a 

25 MWe solar hybrid repowered plant at Reeves 2. 

Significant efforts have been performed in assessing the eye hazards and 

evaluating the glint aspects in the development of this 5 MW STTF. (45) 

Potential eye hazards associated with concentrated reflected 1 ight (solar 

reflectance hazards) were evaluated. Specific 1 ight intensities and hazar.dous 

ranges of single and niultiple coincident heliostat beams have'been assessed 

for conditions a.t butt1 ground level and in the air space above the facility. 

The possible long-range and short-range d.i stracti ve effects of ref1 ected bea11.1~ 

were also discussed. Certain beam control modifications which needed to be 

incorporated so as to minimize the altitude at which over-flying aircraft 

could encounter unsafe levels were described. Rccommendations were made in 

Reference (45) with respect to the 5 MW STTF for further evaluation of the 

intensity.excursions during fail-safe shutdown situations and for specific 

experiments which could be used to verify analytical models and to assess 

the distractive glint affects. 
Excerpts from some of the conclusions drawn in Reference (45). along with 

additional specific notations which apply, in general, to a solar hybrid 

repowered plant, are as follows: 

o With regard to the application of the 25 faceted heliostat 

design by Martin-Marietta at the STTF, the reflected beam from 

any single heliostat with a focal length shorter than about 

260 m c o n s t i t u t e s a potential eye hazard that extends for a 

comparatively short distance on either side of its focal point. 

This hazard zone is generally confined to 20-30 meters on either 

side of the focal point with the shorter focal length beams 

being the most hazardous. Similar assessments will need to be 

made when one considers the potential eye hazards of the latest 

heliostat designs being developed by MDAC, Martin-Marietta, or 

others which might be used for the 25 MWe solar hybrid repowered 

plant at Reeves 2. 

e Specific beam control measures needed to be incorporated as a 

result of possible multiple beam intensities so as to minimize 

the altitude at which over-flying aircraft might encounter eye 

hazards. These efforts were desi yr~ed to effectively preclude 

intensities greater than one sun and thereby prevent unsafe 

retinal irradiances at altitudes greater than about 200 m d u r i n g 

normal operations. 

e Although, during certain types of fail-safe shutdown, the 

potential fcri' i~iul'l~er~tary excur$ions of greater than one-sun 

intensity may extend to several hundred meters, these types of 

failures were considered to be very rare. 

a Based on the Martin-Marietta cavity receiver for the STTF, the 

reflected light from diffuse surfaces located in the focal zone 

does not appear to present a hazard except in controlled areas 

near the top of the tower. Further consideration of this aspect 

will need to be performed if a MDACIRocketdyne external receiver 

design is employed in the 25 MWe solar hybrid repowered plant.. 

The potential fire hazard which might exist for the shorter 

focal length heliostats needs to be evaluated for the conditions 

in which the beams might impinge on a combustible material. 

A preliminary review of the safety considerations for the conceptual design 

of a solar hybrid repowered facility has been completed. In developing 

prel iminar'y Ileal th and safety consideratiuns, initial evaluations call for the 
identification of potential hazards and the corresponding subsystem(s) in 

which these hazards can occur. In most cases, possible causes for the 

hazardous conditions have been outlined. Some of the specific corrective 

actions which will be pursued to mitigate the severity or frequency of 

occurrence, or to eliminate the hazard entirely, have. been identified. A 

complete health and safety assessment of the solar hybrid facility at PNM 

Reeves 2 will be required in subsequent phases of this program. This assessment will be based on the final design of the solar subsystem as well as on 

the specific components and working fluids selected for the solar hybrid 

repowered uni t . 

In developing an approach to specifying the health and safety considerations 

appropriate to the solar hybrid repowering program, several items will need 

to be delineated and/or evaluated: 1) the objectives of the health and safety 

program, 2) the applicable design guidelines, requirements and regulations fur 

health and safety, 3) the types of hazards which need to be considered during 

the subsequent phases of the program and 4) the definition of a recommended 

set of safety related categories to be utilized in the analysis. A detailed 

health and safety analysis which will need to be performed will treat the 

following types of hazards associated with the solar hybrid repowering 

application at Re'eves 2: solar reflectance; working fluid (steam and hot 

~ater) and oi 1 fuel ; electrical ; mechanical ; ma1 function; and maintenance 

hazards. In addi ti on, several u.ther pstenti al problems wh~i cti extenc:l 

beyond the normal health and safety of operating personnel will require 

investigation. These include a) the health and safety considerations of the 

general public, as well as visitors to the facility, b) transportation (both 

vehicular and airline modes) and its impact on safety, and c) the environmental 

and re1 i abi 1 l ty considerations. The prcl iminary conclusions wi fh regard to 

assessing health and safety considerations which can be drawn from this 

concrpt~ral design phase fnr the solar hybrid repowering program are: 

1) numerous hazards, causes of potential hazards and possible corrective 

actions can be identified, and 2) all potential problems are amenable to 

solution. 
Preliminary health and safety considerations have been developed for a 25 MWe 

solar hybrid repowered plant at Reeves 2. This development effort is consistent with the conceptual design phase of the Technical and Economic' Assessment 

of Solar Hybrid Repowering. Some of these considerations will be applicable not 

only to the design of the solarlhybrid subsystems being proposed for repowering, 

but also may be appropriate to the general solar central receiver programs being 

developed by the Department of Energy. The prel iminary design guide1 ines and 

the safety analysis for the identification of potential hazards discussed below 

will relate specifically to the PNM design for the solar hybrid repowered unit, 

to the working fluids required for the system and to the appropriate components 

currently envisioned for use by the system. 

With respect to safety considerations in the development, construction, start-up, 

test and operation of a solar hybrid repowered f a c i l i t y a t Reeves 2, the complete 

system must be designed to fulfill a number of the following objectives: 

e Protect the health and insure the safety of the general public. 

s Protect the health anil illsure the safety of the PNM Operating 

personnel and of visitors to the solar hybrid repowered facility. 

e Prutect the health and insure the safety of the construction, 

testing, and maintenance personnel for the facility. 

e Protect the health and/or insure the safety of the living 

environment (birds, animals, other wild1 ife, trees, shrubs, 

grass, etc. ) . 

e Maintain the qualily oP the environment by minimizing or eliminating the pollution or contamination of the surrounding land, 

water and air. 

The first three objectives deal directly with health and safety and will be 

the primary goals of this effort. The last two objectives (environmental 

health, safety and quality) deal indirectly with health and safety. Any 

Impacts to the quality, health and safety of the living environment 

identified herein will need to be evaluated further as part of the complete 
envi ronmental assessment. The above criteria, possibly compl imented by others 

yet to be identified, have been set forth as the preliminary health and safety 

objectives .in future phases of this program. 

4.9.2 DESIGN GUIDELINES 

Numerous guide1 ines , requi rements and regulations are appl icable to the 

health and safety considerations which will be assessed during the development 

of the solar hybrid repowered facility at Reeves 2. Special attention will be 

devoted to the design of the solar collector (he1 iostat) field and the central 

receiver/tower subsysl;en~s because of thc relatively less rnilt.11r-e technology of 

these components in solar central receiver systems. Thc ePectrica1 power 

generation subsystem (consisting of piping, componen.ts, controls acd wiring for 

fluid power and electrical power generation), the fossi 1 boiler subsystem and 

the auxiliary subsystems are based on a more mature'technology and, in fact, are 

mostly in existance at Reeves 2. Accordingly, the applicable codes and standards 

which are now available for the electrical power generation and auxiliary power 

subsystems will be observed for the new construction or modificdtio~s to thesc 

subsystems. These same codes and standards, appropriately applied, will serve . 

to ensure safe design of the components and subsystems unique to solar central 

receiver hybrid repoweri ng sys terns. 

An extensive 1 ist of standards, regulations, manuals ar~d codes has been compiled 

which may comprise some of the design guidelines and requirements for the solar 

hybrid repowering project. These include: 

e American Society of Mechanical Engineers (ASME) Boiler and , Pressure Vessel Code: 

- Section I, Power Boilers 

- Section 11, Material Specifications 

- Section V, Nondestructive Examination 

- Section V'III, Pressure Vessels 

- Section IX, Welding and Brazing Qualifications 
National Fire Protection Association (NFPA): 

Fi re Protection Handbook 

National Fire Protection Association (NFPA) National Fire 

Codes (NFC): 

- Volume 2, Water Spray Fixed Systems 

- Volume 5, Explosion Prevention Systems 

- Volume 6, National Electrical Code 

American National Standards Institute (ANSI ) : 

- ANSI A13.1, Scheme for the Identification of Piping Systems 

- ANSI A58.1, Building Code Requirements for Minimum Design 

Loads in Buildings and other Structures 

- ANSI 831.1, Power Piping Code 

- ANSI 253.1, Safety Color Code for Marking Physical Hazards 

arid Identification of Equipment 

Occupational Safety and Health Administration (OSHA) 

- OSHA 2206, General Industry Standards : 

Al~~er-i~drl Suclety of Heaeiiig , Ketri gerating and Air Conditioning 

Engineers (ASHRAE) : 

- ASHRAE Standards for Design of HVAC Equipment 

- ASHRAE standard 90-75, Energy Conservation in New Building 

Design 

Air Conditioning and Refrigeration Institute (ARI) : 

- Standards for Cooling Towers and Condensers 

National Board of Fire Underwri ters (NBFU) : 

- Codes for Buildings and Equipment 

National Electric Manufacturers Association '(NEMA) : 

- Standards for Electrical Equipment and Controls 1 
a Safety Rules for the Installation and Maintenance of Electric 

Supply and Communication Lines 

a Steel Boiler Institute (SBI): 

- Codes for Boi lers 

a Tubular Exchanger Manufacturers Association (TEMA) : 

- Standards for Heat Exchangers 

e Underwriters ' Laboratory (UL) Standards 

a Uniform Building Code 

a Standards of American Institute of Steel Construction and 

Ameri can Concrete Ins ti tute 

0 Interstate Commerce Commi ssion (ICC) Shipping Standards and 

Regulations 

e National Safety Council 

- Accident Prevention Manual for Industrial operations 

These standards and codes, and possibly others, will be utilized as the controlling design guidelines and requirements during future phases of the solar 

hybrid repoweri ng project, as appropriate. 

FNM also intends to review and utilize, where appropriate, the health and 

safety assessment being prepared for the 10 MWe Solar Central Receiver Pilot 

Plant to be constructed at Barstow, California. In addition, it is anticipated 

that further desi,gn guidelines and safety criteria will be developed by the 

Department of Energy in other solar central receiver and solar hybrid programs 

which may be appropriate to incorporate into the solar hybrid repowering 

project. Finally, further technology development and testing efforts at 

Sandia Albuquerque and Sandia Livemore in the safety area are expected and 

these results will need to be considered. 
4.9.4 SAFETY HAZARD CATEGORY DEFINITIONS 

The conventional definitions by which possible hazardous conditions can be 

categorized for severity during subsequent phases of the project are as 

follows: 

e Category I - Safety Catastrophic. Condition(s) such that 

environment, personnel error, design characteristics, procedural 

deficiencies or subsystem or component malfunction will cause 

death or multiple injuries to personnel or to the general public. 

e Category I1 - Safety Critical. Condi tion(s) such that environment, personnel error, design characteristics, procedural 

deficiencies, or subsystem or component malfunction will cause 

major.. personnel injury, or will result in a hazard requiring 

immediate action to preclude major injury, including possible 

injury to the general public. 

e Category I11 - Safety Marginal. Condition(s) such that environment, personnel error, design characteristics, procedural 

deficiencies, or subsystem or component malfunction wi 11 cause 

minor injuries to personnel or the general public. 

Category IV - Safety Negligible. Condition(s) such that environment, personnel error, design characteristics, procedural 

deficiencies, or subsystem or component malfunction will not 

cause personnel injury. 

4.9.4 SOLAR REFLECTANCE HAZARDS 

Several different hazardous conditions could result from the effects of 

concentrated solar insolation or reflectance from individual or mu1 tip1 e 

heliostats in the collector subsystem. Thus, a potential safety hazard 

associated with the solar hybrid repowering site could stem from emergency 

or accidental misdirected solar radiation. This invisible concentrated and 

focused solar radiation,can potentially cause fires and burns as well as 

create glare problems. At the focal point, there is a concentrated beam of 

focused radiation. Beyond the focal point, this beam becomes increasingly 

dispersed and eventually becomes more diffuse than the original solar radiation. 

Thus, there is a range around the focal point where the beam is concentrated 

to a degree to present potential safety hazards. These include potential 

fires, burns and glare. 
A severe eye hazard exists for those personnel whose eyes are looking at, and 

happen to be located near the focal point 0% several heliostats during periods 

of sunshine. Depending upon the concentration ratio for these heliostats and 

the eye 1 ocati on, temporary "f 1 ash" bl indness or permanent bl i ndness (from the 

burn damage to the choroid and retina of the eye) could occur. A glare hazard 

may also exist when personnel are located in or near the collector field. As 

discussed above, a glint or glare hazard is also a safety consideration to the 

general public outside and above the boundaries of the solar hybrid repowered 

facility. 

A skin hazard (concentrated sunburn) is,also a consideration for the design of 

a solar central receiver system. Although the above-mentioned eye hazard is 

more critical, serious burns from concentrated insol ation (reflectance) could 

occur near the focal point. However, multiple sun intensities would be 

sufficiently uncomfortable on the skin that evasive action would probably be 

taken immediately. Skin or eye hazards to the living environment, like that 

to a bird flying at nor near the focal point of the collector subsystem, is an 

additional consideration. 

While not as hazardous as burns or fire, glare is a potential problem resulting 

from misaligned or even properly aligned heliostat collectors. This is due to 

its abil ity to impact both on- and off-si te receptors .as we1 1 as those in 

overflying aircraft. The intensity of this glare will he a f~lnction of the 

distance of the receptor from the heliostat field or individual heliostats 

producing the glare. As this distance increases, the intensity of the glare 

wi 11 decrease. 

Nuisance glare and gl int caused by reflected sun1 ight from the heliostats may 

affect nearby residents, aircraft pilots and passengers and highway travelers. 

Several studies have been conducted which describe the potential environmental 

and safety hazards that exist for solar plants. A few of these studies were 

discussed above at the beginning of Section 4,9. One of the safety considerations most frequently cited is variously termed distractive glint, nuisance 

glare, misdirected l i g h t o r spurious reflections. These can result during 

normal operations, from misaligned heliostats, or during mirror washing 
operations. The impact can range from nuisance glare and temporary blindness 

to serious skin burns and permanent eye damage, depending on the proximity 

and length of exposure. The occurrence of these impacts will depend upon the 

proximity of the field to residences and traffic.corridors, upon the terrain, 

and upon the presence of other structures within the line of sight, as well 

as the orientation of the heliostats. Several mitigating measures can be 

taken when proven necessary that will eliminate or reduce these potential 

hazards or annoyances. Fencing or vegetative screening can be used to 

surround the heliostat collector field to prevent nuisance glare or glint to 

residents and motorists. 

Potential safety hazards exist for aircraft pilots and airline passengers due 

to glint and glare from the heliostats and the 530 foot height of the receiver 

tower, since four airports are within %I0 miles of the proposed site. Specific 

evaluations of flight paths, aircraft altitudes, types and sizes of aircraft, 

and air traffic volumes would have to be made to determine the probability and 

severity of these potential impacts. Coctrol measures to protect pilots and 

air travelers from glint include the use of exclusion zones for aircraft and 

beam control techniques, and these can be determined in cooperation with FAA 

authorities. 

