A Survey on Renewable Energy for Electric Generation

T.C.

Çukurova University

Faculty of Engineering and Architecture

Department of Electrical and Electronics Engineering

Graduation Thesis

A Survey on Renewable Energy for Electric Generation

By

Kasım Zor

2004514018

Advisor

Prof. Dr. Mehmet Tümay

May-2010

ADANA

I

CONTENTS I

LIST OF FIGURES XII

LIST OF TABLES XX

ABSTRACT XXI

ACKNOWLEDGEMENTS XXII

1 INTRODUCTION 1

1.1 Renewable Energy at a Glance 1

2 ELECTRIC GENERATION FROM RENEWABLE ENERGY SOURCES 3

2.1 Solar Energy and Electric Generation 3

2.1.1 Introduction 3

2.1.2 Solar Thermal Power System 3

2.1.2.1 Energy Collection 5

1) Parabolic Trough 5

2) Central Receiver 7

3) Parabolic Dish 9

2.1.2.2 Solar Chimney Power Plant 10

2.1.2.3 Commercial Power Plants 12

2.1.2.4 Potential Technology Developments and Recent Trends 13

2.1.2.5 Future Expectations 14

1. Short Term: Present to 2020 14

2. Medium Term: 2020 to 2035 15

3. Long Term: After 2035 16

II

2.1.3 Phovoltaics 16

2.1.3.1 Introduction 16

2.1.3.2 PV Cell 17

1) PV Cell Technologies 19

a. Crystalline Silicon Solar Cells 19

b. Thin Film Solar Cells 20

c. Concentrator Cell 21

2.1.3.3 Module and Array 23

2.1.3.4 Array Design 26

1) Sun Intensity 26

2) Sun Angle 27

3) Shadow Effect 28

4) Temperature Effect 30

5) Effect of Climate 32

6) Electrical Load Matching 32

7) Sun Tracking 34

8) Peak-Power Operation 37

9) System Components 38

2.1.3.5 Power Electronics for Photovoltaic Power Systems 40

1) Stand-alone PV Systems 41

1.1) Battery Charging 42

1.1.1) Batteries for PV Systems 42

1.1.2) PV Charge Controllers 43

1.1.2.1) A Series Charge Regulators 44

1.1.2.2) Shunt Charge Regulators 45

1.1.2.3) DC-DC Converter Type Charge

Regulators 45

1.1.3) Maximum Power Point Tracking 47

1.1.4) Analog Control 48

1.1.5) Digital Control 49

1.2) Inverters for Stand-alone PV Systems 49

2) Hybrid Systems 54

III

2.1) Series Configuration 54

2.2) Switched Configuration 56

2.3) Parallel Configuration 58

2.4) Control of Hybrid Energy Systems 60

3) Grid-connected PV Systems 62

3.1) Inverters for Grid-connected Applications 64

3.2) Inverter Classifications 64

3.3) Inverter Types 66

3.3.1) Line-commutated Inverter 66

3.3.2) Self-commutated Inverter 67

3.3.3) Inverter with High Frequency

Transformer 68

3.3.4) Other PV Inverter Topologies 69

3.3.4.1) Multilevel Converters 69

3.3.4.2) Non-insulated

Voltage Source 70

3.3.4.3) Non-insulated

Current Source 70

3.3.4.4) Buck Converter with Half-bridge

Transformer Link 71

3.3.4.5) Flyback Converter 71

3.3.4.6) Interface Using Paralleled

PV Panels 72

3.4) System Configurations

3.4.1) Central Plant Inverter 73

3.4.2) Multiple String DC/DC Converter 73

3.4.3) Multiple String Inverters 74

3.4.4) Module Integrated Inverter 75

3.5) Grid-compatible Inverters Characteristics 75

3.5.1) Protection Requirements 77

2.1.3.6 Potential Technology Developments and Recent Trends 79

1) Dye-sensitized Solar Cells 80

IV

2) Organic and Nanotechnology Solar Cells 80

2.1.3.7 Future Expectations 81

1) Short Term: Present to 2020 81

2) Medium Term: 2020 to 2035 82

3) Long Term: After 2035 82

2.2 Wind Energy and Electric Generation 84


2.2.2 Wind Speed and Energy 85

2.2.2.1 Power Extracted from the Wind 87

2.2.2.2 Effect of Hub Height 90

2.2.3 Wind Power Systems 92

2.2.3.1 System Components 92

1) Towers 94

2) Turbine 99

3) Blades 100

2.2.3.2 Turbine Rating 101

2.2.3.3 Power vs Speed and TSR 102

2.2.3.4 Maximum Power Operation 105

1) Constant-TSR Scheme 105

2) Peak-Power-Tracking Scheme 106

2.2.3.5 System Design Trade-Offs 107

1) Turbine Towers and Spacing 107

2) Number of Blades 109

3) Rotor Upwind or Downwind 110

4) Horizontal vs Vertical Axis 111

2.2.4 Power Electronics for Modern Wind Turbines 111

1) Wind Energy Conversion 111

2) Modern Power Electronics and Converter Systems 115

2.1) Power Electronic Devices 115

2.2) Power Electronics Converters 116

V

3) Generator Systems for Modern Wind Turbines 118

3.1) Fixed-Speed Wind Turbines 118

3.2) Variable-Speed Wind Turbines 122

3.2.1) Variable-Speed Wind Turbines with Partially Rated

Power Converters 123

3.2.1.1) Dynamic Slip-Controlled Wounded Rotor

Induction Generator 124

3.2.1.2) Doubly Fed Induction Generator 124

3.2.2) Full Scale Power Electronic Converter

Integrated Systems 125

4) Control of Wind Turbines 127

4.1) Active Stall Wind Turbine with Cage Rotor Induction

Generators 127

4.2) Variable Pitch Angle Control with Doubly Fed

Generators 128

4.3) Full Rated Power Electronic Interface

Wind Turbine Systems 130

5) Electrical Topologies of Wind Farms Based on Different Wind

Turbines 131

6) Integration of Wind Turbines into Power Systems 134

6.1) Requirements of Wind Turbine Grid Integration 135

6.1.1) Frequency and Active Power Control 135

6.1.2) Short Circuit Power Level and Voltage Variations 135

6.1.3) Reactive Power Control 137

6.1.4) Flicker 138

6.1.5) Harmonics 138

6.1.6) Stability 139

6.2)Voltage Quality Assessment 140

6.2.1) Steady-State Voltage 140

6.2.2) Voltage Fluctations 141

6.2.2.1) Continuous Operation 141

6.2.2.2) Switching Operations 142

VI

6.2.3) Harmonics 142

2.2.5 Environmental Aspects 143

2.2.5.1 Audible Noise 143

2.2.5.2 Electromagnetic Interference 144

2.2.5.3 Effect on Birds 145

2.2.5.4 Other Impacts 145

2.2.6 Potential Catastrophes 146

2.2.6.1 Fire 146

1) Lightning Strike 146

2) Internal Fault 146

2.2.6.2 Earthquake 147

2.2.7 Potential Technology Development and Recend Trends 148

2.2.7.1 Potential Technology Development 148

2.2.7.2 Recent Trends 152

1) Small Wind Systems 153

2) System-Design Trends 153

2.2.8 Future Expectations 154

2.2.8.1 Short Term: Present to 2020 154

2.2.8.2 Medium Term: 2020 to 2035 155

2.2.8.3 Long Term: After 2035 156

2.3 Geothermal Energy and Electric Generation 158


2.3.2 Geothermal Resources 159

2.3.2.1 Model of a Hydrothermal Geothermal Resource 159

2.3.2.2 Other Types of Geothermal Resources 161

1) Hot Dry Rock 162

2) Geopressure 163

3) Magma Energy 165

2.3.3 Geothermal Power Plants 167

2.3.3.1 Direct Steam Power Plants 169

VII

2.3.3.2 Flash Steam Power Plants 172

1) Single Flash Power Plants 172

2) Double Flash Power Plants 174

2.3.3.3 Binary Cycle Power Plants 175

2.3.3.4 Hybrid Power Plants 178

1) Hybrid Single-Flash and Double-Flash Systems 178

a) Integration of These Systems 178

b) Combined System 179

2) Hybrid Flash-Binary Systems 180

a) Combined Plants 181

b) Integrated Flash-Binary Plants 181

2.3.4 Benefits of Geothermal Energy 183

2.3.5 Potential Technology Development and Recent Trends 183

2.3.5.1 Potential Technology Development 183

2.3.5.2 Recent Trends 184

1) Enhanced Geothermal Systems 184

2.3.6 Future Expectations 186

2.3.6.1 Short Term: Present to 2020 186

2.3.6.2 Medium Term: 2020 to 2035 186

2.3.6.3 Long Term: After 2035 187

2.4 Ocean Energy and Electric Generation 188


2.4.2 Tidal Energy 188


2.4.2.2 Basic Physics 189

2.4.2.3 Tidal Energy Status 190

1) Tidal Barrages 191

1.1) Principles of Operation 191

1.2) Single-Basin Tidal Barrages 191

a) Ebb Generation 191

VIII

b) Flood Generation 191

c) Two-Way Generation 192

1.3) Double-Basin Tidal Barrages 192

1.4) La Rance, France 193

2) Tidal Current Turbines 193

2.1) Principle of Operation 193

a) Kinetic Energy Extraction 193

2.2) Turbine Technologies and Concepts 195

a) DeltaStream Turbine 196

b) Evopod Tidal Turbine 196

c) Free Flow Turbines 197

d) Gorlov Helical Turbine 198

e) Lunar Energy Tidal Turbine 198

f) Neptune Tidal Stream Device 199

g) Nereus and Solon Tidal Turbines 200

h) Open Centre Turbine 201

i) Pulse Tidal Hydrofoil 201

j) SeaGen 202

k) Stingray Tidal Energy Converter 203

l) Tidal Fence Davis Hydro Turbine 204

m) TidEl Stream Generator 204

n) Tidal Stream Turbine 205

2.4.2.4 Current Issues on Tidal Energy 206

1) Tidal Barrage Systems 206

2) Tidal Current Turbines 206

2.4.2.5 Future Developments 208

1) Tidal Barrage Systems 208

2) Tidal Cyrrent Turbines 208

2.4.3 Wave Energy 209


2.4.3.2 Wave Resources 210

2.4.3.3 The Various Technologies 210

IX

1) The Oscillating Water Column 211

a. Fixed-structure OSW 211

b. Floating-structure OSW 214

2) Oscillating Body Systems 215

a. Single-body Heaving Buoys 216

b. Two-body Heaving Systems 219

c. Fully Submerged Heaving Systems 222

d. Pitching Devices 222

e. Bottom-hinged Systems 227

f. Many-body Systems 228

3) Overtopping Converters 229

4) Electrical Equipment 231

2.4.3.4 Wave Energy Transmission Concepts for Linear Generator

Arrays 232

1) System Description 232

a. Base Unit 232

b. System Options 233

c. Connection Schemes 236

2.4.3.5 Conclusion 238

2.4.4 Ocean Thermal Energy Conversion 239


2.4.4.2 Design Requirements for OTEC Systems 241

2.4.4.3 OTEC Power Systems 242

2.4.4.4 Applications for OTEC 245

2.4.4.5 Advantages and Disadvantages of OTEC System 246

1) Advantages 246

2) Disadvantages 246

2.4.4.6 Perspectives 246

2.5 Biomass Energy and Electric Generation 248


X

2.5.2 Biomass Technologies 248

2.5.2.1 Gasification-based Biomass 248

2.5.2.2 Direct-fired Biomass 252

2.5.2.3 Biomass Co-firing 254

2.5.3 Status of Technology 256

2.5.4 Biomass Future 258

2.6 Hydropower Energy and Electric Generation 263


2.6.2 Hydropower Plant Models and Control 263

2.6.3 Hydroelectricity 265

2.6.4 Micro Hydropower Station 268

2.6.4.1 A Hydropower Station Under Study 268

2.6.5 Hydropower’s Future in a Fluid Energy World 269

2.7 Hydrogen Energy and Electric Generation 273


2.7.2 Electrical Energy Storage 273

2.7.3 Electrolyser 275

2.7.4 Hybrid Systems 276

2.7.4.1 Solar-hydrogen Energy Systems 276

2.7.4.2 Wind to Hydrogen System 278

3 FINANCIAL AND ECONOMIC VIEW OF RENEWABLE ENERGY 280

3.1 Cost of Renewable Energy Systems 280

3.2 Wind Power Cost 287

3.3 Solar Power Cost 289

3.3.1 Solar Photovoltaic Cost 289

3.3.2 Concentrating Solar Power 292

XI

3.4 Geothermal Power 295

3.5 Biopower Cost 296

3.6 Costs in 2020 297

REFERENCES 302

XII

LIST OF FIGURES

Figure Name of the Figure Page

1.1 Solar Thermal Power Plant Schematic for Generating Electricity 4

1.2 Parabolic Trough 5

1.3 Principle of a Parabolic Trough Solar Power Plant 7

1.5 Central Receiver 7

1.6 Operational Schematic of Planta Solar 10 8

1.7 PS10 Solar Thermal Power Plant, Sevilla, Spain 8

1.8 Principle of a Dish-Stirling System 9

1.9 California Edison 25kW Dish-Stirling System 10

1.10 Principle of the Solar Chimney Power Plant 10

1.11 Solar Heat Induced Wind Chimney Power Plant 11

1.12 PV Effect Converts the Photon Energy into Voltage across the P-N Junction 17

1.13 Basic Construction of PV Cell with Performance Enhancing Features 18

1.14 Crystalline Silicon Wafers 19

1.15 Amorphous Silicon Thin Film 21

1.16 Lens Concentrating the Sunlight on a Small Area Reduces the Need for 22

Active Cell Material

1.17 Several PV Cells Constitute a Module and Several Modules Constitute an Array 23

1.18 Construction of PV Cell 24

1.19 PV Module Mounting Methods 25

1.20 I-V Characteristic of PV Module Shifts down at Lower Sun Intensity, 26

with Small Reduction in Voltage

1.21 Photoconversion Efficiency vs Solar Radiation 27

1.22 Kelly Cosine Curve for PV Cell at Sun Angles form 0° to 90° 28

1.23 Shadow Effect on One Long Series String of an Array 29

1.24 Bypass Diode in PV String Minimizes Power Loss under Heavy Shadow 30

1.25 Effect on Temperature on I-V Characteristic 30

1.26 Effect of Temperature on P-V Characteristic 32

XIII


1.27 Operating Stability and Electrical Load Matching with Constant-resistive Load 33

and Constant-power Load

1.28 Dual-Axis Sun Tracker Follows the Sun throughout the Year 34

1.29 Actual Motor of the Sun Tracker 35

1.30 Sun-Tracking Actuator Principle 36

1.31 Peak-Power-Tracking PV Power System Showing Major Components 39

1.32 Stand-alone PV System 40

1.33 PV-diesel Hybrid System 41

1.34 Grid-connected PV System 41

1.35 Nominal Number of Battery Cycles vs DOD 43

1.36 Series Charge Regulator 44

1.37 Shunt Charge Regulator 45

1.38 Buck Converter 46

1.39 Boost Converter 46

1.40 Buck-Boost Converter 46

1.41 Typical Power/Voltage Characteristic for Increased Insolation 47

1.42 PV Array and Load Characteristic 48

1.43 Single-Phase Inverter 51

1.44 A Stand-alone Three-phase Four-wire Inverter 51

1.45 Typical Inverter Efficiency Curve 52

1.46 Bi-directional Inverter System 53

1.47 Series Hybrid Energy System 55

1.48 Switched PV-diesel Hybrid Energy System 57

1.49 Parallel PV-diesel Hybrid Energy System 58

1.50 Operating Modes for a PV Single-Diesel Hybrid Energy System 60

1.51 Voltage Source Inverter 65

1.52 Line-commutated Single-phase Inverter 66

1.53 Self-commutated Inverter with PWM Switching 67

1.54 PV Inverter with High Frequency Transformer 68

1.55 Half-bridge Diode-clamped Three Level Inverter 69

XIV


1.56 Non-insulated Voltage Source 70

1.57 Non-insulated Current Source 70

1.58 Buck-converter with Half-bridge Transformer Link 71

1.59 Flyback Converter 72

1.61 Converter Using Parallel PV Units 72

1.62 Central Plant Inverter 73

1.63 Multiple String DC/DC Converter 74

1.64 Multiple String Inverters 74

1.65 Module Integrated Inverter 75

2.1 Horizontal-axis Wind Turbine Showing Major Components 86

2.2 Vertical-axis 33 m Diameter Wind Turbine Built and Tested by DOE/Sandia 87

National Laboratory during 1994 in Bushland

2.3 Rotor Efficiency vs V0/V ratio has a single maximum 89

2.4 Rotor Efficiency vs V0/V ratio for rotors with different numbers of blades 90

2.5 Wind Speed Variations with Height over Different Terrain 91

2.6 Baix Ebre Wind Farm and Control Center, Catalonia, Spain 92

2.7 Nacelle Details of a 3.6MW /104m Diameter Wind Turbine 94

2.8 A Large Nacelle under Installation 95

2.9 A 600kW Wind Turbine and Tower Dimensions with Specifications 96

2.10 A 600kW Wind Turbine and Tower Dimensions with Specifications 96

2.11 Tower Heights of Various Capacity Wind Turbines 97

2.12 WEG MS-2 Wind Turbine Installations at Myers Hill 98

2.13 Wind Turbine Torque vs Rotor Speed Characteristic 102

at Two Wind Speeds V1 and V2

2.14 Wind Turbine Power vs Rotor Speed Characteristic 103

at Two Wind Speeds V1 and V2

2.15 Rotor Efficiency and Annual Energy Production vs Rotor TSR 104

2.16 Maximum Power Operation Using Rotor Tip Speed Control Scheme 105

2.17 Maximum Power Operation Using Power Control Scheme 106

2.18 Optimum Tower Spacing in Wind Farms in Flat Terrain 107

XV


2.19 Original Land Use Continues in a Wind Farm in Germany 108

2.20 Main Components of a Wind Turbine System 112

2.21 Power Characteristics of a Fixed Speed Wind Turbines 114

2.22 Roadmap for Wind Energy Conversion 114

2.23 Development of Power Semiconductor Devices in the Past and in the Future 115

2.24 Circuit Diagram of a Voltage Source Converter with IGBTs 116

2.25 Waveforms of a Bi-directional Active and Reactive Power of a VSC 117

2.26 Wind Turbine Systems without Power Converter, 119

but with Aerodynamic Power Control

2.27 The Startup of a Fixed-speed Wind Turbine 121

2.28 Wind Turbine Topologies with Partially Rated Power Electronics 123

and Limited Speed Range

2.29 Torque and Speed Characteristics of Rotor Resistance Controlled 124

Wound Rotor Induction Generator

2.30 Wind Turbine Systems with Full-scale Power Converters 126

2.31 Control of Wind Turbine with DFIG System 129

2.32 Basic Control of Active and Reactive Power in a Wind Turbine 131

with a Multipole Synchronous Generator System

2.33 Wind Farm Solutions 132

2.34 A Simple System with an Equivalent Wind Power Generator 136

Connected to a Network

2.35 World Total Installed Capacity in 2001-2010 148

2.36 Top 10 Countries by Growth Rate in 2008 and 2009 149

2.37 Top 10 Countries by Total Capacities in 2008 and 2009 150

2.38 Top 5 Countries in Offshore Wind 152

2.39 Continental Distribution 2007-2009 152

2.40 Areas of Potential Wind Power Technology Improvements 155

3.1 A Geothermal Reservoir 159

3.2 Schematic Model of a Hydrothermal Geothermal System 160

3.3 Ideal Hot Dry Rock Production Scheme 162

XVI


3.4 Cross-section Schematic of a Geopressured Reservoir 164

3.5 Conceptual Design of Long Valley Magma Energy Exploratory Well 167

3.6 A Geothermal System 168

3.7 Turbine Generator 168

3.8 Lardarello, Tuscany, Northern Italy 169

3.9 Principle of Dry Steam Power Plant 170

3.10 The Geysers Power Plant, California 171

3.11 Simplified Flow Diagram for a Dry Steam Power Plant 172

3.12 Principle of Flash Steam Power Plant 173

3.13 East Mesa, California 173

3.14 Simplified Flow Diagram of a Single Flash Geothermal Power Plant 174

3.15 Double-Flash Power Plant Diagram 175

3.16 Principle of Binary Cycle Power Plant 175

3.17 Binary Power Plant Heat Exchanger 176

3.18 Schematic Diagram of Binary Power Plant 177

3.19 Integrated Single and Double Flash Facility 179

3.20 Combined Single and Double Flash Plants 180

3.21 Combined-Flash Binary System 181

3.22 Integrated Flash-Binary Plants 182

3.23 Simplified Representation of an EGS system where water is circulated 185

through hot dry rock and heat is mined in a closed loop

4.1 The Effect of the Moon on Tidal Range 190

4.2 Tidal Turbine against an Offshore Wind Turbine 194

4.3 Tidal Turbine Fundamental Types 195

4.4 Delta Stream Turbine 196

4.5 Evopod Tidal Turbine 197

4.6 Free Flow Turbine 197

4.7 Gorlov Helical Turbine 198

4.8 Lunar Energy Tidal Turbine 199

4.9 Neptune Tidal Stream Device 199

XVII


4.10 Nereus Tidal Turbine 200

4.11 Solon Tidal Turbine 200

4.12 Open Centre Turbine 201

4.13 Pulse Tidal Hydrofoil 202

4.14 SeaGen 203

4.15 Stingray Tidal Energy Converter 203

4.16 Tidal Fence Davis Hydro Turbine 204

4.17 TidEl Stream Generator 205

4.18 Tidal Stream Turbine 205

4.19 The Various Wave Energy Technologies 211

4.20 Cross-sectional View of a Bottom-standing OWC 212

4.21 Schematic Representation of the Backward Bent Duct Buoy 214

4.22 Norwegian Heaving Buoy in Trondheim Fjord, 1983 216

4.23 Swedish Heaving Buoy with Linear Electrical Generator 217

4.24 L-10 Wave Energy Converter with Linear Electrical Generator 218

4.25 Schematic Representation of the IPS Buoy 220

4.26 Wavebob 221

4.27 The PowerBuoy Prototype Deployed off Santana, Spain, in 2008 221

4.28 Schematic Representation of the Archimedes Wave Swing 222

4.29 The Duck Version of 1979 Equipped with Gyroscopes 223

4.30 The Three-unit 3x750kW Pelamis Wave Farm 224

in Calm Sea off Northern Portugal, in 2008

4.31 Side and Plan Views of the McCabe Wave Pump 225

4.32 Front and Side Views of the PS Frog Mk 5 225

4.33 Schematic Representation of the Saraev 226

4.34 The Swinging Mace in Three Angular Positions 227

4.35 Oyster Protoype 228

4.36 Schematic Plan View of the Tapered Channel Wave Power Device 230

4.37 Plan View of Wave Dragon 231

4.38 Linear Generator with Point Absorber 232

XVIII

4.39 Single Line Diagram for Base Unit 233

4.40 System Option 1 233

4.41 System option 2 234



4.43 System Option Cable Cross vs Complexity 235

4.44 One Cable from Base Unit to Shore 236

4.45 One Cable from Farm to Shore 236

4.46 One Cable from Cluster to Shore 237

4.47 Subclusters and Clusters with Cable to Shore 237

4.48 Ocean Temperature Resource for OTEC 240

4.49 Diagram of Closed-cycle OTEC Plantship 241

4.50 Diagram of Open-cycle OTEC Power System 242

4.51 Layout Diagram of OTEC-1 Subsystems (Castellano,1981) 243

4.52 Hyberid-cycle OTEC Power System 244

4.53 Block Diagram of All Applications from OTEC Technology 245

4.54 Futurist Project Based on OTEC Technology 246

5.1 Biomass Gasification Combined Cycle System Schematic 249

5.2 Low-pressure Direct Gasifier 250

5.3 Indirect Gasifier 251

5.4 Direct-fired Biomass Electricity Generating System Schematic 253

5.5 Biomass Co-firing Retrofit Schematic for a Pulverized Coal Boiler System 254

5.6 Integrated Gasifier Combined Cycle 260

6.1 General Layout Form of a Hydropower Plant 264

6.2 Block Diagram Form of a Hydropower Plant 264

6.3 Huge Turbine Engines inside the Hoover Dam in Black Canyon, Nevada 265

6.4 Aeiral View of Hoover Dam, Nevada, Creating the Reservoir Lake Mead 266

6.5 Autonomous Variable Speed Micro Hydropower Station 269

7.1 Energy Supply Structure 274

7.2 Paths for Hydrogen 274

7.3 Hydrogen Filling Station Network with Electrolyser as Controllable Load 276

XIX

7.4 Solar-hydrogen Energy System 277

7.5 System without Hydrogen 277

7.6 System with Hydrogen 278

7.7 Construction of the 1.65MW Wind Turbine at the Morris Research Center 278

8.1 Projected 2010 Costs of Wind with Production Tax Credit 288

8.2 Wind Capacity Factor in 2006 by Region and Vintage of Wind Facility 288

8.3 PV Power Costs as Function of Module Efficiency and Cost 289

8.4 Fractional Energy PV Rooftop supply curves 290

for the Three U.S. Interconnections

8.5 Price, customer cost after subsidy, and number of PV installations per year in 291

California under California Energy Commission incentive programs

8.6 Supply curves describe the potential capacity and current busbar costs in terms 293

of nominal levelized cost of energy (LCOE) of concentrating solar power

8.7 Concentrating solar power supply curve based on 20 percent availability of city 294

peak demand and 20 percent availability of transmission capacity

8.8 Geothermal Supply Curve 295

8.9 Levelized Cost Estimate for Biomass and Solar PV Systems in 2010 and 2020 298

8.10 Levelized Cost Estimate for Wind and Solar Thermal Systems in 2010 and 2020 299

8.11 Learning Curve for PV Production 300

XX

LIST OF TABLES

Table Name of the Table Page

1.1 Comparison of Alternative Solar Thermal Power Technologies 10

1.2 Comparison of 10MWe Solar-II and 100MWe Prototype Design 12

1.4 Kelly Cosine Values of the Photocurrent in Silicon Cells 28

2.1 Friction Coefficient α of Various Terrains 91

2.2 World’s Major Wind Turbine Suppliers in 2004 100

2.3 Wind Turbine Topologies Market in 2001 127

2.4 Comparison of Four Wind Farm Topologies 134

2.5 Noise Levels of some Commonly Known Sources Compared with Wind Turbine 143

2.6 Offshore Overall Capacity in 2009 151

3.1 HDR Projects Worldwide 163

3.2 Estimates of U.S. Geothermal Resource Base to 10km depth by category 186

8.1 Current Cost Assumptions for Renewable Technologies (2007) 280

8.2 2020 Cost Projections and Comparisons 282

8.3 Levelized Cost of Energy for New Plants Coming Online in 2012 285

XXI

ABSTRACT

Energy production is a field that routes countries strategically and politically. Due to

the forthcoming global warming danger, and the extinction of fossil fuels, renewable energy

will extend the life length of next generations of humanity.

By means of energy, electricity generation technologies with respect to the

developments in science and engineering improve their efficiency day by day. Because of the

vitality of energy in global meaning, the feature of being inexhaustible of renewable energy

makes it popular and leads the new investments.

Meanwhile, utilization of renewable energy resources attracts and triggers the usage of

technologies which are environmentally friendly. Despite the installation and operation costs,

governments support investors and enterprisers by directing them to renewables, hence CO2

emissions is being reduced and in the near future, our dreams of having a green earth may be

realized optimistically.

Consequently, in this thesis, a general survey which focuses on the generation of

electricity from renewable sources such as solar, wind, geothermal, ocean, biomass,

hydropower and hydrogen resources is presented.

XXII

ACKNOWLEDGEMENTS

I would like to express my gratitude to the following people who have helped me

throughout this thesis duration, and my past up to now.

Prof. Dr. Mehmet Tümay and Assist. Prof. Dr. K. Çağatay Bayındır for giving me the

opportunity to work on this thesis. I would also like to thank Assist. Prof. Dr. K. Çağatay

Bayındır for his guidance, patience and support during thesis.

I would like to thank my teachers in primary, secondary and high school level who

taught me being true hearted, loyal and honest.

Special thanks to my best friends, Caner Yıldırım and Emrah Mehmet Güllüoğlu,

because of their endless support anytime I needed in the past and I never give up this

brotherhood which will exist in the future.

Finally, I would like to appreciate and present my everlasting thanks to my family for

their support financially and mentally, especially my mother, Ayşe Zor, because of her

unconditional love ,which can not be repaid, makes me proud everytime.

1

1 INTRODUCTION

1.1 Renewable Energy at a Glance

Energy is a vital element in human life. A secure, sufficient and accessible supply of

energy is very crucial for the sustainability of modern socities. The demand for the provision

of energy is increasing rapidly worldwide and the trend is likely to continue in the future.

Electricity producing systems presently in use across the world can be classified into

three main categories: fossil fuels, nuclear power and renewables.

Fossil fuels in their crude form, i.e. wood, coal and oil have traditionally been an

extensive used energy source. The present energy supply mainly depends on fossil energy

resources. The priority is to produce and transport fossil fuels in the most economical fashion

and to convert them cheaply into other types of energy in central power stations. The main

advantage of fossil fuel-based energies is their ready availability. Fossil energy can be used

wherever there is a consumer demand.

Nuclear power due to a number of reasons is not accesible to the vast majority of the

world and has found its application only within developed countries.

Renewable energy sources are energy resources that are inexhaustible within the time

horizon of humanity. Renewable energy resources are easily accessible to mankind around the

world. Renewable energy is not only available in wide range, but are also abundant in nature.

Renewables contribute less to air pollution, reduce the human health damages and can balance

the use of fossil fuels in order to save these for other applications and future use.

In 2005, the worldwide electricity generation was 17450 TWh out of which 40%

originated from coal, 20% from gas, 16% from nuclear, 16% from hydro, 7% from oil and

only 2% from renewable sources i.e. small hydro, wind, geothermal, etc. Renewable energy

sector is meeting at present 13.5% of the global energy demand and it is now growing faster

than the growth in overall energy market.

Some long-term scenarios postulate a rapidly increasing share of renewable

technologies (made up of solar, wind, geothermal, modern biomass, as well as the more

traditional source i.e. hydro). Under these scenarios renewables could meet up to 50% of the

2

total energy demand by mid-21st century with appropriate policies and new technology

developments.[1]

3

2 ELECTRIC GENERATION FROM RENEWABLE ENERGY SOURCES

2.1 Solar Energy and Electric Generation

2.1.1 Introduction

Among renewable sources, solar energy comes at the top of the list due to its

abundance, and more evenly distribution in nature than any other renewable energy types

such as wind, geothermal, hydro, wave and tidal energies.

The sun is the central point of our solar system; it has probably been in existence for 5

billion years and is expected to survive for a further 5 billion years. Nuclear fusion processes

create the radiant power of the sun. Various influences of the atmosphere reduce the

irradience, thus values measured on the surface of Earth are usually lower than the solar

constant.

In direct or indirect fashion, the sun is responsible for nearly all the energy sources to

be found on Earth. All the coal, oil and natural gas were produced by decaying plants millions

of years ago. In other words, the primary fossil fuels used today are really stored solar energy.

The heat from the sun also drives the wind, which is another renewable source of

energy. Wind arises because Earth‘s atmosphere is heated unevenly by the sun. The only

power sources that do not come from the sun‘s heat are the heat produced by radioactive

decay at Earth‘s core; ocean tides which are influenced by the moon‘s gravitational force; and

nuclear fusion and fission.

This inexhaustible source of solar energy can be utilized directly by solar thermal or

photovoltaic systems.[2]

2.1.2 Solar Thermal Power System

The solar thermal power system collects the thermal energy in solar radiation and uses

it at high or low temperatures. Low temperature applications include water and room heating

for commercial and residential buildings. High temperature applications concentrate the sun‘s

heat energy to produce steam for driving electrical generators. Concentrating solar power

4

(CSP) technology has the ability to store thermal energy from sunlight and deliver electric

power during dark or peak-demand periods.

Figure 1.1 Solar Thermal Power Plant Schematic for Generating Electricity(Ref:3)

Figure 1.1 is a schematic of a large scale solar thermal power station. In such a plant,

solar energy is collected by thousands of sun-tracking mirrors, called heliostats, which reflect

the sun‘s energy to a single receiver atop a centrally located tower. This enormous amount of

energy that is focused on the receiver tower is used to melt a salt at high temperature. The hot

molten salt is stored in a storage tank and used when needed to generate steam and drive a

turbine generator. After generating steam, the used molten salt, now at low temperature, is

returned to the cold salt storage tank. From here the salt is pumped to the receiver tower to be

heated again for the next thermal cycle. The usable energy extracted during such a thermal

cycle depends on the working temperatures. The maximum thermodynamic conversion

efficiency that can be theoretically achieved with the hot side temperature Thot and the cold

side temperature Tcold is given by the Carnot efficiency, which is as follows:

5

(1.1)

where the temperatures are in degrees Kelvin. A higher hot side working temperature and a

lower cold side exhaust temperature give higher plant efficiency to convert the captured solar

energy to electricity. The hot side temperature, however, is limited by the properties of the

working medium. The cold side temperature is largely determined by the cooling method and

the environment available to dissipate the exhaust heat.

A major benefit of this scheme is that it incorporates thermal energy storage for

several hours with no degradation in performance or for longer with some degradation. This

feature makes this technology capable of producing high value electricity in order to meet

peak demands. Moreover, compared with the solar photovoltaic system, the solar thermal

system is economical and more efficient because it eliminates use of costly PV cells and

alternating current (AC) inverters. It is, however, limited to large scale applications.[3]

2.1.2.1 Energy Collection

CSP research and development focuses on three types of concentrators, which use

different kinds of concentrating mirrors to convert the sun‘s energy into high temperature heat

energy:

1) Parabolic Trough

Figure 1.2 Parabolic Trough(Ref:3)

6

Parabolic trough power plants the first type of solar thermal power plant technologies

operating commercially. Nine large power plants called SEGS I to IX (Solar Electric

Generation System) were commissioned in California between 1984 and 1991. These power

plants have a nominal capacity of between 13.8 and 80 MW each, producing 354 MW in total.

The parabolic trough collector consists of large curved mirrors, which concentrate the

sunlight by a factor of 80 or more to a focal line. A series of parallel collectors are lined up in

rows 300–600 metres long. Multiple parallel rows form the solar collector field. The

collectors moved on one axis in order to follow the movement of the sun; this is called

tracking. A collector field can also be formed by long rows of parallel Fresnel collectors. In

the focal line of the collectors is a metal absorber tube, which usually is embedded into an

evacuated glass tube to reduce heat losses. A special selective coating that withstands high

temperatures reduces radiation heat losses.

In the Californian systems, thermo oil flows through the absorber tubes. These tubes

heat the oil to 400°C. A heat exchanger transfers the thermal energy from the oil to a water–

steam cycle (also called the Rankine cycle). A pump pressurizes the water and an economizer,

vaporizer and a superheater jointly produce superheated steam. This steam expands in a two-

stage turbine; between the high- and low-pressure parts of this turbine is a reheater. The

turbine itself drives an electrical generator that converts the mechanical energy into electrical

energy; the condenser after the turbine condenses the steam back to water, which allows the

closing of the cycle by feeding this water back into the initial pump.

Solar collectors can also produce superheated steam directly. This makes the thermo

oil superfluous and reduces costs due to savings associated with not using the expensive

thermo oil. Furthermore, heat exchangers are no longer needed. However, direct solar steam

generation is still at the prototype stage.

One important advantage of solar thermal power plants is that they can operate with

other means of water heating and thus a hybrid system can ensure security of supply. During

periods of insufficient irradiance, a parallel burner can be used to produce steam. Climate-

compatible fuels such as biomass or hydrogen produced by renewable energy can also fire

this parallel burner.

Figure 1.3 shows the principle of a parabolic trough solar power plant.[4]

7

Figure 1.3 Principle of a Parabolic Trough Solar Power Plant(Ref:4)

2) Central Receiver (Power Tower)

Figure 1.5 Central Receiver(Ref:3)

In the central receiver system, an array of field mirrors focus sunlight on a central

receiver mounted on a tower. To focus sunlight on the central receiver at all times, each

heliostat is mounted on a dual-axis sun tracker to seek a position in the sky that is midway

between the receiver and the sun. Compared with the parabolic trough, this technology

produces a much higher concentration and hence a higher temperature of the working

medium, usually a salt. Consequently, it yields higher Carnot efficiency and is well suited for

utility-scale power plants of tens of hundreds of megawatt capacity.