Most of the above solar reflectance hazards are of concern primarily to the 

construction, testing, operating and maintenance personnel, and to the visitors, 

authorized or unauthorized, to the solar hybrid repowered facility. Techniques 

which might be used to eliminate, reduce the frequency of or mitigate the 

severity of, some of these potential hazards include: the use of fencing to 

enclose the collector field; requiring eye protection, protective clothing and/or 

gloves when working near the heliostat collector field or the receiver at the 

top of the tower; proper instruction of personnel on the methods to avoid these 

hazards; proper design of the controls for the collector subsystem (particularly 

for quick and safe emergency shutdown conditions) ; a1 1 potentially combustible 

materials will be stored in places inaccessible to misdirected radiation; and 

the use of safely and warning devices or signs. 
4.10 PRELIMINARY NOTES ON INSOLATION PREDICTION FOR SOLAR ELECTRIC POWER PLANTS 

This section discusses insolation prediction in terms of its importance to solar a 

power plants, factors controlling insolation, cloud characteristics, and other 

- 

weather situations that affect insolation. 

4.10.1 THE NEED FOR LOOK-AHEAD REQMREMENTS 

There are three major types of look-ahead or insolation prediction requirements 

for solar el ectric power plants : 

a Short-term, minutes to hours 

e Intermediate, several hours to several days 

e Long-term, average monthly to annual values 

Short-term prediction of heliostat field outputs is especially necessary for 

solar repowered stations that do 'not have thermal storage. Typical thermal 

response time of such station's is in the order of a few minutes, and back-up 

boilers require a minimum build-up warning time of 10 minutes for load following. 

It is also desirable to have warning times of an hour or more to come up from 

cold conditions. Predictions of up to 10 to 15 minutes will be of value, and a 

look-ahead capability of one hour shoule meet most short-term needs. 

Intermediate prediction of one-half to three days will be of value in determining 

how much of a solar capacity can be anticipated, and if it. is likely to he 

uninterrupted. 

Long-term prediction is of value in determining the economic worth of a plant, 

as well as how much energy will be available from a solar plant on a month-bymonth basis, which can assist in determining likely fuel usage. 

4.10.2 FACTORS CONTROLLING INSOLATION 

The diurnal and seasonal variation in the direction of arrival of the sun's 

direct rays as a function of location for obs'ervat.ions above the earth's 

surface is well established. The effects of the atmosphere in modifying the 

sun's radiati.on available at the earth's surface is much more complex. A 
model has been developed that allows the prediction of the direct normal 

term with a good degree of accuracy based on atmospheric parameters. (See, 

for example, "On the Nature and Distribution of Solar Radiation," Report 

HCPlT2552-01, U. S. Department of Energy, Di vi si on of Solar Techno1 ogy , 

Environmental Resource Assessments Branch, March 1978.) The variation in the 

direct normal term caused by changes in aerosols and atmospheric watcr vapor 

can be accounted for and, in general, predicted with a good degree of accuracy 

particularly since their characteristics do not vary rapidly. The major 

problem in look-ahead capability is the ability to predict the presence of 

clouds over the solar energy site. 

The general insolation model employed is illustrated in Figure 4.9-1, which - 

indicates the variation in inso!ation values above the atmosphere due to 

varying sun-earth distance, and then the reduction in the direct normal term 

due to the various atmospheric constituents. 

The major problem, particularly as far as short term prediction, involves the 

motion, formation and dissipation of clouds. In general, there may be a 

short boundary of the clouds where the direct normal term is reduced, but ' 

this is usually fo'l lowed by an essentially complete blockage of the direct 

term as the cloud moves across the observing point. In view of the importance 

of clouds in determining the ability to predict insolation, particularly on 

a short term ba.sis, the following section will treat in some detail the 

characteristics of clouds as they are important to the prediction problem.' 

4.10.3 CHARACTERISTICS OF CLOUDS 

CLOUDS IN GENERAL 

Many different ways have been proposed to describe cloud types. F.H. Ludlam 

has proposed four basic classes of clouds based on the formation process: 

0 Orographic clouds, which are formed as a result of vertical 

motion caused by mountains or hills 

e Layer clouds formed by widespread irregular stirring of the air 
zenith angle varies with 

latitude, time, and season 

sun-earth distance 

. seasonally variable 

upper dust 

layer 

15-25 Km dry air 

0-30 Km 

ter vap~r 

d lower 

st layer 

3 Krn 

W.V. 3 to 

% Sunshine 

Figure 4.1 0-1 . Insolation model showing : solar flux outside the atmosphere, 

Io; absorption and scattering by various layers; the dlrect 

normal term at the earth's surface, ID,,,; and the downward 

scattered term. 
e Layer clouds formed by widespread regular assent of air 

e Cumuliform clouds formed by "penetrative convection" 

Strahler has classified clouds into families based on height and vertical 

development. He has suggested high clouds, in the region of 20,000 feet and 

above; middle clouds for 6,000 t6 20,000 feet; and low clouds below about 

6,000 feet. The types and examples of clouds are shown in Figure 4.9-2, which 

is obtained from Strahler (1963). The types of clouds typical to a given 

region vary with the time of year as well as location. In many of the northern 

regions the typical clouds are of the lower nimbo stratus type, while in the 

Albuquerque, New Mexico region a great deal of the cloudiness i s i n the form 

of cumulus clouds, particularly in the summer months. A fair amount of 

cirrus clouds can be present at some times of the year. The amount ot cirrus 

appears to be quite variable from year to year. 

The greatest emphasis in short term prediction should probably be placed 

relative to cumulus type of clouds which are of the fair weather nature. The 

clouds are broken up into small. cellular structures and account for periods 

when a significant amount of radiation is available that is interrupted for 

short periods of time. Insolation records at Albuquerque show that very 

frequently in summer afternoons this type of cloud pattern is present. The 

cumulus clouds start out as small sized structures, with dimensions in the 

order of meters, and can grow to dimensions of several kilometers. The initial 

phases are usually such that the horizontal extent of the cloud is larger than 

the vertical extent, but once a cell grows to the large cumulonimbus stage, 

its height is often several times the horizontal extent. 

The formation of cumulus clouds occurs with the upward motion of moist air 

into colder regions. Often at the same time some of the clouds are, 

dissipating as the air moves downward into warmer regions. It is important 

to note that clouds of this nature are not predictable on a simple horizontal 

motion of uniform cloud cell types. Careful observations of clouds indicate 

that on some days the changes of shading on a local basis are more influenced 
___ - - - -- - - - --- I.-T-- -- --- 

FAMILY ~HIGH-CLOUDS - '- . 

Halo ' Cirrostratus 

FAMILY B: MIDDLE CLOUDS 

VERTICAL 

FAMILY C: LOW CLOUDS 

Strameumuit~s 

Figure 4.10-2. Cloud Forms Classified by Height and Vertical 

Development, from A. N. Strahler, 1963 
by the growth and decay of individual clouds than by their horizontal motion. 

In view of this, it is important to note that short term predicting capability 

will require, in addition to horizontal wind speedland remote sensors, some 

indication of vertical motion of the air and temperature vs. height i.nformation. 

When the gross temperature decreases with increasing height greater than the dry 

adiabatic rate, there is a tendency for moist air to move upward and produce 

clouds. If the moist air moves up to a height where condensation occurs, the 

lapse rate will be significantly greater than the wet adiabitic rate, and a ' 

large cell ular bui ld-up usually occurs. 

Vertical wind speeds of up to 30 or more mph can occur, andcloud heights may 

extend from 5,000 to 50,000 feet, with horizontal extents of several miles for 

well developed cumulus clouds. 

Once a cloud is fairly well developed, then prediction is possibly by tracing 

its horizontal motion. On the other hand, during periods when only small 

cells are built up, a significant part of the prediction problem is determining 

when a cloud is likely to form or dissipate as opposed to a simple horizontal 

drift of the cloud. 

High level cirrus clouds are likely to move horizontally at a much higher rate 

due tothegreater wide speeds at high altitudes. The prediction of such clouds 

will likely be significantly different than for the cumulus type. In view of 

this, it is apparent that a determination of actual cloud height is important. 

ANTICIPATED CLOUD CHARACTERISTICS AT THE REEVES STATION 

One of the features of the A1 buquerque climate is the large number of clear 

days and resulting high percentage of sunshine. The average percentage of 

possible sunshine ranges from a low of 72 percent in December to a high of 

83 percent in June. The Reeves site, which is located in the Rio Grande River 

Valley north of the city of Albuquerque, Figure 4.10-3, is expected to have 

sunshine characteristics similar to that observed by the Weather Bureau at 

the airport. The gross motion of air is predominantly from the south in the 
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Figure 4.10-3. Locations of Reeves Plant and

Weather Service Site

4-320
summer months, with northwesterly winds in February and March. The normal 

surface wind velocities are in the order of 10 mph. The .local wind directions 

are variable enough that prediction sites will have to be spaced in most 

directions around the station to account for the changes in air flow. 

The presence of the Sandia Mountains to the east of the site can have some 

influence; however, in general the main pattern, particularly during the summer 

months when the flow of air is from the south, is one of a slow gradual rise 

as the air flows up the valley. A significant increase in cloudiness does not 

occur until one gets much closer to the mountains. For air motion from the 

east, some of the moisture is removed from the air as it flows over the 

Sandia Mountai~s. This can result in less cloud cover at the Reeves site with 

wind from the east. July and August are the months with the heaviest 

precipitation and the greatest number of partly cloudy days. This is caused 

by the flow of moist air from the Gulf of Mexico in the summer "monsoon 

season." During these months, the wind is largely from the south or southeast. 

A condensed view of the direct normal radiation observed for June 1962 is 

shown in Figure 4.10-4. On a number of days it is clear that there are ' '. ' 

numerous dropouts occurring in the afternoon. See, for example, June 1, 2, 

8, 10, 23, 24 and 29. These values shown are the 10 minute average values. I . -, . 

The original strip chart records show many more fades all the way to zero 

on these days. It appears that these fades result from a significant bui ld-up - . ,: " , ' :. 

of cumulus cloud forms in the afternoons. The dropout statistics are shown _I -. 

in Figure 4.10-5for periods of four hours in the afternoon for three different 

days. It is apparent that a large number of the fades are four minutes or 

shorter in duration. The surface wind velocity and direction are shown in 

the calculation for each of the days. The effective projected width of the 

clouds for the case of horizontal motion is We = t/v. 

For a median dropout time of 3 minutes (180 seconds) and an average wind 

speed of 6 knots (2.7 meterslsec) the median effective width for the days 

analyzed appears to be about 70 meters. The 20 minute dropouts could 
DIRECT NDRMRL 

SDLRR RRDlRTlON 

RLBUQUERE4UE 

WlTT CNG. LTD. 

Figure 4.1 0-4. Direct Normal Solar Radiation (A1 buquerque) 
6/8/62, 5 DROPOUTS/H I 

6/2/62, ? DROPOUTS/HR 

?UNE 

1 a 3 

HR CC W!ND CC WIND SC W'ND 

' 2 NW 5 

-3 4 NW 3 2 SW6 

14 1NE5 7s 8 4 MW4 

15 2 WNW5 7 ESE 5 4 SW 8 

16 3 NE 6 3 N4 

17 e~3 

CLQlJD LAYERS = ! FOR ALL BUT LAST 2 HRS 3F 612 

WIND SPEED IN KNOTS 

SI<Y COVER IN TENTHS 

2 4 6 1 [! 29 40 

LENGTH OF DROPOUTS, MlNUTES 

Figure 4.10-5. Dropout Length Distributions of Di rect Normal 

Insol ation at A1 buquerque, New Mexico, 

Dropout Level = 300 ~/m2 
result from a 500 meter effective width. It should be noted that the effective 

width is the actual width plus the height times the tangent of the sun's zenith 

angle. It is important to note that the formation and dissipation times of 

small cumulus clouds is often in the order of 5 to 15 minutes, so it is possible 

that the variations observed are not a17 associated with horizontal cloud 

motion. 

In any event, it appears desirable to examine carefully the cloud structures 

with due regard to the vertical, as well as horizontal, components of wind in 

determining the best type of prediction system to employ. 

lntermediate term variations of cloud cover can, in some cases, be predicted 

several days in advance with a fair degree of certainty. As an example, in 

April 1971, the weather patterns over the western U.S. are shown in Figure 4.10-6. 

The lower left-hand track, with dates of 2, 13, and 14 of April, show a storm 

starting out of the Gulf of Alaska and approaching the western U.S. with a 

swerve down to the California coast on the 14th. Cloud cover photos for the 

days of April 11 through 16 are shown in Figures 4.10-7 through 4.10-12. On the 

llth, the skies over Albuquerque were clear and bath the direct normal 

radiation values and total horizontal radiation values were high for that 

date, as shown in Table 4.10-1. 

TARLE 4.10-1 . UIHECT NORMAL ( LANGLEYSIMINUTE) AND 

TOTAL HORIZONTAL ( LANGLEYS/DAY) OBSERVED 

AT ALBUQUERQUE, NM, APRIL 1971 

Apri 1 

11 

12 

13 

14 

15 

16 

17 

1.17 

1.27 

1.1 clds 

1.06 clds 

Figure 4.1 0-7. Cloud Cover, 11 April 1971 
Ftgure 4.10-8. Cloud Cover, 12 April 1971 
Figure 4.10-9. Cloud Cover, 13 April 1971 
Figure 4.10-1 0. Cloud Cavsr, 14 April 1971 

Figure 4.10-12. Cloud Cover, 16 April 1971 
- 

* -~*--& - & -: 

On April 12,- if can be seen that the band of clouds is approaching the west 

coast of the U.S. and Albuquerque is still in the clear. On April 13, it is 

apparent that although the cyclone is dissipating, the cloud structure is 

11 

1 

still sweeping inland and approaching Albuquerque. By April 14, the cloud 

cover has reached Albuquerque. It can be seen in Table 4.10-1 that the direct 

normal values are missing for this date (this omission occurs on cloudy 

days) and that there is a significant decrease in the total horizontal 

radiation values. By the 15th, the cloud cover over the Albuquerque area is 

we1 1 established, and even the total horizontal value has dropped to a very 

low amount. By the 16th, the clouds are dissipating and the total horiz~ntal 

radiation is bdck to normal. There is some cloud cover in the area so that 

the direct normal reading at 60" zenithpangle was not available. By the 17th, 

the cloud cover has decreased to the point where direct values are again 

available. 

This type of frontal storm, which is typical of the winter and spring conditions, 

can be observed and prepared for with the aid of satellite information. This 

simple sweeping in of cloud cover does not always occur. In fact, during the 

sumer months an appreciably dif rerent pattern is observed. Clouds frequently 

disappear from storms moving in off the southern California coast due to the 

warm dry desert air. If enough moisture is carried along, they re-appear over 

the Rocky Mountains. A significantly different type of prediction method is 

required for this type of clo~ld cover. 

4.1 0.4 SHORT-TERM LOOK-AHEAD SYSTEMS 

There are a number of cases where it is believed that short term look-ahead 

systems will be feasible. Figure 4.10-13 shows a typical size heliostat field 

about 1 kilometer across, with two examples of clouds approaching. In case A, 

the large cumulonimbus clouds are shown as approaching from the ssuthwesd. If 

they are approaching at a vel~city of three meterst, per second, which corresponds 

to a wind of seven knots, the times of passage for radial inflor is shown. 

Since the lifetime of large clouds of this type will be in excess of 20 to 30 

minutes, it is possible to predict the degree of coverage and likelihood of 

encounter from each of the clouds shown which are approximately one kilometer 

across. 
Cumul onimbus clouds 

approaching from SW 

o P distance km 

b* *a 0. 6 

- Case B 

Small cumul us clouds 

Wind flow from SE 

- approximate time, minutes 

(based on v = 3 meterslsec) 

Figure 4.9-13. Plan View of a Heliostat Field Showing 2 Examples 

of Clouds Approaching the Site. 

4-333 
It becomes apparent that any simple vertical looking photoelectric system 

must be spaced at least two to four kilometers away from the station, and 

preferably some information should be received from sites as far as six to 

eight km away. It can also be seen that the horizontal resolution must be 

significant to keep the number of observing sites to a reasonable value. At 

a six km distance, if the horizontaL detection capability is limited to one km, 

there would be a requirement for about 18 stations. This would not give 

sufficient resolution to determine whether or not a particular cloud would, 

in fact, cross the site, and it would be necessary to have an additional set 

of stations at a distance of two km from the field center. 

Next, consider case By with small cumulus clouds having widths in the order 

of 50 to several hundred meters. It is apparent that a simple vertical looking 

station or ring of stations is not likely to be of much value. In addition, 

when it is noted that the lifetime of the small cumulus clouds is frequently 

in the order of 5 to 15 minutes, it is obvious that any attempt to track small 

clouds at distances in excess of one to two km from the site will be of little 

value under most conditions. 

It soon becomes apparent that an ideal look-ahead system should present a view 

with the heliostat fie Id iri the cer~ler* and showing clouds for a distance of 

out to eight km. It is possible that a presentation to four or five km will 

be of great value in short term prediction. One possible approach would be 

to have a scanning all sky type camera Lu dcter-mine the location of clouds 

around the station. If the scarlner i s i n the form of a 1 idar or some 

similar device, the actual height and distance can be determined. 

SYSTEM LAYOUTS 

A desirable look-ahead system will provide a visual presentation of clouds 

and their IIIUL ions, inclding direction, speed, and height information for 

a distance of several km from the heliostat field. It is believed that a 

system could be constructed around a mini computer which would'take the 

optical data and present it in visual form, as well as provide alerting 

information based on logic built into..the computer. A measure of the ~~~~~~~~e 
content of the air above the station is also desirable in that increasing 

values would aid in alerting to the onset of condensation and the growth 

locally of clouds over the he1 iostat field. 

INSTRUMENTATION 

There will be a need for several types of instruments including local wind 

velocity, air temperature, humidity, absolute moisture content, and optical 

scanning systems. These instrumental inputs would then be employed, with 

suitable computer software, to arrive at both a visual presentation and alerting 

system for the look-ahead system. At this time, it is difficult to estimate 

the best mix of instruments to employ or to arrive at the cost of the system. 

It may, however, be possible to give some very rough order of magnitude guesses 

which should be subsequently modified after a more detailed analysis is carried 

out of the look-ahead problem. 

4.10.5 INTERMEDIATE TERM LOOK-AHEAD SYSTEMS 

The intermediate term look-ahead systems would likely be.based about the existing 

satellite pictures and other prediction methods used by the Weather Bureau and 

other predictors. This type of system will rely on trained personnel and 

methodology development, rather than in instrumentation. 

4.10.6 LONG RANGE LOOK-AHEAD SYSTEMS 

It is known that climatic change often follows general trends, with some 

variation in the annual patterns. Year to year variations can also be 

anticipated. Initially, the emphasis will be on analyzinq past changes and 

then alle~i~ptlng to determine what the driving forces were that caused the 

variations observed. Again, the major cost would be in the research effort 

i nvol ved, as opposed to instrumentation. 

The order of magnitude costs can perhaps be qrrived at by ass-iyriing three 

subtotals; one for basic weather and optical instrumentation at $20,000 to 

$50,000, a PDP 11 type computer with extra storage, at $25,000 to $35,000, 
and system design and integration at $50,000 to $75,000. It should be 

emphasized that there can be a wide range of costs, depending on the degree 

of system complexity. lnitially it may be possible to start with some of the 

inputs from a nearby weather station and relatively simple optical systems 

to determine the type of prediction reliability attainable. 
5.0 UNIT ECONOMIC ANALYSIS 

This section presents the detailed economic analysis of the solar repowered 

Reeves No. 2 Unit operating on the PNM system. The analysis is based on the 

conceptual design of the repowered unit described in Section 4.0. The 

methodology used to perform the analysis is discussed in Section 2.5. The 

analysis described herein is similar to the analysis performed in Section 2.5 

except that the following changes have been incorporated: 

a Reference plant description has heen revised consistent with 

the conceptual design presented in Section 4.0 

a The insolation data base has been updated consistent with the 

1978 version of the Aerospace tapes for Albuquerque, New Mexico 

a The PNM system description has been revised to reflect the 

July 1978 plan for future power generation capability 

a The economic scenario has been modified to approximate PNM 

system changes 

a The cost of the repowered plant has been revised consistent 

with the data presented in Section 4.7 

The intent of the analysis presented is to realistically assess the economics 

of the "first" repowered plant using present cost data for a limited production 

level for the solar hardware. The results therefore are not indicative of the 

ecnnomic potential of solar repowering but rather only of the economics of the 

"first demonstration" plant; the economic potential of solar repowering was 

presented in Section 2.5. 

This section of the report includes a brief description of the unit, a discusslon sf the economic basis for the analysis, a description of the PNM 

system, and the results of the analysis. 
5.1 UNIT DESCRIPTION 

A reference solar hybrid repowered plant concept has been established for the 

Reeves Unit No. 2 for the purpose of performing the unit economic analysis. 

The reference plant concept for Reeves Unit No. 2 is based on the conceptual 

design presented in Section 4.0 and utilizes the solar hardware and technology 

being developed for the 10 MWe solar-central receiver pilot plant to be built 

near Barstow, California. Table 5.1-1 summarizes the characteristics of the 

reference Reeves Unit No. 2.. The capita.1 cost data are given in Section 4.7. 

The solar subsystem has been sized to provide 25 MWe (50 percent repowering) 

2 at 2 P.M. winter solstice based on an insolation level of 950 watts/m . The 

fol 1 owing changes were incorporated in the Reference Plant description described 

in Section 2.5 to yield the model summarized in Table 5.1-1 for Reeves UnitNo.2: 

e Solar subsysten~ was revised consistent with the conceptual design 

presented in section 4.0 

Net plant efficiencies were revised based on the heat balance 

caiculations for'the Reeves Unit No. 2 

0 Part load performance of the turbine generator was revised 

consistent with Reeves Unit No. 2 data 

a The port and full load efficiency of the fossil boiler was 

revised to represent the Reeves Unit No. 2 boiler data 

The solar system design is characterized by an external receiver mounted on a 

tower, and located in a 360' array of two ax.is sun-tracking he1 i0st.at.s which 

comprise the collector subsystem. Feedwater from the electrical power generation subsystem is pumped through a riser to the receiver and converted to 

superheated s.Ltiarn in a single pass through the tubes of the receiver panels. 

The steam from the receiver is routed through a downcomer to ground level and 

transported from the tower base to the turbine through horizontal steam lines. 

The collector field has been sized to provide for 50% repvwerlng of the 

50 MWe fossil plant and is comprised of 4086 heliostats having a total mirror 

2 2 area of 155,268 m . The 950 Watts/m insolation level assumed for sizing the 

collector fields is representative of 2 P.M. winter solstice conditions; the 

design point for the solar repowering project being used by PNM. 
TABLE 5.1-1. REFERENCE REEVES UNIT NO. 2 PLANT PARAMETER SUMMARY 

Plant Type Steam TurbineINon-Reheat 

Plant Rating 50 MWe (25 MWe Solar) 

e Plant Repowering Percentage* 50% 

e Plant Operating Scenario Maximize solar benefit 

Fossil operation - full time, part 

time, and only on cloudy days 

Economic dispatch fossil energy 

e Col 1 ector Subsystem 

- Field Configuration 360" 

- Ficld Area I30 Acres 

- Heliostat Area 155,268 m2 

- Number of Heliostats 4086 

e ReceiverITower Subsystem 

- Receiver Type External (single pass to superheat) 

- Tower Height 150 M 

e Electric Power Generati on 

Subsystem. 

- Cycle Steam Ranki ne 

- Net Plant Efficiency 33.5% Solar, 34.7% Fossil 

- Turbine Inlet 95O0F/125O psi 

- Heat Rejection Wet Cooling Tower 

e Fossil Boiler 

- Type Oi 1 

- Rated Load Efficiency 8G% 

- Start Up Warm 

*Based on an insolation level of 950 Watts/M 2 
The a b i l i t y t o operate on fossil fuel has been maintained in the repowered 

plant concept. The plant can therefore operate and produce 50 MWe using 

steam generated from the fossil boiler or a combination of both fossil and 

solar. It is assumed that the plant will always operate on fossil only or a 

combination of solar and fossil produced steam during cloudy days - a cloudy 

day for the purpose of the unit economic analyses is defined as a day during 

which the sky cover exceeds 0.5 for two or more consecutive hours (see Section 

2.5). 

The operation scenario assumed for the fossil boiler is important in determining 

the economic benefit of solar hybrid repowering. Two different scenarios were 

analyzed as discussed in Section 5.4. In order for the fossil boiler to be 

capable of responding to insolation variations during periods of intermittent 

cloud cover, the boiler must be operating at a minimum of approximately 25 

percent of rated thermal output. The boiler response time to achieve 100 percent 

rated output from an operating level of 25 percent of rated output is approximately 10 to 15 minutes. 

During those periods of the day when the plant is operating from solar generated 

steam, the fossil boiler is maintained in the warm standby condition for one 

of the scenarios analyzed. The other scenario assumes the tossil boller is 

providing steam to produce 25 MWe. 

At the end of the day, however, the boiler is "banked" ar~d maintained in a 

warm standby condition overnight. The boiler is also "banked" during days 

when it is not economica l to operate the plant from either solar or foszi 1 

energy. In order to account for scheduled and forced plant outages throughout 

the year, three "cold" starts uF the boiler have been included in the unit 

economic analysi5. 
5.2 ECONOMIC BASIS 

For the Task 1400 analysis, the economic assumptions were adjusted to a set of 

parameters provided by Public Service Company of New Mexico, whereas in Task 1100 

the base economic assumptions were EPRI RP 648-1 (see Tables 5.2-1 and 5.2-2). 

Among the new parameters were those reflected by the design study results for 

the repowering of Reeves Unit No. 2. The revised plant characteristics were 

discussed in the previous section (5.1) and include a smaller collector area, 

revised boiler efficiency curves, higher repowering cost and different operating 

and maintenance cost assumptions. 

Regarding the higher capital cost assumptions, it is important to note that the 

Task 1400 results reflect demonstration plant cost assumptions, whereas with 

Task 1100 DOE heliostat goal costs.were used assuming commercial penetration. 

The repowering direct cost for 25 MWe solar capacity in the demonstration phase 

(Task 1400) was assumed to be 82.8M$ (1978), where in Task 1100 the commercial 

direct cost for 25 MWe was 25.2M$. The operating and maintenance costs produced 

in Task 1400 were derived from separately estimated fixed and variable costs. 

In Task 1100 a simple percentage of the repowering capitalization was used for 

the tota1,of fixed and variable 0 and M. 

The fuel costs, excalation rates and other assumptions were changed from Task 

1100 to 1400 as shown in Table 5.2-1. Three fuel escalation scenarios were 

investigated as will be described in Section 5.4. 

Sev~ral changes wcrc made affec L i r~g the capacity credit cal cul ations . One was 

that the credit was taken effective in 1997 representing the anticipated retirement date of the Reeves No. 2 plant, rather than the prior assumption of 1995. 

Per Public Service of New Mexico expansion studies, the capacity displacement 

used in this task was 25 MWe of pumped storage hydro rather than $0 MWe of peaking 

(combustion-turbine) plants. Other changes are shown in Tab1 e 5.2-1 . 
TABLE .5.2-1. TASK 1400 ASSUMPTION CHANGES 

REPOWERED PLANT CHARACTERISTICS 

e Col lector Area - Smaller 

Boiler Efficiency - Flatter 

0 Repowering Cost - Higher 

0 Solar O&M - Variable and Higher 

ECONOMIC ASSUMPTIONS 

1400 -- 1100 

e Level ized Fixed Charge Rate 14.6% v s 18% 

0 Oil Escalation Rates 7%, 15.5% vs . 12% 

0 Other Fuel Escalation kates 7% vs: 10% 

0 O&M Escalation Rates 7% vs 8% 

0 Base Fuel Costs (See Table 5.2-2) 

0 Capital Escalation Rate 7 % v s 10% 

' 

CAPACITY CREDIT 

Reduced MWe Credit 25 MWe VS 50 MWe 

e Different Unit Discplacement P.S. Hydro vs Pkg. 

m Different Year 1997 vs 1995 

Different $/kWe (1985) 67 5 v s 300 

0 Fixed Charge Rate (%) 14.6 . vs 2 0 r 

OPERATING STRATEGY 

e 1982 - 84 25 MWe Fossil All times 

e 1985 - 86' 25 MWe Fossil 50% Time 

Warm Start Operat ion 
#2 Oil 

#6 Oil 

Coal 

Nuclear 

TABLE 5.2-2 Fuel Cost Assumptions ($/MBTU) 

TASK 1400 TASK 1100 

*Oil escalated at 15.5%/year from 1977 to 1985, 

other fuels escalated at 7%. 
For the Task 1400 analysis, detailed modelling of the operation of the 

repowered plant and the PNM system was performed for several discrete years, 

beginning in 1981. The penalty for the loss of the Reeves No. 2 unit during 

repowering was estimated. Also, the operating strategy was varied from year to 

year, requiring 25 MWe of fossil firing any time the solar side was being used 

in years 1982-1984, and requiring the same operating strategy 50 percent of the 

time in the years 1985-1986. Beyond.1986 the repowered plant was allowed to 

operate in the most economical mode. In Task 1100, economic mode operation 

was assumed throughout the 1 ife of 'the plant. Also in Task 1100, 1985 plant 

introd11ct.inn was assumed. For Task 1400, a detailed PNM expansion plan for 

conventional generati on was used. 

The methodology developed by Westinghouse for EPRI under study RP 648-1 was used 

for the analysis in Task 1400 as well as 1100. However; in this task much more 

detailed simulation was utilized. 
5.3 PNM SYSTEM DESCRIPTION 

The detailed analysis reported in this section was performed based on a model of 

the Public Service Company of New Mexico system. As reported in Section 2, this 

is a summer peaking system with a moderate nuclear/coal base (see Figure 2.5-1). 

In the years from 1982 through 1987, most of the capacity additions were in the 

form of nuclear and coal plants with a pumped storage hydro facility being added 

toward the end of that period. The 1985 peak demand was estimated to be around 

An example of the fuel displaced by the repowered plant, for economic operation 

in 1985, is shown .in Table 5.3-1. Because the repowered plant operates on 

weekends and during low load seasons of the year, it displaces energy generated 

by coal as well as oil plants, as shown in the table. During these periods, 

the repowered plant is still more economical to operate than the competing coal 

. . 

plants because of the minimal solar operating cost. 