The first commercial plant is an 11 MW steam receiver plant developed by Abengoa

and inaugurated in March 2007 near Sevilla, Spain. Known as PS10, the plant has a 114-

8

meter tower and 624 heliostats, each 120 square meters. The plant uses a saturated steam

receiver and includes a 20 MWp water storage component. The developer reports a solarto-

electric conversion efficiency of 17 percent. Spain‘s electric feed-in law, set at 18 euro ¢/kWh

at all times, and EU and government subsidies for the plant totaling 6.2 million euros were the

main drivers for the plant. A 20 MW power tower plant is under construction adjacent to

PS10 at the Solúcar Solar Park. The solar field will consist of 1,255 heliostats, each 120

square meters, and a 160 meter high tower. Like PS10, the PS20 receiver will use steam

technology.[3]

Figure 1.6 Operational Schematic of Planta Solar 10 (PS10)(Ref:39)

Figure 1.7 PS10 Solar Thermal Tower Power Plant, Sevilla, Spain(Ref:39)

9

3) Parabolic Dish (Dish-Stirling Technology)

Figure 1.8 Principle of a Dish-Stirling System(Ref:38)

So-called Dish–Stirling systems can be used to generate electricity in the kilowatt

range. A parabolic concave mirror (the dish) concentrates sunlight. A two-axis tracked mirror

tracks the sun with the required high degree of accuracy. This is necessary in order to achieve

high efficiencies. The receiver at the focus is heated to 650°C. The heat absorbed drives a

Stirling motor, which converts the thermal energy into mechanical energy that is used to drive

a generator producing electricity. If sufficient sunlight is not available, combustion heat from

either fossil fuels or bio-fuels can also drive the Stirling engine and generate electricity. The

system efficiency of Dish–Stirling systems can reach 20 per cent or more. Some Dish–Stirling

system prototypes have been tested successfully in a number of countries; however, the cost

of electricity generation using these systems is much higher than that of trough or tower

power plants. Large-scale production might achieve significant cost reductions for Dish–

Stirling systems. Figure 1.8 shows the principle of a Dish–Stirling system.[4]

10

Figure 1.9 California Edison 25kW Dish-Stirling System(Ref:3)

The three alternative solar thermal technologies are compared in Table 1.1.[3]

Technology Solar Concentration Operating

Temperature

Thermodynamic

Cycle Efficiency

Parabolic Trough 100 300-500oC Low

Central Receiver 1000 500-1000 oC Moderate

Dish-Stirling 3000 800-1200 oC High

Table 1.1 Comparison of Alternative Solar Thermal Power Technologies(Ref:3)

2.1.2.2 Solar Chimney Power Plant

Figure 1.10 Principle of the Solar Chimney Power Plant(Ref:4)

11

A solar chimney power plant has a high chimney (tower), with a height of up to 1000

metres. This is surrounded by a large collector roof, up to 5000 metres in diameter, that

consists of glass or clear plastic supported on a framework. Towards its centre, the roof curves

upwards to join the chimney, creating a funnel. The sun heats up the ground and the air under

the collector roof, and the hot air follows the upward slope of the roof until it reaches the

chimney. There, it flows at high speed through the chimney and drives wind generators at the

bottom. The ground under the collector roof acts as thermal storage and can even heat up the

air for a significant time after sunset. The best efficiency of solar chimney power plants is

currently below 2 per cent. It depends mainly on the height of the tower. Due to the large area

required, these power plants can only be constructed on cheap or free land. Suitable areas

could be situated in desert regions. However, the whole power plant has additional benefits, as

the outer area under the collector roof can also be utilized as a greenhouse for agricultural

purposes. As with trough and tower plants, the minimum economic size of a solar chimney

power plant is in the multi-megawatt range. Figure 1.10 illustrates the principle of the solar

chimney power plant.[4]

In the arid flat land of southeastern Australia, EnviroMission of Melbourne has plans

for a solar wind tower (Figure 1.11). The sun-capture area is a 11-km2 glassroof enclosure.

The concrete chimney is 140 m in diameter and 1000 m tall. At the top, 32 wind turbines add

to a total capacity of 200 MW of electric power.[3]

Figure 1.11 Solar Heat Induced Wind Chimney Power Plant(Ref:37)

12

2.1.2.3 Commercial Power Plants

Commercial power plants using the solar thermal system are being explored in

capacities of a few hundred MWe. Based on the experience of operating Solar-II, the design

studies made by the National Renewable Energy Laboratory (NREL) have estimated the

performance parameters that are achievable for a 100-Mwe commercial plant. Table 1.2

summarizes these estimates and compares them with those achieved in an experimental 10-

MWe Solar-II power plant. The 100-Mwe prototype design studied showed that an overall

(solar radiation to AC electricity) conversion efficiency of 23% could be achieved in a

commercial plant using existing technology. For comparison, conventional coal thermal

plants typically operate at 40% overall efficiency, and the PV power systems have an overall

efficiency of 6 to 8% with amorphous silicon, 12 to 15% with crystalline silicon, and 20 to

25% with new thin-film multijunction PV cell technologies.

Performance Paramater Solar-II Plant 10 MWe (in

%)

Commercial Plant 100

MWe (in %)

Mirror reflectivity 90 94

Field efficiency 73 73

Mirror cleanliness 95 95

Receiver efficiency 87 87

Storage efficiency 99 99

Electromechanical

conversion efficiency of

generator

34 43

Auxiliary components

efficiency

90 93

Overall solar-to-electric

conversion efficiency

16 23

Table 1.2 Comparison of 10-MWe solar-II and 100-MWe prototype design (Ref:3)

13

The major conclusions of the studies to date are the following:

1. Designing and building plants with capacities as large as 200 MWe is possible,

based on the demonstrated technology to date. Future plants could be larger. A 200-MWe

plant would require about 3 mi2 of land.

2. The plant capacity factors up to 65% are possible.

3. About 20% of the conversion efficiency of solar radiation to AC electricity is

achievable annually

4. The thermal energy storage feature of the technology can meet peak demand on

utility lines.

5. Leveled energy cost is estimated to be 7 to 9 cents/kWh.

6. The capital cost of $2000/kWe for the first few commercial plants, and less for

future plants, is estimated. The fuel (solar heat) is free.

7. A comparable combined-cycle gas turbine plant would initially cost $1000/kWe,

and then the fuel cost would be added every year.

Compared with PV and wind power, solar thermal power technology is less modular.

Its economical size is estimated to be in the range of 100 to 300 MWe. The cost studies at

NREL have shown that a commercially designed utility-scale power plant using central

receiver power tower technology can produce electricity at a cost of 6 to 10 cents/kWh,

depending on the size. [3]

2.1.2.4 Potential Technology Developments and Recent Trends

A number of new CSP plants are under development or planned. In Spain, Abengoa is

constructing a 20 MW power tower plant next to the PS10 plant. Recent developments

include the AndaSol trough project, which is the first large-scale trough plant in Europe and

the first anywhere with molten salt storage. The salt is a mixture of 60 percent sodium nitrate

and 40 percent potassium nitrate. The Spanish government plans to have 10 GW of CSP

within the next 5 to 7 years. There are a number of upcoming projects for CSP in the United

States, particularly in California, which has an aggressive renewable portfolio standard (20

percent of investor-owned-utilities‘ loads to be served by renewables in 2010, with the same

target intended for public utilities). A number of utilities in the Southwest have formed a

consortium to pursue 250 MW of new CSP plants. The CSP industry estimates 13.4 GW

14

could be deployed for service by 2015. Purchase agreements for CSP of about 4 GW in the

United States had been signed as of February 2009, but there is probably twice that capacity

in planned projects. An evolving technology that relies on solar concentration is high-

temperature chemical processing. The concentrating component of these systems is identical

to that of concentrated solar thermal processes for power generation, but the receiver placed at

the focus of the concentrating reactor is designed to include a chemical reactor. These systems

can provide long-term storage of intermittent solar energy, such as storage in the form of fuel

or a commodity chemical. The global research community is pursuing a number of multiple-

step cycles, including production of hydrogen using water as the feedstock; decarbonization

of fossil fuels; gasification of biomass; production of metals including aluminum; and

processing and detoxification of waste. These systems are most likely to become cost-

competitive when a cost is associated directly with reduction in carbon emissions.[5]

2.1.2.5 Future Expectations

1) Short Term: Present to 2020

CSP technologies are commercially available, and in the past few years new plants

have been deployed in the United States and abroad, with trough systems dominating the U.S.

CSP market. With nearly 4 GW of signed purchase agreements and additional planned

projects, along with favorable financial policies, it is reasonable to expect significant growth

by 2020. Most of the new plants are solar-only plants and do not include fossil fuel backup

on-site. During this timeframe, with the anticipated growth rate, CSP plants will continue to

provide peaking power. With even more expanded growth, CSP technologies will probably be

hybridized with fossil fuel-fired components to share the generation portion of a fossil fuel

facility, as well as continue to serve as peaking plants.

In the short term, incremental design improvements will drive down costs and reduce

uncertainty in performance predictions. With more systems installed, there will be increased

economies of scale, both for plant sites and for manufacturing. Increasing the reflector size

and working with low-cost structures, better optics, and high-accuracy tracking may reduce

the cost of the heliostat or dish concentrators. There may also be design improvements in

receiver technology. Until 2020, long term thermal storage, extending over days rather than

15

hours, will not be a major roadblock. However, new storage technologies will be needed in

the longer term to make solar dispatchable. Storage technologies, such as concrete, graphite,

phase-change materials, molten salt, and thermocline storage, show promise. The number of

molten salt tanks providing thermal storage on the order of hours will likely increase, as

ancillary equipment such as pumps and valves are improved for greater reliability. Molten salt

receivers, which provide storage at about 550°C to power a turbine, can extend storage up to

12 hours, but there are no molten salt receiver plants at this time.

Availability of water may not be a major deterrent, as water withdrawals are not large

with CSP. However, CSP consumes at least as much water as some conventional generation

technologies. The primary water uses at a Rankine steam solar power plant are for condensate

makeup, cooling for the condenser, and washing of mirrors. Historically, parabolic trough

plants have used wet-cooling towers for cooling. With wet-cooling, the cooling tower makeup

represents approximately 90 percent of the raw water consumption. Steam cycle makeup

represents approximately 8 percent of raw water consumption, and mirror washing represents

the remaining 2 percent. Dust-resistant glass is being explored as a possible means to reduce

the mirror washing requirement.[5]

2) Medium Term: 2020 to 2035

New demands on existing transmission systems may require new or upgraded lines.

Longer-term storage on the order of days will be needed if CSP is to be a major source of

electricity. Research and development will continue to accelerate design improvement and

drive down manufacturing costs. Development of less expensive yet durable optical materials

will help control cost and water use, including selective surfaces for receivers in towers and

dishes, transparent polymeric materials that are cheaper than glass, and reflective surfaces that

prevent dust deposition.[5]

16

3) Long Term: After 2035

In the longer term, the use of concentrated solar energy to produce fuels and thus

provide storage via a number of reversible chemical reactions is promising. Fuels produced

from concentrated solar energy may provide a means of generating electricity during periods

of low insolation or at night. Much of the scientific work to date has focused on the

production of hydrogen and synthesis gas through various processes, including direct

thermolysis of water and a number of metal oxide reduction/oxidation cycles. Direct water

splitting is not feasible, because the required temperatures exceed the capability and material

limits of modern concentrating systems, and separation of the products at such temperatures is

impractical. Multiple-step metal oxide reactions are more promising. A two-step process

involves endothermic dissociation of a metal oxide (MxOy) to the metal (M) and oxygen in a

solar reactor, followed by hydrolysis of the metal to produce hydrogen and the corresponding

metal oxide. Carbothermal reduction in a solar reactor reduces the required operating

temperature and yields syngas. The process is technically feasible, but has not been

demonstrated at production scale. Gasification of cellulosic biomass is another promising

route to produce synthesis gas.[5]

2.1.3 Photovoltaics

2.1.3.1 Introduction

Photovoltaic means the direct conversion of sunlight to electricity. The common

abbreviation for photovoltaic is PV.

The history of photovoltaics goes back to the year 1839, when Becquerel discovered

the photo effect, but in that century the technology was not available to exploit this discovery.

The semiconductor age began about 100 years later. After Shockley had developed a model

for the p–n junction, Bell Laboratories produced the first solar cell in 1954. The efficiency of

this cell was about 5 per cent. Initially, cost was not a major issue, because the first cells were

designed for space applications in order to convert sunlight to electricity for earth-orbiting

satellites.

17

In the following years, solar cell efficiency increased continuously; laboratory silicon

solar cells have reached efficiencies of around 25 per cent today. The main material used in

the construction of solar cells is still silicon, but other materials have been developed, either

for their potential for cost reduction or their potential for high efficiency. Costs have

decreased significantly in recent decades; nevertheless, photovoltaic electricity generating

costs are still higher than the costs of conventional power plants. Due to high growth rates in

the photovoltaic sector, cost reduction will continue.

Photovoltaics offer the highest versatility among renewable energy technologies. One

advantage is the modularity. All desired generator sizes can be realized, from the milliwatt

range for the supply of wristwatches or pocket calculators to the megawatt range for the

public electricity supply.

Many photovoltaic applications are built into consumer appliances or relate to leisure

activities or off-grid site supply, for example, telecommunications or solar home systems. In

several countries, particularly in Japan and Germany, large governmental programmes were

initiated, advancing grid-connected installations. Tens of thousands of grid-connected systems

that have been installed since the early 1990s have proven the suitability of the technology.

The potential for photovoltaic installations is enormous. Theoretically, PV systems could

cover the whole electricity demand of most countries in the world.[4]

2.1.3.2 PV Cell

The physics of the PV cell is very similar to that of the classical diode with a pn

junction.

Figure 1.12 PV Effect Converts the Photon Energy into Voltage across the P-N Junction(Ref:3)

18

When the junction absorbs light, the energy of absorbed photons is transferred to the

electron–proton system of the material, creating charge carriers that are separated at the

junction. The charge carriers may be electron–ion pairs in a liquid electrolyte or electron–hole

pairs in a solid semiconducting material. The charge carriers in the junction region create a

potential gradient, get accelerated under the electric field, and circulate as current through an

external circuit. The square of the current multiplied by the resistance of the circuit is the

power converted into electricity. The remaining power of the photon elevates the temperature

of the cell and dissipates into the surroundings.

Figure 1.13 Basic Construction of PV Cell with Performance Enhancing Features(Ref:3)

Figure 1.13 shows the basic cell construction. Metallic contacts are provided on both

sides of the junction to collect electrical current induced by the impinging photons. A thin

conducting mesh of silver fibers on the top (illuminated) surface collects the current and lets

the light through. The spacing of the conducting fibers in the mesh is a matter of compromise

between maximizing the electrical conductance and minimizing the blockage of the light.

Conducting foil (solder) contact is provided over the bottom (dark) surface and on one edge of

the top surface. In addition to the basic elements, several enhancement features are also

included in the construction. For example, the front face of the cell has an antireflective

coating to absorb as much light as possible by minimizing the reflection. The mechanical

protection is provided by a cover glass applied with a transparent adhesive.[3]

19

1) PV Cell Technologies

In comparing alternative power generation technologies, the most important measure

is the energy cost per kilowatthour delivered. In PV power, this cost primarily depends on two

parameters: the PV energy conversion efficiency, and the capital cost per watt capacity.

Together, these two parameters indicate the economic competitiveness of the PV electricity.

The conversion efficiency of the PV cell is defined as follows:

(1.2)

The primary goals of PV cell research and development are to improve the conversion

efficiency and other performance parameters to reduce the cost of commercial solar cells and

modules. The secondary goal is to significantly improve manufacturing yields while reducing the

energy consumption and manufacturing costs, and reducing the impurities and defects.[3]

a) Crystalline Silicon Solar Cells

Historically, crystalline silicon (c-Si) has been used as the light-absorbing

semiconductor in most solar cells, even though it is a relatively poor absorber of light and

requires a considerable thickness (several hundred microns) of material. Nevertheless, it has

proved convenient because it yields stable solar cells with good efficiencies (11-16%, half to

two-thirds of the theoretical maximum) and uses process technology developed from the huge

knowledge base of the microelectronics industry.

Figure 1.14 Crystalline silicon wafers(Ref:6)

20

Two types of crystalline silicon are used in the industry. The first is monocrystalline,

produced by slicing wafers (up to 150mm diameter and 350 microns thick) from a high-purity

single crystal boule. The second is multicrystalline silicon, made by sawing a cast block of

silicon first into bars and then wafers. The main trend in crystalline silicon cell manufacture is

toward multicrystalline technology. For both mono- and multicrystalline Si, a semiconductor

homojunction is formed by diffusing phosphorus (an n-type dopant) into the top surface of the

boron doped (p-type) Si wafer. Screen-printed contacts are applied to the front and rear of the

cell, with the front contact pattern specially designed to allow maximum light exposure of the

Si material with minimum electrical (resistive) losses in the cell.

The most efficient production cells use monocrystalline c-Si with laser grooved,

buried grid contacts for maximum light absorption and current collection. Each c-Si cell

generates about 0.5V, so 36 cells are usually soldered together in series to produce a module

with an output to charge a 12V battery.[6]

b) Thin Film Solar Cells

The high cost of crystalline silicon wafers (they make up 40-50% of the cost of a

finished module) has led the industry to look at cheaper materials to make solar cells.

The selected materials are all strong light absorbers and only need to be about 1micron

thick, so material‘s costs are significantly reduced. The most common materials are

amorphous silicon (Figure 1.15) (a-Si, still silicon, but in a different form), or the

polycrystalline materials: cadmium telluride (CdTe) and copper indium (gallium) diselenide

(CISorCIGS).

Each of these three is agreeable to large area deposition (on to substrates of about 1

meter dimensions) and hence high volume manufacturing. The thin film semiconductor layers

are deposited on to either coated glass or stainless steel sheet.

Thin film technologies are all complex. They have taken at least twenty years,

supported in some cases by major corporations, to get from the stage of promising research

(about 8% efficiency at 1 cm2 scale) to the first manufacturing plants producing early product.

21

Figure 1.15 Amorphous silicon thin film(Ref:6)

Amorphous silicon is the most well-developed thin film technology to-date and has an

interesting avenue of further development through the use of "microcrystalline" silicon which

seeks to combine the stable high efficiencies of crystalline Si technology with the simpler and

cheaper large area deposition technology of amorphous silicon.

However, conventional c-Si (crystalline silicon) manufacturing technology has

continued its steady improvement year by year and its production costs are still falling too.

The emerging thin film technologies are starting to make significant in-roads in to grid

connect markets, particularly in Germany, but crystalline technologies still dominate the

market. Thin films have long held in low power (<50W) and consumer electronics

applications, and may offer particular design options for building integrated applications.[6]

c) Concentrator Cell

In an attempt to improve conversion efficiency, sunlight is concentrated tens or

hundreds of times the normal intensity by focusing on a small area using low-cost lenses

(Figure 1.16).

22

Figure 1.16 Lens Concentrating the Sunlight on a Small Area Reduces the Need for Active Cell

Material (Ref:3)

A primary advantage of this is that such a cell requires a small fraction of area

compared to the standard cells, thus significantly reducing the PV material requirement.

However, the total sunlight collection area remains approximately the same for a given power

output. Besides increasing the power and reducing the size or number of cells, the

concentrator cell has the additional advantage that the cell efficiency increases under

concentrated light up to a point. Another advantage is its small active cell area. It is easier to

produce a high-efficiency cell of small area than to produce large-area cells with comparable

efficiency. An efficiency of 37% has been achieved in a cell designed for terrestrial

applications, which is a modified version of the triple-junction cell that Spectrolab developed

for space applications. On the other hand, the major disadvantage of the concentrator cell is

that it requires focusing optics, which adds to the cost. Concentrator PV cells have seen a

recent resurgence of interest in Australia and Spain.[3]

23

2.1.3.3 Module and Array

The solar cell described previously is the basic building block of the PV power

system. Typically, it is a few square inches in size and produces about 1 W of power. To

obtain high power, numerous such cells are connected in series and parallel circuits on a panel

(module) area of several square feet (Figure 1.17).

Figure 1.17 Several PV Cells Constitute a Module and Several Modules Constitute an Array(Ref:3)

The solar array or panel is defined as a group of several modules electrically

connected in a series–parallel combination to generate the required current and voltage.

Figure 1.18 shows the actual construction of a module in a frame that can be mounted on a

structure.

24

Figure 1.18 Construction of PV Cell: (1) Frame, (2) Weatherproof Junction Box, (3) Rating Plate, (4) Weather Protection for 30 year life, (5)

PV Cell, (6) Tempered High-Transmittivity Cover Glass, (7) Outside Electrical Bus, (8) Frame Clearance. (Ref:3)

25

Mounting of the modules can be in various configurations as seen in Figure 1.19.

Figure 1.19 PV Module Mounting Methods(Ref:3)

In roof mounting, the modules are in a form that can be laid directly on the roof. In the

newly developed amorphous silicon technology, the PV sheets are made in shingles that can

replace the traditional roof shingles on a one-to-one basis, providing better economy in regard

to building material and labor.[3]

26

2.1.3.4 Array Design

The major factors influencing the electrical design of the solar array are as follows:

• The sun intensity

• The sun angle

• The load matching for maximum power

• The operating temperature

1) Sun Intensity

The magnitude of the photocurrent is maximum under a full bright sun (1.0 sun). On a

partially sunny day, the photocurrent diminishes in direct proportion to the sun intensity. At a

lower sun intensity, the I -V characteristic shifts downward as shown in Figure 1.20. On a

cloudy day, therefore, the short-circuit current decreases significantly. The reduction in the

open-circuit voltage, however, is small. The photoconversion efficiency of the cell is

insensitive to the solar radiation in the practical working range. For example, Figure 1.21

shows that the efficiency is practically the same at 500 W/m2 and at 1000 W/m

2. This means

that the conversion efficiency is the same on a bright sunny day as on a cloudy day. We get a

lower power output on a cloudy day only because of the lower solar energy impinging on the

cell. [3]

Figure 1.20 I-V Characteristic of PV module shifts down at lower sun intensity, with small reduction in

voltage(Ref:3)

27

Figure 1.21 Photoconversion efficiency vs. solar radiation

(practically constant over a widerange of radiation) (Ref:3)

2) Sun Angle

The cell output current is given by I = Iocosθ, where Io is the current with normal sun

(reference), and θ is the angle of the sun line measured from the normal. This cosine law

holds well for sun angles ranging from 0 to about 50°. Beyond 50°, the electrical output

deviates significantly from the cosine law, and the cell generates no power beyond 85°,

although the mathematical cosine law predicts 7.5% power generation (Table 1.4). The actual

power-angle curve of the PV cell, called the Kelly cosine, is shown in Figure 1.22. [3]

28

Table 1.4 Kelly cosine values of the photocurrent in silicon cells(Ref:3)

Sun angle degrees Mathematical cosine value Kelly cosine value

30 0.866 0.866

50 0.643 0.635

60 0.500 0.450

80 0.174 0.100

85 0.087 0

Figure 1.22 Kelly cosine curve for PV cell at sun angles form 0 to 90°.(Ref:3)

3) Shadow Effect

The array may consist of many parallel strings of series-connected cells. Two such

strings are shown in Figure 1.23. A large array may get partially shadowed due to a structure

interfering with the sun line. If a cell in a long series string gets completely shadowed, it loses

the photovoltage but still must carry the string current by virtue of its being in series with all

other cells operating in full sunlight. Without internally generated voltage, the shadowed cell

cannot produce power. Instead, it acts as a load, producing local I2R loss and heat. The

29

remaining cells in the string must work at higher voltage to make up the loss of the shadowed

cell voltage. A higher voltage in healthy cells means a lower string current as per the I-V

characteristic of the string. This is shown in the bottom left of Figure 1.23. The current loss is

not proportional to the shadowed area, and may go unnoticed for a mild shadow on a small

area. However, if more cells are shadowed beyond the critical limit, the I-V curve goes below

the operating voltage of the string, making the string current fall to zero, losing all the power

of the string. This causes loss of one whole string from the array.

Figure 1.23 Shadow effect on one long series string of an array

(power degradation is small until shadow exceeds the critical limit) (Ref:3)

30

Figure 1.24 Bypass diode in PV string minimizes power loss under heavy shadow(Ref:3)

The commonly used method to eliminate loss of string power due to a possible shadow

is to subdivide the circuit length in several segments with bypass diodes (Figure 1.24). The

diode across the shadowed segment bypasses only that segmentof the string. This causes a

proportionate loss of the string voltage and current, without losing the whole-string power.

Some modern PV modules come with such internally embedded bypass diodes. [3]

4) Temperature Effect

Figure 1.25 Effect of temperature on I-V characteristic

(cell produces less current but greater voltage, with net gain in the power output at cold temperatures)

(Ref:3)

31

With increasing temperature, the short-circuit current of the cell increases, whereas the

open-circuit voltage decreases (Figure 1.25). The effect of temperature on PV power is

quantitatively evaluated by examining the effects on the current and the voltage separately.

Suppose Io and Vo are the short-circuit current and the open-circuit voltage at the reference

temperature T, and α and β are their respective temperature coefficients. If the operating

temperature is increased by ΔΤ, then the new current and voltage are given by the following:

and (1.3)

Because the operating current and the voltage change approximately in the same

proportion as the short-circuit current and open-circuit voltage, respectively, the new power is

as follows:

(1.4)

This can be simplified in the following expression by ignoring a small term:

(1.5)

For a typical single-crystal silicon cell, α is about 20 μu/°C and β is about 5 mu/°C,

where u stands for unit. The power is, therefore, given by the following:

P = Po[1 + (20×10−6 − 5×10−3) ΔΤ] or P = Po[1 − 0.005⋅ΔΤ] (1.6)

This expression indicates that for every degree centigrade rise in the operating

temperature above the reference temperature, the silicon cell power output decreases by about

0.5%. Because the increase in current is much less than the decrease in voltage, the net effect

is adecrease in power at a higher operating temperature.

The effect of temperature on the power output is shown in the power vs. voltage

characteristics at two operating temperatures in Figure 1.26.

32

Figure 1.26 Effect of temperature on P-V characteristic(cell produces more power at cold

temperatures) (Ref:3)

The figure shows that the maximum power available at a lower temperature is higher

than that at a higher temperature. Thus, a cold day is actually better for the PV cell, as it

generates more power. However, the two Pmax points are not at the same voltage. In order to

extract maximum power at all temperatures, the PV system must be designed such that the

module output voltage can increase to V2 for capturing Pmax2 at a lower temperature and can

decrease to V1 for capturing Pmax1 at a higher temperature. This adds to the system-design

complexity. [3]

5) Effect of Climate

On a partly cloudy day, the PV module can produce up to 80% of its full sun power. It

can produce about 30% power even with heavy clouds on an extremely overcast day. Snow

does not usually collect on the module, because it is angled to catch the sun. If snow does

collect, it quickly melts. Mechanically, the module is designed to withstand golf-ball-size

hail.[3]

6) Electrical Load Matching

The operating point of any power system is the intersection of the source line and the

load line. If the PV source having the I-V and P-V characteristics shown in Figure 1.27(a) is

supplying power to a resistive load R1, it will operate at point A1. If the load resistance

increases to R2 or R3, the operating point moves to A2 or A3, respectively. The maximum

power is extracted from the module when the load resistance is R2 (Figure 1.27(b)). Such a

33

load that matches with the source is always necessary for the maximum power extraction

from a PV source.

Figure 1.27 Operating stability and electrical load matching with constant-resistive load and constant-

power load. (Ref:3)

The operation with a constant-power load is shown in Figure 1.27(c) and Figure

1.27(d). The constant power load line has two points of intersection with the source line,

denoted by B1 and B2. Only the point B2 is stable, as any perturbation from it generates a

restoring power to take the operation back to B2, and the system continues to operate at B2

with an inherent stability.

Therefore, the necessary condition for the electrical operating stability of the solar array is as

follows:

(1.7)

34

Some loads such as heaters have constant resistances, which absorb power that varies

with the square of the voltage. Other loads such as induction motors behave more like

constant-power loads. They draw more current at lower voltage and vice versa. In most large

systems with mixed loads, the power varies approximately in a linear proportion with voltage.

[3]

7) Sun Tracking

More energy is collected by the end of the day if the PV module is installed on a

tracker with an actuator that follows the sun. There are two types of sun trackers:

• One-axis tracker, which follows the sun from east to west during the day.

• Two-axis tracker, which follows the sun from east to west during the day, and from north to

South during the seasons of the year (Figure 1.28).

Figure 1.28 Dual-Axis sun tracker follows the sun throughout the year (Ref:3)

35

A sun-tracking design can increase the energy yield up to 40% over the year compared

to the fixed array design. Dual-axis tracking is done by two linear actuator motors, which

follow the sun within one degree of accuracy (Figure 1.28). During the day, it tracks the sun

east to west. At night it turns east to position itself for the next morning‘s sun. Old trackers

did this after sunset using a small nickel cadmium battery. The new design eliminates the

battery requirement by doing the turning in the weak light of the dusk and/or dawn. The Kelly

cosine presented in Table 1.4 is useful in assessing accurately the power available in sunlight

incident at extreme angles in the morning or evening. When a dark cloud obscures the sun, the

tracker may aim at the next brightest object, which is generally the edge of a cloud. When the

cloud is gone, the tracker aims at the sun once again, and so on and so forth. Such sun hunting

is eliminated in newer sun trackers.

Figure 1.29 Actual motor of the sun tracker(Ref:3)

One method of designing the sun tracker is to use two PV cells mounted on two 45°

wedges (Figure 1.29), and connecting them differentially in series through an actuator motor.

When the sun is normal, the currents on both cells are equal to Iocos 45°. As they are

connected in series opposition, the net current in the motor is zero, and the array stays put. On

36

the other hand, if the array is not normal to the sun, the sun angles on the two cells are

different, giving two different currents as follows:

I1 = Iocos(45 + δ) and I2 = Iocos(45 − δ) (1.8)

Figure 1.30 Sun-Tracking actuator principle. (Two differentially connected sensors at 45° generate

signals proportional to the pointing error.) (Ref:3)

The motor current is therefore:

Im = I1 – I2 = Io cos(45 + δ) – Io cos(45 − δ) (1.9)

Using Taylor series expansion:

(1.10)

we can express the two currents as follows:

I1 = Io cos 45 – Ioδ sin 45 and I2 = Io cos 45 + Ioδ sin 45 (1.11)

37

The motor current is then

Im = I1 – I2 = 2Ioδ sin45° = √2Io δ if δ is in radians (1.12)

A small pole-mounted panel can use one single-axis or dual-axis sun tracker. A large

array, on the other hand, is divided into small modules, each mounted on its own sun tracker.

This simplifies the structure and eliminates the problems related to a large movement in a

large panel. [3]

8) Peak-Power Operation

The sun tracker drives the module mechanically to face the sun to collect the

maximum solar radiation. However, that in itself does not guarantee the maximum power

output from the module. As was seen in Figure 1.26, the module must operate electrically at a

certain voltage that corresponds to the peak power point under a given operating condition.

First we examine the electrical principle of peak-power operation. If the array is operating at

any point at voltage V and current I on the I-V curve, the power generation is P = VI watts. If

the operation moves away from the preceding point such that the current is now I + ΔI, and

the voltage is V + ΔV, then the new power is as follows:

P + ΔP = (V + ΔV)(I + ΔI) (1.13)

which, after ignoring a small term, simplifies to the following:

ΔP = ΔV⋅I + ΔI⋅V (1.14)

ΔP would be zero if the array were operating at the peak power point, which

necessarily lies on a locally flat neighborhood. Therefore, at the peak power point, the

preceding expression in the limit becomes:

(1.15)

38

We note here that dV/dI is the dynamic impedance of the source, and V/I the static

impedance. Thus, at the peak power point, the following relation holds:

Dynamic impedance Zd = –static impedance Zs (1.16)

There are three electrical methods of extracting the peak power from a PV source, as

described in the following text:

1. In the first method, a small signal current is periodically injected into the array bus,

and the dynamic bus impedance (Zd = dV/dI) and the static bus impedance (Zs = V/I) are

measured. The operating voltage is then increased or decreased until Zd equals −Zs. At this

point, the maximum power is extracted from the source.

2. In another method, the operating voltage is increased as long as dP/dV is positive.

That is, the voltage is increased as long as we get more power. If dP/dV is sensed negative,

the operating voltage is decreased. The voltage stays the same if dP/dV is near zero within a

preset deadband.

3. The third method makes use of the fact that for most PV cells, the ratio of the

voltage at the maximum power point to the open-circuit voltage (i.e. Vmp/Voc) is

approximately constant, say K. For example, for highquality crystalline silicon cells, K =

0.72. An unloaded cell is installed on the array and kept in the same environment as the

power-producing cells, and its open-circuit voltage is continuously measured. The operating

voltage of the power-producing array is then set at K·Voc, which will produce the maximum

power. [3]

9) System Components

The array by itself does not constitute the PV power system. We may also need a

structure to mount it, a sun tracker to point the array to the sun, various sensors to monitor

system performance, and power electronic components that accept the DC power produced by

the array, charge the battery, and condition the remaining power in a form that is usable by the

load. If the load is AC, the system needs an inverter to convert the DC power into AC at 50 or

60 Hz.

39

Figure 1.31 shows the necessary components of a stand-alone PV power system. The

peak-power tracker senses the voltage and current outputs of the array and continuously

adjusts the operating point to extract the maximum power under varying climatic conditions.

The output of the array goes to the inverter, which converts the DC into AC. The array output

in excess of the load requirement is used to charge the battery. The battery charger is usually a

DC–DC buck converter. If excess power is still available after fully charging the battery, it is

shunted in dump heaters, which may be a room or water heater in a stand-alone system. When

the sun is not available, the battery discharges to the inverter to power the load. The battery

discharge diode Db is to prevent the battery from being charged when the charger is opened

after a full charge or for other reasons. The array diode Da is to isolate the array from the

battery, thus keeping the array from acting as the load on the battery at night. The mode

controller collects system signals, such as the array and the battery currents and voltages, and

keeps track of the battery state of charge by bookkeeping the charge/discharge ampere hours.

It uses this information to turn on or off the battery charger, discharge converter, and dump

loads as needed. Thus, the mode controller is the central controller of the entire system.

Figure 1.31 Peak-power-tracking PV power system showing major components(Ref:3)

In the grid-connected system, dump heaters are not required, as all excess power is

always fed to the grid lines. The battery is also eliminated, except for a few small critical

loads, such as the start-up controller and the computer. DC power is first converted into AC

by the inverter, ripples are filtered, and only then is the filtered power fed into the grid lines.

In the PV system, the inverter is a critical component, which converts the array DC power

40

into AC for supplying the loads or interfacing with the grid. A new product line recently

introduced into the market is the AC PV module, which integrates a inverter directly into

module design. It is presently available in a few hundred watts capacity. It provides utility-

grade 60-Hz power directly from the module junction box. This greatly simplifies PV system

design. [3]

2.1.3.5 Power Electronics for Photovoltaic Power Systems

Photovoltaic power systems can be classified as:

• Stand-alone PV systems.

• Hybrid PV systems.

• Grid-connected PV systems.

Stand-alone PV systems, shown in Fig. 1.32, are used in remote areas with no access

to a utility grid.

Figure 1.32 Stand-alone PV System(Ref:7)

Conventional power systems used in remote areas often based on manually controlled

diesel generators operating continuously or for a few hours. Extended operation of diesel

generators at low load levels significantly increases maintenance costs and reduces their

useful life. Renewable energy sources such as PV can be added to remote area power systems

using diesel and other fossil fuel powered generators to provide 24-hour power economically

41

and efficiently. Such systems are called ―hybrid energy systems.‖ Figure 1.33 shows a

schematic of a PV-diesel hybrid system.

Figure 1.33 PV-diesel Hybrid System(Ref:7)

In grid connected PV systems shown in Fig. 1.34, PV panels are connected to a grid

through inverters without battery storage.

Figure 1.34 Grid-connected PV System(Ref:7)

These systems can be classified as small systems like the residential rooftop systems

or large grid-connected systems. The grid-interactive inverters must be synchronized with the

grid in terms of voltage and frequency.[7]

1) Stand-alone PV Systems

The two main stand-alone PV applications are:

• Battery charging.

• Solar water pumping.