TABLE 5.3-1. CONVENTIONAL ENERGY DISPLACEMENT 

Til3 k 11 00 Me Lt1udo1 ogy 

(1985 Instal lation) 

Plant % Energy X $ 

Type Displaced Value 

Coal 2 3 15 
5.4 RESULTS 

Several analyses were performed in this task using the methods and assumptions 

previously described. Sensitivities were performed on several critical parameters as shown in Table 5.4-1. These include oil escalation rate, repowered 

plant life, repowering cost and alternate methods of analysis. The latter 

sensitivity was to use the methods used in 1100 with the 1400 assumptions to 

compare with the more detailed 1400 analysis. 

The results given in this section will be presented primarily in 1978 dollars 

as opposed to the 1985 dollars used in Section 2.5. 

The impact of varying the repowering capital cost is shown in Table 5.4-2. 

This table shows the reference given in Section 5.1 and a deviation of plus and 

minus 25 percent. The cost numbers shown are the present worth of the revenue 

requirements to support the repowering investment. A 30-year repowered life 

is assumed. 

Three different fuel escalation scenarios were evaluated. For each of the 

scenarios, fuels other than oil were escalated at 7 percent per year. For .the 

first scenario oil was also escalated at 7 percent. For the second scenario 

oil was escalated at 15.5 percent per year from 1977 to 1985, and then at 

7 percent from 1985 on. The third scenario assumed a 15.5 percent escalation 

rate for oil from 1977 through the life of lhe repowered plant. The results 

are given in Table 5.4-3. 

Even though the oil escalation rate is changed significantly, the cost/benefit 

is altered only slightly. The change in cost/benefit will not be significant as 

long as the oil displaced by the repowered plant is approximately equal tn that 

cons~~med. With the 15.5 percent oil escalation rate the nature of the present 

worth calc~rlation emphasizes t.he latter years of plant operation. During these 

years the oil displaced by the repowered plant is slightly smaller than that 

consumed. Therefore, the fuel cost increases more than the fuel savings, resulting in a slightly smaller overall plant value. In the 15.517 percent case the 

early years of plant operation are emphasized, again due to the nature of the 
TABLE 5.4-1. TASK 1400 CASES 

FUEL ESCALATION RATES 

0 Oil - 7% Post 1977 

e Oil - 15.5% Post 1977 

e Oil - 15.5% 1977-85, 7% 1985- 

REPOWERED PLANT LIFE EXPECTANCY 

o 30 Years Post Repowering 

e 20 Years Post Repowering 

9 15 Years Post Repowering 

REPOWERING COST 

0 Reference 

o Reference + 25% 

o Reference - 25% 

ALTERNATE METHODS OF ANALYSIS 

e Detailed Annual , 1981 - 

0 Detai led 1985, Projections 
TABLE 5.4-2. COST/VALUE VS REPOWERING CAPITAL COST 

30 Year, 7% Escalation, 1978 M$ 

(Present Worth of Revenue Requirements) 

-25% Ref +25% 

Solar Plant Cost 

STC Plant Cost 

STC Plant O&M 

STC Total 

Solar Plant Value 

Fuel Value 

Variable O&M 

STC Fuel Cost 

Capacity Credit 

Total Value 

Net Value 
TABLE 5.4-3. COSTIVALUE VS FUEL OIL ESCALATION RATE 

30 Year, 1978 M$ 

(Present Worth of Revenue Requirements) 

Solar Plant Cost 

STC Plant Cost 124.8 124.8 124.8 

STC Plant O&M 5.9 5.9 5.9 

STC Total Cost 130.7 130.7 1 30.7 

Solar Plant Value 

Fuel Value 16.9 23.3 33.2 

Variable O&M 1.7 1.7 1.7 

STC Fuel Cost -8.4 -14.4 -24.9 

Capacity Credit 5.7 5.7 5.7 

Total Value 15.9 16.3 15.7 

Net Value -1 14.8 -114.4 -1 15 .O 
present worth calculations. However, during these years the repowered plant 

displaces more oil than it consumes, resulting in a slightly higher total value. 

This change in net oil savings is due to the significant amount of coal added in 

the latter years. I n a l l cases investigated, the combined savings in coal and 

oil justified the oil consumed by the solar repowered plant. 

The sensitivity of cost and value to repowered plant life is given in Table 5.4-4. 

Life expectancies of 15, 20, and 30 years past repowering were investigated. A 

strong incentive to assure substantial plant life is. seen. 

The detailed methodology used in Task 1400 is compared with that used in Task 

1100, in Tab'le 5.4-5. The 1400 methodology ass~~med heginning operation in 1982 

with phasing in of the economic dispatch mode. The 1100 methodology assumed 1985 

operation with immediate economic dispatch. This difference in operating niode 

during the early years of plant life is one of the reasons why the 100 methodology produced a better cost/benefit. The capacity credit differs between the 

two methodologies because the number of years of capacity displacement are 

different. There are 18 years of capacity displacement in the 1100 methodology 

and only 15 years in the 1400. 

For comparison with the repowering cost assumptions used in Task 1100, -the same 

capital cost basis was used (DOE heliostat goal) and the cost/benefit calculated 

using the detailed model i ing from Task 1400. A comparison of results using the 

demonstration (1 400) and commercial (1 100) cost assumption is shown in Table 

5.4-6. The substantial difference in the repowered plant cost is the reason 

for the significant change in cost/benefit. In the commercial/DOE goal cost 

assumption, the repowered plant O&M was assumed to be the same a< that. revised 

for Task 1400. Both plant values reflect restrained operation in the early 

years of plant 1 ife. 

Again, one should be conscious of the fact that the repowering costs used in the 

Task 1400 analysis were based on a first demonstration plant, and that economic 

dispatch was restrained for the first few years. 
TABLE 5.4-4. COST/VALUE VS REPOWERED PLANT LIFE 

7% Escalation, 1978 M$ 

(Present Worth of Revenue Requirements) 

30 Yr 20 Yr 15 Yr 

Solar Plant Cost 

STC Plant Cost 124.8 119.6 109.4 

STC Plant O&M 5.9 4.7 3.8 

STC Total Cost 130.7 124.3 113.2 

Solar Plant Value 

Fuel Value 16.9 14.1 12.2 

Variable O&M 1.7 1.3 1 .O 

STC Fuel Cost -8.4 -7.5 -6.9 

Capacity Credi t 5.7 2.9 0.0 

Total Value 15.9 10.8 6.3 

Net Value 114.8 113.5 -106.9 
TABLE 5.4-5. COST/VALUE VS METHODOLOGY 

30 Year, 7% Escalation, 1978 M$ 

(Present Worth of Revenue Requirements) 

Solar Plant Cost 

STC Plant Cost 

STC Plant O&M 

STC Total 

Solar Plant Value 

Fuel Value 

Variable O&M 

STC Fuel Cost 

Capacity Credit 

Total Value 

Net Value 

Cos t/Benef i t 

Task 1400 Task 1100 
TABLE 5.4-6. COST/VALUE VS PLANT COST 

30 Year, 7% Escalation, 1978 M$ 

(Present Worth of Revenue Requirements) 

Solar Plant Cost 

STC Plant Cost 

STC Plant O&M 

STC Total Cost 

Snlar Plant Va111e 

Fuel Value 

Variable O&M 

STC Fuel Cost 

Capacity Credit 

Total Value 

Net Value 

Demonstration Commercial/DOE Goal 
The work performed and results from this task point to the necessity for detailed 

model1 ing of the specific power system (utility) involved to determine the impact 

of sol ar repoweri ng . 
6.0 PROGRAM PLANNING, FUTURE PHASES 

The results of the market survey of southwestern utilities (Section 2.0) indicate that a large.potentia1 market exists for the solar hybrid repowering 

concept if the approach can be successfully demonstrated and proven to be 

economically attractive. Likewise, the cost/benefi t analysis results (Section 2 .O) 

have indicated that the solar hybrid repowering concept has the potential to be 

economically attractive for utility applications when compared with conventional 

methods of electric power generation. PNM therefore believes that a timely demonstration of the solar hybrid repowering concept is mandatory to the acceptance 

and future commercialization of solar energy within the utility industry. In 

addition, PNM believes che demonstration can ultimately provide the stimulation 

needed for solar energy to enhance the conservation of our dwindling oil and 

natural gas reserves to reduce our nation's severe foreign oil dependence, achieve 

the earliest commercialization of solar components as well as to introduce earliest 

direct utility participation in commercializing solar energy, extend the life and 

use of existing generation equipment, utilize present generation sites wherever 

adjacent land is avai lab1 e, reduce fossil fuel emissions at existing sites , improve 

present generation mix, determine hybrid operating principles, and minimize backup 

requirements for early solar thermal electric plants. 

The program plan presented in this section to implement the factors noted above 

includes the objective, project and major task description, the management plan 

and work breakdown structure. 

The program plan is structured to provide appropriate visibility and control 

of all technical effort, schedules and costs. It utilizes the Work Breakdown 

Structure approach and anticipates control documents, such as design requirements and interface control drawings,to assure a successful demonstration 

of the solar hybrid repowering concept. It recognizes and accommodates the 

acquisition, analysis and reporting o f - d a t a v i t a l to the repowering program. 
6.1 OBJECTIVE 

The principal objective is to establish the technical viability and economic 

attractiveness of the solar hybrid repowering concept and widespread utility 

application. The specific objectives are: 

Preparation of the detailedMdesign of the solar repowered plant. 

Construction of the solar repowered plant. 

Successful start-up and operation of the solar repowered plant 

for a period of two years., with five years optional. 

Timely dissemination of the progress and the results of the 

program to other utilities, industries, and government agencies 

to enhance the early commercialization of solar repowering. 
6.2 PROJECT AND MAJOR TASK DESCRIPTION 

The program to implement the solar hybrid repowering concept is divided into 

six principal phases: These phases are: 

Phase 1 - Technical/Economic Assessment 

Phase 2 - Design 

Phase 3 - Procurement 

Phase .4 - Construction 

Phase 5 - Checkout 

Phase 6 - Operation 

Figure 6.2-1 presents the schedule for the proposed program. 

The Phase 1 portion of the program is completed with the issuance of this 

final report; the following output will be available to initiate the 

Phase 2 Design: 

A market survey and cost/benefit analysis. 

A specific site selected for the ~nlarepnwering program. 

o A conceptual design of the solar repowered unit. 

A cost estimate for the unit. 

Phase 2 through Phase 5 are scheduled over a 42 month period. A two year operating period (Phase 6) is also planned, the option for DOE to continue the operations 

period for a longer time period sho1.11r-I he reevaluated once successful operation of 

the unit has been achieved. 

The foundation of the proposed program is Phase 2, Design. The solar repowering 

system for Unit No. 2, located at Reeves Station, will be designed, fabricated and 

constructed on the basis of the central receiver technology. Major components such 
MONTHS 

. - .- --- - . .. - .. . . - -- 

- 4 6 

. . . . . - . . - . -- . .. .- . - . - . - - . -- .-. . -- -. . - . . - . . - . . - - . . -- - - 8 10 12 14 -6 18 20 22 24 26 28 30 32 34 36 38 40 42 

..I L-,.I...-.-L .--- L .--. 1 ..-.!--I_ ..--.! L___L___I..lI1l.lI--.., 

DETAILED STUDIES & ENGliif Eir;ll$t.; 

~~~~@~~~~@~j~;@~~g~&[;;~:~~~~ 

PLANT EQUIPMENT PROCUlGErVIENT 

~~~&~@~4&3@x~@~~~@fi~~~2@&<&~@92~~~&2~~~@@&@~~ 

t-IELIOS-'AT' PHOCUF'\ENiENl' 

~~@&~~&&<,~;~~;~;~g;$r&~j~;$~&;~&~&~~;~@@c@

SOLAR Fi ECE,I'lEE PROCUREMENT 

~~~&@~~~<@;~~~~~$~~~~~~~~;~~@~~-- - 

FAC5LIT'Y CONSTRUCTION & EQ.UIF'MEMT ERECTION 

B@ - &@~j~~~@~~$~~f~<~~~~~~$~~~~~j@~~~@@~~@

TURBINE MODIF 

SBLAR R%PQ'@f RL@<G 

REEVES STATION UNiT #2 

-. 

PLFlt4NING SCtQEDUl..E 

~igure 6.2-1. Detail4 Schedule for Solar Hybrid Repowering Program 
as the heliostat system, the receiver system, and potentially the master ) control system will have been operationally demonstrated to varying degrees 

of maturity as part of the solar central receiver 10 MWe Pilot Plant Program. 

Successful and timely accomplishment of project objectives requires detailed 

technical and programmatic coordination during the project and, in particular, 

during Phase 2 Design. A project management organization will, therefore be 

established at?project initiation to provide necessary technical and programmatic 

coordination. 

. Early in the first quarter of the first year, the Project Plan, which i,ncludes 

the Work Breakdown Structure (WBS) will be finalized and submitted to DOE for 

approval. The Pro,ject Plan will be updatedlrevised during the performance of 

the project. As a minimum, the plan will be updated at the end of preliminary 

engineering prior to the start of construction and prior to unit checkout. 

PNM will secure use of the required adjacent land for the life of the project 

during Phase 2. The necessary plans, including site preparation and site access 

will be formulated. PNM is measuring the direct normal insulation and other 

climatological data at the site; this is being performed as a portion of the 

West Solar Resource Data Evaluation Project. This effort will be continued and 

it is further planned that all data collected will be transferred to the SERI 

data bank for utilization and integration into that program. 

The preliminary design for the solar subsysten:, the master control subsystem, 

the modifications to the existing plant equipment, and support facilities is 

to be prepared during Phase 2; this effort will require coordination with the 

DOE, 10 MWe Pilot Plant design teams throughout this project, particularly during 

preparation of a preliminary design document. Two preliminary design reviews are 

contemplated during Phase 2 to afford DOE maximum project visibility. Specifications parameters for the plant equipment and support facilities will be defined 

durirry Phclse 2. 
A unit layout will be prepared based on the conceptual design resulting from 

the Phase 1 Assessment. The preliminary design requirements for the plant and 

support facilities will be defined. A preliminary system design will be prepared 

from which design specifications for the component hardware can be formulated. 

An interface control drawing will be maintained throughout the project and will 

be modified to incorporate mandatory plant design changes. 

An environmental assessment will be made within the scope of Phase 2. Furthermore, 

during Phase 2, all aspects of the solar plant designs and development data of 

the 10 MWe Pilot Plant will be considered. The findings at this review will be 

utilized in the selection of components and systems for the design of the precommercial unit. 

Phase 3 will commence with the preparation of specifications for the solar subsystem, the master control subsystem, the modification to the existing plant 

equipment, and the support facilities. 

Procurement will be initiated early to allow for long lead times. Activities 

will include vendor surveys, bid-package preparation, vendor selection, purchasing, 

expediting, inspecting, and quality assurance. Special attention will be given 

to the procurement of potentially long lead items such as heliostats, receiver 

and control system components. 

Phase 4 encompasses the construction which could start as early as May 1979. A 

detailed construction schedule for Phase 4 will be prepared to cover the solar 

subsystem, the master control subsystem, the modifications to existing plant. 

equipment and support facilities. Principal items of work will be incorporated 

in this schedule. Additional charts will be prepared, as considered necessary, 

to schedule the construction of particular areas in greater detail. 

Phase 5.involving checkout of the unit and all support subsystems, is scheduled 

to occur during the first two quarters of the fourth year. The solar subsystems 

will be checked out during this time. The unit startup tests will be performed 

during the fourth quarter of the fourth year. 
The repowered unit, although intended to operate as an on-line power unit in 

the PNM system, is a first-of-a-kind system. In formulating this program plan, 

therefore, a number of tests have been identified which encompass the regime 

from component and subsystem operation verification to unit checkout and test 

and to normal and emergency operating performance tests. A test plan will be 

prepared with appropriate revisions being incorporated as required during subsequent phases. The test plan will include: 

e Startup tests and checkout 

e Acceptance tests for the solar subsystem 

e Data acquisition system validation 

e Steady state and transient performance tests 

Phase 6 Operation will be defined in detail during Phase 2 of the program. 

However, the operation task of the program has been considered in sufficient 

detail to permit base estimates of manpower requirements to summarize the 

effort needed during the initial phases. It is currently envisioned that the 

utility operations would be studied by PNM and DOE for approximately two years. 

Personnel for the operation and'maintenance crews will be selected, utilizing 

a thorough screening and testing process. The test engineering team, a 

necessary requirement during the operations task, wi 11 be selected from 

personnel having extensive backgrounds in the startup and testing of a 

first-of-a-kind power plant. Training of supporting PNM personnel wi 11 be 

an objective of the team effort. 

The operation, maintenance, and testing crews will be given thorough training 

and testing during the startup task in preparation for their responsibilities. 

The actual equipment manuals will be used by the operators in the preparation 

for checkout as well as plant operation, and maintenance crews will work with 

the construction, installation and erection crews as components and subsystems 

are completed and operated in their respective checkout modes. Hence, as 
larger subsystems are made operational and until the total pilot plant has been 

carried through the checkout and startup mode, the operation crew will be assuming 

greater responsibility and acquiring full familiarity wi th their assignments. 

Pertinent data will have been generated during the startup and checkout 

activities and these data will be recorded, analyzed and reported. Technology \ 

transfer, Public Relations, and other like functions assisting and promoting 

the commercialization efforts are also included. 

HELIOSTAT MARKETING PRODUCTION SCHEDULE 

Utilily rqesponse to the survey presented in Section 2.0 indicates a definite 

interest in snlar hybrid repoweriny of existing power plants. Section 2.0 

further defines this interest to show that 82 units corresponding to 

approximately 5189 MWe (< -200 MWe unit size) are considered as candidates for 

solar repowering efforts. Heliostat production capability must be developed to 

a1 low accompl ishment of such an endeavor. The approximate level of he1 i~stat 

production required to achieve solar repowering within a ten year time frane (1983 

to 1990) has therefore been determined. Due to unique plant site constraints 

and criteria, approximations and assumptions must be introduced into any heliostat 

production 1 eve1 number, 

The baseline for the number of helinstats required per MWc is derived from Ltie 

equinox noon insolation heliostat requirement for thc 100 MWe Commercial Plant. 

Solar multiples for thermal storage capability have been removed to provide 

a net of approximately 13,500 he1 iostats for 100 MWe (net). Naturally, other 

plants may be desiqned for either winter or summer solstice. 

In such cases, heliostat quantities may vary considerably. Solar insolation 

available at each plant site and solar field optimization studies may also 

have an impact on the Sevelized heliostat production requirement. Figure 6.3-2 

indicates the approximate heliostat quantities per MWe (net) that could be 

2 experienced based on an insolation level of 950 W/m . 
NO. OF 

COLLECTORS 

MWe (NET) 

Figure 6.2-2. Number of Collectors vs. Power Output 
YEAR 

100.000 

90,000 

Fi gure 6..2-3,. Average Annual He1 iostat Production Range 

(Based on Solar Hybrid Repowering of 5189 MWe in Ten Years) 

. 

NOTE: THERMAL STORAGE REQUIREMENTS WOULD 

INCREASE THE NUMBER OF HELICSTATS 

REQUIRED. 

ANNUAL 

HELIOSTAT 

I 

80.000 

70.000 

or 

I 

d 

0 

60,000 

50,000 

c=j 

R0,000 HELIOSTATS PER YEAR) 

1987 1988 1989 1990 

I 

1980 

1-

i 981 1982 1984 1985 

I 

1983 

1 

1986 
Efficiencies of the larger plants (%I00 MWe) can be considered higher than ) those in the lower MWe ranges. These efficiency variations have been 

accounted for in the range of average annual heliostat production shown in 

Figure 6.2-3. 

Productivity of heliostat installation will be determined by such considerations 

as plant location, labor availability, local weather conditions during construction, etc. Applying an arbitrary productivity factor to heliostat installation time produces the curve "Estimated Productivity Adjusted Line" shown 

in Figure 6.2-4. 

The MDAC Preliminary Report for the 100 MWe Commercial Plant optimized onsite 

heliostat assembly at 60 per day. The values in Figure 6.2-5 were determined 

using the 60 heliostat per day per plant site capability to estimate time 

durations for the 82 units. The figure is not an attempt to schedule particular 

plants for solar repowering, but an indication of quantities of engineering 

and construction starts per year to fully utilize the levelized heliostat yearly 

production. 

An average annual he1 iostat production 1 eve1 of between 70,000 to 80 $1 00 could 

be anticipated in order to accomplish solar repowering of 82 units representing 

approximately 5189. MWe. 

Thermal storage capability, unique efficiencies that vary with plant site and 

operating characteri stics, locale, and local solar insolation levels will vary 

heliostat requirements and consequently have an impact on the annual heliostat 

production level. Productivity for smaller unit he1 iostat instal lation would 

not be anticipated to be as high as for the larger units; it will also vary 

by locale. 

With an annual heliostat production of 80,100 and single plant unit installation capability of 60 heliostats per day, five different sites could be 

simultaneously under construction for solar repowering. Figure 6.2-5 tends 

to indicate a heliostat production dropoff in the tenth year. The variables 

previously mentioned would tend to increase the tenth year production by 

increasing either installation time or heliostat quantities per unit. 
0 10 20 40 50 60 70 80 90 100 

PLANT SIZE (MW~) 

Figure 6.2-4. Helkostat Installation Time vs Plant Size 
Figure '6.2-5. Heliostat Instal lation 

Durations 

r I 

UTILITY 

PARTICIPANT COUPICIL 

PFlf.1 KEY I1ANAGElriEFU' 

PERSOGNEL 

LAR HYCRID REPOWERIN12 r So I 

APi D 1 I TECINiICAL MANAGER 

PROJECT t4ANAGER 

I 

r'-l PNY HOST UTILITY 

A/E SERVICES 

SY STEP! EEIVGIF.IEEF!ING/ 

PPOJECT INTEGRATION 

Figure 6.3-1. .OVERALL PROGRAM ORGANIZATION 
The Project Manager also will be supported by a system engineering firm who will 

be responsible for the system engineering and project integration which will 

include the system design and integration, the solar system design coordination, 

technical inputs to the master control and data acquisition system design, the 

turbine generator and turbine generator control system design modification, the 

performance of impact assessments inoding safety, operational, and network, the 

test engineering in support of the unit operation, and the project integration 

including maintaining the work breakdown structure. 

It is suggested that to effectively accomplish the program a cooperative 

agreement be executed between PNM and DOE for the direction of the project. 

A Solar Project Operating Committee (SPOC) will be formulated as part of the 

cooperative agreement to.assist the PNM Project Manager in his direction of 

the project. Membership of the SPOC will consist of key management personnel 

from PNM. The SPOC is responsible for the overall project as a joint DOEutility endeavor in accordance with the terms of the contract. It .is the 

executive decision-making authority for a1 l matters not specifically del.egated 

and entrusted to the PNM Project Manager. The committee, in addition to its 

role to direct, advise, and counsel, represents the project administratively 

to other fur~ctional elements of PNM. The committee is the decision-making 

authority for the project on a91 matters referred to It, Includiny those 

which cut across functjonal or departmental lines. The Operating Committee 

will receive periodic reports from the Project Manager and will regularly 

review project progress. 

A number of utilities will participate in an advisory capacity to PNM as part 

of the utility council. PNM recognizes that one of the most important objectives of the project is the timely dissemination of the progress and results 

of the project to the utilities committed to the solar repowering program. 

The direct participation by the utilities in the project will assure that 

the required technical expertise within the utility industry exists in order 

to achieve an agressive fossil fuel displacement goal. In addition, direct 

utility participation, particularly during the engineering stage, is mandatory 

to ensure that the design of the repowered unit does not restrict its 

applicability to other utility systems. 
Major functions of program management are: 

0 Program Plan 

Work Initiation 

e Monitoring of Project Progress 

Variance (from Plan) Resolution 

Reporting (to DOE) 

These principal elements of successful program management are performed in 

accordance with the logic illustrated in Figure 6.3-2. The Program Plan 

provides definition of the program effort in detail in the Work Breakdown 

Structure. This, along with the schedules and budgets for these subtasks, 

will provide a consistent set of directions for all program participants. 

There also will be related technical direction and control documents that 

are important parts of the planning element. These include the Design 

Requi rements , which translate the contractual requi rements into design 

directives, and the Interface Control Drawings, which define the physical 

and other.interre1ationships between subsystem responsibilities. These 

also become control documents and are updated, as required, as the 

proceeds. 

'The monitoring effort by PNM will encompass management reviews at each subcontractor organization, analysis of technical progress against the Program. 

Plan and Design Requirements to identify any variance, and cost/schedule 

analysis against the Program Plan milestones and budgets. The results of the 

monitoring activities will be provided to the Project Managers. 

The results of the monitoring activity will be reviewed at Project Manager 

review meetings. In addition to a project status review, the Project 

Managers will take action to resolve ttie delinquent items.' in the event 

that the needed corrective action impacts the contract requirements, schedule 

or budget; the recommended change will be subrrritted to DOE. On receipt of 
PLANNING 

Figure 6.3-2. Program Management and Control Logic 

I 

CONTRACTUAL 

REQUIREMENTS 

A 

b 

UPDATE OF 

PLAN & ICD L r r 

J 

> 

I DOE 

r 2 

PROJECT PLAN 

WBS 

SCHEDULES 

BUDGETS 

b 

b 

I APPROVAL 

DESIGN 

REQUIREMENTS ) 

4 

SUBCONTRACTS 

J 

INTER FACE 

- 

SUBSYSTEM DESIGN 

REQUIREMENTS 

CONTROL DRAWING ORDERS 

CHANGE 

RECOMMENDATIONS 

- 

' 

VARIANCE RESOLUTION MONITORING 

* - r 

WORK 

I h 

4 , 

PROJECT MANAGER 

REVIEWS 

ORGANIZATIONAL 

L 

PROJECT REVIEWS + 

A 

4 

CHANGE 

CONTROL 

L 

* 

, 

I 

I

MONTHLY REPORTS 

I 

VAR IANCE 

ANALYSES 

I 

r 

COSTISCHEDULE 

ANALYSES t 
DOE approval, the Program Plan and other affected control document's will be 