42

1.1) Battery Charging

1.1.1) Batteries for PV Systems

Stand-alone PV energy system requires storage to meet the energy demand during

periods of low solar irradiation and nighttime. Several types of batteries are available such as

the lead acid, nickel– cadmium, lithium, zinc bromide, zinc chloride, sodium sulfur, nickel–

hydrogen, redox, and vanadium batteries. The provision of cost-effective electrical energy

storage remains one of the major challenges for the development of improved PV power

systems. Typically, lead-acid batteries are used to guarantee several hours to a few days of

energy storage. Their reasonable cost and general availability has resulted in the widespread

application of lead-acid batteries for remote area power supplies despite their limited lifetime

compared to other system components. Lead-acid batteries can be deep or shallow cycling

gelled batteries, batteries with captive or liquid electrolyte, sealed and non-sealed batteries

etc. Sealed batteries are valve regulated to permit evolution of excess hydrogen gas (although

catalytic converters are used to convert as much evolved hydrogen and oxygen back to water

as possible). Sealed batteries need less maintenance. The following factors are considered in

the selection of batteries for PV applications:

• Deep discharge (70–80% depth of discharge).

• Low charging/discharging current.

• Long duration charge (slow) and discharge (long duty

cycle).

• Irregular and varying charge/discharge.

• Low self discharge.

• Long life time.

• Less maintenance requirement.

• High energy storage efficiency.

• Low cost.

Battery manufacturers specify the nominal number of complete charge and discharge

cycles as a function of the depth-of-discharge (DOD), as shown in Fig. 1.35. While this

information can be used reliably to predict the lifetime of lead-acid batteries in conventional

43

applications, such as uninterruptable power supplies or electric vehicles, it usually results in

an overestimation of the useful life of the battery bank in renewable energy systems.

Figure 1.35 Nominal Number of Battery Cycles vs DOD(Ref:7)

Two of the main factors that have been identified as limiting criteria for the cycle life

of batteries in PV power systems are incomplete charging and prolonged operation at a low

state-of-charge (SOC). The objective of improved battery control strategies is to extend the

lifetime of lead-acid batteries to achieve a typical number of cycles shown in Fig. 1.35. If this

is achieved, an optimum solution for the required storage capacity and the maximum DOD of

the battery can be found by referring to manufacturer‘s information. Increasing the capacity

will reduce the typical DOD and therefore prolong the battery lifetime. Conversely, it may be

more economic to replace a smaller battery bank more frequently.[7]

1.1.2) PV Charge Controllers

Blocking diodes in series with PV modules are used to prevent the batteries from

being discharged through the PV cells at night when there is no sun available to generate

energy. These blocking diodes also protect the battery from short circuits. In a solar power

system consisting of more than one string connected in parallel, if a short circuit occurs in one

44

of the strings, the blocking diode prevents the other PV strings to discharge through the

shortcircuited string.

The battery storage in a PV system should be properly controlled to avoid catastrophic

operating conditions like overcharging or frequent deep discharging. Storage batteries account

for most PV system failures and contribute significantly to both the initial and the eventual

replacement costs. Charge controllers regulate the charge transfer and prevent the battery

from being excessively charged and discharged. Three types of charge controllers are

commonly used:

• Series charge regulators.

• Shunt charge regulators.

• DC–DC converters.

1.1.2.1) A Series Charge Regulators

The basic circuit for the series regulators is given in Fig. 1.36. In the series charge

controller, the switch S1 disconnects the PV generator when a predefined battery voltage is

achieved. When the voltage reduces below the discharge limit, the load is disconnected from

the battery to avoid deep discharge beyond the limit. The main problem associated with this

type of controller is the losses associated with the switches. This extra power loss has to come

from the PV power and this can be quite significant. Bipolar transistors, metal oxide semi

conductor field effect transistors (MOSFETs), or relays are used as the switches.[7]

Figure 1.36 Series Charge Regulator(Ref:7)

45

1.1.2.2) Shunt Charge Regulators

In this type, as illustrated in Fig. 1.37, when the battery is fully charged the PV

generator is short-circuited using an electronic switch (S1). Unlike series controllers, this

method works more efficiently even when the battery is completely discharged as the short-

circuit switch need not be activated until the battery is fully discharged.

The blocking diode prevents short-circuiting of the battery. Shunt-charge regulators

are used for the small PV applications (less than 20 A).

Deep discharge protection is used to protect the battery against the deep discharge.

When the battery voltage reaches below the minimum set point for deep discharge limit,

switch S2 disconnects the load. Simple series and shunt regulators allow only relatively

coarse adjustment of the current flow and seldom meet the exact requirements of PV

systems.[7]

Figure 1.37 Shunt Charge Regulator(Ref:7)

1.1.2.3) DC-DC Converter Type Charge Regulators

Switch mode DC-to-DC converters are used to match the output of a PV generator to a

variable load. There are various types of DC–DC converters such as:

• Buck (step-down) converter.

• Boost (step-up) converter.

• Buck–boost (step-down/up) converter.

46

Figures 1.38–1.40 show simplified diagrams of these three basic types converters. The

basic concepts are an electronic switch, an inductor to store energy, and a ―flywheel‖ diode,

which carries the current during that part of switching cyclewhen the switch is off. The DC–

DC converters allow the charge current to be reduced continuously in such a way that the

resulting battery voltage is maintained at a specified value.[7]

Figure 1.38 Buck Converter(Ref:7)

Figure 1.39 Boost Converter(Ref:7)

Figure 1.40 Buck-Boost Converter(Ref:7)

47

1.1.3) Maximum Power Point Tracking (MPPT)

A controller that tracks the maximum power point locus of the PV array is known as

the MPPT. In Fig. 1.41, the PV power output is plotted against the voltage for insolation

levels from 200 to 1000W/m2. The points of maximum array power form a curve termed as

the maximum power locus. Due to high cost of solar cells, it is necessary to operate the PV

array at its maximum power point (MPP). For overall optimal operation of the system, the

load line must match the PV array‘s MPP locus.

Figure 1.41 Typical Power/Voltage Characteristics for Increased Insolation(Ref:7)

Referring to Fig. 1.42, the load characteristics can be either curve OA or curve OB

depending upon the nature of the load and it‘s current and voltage requirements. If load OA is

considered and the load is directly coupled to the solar array, the array will operate at point

A1, delivering only power P1. The maximum array power available at the given insolation is

P2. In order to use PV array power P2, a power conditioner coupled between array and the

load is needed.

48

Figure 1.42 PV Array and Load Characteristics(Ref:7)

There are generally two ways of operating PV modules at maximum power point. These ways

take advantage of analog and/or digital hardware control to track the MPP of PV arrays.[7]

1.1.4) Analog Control

There are many analog control mechanisms proposed in different articles. For

instance, fractional short-circuit current (Isc), fractional open-circuit voltage (VOP), and ripple

correlation control (RCC).

Fractional open-circuit voltage (VOP) is one of the simple analogue control method. It

is based on the assumption that the maximum power point voltage, VMPP, is a linear function

of the open-circuit voltage, VOC. For example VMPP = kVOC where k ≈ 0.76. This assumption is

reasonably accurate even for large variations in the cell short-circuit current and temperature.

This type of MPPT is probably the most common type. A variation to this method involves

periodically open-circuiting the cell string and measuring the open-circuit voltage. The

appropriate value of VMPP can then be obtained with a simple voltage divider.[7]

49

1.1.5) Digital Control

There are many digital control mechanisms that were proposed in different articles.

For instance, perturbation and observation (P&O) or hill climbing, fuzzy logic, neural

network, and incremental conductance (IncCond).

The P&O or hill climbing control involves around varying the input voltage around

the optimum value by giving it a small increment or decrement alternately. The effect on the

output power is then assessed and a further small correction is made to the input voltage.

Therefore, this type of control is called a hill climbing control. The power output of the PV

array is sampled at an every definite sampling period and compared with the previous value.

In the event, when power is increased then the solar array voltage is stepped in the same

direction as the previous sample time, but if the power is reduced then the array voltage is

stepped in the opposite way and try to operate the PV array at its optimum/maximum power

point.

To operate the PV array at the MPP, perturb and adjust method can be used at regular

intervals. Current drawn is sampled every few seconds and the resulting power output of the

solar cells is monitored at regular intervals. When an increased current results in a higher

power, it is further increased until power output starts to reduce. But if the increased PV

current results in lesser amount of power than in the previous sample, then the current is

reduced until the MPP is reached.[7]

1.2) Inverters for Stand-alone PV Systems

Inverters convert power from DC to AC while rectifiers convert it from AC to DC.

Many inverters are bi-directional, i.e. they are able to operate in both inverting and rectifying

modes. In many stand-alone PV installations, alternating current is needed to operate 230V

(or 110 V), 50 Hz (or 60 Hz) appliances. Generally stand-alone inverters operate at 12, 24, 48,

96, 120, or 240V DC depending upon the power level. Ideally, an inverter for a stand-alone

PV system should have the following features:

• Sinusoidal output voltage.

• Voltage and frequency within the allowable limits.

• Cable to handle large variation in input voltage.

50

• Output voltage regulation.

• High efficiency at light loads.

• Less harmonic generation by the inverter to avoid damage to electronic appliances like

television, additional losses, and heating of appliances.

• Photovoltaic inverters must be able to withstand overloading for short term to take care of

higher starting currents from pumps, refrigerators, etc.

• Adequate protection arrangement for over/under-voltage and frequency, short circuit etc.

• Surge capacity.

• Low idling and no load losses.

• Low battery voltage disconnect.

• Low audio and radio frequency (RF) noise.

Several different semiconductor devices such as metal oxide semiconductor field

effect transistor (MOSFETs) and insulated gate bipolar transistors (IGBTs) are used in the

power stage of inverters. Typically MOSFETs are used in units up to 5 kVA and 96V DC.

They have the advantage of low switching losses at higher frequencies. Because the on-state

voltage drop is 2V DC, IGBTs are generally used only above 96V DC systems.

Voltage source inverters are usually used in stand-alone applications. They can be

single phase or three phase. There are three switching techniques commonly used: square

wave, quasi-square wave, and pulse width modulation. Square-wave or modified square-wave

inverters can supply power tools, resistive heaters, or incandescent lights, which do not

require a high quality sine wave for reliable and efficient operation. However, many

household appliances require low distortion sinusoidal waveforms. The use of true sine-wave

inverters is recommended for remote area power systems. Pulse width modulated (PWM)

switching is generally used for obtaining sinusoidal output from the inverters.

A general layout of a single-phase system, both half bridge and full bridge, is shown in

Fig. 1.43. In Fig. 1.43(a), singlephase half bridge is with two switches, S1 and S2, the

capacitors C1 and C2 are connected in series across the DC source. The junction between the

capacitors is at the mid-potential. Voltage across each capacitor is Vdc /2. Switches S1 and S2

can be switched on/off periodically to produce AC voltage. Filter (Lf and Cf ) is used to

reduce high-switch frequency components and to produce sinusoidal output from the inverter.

The output of inverter is connected to load through a transformer. Figure 1.43(b) shows the

similar arrangement for full-bridge configuration with four switches. For the same input

51

source voltage, the full-bridge output is twice and the switches carry less current for the same

load power.

Figure 1.43 Single-phase Inverter: (a)Half Bridge, (b)Full Bridge(Ref:7)

The power circuit of a three phase four-wire inverter is shown in Fig. 1.44. The output

of the inverter is connected to load via three-phase transformer (delta/Y). The star point of the

transformer secondary gives the neutral connection. Three phase or single phase can be

connected to this system. Alternatively, a center tap DC source can be used to supply the

converter and the mid-point can be used as the neutral.

Figure 1.44 A Stand-alone Three-Phase Four Wire Inverter(Ref:7)

52

Figure 1.45 shows the inverter efficiency for a typical inverter used in remote area

power systems. It is important to consider that the system load is typically well below the

nominal inverter capacity Pnom, which results in low conversion efficiencies at loads below

10% of the rated inverter output power. Optimum overall system operation is achieved if the

total energy dissipated in the inverter is minimized. The high conversion efficiency at low

power levels of recently developed inverters for grid connected PV systems shows that there

is a significant potential for further improvements in efficiency.

Figure 1.45 Typical Inverter Efficiency Curve(Ref:7)

Bi-directional inverters convert DC power to AC power (inverter) or AC power to DC

power (rectifier) and are becoming very popular in remote area power systems. The principle

of a stand-alone single-phase bi-directional inverter used in a PV/battery/diesel hybrid system

can be explained by referring Fig. 1.46. A charge controller is used to interface the PV array

and the battery. The inverter has a full-bridge configuration realized using four power

electronic switches (MOSFET or IGBTs) S1–S4. In this scheme, the diagonally opposite

switches (S1, S4) and (S2, S3) are switched using a sinusoidally PWM gate pulses. The

inverter produces sinusoidal output voltage. The inductors X1, X2, and the AC output

capacitor C2 filter out the high-switch frequency components from the output waveform.

53

Most inverter topologies use a low frequency (50 or 60 Hz) transformer to step up the inverter

output voltage. In this scheme, the diesel generator and the converter are connected in parallel

to supply the load. The voltage sources, diesel and inverter, are separated by the link inductor

Xm. The bi-directional power flow between inverter and the diesel generator can be

established.

Figure 1.46 Bi-directional Inverter System(Ref:7)

The power flow through the link inductor, Xm, is

(1.17)

(1.18)

(1.19)

(1.20)

where δ is the phase angle between the two voltages. From Eq. (1.18), it can be seen that the

power supplied by the inverter from the batteries (inverter mode) or supplied to the batteries

(charging mode) can be controlled by controlling the phase angle δ. The PWM pulses

separately control the amplitude of the converter voltage, Vc , while the phase angle with

respect to the diesel voltage is varied for power flow.[7]

54

2) Hybrid Systems

The combination of RES, such as PV arrays or wind turbines, with engine-driven

generators and battery storage, is widely recognized as a viable alternative to conventional

remote area power supplies (RAPS). These systems are generally classified as hybrid energy

systems (HES). They are used increasingly for electrification in remote areas where the cost

of grid extension is prohibitive and the price for fuel increases drastically with the remoteness

of the location. For many applications, the combination of renewable and conventional energy

sources compares favorably with fossil fuel-based RAPS systems, both in regard to their cost

and technical performance. Because these systems employ two or more different sources of

energy, they enjoy a very high degree of reliability as compared to single-source systems such

as a stand-alone diesel generator or a stand-alone PV or wind system. Applications of hybrid

energy systems range from small power supplies for remotehouseholds, providing electricity

for lighting and other essential electrical appliances, to village electrification for remote

communities has been reported.

Hybrid energy systems generate AC electricity by combining RES such as PV array

with an inverter, which can operate alternately or in parallel with a conventional enginedriven

generator. They can be classified according to their configuration as:

• Series hybrid energy systems.

• Switched hybrid energy systems.

• Parallel hybrid energy systems.

The parallel hybrid systems can be further divided to DC or AC coupling.

2.1) Series Configuration

In the conventional series hybrid systems shown in Fig. 27.28, all power generators

feed DC power into a battery. Each component has therefore to be equipped with an

individual charge controller and in the case of a diesel generator with a rectifier.

To ensure reliable operation of series hybrid energy systems both the diesel generator

and the inverter have to be sized to meet peak loads. This results in a typical system operation

where a large fraction of the generated energy is passed through the battery bank, therefore

resulting in increased cycling of the battery bank and reduced system efficiency. AC power

55

delivered to the load is converted from DC to regulated AC by an inverter or a motor

generator unit. The power generated by the diesel generator is first rectified and subsequently

converted back to AC before being supplied to the load, which incurs significant conversion

losses.

Figure 1.47 Series Hybrid Energy System(Ref:7)

The actual load demand determines the amount of electrical power delivered by the

PV array, wind generator, the battery bank, or the diesel generator. The solar and wind

charger prevents overcharging of the battery bank from the PV generatorwhen the PV power

exceeds the load demand and the batteries are fully charged. It may include MPPT to improve

the utilization of the available PV energy, although the energy gain is marginal for a well-

sized system. The system can be operated in manual or automatic mode, with the addition of

appropriate battery voltage sensing and start/stop control of the engine-driven generator.

56

Advantages:

• The engine-driven generator can be sized to be optimally loaded while supplying the load

and charging the battery bank, until a battery SOC of 70–80% is reached.

• No switching of AC power between the different energy sources is required, which

simplifies the electrical output interface.

• The power supplied to the load is not interrupted when the diesel generator is started.

• The inverter can generate a sine-wave, modified squarewave, or square-wave depending on

the application.

Disadvantages:

• The inverter cannot operate in parallel with the enginedriven generator, therefore the

inverter must be sized to supply the peak load of the system.

• The battery bank is cycled frequently, which shortens its lifetime.

• The cycling profile requires a large battery bank to limit the depth-of-discharge (DOD).

• The overall system efficiency is low, since the diesel cannot supply power directly to the

load.

• Inverter failure results in complete loss of power to the load, unless the load can be supplied

directly from the diesel generator for emergency purposes.[7]

2.2) Switched Configuration

Despite its operational limitations, the switched configuration remains one of the most

common installations in some developing countries. It allows operation with either the

engine-driven generator or the inverter as the AC source, yet no parallel operation of the main

generation sources is possible. The diesel generator and the RES can charge the battery bank.

The main advantage compared with the series system is that the load can be supplied directly

by the engine-driven generator, which results in a higher overall conversion efficiency.

Typically, the diesel generator power will exceed the load demand, with excess energy being

used to recharge the battery bank. During periods of low electricity demand the diesel

generator is switched off and the load is supplied from the PV array together with stored

energy.

57

Switched hybrid energy systems can be operated in manual mode, although the increased

complexity of the system makes it highly desirable to include an automatic controller, which

can be implemented with the addition of appropriate battery voltage sensing and start/stop

control of the engine-driven generator (Fig. 1.48).

Figure 1.48 Switched PV-diesel Hybrid Energy System(Ref:7)

Advantages:

• The inverter can generate a sine-wave, modified squarewave, or square-wave, depending on

the particular application.

• The diesel generator can supply the load directly, therefore improving the system efficiency

and reducing the fuel consumption.

Disadvantages:

• Power to the load is interrupted momentarily when the AC power sources are transferred.

• The engine-driven alternator and inverter are typically designed to supply the peak load,

which reduces their efficiency at part load operation.[7]

58

2.3) Parallel Configuration

The parallel hybrid system can be further classified as DC and AC couplings as shown

in Fig. 1.49. In both schemes, a bi-directional inverter is used to link between the battery and

an AC source (typically the output of a diesel generator). The bi-directional inverter can

charge the battery bank (rectifier operation) when excess energy is available from the diesel

generator or by the renewable sources, as well as act as a DC–AC converter (inverter

operation). The bi-directional inverter may also provide ―peak shaving‖ as part of a control

strategy when the diesel engine is overloaded. In Fig. 1.49(a), the renewable energy sources

(RES) such as photovoltaic and wind are coupled on the DC side. DC integration of RES

results in ―custom‖ system solutions for individual supply cases requiring high costs for

engineering, hardware, repair, and maintenance. Furthermore, power system expandability for

covering needs of growing energy and power demand is also difficult. A better approach

would be to integrate the RES on the AC side rather than on the DC side as shown in Fig.

1.49(b).

Figure 1.49 Parallel PV-diesel Hybrid Energy System: (a) DC Decoupling, (b) AC Coupling(Ref:7)

59

Parallel hybrid energy systems are characterized by two significant improvements over

the series and switched system configuration.

The inverter plus the diesel generator capacity rather than their individual component

ratings limit the maximum load that can be supplied. Typically, this will lead to a doubling of

the system capacity. The capability to synchronize the inverter with the diesel generator

allows greater flexibility to optimize the operation of the system. Future systems should be

sized with a reduced peak capacity of the diesel generator, which results in a higher fraction

of directly used energy and hence higher system efficiencies.

By using the same power electronic devices for both inverter and rectifier operation,

the number of system components is minimized. Additionally, wiring and system installation

costs are reduced through the integration of all power-conditioning devices in one central

power unit. This highly integrated system concept has advantages over a more modular

approach to system design, but it may prevent convenient system upgrades when the load

demand increases.

The parallel configuration offers a number of potential advantages over other system

configurations. These objectives can only be met if the interactive operation of the individual

components is controlled by an ―intelligent‖ hybrid energy management system. Although

today‘s generation of parallel systems include system controllers of varying complexity and

sophistication, they do not optimize the performance of the complete system. Typically, both

the diesel generator and the inverter are sized to supply anticipated peak loads. As a result

most parallel hybrid energy systems do not utilize their capability of parallel, synchronized

operation of multiple power sources.

Advantages:

• The system load can be met in an optimal way.

• Diesel generator efficiency can be maximized.

• Diesel generator maintenance can be minimized.

• A reduction in the rated capacities of the diesel generator, battery bank, inverter, and

renewable resources is feasible, while also meeting the peak loads.

60

Disadvantages:

• Automatic control is essential for the reliable operation of the system.

• The inverter has to be a true sine-wave inverter with the ability to synchronize with a

secondary AC source.

• System operation is less transparent to the untrained user of the system.[7]

2.4) Control of Hybrid Energy Systems

The design process of hybrid energy systems requires the selection of the most

suitable combination of energy sources, power-conditioning devices, and energy storage

system together with the implementation of an efficient energy dispatch strategy. System

simulation software is an essential tool to analyze and compare possible system combinations.

The objective of the control strategy is to achieve optimal operational performance at the

system level. Inefficient operation of the diesel generator and ―dumping‖ of excess energy is

common for many RAPS, operating in the field. Component maintenance and replacement

contributes significantly to the lifecycle cost of systems. These aspects of system operation

are clearly related to the selected control strategy and have to be considered in the system

design phase.

Figure 1.50 Operating Modes for a PV Single-diesel Hybrid Energy System(Ref:7)

61

Advanced system control strategies seek to reduce the number of cycles and the DOD

for the battery bank, run the diesel generator in its most efficient operating range, maximize

the utilization of the renewable resource, and ensure high reliability of the system. Due to the

varying nature of the load demand, the fluctuating power supplied by the photovoltaic

generator, and the resulting variation of battery SOC, the hybrid energy system controller has

to respond to continuously changing operating conditions. Figure 1.50 shows different

operating modes for a PV single-diesel system using a typical diesel dispatch strategy.

Mode (I): The base load, which is typically experienced at nighttime and during the early

morning hours, is supplied by energy stored in the batteries. Photovoltaic power is not

available and the diesel generator is not started.

Mode (II): PV power is supplemented by stored energy to meet the medium load demand.

Mode (III): Excess energy is available from the PV generator, which is stored in the battery.

The medium load demand is supplied from the PV generator.

Mode (IV): The diesel generator is started and operated at its nominal power to meet the high

evening load. Excess energy available from the diesel generator is used to recharge the

batteries.

Mode (V): The diesel generator power is insufficient to meet the peak load demand.

Additional power is supplied from the batteries by synchronizing the inverter AC output

voltage with the alternator waveform.

Mode (VI): The diesel generator power exceeds the load demand, but it is kept operational

until the batteries are recharged to a high SOC level.

In principle, most efficient operation is achieved if the generated power is supplied

directly to the load from all energy sources, which also reduces cycling of the battery bank.

However, since diesel generator operation at light loads is inherently inefficient, it is common

practice to operate the engine-driven generator at its nominal power rating and to recharge the

batteries from the excess energy. The selection of the most efficient control strategy depends

62

on fuel, maintenance and component replacement cost, the system configuration,

environmental conditions, as well as constraints imposed on the operation of the hybrid

energy system.[7]

3) Grid-connected PV Systems

The utility interactive inverters not only conditions the power output of the PV arrays

but ensures that the PV system output is fully synchronized with the utility power. These

systems can be battery less or with battery backup. Systems with battery storage (or flywheel)

provide additional power supply reliability. The grid connection of PV systems is gathering

momentum because of various rebate and incentive schemes. This system allows the

consumer to feed its own load utilizing the available solar energy and the surplus energy can

be injected into the grid under the energy by back scheme to reduce the payback period. Grid-

connected PV systems can become a part of the utility system. The contribution of solar

power depends upon the size of system and the load curve of the house. When the PV system

is integrated with the utility grid, a two-way power flow is established. The utility grid will

absorb excess PV power and will feed the house during nighttime and at instants while the PV

power is inadequate. The utility companies are encouraging this scheme in many parts of the

world.

The grid-connected system can be classified as:

• Rooftop application of grid-connected PV system.

• Utility scale large system.

For small household PV applications, a roof mounted PV array can be the best option.

Solar cells provide an environmentally clean way of producing electricity, and rooftops have

always been the ideal place to put them. With a PV array on the rooftop, the solar generated

power can supply residential load. The rooftop PV systems can help in reducing the peak

summer load to the benefit of utility companies by feeding the household lighting, cooling,

and other domestic loads. The battery storage can further improve the reliability of the system

at the time of low insolation level, nighttime, or cloudy days. But the battery storage has some

inherent problems like maintenance and higher cost.

63

For roof-integrated applications, the solar arrays can be either mounted on the roof or

directly integrated into the roof. If the roof integration does not allow for an air channel

behind the PV modules for ventilation purpose, then it can increase the cell temperature

during the operation consequently leading to some energy losses. The disadvantage with the

rooftop application is that the PV array orientation is dictated by the roof. In case, when the

roof orientation differs from the optimal orientation required for the cells, then efficiency of

the entire system would be suboptimal.

Utility interest in PV has centered on the large gridconnected PV systems. In

Germany, USA, Spain, and in several other parts of the world, some large PV scale plants

have been installed. The utilities are more inclined with large scale, centralized power supply.

The PV systems can be centralized or distributed systems.

Grid-connected PV systems must observe the islanding situation, when the utility

supply fails. In case of islanding, the PV generators should be disconnected from mains. PV

generators can continue to meet only the local load, if the PV output matches the load. If the

grid is re-connected during islanding, transient overcurrents can flow through the PV system

inverters and the protective equipments like circuit breakers may be damaged. The islanding

control can be achieved through inverters or via the distribution network. Inverter controls can

be designed on the basis of detection of grid voltage, measurement of impedance, frequency

variation, or increase in harmonics. Protection shall be designed for the islanding, short

circuits, over/under-voltages/currents, grounding, and lightening, etc.

The importance of the power generated by the PV system depends upon the time of

the day specially when the utility is experiencing the peak load. The PV plants are well suited

to summer peaking but it depends upon the climatic condition of the site. PV systems being

investigated for use as peaking stations would be competitive for load management. The PV

users can defer their load by adopting load management to get the maximum benefit out of the

grid-connected PV plants and feeding more power into the grid at the time of peak

load.

The assigned capacity credit is based on the statistical probability with which the grid

can meet peak demand. The capacity factor during the peaks is very similar to that of

conventional

plants and similar capacity credit can be given for the PV generation except at the times when

the PV plants are generating very less power unless adequate storage is provided. With the

64

installation of PV plants, the need of extra transmission lines, transformers can be delayed or

avoided. The distributed PV plants can also contribute in providing reactive power support to

the grid and reduce burden on VAR compensators.[7]

3.1) Inverters for Grid-connected Applications

Power conditioner is the key link between the PV array and mains in the grid-

connected PV system. It acts as an interface that converts DC current produced by the solar

cells into utility grade AC current. The PV system behavior relies heavily on the power-

conditioning unit. The inverters shall produce good quality sine-wave output. The inverter

must follow the frequency and voltage of the grid and the inverter has to extract maximum

power from the solar cells with the help of MPPT and the inverter input stage varies the input

voltage until the MPP on the I–V curve is found. The inverter shall monitor all the phases of

the grid. The inverter output shall be controlled in terms of voltage and frequency variation. A

typical grid-connected inverter may use a PWM scheme and operates in the range of 2–20

kHz.[7]

3.2) Inverter Classifications

The inverters used for the grid interfacing are broadly classified as:

• Voltage source inverters (VSI).

• Current source inverters (CSI).

Whereas the inverters based on the control schemes can be classified as:

• Current controlled (CC).

• Voltage controlled (VC).

The source is not necessarily characterized by the energy source for the system. It is a

characteristic of the topology of the inverter. It is possible to change from one source type to

another source type by the addition of passive components.

In the voltage source inverter (VSI), the DC side is made to appear to the inverter as a voltage

source. The VSIs have a capacitor in parallel across the input whereas the CSIs have an

inductor is series with the DC input. In the CSI, the DC source appears as a current source to

65

the inverter. Solar arrays are fairly good approximation to a current source. Most PV inverters

are voltage source even though the PV is a current source. Current source inverters are

generally used for large motor drives though there have been some PV inverters built using a

current source topology. The VSI is more popular with the PWM VSI dominating the sine-

wave inverter topologies.

Figure 1.51(a) shows a single-phase full-bridge bi-directional VSI with (a) voltage

control and phase-shift (δ) control – voltage-controlled voltage source inverter (VCVSI). The

active power transfer from the PV panels is accomplished by controlling the phase angle δ

between the converter voltage and the grid voltage. The converter voltage follows the grid

voltage.

Figure 1.51(b) shows the same VSI operated as a current controlled (CCVSI). The

objective of this scheme is to control active and reactive components of the current fed into

the grid using PWM techniques.[7]

Figure 1.51 Voltage Source Inverter: (a)Voltage Control, (b)Current Control(Ref:7)

66

3.3) Inverter Types

Different types are being in use for the grid-connected PV applications such as:

• Line-commutated inverter.

• Self-commutated inverter.

• Inverter with high-frequency transformer.

3.3.1) Line-commutated Inverter

The line-commutated inverters are generally used for the electric motor applications.

The power stage is equipped with thyristors. The maximum power tracking control is required

in the control algorithm for solar application. The basic diagram for a single-phase

linecommutated inverter is shown in the Fig. 1.52.

Figure 1.52 Line-commutated Single Phase Inverter(Ref:7)

The driver circuit has to be changed to shift the firing angle from the rectifier

operation (0 < φ < 90) to inverter operation (90 < φ < 180). Six-pulse or 12-pulse inverter are

used for the grid interfacing but 12-pulse inverters produce less harmonics. The thysistor type

inverters require a low impedance grid interface connection for commutation purpose. If the

maximum power available from the grid connection is less than twice the rated PV inverter

power, then the line-commutated inverter should not be used. The line-commutated inverters

are cheaper but inhibits poor power quality. The harmonics injected into the grid can be large

unless taken care of by employing adequate filters. These line-commutated inverters also have

poor power factor, poor power quality, and need additional control to improve the power

67

factor. Transformer can be used to provide the electrical isolation. To suppress the harmonics

generated by these inverters, tuned filters are employed and reactive power compensation is

required to improve the lagging power factor.[7]

3.3.2) Self-commutated Inverter

A switch mode inverter using pulse width modulated (PWM) switching control, can be

used for the grid connection of PV systems. The basic block diagram for this type of inverter

is shown in the Fig. 1.53.

Figure 1.53 Self-commutated Inverter with PWM Switching(Ref:7)

The inverter bridges may consist of bipolar transistors, MOSFET transistors, IGBT‘s,

or gate turn-off thyristor‘s (GTO‘s), depending upon the type of application. GTO‘s are used

for the higher power applications, whereas IGBT‘s can be switched at higher frequencies i.e.

16 kHz, and are generally used for many grid-connected PV applications. Most of the present

day inverters are self-commutated sine-wave inverters.

Based on the switching control, the voltage source inverters can be further classified based on

the switching control as:

• PWM (pulse width modulated) inverters.

• Square-wave inverters.

• Single-phase inverters with voltage cancellations.

• Programmed harmonic elimination switching.

• Current controlled modulation.[7]

68

3.3.3) Inverter with High-frequency Transformer

The 50 Hz transformer for a standard PV inverter with PWM switching scheme can be

very heavy and costly. While using frequencies more than 20 kHz, a ferrite core transformer

can be a better option [3]. A circuit diagram of a grid-connected PV system using high

frequency transformer is shown in the Fig. 1.54.

Figure 1.54 PV Inverter with High-frequency Transformer(Ref:7)

The capacitor on the input side of high frequency inverter acts as the filter. The high

frequency inverter with PWM is used to produce a high frequency AC across the primary

winding of the high frequency transformer. The secondary voltage of this transformer is

rectified using high frequency rectifier. The DC voltage is interfaced with a thyristor inverter

through low-pass inductor filter and hence connected to the grid. The line current is required

to be sinusoidal and in phase with the line voltage. To achieve this, the line voltage (V1) is

measured to establish the reference waveform for the line current IL* . This reference current

IL* multiplied by the transformer ratio gives the reference current at the output of high

frequency inverter. The inverter output can be controlled using current control technique [40].

These inverters can be with low frequency transformer isolation or high frequency

transformer isolation. The low frequency (50/60 Hz) transformer of a standard inverter with

PWM is a very heavy and bulky component. For residential grid interactive rooftop inverters

below 3 kW rating, high frequency transformer isolation is often preferred.[7]

69

3.3.4) Other PV Inverter Topologies

In this section, some of the inverter topologies discussed in various research papers

have been discussed.

3.3.4.1) Multilevel Converters

Multilevel converters can be used with large PV systems where multiple PV panels

can be configured to create voltage steps. These multilevel voltage-source converters can

synthesize the AC output terminal voltage from different level of DC voltages and can

produce staircase waveforms. This scheme involves less complexity, and needs less filtering.

One of the schemes (half-bridge diode-clamped three level inverter) is given in Fig. 1.55.

There is no transformer in this topology. Multilevel converters can be beneficial for large

systems in terms of cost and efficiency. Problems associated with shading and malfunction of

PV units need to be addressed.[7]

Figure 1.55 Half-bridge Diode-clamped Three Level Inverter(Ref:7)

70

3.3.4.2) Non-insulated Voltage Source

In this scheme, string of low voltage PV panels or one high-voltage unit can be

coupled with the grid through DC to DC converter and voltage-source inverter. This topology

is shown in Fig. 1.56. PWM-switching scheme can be used to generate AC output. Filter has

been used to reject the switching components.[7]

Figure 1.56 Non-insulated Voltage Source(Ref:7)

3.3.4.3) Non-insulated Current Source

Figure 1.57 Non-insulated Current Source(Ref:7)

71

This type of configuration is shown in Fig. 1.57. Noninsulated current-source inverters

can be used to interface the PV panels with the grid. This topology involves low cost which

can provide better efficiency. Appropriate controller can be used to reduce current

harmonics.[7]

3.3.4.4) Buck Converter with Half-bridge Transformer Link

PV panels are connected to grid via buck converter and half bridge as shown in Fig.

1.58. In this, high-frequency PWM switching has been used at the low-voltage PV side to

generate an attenuated rectified 100 Hz sine-wave current waveform. Half-wave bridge is

utilized to convert this output to 50 Hz signal suitable for grid interconnection. To step up the

voltage, transformer has also been connected before the grid connection point.[7]

Figure 1.58 Buck Converter with Half-bridge Transformer Link(Ref:7)

3.3.4.5) Flyback Converter

This converter topology steps up the PV voltage to DC bus voltage. Pulse width

modulation operated converter has been used for grid connection of PV system (Fig. 1.59).

This scheme is less complex and has less number of switches. Flyback converters can be

beneficial for remote areas due to less complex power conditioning components.[7]

72

Figure 1.59 Flyback Converter(Ref:7)

3.3.4.6) Interface Using Paralleled PV Panels

Low voltage AC bus scheme can be comparatively efficient and cheaper option. One

of the schemes is shown in Fig. 1.60. A number of smaller PV units can be paralleled together

and then connected to combine single low-frequency transformer. In this scheme, the PV

panels are connected in parallel rather than series to avoid problems associated with shading

or malfunction of one of the panels in series connection.[7]

Figure 1.61 Converter Using Parallel PV Units(Ref:7)

3.4) System Configurations

The utility compatible inverters are used for power conditioning and synchronization

of PV output with the utility power.

73

In general, four types of battery-less grid-connected PV system configurations have

been identified:

• Central plant inverter.

• Multiple string DC/DC converter with single output

inverter.

• Multiple string inverter.

• Module integrated inverter.

3.4.1) Central Plant Inverter

In the central plant inverter, usually a large inverter is used to convert DC power

output of PV arrays to AC power. In this system, the PV modules are serially stringed to form

a panel (or string) and several such panels are connected in parallel to a single DC bus. The

block diagram of such a scheme is shown in Fig. 1.62.[7]

Figure 1.62 Central Plant Inverter(Ref:7)

3.4.2) Multiple String DC/DC Converter

In multiple string DC/DC converter, as shown in Fig. 1.63, each string will have a

boost DC/DC converter with transformer isolation. There will be a common DC link, which

feeds a transformer-less inverter.[7]

74

Figure 1.63 Multiple String DC/DC Converter(Ref:7)

3.4.3) Multiple String Inverters

Figure 1.64 shows the block diagram of multiple string inverter system. In this

scheme, several modules are connected in series on the DC side to form a string. The output

from each string is converted to AC through a smaller individual inverter. Many such

inverters are connected in parallel on the AC side. This arrangement is not badly affected by

the shading of the panels. It is also not seriously affected by inverter failure.[7]

Figure 1.64 Multiple String Inverters(Ref:7)

75

3.4.4)Module Integrated Inverter

In the module integrated inverter system (Fig. 1.65), each module (typically 50–300

W) will have a small inverter. No cabling is required. It is expected that high volume of small

inverters will bring down the cost.[7]

Figure 1.65 Module Integrated Inverter(Ref:7)

3.5) Grid-compatible Inverters Characteristics

The characteristics of the grid-compatible inverters are:

• Response time.

• Power factor.

• Frequency control.

• Harmonic output.

• Synchronization.

• Fault current contribution.

• DC current injection.

• Protection.

76

The response time of the inverters shall be extremely fast and governed by the

bandwidth of the control system. Absence of rotating mass and use of semiconductor switches

allow inverters to respond in millisecond time frame. The power factor of the inverters is

traditionally poor due to displacement power factor and the harmonics. But with the latest

development in the inverter technology, it is possible to maintain the power factor close to

unity. The converters/inverters have the capability of creating large voltage fluctuation by

drawing reactive power from the utility rather than supplying. With proper control, inverters

can provide voltage support by importing/exporting reactive power to push/pull towards a

desired set point. This function would be of more use to the utilities as it can assist in the

regulation of the grid system at the domestic consumer level.

Frequency of the inverter output waveshape is locked to the grid. Frequency bias is

where the inverter frequency is deliberately made to run at 53 Hz. When the grid is present,

this will be pulled down to the nominal 50 Hz. If the grid fails, it will drift upwards towards

53 Hz and trip on over frequency. This can help in preventing islanding.

Harmonics output from the inverters have been very poor traditionally. Old thyristor-

based inverters are operated with slow switching speeds and could not be pulse width

modulated. This resulted in inverters known as six-pulse or twelve-pulse inverters. The

harmonics so produced from the inverters can be injected into the grid, resulting in losses,

heating of appliances, tripping of protection equipments, and poor power quality. The number

of pulses being the number of steps in a sine-wave cycle. With the present advent in the

power electronics technology, the inverter controls can be made very good. Pulse width

modulated inverters produce high quality sine waves. The harmonic levels are very low, and

can be lower than the common domestic appliances. If the harmonics are present in the grid

voltage waveform, harmonic currents can be induced in the inverter. These harmonic currents,

particularly those generated by a voltage-controlled inverter, will in fact help in supporting

the grid. These are good harmonic currents. This is the reason that the harmonic current

output of inverters must be measured onto a clean grid source so that the only harmonics

being produced by the inverters are measured.

Synchronization of inverter with the grid is performed automatically and typically uses

zero crossing detection on the voltage waveform. An inverter has no rotating mass and hence

has no inertia. Synchronization does not involve the acceleration of a rotating machine.

Consequently the reference waveforms in the inverter can be jumped to any point required

77

within a sampling period. If phase-locked loops are used, it could take up a few seconds.

Phase-locked loops are used to increase the immunity to noise. This allows the

synchronization to be based on several cycles of zero crossing information. The response time

for this type of locking will be slower.

Photovoltaic panels produce a current that is proportional to the amount of light falling

on them. The panels are normally rated to produce 1000W/m2 at 25◦ C. Under these

conditions, the short-circuit current possible from these panels is typically only 20% higher

than the nominal current whereas it is extremely variable for wind. If the solar radiation is low

then the maximum current possible under short-circuit is going to be less than the nominal

full load current. Consequently PV systems cannot provide the short-circuit capacity to the

grid. If a battery is present, the fault current contribution is limited by the inverter. With the

battery storage, it is possible for the battery to provide the energy. However, inverters are

typically limited between 100 and 200% of nominal rating under current limit conditions. The

inverter needs to protect itself against the short circuits because the power electronic

components will typically be destroyed before a protection device like circuit breaker trips.

In case of inverter malfunction, inverters have the capability to inject the DC

components into the grid. Most utilities have guidelines for this purpose. A transformer shall

be installed at the point of connection on the AC side to prevent DC from being entering into

the utility network. The transformer can be omitted when a DC detection device is installed at

the point of connection on the AC side in the inverter. The DC injection is essentially caused

by the reference or power electronics device producing a positive half cycle that is different

from the negative half cycle resulting in the DC component in the output. If the DC

component can be measured, it can then be added into the feedback path to eliminate the DC

quantity.[7]

3.5.1) Protection Requirements

A minimum requirement to facilitate the prevention of islanding is that the inverter

energy system protection operates and isolates the inverter energy system from the grid if:

• Over voltage.

• Under voltage.

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• Over frequency.

• Under frequency exists.

These limits may be either factory set or site programmable. The protection voltage

operating points may be set in a narrower band if required, e.g. 220–260 V. In addition to the

passive protection detailed above, and to prevent the situation where islanding may occur

because multiple inverters provide a frequency reference for one another, inverters must have

an accepted active method of islanding prevention following grid failure, e.g. frequency drift,

impedance measurement, etc. Inverter controls for islanding can be designed on the basis of

detection of grid voltage, measurement of impedance, frequency variation, or increase in

harmonics. This function must operate to force the inverter output outside the protection

tolerances specified previously, thereby resulting in isolation of the inverter energy system

from the grid. The maximum combined operation time of both passive and active protections

should be 2 s after grid failure under all local load conditions. If frequency shift is used, it is

recommended that the direction of shift be down. The inverter energy system must remain

disconnected from the grid until the reconnection conditions are met. Some inverters produce

high voltage spikes, especially at light load, which can be dangerous for the electronic

equipment. IEEE P929 gives some idea about the permitted voltage limits.

If the inverter energy system does not have the above frequency features, the inverter

must incorporate an alternate anti-islanding protection feature that is acceptable to the

relevant electricity distributor. If the protection function above is to be incorporated in the

inverter it must be type tested for compliance with these requirements and accepted by the

relevant electricity distributor. Otherwise other forms of external protection relaying are

required which have been type tested for compliance with these requirements and approved

by the relevant electricity distributor. The inverter shall have adequate protection against short

circuit, other faults, and overheating of inverter components.[7]

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2.1.3.6 Potential Technology Developments and Recent Trends

Future directions for thin film technologies include multi-junction thin films aimed at

significantly higher conversion efficiencies, better transparent conducting oxide electrodes,

thin polycrystalline silicon films, and organic inks.

Concentrator systems use only direct, rather than diffuse or global, solar radiation;

therefore, their areas of best application (e.g., in the southwestern United States) are more

limited than those for flat plates. There is also ongoing research to improve the long-term

reliability of concentrator systems and to develop standard tests for concentrator cells and

systems. Thus, most of today‘s remote and distributed markets for PV systems are not suitable

for concentrator systems.

By far the fastest-growing segment of the PV industry is that based on casting large,

multicrystalline ingots in some crucible that is usually consumed in the process.

Manufacturers routinely fabricate large multicrystalline silicon solar cells with efficiencies in

the 13 to 15 percent range; small-area research cells are 20 percent efficient. Silicon ribbon or

sheet technologies avoid the costs and material losses associated with slicing ingots. The

present commercial approaches in the field are the edge-defined, film-fed growth of silicon

ribbons and the string ribbon process. Full-scale production of silicon modules based on

micron-sized silicon spheres was recently announced. In this process, submillimeter-size

silicon spheres are bonded between two thin aluminum sheets, processed into solar cells, and

packaged into flexible, lightweight modules. Another approach uses a micromachining

technique to form deep narrow grooves perpendicular to the surface of a 1- to 2-mm thick

single-crystal silicon wafer. This technique results in large numbers of thin (50 μm), long

(100 mm), and narrow (nearly the original wafer thickness) silicon strips that are processed

into solar cells just prior to separation from the wafer. In another technique, a carbon foil is

pulled through a silicon melt, resulting in the growth of two thin silicon layers on either side

of the foil. After the edges are scribed and the sheet is cut into wafers, the carbon foil is

burned off, resulting in two silicon wafers (150 μm thick) for processing into solar cells.

Thin-film technologies have the potential for substantial cost advantages over wafer-

based crystalline silicon, because of factors such as lesser material use due to direct band

gaps, fewer processing steps, and simpler manufacturing technology for large-area modules.

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Thin-film technologies commonly require less or no high-cost crystalline Si. Many of the

processes are high throughput and continuous (e.g., roll-to-roll); they usually do not involve

high temperatures and, in some cases, do not require high-vacuum deposition equipment.

Module fabrication, involving the interconnection of individual solar cells, is usually carried

out as part of the film-deposition processes. The major systems are amorphous silicon,

cadmium telluride, and copper indium diselenide (CIS) and related alloys. Future directions

include multijunction thin films aimed at significantly higher conversion efficiencies, better

transparent conducting oxide electrodes, and thin polycrystalline silicon films. [5]

1) Dye-sensitized Solar Cells

The dye-sensitized solar cell has its foundation in photochemistry rather than in solid-

state physics. In this device, also called the ―Grätzel cell‖ after its Swiss inventor, organic dye

molecules are adsorbed on a nanocrystalline titanium dioxide (TiO2) film, and the nanopores

of the film are filled with a redox electrolyte. The dyes absorb solar photons to create an

excited molecular state that can inject electrons into the TiO2. The electrons percolate through

the nanoporous TiO2 film and are collected at a transparent electrode. The oxidized dye is

reduced back to its initial state by accepting electrons from the redox relay via ionic transport

from a metal counter-electrode; this completes the circuit and electrical power is delivered in

the external circuit. Dye-sensitized solar cells are very attractive, because of the very low cost

of the constituent materials (TiO2 is a common material used in paints and toothpaste) and the

potential simplicity of their manufacturing process. Additionally, sensitized solar cells are

tolerant to impurities, which allow ease in scaling up the production. Laboratory-scale devices

of 11 percent efficiency have been demonstrated, but larger modules are typically less than

half that efficient. Stability of the devices (e.g., dye materials and electrolyte) while

maintaining high efficiency is an ongoing research issue. [5]

2) Organic and Nanotechnology Solar Cells

Organic semiconductors hold promise as building blocks for organic electronics,

displays, and very low-cost solar cells. In an organic solar cell, light creates a bound electron-

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hole pair, called an exciton, which separates into an electron on one side and a hole on the

other side of a material interface within the device. Polymers, dendrimers, small molecules

and dyes, and inorganic nanostructures are materials that can be used. Organic solar cells can

be about 10 times thinner than thin film solar cells. Consequently, organic solar cells could

lower costs in four ways: low-cost constituent elements (e.g., carbon, hydrogen oxygen, and

nitrogen sulfur); reduced material use; high conversion efficiency; and high-volume

production techniques (e.g., high-rate deposition on roll-to-roll plastic substrates). Organic

solar cells are the focus of DOE‘s research goals for 2020. Research examples in organic solar

cells include quantum dots embedded in an organic polymer, liquid-crystal (smallmolecule)

cells, and small-molecule chromophore cells. Solar cell efficiencies to date are modest (less

than 3 to 5 percent). Unresolved problems associated with this technology include large

optical bandgap, unoptimized band offset, and fast degradation rate due to photoxidation,

interfacial instability delamination, interdiffusion, and morphological changes.

The use of nanotechnology for PV is especially promising, because the optical and

electronic properties of the materials could be tuned by controlling particle size and shape.

They may be easy to manufacture when the nanoparticles are produced by means of chemical

solution. Some of these concepts are already being pursued commercially. Long-term stability

of these devices is another major issue to resolve, along with increasing the efficiency.[5]

2.1.3.7 Future Expectations

1) Short Term: Present to 2020

Currently, polycrystalline silicon PV technologies are well developed and

commercially available. Today, the PV industry is capacity-limited. Given its higher cost than

fossil-based electricity now and for the foreseeable future, deployment of the existing PV

technology will only be constrained by the extent of financial incentives and the absence of

policies that encourage use of solar electricity technology in the nation‘s electricity mix.

Improvement in thin-film efficiencies, which are lower-cost but lower efficiency compared

with Si-base cells, is important for the development of this technology.

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Balance-of-systems costs must be brought down significantly to reduce the whole cost

of a solar electricity system. For example, in California at present, approximately 50 percent

or more of the total installed cost of a rooftop PV system is not in the module cost, but in the

costs of installation, and of the inverter, cables, support structures, grid hook-ups, and other

components. These costs must come down through innovative system-integration approaches,

or this aspect of a PV system will set a floor on the price of a fully installed PV system, either

free-standing or in a rooftop installation. In addition, PV interface devices must improve,

including integrated PV inverters; disconnect, metering, and communications interfaces;

direct PV-DC devices such as Dcdriven end-use devices; and master controllers for use in

buildings with PV, storage, and end users. [5]

2) Medium Term: 2020 to 2035

Cost reductions are needed through new technology development and in the

manufacturing that will accompany the scale-up of existing PV technologies. For example,

new technologies are being developed to make conventional solar cells by using

nanocrystalline inks of precursor as well as semiconducting materials. New cell structures are

being investigated to produce higher efficiency at lower cost.

Thin film technologies have the potential for substantial cost reduction over current wafer-

based crystalline silicon methods, because of factors such as lower material use (due to direct

band gaps), fewer processing steps, and simpler manufacturing technology for large-area

modules. Thin film technologies have many advantages, such as high throughput and

continuous production rate, lower-temperature and non-vacuum processes, and ease of film

deposition. Even lower costs are possible with plastic organic solar cells, dye-sensitized solar

cells, nanotechnology-based solar cells, and other new photovoltaic technologies. [5]

3) Long Term: After 2035

Widespread deployment of PV technology will depend on the ability to reach scale in

manufacturing capacity and achieve cost reductions using technologies for ultralow-cost

module production at acceptable efficiency. Reaching ultralow costs will probably require

learning-curve-based cost reduction, along with development of future generations of PV

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materials and systems to increase efficiency. Next-generation PV cells will most likely have

structures that will make optimal use of the total solar spectrum to maximize light-to-

electricity conversion efficiency.[5]

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2.2 Wind Energy and Electric Generation

2.2.1 Introduction

Wind energy is an indirect form of solar energy in contrast to the direct solar energy.

Solar irradiation causes temperature differences on Earth and these are the origin of winds.

The wind itself can be used by technical systems. Wind can reach much higher power

densities than solar irradiance: 10 kW/m2 during a violent storm and over 25 kW/m

2 during a

hurricane, compared with the maximum terrestrial solar irradiance of about 1 kW/m2.

However, a gentle breeze of 5 m/s (18 km/h, 11.2 mph) has a power density of only 0.075

kW/m2.

The history of wind power goes back many centuries. Wind power was used for

irrigation systems 3000 years ago. Historical sources give evidence for the use of wind power

for grain milling in Afghanistan in the 7th century. These windmills were very simple systems

with poor efficiencies compared to today‘s systems. In Europe, wind power became important

from the 12th century onwards. Windmills were improved over the following centuries. Tens

of thousands of windmills were used for land drainage in The Netherlands in the 17th and

18th centuries; these mills were sophisticated and could track the wind autonomously. In the

19th century numerous western windmills were used in North America for water pumping

systems. Steam powered machines and internal combustion engines competed with wind

power systems from the beginning of the 20th century. Finally, electrification made wind

power totally redundant. The revival of wind power began with the oil crises of the 1970s. In

contrast to the mechanical wind power systems of past centuries, modern wind converters

almost exclusively generate electricity. Germany became the most advanced country for wind

technology development in the 1990s. State of the art wind generators have reached a high

technical standard and now have powers exceeding 4 MW. The German wind power industry

alone has created more than 45,000 new jobs and has reached an annual turnover of more than

€3500 million.

The high growth rate of the wind power industry indicates that wind power will reach

a significant share of the electricity supply within the next two decades, and not only in

Germany and Denmark (the other significant centre of development). Therefore, the main

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deciding factors are the legislative conditions. For instance, the Renewable Energy Sources

Acts in Germany and Spain were the basic conditions for the wind power boom in these two

countries. In most countries the potential for wind power utilization is enormous. Germany

could provide one-third of its electricity demand and the UK could theoretically cover even

more than its whole electricity demand with wind power.

Germany can be taken as example of the rapid development of wind power and its

integration into the electricity supply structures. Most of the established utilities fear the

competition and complain about the problems with line regulation that result from

fluctuations in wind power; however, some utilities have demonstrated that improved wind

speed forecasts can solve these problems. Even some environmental organizations protest

against new wind installations. Their reasons are conservation, nature or noise protection;

indeed, some of their arguments are justifiable. On the other hand, wind power is one of the

most important technologies for stopping global warming. No doubt, wind generators change

the landscape, but if we do not get global warming under control, coastal areas that would be

protected by the reduction in global warming resulting from wind generator installation will

most likely not exist far into the future.[4]

2.2.2 Wind Speed and Energy

The sun heats up air masses in the atmosphere. The spherical shape of the Earth, the

Earth‘s rotation and seasonal and regional fluctuations of the solar irradiance cause spatial air

pressure differentials. These are the source of air movements that create winds.

Technically, the wind turbine captures the wind‘s kinetic energy in a rotor consisting

of two or more blades mechanically coupled to an electrical generator. The turbine is mounted

on a tall tower to enhance the energy capture. Numerous wind turbines are installed at one site

to build a wind farm of the desired power generation capacity. Obviously, sites with steady

high wind produce more energy over the year. [4]

Two distinctly different configurations are available for turbine design, the horizontal-

axis configuration (Figure 2.1) and the vertical-axis configuration (Figure 2.2).

The horizontal-axis machine has been the standard in Denmark from the beginning of

the wind power industry. Therefore, it is often called the Danish wind turbine.

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Figure 2.1 Horizontal-axis Wind Turbine Showing Major Components(Ref:3)

The vertical-axis machine has the shape of an egg beater and is often called the

Darrieus rotor after its inventor. It has been used in the past because of its specific structural

advantage.

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Figure 2.2 Vertical-axis 33 m Diameter Wind Turbine Built and Tested by DOE/Sandia National

Laboratory during 1994 in Bushland, TX. (Ref:3)

However, most modern wind turbines use a horizontal axis design. Except for the

rotor, most other components are the same in both designs, with some differences in their

placements.[3]

2.2.2.1 Power Extracted from the Wind

The actual power extracted by the rotor blades is the difference between the upstream

and downstream wind powers. Using Equation 2.1, this is given by the following equation in

units of watts:

(2.1)

where

Po = mechanical power extracted by the rotor, i.e., the turbine output power,

V = upstream wind velocity at the entrance of the rotor blades, and

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Vo = downstream wind velocity at the exit of the rotor blades.

Let us leave the aerodynamics of the blades to the many excellent books available on

the subject, and take a macroscopic view of the airflow around the blades. Macroscopically,

the air velocity is discontinuous from V to Vo at the ―plane‖ of the rotor blades, with an

―average‖ of ½(V + Vo). Multiplying the air density by the average velocity, therefore, gives

the mass flow rate of air through the rotating blades, which is as follows:

(2.2)

The mechanical power extracted by the rotor, which drives the electrical generator, is

therefore:

(2.3)

The preceding expression is algebraically rearranged in the following form:

(2.4)

The power extracted by the blades is customarily expressed as a fraction of the upstream wind

power in watts as follows:

(2.5)

where

(2.6)

Due to Equation 2.5, we can say that Cp is the fraction of the upstream wind power that is

extracted by the rotor blades and fed to the electrical generator. The remaining power is

dissipated in the downstream wind. The factor Cp is called the power coefficient of the rotor

or the rotor efficiency.

For a given upstream wind speed, Equation 2.6 clearly shows that the value of Cp depends on

the ratio of the downstream to the upstream wind speeds (Vo/V). A plot of power vs. (Vo/V)

shows that Cp is a single-maximum-value function (Figure 2.3).

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Figure 2.3 Rotor Efficiency vs V0/V ratio has a single maximum. Rotor efficiency is the fraction of

available wind power extracted by the rotor and fed to the electrical generator. (Ref:3)

It has the maximum value of 0.59 when the Vo/V ratio is one third. The maximum power is

extracted from the wind at that speed ratio, i.e., when the downstream wind speed equals one

third of the upstream speed. Under this condition (in watts):

(2.8)

The theoretical maximum value of Cp is 0.59. Cp is often expressed as a function of the rotor

tip-speed ratio (TSR) as shown in Figure 2.4. [3]

TSR is defined as the linear speed of the rotor‘s outermost tip to the upstream wind speed.

The aerodynamic analysis of the wind flow around the moving blade with a given pitch angle

establishes the relation between the rotor tip speed and the wind speed. In practical designs,

the maximum achievable Cp ranges between 0.4 and 0.5 for modern high speed two-blade

turbines, and between 0.2 and 0.4 for slow-speed turbines with more blades. If we take 0.5 as

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the practical maximum rotor efficiency, the maximum power output of the wind turbine

becomes a simple expression (in watts per square meter of swept area):

(2.9)

Figure 2.4 Rotor Efficiency vs V0/V Ratio for Rotors with Different Numbers of Blades. Two blade

rotors have the highest efficiency. (Ref:3)

2.2.1.2 Effect of Hub Height

The wind shear at a ground-level surface causes the wind speed to increase with height

in accordance with the following expression:

(2.8)

where

V1 = wind speed measured at the reference height h1,

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V2 = wind speed estimated at height h2, and

α = ground surface friction coefficient.

The friction coefficient α is low for smooth terrain and high for rough ones. The values of α

for typical terrain classes are given in Table 2.1, and their effects on the wind speed at various

heights are plotted in Figure 2.5.

Terrain Type Friction Coefficient α

Lake, ocean, and smooth, hard ground 0.10

Foot-high grass on level ground 0.15

Tall crops, hedges and shrubs 0.20

Wooded country with many trees 0.25

Small town with some trees and shrubs 0.30

City area with tall buildings 0.40

Table 2.1 Friction Coefficient α of Various Terrains(Ref:3)

Figure 2.5 Wind Speed Variations with Height over Different Terrain. Smooth, Low-friction Terrain with

Low α Develops a Thinner Layer of Slow Wind near the Surface and High Wind at Heights(Ref:3)

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It is noteworthy that the offshore wind tower, being in low-α terrain, always sees a

higher wind speed at a given height and is less sensitive to tower height.[3]

2.2.3 Wind Power Systems

2.2.3.1 System Components

The wind power system comprises one or more wind turbine units operating

electrically in parallel. Each turbine is made of the following basic components:

• Tower structure

• Rotor with two or three blades attached to the hub

• Shaft with mechanical gear

• Electrical generator

• Yaw mechanism, such as the tail vane

• Sensors and control

Because of the large moment of inertia of the rotor, design challenges include starting, speed

control during the power-producing operation, and stopping the turbine when required. The

eddy current or another type of brake is used to halt the turbine when needed for emergency

or for routine maintenance.

In a modern wind farm, each turbine must have its own control system to provide

operational and safety functions from a remote location (Figure 2.6).

Figure 2.6 Baix Ebre Wind Farm and Control Center, Catalonia, Spain. (Ref:3)

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It also must have one or more of the following additional components:

• Anemometers, which measure the wind speed and transmit the data to the controller.

• Numerous sensors to monitor and regulate various mechanical and electrical parameters. A

1-MW turbine may have several hundred sensors.

• Stall controller, which starts the machine at set wind speeds of 8 to 15 mph and shuts off at

50 to 70 mph to protect the blades from overstressing and the generator from overheating.

• Power electronics to convert and condition power to the required standards.

• Control electronics, usually incorporating a computer.

• Battery for improving load availability in a stand-alone plant.

• Transmission link for connecting the plant to the area grid.

The following are commonly used terms and terminology in the wind power industry:

Low-speed shaft: The rotor turns the low-speed shaft at 30 to 60 rotations per minute (rpm).

High-speed shaft: It drives the generator via a speed step-up gear.

Brake: A disc brake, which stops the rotor in emergencies. It can be applied mechanically,

electrically, or hydraulically.

Gearbox: Gears connect the low-speed shaft to the high-speed shaft and increase the turbine

speed from 30 to 60 rpm to the 1200 to 1800 rpm required by most generators to produce

electricity in an efficient manner. Because the gearbox is a costly and heavy part, design

engineers are exploring slow-speed, direct-drive generators that need no gearbox.

Generator: It is usually an off-the-shelf induction generator that produces 50- or 60-Hz AC

power.

Nacelle: The rotor attaches to the nacelle, which sits atop the tower and includes a gearbox,

low- and high-speed shafts, generator, controller, and a brake. A cover protects the

components inside the nacelle. Some nacelles are large enough for technicians to stand inside

while working.

Pitch: Blades are turned, or pitched, out of the wind to keep the rotor from turning in winds

that have speeds too high or too low to produce electricity.

Upwind and downwind: The upwind turbine operates facing into the wind in front of the

tower, whereas the downwind runs facing away from the wind after the tower.

Vane: It measures the wind direction and communicates with the yaw drive to orient the

turbine properly with respect to the wind.

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Yaw drive: It keeps the upwind turbine facing into the wind as the wind direction changes. A

yaw motor powers the yaw drive. Downwind turbines do not require a yaw drive, as the wind

blows the rotor downwind.[3]

1) Towers

The wind tower supports the rotor and the nacelle containing the mechanical gear, the

electrical generator, the yaw mechanism, and the stall control.

Figure 2.7 Nacelle Details of a 3.6MW / 104 m Diameter Wind Turbine(Ref:3)

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Figure 2.7 depicts the component details and layout in a large nacelle, and Figure 2.8 shows

the installation on the tower.

Figure 2.8 A Large Nacelle under Installation. (Ref:3)

The height of the tower in the past has been in the 20 to 50 m range. For medium- and large-

sized turbines, the tower height is approximately equal to the rotor diameter, as seen in the

dimension drawing of a 600-kW wind turbine (Figure 2.9).

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Figure 2.10 A 600 kW Wind Turbine and Tower Dimensions with Specifications(Ref:3)

Small turbines are generally mounted on the tower a few rotor diameters high.

Otherwise, they would suffer fatigue due to the poor wind speed found near the ground

surface. Figure 2.11 shows tower heights of various-sized wind turbines relative to some

known structures.

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Figure 2.11 Tower Heights of Various Capacity Wind Turbines(Ref:3)

Both steel and concrete towers are available and are being used. The construction can

be tubular or lattice. Towers must be at least 25 to 30 m high to avoid turbulence caused by

trees and buildings. Utility-scale towers are typically twice as high to take advantage of the

swifter winds at those heights.

The main issue in the tower design is the structural dynamics. The tower vibration and

the resulting fatigue cycles under wind speed fluctuation are avoided by the design. This

requires careful avoidance of all resonance frequencies of the tower, the rotor, and the nacelle

from the wind fluctuation frequencies. Sufficient margin must be maintained between the two

sets of frequencies in all vibrating modes.

The resonance frequencies of the structure are determined by complete modal

analyses, leading to the eigenvectors and eigenvalues of complex matrix equations

representing the motion of the structural elements. The wind fluctuation frequencies are found

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from the measurements at the site under consideration. Experience on a similar nearby site

can bridge the gap in the required information.

Big cranes are generally required to install wind towers. Gradually increasing tower

height, however, is bringing a new dimension in the installation (Figure 2.12).

Figure 2.12 WEG MS-2 Wind Turbine Installation at Myers Hill(Ref:3)

Large rotors add to the transportation problem as well. Tillable towers to nacelle and

rotors moving upwards along with the tower are among some of the newer developments in

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wind tower installation. The offshore installation comes with its own challenge that must be

met.

The top head mass (THM) of the nacelle and rotor combined has a significant bearing

on the dynamics of the entire tower and the foundation. Low THM is generally a measure of

design competency, as it results in reduced manufacturing and installation costs. The THMs

of Vestas‘ 3-MW/90-m turbine is 103 t, NEG Micon‘s new 4.2-MW/110-m machine is 214 t,

and Germany‘s REpower‘s 5- MW/125-m machine is about 350 t, which includes extra 15 to

20% design margins. [3]

2) Turbine

Wind turbines are manufactured in sizes ranging from a few kW for stand-alone

remote applications to a few MW each for utility-scale power generation. The turbine size has

been steadily increasing. The average size of the turbine installed worldwide in 2002 was over

1 MW. By the end of 2003, about 1200 1.5-MW turbines made by GE Wind Energy alone

were installed and in operation. Today, even larger machines are being routinely installed on a

large commercial scale, such as GE‘s new 3.6-MW turbines for offshore wind farms both in

Europe and in the U.S. It offers lighter variable-speed, pitch-controlled blades on a softer

support structure, resulting in a cost-effective foundation. Its rated wind speed is 14 m/sec

with cutin speed at 3.5 m/sec and the cutout at 25 m/sec. The blade diameter is 104 m with

hub height 100 m on land and 75 m offshore. In August 2002, Enercon‘s 4.5-MW wind

turbine prototype was installed near Magdeburgh in eastern Germany. It has a 113-m rotor

diameter, 124-m hub height, and an egg-shaped nacelle. Its reinforced concrete tower

diameter is 12 m at the base, tapering to 4 m at the top. Today, even 5-MW machines are

being installed in large offshore wind farms. The mass of a 5- MW turbine can vary from 150

to 300 t in nacelle and 70 to 100 t in the rotor blades, depending on the manufacturing

technologies adopted at the time of design. The most modern designs would naturally be on

the lighter side of the range.

Turbine procurement requires detailed specifications, which are often tailored from the

manufacturers‘ specifications. The leading manufacturers of wind turbines in the world are

listed in Table 2.2, with Denmark‘s Vestas leading with 22% of the world‘s market share. The

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major suppliers in the U.S. are GE Wind (52%), Vestas (21%), Mitsubishi (12%), NEG

Micon (10%), and Gamesha (3%). [3]

Supplier % Share of the Market

Vestas, Denmark 22

GE Wind, U.S. 18

Enercon, Germany 15

Gamesha, Spain 12

NEG Micon, Denmark (Being acquired by

Vestas, still separate trade names)

10

Table 2.2 World’s Major Wind Turbine Suppliers in 2004(Ref:3)

3) Blades

Modern wind turbines have two or three blades, which are carefully constructed

airfoils that utilize aerodynamic principles to capture as much power as possible. The airfoil

design uses a longer upper-side surface whereas the bottom surface remains somewhat

uniform. By the Bernoulli principle, a ―lift‖ is created on the airfoil by the pressure difference

in the wind flowing over the top and bottom surfaces of the foil. This aerodynamic lift force

flies the plane high, but rotates the wind turbine blades about the hub. In addition to the lift

force on the blades, a drag force is created, which acts perpendicular to the blades, impeding

the lift effect and slowing the rotor down. The design objective is to get the highest lift-to-

drag ratio that can be varied along the length of the blade to optimize the turbine‘s power

output at various speeds. The rotor blades are the foremost visible part of the wind turbine,

and represent the forefront of aerodynamic engineering. The steady mechanical stress due to

centrifugal forces and fatigue under continuous vibrations make the blade design the weakest

mechanical link in the system. Extensive design effort is needed to avoid premature fatigue

failure of the blades. A swift increase in turbine size has been recently made possible by the

rapid progress in rotor blade technology, including emergence of the carbon- and glass-fiber-

based epoxy composites. The turbine blades are made of high-density wood or glass fiber and

epoxy composites.

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The high pitch angle used for stall control also produces a high force. The resulting

load on the blade can cause a high level of vibration and fatigue, possibly leading to a

mechanical failure. Regardless of the fixed- or variable-speed design, the engineer must deal

with the stall forces. Researchers are moving from the 2-D to 3-D stress analyses to better

understand and design for such forces. As a result, the blade design is continually changing,

particularly at the blade root where the loading is maximum due to the cantilever effect.

The aerodynamic design of the blade is important, as it determines the energycapture

potential. The large and small machine blades have significantly different design

philosophies. The small machine sitting on a tower relatively taller than the blade diameter,

and generally unattended, requires a low-maintenance design. On the other hand, a large

machine tends to optimize aerodynamic performance for the maximum possible energy

capture. In either case, the blade cost is generally kept below 10% of the total installed

cost.[3]

2.2.3.2 Turbine Rating

The method of assessing the nominal rating of a wind turbine has no globally accepted

standard. Many manufacturers have, adopted the combined rating designations x/y, the

generator‘s peak electrical capacity followed by the wind turbine diameter. For example, a

300/30-kW/m wind system means a 300-kW electrical generator and a 30-m diameter turbine.

The specific rated capacity (SRC) is often used as a comparative index of the wind turbine

designs. It measures the power generation capacity per square meter of the blade-swept area,

and is defined as follows in units of kW/m2:

(2.10)

The SRC for a 300/30 wind turbine is 300/ Π x 152 = 0.42 kW/m2. It increases with

diameter, giving favorable economies of scale for large machines, and ranges from

approximately 0.2 kW/m2 for a 10-m diameter rotor to 0.5 kW/m

2 for a 40-m diameter rotor.

Some aggressively rated turbines have an SRC of 0.7 kW/m2, and some reach as high as 1

kW/m2. The higher- SRC rotor blades have higher operating stresses, which result in a shorter

fatigue life. All stress concentration regions are carefully identified and eliminated in high-

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SRC designs. Modern design tools, such as the finite element stress analysis and the modal

vibration analysis, can be of great value in rotor design.

Turbine rating is important as it indicates to the system designer how to size the

electrical generator, the plant transformer, and the connecting cables to the substation and the

transmission link interfacing the grid. The power system must be sized on the peak capacity

of the generator. Because turbine power depends on the cube of the wind speed, the system-

design engineer matches the turbine and the generator performance characteristics. This

means selecting the rated speed of the turbine to match with the generator. As the gearbox and

generator are manufactured only in discrete sizes, selecting the turbine‘s rated speed can be

complex. The selection process goes through several iterations, trading the cost with benefit

of the available speeds. Selecting a low rated speed would result in wasting much energy at

high winds. On the other hand, if the rated speed is high, the rotor efficiency will suffer most

of the time.[3]

2.2.3.3 Power vs Speed and TSR

The typical turbine torque vs. rotor speed is plotted in Figure 2.13.

Figure 2.13 Wind Turbine Torque vs Rotor Speed Characteristic at Two Wind Speeds, V1 and

V2(Ref:3)

It shows a small torque at zero speed, rising to a maximum value before falling to nearly zero

when the rotor just floats with the wind. Two such curves are plotted for different wind

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speeds V1 and V2, with V2 being higher than V1. The corresponding power vs. Rotor speed at

the two wind speeds are plotted in Figure 2.14.

Figure 2.14 Wind Turbine Power vs Rotor Speed Characteristic at Two Wind Speeds, V1 and

V2(Ref:3)

As the mechanical power converted into the electric power is given by the product of the

torque T and the angular speed, the power is zero at zero speed and again at high speed with

zero torque. The maximum power is generated at a rotor speed somewhere in between, as

marked by P1max and P2max for speeds V1 and V2, respectively. The speed at the maximum

power is not the same speed at which the torque is maximum. The operating strategy of a

well-designed wind power system is to match the rotor speed to generate power continuously

close to the Pmax points. Because the Pmax point changes with the wind speed, the rotor speed

must, therefore, be adjusted in accordance with the wind speed to force the rotor to work

continuously at Pmax. This can be done with a variable-speed system design and operation.

At a given site, the wind speed varies over a wide range from zero to high gust. We define tip

speed ratio (TSR) as follows:

(2.11)

where R and ω are the rotor radius and the angular speed, respectively.

For a given wind speed, the rotor efficiency Cp varies with TSR as shown in Figure 2.15.

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Figure 2.15 Rotor Efficiency and Annual Energy Production vs Rotor TSR(Ref:3)

The maximum value of Cp occurs approximately at the same wind speed that gives peak

power in the power distribution curve of Figure 2.14. To capture high power at high wind, the

rotor must also turn at high speed, keeping TSR constant at the optimum level. However, the

following three system performance attributes are related to TSR:

1. The maximum rotor efficiency Cp is achieved at a particular TSR, which is specific to

the aerodynamic design of a given turbine. As was seen in Figure 2.4, the TSR needed

for maximum power extraction ranges from nearly one for multiple-blade, slow-speed

machines to nearly six for modern high-speed, two-blade machines.

2. The centrifugal mechanical stress in the blade material is proportional to the TSR. The

machine working at a higher TSR is necessarily stressed more. Therefore, if designed

for the same power in the same wind speed, the machine operating at a higher TSR

would have slimmer rotor blades.

3. The ability of a wind turbine to start under load is inversely proportional to the design

TSR. As this ratio increases, the starting torque produced by the blade decreases.