updated and the change will be implemented. 

6.3.1 WORK BREAKDOWN STRUCTURE 

A prel iminary Work Breakdown Structure (WBS) developed on a subsystem basis is 

provided in Tables 6.3-1 and' 6.3-2 to define the content of the Solar Hybrid 

Repowering Program. PNM has overall responsibility for all work performed as 

previously indicated in the project organization. 

6.3.2 PROGRAM PLAN 

PNM will prepare a Program Plan reflecting the contractual commitments as 

negotiated. The Program Plan wili consist of the management plan, the 

work breakdown structure, the schedule and milestone chart, and the cost 

schedules, and manpower control plan. The Plan will be submitted to DOE 

within 45 days after contract initiation. When approved by DOE, the Plan 

will be utilized as a "controlled document" under which the project will be 

executed. The Plan will be updated, as required, through the procedure 

described in Subsection 6.3.5. The Plan will define the,Work Breakdown 

Structure, schedules and milestones, and budgets for each level two WBS 

tasks. Further detai 1 breakdowns into manageable work packages (levels 

three and four) will be implemented for internal management and control of 

the work. 

SCHEDULE 

Thc pro'jcct schedule is presented ill Section 6.2. A further breakdown of schedules 

and milestones will be prepared, as necessary, for use in managing and controlling 

the program. PNM will hold periodic review meetings consisting of discussions of 

the program status re1 ative to achieving the milestones , the technical status 

including the resolution of interface problems, and a detailed review of the 

technical work completed. In addition, the PNM Project Manager will hold project 

rcview meetings as required to vesulve major Issues impacting the milestone 

schedule. 
TABLE 6.3-1. WORK BREAKDOWN STRUCTURE OUTLINE 

11 SOLAR COLLECTORS 

11 1 Engi neeri ng 

11 121 1 General 

11 121 15001 Prel iminary Design of C o l l e c t o r s 

111221 Heliostat Equipment 

11 1221 $001 Prepare Specs 

11 1221 5002 Equipment Selection 

1 11 221 5003 Procurement 

11 1222 He1 iostat Controls 

11 12223001 Prepare Specs 

1112225002 Equipment Selection 

111223 Heliostat Foundations/Pedestal 

11 12235001 Detai 1 Design 

1112235002 Prepare Specs 

1112235003 Procurement 

11 2 Construction 

11 2221 He1 iostat Equi pment 

112221D001 Fabrication and Installation 

112222 Heliostat Controls and Power 

112222F001 Electrical 

11 2222N001 Instrumentation 

112223 Heliostat Foundations/Pedestal 

11 2223A001 Earthwork 

11 2223B001 Concrete 

11 2223COQ1 Steel 

112241 Quality Assurance 

11 2241 H001 Qua1 i ty Assurance 
12 RECEIVER 

121 Engineering 

121 21 1 General 

12121 15001 Prel iminary Design CF Receiver 

121 21 15002 Prel imi nary Design of Tower 

121 221 Engineering - Receiver 

121 221 5001 Prepare Spec 

121 221 5002 Equipment Sel ection 

121 221 5003 Procurement 

121 224 Engineering Tower 

121 2245001 Detai 1 Design 

121 2243002 Prepare Spec 

121 2245003 Equipment Sel ection 

121 2245004 Procurement 

121 225 Engineering - Piping and Pipe Rack 

1212255001 Detail Design 

121 2255002 Prepare Spec 

121 2255003 Equi pment Sel ection 

121 2255004 Procurement 

121226 Engineering - Auxiliary Equipment 

121 2265001 Detai 1 Design 

121 2265002 Equipment Selection 

121 2265004 Procurement 

122 Construction 

122222 Receiver 

122222C001 Structural Steel 

122222D001 Equipment 

122222E001 Pi ping 

122222G001 Painting 

' 122224 Tower 

'1 22224A001 .Earthwork 

1222240001 Concrete 

122224C001 Steel 

122224C002 Elevator 

122224E001 Main Streairi Pi ping 
122224E002 Feedwater Pi ping 

122224E003 Other Pi ping 

122224F001 Electrical 

122224G001 Painting 

122226 Auxi 1 iary Equipment 

122226001 Auxiliary Equipment 

122241 Qual i ty Assurance 

122241 H001 Qual i ty Assurance 

13 THERMAL STORAGE 

131 Engineering 

131211 General 

131 21 15001 ~rel imi nary Design CF System 

131 221 Thermal Storage Equipment 

131 221 5001 Prepare Specs 

131 221 5002 Equipment Selection 

131 221 5003 Procurement 

132 Construction 

132221 Thermal Storage Unit 

Earthwork 

Concrete 

Steel 

Equi pment 

pi ping 

Electrical 

Painting 

Instruments 

Insulation 

132241 Qual i ty Assurance 

'I 32231 H001 Qual i ty Assurance 

132251 Checkuut 

132251 MOO1 Checkout 
14 CONTROLS AND INSTRUMENTS 

141 Engineering 

141 21 1 General 

141 21 15001 Prel imi nary Design of Control Systems 

1412115002 Preliminary Design of Instrumentation 

141 22851 Control System' 

1412285101 Master Control Computer - Design & Prepare Specs 

1412285102 Data Acquisition System - Design & Prepare Specs 

141 22851 03 Analog System .Design and Prepare Specs 

1412285104 Interface Logic System Design and Prepare Specs 

141 22851 05 Control Systems Procurement 

1422852 Instrumentation 

1412285201 Control Panel - Design and Prepare Specs 

1412285202 Turbine Control System - Design & Prepare Specs 

1412285203 Annunciator - Design and Prepare Specs 

1412285204 Boiler Combustion Controls - Design & Prepare Specs 

1412285205 Other Instrumentation - Design and Prepare Specs 

142 Construction 

14228 Installation of Controls and Instrumentation 

142228N001 Control Systems Installation 

142228N002 Instrumentation Installation and Hookup 

142241 Quality Assurance 

142241H001 Quality Assurance 

142251 Checkout 

15 BALANCE OF PLANT 

151 Engineering Balance of Plant 

151212 Systems Engineering 

151 21 251 01 Prepare Functional Design Requirements 

151 21 231 02 Prepare System Desiqn Specs 

15121 23202 Prepare Integrated Plant Layout 

151 21 25203 Prepare Interface Control Drawings 

151 21 25204 Prepare Overall System Flow Diagram 

1512125301 Perform Systems Studies and Transient Analysis 
Perform Re1 iabil i ty Studies 

Perform Transient Analysis 

Prepare Design Plans 

Prepare Quality Assurance Plans 

Prepare Procurement and Construction Plans 

Prepare Plant Checkout Plan 

Data Acquisition Plan 

Prepare Operations Test Plan 

151213 Site Engineering 

Permi ts and Approval s 

Prepare Site Preparation Plan 

Prepare Faci 1 i ty Plan 

Prepare Pub1 i c Awareness Plan 

Periodic Review and Update of Plan 

Prepare Site Specs 

Prepare Faci 1 i ty Specs 

Facility Design 

Prepare Test Plan to Acquire Site Data 

Perform Tests 

Analyze and Report Data 

EstablishIMaintain Site Data Bank 

Site Data Dissemination 

Site Data Preparation 

Perform Environmental Assessment 

Prepare Impact Statement 

152 Construction Balance of Plant 

152229 Demolition 

1 SZZ~U Mod1 tications to txi sting btructures and tquipment 

152230F001 Electrical 

152230F002 Relocate Transmission Lines 

152231 New Work 

Earthwork-Site Grading 

Earthwork-Underground Diversion 

Earthwork-Roadways and Fence 

Concrete 

Buildings 

Warehouse 

Equipment 

P i p i n g 

Electrical 

Painting 
152251 Checkout 

152251M001 Checkout 

16 ELECTRICAL POWER GENERATION SYSTEM 

161 Engi neeri ng 

161214 Prel iminary System Design 

161 2.145001 Prepare Design Requirements 

161 2145002 Prepare Prel iminary Design of Existing System 

16121 5 System Design and Modification 

1612155001 Detail Design 

161 21 55002 Prepare Specs 

161 21 55003 Equipment Sel ection 

161 21 55004 Procurement 

167 21 6 Component Design 

1612165001 Mechanical 

161 21 65002 Electrical 

161 21 6J003 Civi 1 /Structural 

161 21 65004 Pi pi ng/Instrument Design 

161 21 65005 Control System Design 

161 21 65006 Procurement 

162 Construction 

162229 Demo1 i tion , 

162229T001 Demol i tion 

162230 Modifications to Existing Structures and Equipment 

162231 New Work 

Earthwork 

Concrete 

Buildings and Structures 

Process Equipment 

Pi ping 

Electrical 

Painting 

Plant I tems 

Instru~iientation 

Insulation 

i 62ZSIUUU1 tarthwork 

162231 BOO1 Concrete 
Buildings and Structures 

Equi pment 

Main Steam Piping 

Feedwater Pi ping 

Other Pi ping 

Electrical 

Painting 

Plant I tem 

Instrument&tion 

Insulation 

162241 Qual i ty Assurance 

162241 H001 Qual i ty Assurance 

162251 Checkout 

162251M001 Checkout 

17 DISTRIBUTABLES 

173 Field 

17300 Indirect Expense 

173700H001 Field Expense 

173700H002 All Risk Insurance Payroll Tax, Bond 

1737UOKUUl Construction Supplies 

173700S001 Temporary Faci 1 i ti es 

173900 Escalation, Contingency, Contractor ' s Fee 

173900Y001 Escalation 

173900Y002 Contingency 

173900Y003 Construction, Contractor's Fee/C&A 

176 Management 

176771 Administration 

176771 5001 Project Management 

176771 5002 Cost/Schedul e Control 

1767715003 Engineering Change Control 

176772 Pl anni ng 

1761 7725001 WBS Extension Kevi ew and Upgrade 

176773 Reporting 

1767735001 Technical Reports 

1767735002 Financial Reports 

1767735003 Topical Reports 
176774 Overall Quality Control 

1767745001 Design Review 

1767745002 Meetings and Reviews 

176775 Other Expenses 

1767755001 Travel 

1767755002 Communications 

1767753003 Reproductions 

1767755004 Computer 

1767755005 Postage 

1767755006 Other Expenses 

176976 Fees 

176776Y001 Participants' Fees/G&A 

176976Y002 Engineering Fees/G&A 

176976Y003 Consultants' Fees/G&A 

18 PLANT OPERATION Ar4D MAINTENANCE 

184 Operation and Maintenance 

184081 Opera t i ng Crew 

184081 0001 Define Requirements 

1840810002 Operating Crew Cost Estimates 

184081 0003 Crcw Sel cction 

184081 0004 Crew Training Manuals 

184081 0005 Crew raining 

184082 Manual s 

1840820001 Operating Plan and Manual 

1840820002 Maintenance Plan and Manual 

184083 Operation 

1840830001 Total Plant Checkout and Startup 

1840830002 Operations - Test and Power . 

1840830003 Operational Analysis and Reporting 

184084 Spare Parts 

. ,184085 Special Eqlli prnent 

1840850001 He1 iostat Wash Truck 
'.* ' 

TABLE 6.3-2. EXPLANATION OF ACCOUNT NUMBER SYSTEM 

Level tli 124 t- 3-4 141 154 base4 

Position 

Task 

Sequence 

Numbers 

Secondary 

Subsystems 

Sequence 

Numbers 

ABC 

Designation 

(See Page 6) 

Subsystem 

Number 

(See Page 5) 

FPC 

Number 

(See Page 4) 

Ma j or 

Cat cgory 

Designation 

(See Page 3) 

Major 

Systems 

Number 

(See Page 2) 

Solar 

Repowering 

Project No. 
C-20266 Xl5100 

PSCNM 

Major Systems Number (Position 2): 

1 Solar Collectors 

2 Receiver 

3 Thermal Storage 

4 Master Control and Data Acquisition System 

5 Balance of Plant 

6 EPGS 

7 Distributables 

8 Plant Operations and Maintenance 

Page 2 of 6 
C-20266 Xl5100 

PSCNM . 

Major Category Designation (Position 3): 

0 Dummy 

1 Engineering 

2 Construction 

3 Distributables 

4 Operations 

5 Land 

6 Managerment 

, '. : 

Page 3 of 6 
C-20266 X15100 

PSCNM 

FPC Number (Position 4) : 

0 D-Y 

1 Structures and Improvements 

2 Process Equipment 

7 Indirect Costs 

9 Escalation, Contingency and Fee 

Page 4 of 6 
C-20266 ~15100 

PSCNM Page .5 of 6 

Subsystem Numbers (Positions 5 & 6): 

0 0 DU~Y 

11 General Engineering 

12 System Engineering 

13 Site Engineering 

14 Preliminary System Design 

15 System Design & Modification 

16 Component Design 

Major Equipment 

Controls 

Foundat ions 

Tower 

~iser/Downcomer 

~ther/~uxiliary Equipment 

Steel 

Master Control & Data Acquisition System 

Demolition 

Modification 

New Work 

41 Quality Assurance 

61 Distributables 

71 Administration 

7 2 Planning 

7 3 Reporting 

7 4 Overall Quality Control 

7 5 Other Expenses 

7 6 Fees 

81 Operating Crew 

8 2 Manuals 

83 Operat ion 

8 4 Spare Parts 

85 Special Equipment 
ABC Designation (Position 7): 

Earthwork 

Concrete 

Buildings & Structures 

Process Equipment 

Piping 

Electrical 

Painting 

Field Expense 

Engineering 

Construction Supplies 

Plant Items 

Startup 

Instruments & Controls 

Ii'l9ila t ion 

Sales Taxes 

Premium Pay 

Temporary Facilities 

Demolition 

Spare Parts 

Craft Personnel - Maintenance Cost 

Construction Equipment 

Extras 

Additional Expense 

Page 6 of 6 
6.3.3 REPORTING 

PNM will provide to DOE monthly reports on the technical and financial status 

of the project. The first report will be provided within 60 days of contract 

initiation. The format of these reports will include: 

e A cover page designating the contract, the contract numbe,r, and 

the period covered by the r'eport. 

A brief statement of the contract content. 

A summary of technical progress during the report period. 

An update of the schedule and milestone chart. 

A discussion of any anticipated problems along with a summary 

of action for their resolution. 

o A financial tabulation comparing cost to budget for each of the 

nine WBS tasks. 

PNM will also provide topical reports as may be required to document significant project accomplishments. In addition, PNM will provide a report 

summarizing the results of each of the major tasks as well as a final report 

discussing the overall accomplishments of the programs. 

6.3.4 BUDGETARY COST ESTIMATE 

A budgetary cost estimate has been developed as a subtask of the Technical and 

Economic Assessment of Solar Hybrid Repowering. It encompasses the detailed 

engineering design, procurement, construction and test operation of a solar 

hybrid precommercial unit at Keeves Unit No. 2. The cost estimate is based upon 

the conceptual design cost estimate discussed in Section 4.0. It was assumed 

the most desirable presentation of data for DOE planning purposes was to reflect 

costs in terms of annual cash flow. 

Cash flow data were determined by PNM for archi tectlengineer functions, project 

engineering, system integration and utility management. The budgetary cost 

estimate was developed in 1978 constant dollars, therefore, these values may be 

escalated as deemed appropriate by the reader. No contingency values were 

assumed in addition to the overall project costs; this cost estimate is assumed 
to be of plus or minus 25 percent accuracy, a nominal conceptual design value. 

It was assumed that an October 1, 1978 start date would be appropriate for the 

study as the current assessment phase ends on September 30. It was also assumed 

that an approximate two-year test/opera,tion period occurs in the 1982 through 

1983 time frame. PNM operation and maintenance costs were accounted for in this 

period. AFUDC was not accounted for, nor was escalation during construction. 

Figure 6.3-3 presents the anticipated cumulative cash flow as a function of time; 

the cash flow, as a function of time, is presented in Figure 6.3-4, The approximate dollar value associated with the precommercial unit at the conceptual design 

stage is $88,533,000. The assumptions above should be noted when utilizing this 

value for budgetary planning purposes. 

6.3.5 FINANCIAL INCENTIVES 

Financia.1 incentives can produce economic favoratism for utility deployment of 

one generation alternative versus others. It appeared appropriate to address 

this in a cursory fashion to indicate the potential impact of a strong and weak 

incentive with respect to solar hybrid repowering. . 

An analysis was performed to determine the impact of two different tax incentive 

measures. The first involved a shortened tax write-off period, from 28 to 

15 years, and the second assumed an increase in the investment tax credit rate 

from 10 percent to 20 percent for the repowered plant. 

The results of this analysis are shown in Table 6.3-3. The effects of these 

tax incentives are to decrease the effective levelized fixed charge rates. Using 

as a reference the case shown in Table 2.5-8, the impacts upon fixed charge rate, 

revenue- requirements associated with plant capital cost, and resulting cost/ 

benefit ratios are shown. 

As would be anticipated, the investment tax credit is a much more effective 

incentive approach. To achieve the benefits shown, the assumption is that the 

utility is in a position to take full advantage of the tax credit. That is,' if 

the utility had other tax write-offs adequate to reduce its tax obligation for 

the year to zero, then the additional tax credit would be of less benefit. 
CUMULATIVE CASH FLOW VS. BlME 

7 979 3 980 198'8 1982 '8 983 1984 

CALENDAR YEAR 

Figure 6.3-3. Anticipated Cumulative Cash Flow as a Function of Time 
CASH FLOW VS. TIME 

Figure 6.3-4. Cash Flow as a Function of Time 
TABLE 6.3-3. TAX INCENTIVE ANALYSIS 

1. 15 Year vs 28 Year Tax Wri te-Off 

2. 20% vs 10% Investment Tax Credit 

Impacts : 

Level i zed Present Worth Cost/ 

Case Fixed Charge Rate RP Plant Cost Benef i t 

Ref. 1 8% 126.8 M$ 7.5 

*Provided the utility can utilize the credit in the year the 

plant is put into service. 