A variable-speed control is needed to maintain a constant TSR to keep the rotor efficiency at

its maximum. At the optimum TSR, the blades are oriented to maximize the lift and minimize

the drag on the rotor. The turbine selected for a constant TSR operation allows the rotational

speed of both the rotor and generator to vary up to 60% by varying the pitch of the blades.[3]

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2.2.3.4 Maximum Power Operation

In general, operating the wind turbine at a constant TSR corresponding to the

maximum power point at all times can generate 20 to 30% more electricity per year.

However, this requires a control scheme to operate with a variable speed to continuously

generate the maximum power. Two possible schemes for such an operation are as follows:

1) Constant-TSR Scheme

In this scheme the machine is continuously operated at its optimum TSR, which is a

characteristic of the given wind turbine. This optimum value is stored as the reference TSR in

the control computer. The wind speed is continuously measured and compared with the blade

tip speed. The error signal is then fed to the control system, which changes the turbine speed

to minimize the error (Figure 2.16).

Figure 2.16 Maximum Power Operation Using Rotor Tip Speed Control Scheme(Ref:3)

At this time the rotor must be operating at the reference TSR, generating the maximum power.

This scheme has the disadvantage of requiring the local wind speed measurements, which

could have a significant error, particularly in a large wind farm with shadow effects. Being

sensitive to the changes in the blade surface, the optimum TSR gradually changes with age

and environment. The computer reference TSR must be changed accordingly many times,

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which is expensive. Besides, it is difficult to determine the new optimum TSR with changes

that are not fully understood or easily measured.[3]

2) Peak-Power-Tracking Scheme

The power vs. speed curve has a single well-defined peak. If we operate at the peak

point, a small increase or decrease in the turbine speed would result in no change in the power

output, as the peak point locally lies in a flat neighborhood. In other words, a necessary

condition for the speed to be at the maximum power point is as follows:

(2.12)

This principle is used in the control scheme (Figure 2.17).

Figure 2.17 Maximum Power Operation Using Power Control Scheme(Ref:3)

The speed is increased or decreased in small increments, the power is continuously measured,

and ΔP/Δω is continuously evaluated. If this ratio is positive that means we get more power

by increasing the speed, the speed is further increased. On the other hand, if the ratio is

negative, the power generation will reduce if we change the speed any further. The speed is

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maintained at the level where ΔP/Δω is close to zero. This method is insensitive to errors in

local wind speed measurement, and also to wind turbine design. It is, therefore, the preferred

method. In a multiple-machine wind farm, each turbine must be controlled by its own control

loop with operational and safety functions incorporated.[3]

2.2.3.5 System-Design Trade-Offs

When the land area is limited or is at a premium price, one optimization study that

must be conducted in an early stage of the wind farm design is to determine the number of

turbines, their size, and the spacing for extracting the maximum energy from the farm

annually.

1) Turbine Towers and Spacing

Figure 2.18 Optimum Tower Spacing in Wind Farms in Flat Terrain(Ref:3)

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Large turbines cost less per megawatt of capacity and occupy less land area. On the

other hand, fewer large machines can reduce the megawatthour energy crop per year, as

downtime of one machine would have larger impact on the energy output. A certain turbine

size may stand out to be the optimum for a given wind farm from the investment and energy

production cost points of view.

Tall towers are beneficial, but the height must be optimized with the local regulations

and constrains of the terrain and neighborhood. Nacelle weight and structural dynamics are

also important considerations.

When installing a cluster of machines in a wind farm, certain spacing between the

wind towers must be maintained to optimize the energy crop over the year. The spacing

depends on the terrain, wind direction, wind speed, and turbine size. The optimum spacing is

found in rows 8 to 12 rotor diameters apart in the wind direction, and 2 to 4 rotor diameters

apart in the crosswind direction (Figure 2.18).

Figure 2.19 Original Land Use Continues in a Wind Farm in Germany(Ref:3)

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The average number of machines in wind farms varies greatly, ranging from several to

hundreds depending on the required power capacity of the farm. The preceding spacing rules

would ensure that the turbines do not shield those further downwind. Some wind farms have

used narrow spacing of five to six rotor diameters in the wind direction. One such farm in

Mackinaw City, MI, has reported the rotors in downwind direction running slower due to the

wake effect of the upwind rotors.

The wind power fluctuations and electrical transients on fewer large machines would

cost more in the filtering of power and voltage fluctuations, or would degrade the quality of

power, inviting penalty from the grid.

Additionally, it includes the effect of tower height that goes with the turbine diameter,

available standard ratings, cost at the time of procurement, and wind speed. The wake

interaction and tower shadow are ignored for simplicity. Such optimization leads to a site-

specific number and size of the wind turbines that will minimize the energy cost.[3]

2) Number of Blades

One can extract the power available in the wind with a small number of blades rotating

quickly, or a large number of blades rotating slowly. More blades do not give more power,

but they give more torque and require heavier construction. A few fast-spinning blades result

in an economical system. Wind machines have been built with the number of blades ranging

from 1 to 40 or more. A one-blade machine, although technically feasible, gives a supersonic

tip speed and a highly pulsating torque, causing excessive vibrations. It is, therefore, hardly

used in large systems.

A very high number of blades were used in old low-TSR rotors for water pumping and

grain milling, the applications requiring high starting torque. Modern high-TSR rotors for

generating electric power have two or three blades, many of them with just two, although the

Danish standard is three blades.

The major factors involved in deciding the number of blades are as follows:

• The effect on power coefficient

• The design TSR

• The means of limiting yaw rate to reduce the gyroscopic fatigue

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Compared to the two-blade design, the three-blade machine has smoother power

output and a balanced gyroscopic force. There is no need to teeter the rotor, allowing the use

of a simple rigid hub. Three blades are more common in Europe, where large machines up to

a few MW are being built using the three-blade configuration. The practice in the U.S,

however, has been to use the two-blade design. Adding the third blade increases the power

coefficient only by about 5%, thus giving a diminished rate of return for the 50% more blade

weight and cost. The two-blade rotor is also simpler to erect, because it can be assembled on

the ground and lifted to the shaft without complicated maneuvers during the lift. The number

of blades is often viewed as the blade solidity. Higher solidity ratio gives higher starting

torque and leads to low-speed operation. For electric power generation, the turbine must run

at high speeds as the electrical generator weighs less and operates more efficiently at high

speeds. That is why all large-scale wind turbines have low solidity ratio, with just two or three

blades.[3]

3) Rotor Upwind or Downwind

Operating the rotor upwind of the tower produces higher power as it eliminates the

tower shadow on the blades. This results in lower noise, lower blade fatigue, and smoother

power output. A drawback is that the rotor must constantly be turned intothe wind via the yaw

mechanism. The heavier yaw mechanism of an upwind turbine requires a heavy-duty and

stiffer rotor compared to a downwind rotor.

The downwind rotor has the wake (wind shade) of the tower in the front and loses

some power from the slight wind drop. On the other hand, it allows the use of a free yaw

system. It also allows the blades to deflect away from the tower when loaded. Its drawback is

that the machine may yaw in the same direction for a long period of time, which can twist the

cables that carry current from the turbines.

Both types have been used in the past with no clear trend. However, the upwind rotor

configuration has recently become more common.[3]

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4) Horizontal vs Vertical Axis

In the horizontal-axis Danish machine, considered to be classical, the axis of blade

rotation is horizontal with respect to the ground and parallel to the wind stream. Most wind

turbines are built today with the horizontal-axis design, which offers a cost-effective turbine

construction, installation, and control by varying the blade pitch.

The vertical-axis Darrieus machine has different advantages. First of all, it is

omnidirectional and requires no yaw mechanism to continuously orient itself toward the wind

direction. Secondly, its vertical drive shaft simplifies the installation of the gearbox and the

electrical generator on the ground, making the structure much simpler. On the negative side, it

normally requires guy wires attached to the top for support. This could limit its applications,

particularly at offshore sites. Overall, the vertical-axis machine has not been widely used,

primarily because its output power cannot be easily controlled in high winds simply by

changing the blade pitch. With modern low-cost variable-speed power electronics emerging in

the wind power industry, the Darrieus configuration may revive, particularly for large-

capacity applications.

The Darrieus has structural advantages compared to a horizontal-axis turbine because

it is balanced. The blades only ―see‖ the maximum lift torque twice per revolution. Seeing

maximum torque on one blade once per revolution excites many natural frequencies, causing

excessive vibrations. Also a vertical-axis wind turbine configuration is set on the ground.

Therefore, it is unable to effectively use higher wind speeds using a higher tower, as there is

no tower here.[3]

2.2.4 Power Electronics for Modern Wind Turbines

1) Wind Energy Conversion

The development in wind turbine systems has been steady for the last 25 years and

four to five generations of wind turbines exist. The main components of a wind turbine

system, including the turbine rotor, gearbox, generator, transformer, and possible power

electronics, are illustrated in Fig. 2.20.

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Figure 2.20 Main Components of a Wind Turbine System(Ref:8)

The turbine rotor converts the fluctuating wind energy into mechanical energy, which

is converted into electrical power through the generator, and then transferred into the grid

through a transformer and transmission lines.

Wind turbines capture the power from the wind by means of aerodynamically

designed blades and convert it to rotating mechanical power. The number of blades is

normally three and the rotational speed decreases as the radius of the blade increases.

For megawatt range wind turbines the rotational speed will be 10–15 rpm. The

weightefficient way to convert the low-speed, high-torque power to electrical power is to use

a gearbox and a generator with standard speed. The gearbox adapts the low speed of the

turbine rotor to the high speed of the generator. The gearbox may be not necessary for

multipole generator systems.

The generator converts the mechanical power into electrical energy, which is fed into a

grid through possibly a power electronic converter, and a transformer with circuit breakers

and electricity meters. The connection of wind turbines to the grid is possible at low voltage,

medium voltage, high voltage, and even at the extra high voltage system since the

transmittable power of an electricity system usually increases with increasing the voltage

level. While most of the turbines are nowadays connected to the medium voltage system,

large offshore wind farms are connected to the high and extra high voltage level.

The electrical losses include the losses due to the generation of power, and the losses

occur independently of the power production of wind turbines and also the energy used for

lights and heating. The losses due to the power generation of the wind turbines are mainly

losses in the cables and the transformer. The low-voltage cable should be short so as to avoid

high losses. For modern wind turbine system, each turbine has its own transformer to raise

voltage from the voltage level of the wind turbines (400 or 690 V) to the medium voltage. The

transformer is normally located close to the wind turbines to avoid long low-voltage cables.

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Only small wind turbines are connected directly to the low-voltage line without a transformer

or some of small wind turbines are connected to one transformer in a wind farm with small

wind turbines. Because of the high losses in low-voltage lines, large wind farms may have a

separate substation to increase the voltage from a medium voltage system to a high voltage

system. The medium voltage system could be connected as a radial feeder or as a ring feeder.

At the point of common coupling (PCC) between the single wind turbines or the wind

farm and the grid, there is a circuit breaker for the disconnection of the whole wind farm or of

the wind turbines. Also the electricity meters are installed usually with their own voltage and

current transformers.

The electrical protective system of a wind turbine system needs to protect the wind

turbine and as well as secure the safe operation of the network under all circumstances. For

the wind turbine protection, the short circuits, overvoltage, and overproduction will be limited

to avoid the possibly dangerous damage to the wind turbine system. Also the system should

follow the grid requirements to decide whether the wind turbine should be kept in connection

or disconnected from the system. Depending on the wind turbine operation requirement, a

special relaymay be needed to detect if the wind turbine operates in a grid connection mode or

as an autonomous unit in an isolated part of the network due to the operation of protection

devices.

The conversion of wind power to mechanical power is done aerodynamically as

aforementioned. It is important to control and limit the converted mechanical power at higher

wind speed, as the power in the wind is a cube of the wind speed. The power limitation may

be done by stall control (the blade position is fixed but stall of the wind appears along the

blade at higher wind speed), active stall control (the blade angle is adjusted in order to create

stall along the blades), or pitch control (the blades are turned out of the wind at higher wind

speed).

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Figure 2.21 Power Characteristics of a Fixed Speed Wind Turbines: (a)Stall Control, (b)Active Stall

Control, and (c)Pitch Control(Ref:8)

Fig. 2.21 shows the power curves of different types of turbine rotor power limitation methods.

It can be seen that the power may be smoothly limited by rotating the blades either by pitch or

by active stall control while the power limited by the stall control shows a small overshoot,

and this overshoot depends on the aerodynamic design. The possible technical solutions of the

electrical system are many and Fig. 2.22 shows a technological roadmap starting with wind

energy/power and converting the mechanical power into electrical power. It involves

solutions with and without gearbox as well as solutions with or without power electronic

conversion.[8]

Figure 2.22 Roadmap for Wind Energy Conversion (PE=Power Electronics, DF=Doubly Fed) (Ref:8)

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2) Modern Power Electronics and Converter Systems

Many types of wind turbines, such as variable speed wind turbine systems, use power

electronic systems as interfaces. Since the wind turbine operates at variable rotational speed,

the electric frequency of the generator varies andmust therefore be decoupled from the

frequency of the grid. This can be achieved by using a power electronic converter system.

Even in a fixed speed system where the wind turbines may be directly connected to the grid,

thyristors are used as soft-starters.

2.1) Power Electronics Devices

Power electronics has changed rapidly during the last 30 years and the number of

applications has been increasing, mainly due to the developments of semiconductor devices

and microprocessor technology. For both cases higher performance is steadily given for the

same area of silicon, and at the same time the price of the devices is continuously falling.

Three important issues are of concern in using a power electronic system. These are

reliability, efficiency, and cost. At the moment the cost of power semiconductor devices is

decreasing 2–5% every year for the same output performance. Fig. 2.23 shows some key self-

commutated devices and the area where the development is still on going.

Figure 2.23 Development of Power Semiconductor Devices in the Past and in the Future(Ref:8)

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The only power device that is no longer under development (see Fig. 2.23) is the

silicon-based power bipolar transistor because MOS-gated devices are preferable in the sense

of easy control. The breakdown voltage and/or current carrying capability of the components

are also continuously increasing. Also, important research is going on to change the material

from silicon to silicon carbide. This may dramatically increase the power density of power

converters, but silicon carbide based transistors on a commercial basis, with a competitive

price, will still take some years to appear on the market.[8]

2.2) Power Electronic Converters

Power electronic converters are constructed by power electronic devices, driving,

protection and control circuits. A converter, depending on the topology and application, may

allow both directions of power flow and can interface between the load/generator and the grid.

There are two different types of converter systems: grid commutated and self commutated

converter systems. The grid commutated converters are mainly thyristor converters, 6 or 12 or

even more pulse. This type of converter produces integer harmonics which in general requires

harmonic filters. Also thyristor converters are not able to control the reactive power and

consume inductive reactive power.

Figure 2.24 Circuit Diagram of a Voltage Source Converter (VSC) with IGBTs(Ref:8)

Self commutated converter systems are mainly pulse width modulated (PWM)

converters, where IGBTs (Insulated Gate Bipolar Transistor) are mainly used. This type of

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converter can control both active power and reactive power. That means the reactive power

demand can be delivered by a PWM-converter. The high frequency switching of a PWM-

converter may produce harmonics and interharmonics. In general these harmonics are in the

range of some kHz.Due to the high frequencies, the harmonics are relatively easier to be

removed by small size filters. Fig. 2.24 shows a typical power electronic converter consisting

of self commutated semiconductors such as IGBTs and Fig. 2.25 shows the waveforms of

different operation modes.[8]

Figure 2.25 Waveforms of Bidirectional Active and Reactive Power of a VSC: (a)Active Power Flow from the AC System to the Converter DC Side, (b)Active Power Flow from the Converter DC Side to

the AC System, (c)The Converter Generating Reactive Power, (d)The Converter Consuming Reactive Power(Ref:8)

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3) Generator Systems for Wind Turbines

Both induction and synchronous generators can be used for wind turbine systems.

Induction generators can be used in a fixed-speed system or a variable-speed system, while

synchronous generators are normally used in power electronic interfaced variable-speed

systems. Mainly, three types of induction generators are used in wind power conversion

systems: cage rotor, wound rotor with slip control by changing rotor resistance, and doubly

fed induction generators. The cage rotor induction machine can be directly connected into an

ac system and operates at a fixed speed or uses a full-rated power electronic system to operate

at variable speed. The wound rotor generator with rotor-resistance-slip control is normally

directly connected to an ac system, but the slip control provides the ability of changing the

operation speed in a certain range. The doubly fed induction generators provide a wide range

of speed variation depending on the size of power electronic converter systems.

3.1) Fixed-Speed Wind Turbines

In fixed-speed wind turbines, the generator is directly connected to the mains supply

grid. The frequency of the grid determines the rotational speed of the generator and thus of the

rotor. The generator speed depends on the number of pole pairs and the frequency of the grid.

The ―Danish Concept,‖ of directly connecting a wind turbine to the grid, is widely used for

power ratings up to 2.3 MW. The scheme consists of a squirrel-cage induction generator

(SCIG), connected via a transformer to the grid. The wind turbine systems using cage rotor

induction generators almost operate at a fixed speed (variation of 1–2%). The power can be

limited aerodynamically by stall control, active stall control, or by pitch control. The basic

configurations of three different fixed speed concepts are shown in Fig. 2.26. The advantage

of wind turbines with induction generators is the simple and cheap construction. In addition,

no synchronization device is required. These systems are attractive due to cost and reliability,

but they are not fast enough (within a few ms) to control the active power. There are some

other drawbacks also: the wind turbine has to operate at constant speed, it requires a stiff

power grid to enable stable operation, and it may require a more expensive mechanical

construction in order to absorb high mechanical stress since wind gusts may cause torque

pulsations in the drive train and the gearbox. Other disadvantages with the induction

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generators are high starting currents and their demand for reactive power. They need a

reactive power compensator to reduce (almost eliminate) the reactive power demand from the

turbine generators to the grid. It is usually done by continuously switching capacitor banks

following the production variation (5–25 steps).

Figure 2.26 Wind Turbine Systems without Power Converter, but with Aerodynamic Power Control: (a)Pitch Controlled[System 1], (b)Stall Controlled[System II], and (c)Active Stall Controlled [System III]

(Ref:8)

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Connecting the induction generators to power system produces transients that are short

duration, very high inrush currents causing both disturbances to the grid and high torque

spikes in the drive train of wind turbines with a directly connected induction generator.

Unless special precautions are taken, the inrush currents can be up to 5–7 times the

rated current of the generator; however, after a very short period (less than 100 ms), the

current peak may be considerably higher, up to 18 times the normal rated current. A transient

like this disturbs the grid and limits the acceptable number of value of all wind turbines. All

three systems shown in Fig. 2.26 use a thyristor controller, the soft starter (not shown in Fig.

2.26), in order to reduce the inrush current. The current limiter, or soft starter, based on

thyristor technology, typically limits the highest rms value of the inrush current to a level that

is two times below that of the generator rated current. The soft starter has a limited thermal

capacity and so it is short circuited by a contactor, which carries the full load current when the

connection to the grid has been completed. In addition to reducing the impact on the grid, the

soft starter also effectively dampens the torque peaks associated with the peak currents and

hence reduces the loads on the gearbox.

An example is shown here to illustrate the startup of a soft-starter-fed induction

generator. The induction machine has 2MW rated power, 690 V/1700A rated phase voltage

and rated line current, respectively (delta connection). The induction machine is connected via

a soft starter to the supply voltage below synchronous speed (1450 rpm). The starting firing

angle for the soft starter is 120◦. The equivalent diagram of this system is shown in Fig.

2.27(a). The electromagnetic torque and the rotational speed of the high-speed shaft during

the startup are presented in two cases: direct startup and using a soft starter. Fig. 2.27(b)

shows the simulation results for the direct startup, while Fig. 2.27(c) shows the results when

the machine is connected to the grid via a soft starter. When the induction machine is

connected directly to the grid, high starting torque is observed. Large oscillations in the shaft

speed can be seen in Fig. 2.27(b). By using a soft starter, the inrush currents and therefore the

high starting torque are limited and the shaft speed is smoothed as shown in Fig. 2.27(c).[8]

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Figure 2.27 The Startup of a Fixed-speed Wind Turbine: (a)Equivalent Diagram of a Fixed-speed Wind Turbine to Show the Startup, (b)Electromagnetic Torque and Shaft Speed during the Direct

Startup of a 2MW Induction Machine (c)Electromagnetic Torque and Shaft Speed during the Startup of a 2MW Soft-starter-fed Induction Machine(Ref:8)

3.2) Variable-Speed Wind Turbines

In variable-speed systems the generator is normally connected to the grid by a power

electronic system. For synchronous generators and for induction generators without rotor

windings, a full-rated power electronic system is connected between the stator of the

generator and the grid, where the total power production must be fed through the power

electronic system. For induction generators with rotor windings, the stator of the generator is

connected to the grid directly. Only the rotor of the generator is connected through a power

electronic system. This gives the advantage that only a part of the power production is fed

through the power electronic converter. This means the nominal power of the converter

system can be less than the nominal power of the wind turbine. In general the nominal power

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of the converter may be 30% of the power rating of the wind turbine, enabling a rotor speed

variation in the range of 30% of the nominal speed. By controlling the active power of the

converter, it is possible to vary the rotational speed of the generator and thus of the rotor of

the wind turbines.

3.2.1) Variable-speed Wind Turbines with Partially rated Power Converters

By using wind turbines with partially rated power converters the improved control

performance can be obtained. Fig. 2.28 shows two such systems. The generator for wind

turbine systems shown in Fig. 2.28 is an induction generator with a wounded rotor.

Figure 2.28 Wind Turbine Topologies with Partially Rated Power Electronics and Limited Speed Range. Rotor-resistance Converter [System IV] and Doubly-fed Induction Generator [System V]

(Ref:8)

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3.2.1.1) Dynamic Slip-ControlledWounded Rotor Induction Generator

In Fig. 2.28(a) an extra resistance is added in the rotor, which can be controlled by

power electronics. The variation of rotor resistance produces a group of torque-speed

characteristics as shown in Fig. 2.29.

Figure 2.29 Torque and Speed Characteristics of Rotor Resitance Controlled Wound Rotor Induction

Generator(Ref:8)

This is known as the dynamic slip control and gives typically a speed range of 2–5%. The

power converter for the rotor resistance control is for low voltage but high currents. At the

same time an extra control freedom is obtained at higher wind speeds in order to keep the

output power fixed. This system still needs a soft starter and reactive power compensation.[8]

3.2.1.2) Doubly Fed Induction Generator

A doubly fed induction generator (DIFG) using a medium scale power converter is

shown in Fig. 2.28(b). Slip rings are making the electrical connection to the rotor. If the

generator is running super-synchronously, electrical power is delivered to the grid through

both the rotor and the stator. If the generator is running sub-synchronously, electrical power is

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delivered into the rotor from the grid. A speed variation of ±}30% around synchronous speed

can be obtained by the use of a power converter of 30% of nominal power. Furthermore, it is

possible to control both active (Pref) and reactive power (Qref), which gives a better grid

performance, and the power electronics enables the wind turbine to act as a more dynamic

power source to the grid.

The DFIG system does not need either a soft starter or a reactive power compensator.

The system is naturally a little bit more expensive compared to the classical systems shown

before in Figs. 2.26 and 2.28(a). However, it is possible to save money on the safety margin

of gear and reactive power compensation units, and it is also possible to capture more energy

from the wind.[8]

3.2.2) Full Scale Power Electronic Converter Integrated Systems

The wind turbines with a full-scale power converter between the generator and the

grid give the added technical performance. Fig. 3.5 shows four possible systems with full-

scale power converters.

The systems shown in Figs. 2.30(a) and 2.30(b) are characterized by having a gearbox. The

wind turbine system with a cage rotor induction generator and full-rated power electronic

converters is shown in Fig. 2.30(a). Usually, a back-to-back voltage source converter is used

in order to achieve full control of the active and reactive power.

The synchronous generator shown in Fig. 2.30(b) needs a small power converter for

field excitation. Multipole systems with the synchronous generator without a gear are shown

in Figs. 2.30(c) and 2.30(d). The last system is using permanent magnets, which are becoming

cheaper and thereby attractive. All four systems have almost the same controllable

characteristics since the generator is decoupled from the grid by a dc link. The power

converter to the grid enables the system to control active and reactive power very fast.

However, the disadvantage is a more complex system with more sensitive electronic parts.[8]

126

Figure 2.30 Wind turbine systems with full-scale power converters. (a) Induction generator with gear [System VI], (b) Synchronous generator with gear [System VII], (c) Multipole

synchronous generator [System VIII], (d) Multipole permanent magnet synchronous generator [System IX] (Ref:8)

127

Turbine Concept % World Market Share

Fixed-speed (Stall or Active-stall

Gearbox)[System I, II, III]

23

Dynamic Slip Control (Limited Variable Speed,

Pitch Control, Gearbox)[System IV]

11

Doubly Fed Generator (Variable Speed

Operation, Pitch Control, Gearbox)[System V]

50

Direct Driven (Variable Speed Operation, Pitch

Control)[System VIII]

16

Table 2.3 Wind Turbine Topologies Market in 2001(Ref:8)

4) Control of Wind Turbines

Overall, the power can be controlled by means of the aerodynamic system and has to

follow a set point given by a dispatch center or locally, with the goal to maximize the

production based on the available wind power. The power control system should also be able

to limit the power. Controlling a wind turbine involves both fast and slow control.

4.1) Active Stall Wind Turbine with Cage Rotor Induction Generators

In principle, an active stall wind turbine is a stall turbine with a variable pitch angle.

The main difference between a stall turbine and an active stall turbine is a pitch system for

variable pitch angles, which allows the stall effect to be controlled. An active stall wind

turbine has to pitch in a negative direction to limit the power when the electrical power of the

wind turbine exceeds nominal power. The active stall system basically maintains all the

characteristics of a stall-regulated system. Large wind farms such as Nysted (170MW

installed capacity) have been built with active stall wind turbines.

The generator of an active stall turbine can be a simple squirrel cage induction

generator directly connected to the grid. In order to compensate for the output power factor, a

capacitor bank is used. A soft starter is used only during the startup sequence of the generator

in order to limit the inrush currents and hence reduce the high starting torque.

The maximum power output of the active stall turbines can be maintained at a constant

value. In addition, the aerodynamic efficiency Cp can be optimized to a certain extent. The

active stall control can improve the efficiency of the overall system. The flexible coupling of

128

the blades to the hub also facilitates emergency stopping and start up. One drawback of the

active stall controlled wind turbine compared to the passive stall one is the higher price,

which is due to the pitching mechanism and its controller.

The implemented active stall wind turbine controller achieves good power yield with a

minimum of pitch actions. Once the overall mean wind speed is at a constant level, pitch

angle adjustments are rarely necessary, allowing the controller to optimize the pitch angle as

often as possible.

Depending on the pitch system, the lost power (due to slow control) may be justified

by reduced stress and wear in the pitch system and reduced fatigue loads on the wind turbine.

This applies both to power optimization, where the controller strives for maximum power

yield by using the moving average of the wind speed signal to find the appropriate pitch angle

in a lookup table, and to power limitation where the power output is controlled in a closed

control loop. With a slow control system, substantial over-power in the power limitation

mode may cause a problem. This may be avoided by an over-power protection feature.[8]

4.2) Variable Pitch Angle Control with Doubly Fed Generators

The variable speed DFIG wind turbine is a widely used concept today. The control

system of a variable speed wind turbine with DFIG mainly functions to

• control the power drawn from the wind turbine in order to track the wind turbine optimum

operation point,

• limit the power in the case of high wind speeds, and

• control the reactive power exchanged between the wind turbine generator and the grid.

Two hierarchical control levels are related to each other with different bandwidths,

namely, DFIG control level and wind turbine control level. An example of an overall control

scheme of a wind turbine with a doubly fed generator system is shown in Fig. 2.31.

The DFIG control, with a fast dynamic response, contains the electrical control of the

power converters and of the DFIG. The wind turbine control, with slow dynamic response,

supervises both the pitch system of the wind turbine as well as the active power set point of

the DFIG control level.

12

9

Fig

ure

2.3

1 C

ontro

l of W

ind T

urb

ine w

ith D

FIG

Syste

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)

130

A vector control approach is adopted for the DFIG control, while two crosscoupled

controllers are used to control the wind turbine. These controllers are speed and power

limitation controllers. Their goals are to track the wind turbine optimum operation point, to

limit the power in the case of high wind speeds, and to control the reactive power exchanged

between the wind turbine generator and the grid.

Below maximum power production, the wind turbine will typically vary the speed

proportionally with the wind speed and keep the pitch angle θ fixed. At very low wind, the

speed of the turbine will be fixed at the maximum allowable slip in order not to have

overvoltage. A pitch angle controller will limit the power when the turbine reaches the

nominal power. The generated electrical power is controlled by the doubly fed generator

through the rotor-side converter. The control of the grid-side converter simply keeps the dc-

link voltage fixed. Internal current loops in both converters are used with typical PI-

controllers. The power converters to the grid-side and the rotor-side are voltage source

inverters.

The significant feature of the control method is that it allows the turbine to operate

with optimum power efficiency over a wide range of wind speeds. Moreover, because of the

design of this control method, small changes in generator speed do not lead to large power

fluctuations and unnecessary transitions between power optimization and power limitation

modes. A gain scheduling control of the pitch angle is also implemented in order to

compensate for the nonlinear aerodynamic characteristics.[8]

4.3) Full Rated Power Electronic Interface Wind Turbine Systems

Cage induction generators and synchronous generators can be integrated into the

system by full rated power electronic converters. As shown in Fig. 2.32, a passive rectifier

and a boost converter are used in order to boost the voltage at low speed. It is possible to

control the active power from the generator. A grid inverter interfaces the dc-link to the grid.

Here it is also possible to control the reactive power to the grid. The system is able to control

reactive and active power quickly and then the turbine may take part in the power system

control.[8]

131

Figure 2.32 Basic control of active and reactive power in a wind turbine with a multipole

synchronous generator system(Ref:8)

5) Electrical Topologies of Wind Farms Based on Different Wind Turbines

In many countries, energy planning with a high penetration of wind energy is going

on, which includes large wind farms. These wind farms may present a significant power

contribution to the national grid, and therefore, play an important role in power quality and

the control of power systems.

Consequently, high technical demands are expected to be met by these generation

units in order to perform frequency and voltage control, the regulation of active and reactive

power, and quick responses under power system transient and dynamic situations. For

example, it may be required to reduce the power from the nominal power to 20% power

within 2 s. The power electronic technology is again an important part in both the system

configurations and the control of the wind farms in order to fulfill these demands. Also, the

overall performance of a wind farmwill largely depend on the types of the wind turbines

installed as well as the topology of the electrical system. Some possible electrical

configurations of wind farms are shown in Fig. 2.33.

A wind farm equipped with power electronic converters, as shown in Fig. 2.33(a), can

perform both real and reactive power control and also operate the wind turbines in variable

speed to maximize the energy captured as well as reduce the mechanical stress and noise.

Such a system is in operation in Denmark as a 160MWoff-shore wind power station.

133

Figure 2.33 Wind farm solutions. (a) DFIG system with ac-grid [System A], (b) Induction generator with ac-grid [System B], (c) Speed controlled induction generator with common dc-bus

and control of active and reactive power [System C], (d) Speed controlled induction generator with common ac-grid and dc transmission [System D] (Ref:8)

Fig. 2.33(b) shows a wind farm with induction generators. A STATCOM can be used

to provide the reactive power control to meet the system reactive power control requirements,

and it can help to control the voltage, as well as, provide the reactive power demand of the

induction generators in the wind farm.

For long distance transmission of power from off-shore wind farms, HVDC may be an

interesting option. In a HVDC transmission, the low or medium ac voltage at the wind farm is

converted into a high dc voltage on the transmission side and the dc power is transferred to

the onshore system where the dc voltage is converted back into ac voltage as shown in Fig.

2.33(d). For certain power level, a HVDC transmission system, based on voltage source

converter technology, may be used in such a system instead of the conventional thyristor-

based HVDC technology. The topology may even be able to vary the speed on the wind

turbines in the complete wind farm. Another possible dc transmission system configuration is

shown in Fig. 2.33(c), where each wind turbine has its own power electronic converter and so

it is possible to operate each wind turbine at an individual optimal speed. A comparison of the

topologies of these four wind farms is given in Table 2.4. As it can be seen, the wind farms

have interesting features so as to act as a power source to the grid. Some have better abilities

than others. The overall considerations will include production, investment, maintenance, and

reliability.

134

There are other possibilities, such as field excited synchronous machines or permanent

magnet synchronous generators, that may be used in the systems shown in Fig. 2.33(c) or

2.33(d). In the case of a multipole generator, the gearbox may be removed.[8]

FARM

CONFIGURATIONS

PARK A PARK B PARK C PARK D

Individual Speed Control Yes No Yes No

Control Active Power

Electronicaly

Yes No Yes Yes

Control Reactive Power Yes Centralized Yes Yes

Short Circuit (Active) Partly Partly Yes Yes

Short Circuit Power Contribute Contribute No No

Control Bandwidth 10-100ms 200ms to 2s 10-100ms 10ms to

10s

Standby-function Yes No Yes Yes

Softstarter Needed No Yes No No

Rolling Capacity on Grid Yes Partly Yes Yes

Redundancy Yes Yes No No

Investment + ++ + +

Maintenance + ++ + +

++ Cheaper, +More Expensive

Table 2.4 Comparison of Four Wind Farm Topologies(Ref:8)

6) Integration of Wind Turbines into the Power Systems

Large-scale integration of wind turbines may have significant impacts on power

system operation. Traditionally, wind turbines are not required to participate in frequency and

voltage control. However, in recent years, attention has been increased on wind farm

performance in power systems. Consequently, some grid codes have been defined to specify

the requirements that wind turbines must meet in order to be connected to the grid. Examples

of such requirements include the capability of contributing to frequency and voltage control

by continuously adjusting active power and reactive power supplied to the transmission

135

system, and the power regulation rate that a wind farm must provide. Some of the

requirements can be dealt with by implementing control schemes in certain types of wind

turbines, such as reactive power control with wind turbines having power electronic

converters. Many research activities have been conducted in this area.

6.1) Requirements of Wind Turbine Grid Integration

6.1.1) Frequency and Active Power Control

The electrical supply and distribution systems used worldwide today are based on ac

systems (50 or 60 Hz). The frequency of a power system is proportional to the rotating speed

of the synchronous generators operating in the system. The generators in the same ac system

are synchronized, running at the same speed. Increasing the electrical load in the system tends

to slow down the generators and reduce the frequency. The task of frequency control of the

system is to increase or reduce the generated power so as to keep the generators operating in

the specified frequency range. However, renewable resources can only produce when the

source is available. For wind power, this is when and where the wind blows. This

characteristic is important when the amount of wind power covers a large fraction of the total

demand for electricity energy in the system. In order to be able to increase the power output

for frequency control, a wind turbine may have to operate at a lower power level than the

available power, which means low utilization of the wind energy resources. One way to

improve the situation may be the use of ―energy storage‖ technologies, such as batteries,

pump storage, and fuel cells, though the speed of response will vary depending on the energy

storage technology. So far large-scale, cost-effective energy storage technologies are yet to be

developed.[8]

6.1.2) Short Circuit Power Level and Voltage Variations

The short circuit power level at a given point in an electrical network is a measure of

its strength, and although it is not a direct parameter of voltage quality, it has a significant

influence. The ability of the grid to absorb disturbances is directly related to the short circuit

power level.

136

Considering a point in the network, the voltage far away from the point may not be

influenced by the conditions at this point. Zk is the equivalent impedance between the

concerned point and the remote location. Uk, is a nominal voltage of the point, and the short

circuit power level Sk in MVA can be found as U2

k /Zk. Strong and/or weak grids are terms

often used in connection with wind power installations. If the impedance Zk is small, the

voltage variations at PCC will be small (the grid is strong), but if Zk is large, the voltage

variations will be large (the grid is weak).

Figure 2.34 A simple system with an equivalent wind power generator connected to a network.

(a) System circuit and (b) phasor diagram(Ref:8)

Fig 2.34 illustrates an equivalent wind power generation unit, connected to a network

with short circuit impedance Zk. The network voltage at the assumed remote busbar and the

voltage at the point of common coupling (PCC) are Us and Ug, respectively. The output power

and reactive power of the generation unit are Pg and Qg, which correspond to a current Ig:

(2.13)

The voltage difference ΔU between the system and the connection point is given by

(2.14)

137

ΔU is related to the short circuit impedance, the real and reactive power output of the wind

power generation unit. It is clear that the variations of the generated power will result in

variations of the voltage at PCC.