The basis for the calculation^ shown are fundamental tax fnrmula developed by 

Paul H. Jeynes in his book on revenue requirements entitled, "Profitability and 

Economic Choice."* The specific formula used was an extension to this which 

reflects normalized accounting prnced~~r~s 8,nd variations in tax life,** The 

precise capitalization and accounting assumptions used were defined by PNM. 

*Paul H. Jeynes, Profitability and Economic Choice, Iowa State University 

Press, Ames, Iowa, 1968. 

**J.T. Day and T.A. Ochs, Economics Correspondence Course, Westinghouse 

Electric Corporation, East Pittsburgh, Pennsylvania, 1972. 
APPENDIX A 

PNM SOLAR HYBRID REPOWERING 

PROJECT QUESTIONNAI.RE' 

D.J. Groves, Pub1 ic Service Company of New Mexico (PNM) 

Letter to. Distribution (78 Utilities), "PNM Solar Hybrid 

Repowering Project Questionnaire," November 11 & 14, 1977 
PUBLIC SERVICE CDPIIPANY CF NEM/ MEXICO 

Post Offlce Box 2267 :Albuquerque. New Mex~co 87103 

November 11, 1977 

Nr. Eric R. Weber 

Research Programs 

Arizona Public Service ~ompdny 

Post Office Box 21666 

Phoenix, AZ 85036 

Dear Mr. Weber: 

Subject: PNM Solar FIybtid Repawering Project Questionnaire 

Initial study efforts for the PNM Solar Hybrid Repowering Project are 

underway. Tte shdy will identify, from a utility point of view, if a 

cost-effective approach =ists to tepower existing steam or combustian 

turbine units with solar energy systems to reduce or supplant natural 

gas and/or oil boiler firing. Your utility is similar to PNM in that 

you utilize natural gas and/or oil for part of your electric generation. 

These fuels are increasing substantially ia price and may be of questionable availability within your system as they are within PNM's. 

The concept 6f.solar repowering existing units might be accomplished to 

extend their operating life to a maximum, while greatly reducing future 

fossil fuel consumption. It will also help meet the legislative and 

administrative goal of conserving scarce natural resources, while potentially adding stability to your cost of power generation by reducing the 

5mpact of the oil/natural gas fuel cnmpnneat in rout aeet bast, 

The prh item whtch will enable PNM to assess the possible market and 

the impact on fuel consumption in the South and Southwest is the enciosed 

utility questionnaire. This is being sent to many utilities in order to 

obtain the most complete, up-to-dare information available. It has been 

reviewed many times and simplified primarfly to a checklist to reduce 

your efforts to sapply the information needed. 

In order to make this important study of maximum value, not. only to all 

utilities, but your individual system, we urge your completion and 

return of the questionnaire before December 16, 1977, Note that additional pages 2 and 3 are enclosed if you have mere than tllrre units :hat 

are applicable. This will be the oaly request for information for the 
Public Service Company of New Mexico 

Nr. Eric R. Weber -2- November 11, 1977 

study required from you by PNM. Please complete and return the form in 

the enclosed, stamped envelope. Should you have any questions on the 

content of the questionnaire, or other matters related to the project, 

please phone at (505) 842- 2606. 

Thak you in advance for your timely response. 

Very truly yours, 

=5q$&..'' 

D. 'J . roves 

Project Coordinator 

Solar Hybrid Reparering 

DJG:dj 

Encf osures 
PQ! SOLAR HY2RID REPOWERING PXOJECT 

UTILITY QUESTIOMJAIRE 

1. Utility Name: 

2. Name, Title, and Address of contact an solar energy in your company 

- if different than addressee: 

3. Has your utility considered the possibility of solar power generation 

as a future alternative? 

YES - 

4. Would your company be interested in participating in a solar hybrid 

plant program if financial incentives made it equivalent or superior 

to existing generation alternatives? 

YES - NO - 

5. Do you have any plans or interest in repowering any units of.200 

MWe or less? 

6. What is your approximate generation mix? 

Oil/Natural 

Gas - Coal Nuclear 

7. khen is your sysra peak? 

Summer Winter 

8. What are your availability requirements? 

Peaking Intermediate 
Data on units less than 200 PNe: 

B. Size, MWe: Nameplate 

Rated 

CHECK ONE OF THE FOLLOWING FOR EACH Im: 

C. Turbine Type: 

SteamlReheat 

Steam/No Reheat 

Combustion 

Combined Cycle 

D. Turbine Inlet Temperature: 

E. Turbine Inlet Pressure 

150 - 300 psi 

301 - 600 psi 

601 - 900 psi 

901+ psi 

F. Year Built 

before - 1941 

1941 - 1950 

1951 - 1960 

1961 - 1970 

1971+ 

G. General Unit Condition: 

New 

Good 

Fair 

Poor 

H. Current Use 

2ase 

Intermediate 

Peak 

Standby 
I. Estimated Retirement 

J. General Plant Locatiog 

Industrial 

Suburban 

Urban 

Rural 

K. Solar repowering would require adjacent land area near your plant(s) 

for the collector. field. Based on a requirement of six acres of 

land per.ilWe, we estimate there is sufficient vacant area near the 

plant for solar repowering this percent of'the unit: 

L. Estimated closest distance from ~it to land parcels noted in Item 

(K) above: 

0 - 1000 ft. 

lon7, - 25n0 ft. 

2501 - 5000 ft. 

5001 ft. + --.-....-. 

M. Geueral comments concemidg solar hybrid repowering, if any: 
9. Data on units less than 200 We: 

B. Size, We: Nameplate 

Rated 

CHECK ONE OF TEE FOLLOWLUG FOR MCH ITLY: 

C. Turbine Type: 

Steam/Reheat 

Steam/No Reheat ' 

Cembus.tion 

Combined Cycle 

D. Turbine Inlet Temperature: 

E. Turbine. Inlet Pressure 

150 -. 300. psi 

301 - 600 psi 

601 - 900 psi 

901+ psi 

F. Year Built 

before - 1941 

1941 - 1950 

1951 - 1960 

1961 - 1970 

1971+ 

G. General Unit Condition: 

New 

Good 

Fair 

Poor 

8. Current Use 

Base 

Intermediate 

Peak 

S Landby 
I. Estimated Retirement 

J. General Plant '~ocatioa 

Industrial 

Suburban - 

Urban 

Rural . 

IC. Solar repowering would require adjacent land area near your plant(s) 

for the collector field. Based on a requirement of six acres of 

land per LW~, we estimate there is sufficient vacant area near the 

plant for solar repowering this percent of the unit: 

L. Estimated closest distance from unit to land parcels noted in Item 

(K). above: 

0 - 1000 ft. 

1001 - 2500 ft. . .- 

2501 - 5000 ft. 

5001 ft. + 

Y. General comments concerning solar hybrid regowering, if any: 
APPENDIX B 

A methodology developed by the Westinghouse Advanced Systems Technology Division 

in the performance of EPRI RP-648-1, "Requirements Definition and Impact Analysis 

of Solar Thermal Power Plants," was applied to the analysis required in this 

study. The appl icabl e aspects included: 

A general methodology framework for assessment of solar-thermal 

electric plants 

A specific economic calculation methodology 

e A process for modeling the interdependent operation of a solar 

plant and the balance of the utility system 

0 A procedure for reserve margin analysis that includes the 

vagaries of solar plants 

A method for solar plant penetration analysis as the utility 

system grows 

The methodology includes a system of computer models and economic procedures 

specifically integrated to perform solar plant concept assessment and economic 

impact analysis. The framework of the specific methods employed involves the 

following sequence of analysis (see Figure B-1) : 

Develop hourly projections for year and utility system of 

interest 

Simulate the operation of conventional units on utility system 

for that year, producing incremental operating cost tables 

0 Use incremental cost tables, hourly system loads, and hourly 

insolation to dispatch solar plant, subtracting solar plant 

electrical output from the load 

0 Use hourly load reduction to calculate solar plant capacity 

credit and conventional capacity displacement 

0 Resimulate operation of conventional generating units with 

reduced system load 
MODEL USAGE FLOW 

HlStorlc3l Load 

(Ease Case) I I I I 

'1 Model lnsqlat~on 1 

1 

Inc. Coslr'l I 

4 Modified hcad I I 

I 

Load Srat~s:ical 

Analysls 

9alance of 

System 

Capacity Credit 

Aeliabil~ty 

I 

I 

I 

Fuel I 

Costs I 

I 

Oetailed 

1 , ,,J ?roduct~on Cost 

Operating Costs 

Fuel Consumpt~on 

Figure B-1 . Model Usage Flow 
e Use economic procedures to calculate resulting solar plant 

value 

This framework allows the evaluation of a variety of solar plant concepts and 

configurations, in different operating and insolation environments . It a1 so 

provides a vehicle for assessing the value of either a single solar plant or a 

number of them, independent of their cost projection. 

These procedures were developed using conventional utility planning methods and 

tools as much as possible. This serves to enhance the ease of interpretation of 

results for those familiar with'utility planning procedures and provides a level 

of confidence through the use of established, tested methods. 

B .1 ECONOMIC METHODS 

The economic methods developed use conventional Revenue Requirements analysis, 

recognizing both the time value of money and independent escalation of varjous 

cost elements. These methods are consistent with electric utility practice 

and provide the needed flexibility. The Revenue Requirements methodology is 

also consistent with the EPRI economic evaluation guidelines stipulated in the 

August 1977 EPRI "Technical Assessment Guide."* 

The principal economic measures of solar plants implemented in this methodology c 

are as follows: 

The value of the solar plant 

Solar plant busbar energy cost 

Net economic impact upon utility 

e Costlbenefit of the solar plant 

Because of the uncertainty of the costs of certain portions of the solar plant, 

particularly under mass production conditions, it was deemed important to 'assess 

the economic value of the solar ~lant independent o f i t s costs. The value arises 

"Technical Assessment Guide, Prepared by Electric Power Research Institute, 

June 1977. 
potentially from both operating cost and capital cost savings to the balance of 

the utility system. The operating cost savings are derived from reductions in 

fuel consumption and variable operating and maintenance costs. The capital cost 

savings arise from reduced conventional capacity requirements and a potential 

shift in the mix of conventional units. The busbar energy costs, which are consistent with ERDAIEPRI guidelines, are a function of solar plant cost and 

e l e c t r i c energy production. 

The net economic impact of a solar plant upon a utility system is calculated by 

simply subtracting the solar plant value from its estimated costs. 

The costlbenefit ratio is calculated by dividing the present worth of solar plant 

1 ifetime costs (revenue requirements) by the ,present worth of its 1 ifetime value. 

The handling of the following areas is fundamental to the evaluations: 

0 Revenue requirement components 

Time value of money 

Escalation of different costs 

The concept of revenue requirements includes cost components to support the 

capital investment and other expenses, which in this case are primarily operating costs. The concept may apply to a single project or to an entire system 

made up of many projects. 

The revenue requirements to support the capital investment are primarily as 

fol.1 ows : 

Adequate return on the investment to cover the cost of capital 

(similar to interest on money borrowed) " 

e Recovery of the amount invested (depreciation) 

Income taxes required 

0 Othcr taxcs 

Insurance 
The annual revenue requirements for the above can usually be expressed as a 

percentage of the capitalized investment. 

Additional revenue requirements for a generating plant are other expenses, which 

are primarily as follows: 

e Fuel costs 

e Maintenance costs 

e Other operating costs 

These expenses are usually not expressed as a percentage of capitalized investment, and may escalate independently. For purposes of this analysis, operating 

costs and maintenance costs are lumped together as operating and maintenance 

costs . I 

The methods and the indices used provided an excellent basis for the economic 

analysis required in this study. An example analysis showing the various 

criteria is shown in Table B-1, a reproduction of the computer case analysis 

summary output. 

B.2 ELECTRIC UT1,LITY SYSTEM MODELING 

Two principal aspects of the potential impact of solar repowered plants upon 

utility systems required detailed modeling of the conventional generating capacity on the system. These two aspects are: 1) operational impact; and 

2) reliability and/or capacity credit impact. 

As shown in Figure B-1, the modeling of the operation of the utility system with 

and without the presence of the solar plant establ ishes the fuel savings and 

operating credit of the solar plant. For this purpose, the Westinghouse Detailed 

Production Cost Model was used to establish base-case (non-solar) utility system 

operating costs and other operating parameters, and for the balance-of-system 

simulation in cases including solar plant(s). It is an established computer 

program that simulates the operation of a utility system by performing economic 

dispatch on a bi-hourly basis. Minor modifications have been implemented to 
TABLE B-1. EXAMPLE HYBRID ANALYSIS SUMMARY COMPUTER PRINTOUT 

-100 MW SOLAR HYBRID PLANT COLD START 

-SOLAR PLANT VALUE AND COST TABLE ECONOMICS B METHOD 2 

PRESENT WORTH OF REVENUE REQUIREMENTS 1985 MILLIONS 

Solar Plant Cost 

STC Plant Cost 

STC Plant O&M 

STC Total Cost 

Solar Plant Value 

6 Fuel Value 

Variable O&M 

STC Fuel Cost 

0 Capacity Credit 

Total Value 

Net Value 

Cos t/Benef i t 

Breakeven $/kW 1985 

Breakeven $/kW 1977 

Plant Cost $/kW 1977 

STC Energy GWHlyr 

Capacity Factor 

Energy Cost mills/kWhr 

Capacity Displ~ccrncnt Tab1 es 

Peaking 

0 Interrriediate 

Base Loaded 

TOTAL 

L 0 REF HI 

Megawatts Value RR 

64.0 34.6 

9.0 8.9 

27 .O 68.4 

100.0 111.9 
enhance communication with the solar model. This program contains the ability 

to represent various forms of hydroelectric generation and external system 

interchanges as well as fossil and nuclear plants. 

The use of such a program that utilizes daily load cycle information facilities 

impact analysis associated with daily, as well as seasonal, insolation correlations. It also allows examination of the impact upon the daily operating 

strategies of conventional units. Spinning reserve representation and explicit 

i~~aititenance schedules are also part of this model. 

A partial list of the inputs and outputs for the Detailed Production Costing is 

as follows: 

e Input 

- Loadlenergy data 

- Unit availabilit.ies 

- Unit incremental heat rates 

- Unit fuel and startup costs 

- Unit capacities (minimum and maximum) 

- Unit operating and maintenan'ce costs 

- Pondage and pumped storage hydro energy 

- Pumped storage hydro cycle efficiency 

- System spinning reserve policy 

- System interchange limits 

- Unit transmission penalty factors 

Output 

- Amounts of fuels consumed by unit 

- Total fuel costs by unit 

- Total operating costs by unit 

- Energy generated by unit 

- Number of starts by unit 

- S.ystem interchange energy and costs 

- System fuel consumption 

- Sys Len) gei~e~%d ted ei'lergy 

- sys'tem total operating cost 
- System generation by fuel class and station 

- By-hourly loads 

For reliability analysis, special modeling procedures have been developed by 

Westinghouse to handle insolation as well as equipment outages. However, with 

a solar repowered plant, the non-solar side of the plant can be called upon at , 

the will of the system operator. Therefore, for reliability analysis, solar 

repowered plants are subject only to equipment-related outages and can be 

treated much the same as conventional plants. 

To translate the capacity credit to dollars is more complicated in that generally 

a repowered plant will not operate purely as a peaking, intermediate, or baseload plant. Thus, an analysis of load curve alteration and breakpoint analysis 

is used to translate the megawatt credit to dollars. This usually results in 

displacement of a mixture of peaking, intermediate and base-load plants (see 

Table B-1). 

Also involved with the reliabil ity model ing analysis is the maintenance scheduling. An automatic scheduling routine that minimizes loss-of-load probability is 

used for conventional unit maintenance schedulinq; however, the seasonal insolation variations are also considered for the solar hybrid scheduled outage. A 