Equation (2.14) indicates the relationship between the voltage and the power

transferred into the system. ΔU can be calculated with load flow methods as well as with

other simulation techniques. The voltage at PCC should be maintained within utility

regulatory limits. Operation of wind turbines may affect the voltage in the connected network.

If necessary, appropriate precautions should be taken to ensure that the wind turbine

installation does not bring the magnitude of the voltage outside the required limits.[8]

6.1.3) Reactive Power Control

Conventional reactive power concept is associated with the oscillation of energy

stored in capacitive and inductive components in a power system. Reactive power is produced

in capacitive components and consumed in inductive components.Asynchronous generator

can either produce or consume reactive power by controlling the magnetizing level of the

generator, i.e. a high magnetizing level results in high voltage and production of reactive

power.

The current associated with the reactive power flow causes system voltage drop as

aforementioned and also power losses. Furthermore, large reactive currents flowing in a

power system may cause voltage instability in the network due to the associated voltage drops

in the transmission lines. Therefore, reactive power control is important. The induction

generator based wind turbines are the consumer of reactive power. To minimize the power

losses and to increase voltage stability, these wind turbines are compensated to a level

depending on the requirements of the local utility or distribution company. For wind turbines

with PWM converter systems, the reactive power can be controlled by the converter. For

example, these wind turbines can have a power factor of 1.00 and also have the possibility to

control voltage by controlling the reactive power (generation or consumption of reactive

power).[8]

138

6.1.4) Flicker

Voltage variations caused by fluctuating wind power generationmay cause voltage

quality problems. Fluctuations in the system voltage (in terms of rms value) may cause

perceptible light flicker depending on the magnitude and frequency of the fluctuation. This

type of disturbance is called voltage flicker, commonly known as flicker.

The allowable flicker limits are generally established by individual utilities. Rapid

variations in the power output from a wind turbine, such as generator switching and capacitor

switching, can also result in variations in the rms value of the voltage. At certain rate and

magnitude, the variations cause flickering of the electric light. In order to prevent flicker

emission from impairing the voltage quality, the operation of the generation units should not

cause excessive voltage flicker.

Flicker evaluation based on IEC 1000-3-7 gives guidelines for emission limits of

fluctuating loads in medium voltage and high voltage networks. The basis for the evaluation

is a measured curve giving the threshold of visibility for rectangular voltage changes applied

to an incandescent lamp. The level of flicker is quantified by the shortterm flicker severity Pst,

which is normally measured over a 10-min period. Disturbances just visible are said to have a

flicker severity factor of Pst = 1. Furthermore, a long-term flicker severity factor Plt is defined

where Plt is measured over 2-h periods.

Determination of flicker emission can be done on the basis of measurement. IEC

61000-4-15 specifies a flickermeter, which can be used to measure flicker directly. The flicker

emissions may be estimated with the coefficient and factors, cf (Ψk, va) and kf(Ψk) obtained

from the measurements, which are usually provided by wind turbine manufacturers.[8]

6.1.5) Harmonics

Harmonics are a phenomenon associated with the distortion of the voltage and current

waveforms. Any periodical function may be expressed as a sum of sinusoidal waveforms with

different frequencies including the fundamental frequency and a series of integer multiples of

the fundamental component. Depending on the harmonic order these may cause damage of

various kinds to different type of electrical equipment. All harmonics cause increased currents

and possible destructive overheating in capacitors as the impedance of a capacitor goes down

139

in proportion to the increase in frequency. The higher harmonics may further give rise to

increased noise in analogue telephone circuits. The harmonic distortion is expressed as total

harmonic distortion (THD). THD and individual harmonics should meet the system

requirements.

The pulse width modulation (PWM) switching converters are used in most variable

speed wind turbine technologies today. The switching frequency is typically around a few

kilohertzs. The high-frequency harmonics are small in magnitude and are easier to be

removed by filters.[8]

6.1.6) Stability

The problem of network stability is often associated with different types of faults in

the network, such as tripping of transmission lines (e.g. overload), loss of production capacity,

and short circuits. Tripping of transmissions lines due to overload or component failure

disrupts the balance of power (active and reactive) flow. Although the capacity of the

operating generators may be adequate, large voltage drops may occur suddenly. The reactive

power flowing through new paths in a highly loaded transmission grid may force the voltage

of the network in the area down beyond the border of stability. Often a period of low voltage

is followed by complete loss of power. Loss of production capacity obviously results in a

large,momentary, power imbalance. Unless the remaining operating power plants have

enough ―spinning reserve,‖ that is, generators are not loaded to their maximum capacity, to

replace the loss within very short time, a large frequency and voltage drop will occur,

followed by complete loss of power. One way of dealing with this situation is to disconnect

the supply to some areas or some large consumers, so as to restore the power balance and to

limit the number of consumers affected by the fault.

Short circuits have a variety of forms, from the one-phase earth fault caused by trees,

to the three-phase short circuit with low impedance in the short circuit path. Many of these

faults are cleared by the relay protection of the transmission system, either by disconnection

and fast reclosure, or by disconnection of the equipment in question after a few hundred

milliseconds. In all the situations, the result is a short period with low or no voltage followed

by a period when the voltage restores. A large wind farm in the vicinity will see this event and

may be disconnect from the grid if no appropriate control has been implemented. This leads to

140

the situation ―loss of production capacity.‖ The disconnection of the wind farm will further

aggravate the situation and therefore, in some grid codes, wind turbines and wind farms are

required to have the ability of ride through. Studies show that different wind turbines may

have different control methods during the transients.[8]

6.2) Voltage Quality Assessment

The assessment of the impacts from integrating wind turbines may be performed

according to the methods given in the IEC 61400-21 /2/ to determine the acceptability of such

integration. Methods include:

• steady-state voltage

• flicker

• harmonics

6.2.1) Steady-State Voltage

The grid and wind turbine voltage should be maintained within the utility limits.

Operation of a wind turbine may affect the steady-state voltage in the network. It is

recommended that load-flow analyses be conducted to assess this effect to ensure that the

wind turbine installation does not bring the magnitude of the voltage beyond the required

limits of the network. In general, some extreme case of the loads and the wind turbine

production may be checked for compatibility, such as

• low loads and low wind power,

• low loads and high wind power,

• high loads and low wind power, and

• high loads and high wind power.

Depending on the scope of the load-flow analysis, a wind turbine installation may be

assumed as a PQ node, which may use 10-min average data (Pmc and Qmc ) or 60-s average

data (P60 and Q60) or 0.2-s average data (P0.2 and Q0.2).

A wind farm with multiple wind turbines may be represented with its output power at

the PCC. Ten-minute average data (Pmc and Qmc) and 60-s average data (P60 and Q60) can be

141

calculated by simple summation of the output from each wind turbine, whereas 0.2-s average

data (P0.2 and Q0.2) may be calculated according to (2.15) and (2.16):

(2.15)

(2.16)

where Pn,i and Qn,i are the rated real and reactive power of the individual wind turbine and Nwt

is the number of wind turbines in the group.[8]

6.2.2) Voltage Fluctuations

There are two types of flicker emissions: the flicker emission during continuous

operation and the flicker emission due to generator and capacitor switchings. Often, one or the

other will be predominant.

The flicker emissions from a wind turbine installation should be limited to comply

with the flicker emission limits. However, different utilities may have different flicker

emission limits. The assessments of the flicker emissions are described below.

6.2.2.1) Continuous Operation

The flicker emission from a single wind turbine during continuous operation may be

estimated by

(2.17)

where cf (Ψk, va) is the flicker coefficient of the wind turbine for the given network impedance

phase angle Ψk at the PCC and for the given annual average wind speed va at hub-height of

the wind turbine.

A table of data produced from the measurements at a number of specified impedance

angles and wind speeds can be provided by wind turbine manufacturers. From the table, the

flicker coefficient of the wind turbine for the actual Ψk and va at the site may be found by

applying linear interpolation. The flicker emission from a group of wind turbines connected to

the PCC is estimated by (2.18):

142

(2.18)

where cf,i (Ψk, va) is the flicker coefficient of the individual wind turbine, Sn,i is the rated

apparent power of the individual wind turbine, and Nwt is the number of wind turbines

connected to the PCC.

If the limits of the flicker emission are known, the maximum allowable number of

wind turbines for connection can be determined.[8]

6.2.2.2) Switching Operations

The flicker emission due to switching operations of a single wind turbine can be

calculated as

(2.19)

where kf(Ψk) is the flicker step factor of the wind turbine for the given Ψk at the PCC. The

flicker step factor of the wind turbine for the actual Ψk at the site may be found by applying

linear interpolation to the table of data produced from the measurements by wind turbine

manufacturers.

The flicker emission from a group of wind turbines connected to the PCC can be

estimated from

(2.20)

where N10,i and N120,i are the number of switching operations of the individual wind turbine

within 10-min and 2-h periods, respectively, kf,i (Ψk) is the flicker step factor of the individual

wind turbine, and Sn,i is the rated apparent power of the individual wind turbine. Again, if the

limits of the flicker emission are given, the maximum allowable number of switching

operations in a specified period, or the maximum permissible flicker emission factor, or the

required short circuit capacity at the PCC may be determined.[8]

6.2.3) Harmonics

A wind turbine with an induction generator directly connected to the grid is not

expected to cause any significant harmonic distortions during normal operation. Only wind

143

turbines with power electronics need to be checked concerning harmonics. The harmonic

current emission of such wind turbine system is normally given in the power quality data

sheet, while the limits for harmonics are often specified for harmonic voltages. Thus harmonic

voltages should be calculated from the harmonic currents of the wind turbine, which requires

the information of the grid impedances at different frequencies.[8]

2.2.5 Environmental Aspects

2.2.5.1 Audible Noise

A wind turbine with an induction generator directly connected to the grid is not

expected to cause any significant harmonic distortions during normal operation. Only wind

turbines with power electronics need to be checked concerning harmonics. The harmonic

current emission of such wind turbine system is normally given in the power quality data

sheet, while the limits for harmonics are often specified for harmonic voltages. Thus harmonic

voltages should be calculated from the harmonic currents of the wind turbine, which requires

the information of the grid impedances at different frequencies.

Source Noise Level (dB)

Elevated Train 100

Noisy Factory 90

Average Street 70

Average Factory 60

Average Office 50

Quiet Conversation 30

Table 2.5 Noise Levels of Some Commonly Known Sources Compared with Wind Turbine(Ref:3)

The table indicates that the turbine at a 50-m distance produces no noise higher than

the average factory. This noise, however, is a steady noise. Additionally, the turbine makes a

louder noise while yawing under the changing wind direction. In either case, the local noise

ordinance must be complied with. In some instances, there have been cases of noise

complaints reported by the nearby communities. Although noise pollution is not a major

144

problem with offshore wind farms, it depends on the size whether or not one can hear the

turbines while operating. It has also been suggested that the noise from the turbines travels

underwater and disturbs sea life as well.

In general, there are two main sources of noise emitted from the wind turbine. One is

mechanical, which is inherent in the gearing system. The other is created by the aerodynamics

of the rotating blade, which emits a noise when passing the tower, known as the tower thump

or simply the aerodynamic noise. The first may be at a somewhat low level, generally uniform

over the year. The other (the tower thump) can be loud. It varies with the speed of blade

rotation and may cause most of the problems and complaints. Some residents describe the

tower thump noise as being like a boot in a tumble dryer. A large wind turbine can produce an

aggregate noise level of up to 100 dB(A), which weakens to a normal level within a 1.5-km

distance. The worst conditions are when the wind is blowing lightly and the back-ground

noise is minimal. Residents up to 1-km radius have complained to the Environmental Health

Department about noise from such turbines.[3]

2.2.5.2 Electromagnetic Interference (EMI)

Any stationary or moving structure in the proximity of a radio or TV tower interferes

with the signals. The wind turbine tower, being a large structure, can cause objectionable EMI

in the performance of a nearby transmitter or a receiver. Additionally, the rotating blades of

an operating wind turbine may reflect impinging signals so that the electromagnetic signals in

the neighbourhood may experience interference at the blade passage frequency. The exact

nature and magnitude of such EMIs depend on a number of parameters. The primary

parameters are the location of the wind turbine tower relative to the radio or TV tower,

physical and electrical properties of the rotor blades, the signal frequency modulation scheme,

and the high-frequency electromagnetic wave propagation characteristics in the local

atmosphere. EMI may be a serious issue with wind farm planning. For example, 5 of the 18

offshore wind farms planned around the U.K. coasts were blocked by the U.K. Ministry of

Defense due to concerns that they may interfere with radar and flight paths to airfields close

to the proposed sites. Detailed studies on the precise effects of wind turbines on radar and

possible modifications in radar software may mitigate the concerns. The potential cost of such

studies and legal appeals should be factored into the initial planning of large wind farms.[3]

145

2.2.5.3 Effect on Birds

The effect of wind farms on wild life and avian population that includes endangered

species protected by federal laws has created controversy and confusion within the

mainstream environmental community. The breeding and feeding patterns of some birds may

be disturbed. The wind turbine blade can weigh up to 1.5 t and the blade tips can travel at up

to 200 mph, a lethal weapon against any airborne creature. The birds may be killed or at least

injured if they collide with a blade. Often the suction draft created by the wind flowing to a

turbine draws the birds into the airstream headed for the blades. Although less usual, birds are

attracted by the tower hum and simply fly into the towers. On the other hand, studies at an

inshore site near Denmark have determined that birds alter their flight paths 200 m around the

turbine. Thus, a wind farm can significantly alter the flight paths of large avian populations.

In another study, the population of water fowl declined 75 to 90% within 3 yr after installing

an offshore wind farm in Denmark. Such a large decline could have a massive impact on the

ecosystem of the surrounding area.

The initial high bird-kill rate of the 1980s has significantly declined with larger

turbines having longer slower-moving blades, which are easier for the birds to see and avoid.

Tubular towers have a lower bird-hit rate compared to lattice towers, which attract birds to

nest. The turbines are now mounted on either solid tubular towers or towers with diagonal

bracing, eliminating the horizontal supports that attracted the birds for nesting. New wind

farms are also sited away from avian flight paths.

It is generally agreed that migration paths and nesting grounds of rare species of birds

should be protected against the threat of wind farms. Under these concerns, obtaining

permission from the local planning authorities can take considerable time and effort.[3]

2.2.5.4 Other Impacts

The visual impact of the wind farm may be unpleasant to the property owners around

the wind farm. Wind farm designers can minimize aesthetic complaints by installing identical

turbines and spacing them uniformly.

Because wind is a major transporter of energy across the globe, the impact of the

energy removed by many large wind farms on a grand scale may impact the climate.[3]

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2.2.6 Potential Catastrophes

A fire or an earthquake can be a major catastrophe for a wind power plant.

2.2.6.1 Fire

Fire damage amounts to 10 to 20% of the wind plant insurance claims. A fire on a

wind turbine is rare but difficult to fight. Reaching the hub height is slow, and water pressure

is always insufficient to extinguish the fire. This generally leads to a total loss of the turbine,

leading to 9 to 12 months of downtime and lost revenue. The cost of replacing a single 30-m

blade can exceed $100,000, and that of replacing the whole 3-MW turbine can exceed $2

million.

The following are some causes of fire in wind turbines:

1) Lightning Strike

Lightning arresters are used to protect the turbine blades, nacelle, and tower assembly.

However, if lightning is not properly snubbed, it can lead to local damage or total damage if it

leads to sparks and subsequent turbine fire. Lightning occurrences depend on the location.

Offshore turbines are more prone to lightning than land turbines. On land, lightning is rare in

Denmark, whereas it is frequent in northern Germany and the Alps regions, and even more

frequent in parts of Japan and the U.S., particularly in Florida and Texas. The growing trends

of using electrically conducting carbon fiber-epoxy composites for their high strength and low

weight in the blade construction make the blades more vulnerable to lightning.

For this reason, some manufacturers avoid carbon fibers in their blades, more so in

large, tall turbines for offshore installations.[3]

2) Internal Fault

Any electrical or mechanical fault leading to a spark with the transmission fluids or other

lubricants is a major risk. The flammable plastic used in the construction, such as the nacelle

covers, is also a risk.

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Typical internal faults that can cause excessive heat leading to a fire are as follows:

• Bearings running dry and failing

• Failing cooling system

• Brakes becoming hot under sustained braking

• Oil and grease spills

• Short circuit in the battery pack of the pitch-control system

• Cables running against rotating or vibrating components

Frequent physical checks of the entire installation, servicing and maintenance, and a

condition-monitoring system, accessed remotely by computers used in modern installations,

can detect potential fire hazards and avoid fires.[3]

2.2.6.2 Earthquake

Lateral loads resulting from an earthquake are important data to consider in designing

a tall structure in many parts of the world. The wind tower, being always tall, is especially

vulnerable to seismic events. The seismic energy is concentrated in the 1- to 10-Hz frequency

band. A dynamic analysis is required, as a dynamic response amplification is expected.

However, because of the complexities in modeling and performing such analyses, it has been

standard practice to represent seismic loads with equivalent static loads. The severity of the

seismic loads, the potential failure modes, and the resulting effects require that design

engineers make reasonable tradeoffs between potential safety concerns and economics during

the design phase. To alleviate this difficulty, the recent trend in the U.S. has been to require

dynamic analyses to estimate seismic stresses. For example, all primary components of

nuclear power plants in the U.S. must be dynamically analyzed for the specified seismic

loadings. This is required even for plants located in seismically inactive areas.[3]

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2.2.7 Potential Technology Development and Recent Trends

2.2.7.1 Potential Technology Development

Figure 2.35 World Total Installed Capacity in 2001-2010 (Ref: 9)

According to the World Wind Energy Report 2009:

Worldwide capacity reached 159213 MW, out of which 38312 MW were added.

(Figure 2.35)

Wind power showed a growth rate of 31,7 %, the highest rate since 2001.

The trend continued that wind capacity doubles every three years.

All wind turbines installed by the end of 2009 worldwide are generating 340 TW per

annum, equivalent to the total electricity demand of Italy, the seventh largest economy of the

world, and equalling 2 % of global electricity consumption.

The wind sector in 2009 had a turnover of 50 billion.

The wind sector employed 550000 persons worldwide. In the year 2012, the wind

industry is expected for the first time to offer 1 million jobs.

China continued its role as the locomotive of the international wind industry and

added 13800 MW within one year – as the biggest market for new turbines –, more than

doubling the installations for the fourth year in a row.

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The USA maintained its number one position in terms of total installed capacity and

China became number two in total capacity, only slightly ahead of Germany, both of them

with around 26000 Megawatt of wind capacity installed.

Asia accounted for the largest share of new installations (40,4 %), followed by North

America (28,4 %) and Europe fell back to the third place (27,3 %).

Latin America showed encouraging growth and more than doubled it installations,

mainly due to Brazil and Mexico.

A total wind capacity of 200000 Megawatt will be exceeded within the year 2010.

Based on accelerated development and further improved policies, WWEA increases its

predictions and sees a global capacity of 1900000 Megawatt as possible by the year 2020. [9]

Figure 2.36 Top 10 Countries by Growth Rate in 2008 and 2009 (Ref:9)

The growth rate is the relation between the new installed wind power capacity and the

installed capacity of the previous year. The highest growth rates of the year 2009 with more

than 100 % could be found in Mexico which quadrupled its installed capacity, once again in

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Turkey (132 %) which had the highest rate in the previous year, in China (113 %) as well as

in Morocco (104 %).(Figure 2.36)[9]

In the year 2009, altogether 82 countries used wind energy on a commercial basis, out

of which 49 countries increased their installed capacity.[9]

China and the USA established themselves as the by far largest markets for new wind

capacity, together accounting for 61,9 % of the additional capacity, a share which was

substantially bigger than in the previous year (53,7 %).[9]

Figure 2.37 Top 10 Countries by Total Capacities in 2008 and 2009 (Ref: 9)

Nine further countries could be seen as major markets, with turbine sales in a range

between 0,5 and 2,5 Gigawatt: Spain, Germany, India, France, Italy, the United Kingdom,

Canada, Portugal, and Sweden. [9]

Country Share of New Capacity 2009:

Twelve markets for new turbines had a medium size between 100 and 500 Megawatt: Turkey,

Australia, Denmark, Mexico, Brazil Ireland, Poland, Japan, New Zealand, Belgium, South

Korea, and Greece. [9]

Offshore Wind Turbines:

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Offshore wind capacity continued to grow in the year 2009. By the end of the year,

wind farms installed in the sea could be found in twelve countries, ten of them in Europe and

some minor installations in China and Japan. Total installed capacity amounted to almost two

Gigawatt, 1,2 % of the total wind capacity worldwide. Wind turbines with a capacity of 454

Megawatt were added in 2009, with major new offshore wind farms in Denmark, the United

Kingdom, Germany, Sweden and China. The growth rate of offshore wind is with 30 %

slightly below the general growth rate of wind power. In Denmark, so far the largest offshore

wind farm was inaugurated in the North Sea: Horns Rev II, 209 Megawatt. China installed the

first major offshore wind farm outside of Europe – a 21 Megawatt, near Shanghai.[9]

Position

2009

Country Total

Offshore

Capacity

[MW] End

2009

New

Offshore

Capacity

[MW]

Installed in

2009

Total

Offshore

Capacity

[MW] End

2008

Rate of

Growth [%]

1 United Kingdom 688,0 104,0 574,0 18,1

2 Denmark 663,6 237,0 426,6 55,6

3 Netherlands 247,0 0,0 247,0 0,0

4 Sweden 164,0 30,0 134,0 22,4

5 Germany 72,0 60,0 12,0 500,0

6 Belgium 30,0 0,0 30,0 0,0

7 Finland 30,0 0,0 30,0 0,0

8 Ireland 25,0 0,0 25,0 0,0

9 China 23,0 21,0 2,0 1050,0

10 Spain 10,0 0,0 10,0 0,0

11 Norway 2,3 2,3 0,0 /

12 Japan 1,0 0,0 1,0 0,0

TOTAL 1955,9 454,3 1491,6 30,5

Table 2.6 Offshore Overall Capacity in 2009 (Ref: 9)

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Figure 2.38 Top 5 Countries in Offshore Wind (Ref: 9)

Continental Distribution:

Figure 2.39 Continental Distribution 2007-2009(Ref: 9)

The most dynamic progress of the wind industry took place in Asia, followed by North

America and the focus of the global wind sector moved further away from Europe.[9]

2.2.7.2 Recent Trends

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1) Small Wind Systems

The vast majority of wind power is generated by large wind turbines feeding into the

electricity grid, while small wind turbines generally provide electricity directly to customers.

The United States is the leading world producer of small wind turbines. These

residential turbines are erected and connected directly to the customer‘s facility or to the

electricity distribution system at the customer‘s site. The manufacture and marketing of wind-

powered electric systems sized for residential homes, farms, and small businesses have

experienced major growth in the past decade. These small wind turbines, defined as 100 kW

or less in capacity, have seen significant market growth, and the industry has set ambitious

growth targets: growth at 18 to 20 percent through 2010.[5]

2) System-Design Trends

Significant research and development work is underway at the NREL and the National

Wind Technology Center in Golden, CO. The main areas of applied research conducted at the

NWTC are as follows:

• Aerodynamics to increase energy capture and reduce acoustic impacts.

• Inflow and turbulence to understand the nature of wind.

• Structural dynamics models to minimize the need of prototypes.

• Controls to enhance energy capture, reduce loads, and maintain stable closed-loop behavior

of these flexible systems are an important design goal.

• The wind turbine design progress includes larger turbines on taller towers to capture higher

wind speed; the design difficulty increases as these machines become larger and the towers

become taller.[3]

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2.2.8 Future Expectations

2.2.8.1 Short Term: Present to 2020

The key technological issues for wind power focus on continuing to develop better

turbine components and to improve the integration of wind power into the electricity system,

including operations and maintenance, evaluation, and forecasting. Goals appear relatively

straightforward: taller towers; larger rotors; power electronics; reducing the weight of

equipment at the top and cables coming from top to bottom; and ongoing progress through the

design and manufacturing learning curve. Figure 2.40 summarizes the incremental

improvements under consideration.

Although no big breakthroughs are anticipated, continuous improvement of existing

components is anticipated, and many are already being actively developed. For example, there

are advanced rotors that use new airfoil shapes specifically designed for wind turbines,

instead of those based on the design of helicopter blades. These rotors are thicker at points of

highest stress and reduce loads during turbulent winds by flying the blades using turbine

control systems. Other improvements include the use of composite materials and advanced

drive trains. In particular, gear boxes are a major area of concern for reliability. Approaches

for improving of this component include direct drive generators; greater use of rare-earth

permanent magnets in generator design; possibility of single-stage drives using low-speed

generators; and distributed drive trains using the rotor to drive several parallel generators.

Advanced towers are a major focus for innovation, given the current need for large cranes and

transport of large tower and blade sections. Concepts under investigation include self-erecting

towers, blade manufacturing on site, vibration damping, and tower drive train interactions.

There is certain to be some development of offshore wind in the United States in the

near term, but it is not expected that this will have a significant impact before 2020.

Nonetheless, there is a near-term opportunity to learn from offshore projects in Europe and

the United States, if offshore wind is going to have an impact in the medium term.

Other near-term opportunities will lie in improving the integration of existing wind

power plants into the transmission and distribution system, which includes using improved

computational models for simulating and optimizing system integration.[5]

155

Figure 2.40 Areas of Potential Wind Power Technology Improvements(Ref:5)

2.2.8.2 Medium Term: 2020 to 2035

Mid-term wind technology development will have two thrusts: the movement toward

offshore, and its implications for turbine design; and the development of efficient low-wind

speed turbines. Development of offshore wind power plants has already begun in Europe

(approximately 1200 MW of installed capacity), but progress has been slower in the United

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States. Nine projects are in various stages of development in state and federal waters. In

addition to technical risks and higher costs, these projects have been slowed by social and

regulatory challenges.

In the mid-term, offshore turbines will have a larger size and generating capacity than

onshore turbines, but, due primarily to technical and cost concerns, development will likely

lag behind onshore machines. Transmission siting issues with offshore wind power plants will

be simplified because of fewer siting impediments. However, underwater cables must be

carefully constructed, and there will likely be a move to develop microgrids with HVDC to

integrate the offshore resources. Offshore wind technologies face several transition problems

as they move from near-shore, land-based sites to offshore sites of various depths, and finally

floating designs. Assessment tools for sensitive marine areas, wind loads, and system design

are not now ready for offshore development. Offshore projects must be built to handle both

wind and wave loads, and components must be able to endure marine moisture and extreme

weather. Offshore wind projects have a higher balance of station cost (approximately 2/3 of

total costs) than onshore projects, and thus will rely on cost reductions across the system in

order to become more competitive. All of these developments pose both technological and

organizational problems and will require continuous research and development in order to be

feasible. It should be noted that challenges posed by the greater technical difficulties of

offshore wind power development are being addressed by other countries. However, political,

organizational, social, and economic obstacles may continue to inhibit investment in offshore

wind power development, given the higher risk compared to onshore wind energy

development.

In terms of onshore development, as the higher wind speed sites are used, wind power

development will move to lower wind speed sites, which will require turbines that are

relatively efficient at lower wind speeds, necessitating larger rotors with lighter, stronger

materials, and increased tower height.[5]

2.2.8.3 Long Term: After 2035

At present, no revolutionary technology to extract energy from wind has been

proposed, but several designs, e.g., vertical wind turbines or eggbeaters, are again under

consideration. There have been conceptual proposals to access high-altitude winds using

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balloons or kites. Component improvements will continue, with additional emphasis on

offshore turbine installation. Floating offshore platforms may gain interest, but first must

come experience from anchored offshore wind facilities.[5]

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2.3 Geothermal Energy and Electric Generation

2.3.1 Introduction

Geothermal comes from the Greek words thermal which means heat and geo which

means earth. Georthemal is the thermal energy contained in the rock and fluid in the earth‘s

crust. It is almost 4,000 miles from the surface of the earth to its center; the deeper it is the

hotter it gets. The outer layer of the earth, the crust, is 35 miles thick and insulates the surface

from the hot interior.

After the Second World War many countries started using geothermal energy,

considering it to be economically competitive with other forms of energy. Geothermal energy

did not have to be imported and, in some cases, it was the only energy source available

locally.[10]

Over the past 20–25 years, worldwide electricity production based on geothermal

sources has increased significantly; the installed generating capacity has grown from

1300MWe in 1975 to almost 10,000MWe in 2007. About 75% of this nearly 9000MWe

increase comes from about 20 sites that produce in excess of 100MWe. These geothermal

power projects convert the energy contained in hot rock into electricity by using water to

adsorb heat from the rock and transport it to the earth‘s surface, where it is converted to

electrical energy through turbine-generators. Moreover, direct applications of geothermal heat

offsetting the need for electricity production and burning of fossil fuels has also gained

importance over the years; the estimated installed thermal capacity of direct-use projects was

more than 28,000MWt in 2005.

It is estimated that more than 97% of current geothermal reservoir production is

frommagmatically driven reservoirs. Geothermal reservoirs may also develop outside regions

of recent volcanic activity, where deeply penetrating faults allow groundwater to circulate to

depths of several kilometers and become heated by the geothermal gradient.

More than 90% of exploited fields are ―liquid-dominated‖ under pre-exploitation

conditions with reservoir pressures increasing with depth in response to liquid-phase density.

―Vapour-dominated‖ systems, such as The Geysers in California (USA) and Larderello (Italy)

have vertical pressure gradients controlled by the density of steam. In the vapor-dominated

systems, steam is cleaned and then passed directly into low-pressure turbines. Typically,

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water from high-temperature (>240 ◦C) reservoirs is partially flashed to steam. Heat is

converted to mechanical energy by passing steam through low-pressure steam turbines. A

small fraction of geothermal generationworldwide is generated using a heat exchanger and

secondary working fluid to drive turbines.[11]

2.3.2 Geothermal Resources

Geothermal energy (earth heat) can be found anywhere in the world. But the high-

temperature energy that is needed to drive electric generation stations is found in relatively

few places.

Figure 3.1 A Geothermal Reservoir [Ref:12]

2.3.2.1 Model of a Hydrothermal Geothermal Resource

There appear to be five features that are essential to making a hydrothermal (i.e., hot

water) geothermal resource commercially viable. They are:

(a) a large heat source

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(b) a permeable reservoir

(c) a supply of water

(d) an overlying layer of impervious rock

(e) a reliable recharge mechanism.

A highly schematic depiction of such a system is shown in Fig. 3.2.

Cold recharge water is seen arriving as rain (point A) and percolating through faults

and fractures deep into the formation where it comes in contact with heated rocks. The

permeable layer offers a path of lower resistance (point B) and as the liquid heats it becomes

less dense and tends to rise within the formation. If it encounters a major fault (point C) it will

ascend toward the surface, losing pressure as it rises until it reaches the boiling point for its

temperature (point D). There it flashes into steam which emerges as a fumarole, a hot spring,

a mud pot, or a steam-heated pool (point E). The boiling curve is the locus of saturation

temperatures that correspond to the local fluid hydrostatic pressure.

Figure 3.2 Schematic Model of a Hydrothermal Geothermal System(Ref:13)

The intent of a geothermal development project is to locate such systems and produce

them by means of strategically drilled wells. As might be presumed, most (but not all)

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hydrothermal systems give away their general location through surface thermal manifestations

such as the ones described above.

If any one of the five features listed as needed for a viable hydrothermal resource is

lacking, the field generally will not be worth exploiting. For example, without a large heat

source geofluid temperatures will be relatively low, i.e., the thermal energy of the system will

be insufficient to support exploitation long enough to make it economic. Without sufficient

permeability in the formation, the fluid will not be able to move readily through it, i.e., it will

not be able to remove much of the stored thermal energy in the rock. Furthermore, low

permeability will cause poor well flow or, even worse, may prevent any production from the

reservoir. Without fluid in the system there is no heat transfer medium and the thermal energy

of the formation will remain in the reservoir. Without an impermeable cap rock, the geofluids

will easily escape to the surface appearing as numerous thermal manifestations and the

pressure in the formation will quickly dissipate. And lastly, without a reliable and ample

recharge to the reservoir, the geofluid will eventually become depleted when it supplies a

power plant.

With the exception of requirements (a) and (d), deficiencies in the others have been

addressed through research and field practice. Insufficient permeability can sometimes be

remedied by artificial means such as hydraulic fracturing (called "hydrofracing") in which

high-pressure liquid is injected from the surface through wells to open fractures by means of

stress cracking. However, unless the newly created widened fractures are held open with

"proppants" they will re-close when the injection ceases. If little water is present in the

formation or recharge is meager, all untlsed geofluid from the plant can be reinjected.

Furthermore, external fluids can be brought to the site by some means and injected into the

formation. Such a process exists at The Geysers field in northern California in the United

States in which treated municipal waste water from nearby communities is sent to the field via

pipeline to assist in the maintenance of an inventory of fluid in the reservoir.[13]

2.3.2.2 Other Types of Geothermal Resources

As of 2004, hydrothermal resources are the only geothermal systems that have been

developed commercially for electric power generation. However, there are three other forms

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of geothermal energy that someday may reach the commercial stage. They are: hot dry rock,

HDR (or enhanced geothermal systems, EGS): geopressure; and magma energy.

1) Hot Dry Rock (HDR)

There are many geothermal prospects that have high temperature but are lacking fluid

in the formation or the permeability is too low to support commercial development. These

systems can be "enhanced" by engineering the reservoirs through hydraulic fracturing. An

injection well is drilled into the hot formation to a depth corresponding to the promising zone.

Cold water is injected under high pressure to open existing fractures or create new ones.

Once the formation reaches a state of sufficient volume and permeability, another well (or

wells) is drilled to intercept the newly formed "reservoir". Ideally, a closed loop is thus

created whereby cold water is pumped down the injection well and returned to the surface

through the production well after passing through the hot, artificially-fractured formation. The

ideal HDR concept is illustrated in Fig. 3.3.

Figure 3.3 Ideal Hot Dry Rock Production Scheme(Ref:13)

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Considerable research has gone into development of the HDR concept and a good deal

continues today. Table 3.1 summarizes these projects.

Country Location Dates

United States Fenton Hill, New Mexico 1973-1996

United Kingdom Rosemanowes 1977-1991

Germany Bad Urach 1977-1990

Japan Hijiori 1985-present

Ogachi 1986-present

France Soultz 1987-present

Switzerland Basel 1996-present

Australia Hunter Valley 2001-present

Cooper Basin 2002-present

Table 3.1 HDR Projects Worldwide(Ref:13)

There are many practical problems in developing a HDR system. It is difficult to

control very deep, directional, geothermal wells. Drilling techniques in the oil industry now

permit wells to be turned 90 ~ while being drilled, allowing the well to drain several vertical

pockets of petroleum. However, oil wells tend to be shallower than the ones envisioned for

HDR, the temperatures encountered are far lower, and the rocks are not as hard as those found

in geothermal regions. Furthermore, the HDR wells must be precisely aimed to hit the deep

target in order to form a closed fluid circuit. Lastly. if some of the engineered fractures are not

connected to the production well, injected fluid may be lost to the formation. This would

require continuous makeup water to maintain the power plant in operation. Some of these

difficulties appear to have been at least partially solved in the on-going research, particularly

at the Japanese sites.[13]

2) Geopressure

Along the western and northern coastline of the Gulf of Mexico, there is a potent

energy resource called "geopressure". During the drilling for oil and gas in the sedimentary

coastal areas of Texas and Louisiana, fluids have been encountered with pressures greater

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than hydrostatic and approaching lithostatic. Hydrostatic pressure increases with depth in

proportion to the weight of water, i.e., at about 0.465 lbf/in2 per ft. However in formations

where the fluid plays a supportive role in maintaining the structure of the reservoir, the weight

of the solid overburden roughly doubles the gradient to approach the lithostatic value of 1.0

lbf/in2 per ft.

Geopressured reservoirs were formed along the Gulf Coast through the steady

deposition of sediments that created an overburden on the underlying strata. Figure 3.4 is a

simplified cross-section through a geopressured reservoir. Periodically, subsidence occurred

causing compaction of the rock layers. Subsidence also resulted in steeply dipping faults that

can isolate elements of the formation. With the heavy overburden and no way to dissipate the

load, the pressure within these lenses of sand grows to levels in excess of hydrostatic.

In the geopressured reservoirs of the Gulf Coast, the pressures were sufficiently high

to prevent drilling for oil and gas. With improved understanding of these zones and better

drilling techniques, these reservoirs can now be safely drilled.

Geopressured reservoirs are characterized by three important properties that make

them potentially attractive for geothermal exploitation: (1) very high pressure, (2) high

temperature, and (3) dissolved methane.

Figure 3.4 Cross-section Schematic of a Geopressured Reservoir(Ref:13)

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The first property allows the use of a hydraulic turbine to extract the mechanical

energy stored in the form of high pressure; the second property allows the use of a heat engine

of some kind to extract the thermal energy; and the last property allows for either the

combustion of the gas on site for power generation or for sale to enhance the economics of a

development project.

However, there are six criteria that must be satisfied before geopressured reservoirs

can be commercially developed; these are:

Is the fluid hot enough, say >230°C?

Is there sufficient methane dissolved in the fluid?

Is the high-pressure sand sufficiently permeable?

Is the high-pressure sand sufficiently thick?

Is the sand formation fault-bounded but not too fractured?

Can we guarantee that no subsidence will occur?

The economic viability of a geopressured geothermal project requires a "yes" answer to all of

these questions.[13]

3) Magma Energy

The last of the geothermal resources is one that goes directly to the source of the heat,

namely, a magma body relatively close to the surface of the earth. The concept is to drill a

well into the magma, insert an injection pipe and pump cold water down the well under great

pressure. The cold fluid will solidify the molten magma into a glassy substance that should

crack under the thermal stress imposed on it. If the water can be made to return to the surface

by passing upward through the cracked, extremely hot glassy material, it would reach the

surface hot and ready for use in a Rankine-type power plant.

As simple as it is to describe the concept, it is not as easy to carry out such a plan. The

U.S. Dept. of Energy conducted two research projects aimed at understanding the magma

environment in the 1970s and 1980s. The first one was carried out at the lava lake within the

crater of Kilauea Iki on the island of Hawaii. This effort succeeded in drilling through the

solidified crust of the lake into the still-molten lava that had a temperature of about 1000°C

(1800°F). In fact 105m of core were obtained from the melt zone and several experiments

were run to understand the mechanism of energy extraction from a lava body.

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The second research program, the Magma Energy Program, was directed at obtaining

a better scientific understanding of the existence and behavior of large magma bodies within

calderas. The one selected for study in the mid- 1980s was the Long Valley caldera in central

California and the research was performed by the Sandia National Laboratory of

Albuquerque, New Mexico. The caldera is an oval-shaped region about 18x32 km with a

prominent resurgent dome. At the time, the dome had risen some 235 mm over the period

from 1980-1985, making it both scientifically interesting and practically important to gain a

clearer understanding of the phenomenon.

The original goals of the program were to:

Demonstrate the existence of crustal magma bodies at depths less than25,000 ft:

Develop and test new drilling technology for hostile environments:

Better understand the creation and evolution of the Long Valley caldera:

and

Better define the hydrothermal system related to the caldera.

An ambitious exploration well was planned, targeted for a final depth of 20,000 ft (6000 m).

The conceptual design of the well is shown in Fig. 3.5 (to scale in vertical direction). Since an

existing 40-in diameter mud riser was in place to a depth of 39 ft from an earlier aborted well.

this was used instead of the planned 40-in surface casing. The well was to be drilled in four

phases: Phase I- to 2500 ft, Phase II- to 7500 ft, Phase III- to 14,000 ft or 300°C (600°F)

whichever came first, and Phase IV- to a total depth of 20,000 ft and 500°C (900°F). In 1989,

Phase I was successful in reaching 2568 ft with the 20-in casing, alter encountering massive

lost circulation at the shallowest depths. Phase II was completed to 7588 ft in November

1991. Core samples were taken at the 2568 ft and the 7588 ft points by drilling ahead some

100-200 ft. The well was not continued beyond Phase II owing to a shift in DOE policy away

from fundamental research and more toward applied research. In 1996 the well was handed

over to the U.S. Geological Survey for use as a monitoring well.

Since the well only reached depths that were routinely achieved at other geothermal

fields, it failed to produce much new drilling technology. For example, it had been planned to

develop insulated drill pipe to maintain the drilling muds at reasonable temperatures in

extremely high temperature formations: this was not done. It did produce some scientific

information that led to a better understanding of the nature of the Long Valley caldera, but no

167

further projects have appeared to try to tap the vast amount of thermal energy contained in

near-surface magma bodies.[13]

Figure 3.5 Conceptual Design of Long Valley Magma Energy Exploratory Well(Ref:13)

2.3.3 Geothermal Power Plants

Geothermal power plants use the natural hot water and steam from the earth to turn

turbine generators for producing electricity. Unlike fossil fuel power plants, no fuel is burned

168

in these plants. Geothermal power plants give off water vapours but have no smoky

emissions. Geothermal electricity is for the base load power as well as the peak load demand.

Geothermal electricity has become competitive with conventional energy sources in many

parts of the world.[10]

Figure 3.6 A Geothermal System(Ref:12)

Figure 3.7 Turbine Generator(Ref:12)

169

Natural steam from the production wells power the turbine generator. The steam is

condensed by evaporation in the cooling tower and pumped down an injection well to sustain

production.

Like all steam turbine generators, the force of steam is used to spin the turbine blades

which spin the generator, producing electricity. But with geothermal energy, no fuels are

burned.[12]

2.3.3.1 Dry (Direct) Steam Power Plants

Dry-steam plants were the first type of geothermal power plant to achieve commercial

status. Their history goes back 100 years to 1904 when Prince Piero Ginori Conti built and

operated a tiny steam engine using the natural steam jets that issued from the ground at

Larderello in the Tuscany region of Italy. Since the geofluid consisted solely of steam, it was

fairly easy to hook up a mechanical device to take advantage of the available energy.

Although the Prince's engine only generated enough electrical power to illuminate five light

bulbs in his factory, it was the springboard for larger plants.[13]

Figure 3.8 Lardarello, Tuscany, Northern Italy[Ref:12]

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Dry steam power plants are the simplest and most economical technology, and

therefore are widespread. The dry steam power plant is suitable where the geothermal steam is

not mixed with water. Production wells are drilled down to the aquifer and the superheated,

pressurized steam (180 - 350°C) is brought to the surface at high speeds, and passed through a

steam turbine to generate electricity.

Figure 3.9 Principle of Dry Steam Power Plant(Ref:12)

In simple power plants, the low pressure steam output from the turbine is vented to the

atmosphere. This improves the efficiency of the turbine and avoids the environmental

problems associated with the direct release of steam into the atmosphere. The United States

and Italy have the largest dry steam geothermal resources; these resources are also found in

Indonesia, Japan and Mexico.[10]

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Figure 3.10 The Geysers Power Plant, California(Ref:12)

The first geothermal power plants in the U.S. were built in 1962 at The Geysers dry

steam field, in northern California. It is still the largest producing geothermal field in the

world. 20 plants are still operating at The Geysers. Wastewater from nearby cities is injected

into the field, providing environmentally safe disposal and increased steam to power

plants.[12]

Once the steam reaches the powerhouse, a dry steam plant is essentially the same as a

single-flash steam plant. The turbines are single-pressure units with impulse-reaction blading,

either single-flow for smaller units or double-flow for larger units (say, 60 MW or greater).

The condensers can be either directcontact (barometric or low-level) or surface-type (shell-

and-tube). For small units, it is often advantageous to arrange the turbine and condenser side-

byside, rather than the more usual condenser-below-turbine arrangement seen in most power

plants.

With the exception of the particulate remover (PR) in place of the cyclone separator

(CS), the flow diagram shown in Fig. 3.11. [13]

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Figure 3.11 Simplified Flow Diagram for a Dry Steam Power Plant (Ref:13) [PW: Production Wells, WV: Wellhead Valves, PR: Particulate Remover, SP: Steam Piping, MR: Moisture Remover, CSV: Control and Stop Valves, SE/C: Steam Ejector/Condenser, T/G: Turbine/Generator, C: Condenser,

CP: Condensate Pump, CT: Cooling Tower, CWP: Cooling Water Pump, IW: Injection Wells] (Ref:14)

2.3.3.2 Flash Steam Power Plants

1) Single Flash Power Plants

In a single flash steam technology, hydrothermal resource is in a liquid form. The fluid

is sprayed into a flash tank, which is held at a much lower pressure than the fluid, causing it to

vapourize (or flash) rapidly to steam. The steam is then passed through a turbine coupled to a

generator in dry steam plants. To prevent the geothermal fluid flashing inside the well, the

well is kept under high pressure. Flash steam plant generators range from 10 MW to 55 MW;

a standard size of 20 MW is used in several countries. [10]

Flash steam power plants use hot water reservoirs. In flash plants, as hot water is

released from the pressure of the deep reservoir in a flash tank, some if it flashes to steam.

Flash technology was invented in New Zealand. Flash steam plants are the most

common, since most reservoirs are hot water reservoirs. [12]

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We will assume that the geofluid starts off as a compressed liquid somewhere in the

reservoir, that it experiences a flashing process somewhere, that the twophases are separated,

Figure 3.12 Principle of Flash Steam Power Plant(Ref:12)

Figure 3.13 East Mesa, California(Ref:12)

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and that the steam is then used to drive a turbine which in turn drives the electric generator. A

simple schematic of this operation is given in Fig. 3.14, where the main components of a

single-flash plant are shown.[13]

Figure 3.14 Simplified Flow Diagram of a Single Flash Geothermal Power Plant(Ref:13) [S: Silencer, PW: Production Wells, WV: Wellhead Valves, CS: Cyclone Separator, BCV: Ball Check Valve, SP:

Steam Piping, MR: Moisture Remover, CSV: Control and Stop Valves, SE/C: Steam Ejector/Condenser, T/G: Turbine/Generator, C: Condenser, CP: Condensate Pump, CT: Cooling

Tower, CWP: Cooling Water Pump, IW: Injection Wells, WP: Water Piping] (Ref:14)

2) Double Flash Power Plants

About 20-25% more power can be generated from the same geofluid mass flow rate by

using Double-Flash technology. The secondary, low-pressure steam produced by throttling

the separated liquid to a lower pressure is sent either to a separate low-pressure turbine or to

an appropriate stage of the main turbine (i.e., a dual-pressure, dual-admission turbine). The

principles of operation of the Double-Flash plant are similar to those for Singl-Flash plant.

The Double-Flash plant is, however, more expensive owing to the extra equipment associated

with the flash vessel(s), the piping system for the low-pressure steam, additional control

valves, and the more elaborate or extra turbine. Figure 3.15 is a simplified flow diagram for a

Double-Flash plant.[14]

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Figure 3.15 Double-Flash Power Plant Diagram (Ref:13) [S: Silencer, PW: Production Wells, WV: Wellhead Valves, CS: Cyclone Separator, BCV: Ball Check Valve, TV: Throttle Valve, F: Flasher, SP:

Steam Piping, MR: Moisture Remover, CSV: Control and Stop Valves, SE/C: Steam Ejector/Condenser, T/G: Turbine/Generator, C: Condenser, CP: Condensate Pump, CT: Cooling

Tower, CWP: Cooling Water Pump, IW: Injection Wells, WP: Water Piping] (Ref:14)

2.3.3.3 Binary Cycle Power Plant

Figure 3.16 Principle of Binary Cycle Power Plant(Ref:12)

In a binary cycle power plant (binary means two), the heat from geothermal water is

used to vapourize a "working fluid" in separate adjacent pipes. The vapour, like steam,

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powers the turbine generator. In the heat exchanger, heat is transferred from the geothermal

water to a second liquid. The geothermal water is never exposed to the air and is injected back

into the periphery of the reservoir. Binary technology allows the use of lower temperature

reservoirs, thus increasing the number of reservoirs that can be used.[12]

Figure 3.17 Binary Power Plant Heat Exchanger(Ref:12)

Binary cycle geothermal power plants are the closest in thermodynamic principle to

conventional fossil or nuclear plants in that the working fluid undergoes an actual closed

cycle. The working fluid, chosen for its appropriate thermodynamic properties, receives heat

from the geofluid, evaporates, expands through a prime-mover, condenses, and is returned to

the evaporator by means of a feedpump.

The first geothermal binary power plant was put into operation at Paratunka near the

city of Petropavlovsk on Russia's Kamchatka peninsula in 1967. It was rated at 670 kW and

served a small village and some farms with both electricity and heat for use in greenhouses. It

ran successfully for many years, proving the concept of binary plants as we know them today.

At the birth of the commercial geothermal power age in 1912 at Larderello, Italy, a so-

called "indirect cycle" was adopted for a 250 kW plant. The geothermal steam from wells was

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too contaminated with dissolved gases and minerals to be sent directly to a steam turbine so it

was passed through a heat exchanger where it boiled clean water that then drove the turbine.

This allowed the use of standard materials for the turbine components and permitted the

minerals to be recovered from the steam condensate.

Today binary plants are the most widely used type of geothermal power plant with 155

units in operation in July 2004, generating 274 MW of power in 16 countries. They constitute

33% of all geothermal units in operation but generate only 3% of the total power. Thus, the

average power rating per unit is small, only 1.8 MW/unit, but units with ratings of 7-10 MW

are coming into use with advanced cycle design. Several binary units recently have been

added to existing flash-steam plants to recover more power from hot, waste brine.[13]

Figure 3.18 Schematic Diagram of Binary Power Plant(Ref:13) [P: Well Pump, PW: Production Wells, SR: Sand Remover, E: Evaporator, PH: Preheater, IP: Injection Pump, CSV: Control and Stop Valves, FF: Final Filter , T/G: Turbine/Generator, C: Condenser, CP: Condensate Pump, CT: Cooling Tower,

CWP: Cooling Water Pump, IW: Injection Wells, M: Make-up Water] (Ref:14)

The production wells PW are fitted with pumps P that are set below the flash depth

determined by the reservoir properties and the desired flow rate. Sand removers SR may be

needed to prevent scouring and erosion of the piping and heat exchanger tubes. Typically

there are two steps in the heatingboiling process, conducted in the preheater PH where the

working fluid is brought to its boiling point and in the evaporator E from which it emerges as

a saturated vapour. The geofluid is everywhere kept at a pressure above its flash point for the

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fluid temperature to prevent the breakout of steam and noncondensable gases that could lead

to calcite scaling in the piping.

Furthermore, the fluid temperature is not allowed to drop to the point where silica

scaling could become an issue in the preheater and in the piping and injection wells

downstream of it.[13]

2.3.3.4 Hybrid Power Plants

1) Hybrid Single-Flash and Double-Flash Systems

Let us begin by considering how two of the systems we have already studied can be

combined to form a hybrid-type of power plant. Given the relative simplicity and reliability of

single-flash plants, they are often the first type plant installed at a newly developed field.

However, their utilization efficiency is lower than that of a double-flash plant, and there

usually comes a time in the life of a field when expansion of the generating capacity becomes

possible. When this happens, say because step-out wells have been successful or the

electricity demand rises, it is logical to add another power unit. Since single-flash plants have

a significant amount of waste liquid from their separators that is still fairly hot, typically 150-

170°C the question arises as to whether this could be used to generate more power instead of

being directly reinjected. At several fields around the world, the answer has been "Yes", and

combined single- and double-flash plants have been built.[13]

a) Integration of These Systems

When the geofluid reservoir temperature is about 220-240°C and single-flash units

have been built and have been operating for some time, the addition of one more flash using

the separated brine allows for a lower pressure unit. The arrangement shown in Fig. 3.19

consists of two single-flash units, Units 1 and 2, and a third unit, Unit 3. Taken by itself, Unit

3 appears to be simply anothersingle-flash unit, but the power plant as a whole is an integrated

single- and double-flash facility since the original geofluid experiences two stages of flashing.

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The advantage to this arrangement is that no new wells need to be drilled to supply the third

unit. Unit 3 serves as a bottoming unit to recover some of the wasted potential from the still-

hot brine.[13]

Figure 3.19 Integrated Single and Double Flash Facility(Ref:13) [PW: Production Wells, WV: Wellhead Valves, CS: Cyclone Separator, BCV: Ball Check Valve, F: Flasher, SP: Steam Piping, CSV: Control

and Stop Valves, SE/C: Steam Ejector/Condenser, T/G: Turbine/Generator, C: Condenser, CP: Condensate Pump, IW: Injection Wells, WP: Water Piping, CW: Cooling Water]

b) Combined System

When the resource temperature is equal to or greater than say 240°C it may be

possible to augment the single-flash units with a true double-flash bottoming cycle, as seen in

the schematic flow diagram, Fig. 3.20.[13]

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Figure 3.20 Combined Single and Double Flash Plants(Ref:13) [PW: Production Wells, WV: Wellhead Valves, CS: Cyclone Separator, BCV: Ball Check Valve, HPF:High Pressure Flash Vessel, SP: Steam

Piping, OP: Orifice Plate, LPF: Low-Pressure Flash Vessel, SE/C: Steam Ejector/Condenser, T/G: Turbine/Generator, C: Condenser, CP: Condensate Pump, IW: Injection Wells, WP: Water Piping,

CW: Cooling Water]

2) Hybrid Flash-Binary Systems

An attractive alternative to the use of bottoming flash plants at existing single flash

plants is to add a binary cycle. Combined flash-binary plants are in operation at several plant

sites around the world. A different approach is to design a plant, from scratch, as an integrated

flash binary plant, thereby taking advantage of the best features of both units.

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a) Combined Plants

For this case, we assume that a single-flash plant has been running for some time,

usually a few years, and the reservoir has shown itself capable of sustaining operations for

many more years. The power output can be raised by adding a binary unit between the

separators and the reinjection wells. A simplified schematic of such an arrangement is given

in Fig. 3.21.

Figure 3.21 Combined Flash-Binary System (Ref:13) [PW: Production Wells, WV: Wellhead Valves, CS: Cyclone Separator, BCV: Ball Check Valve, WP: Water Piping, SP: Steam Piping, ST: Steam

Turbine, G: Generator, C: Condenser, CW: Cooling Water, CP: Condensate Pump, E: Evaporator, PH: Preheater, IP:Injection Pump, BT: Binary Turbine, IW: Injection Wells,f: Saturated Liquid, g: Saturated

Vapour]

Initially the single-flash plant operated by itself and the waste liquid from the cyclone

separators CS was sent directly to the injection wells IW. The binary cycle is inserted as

shown to tap into the reinjection pipeline where it extracts some heat and thereby lowers the

temperature of the waste brine prior to injection. The additional power generated by the

binary cycle is gained without any new production wells.[13]

b) Integrated Flash-Binary Plants

When a binary cycle is integrated with a flash plant, the result is a plant with

practically zero emissions. Where environmental concerns are significant, such plants have

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great appeal. An integrated single-flash/binary plant is shown schematically in Fig. 3.22. The

geothermal steam first drives the back-pressure steam turbine and then is condensed in the

upper binary cycle's evaporator E. The two turbines in the upper part of the plant may be

connected to a common generator, as shown.

Figure 3.22 Integrated Flash-Binary Plants(Ref:13)[PW: Production Wells, WV: Wellhead Valves, CS: Cyclone Separator, BCV: Ball Check Valve, WP: Water Piping, SP: Steam Piping, ST: Steam Turbine,

G: Generator, C: Condenser, CW: Cooling Water, CP: Condensate Pump, E: Evaporator, PH: Preheater, IP:Injection Pump, BT: Binary Turbine, IW: Injection Wells,f: Saturated Liquid, g: Saturated

Vapour, BHT: Brine Holding Tank, NCG: Noncondensable Gases, GC:Gas Compressor]

The separated brine (state 3) is used to preheat and evaporate the working fluid in the

lower binary cycle. The noncondensable gases flow with the steam through the steam turbine

ST and into the evaporator where they are isolated, removed and compressed for

recombination with the waste brine just before being reinjected. The brine holding tank BHT

collects all the steam condensate, waste brine and compressed gases that go back into

solution.[13]

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2.3.4 Benefits of Geothermal Energy

1. Geothermal energy is an abundant, secure, and, if properly utilized, a renewable source of

energy.

2. Modern geothermal plants emit less than 0.2% of the carbon dioxide of the cleanest fossil

fuel plant, less than 1% of the sulphur dioxide, and less than 0.1% of particulates, particularly

with respect to greenhouse gas emissions.

3. Geothermal energy is not associated with environmental impacts such as acid rain, mine

spoils, open pits, oil spills, radioactive waste disposal or the damming of rivers.

4. Geothermal power stations are very reliable compared to conventional power plants. They

have a high availability and capacity factor.

5. Geothermal energy has an inherent energy storage capability.

6. Geothermal power stations have a very small land area requirement.[10]

2.3.5 Potential Technology Development and Recent Trends

2.3.5.1 Potential Technology Development

Growth of conventional hydrothermal electricity is expected to be modest and

primarily in the western United States. The Western Governors Association assessed the

potential for new development by 2015 of about 140 known and accessible geothermal sites.

The WGA concluded that the western states share an untapped capacity of 5.6 GW that could

be developed within the next 10 years, with levelized costs of energy (LCOE) of about 5.3 to

7.9 cents per kWh, assuming that federal production tax credits (PTC) remain in place

(without the PTC, LCOE values would be 2.3 cents per kWh higher).

The Geothermal Energy Association has identified more than 100 geothermal projects

under development in 13 states, which represents more than a doubling of conventional

geothermal capacity in the coming decade. No additional technological developments are

required to tap these resources, although advances in exploration and resource assessment

could affect growth of new plants. The studies cited previously do not include EGS. Extensive

development of EGS is less certain, because of the lack of experience in recovering the heat

stored at 3- to 10- km depths in low-permeability rock. The primary technical challenges are

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accurate resource assessment and understanding how to achieve sufficient connectivity within

the fractured rock so that the injection and production well system can yield commercially

feasible and sustainable production rates. Other unresolved issues involve induced seismicity,

land subsidence, and water requirements. Modeling analysis shows a large capability for these

wells to yield significant heat. However, given the depths needed, there has been limited

experience and success in developing EGS wells at sufficient flow rates in the field. Issues

associated with EGSs, including reservoir operation and management, are summarized in the

MIT report (Massachusetts Institute of Technology) and in a series of reports summarizing

workshops sponsored by the DOE.[5]

2.3.5.2 Recent Trends

1) Enhanced Geothermal Systems

Starting as early as 1970, experimentswere conducted in HotDry Rock (HDR) in the

USA, UK, France, Australia, Germany, Switzerland and Japan. The HDR concept has been to

extract heat from rocks that are not naturally fractured and where permeability is generally

low. Ongoing efforts are generally focused onmining heat from rocks by introducing water

into the hot rocks, letting it heat, and then producing hot water or steam in doublet well

configurations (Fig. 3.23). Early on, HDR was not economically successful, but technological

advances in recent years have pushed the concept toward commerciality. When this

technology becomes commercial, the resource base of geothermal energy will increase

dramatically worldwide (e.g. MIT, 2006). Variations of HDR that are being examined include

hot wet rock (HWR) and enhanced geothermal systems (EGS). The thrust of these latter

efforts also involves heat extraction from lower permeability geothermal systems. A new

concept recently proposed utilizes CO2 instead of water as the working fluid in EGS.

The principal technology issues that are being addressed for HDR, HWR and EGS

include decreasing drilling costs, controlling water losses, and improved fracture stimulation

and mapping methods. Additionally, two other types of geothermal resource exploitation that

have been investigated include the development of ―geopressurized‖ reservoirs, where

methane-rich fluids are coproduced with hot water or steam. ―Geopressurized‖ reservoirs

have yet to be commercially developed, but the US government supported production

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engineering studies in the Gulf Coast Region to simultaneously generate electricity from the

geothermal fluids and to produce natural gas. ―Magma‖ resources have also seen some

research and development in an effort to extract heat directly fromcooling magma on active

volcanoes.[11]

Figure 3.23 Simplified representation of an EGS systemwherewater is circulated through hot dry rock and heat is mined in a closed loop(Ref:11)

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2.3.6 Future Expectations

2.3.6.1 Short Term: Present to 2020

In the near term, development of geothermal sites will continue to rely on

conventional extraction methods and technologies. Technology is not a major barrier to

developing conventional hydrothermal resources, but improvements in drilling and power

conversion technologies could result in cost reductions and greater reliability. There is a need

for continued and updated resource assessment. There will also be additional EGS field

demonstrations.[5]

2.3.6.2 Medium Term: 2020 to 2035

Category of Resource Thermal Energy, in

Exajoules (1 EJ=1018

J)

Reference

Conduction Dominated

EGS

-Sedimentary Rock

Formations

>100,000 MIT (2006)

-Crystalline Basement

Rock Formations

13,900,000 MIT (2006)

-Supercritical Volcanic

EGS

74,100 USGS Circular 790

Hydrothermal 2,400-9,600 USGS Circulars 726 and 790

Coproduced Fluids 0,0944-0,4510 McKenna et al (2005)

Geopressured Systems 71,000-170,000 USGS Circulars 726 and 790

Table 3.2 Estimates of U.S. Geothermal Resource Base to 10-km Depth by Category(Ref:5))

As indicated in Table 3-2, the largest source of geothermal energy resides in the

thermal energy stored in rock formations that require EGS technology for extraction.

Implementation of EGS has not been demonstrated at large scale, and there are unanswered

questions about the extent of economical power available. Reaching depths of 3 to 5 km is

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feasible for conventional drilling methods used in the oil and natural gas industry. However, a

significant uncertainty is the flow rate achievable in an enhanced reservoir and the heat flux

associated with this flow rate. Drilling for geothermal resources is somewhat different from

drilling for oil and natural gas, especially since geothermal systems typically occur in

crystalline rocks as opposed to much softer sedimentary rocks targeted by oil and natural gas

exploration. With present EIA projections of the price of electricity, successful

implementation of EGS would require sustained production at 80 kg/s (equivalent to the rate

at a productive hydrothermal reservoir) at a temperature of 250oC, which would generate

about 5 MW per well. The EGS project at Soultz, France (5,000-m-deep wells through

crystalline rock), which is the best-performing project to date, has achieved a well

productivity of about 25 kg/s. Advances in stimulation and higher productivity are likely as

more field demonstrations are conducted. The temperatures of 250oC exist primarily at depths

of 5.5 km and deeper. On the other hand, the MIT study cited very high grade EGS on the

margins of hydrothermal systems or in high-thermal-gradient regions that could work well at

depths of 3 km. Clear Lake, California, and the Fenton Hill, New Mexico, sites are good

examples of these.

Field demonstrations at different high-grade thermal areas would aid a realistic

assessment of the risks and potential of EGS. For cost-effective commercial extraction, the

studies should demonstrate, that EGS technology that is successful at one site can be applied

successfully to other sites with different geologic characteristics. The challenges are the

technical and economic uncertainty of site-specific reservoir properties, such as fractured rock

permeabilities, porosities, and in situ stresses, and the difficulties of stimulating sufficiently

large productive reservoirs, and connecting them to a set of injection and production wells.[5]

2.3.6.3 Long Term: After 2035

Initial field studies of EGS will most likely focus on moderate depths (up to ~5.0 km).

If successful, exploration at greater depth may be warranted and bring improved prospects for

private investment and commercial deployment.[5]

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2.4 Ocean Energy and Electric Generation

2.4.1 Introduction

Oceans, covering more than 70 00 of the earth, have long been appreciated as a vast

renewable energy source. The energy is stored in oceans partly as thermal energy, partly as

kinetic energy (waves and currents) and also in chemical and biological products. Numerous

techniques for extracting energy from the sea have been suggested, most of which can be

included in one of the following categories: wave energy, marine and tidal current energy,

ocean thermal energy.[15]

2.4.2 Tidal Energy


Tidal energy has the potential to play a valuable part in a sustainable energy future. It

is an extremely predictable energy source, depending only on the gravitational pull of the

moon and the sun and the centrifugal forces created by the rotation of the earthmoon system.

Tidal energy has been exploited on a significant scale since the construction of the La Rance

tidal barrage in France in 1967. A tidal barrage utilises the potential energy of the tide and has

proven to be very successful, despite opposition from environmental groups. Kinetic energy

can also be harnessed from tidal currents to generate electricity and involves the use of a tidal

current turbine. This is the more desired method of capturing the energy in the tides.

However, tidal current turbine technology is currently not economically viable on a large

scale, as it is still in an early stage of development.

Tidal energy offers a vast and reliable energy source. Currently, the harnessing of tidal

energy from the rise and fall of the tides has been exploited on a commercial scale using tidal

barrage systems. Recent efforts to exploit this predictable energy source have been directed

towards the kinetic energy in tidal currents. This method of energy extraction is

approximately fifteen years behind the wind technology industry. However, having started its

development later, tidal current energy technology can benefit from the advances in

engineering and science resulting from the development of wind energy technology. [16]

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2.4.2.2 Basic Physics

Tidal energy is the energy dissipated by tidal movements, which derives directly from

the gravitational and centrifugal forces between the earth, moon and sun. A tide is the regular

rise and fall of the surface of the ocean due to the gravitational force of the sun and moon on

the earth and the centrifugal force produced by the rotation of the earth and moon about each

other. The gravitational force of the moon, due to it being closer to the earth, is 2.2 times

larger than the gravitational force of the sun.

The tidal phenomenon occurs twice every 24 hours, 50 minutes and 28 seconds. A

bulge of water is created by the gravitational pull of the moon, which is greater on the side of

the earth nearest the moon. In parallel the rotation of the earth-moon system, producing a

centrifugal force, causes another water bulge on the side of the earth furthest away from the

moon illustrated in Figure 4.1. When a landmass lines up with this earth-moon system, the

water around the landmass is at high tide. In contrast, when the landmass is at 90° to the

earth-moon system, the water around it is at low tide. Therefore, each landmass is exposed to

two high tides and two low tides during each period of rotation of the earth. Since the moon

rotates around the earth, the timing of these tides at any point on the earth will vary, occurring

approximately 50 minutes later each day. The moon orbits the earth every 29.5 days, known

as the lunar cycle. Tides vary in size between spring tides and neap tides. Spring tides occur

when the sun and moon line up with the earth, whether pulling on the same side of the earth

or on opposite sides, resulting in very high spring tides. Neap tides occur when the sun and

moon are at 90° to each other, resulting in low neap tides. Tidal currents are experienced in

coastal areas and in places where the seabed forces the water to flow through narrow

channels. These currents flow in two directions; the current moving in the direction of the

coast is known as the flood current and the current receding from the coast is known as the

ebb current. The current speed in both directions varies from zero to a maximum. The zero

current speed refers to the slack period, which occurs between the flood and ebb currents. The

maximum current speed occurs halfway between the slack periods.

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Figure 4.1 The Effect of the Moon on Tidal Range(Ref:16)

These tidal variations, both the rise and fall of the tide and the flood and ebb currents,

can be utilized to generate electricity.[16]

2.4.2.3 Tidal Energy Status

Tidal energy consists of potential and kinetic components. Tidal power facilities can

be categorised into two main types: tidal barrages and tidal current turbines, which use the

potential and kinetic energy of the tides respectively.

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1) Tidal Barrages

1.1) Principles of Operation

Tidal barrages make use of the potential energy of the tides. A tidal barrage is

typically a dam, built across a bay or estuary that experiences a tidal range in excess of 5 m.

Electricity generation from tidal barrages employs the same principles as hydroelectric

generation, except that tidal currents flow in both directions. A typical tidal barrage consists

of turbines, sluice gates, embankments and ship locks. The turbines that are used in tidal

barrages are either uni-directional or bi-directional, and include bulb turbines, straflo or rim

turbines and tubular turbines. Tidal barrages can be broken into two types: single-basin

systems and double-basin systems.

1.2) Single-Basin Tidal Barrages

Single-basin systems consist of one basin and require a barrage across a bay or

estuary. There are three methods of operation for generating electricity within a single basin:

a) Ebb Generation

The basin is filled with water through the sluice gates during the flood tide. At high

tide, the sluice gates are closed, trapping the water in the basin. At this point extra water can

be pumped into the basin at periods of low demand, typically at night when electricity is

cheap. The turbine gates are kept closed until the tide has ebbed sufficiently to develop a

substantial hydrostatic head across the barrage. The water is let flow out through low-head

turbines, generating electricity for several hours until the hydrostatic head has dropped to the

minimum level at which the turbines can operate efficiently.[16]

b) Flood Generation

During the flood tide the sluice gates and turbines are kept closed until a substantial

hydrostatic head has developed across the barrage. Once the sufficient hydrostatic head is

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achieved, the turbine gates are opened allowing the water to flow through them into the basin.

Flood generation is a less favourable method of generating electricity due to effects on

shipping and the environment. These effects on shipping and the environment are caused by

the average decrease in sea level within the basin.[16]

c) Two-Way Generation

This method of operation utilises both flood and ebb phases of the tide to generate

electricity. The sluice gates and turbines are kept closed until near the end of the flood cycle.

After this point the water is allowed to flow through the turbines, generating electricity. When

the minimum hydrostatic head for generating electricity is reached the sluice gates are then

opened. At high tide, the sluice gates are closed and the water is trapped behind the barrage

until a sufficient hydrostatic head is reached once again. Water is then allowed to flow

through the turbines to generate in the ebb mode. Two-way generation has the advantage of a

reduced period of non-generation and a reduction in the cost of generators due to lower peak

power.[16]

1.3) Double-Basin Tidal Barrages

Double-basin systems consist of two basins. The main basin is basically the same as

that of an ebb generation single-basin system. The difference between a doublebasin system

and a single-basin system is that a proportion of the electricity generated during the ebb phase

is used to pump water into the second basin, allowing an element of storage; therefore this

system can adjust the delivery of electricity to match consumer demands.

The major advantage double-basin systems have over single-basin systems is the

ability to deliver electricity at periods of high electricity demand. However, doublebasin

systems are unlikely to become feasible due to the inefficiencies of low-head turbines. High

construction costs of double-basin systems due to the extra length of the barrage may also

restrict the development of this system.[16]

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1.4) La Rance, France

The largest operating tidal barrage power plant is the La Rance power facility in

France, with a generating capacity of 240 MW. The La Rance power facility was constructed

between 1961 and 1967, and is situated on the river Rance in Brittany. The barrage is 720

metres long which encloses a surface area of 22 km2 of the estuary. The barrage contains 24

reversible 10 MW bulb turbines operating with a typical hydrostatic head of 5 m. The mode of

operation of the La Rance tidal power facility uses a combination of two-way generation and

pumped storage. Pumping from the sea to the basin is carried out at certain tides to enhance

generation on the ebb. The facility produces a net power output of approximately 480 GWh

per year.[16]

2) Tidal Current Turbines

2.1) Principle of Operation

Tidal current turbines extract the kinetic energy in moving water to generate

electricity. Tidal current technology is similar to wind energy technology. However there are

several differences in the operating conditions. Under similar conditions water is 832 times

more dense than air and the water flow speed generally is much smaller. Since tidal current

turbines operate in water, they experience greater forces and moments than wind turbines.

Tidal current turbines must be able to generate during both flood and ebb tides and be able to

withstand the structural loads when not generating electricity.[16]

a) Kinetic Energy Extraction

The total kinetic power in a marine current turbine has a similar dependence as a wind

turbine and is governed by the following equation:

(4.1)

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where is the fluid density, A is the cross-sectional area of the turbine and V is the fluid

velocity.

However, a marine energy converter or turbine can only harness a fraction of this

power due to losses and the equation (4.1) is modified as follows:

(4.2)

Cp is known as the power coefficient and is essentially the percentage of power that can be

extracted from the fluid stream and takes into account losses due to Betz law and those

assigned to the internal mechanisms within the converter or turbine. For wind generators, Cp

has typical values in the range of 0.25-0.3. The upper limit for highly efficient machines with

low mechanical losses. For marine turbines, Cp is estimated to be in the range of 0.35-0.5.

Compared to the largest wind turbines operating today, the power output as well as the

size of a classical tidal turbine are extremely promising. For illustration, Figure 4.2 shows a

tidal turbine against an offshore wind turbine of the same power rating. Furthermore, with

constant or highly predictable marine currents a tidal turbine could not only rival the largest

wind turbines in being more manageable in size but also in generating highly predictable

power. [15]

Figure 4.2 Tidal Turbine against an Offshore Wind Turbine (Ref:15)

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2.2) Turbine Technologies and Concepts

The following two methods of tidal current energy extraction are the most common:

Horizontal axis tidal current turbines: The turbine blades rotate about a horizontal axis

which is parallel to the direction of the flow of water.

Vertical axis tidal current turbines: The turbine blades rotate about a vertical axis

which is perpendicular to the direction of the flow of water.

In its simplest form a tidal current turbine consists of a number of blades mounted on a

hub (together known as the rotor), a gearbox, and a generator. The hydrodynamic effect of the

flowing water past the blades causes the rotor to rotate, thus turning the generator to which the

rotor is connected via a gearbox. The gearbox is used to convert the rotational speed of the

rotor shaft to the desired output speed of the generator shaft. The electricity generated is

transmitted to land through cables.