period with a combination of relatively poor insolation and good utility system 

reliability is desired for maintaining the solar hybrid plant. 

B.3 SOLAR HYBRID AND REPOWERED PLANT MODEL 

The solar hybrid repowered plant model used for this analysis (see Section 3.0) 

is an outgrowth of the one developed by Westinghouse for EPRI in the performance 

of RP 648-1 . This computer model has the capabi 1 i ty of model ing the operation 

of a number of types and configurations of solar plants on an hourly basis. 

lncl uded in the model is the economic operation of solar stand-alone plants with 

series or parallel storage and hybrid Brayton or Rankine systems. 

The purpose of the model is to take solar design parameters as specified, site 

specific insolation and weather data, and simulate the operation of the solar 
plant on an electric utility system. This operational modeling utilizes the 

plant in the most economic fashion recognizing the changes in incremental operating cost of the balance of the utility system on an hourly basis. 

The model simulates, on an hourly basis, the energy flow within a solar-thermal 

electric generating plant. The program is constructed in a modular fashion to 

represent the major subsystems of such a plant. I These subsystems are shown in 

Figure B-2. 

The model takes as input the hourly incident normal insolation, and through a 

series of conversion efficiency and loss calculations develops the electrical 

output of the turbine generator. It accounts for the operation of thermal 

storage of fossil boilers and is capable of simulating a number of different 

solar plant concepts. 

The concept simulated can 'be a system of parabolic trough distributed collectors, 

c e n t r a l - r e c e i v e r parabol ic dishes, or planar (Winston) coll ectors. The troughs 

can be east-west or north-south oriented. 

The Collector Subroutine ta'kes the input solar insolation and combines it with 

the effective collector area and appropriate factors ,to describe the loss due 

to shading, blobking, reflectivity and aiming. The resulting net collected 

thermal energy is then passed to the Receiver Subroutine. 

The collected energy is next subjected to corrections for receiver efficiency 

and receiver heat losses. This is a simulation of the effects of receiver 

absorption efficiency, and convection and radiation losses. 

The thermal energy leaving the receiver is next adjusted to account for pumping 

losses, and for line thermal losses. The net remaining energy is then transmitted 

either to thermal storage, if available, or directly to the turbine generator, or 

if the capacities of these subsystems are exceeded, to LPle condenser. 

A number of input thresholds controls the actions of Valves A and By shown in 

Figure B-2. Valve A determines whether the energy is directed to storage or 
TURS I#€ 

GEM ERATOR 

a 

1 

STORAGE L 

HEAT LOSSES 1 HEAT LOSS L HEAT OY ERFLCM 

Figure 8-2. Central Receiver Solar Plant Model Representation 
TABLE B-2. SOLAR HYBRID PLANT MODEL DISPATCH 

Oil startup l'ogic 

0,il buffer for insol ation transients 

Closeup potential shutdown windows 

High wind speed solar shutdown 

Boiler efficiency corrections 

Oil recovery of low insolation 

Economic oil dispatch 

Hot standby oil (option) 

Economic shutdown at end of day 

Costlbenefit of daily oil use 

RECOGNIZING 

Foreknow1 edge of day's insolation profile 

e Foreknowledge of day's load profile 

e Utility system incremental cost curve 

Fossil boiler limits and efficiency 

a Turbine-generatdr 1 imi ts and efficiency 

Insolation high transient conditions 

r Operation wind 1 irni ts 
directly to the turbine generator. Valve B controls the withdrawal 'of energy 

from storage, which may be simultaneous with use of heat from Valve A. The 

control parameters define levels of system load below which plant output is not 

desired, and the minimum allowable heat in storage. 

The energy passing from Valve A into storage is modified by a storage input , 

efficiency factor. Thermal losses from storage, as a function of time, are also 

modeled. Should the energy in storage begin to exceed the maximum capacity stated 

by icput, the limiting storage capacity is observed and the energy overflow noted 

in the printout. 

The Turbine Generator Subroutine applies an efficiency factor to represent the 

losses in the process of conversion from input thermal energy to output electrical 

energy. This subroutine also incorporates limits for minimum and maximum levels 

of operation. 

In summary, the basic approach of the model, is to account for energy flows by use 

of device efficiencies, some of which are directly input. Others are calculated 

through mathematical relationships in the program. 

In some subroutines the user has the option of providing the input, a simple 

efficiency factor, or relying upon more complex internal calculations . 

For the realistic representation of solar hybrid repowered plants and their most 

economical operation, a number of rules and considerations have been incorporated 

in the solar plant model, as discussed in Section 2.5.2, and briefly reiterated 

be1 ow. 

For realism in the modeling of the operation of the hybrid plant, those items 

shown in Table B-2 included fossil fuel consumption to bring the boiler up to 

temperature, accounting for both fuel consumption and the time required. Operating scenarios where the boiler heat is maintained (standby) is an option in the 

program. 
Logic requiring fossil boiler energy to buffer the turbine during insolation 

transients has also been incorporated. The skycover conditions are sampled hourly 

from the insol ation tape to determine when insolation transient conditions apply. 

To prevent excessive cycling of the turbine, the plant is fired to run through 

what otherwise would be a brief shutdown period. When wind speeds exceed the 

input design limits, the heliostats are assumed stowed and no solar energy is 

collected for that hour. 

Both boiler and turbine generator part-load efficiency curves are incorporated 

in the solar plant model. 

When the insolation is not sufficient to operate the turbine at its minimum level 

and a specified insolation threshhold is exceeded, the boiler is fired to provide . 

enough supplemental energy to salvage the insolation and operate the turbine 

generator. 

i

The incremental cost of competing conventional plants is tested hourly to establish whether additional fossil firing is justified. Also, a test is made to ,'? 

determine whether it is worthwhile (economic) to start up the boiler at a1 1, each 

day, or to leave the boiler cold and suffer the operating consequences (e.g., no ,'. 

electrical output during solar transients). The proper boiler shutdown hour is 

also established on an economic dispatch basis. 

The ability of the model tc examine alternate operating strategies as well as 

desf yi~ paranleters has been found to be extremely valuable. A 1 ist of somc of 

the inputs and outputs of the solar plant model is given in Table B-3. 
TABLE B-3. SOLAR PLANT MODEL INPUTS/OUTPUTS 

e INPUT 

Site location and latitude 

Solar collector system type and orientation 

I-lourly utility system demand 

Uti 1 i ty balance of system incremental cost 

Hourly insolation and me~eorological data 

Collector field area 

Tracking efficiencies 

Reflectivity efficiencies 

Receiver thermal efficiency 

Pumping efficiency 

Line thermal power loss efficiency 

Storage input/output efficiency 

Thermal storage capacity 

Turbine generator efficiency 

Turbine generator operating 1 imi ts 

Cooling tower type and efficiency 

Minimum usable insolation 

Startuplstandby oil consumption 

Storage heat initialization 

Plant incremental fuel cost 

Plant availabil i ty (equipment-related forced outage table) 

Wind-speed design limit 

Skycover transient specification 

Turbine-generator output windows transient suppression 

r OUTPUT 

Plant megawatt electric output (hourly) 

Modlfled utill t,y system demand (hourly) 

Insolation energy (hourly) 

Energy In storage (hourly) 

Storage energy overflow (hourly) 

Intermediate power flows (hourly) 

Annual and monthly electric energy output 

Annual and monthly solar energy output 

Annual and monthly oil consumption output 

Operating mode transition summary 

Windy and cloudy days tab1 e 

Oil consumption 

Startup and buffer oil consumption 

Transient suppression oil consumption 

Average solar power availability by hour 

Average utility demand by hour 

Monthly peak utility demand 
APPENDIX C: REFERENCES 

Section 2.0 

1. Federal Power Commission, "Power System Statement (F.P.C. Form No. 12) ," 

1975 and 1976 Records in F.P.C. Files, Washington, D.C. 

2. U.S. Department of Energy, "Inventory of Power Plants in the united States," 

DOE/RA-001, December 1977. 

Section 4.0 

1. Northrop, S. A. and Hill, A., Geologic Map of the Albuquerque Country, 

Compiles from U.S. Geological Survey Miscellaneous Investigation Map 

T-224, Scale 1 :380160, 1961. 

2. Kelley, V. C., Albuquerque, Its Mountains, Valleys, Water and Volcanoes, 

New Mexico Bureau of Mines and Mineral Resources, Scenic Trips to the 

Geologic Past No. 9, 1969. 

3. Vlissides, S. D. and Beiberman, R. A., Map of New Mexico Showing Oil 

and Gas Fields, Unsuccessful Test Wells, Recerambinan Rocks and 

Pipelines, U.S. Geological Survey Oil and Gas Investigations Map 

OM-207, Scale 1 : 500,000, 1961 . 

4. Bieberman, R. A. and Weber, R. H., New Mexico Energy Resources Map, 

New Mexico Bureau of Mines and Mineral Resources, 1969. 

5. New Mexico Bureau of Mines and Mineral Resources, New Mexico Metal 

Resources Map, Map of New Mexico Showing Metallic Mining Districts 

and Predominant Mineral s, 1958. 

6. New Mexico Bureau of Mines and Mineral Resources, New Mexico NonMetal Resources Map, Map of New Mexico Showing Non-Metallic Mining 

Di stri cts and Predominant Minerals , 1958. 

7. Algermissen, S. T., "Seismic Risk Studies in the United States" Fourth 

World Conference on Earthquakes Engineering, Santiago Chile, 1969. 

8. Sanford; A. R., "Physical Environment: Seismicity" in Western Area Survey, 

Pub1 ic Service Company of New Mexico, 1978. 

9. Richter, C. F., Elementary Seismology, W. H. Freeman and Co., San 

Franci sco, 1985, 
Crosby, G. W. Lankston, R. W. and Sayers, T. E., "Montana Seismicity,!' 

report for Westinghouse Environmental Systems Department, April 1973. 

U.S. Department of Agriculture, Soil Conservation Service and Forest 

Service and U.S. Department of the Interior, Bureau of Indian Affairs 

and Bureau of Land Management in cooperation with New Mexico Agricultural 

Experiment Station, Soil Survey of Bernalillo County and Parts of 

Sandoval and Valencia Counties, New Mexico, June 1977. 

Public Service Company of New Mexico, Environmental Affairs Department, 

Solar Hybrid Repowering Study Unit Selection, Environmental ~ffairs : 

Site Characteristics Terrain Environmental Impacts, January 13, 1978. 

U.S. Geological Survey, Water Resources Data for New Mexico Water Year 

1976, Water Data Report NM-76-1, 1976. 

Federal Register, Department of the Interior, Fish and Wildlife Service, 

Threatened Plants, July 1, 1976. 

Federal Register, Department of the Interior, Fish and Wildlife Service, 

Endangered Plants, June 17, 1976. 

New Mexico Plant Protection Act, Chapter 45, Article 8, Sections 22 

through 38, New Mexico Statutes Annotated, 1953 Compi lation, New ~exi'co 

Department of Agriculture. 

U.S. Fish and Wildlife Service, "Threatened Wildlife of the United States," 

1973 Edition, U.S. Government Printing Office, Resource Publication 114 

(Revised Resource Pub1 ication 34). 

New Mexico State Game Commission's Regulation No. 563, as adopted 

January 24, 1975 and amended March 7, 1975, December 5, 1975 and 

May 21, 1976. 

Dr. H. Roffman, Energy Impact Associates, telephone conversation with 

Dr. John Hubbard, New Mexico State Game and Fish Endangered Species 

Program, August 21, 1978. 

U.S. Department of Commerce, National Climatic Center, "Local Climatological Data - Albuquerque, New Mexico," Ashville, North Carolina, 1975. 

U.S. Department of Commerce, Weather Bureau, "Climatological Summary of 

Temperature and Precipitation of Los Lunas, New Mexico." 

U.S. Department of Commerce, Weather Bureau, Climatic Summary of the 

United States Supplement for 1951 through 1960 - New Mexico, No. 86-25 

Wash~iriytori, D.C., 1965. 
23. Albuquerque/Bernali~Ilo County Planning Department, Albuquerque/ 

Bernalillo County Comprehensive Plan, Metropolitan Areas and Urban 

Center, April, 1975. 

24. Middle Rio Grande Council of Governments (MRGCOG) Projected 1995 Daily 

Traffic Flow, as documented in MRGCOG 1995 Development Patterns, May, 

1975. 

25. Middle Ri o Grande Counci 1 of Governments (MRGCOG) , 1976 Traffic Flow 

for the Greater A1 buquerque Area, 1977. 

26. National Register of Historic Places, annual summary, in Federal 

Register Vol. 43, No. 26, Tuesday, February 7, 1978 

27. National Register of Historic Places, additions, in Federal Register, 

Vol. 43, No. 45, Tuesday, March 7, 1978. 

28. The University of New Mexico, Bureau of Business and Economic Research, 

New Mexico Statistical Abstract, Albuquerque, 1977, pp. 81-97. 

29. Lehman, T., Demographic Profile of Albuquerque/Bernalillo County Residence, 

Albuquerque Urban Observatory, UniversTty of New Mexico, July 1978. "' Y 

I I. . .. , :, 30. Employment Security Commission of New Mexico, Employment Service Division . , ". "I ..I 

Research and Statistics Section, "Table A, Civilian Labor Force, Employment , Unempl oyyen t and Unemployment Rate 1976," A1 buquerque, New Mexico. $*, :e; 

31. Brady, Raymond J. and Adcock, Larry D., Bureau of Business and Economic ,, . Research, Institute for Applied Research Services, Economic and Demographic Forecasts and Projections, Bernal i 1 lo County and City of . ,..‘>: ~ J 

Albuquerque 1975--1800--1985, The University of New Mexico, Albuquerque, ., . ' _ ,,.. 

March. 1976. . . 

32. Patten, D. T. , Arizona State University, Solar Energy Conservation : 

An Analysis of Impacts on Desert Ecosystems, Prepared for U.S. Department 

of Energy, Solar Energy, C00/4339-1, September 1977. 
Clean Air Act, Standards of Performance for New Stationary Sources, 

Section 111, PL 95-95, August 7, 1977. 

Clean Air Act, "Prevention of Significant Deteoriation of Air Quality," 

Sections 160-169, PL 95-95, August 7, 1977. 

Environmental Reporter, "New Mexico Ambient Air Qua1 i ty Standards, " 

May 1977, pages 456:0503-456:0509. 

Turner, D. Atmospheric Dispersion Estimates, Environmental Protection 

Agency, Research Triangle Park, N. C., 1973. 

Code of Federal Regulations, Title 40, Sec 50.3-11, "National Primary 

Ambient Air Quality Standards," January 1977. 

W.yszinski, L. E., Telephone Conversation of Harley, R., Air Quality 

Department, Bernalillo County, New Mexico, March 3, 1978. 

Roffman, A. and Roffman, H., "Effects of Salt Water Cooling Tower Brift 

on Water Bodies and Soils ," Water, Soil and Air Pollution, Vol . 2, 1973, 

pp. 457-571. 

Patten, D. T., Arizona State University, Solar Energy Conversion: An 

Analysis of Impacts of Desert Ecosystems, prepared for the U.S. Department 

of Energy, Solar Energy, Progress Report June 1 to December 31, 1977, 

Roffman, A., Roffman, H., McFeaters, B. D. and Morris, J. R., "The Effect 

of Storm Water Runoff," National Symposium on Urban Hydrology and 

Sediment Control , Lexington, I(entucky, July 20-31, 1975. 

McDonnell Douglas Astonautics Compan,y, Central Receiver Solar Thermal Power 

System, Phase 1, CDRL Item 2 Pilot Plant, Preliminary Design Report, Vol. 

I 11, Book 2, Collector Subsystem System, SAN-1108-76-8, MRC 66776, 

October 1977. 

U.S. Environmental Protection Agency, Rules and Regulations, Title 40, 

Part 112, "Oi 1 Pol lution Prevention ," January 1974. 

S. Haus, L. Duncan, P. Alkon and J. Pratt, the MITRE Corporation, 

"Preliminary Environmental ,Assessment Concerning the Construction and 

Operation of a 5-MW Solar Thermal Central Receiver Test Facility," 

MITRE Working Paper 11290, November, 1975. 

T. D. Brumleve, Sandia Laboratories, Livermore, "Eye Hazard and Glint 

Evaluation for the 5-MWt Solar Thermal Test Facility," SAND 76-8022, 

May, 1977. 

L.L. Young, 111, "Solar Energy Research'at Sandia Laboratories and Its 

Effects on Health and Safety", SAND 77-1412, October 1977. 

C-4 

*US. GOVERNMENT PRINTING OFFICE: 1979-640-0921479