These three parts are mounted to a support structure that is required to withstand the

harsh environmental loadings. There are three main support structure options when

considering installing a tidal current turbine. The first of these is known as a gravity structure

which consists of a large mass of concrete and steel attached to the base of the structure to

achieve stability. The second option is known as a piled structure which is pinned to the

seafloor using one or more steel or concrete beams. The third option is known as a floating

structure. The floating structure is usually moored to the seafloor using chains or wire. The

turbine in this case is fixed to a downward pointing vertical beam, which is fixed to the

floating structure.

Figure 4.3 Tidal Turbine Fundamental Types(Ref:15)

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a) DeltaStream Turbine

The DeltaStream Turbine device was developed by a company called Tidal Energy

Ltd based in the UK. The 1.2 MW device consists of three, three-bladed, horizontal axis tidal

turbines each with a diameter of 15 m, mounted on a triangular frame, producing a low centre

of gravity for structural stability. [16]

Figure 4.4 Delta Stream Turbine[Ref:17]

b) Evopod Tidal Turbine

The Evopod Tidal Turbine (Figure 5) was developed by a company called Ocean Flow

Energy Ltd based in the UK. The device is a five-bladed, horizontal axis, floating structure

which is moored to the seafloor. The mooring system allows the device to maintain optimum

heading into the tidal stream. A 1/10th

scale model is currently being tested in Strangford

Lough in Northern Ireland.[16]

197

Figure 4.5 Evopod Tidal Turbine (Ref: 18)

c) Free Flow Turbines

The Free Flow Turbine was developed by Verdant Power Ltd based in the USA and

Canada. This three-bladed horizontal axis turbine has a diameter of 4.68 m and a prototype is

being tested in New York City‘s East River, generating 1 MWh of electricity per day. Late in

2008 Verdant Power Ltd were awarded a $1.15 million contract from Sustainable

Development Technology Canada to develop phase one of the Cornwall Ontario River Energy

Project.[16]

Figure 4.6 Free Flow Turbine (Ref:19)

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d) Gorlov Helical Turbine

The Gorlov Helical Turbine is a vertical axis tidal current turbine based on the

Darrieus Windmill concept and was developed by a company called GCK Technology Inc

based in the USA. The Gorlov Helical Turbine utilizes three twisted blades in the shape of a

helix, and has proven to be efficient and reduces vibration. A scale model of diameter 1 m

was built and commenced testing on the 10th July 2002.[16]

Figure 4.7 Gorlov Helical Turbine(Ref:16)

e) Lunar Energy Tidal Turbine

The Lunar Energy Tidal Turbine is a horizontal axis tidal current turbine and was

developed by Lunar Energy Ltd based in the UK. The structure consists of a gravity base, a 1

MW bi-directional turbine 11.5 m in diameter, a duct of length 19.2 m and diameter 15 m, and

a hydraulic motor and generator. This tidal turbine is at the development stage, and to-date

nothing has been built. The ducting is included to maximise the energy extraction from the

current water flow. Lunar Energy Ltd has recently agreed a £500 million deal to install 300

tidal current turbines off the coast of Korea.[16]

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Figure 4.8 Lunar Energy Tidal Turbine(Ref:16)

f) Neptune Tidal Stream Device

The Neptune Tidal Stream Device was developed by a company called Aquamarine

Power Ltd based in the UK. The device is said to have a generating capacity of 2.4 MW. It

consists of twin, three-bladed, horizontal axis turbines mounted on a monopole structure. The

device can generate electricity in both the ebb and flood tides. Aquamarine Power Ltd has set

plans to test their device within the next three years at the EMEC. On the 12th January 2009 it

was announced that ABB Ltd, an automation group, will commission the electrical system of

the device.

Figure 4.9 Neptune Tidal Stream Device(Ref:16)

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g) Nereus and Solon Tidal Turbines

The Nereus and Solon Tidal Turbines were developed by Atlantis Resource

Corporation Ltd based in Singapore. The Nereus Tidal Turbine is a shallow water, horizontal

axis turbine and has been grid connected in Australia. The 400 kW rated device was

successfully tested in July 2008. The turbine is robust and has the ability to withstand flow

with large amounts of debris. The Solon Tidal Turbine is a deep water, ducted, horizontal-axis

turbine, developed in 2006. The 500 kW turbine was successfully tested in August 2008.

Figure 4.10 Nereus Tidal Turbine(Ref:20)

Figure 4.11 Solon Tidal Turbine(Ref:20)

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h) Open Centre Turbine

Open-Hydro Ltd based in Ireland has developed the Open Centre Turbine. The

technology consists of a slow moving rotor 6 m in diameter, a stator, a duct and a generator.

Recently, Open-Hydro Ltd became the first tidal current energy company to connect to the

UK national grid and commence electricity generation. The 250 kW Open Centre Turbine

was installed at the EMEC. The company has invested €5 million in the design and

construction of a specialist barge to install their tidal turbine. On October 21st 2008 Open-

Hydro Ltd were chosen by the electricity suppliers in France (EDF) to develop a

demonstration farm there.[16]

Figure 4.12 Open Centre Turbine(Ref:16)

i) Pulse Tidal Hydrofoil

Pulse Tidal Hydrofoil was developed by a company called Pulse Generation Ltd based

in the UK. This design has the ability of operating efficiently in shallow water. In April 2008

permission was granted to deploy a prototype in the Humber estuary in Northern England.

Currently this device is at the design stage of development, and to-date nothing has been

built.[16]

202

Figure 4.13 Pulse Tidal Hydrofoil(Ref:16)

j) SeaGen

SeaGen is a 1.2 MW tidal current turbine, developed by Marine Current Turbines Ltd

based in the UK, after the successful installation of the 300 kW device called Seaflow off the

coast of Devon in the UK in 1993. A trial model of SeaGen was installed and grid connected

in May 2008 in Strangford Lough, Northern Ireland. The technology consists of a pair of two-

bladed horizontal axis rotors, 16 m in diameter. The rotor is connected to a gearbox which

increases the rotational speed of the shaft to drive a generator. The rotor blades are pitch

controlled to allow for operation in both ebb and flood tides. The pitch control is also used as

a braking mechanism in order to facilitate maintenance requirements of the rotor. On the 18th

January 2009, this device successfully operated at full power (1.2 MW).[16]

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Figure 4.14 SeaGen(Ref:16)

k) Stingray Tidal Energy Converter

The Stingray Tidal Energy Generator is a tidal current energy converter developed by

Engineering Business Ltd based in the UK. The concept transforms kinetic energy from the

moving water into hydraulic power. It consists of a parallel linkage holding several large

hydroplanes. The 150 kW prototype was successfully deployed in September 2002, in Yell

Sound, off Shetland in the UK. However the device was removed several weeks later and

development has stalled.[16]

Figure 4.15 Stingray Tidal Energy Converter(Ref:16)

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l) Tidal Fence Davis Hydro Turbine

The Tidal Fence Davis Hydro Turbine was developed by Blue Energy Ltd based in

Canada. The tidal fence technology consists of an array of vertical axis tidal current turbines.

The Davis Hydro Turbine consists of four fixed hydrofoil blades, connected to a rotor that

drives a generator via a gearbox. This system offers the capability of tidal energy extraction

from any site, including river applications from 5 kW to 500 kW, and ocean applications from

200 MW to 8000 MW. No prototypes have been tested to date.[16]

Figure 4.16 Tidal Fence Davis Hydro Turbine (Ref:21)

m) TidEl Stream Generator

The TidEl Stream Generator concept was developed by SMD Hydrovision Ltd based

in the UK. The TidEl system consists of two contra-rotating 500 kW rotors of 15 m diameter.

The company have successfully tested a 1/10th

scale model of the device. The complete

assembly is buoyant and is tethered to the seafloor with the use of mooring chains. The

mooring system allows the turbines to align to the tidal current flow direction quite easily.[16]

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Figure 4.17 TidEl Stream Generator(Ref:22)

n) Tidal Stream Turbine

The Tidal Stream Turbine is a 300 kW three-bladed horizontal axis tidal current

turbine developed by Hammerfest Strom AS, a Norwegian company. The turbine was

installed in September 2003 in the Kvalsundet, which is situated on the north coast of Norway

and it was the world‘s first grid connected tidal current turbine when it became operational in

November 2003. The company has started developing a new 1 MW device, called HS1000.

Scottish Power has an agreement with Hammerfest Strom AS to build and install a full-scale

model in Scottish waters.[16]

Figure 4.18 Tidal Stream Turbine (Ref:23)

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2.4.2.4 Current Issues on Tidal Energy

1) Tidal Barrage Systems

The current issues restricting the development of tidal barrage systems are the high

construction costs and the environmental impact, with no major technical issues requiring

resolution.

The construction of a tidal barrage requires a vast quantity of materials to withstand

the huge loads produced from dammed water. The resulting high construction costs are

considered one of the greatest issues when deciding whether or not a site is economically

viable for tidal energy extraction. Due to the developments in turbine design, routine repair

can now be conducted at greater ease; therefore maintenance is no longer considered a

development issue.

The decision to utilise tidal energy technologies must be made with the awareness that

imminent changes will be made to the surrounding environment. The greatest disadvantage of

tidal barrages is the environmental impacts. Building a dam across an estuary or bay may

change the flow of the tidal currents, affecting the marine life within the estuary. The impact

of a tidal barrage varies from site to site; however, there are very few projects available for

comparison. Water quality within the basin may also be affected, such as sediment

transportation, resulting in changes to water turbidity. The effect on fish and other marine

animals may also be detrimental, due to them passing through the turbines. The presence of a

barrage will also influence maritime traffic. This maritime traffic problem is easier solved for

an ebb generating system, where the basin is kept at a much higher water level than the water

level of a flood generation system. The changes in sediment transportation are not all negative

and, as a result, marine life may flourish at sites where they are not normally found.[16]


The current issues restricting the development of tidal current turbines are installation

challenges, maintenance, electricity transmission, loading conditions and environmental

impacts.

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The installation of tidal current turbines offers challenges some of which have been

addressed from other off-shore energy technologies. These devices must be designed for ease

and speed of installation. Construction of foundations and installation during tidal currents

will be challenging, with only a few minutes of slack time between tides. Some devices may

require mooring systems which are subject to biofouling and corrosion, affecting the

survivability of the system. Several methods have been identified to prevent biofouling and

corrosion, particularly around seals, welds, bearing surfaces and electrical insulation

materials. These methods include antifouling paints and the use of sonic and ultra-sonic

systems.

Easy access to the turbine is required for maintenance. The use of a ship will be

required for routine maintenance and repair of tidal current devices, making it hazardous and

difficult. At the design stage, it is crucial to set out measures to reduce the frequency and

difficulty of maintenance. There are several concepts proposed for ease of maintenance, most

of which include the rising of the turbine above the water level to allow for maintenance from

a platform or ship. Replacement of large parts will be a difficult operation requiring calm

waters and good weather.

Electricity transmission is another issue and in some cases transmission to shore over

longer distances may be required. If so the use of higher voltage transmission will be required.

Generators should be developed to operate at higher voltages, preventing the need to install

transformers at, or below, the sea surface. Tidal current energy resource is often in energy

dense areas, where grid access is limited. Upgrading the grid network may be required so that

it doesn‘t restrict the amount of tidal generated electricity connected; this may be costly and

cause public discontent.

In comparison to wind turbines, tidal current turbines generate a much larger thrust

due to the density of seawater. Resisting these large thrusts will involve the use of greater

amounts of materials or stronger materials, which will result in greater capital costs. The

fluctuations in the velocity of the flow around a tidal current turbine rotor can lead to several

severe problems, such as blade vibrations, which may lead to fatigue failure. When designing

a tidal current turbine turbulence levels must be taken into account to reduce its damaging

effects. The use of computer software to model the water flow and prototype testing will play

an important part in blade design.

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The environmental impacts of tidal current devices are believed to be minimal in

comparison to tidal barrages. The energetic conditions at which tidal turbines will be located

are areas where marine species are not commonly found. Capturing the kinetic energy of the

tidal flow has been identified as possibly the greatest environmental impact. This impact is

also site specific and without appropriate assessments it is unknown how great an impact tidal

current turbine may have on the surrounding environment.[16]

2.4.2.5 Future Developments

1) Tidal Barrage Systems

Tidal barrage technology is mature, reliable and has excellent potential. However, the

high capital cost associated with the construction of a tidal barrage system is the biggest

barrier restricting its development. The future development of tidal barrage systems depends

specifically on an increase in the cost of electricity generated from conventional sources and

on no alternative method of electricity generation materialising in the mean time. The major

advantage this technology has over other renewable energy technologies is the fact that it is

already available and reliable.[16]


The extraction of tidal energy using tidal current turbines is becoming an increasingly

favourable method of electricity generation. Several companies have installed demonstration

devices, both full-scale and down-scaled. If testing continues to be successful full-scale tidal

farms are expected to materialise within the next decade. However, it should be noted that

only a few of the devices discussed above have been built and successfully tested in harsh

tidal currents. The Delta Stream Turbine, Lunar Energy Tidal Turbine, Neptune Tidal Stream

Device, Pulse Tidal Hydrofoil and Tidal Fence Davis Hydro Turbine are all at the design

stage, and todate nothing has been built. Several scale-models have been built and tested

including the Nereus and Solon Tidal Turbines, Evopod Tidal Turbine, Gorlov Helical

Turbine, TidEl Stream Generator and Stingray Tidal Energy Converter. The Stingray Tidal

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Energy Converter was installed and removed and is no longer under development. The

SeaGen and Seaflow, Open Centre Turbine, Tidal Stream Turbine and Free Flow Turbines are

the only full scale operational tidal current turbines, which are generating electricity. All of

these demonstration devices operate with a horizontal axis of rotation, which suggests that

this may be the optimum configuration for tidal current turbines. At the rate at which tidal

current turbine technology is developing, it is expected that other high potential tidal current

sites will become available which were previously uneconomical for energy extraction.[16]

2.4.3 Wave Energy


The energy from ocean waves is the most conspicuous form of ocean energy, possibly

because of the, often spectacular, wave destructive effects. The waves are produced by wind

action and are therefore an indirect form of solar energy.[24]

Extracting energy from ocean waves is already almost commercially viable. Since the

oil crises of the early 1970s many possible schemes have been developed and tested. The

early tests were usually carried out at model scales in tanks or outdoor lakes and fiords, but in

recent years schemes have been developed as full-scale prototypes.

Several prototype wave energy converters were commissioned around the world. The

most significant in size being the two demonstration systems built in Norway, a 600kW

Oscillating Water Column and a 350kW Tapchan. Neither of these is operating today but they

successively demonstrated the principles and subsequent developments have benefited from

the experience gained. [25]

In the last few years, growing interest in wave energy is taking place in northern

America (USA and Canada), involving the national and regional administrations, research

institutions and companies, and giving rise to frequent meetings and conferences on ocean

energy.[24]

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2.4.3.2 Wave Resources

The total exploitable World wave power resource is estimated at 2 - 5 TW, largely to

be found in offshore locations where the water is deeper than 40m, and the power density can

be 50 to 70 kW per metre of wave crest. Since the energy content of waves is partially

dissipated as they run through shallow water on their approach the shore the shoreline

resource has lower power density (around 20 kW/m). These power densities are substantially

greater then that of solar or wind resources and clearly makes wave energy an attractive

possibility.

Wind passing over the surface of water gradually passes some of its energy into the

water to create waves. If the wind has a reasonable strength and persists for a long time across

a long stretch of water then the resulting waves will be large and powerful.

Waves in the North Atlantic, generated by persistent south westerly winds, for

example might be 3 to 4 m high with wavelengths of 150 to 200m. These waves are amongst

the largest in the World making the West coast of Europe a particularly good location for

wave farms. As they approach the coast these typical waves will be powerful. Capturing the

energy from such waves requires floating devices large enough to span waves, which means

that they will have to have dimensions of tens or hundreds of metres, and to be capable of

responding to have periods of the order of 8 to 10 seconds.

Devices to capture the wave energy from shallow water can be fixed to the shore-line:

an easier task but less rewarding in energy production.[25]

2.4.3.3 The Various Technologies

Unlike large wind turbines, there is a wide variety of wave energy technologies,

resulting from the different ways in which energy can be absorbed from the waves, and also

depending on the water depth and on the location (shoreline, near-shore, offshore).

Recent reviews identified about one hundred projects at various stages of

development. The number does not seem to be decreasing: new concepts and technologies

replace or outnumber those that are being abandoned.

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Several methods have been proposed to classify wave energy systems, according to

location, to working principle and to size (‗‗point absorbers‘‘ versus ‗‗large‘‘ absorbers). The

classification in Fig. 4.19 is based mostly on working principle.[24]

Figure 4.19 The Various Wave Energy Technologies(Ref:24)

1) The Oscillating Water Column (OWC)

a. Fixed-structure OWC

Based on various energy-extracting methods, a wide variety of systems has been

proposed but only a few full-sized prototypes have been built and deployed in open coastal

waters. Most of these are or were located on the shoreline or near shore, and are sometimes

named first generation devices. In general these devices stand on the sea bottom or are fixed

to a rocky cliff. Shoreline devices have the advantage of easier installation and maintenance,

and do not require deep-water moorings and long underwater electrical cables. The less

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energetic wave climate at the shoreline can be partly compensated by natural wave energy

concentration due to refraction and/or diffraction (if the device is suitably located for that

purpose). The typical first generation device is the oscillating water column. Another example

is the overtopping device Tapchan (Tapered Channel Wave Power Device), a prototype of

which was built on the Norwegian coast in 1985 and operated for several years.

The oscillating water column (OWC) device comprises a partly submerged concrete or

steel structure, open below the water surface, inside which air is trapped above the water free

surface (Fig. 4.20). The oscillating motion of the internal free surface produced by the

incident waves makes the air to flow through a turbine that drives an electrical generator. The

axial-flow Wells turbine, invented in the mid 1970s, has the advantage of not requiring

rectifying valves. It has been used in most prototypes.

Figure 4.20 Cross-sectional View of a Bottom-standing OWC (Pico Plant) (Ref:24)

Full sized OWC prototypes were built in Norway (in Toftestallen, near Bergen, 1985),

Japan (Sakata, 1990), India (Vizhinjam, near Trivandrum, Kerala state, 1990), Portugal (Pico,

Azores, 1999), UK (the LIMPET plant in Islay island, Scotland, 2000). The largest of all, a

nearshore bottomstanding plant (named OSPREY) was destroyed by the sea (in 1995) shortly

after having been towed and sunk into place near the Scottish coast. In all these cases, the

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structure is fixed (bottomstanding or built on rocky sloping wall) and the main piece of

equipment is the Wells air turbine driving an electrical generator. Except for the OSPREY,

the structure was made of concrete. The cross-sectional area of these OWCs (at mid water-

free-surface level) lies in the range 80–250 m2. Their installed power capacity is (or was) in

the range 60–500 kW (2 MW for OSPREY). Smaller shoreline OWC prototypes (also

equipped with Wells turbine) were built in Islay, UK (1991), and more recently in China.

It has been found theoretically and experimentally since the early 1980s that the wave

energy absorption process can be enhanced by extending the chamber structure by protruding

(natural or man-made) walls in the direction of the waves, forming a harbour or a collector.

This concept has been put into practice in most OWC prototypes. The Australian company

Energetech developed a technology using a large parabolic-shaped collector (shaped like a

Tapchan collector) for this purpose (a nearshore prototype was tested at Port Kembla,

Australia, in 2005); the main novelty lies mostly in the large size of the converging wall

compared with the dimensions of the OWC itself.

The design and construction of the structure (apart from the air turbine) are the most

critical issues in OWC technology, and the most influential on the economics of energy

produced from the waves. In the present situation, the civil construction dominates the cost of

the OWC plant. The integration of the plant structure into a breakwater has several

advantages: the constructional costs are shared, and the access for construction, operation and

maintenance of the wave energy plant become much easier. This has been done successfully

for the first time in the harbour of Sakata, Japan, in 1990, where one of the caissons making

up the breakwater had a special shape to accommodate the OWC and the mechanical and

electrical equipment. The option of the ‗‗breakwater OWC‘‘ was adopted in the 0.75MW

twin-chamber OWC plant planned to be installed in the head of a breakwater in themouth of

the Douro river (northern Portugal) and in the recently constructed breakwater at the port of

Mutriku, in northern Spain, with 16 chambers and 16 Wells turbines rated 18.5 kW each. A

different geometry for an OWC embedded into a breakwater was proposed by Boccotti,

approaching a quasi-two-dimensional terminator configuration, with an OWC that is long in

the wave crest direction but narrow (small aperture) in the fore-aft direction. TheOWC cross-

section is J-shaped, with its outer opening facing upwards. A field experiment was carried out

off the eastern coast of the straits of Messina, in southern Italy.[24]

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b. Floating-structure OWC

The first OWC converters deployed in the sea were floating devices developed in

Japan in the 1960s and 1970s under the leadership of Yoshio Masuda: the wave-powered

navigation buoys and the large Kaimei barge. Masuda realized that the wave-to-pneumatic

energy conversion of Kaimei was quite unsatisfactory and conceived a different geometry for

a floating OWC: the Backward Bent Duct Buoy (BBDB). In the BBDB, the OWC duct is bent

backward from the incident wave direction (Fig. 4.21) (which was found to be advantageous

in comparison with the frontward facing duct version). In this way, the length of the water

column could be made sufficiently large for resonance to be achieved, while keeping the

draught of the floating structure within acceptable limits. The BBDB converter was studied

(including model testing) in several countries (Japan, China, Denmark, Korea, Ireland) and

was used to power about one thousand navigation buoys in Japan and China. In the last few

years, efforts have been underway in Ireland to develop a large BBDB converter for

deployment in the open ocean. A 1/4th-scale 12 m-long model equipped with a horizontalaxis

Wells turbine has been tested in the sheltered sea waters of Galway Bay (western Ireland)

since the end of 2006.

Figure 4.21 Schematic Representation of the Backward Bent Duct Buoy (BBDB) (Ref:24)

The Mighty Whale, another floating OWC converter, was developed by the Japan

Marine Science and Technology Center. After theoretical investigations and wave tank

215

testing, a full-sized prototype was designed and constructed. The device consists of a floating

structure (length 50 m, breadth 30 m, draught 12 m, displacement 4400 t) which has three air

chambers located at the front, side by side, and buoyancy tanks. Each air chamber is

connected to a Wells air turbine that drives an electric generator. The total rated power is 110

kW. The device was deployed near the mouth of Gokasho Bay, in Mie Prefecture, Japan, in

1998 and tested for several years.

The Spar Buoy is possibly the simplest concept for a floating OWC. It is an

axisymmetric device (and so insensitive to wave direction) consisting basically of a (relatively

long) submerged vertical tail tube open at both ends, fixed to a floater that moves essentially

in heave. The length of the tube determines the resonance frequency of the inner water

column. The air flow displaced by the motion of the OWC relative to the buoy drives an air

turbine. Several types of wave-powered navigation buoys have been based on this concept,

which has also been considered for larger scale energy production. The Sloped Buoy has

some similarities with the Spar Buoy and consists of a buoy with three sloped immersed tail

tubes such that the buoy-tube set is made to oscillate at an angle intermediate between the

heave and surge directions.

A report prepared for the British Department of Trade and Industry (DTI) compared

three types of floating OWCs for electricity generation in an Atlantic environment: BBDB,

Sloped Buoy and Spar Buoy.

The floating OWC devices briefly described above are slackmoored to the sea bed and

so are largely free to oscillate (which may enhance the wave energy absorption if the device is

properly designed for that). The Orecon, under development in UK, is a floating OWC device

that is tension moored to the sea bed. It is a multi-resonance converter with several vertical

OWCs of different lengths, each chamber being connected to an air turbine.[24]

2) Oscillating Body Systems

Offshore devices (sometimes classified as third generation devices) are basically

oscillating bodies, either floating or (more rarely) fully submerged. They exploit the more

powerful wave regimes available in deep water (typically more than 40 m water depth).

Offshore wave energy converters are in general more complex compared with first generation

systems. This, together with additional problems associated with mooring, access for

216

maintenance and the need of long underwater electrical cables, has hindered their

development, and only recently some systems have reached, or come close to, the full-scale

demonstration stage.

a. Single-body Heaving Buoys

The simplest oscillating-body device is the heaving buoy reacting against a fixed

frame of reference (the sea bottom or a bottom-fixed structure). In most cases, such systems

are conceived as point absorbers (i.e. their horizontal dimensions are much smaller than the

wavelength).

An early attempt was a device named G-1T, consisting of a wedge-shaped buoy of

rectangular planform (1.8 m x 1.2 m at water line level) whose vertical motion was guided by

a steel structure fixed to a breakwater. The used PTO was an early example of the hydraulic

ram in a circuit including a gas accumulator. The tests, performed in Tokyo Bay in 1980, are

reported in.

Another early example was the Norwegian buoy, consisting of a spherical floater

which could perform heaving oscillations relative to a strut connected to an anchor on the sea

bed through a universal joint. The buoy could be phase-controlled by latching and was

equipped with an air turbine. A model (buoy diameter = 1 m), in which the air turbine was

simulated by an orifice, was tested (including latching control) in the Trondheim Fjord in

1983 (Fig. 4.22).

Figure 4.22 Norwegian Heaving Buoy in Trondheim Fjord, 1983(Ref:24)

217

An alternative design is a buoy connected to a bottom-fixed structure by a cable which

is kept tight by a spring or similar device. The relative motion between the wave-activated

float on the sea surface and the seabed structure activates a PTO system. In the device that

was tested in Denmark in the 1990s, the PTO (housed in a bottom-fixed structure) consisted

in a piston pump supplying high-pressure water to a hydraulic turbine.

A version of the taut-moored buoy concept is being developed at Uppsala University,

Sweden, and uses a linear electrical generator (rather than a piston pump) placed on the ocean

floor. A line from the top of the generator is connected to a buoy located at the ocean surface,

acting as power takeoff. Springs attached to the translator of the generator store energy during

half a wave cycle and simultaneously act as a restoring force in the wave troughs (Fig. 4.23).

Sea tests off the western coast of Sweden of a 3 m diameter cylindrical buoy are reported in.

Figure 4.23 Swedish Heaving Buoy with Linear Electrical Generator(Ref:24)

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Another system with a heaving buoy driving a linear electrical generator was recently

developed at Oregon State University, USA. It consists of a deep-draught spar andanannular

saucer-shaped buoy (Fig. 4.24). The spar is taut-moored to the sea bed by a cable. The buoy is

free to heave relative to the spar, but is constrained in all other degrees of freedom by a linear

bearing system. The forces imposed on the spar by the relative velocity of the two bodies is

converted into electricity by a permanent magnet linear generator. The spar is designed to

provide sufficient buoyancy to resist the generator force in the downdirection.A10

kWprototype L-10 (buoy outer radius 3.5 m, spar length 6.7m) was deployed off Newport,

Oregon, in September 2008, and tested.

Figure 4.24 L-10 Wave Energy Converter with Linear Electrical Generator, Developed at Oregon

State University(Ref:24)

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b. Two-body Heaving Systems

The concept of a single floating body reacting against the sea floor may raise

difficulties due to the distance between the free surface and the bottom and/or to tidal

oscillations in sea level. Multi-body systems may be used instead, in which the energy is

converted from the relative motion between two bodies oscillating differently. Multi-body

wave energy converters raise special control problems.

The Bipartite Point Absorber concept is an early example of a two-point heaving

system. It consists of two floaters, the outer one (with very low resonance frequency) being a

structure that acts as the reference and the inner one acting as the resonating absorber. This

device incorporates a concept that was later to be adopted in the Wavebob (see below): the

mass of the inner body is increased (without significantly affecting the diffraction and

radiation damping forces) by rigidly connecting it to a fully submerged body located

sufficiently far underneath.

One of the most interesting two-body point absorbers for wave energy conversion is

the IPS buoy, invented by Sven A. Noren and initially developed in Sweden by the company

Interproject Service (IPS). This consists of a buoy rigidly connected to a fully submerged

vertical tube (the so-called acceleration tube) open at both ends (Fig. 4.25). The tube contains

a piston whose motion relative to the floater-tube system (motion originated by wave action

on the floater and by the inertia of the water enclosed in the tube) drives a power take-off

(PTO) mechanism. The same inventor later introduced an improvement that significantly

contributes to solve the problem of the end-stops: the central part of the tube, along which the

piston slides, bells out at either end to limit the stroke of the piston. A half-scale prototype of

the IPS buoy was tested in sea trials in Sweden, in the early 1980s. The AquaBuOY is a wave

energy converter, developed in the 2000s, that combines the IPS buoy concept with a pair of

hose pumps to produce a flow of water at high pressure that drives a Pelton turbine. A

prototype of the AquaBuOY was deployed and tested in 2007 in the Pacific Ocean off the

coast of Oregon. A variant of the initial IPS buoy concept, due to Stephen Salter, is the sloped

IPS buoy: the natural frequency of the converter may be reduced, and in this way the capture

width enlarged, if the buoy-tube set is made to oscillate at an angle intermediate between the

heave and the surge directions. The sloped IPS buoy has been studied since the mid-1990s at

the University of Edinburgh, by model testing and numerical modelling.

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Figure 4.25 Schematic Representation of the IPS Buoy(Ref:24)

The Wavebob, under development in Ireland, is another twobody heaving device. It

consists of two co-axial axisymmetric buoys, whose relative axial motions are converted into

electric energy through a high-pressure-oil system (Fig. 4.26). The inner buoy (body 2 in Fig.

4.26) is rigidly connected to coaxial submerged body located underneath, whose function is to

increase the inertia (without reduction in the excitation and radiation hydrodynamic forces)

and allow the tuning to the average wave frequency. A large (1/4th scale) model has been

tested in the sheltered waters of Galway Bay (Ireland).

The American company Ocean Power Technologies developed another axisymmetric

two-body heaving WEC named PowerBuoy. A disc-shaped floater reacts against a submerged

cylindrical body, terminated at its bottom end by a large horizontal damper plate whose

function is to increase the inertia through the added mass of the surrounding water. The

relative heaving motion between the two bodies is converted into electrical energy by means

of a hydraulic PTO. A 40 kW prototype without grid connection was deployed off the coast of

Santona, in northern Spain, in September 2008 (Fig. 4.27). This is planned to be followed by

a farm of 9 buoys rated at 150 kW each, the first version of which will be deployed in

Scotland in 2009.[24]

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Figure 4.26 Wavebob(Ref:24)

Figure 4.27 The PowerBuoy Prototype Deployed off Santona, Spain, in 2008(Ref:24)

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c. Fully Submerged Heaving Systems

The Archimedes Wave Swing (AWS), a fully submerged heaving device, was

basically developed in Holland, and consists of an oscillating upper part (the floater) and a

bottom-fixed lower part (the basement) (Fig. 4.28). The floater is pushed down under a wave

crest and moves up under a wave trough. This motion is resisted by a linear electrical

generator, with the interior air pressure acting as a spring. The AWS device went for several

years through a programme of theoretical and physical modelling. A prototype was built,

rated 2 MW (maximum instantaneous power). After unsuccessful trials in 2001 and 2002 to

sink it into position off the northern coast of Portugal, it was finally deployed and tested in the

second half of 2004. The AWS was the first converter using a linear electrical generator.[24]

Figure 4.28 Schematic Representation of the Archimedes Wave Swing(Ref:24)

d. Pitching Devices

The oscillating-body wave energy converters briefly described above are nominally

heaving systems, i.e. the energy conversion is associated with a relative translational motion.

(It should be noted that, in some of them the mooring system allows other oscillation modes,

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namely surge and pitch). There are other oscillating-body systems in which the energy

conversion is based on relative rotation (mostly pitch) rather than translation. This is

remarkably the case of the nodding Duck (created by Stephen Salter, from the University of

Edinburgh) probably the best known offshore device among those that appeared in the 1970s

and early 1980s, and of which several versions were developed in the following years.

Basically it is a cam-like floater oscillating in pitch. The first versions consisted of a string of

Ducks mounted on a long spine aligned with the wave crest direction, with a hydraulic-

electric PTO system. Salter later proposed the solo duck, in which the frame of reference

against which the nodding duck reacts is provided by a gyroscope (Fig. 4.29). Although the

Duck concept was object of extensive R&D efforts for many years, including model testing at

several scales, it never reached the stage of full-scale prototype in real seas.[24]

Figure 4.29 The Duck Version of 1979 Equipped with Gyroscopes(Ref:24)

Among the wide variety of devices proposed in the 1970s and 1980s that did not

succeed in reaching full-size testing stage, reference should be made to the Raft invented by

Sir Christopher Cockerell (who was also the inventor of the Hovercraft). This was actually a

series of rafts or pontoons linked by hinges, that followed the wave contour, with a PTO

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system (possibly hydraulic) located at each hinge. The Cockerell Raft may be regarded as the

predecessor of a more successful device, the Pelamis, and also of the McCabe Wave Pump.

The Pelamis, developed in UK, is a snake-like slack-moored articulated structure

composed of four cylindrical sections linked by hinged joints, and aligned with the wave

direction. The wave induced motion of these joints is resisted by hydraulic rams, which pump

high-pressure oil through hydraulic motors driving three electrical generators. Gas

accumulators provide some energy storage. As other devices that reached full size, the

Pelamis was the object of a detailed development program over several years, that included

theoretical/numerical modelling and physical model testing at several scales. Sea trials of a

full-sized prototype (120 m long, 3.5 m diameter, 750 kW rated power) took place in 2004 in

Scotland. A set of three Pelamis devices was deployed off the Portuguese northern coast in

the second half of 2008 (Fig. 4.30), making it the first grid-connected wave farm worldwide.

Figure 4.30 The Three-unit 3 x 750 kW Pelamis Wave Farm in Calm Sea off Northern Portugal, in

2008(Ref:24)

The McCabe Wave Pump has conceptual similarities to the Cockerell Raft and the

Pelamis: it consists of there rectangular steel pontoons hinged together, with the heaving

motion of the central pontoon damped by a submerged horizontal plate (Fig. 4.31). Two sets

of hydraulic rams and a hydraulic PTO convert the relative rotational motions of the pontoons

into useful energy. A 40 mlong prototype was deployed in 1996 off the coast of Kilbaha,

County Clare, Ireland.

225

Figure 4.31 Side and Plan Views of the McCabe Wave Pump(Ref:24)

Two-body systems have been conceived in which only one body is in contact with the

water: the other body is located above the water or is totally enclosed inside the wetted one.

The theoretical modelling and control of such devices (especially heaving ones and including

also three-body systems) has been analysed by Korde.

Figure 4.32 Front and Side Views of the PS Frog Mk 5(Ref:24)

226

A typical device based on the totally enclosed hull concept is the Frog, of which

several offshore point-absorber versions have been developed at LancasterUniversity,UK. The

PS FrogMk5 consists of a large buoyant paddle with an integral ballasted handle hanging

below it (Fig. 4.32). The waves act on the blade of the paddle and the ballast beneath provides

the necessary reaction. When the WEC is pitching, power is extracted by partially resisting

the sliding of a power-take-off mass, which moves in guides above sea level.

Figure 4.33 Schematic Representation of the Searev(Ref:24)

The Searev wave energy converter, developed at Ecole Centrale de Nantes, France, is

a floating device enclosing a heavy horizontal-axis wheel serving as an internal gravity

reference (Fig. 4.33). The centre of gravity of the wheel being off-centred, this component

behaves mechanically like a pendulum. The rotational motion of this pendular wheel relative

to the hull activates a hydraulic PTO which, in turn, sets an electrical generator into motion.

Major advantages of this arrangement are that (i) (like the Frog) all the moving parts

(mechanic, hydraulic, electrical components) are sheltered from the action of the sea inside a

closed hull, and (ii) the choice of a wheel working as a pendulum involve neither end-stops

nor any security system limiting the stroke.[24]

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e. Bottom-hinged Systems

Single oscillating-body devices operating in pitching mode have been proposed, based

on the inverted pendulum hinged at the sea bed concept. The mace, invented by Stephen

Salter, consists of a buoyant spar, with symmetry about the vertical axis, that can swing about

a universal joint at the sea bottom (Fig. 4.34). The power take-off reaction to the sea bed is via

a set of cables wound several times round a winch-drum leading both fore and aft in the

prevailing wave direction. The wave-activated reciprocating rotation of the drum is converted

into useful energy by means of a hydraulic system.

Figure 4.34 The Swinging Mace in Three Angular Positions(Ref:24)

Two devices are presently under development that share the same basic concept: a

buoyant flap hinged at the sea bed, whose pitching oscillations activate a set of double-acting

hydraulic rams located on the sea bed that pump high pressure fluid to shore via a sub-sea

pipeline. The fluid flow is converted into electric energy by a conventional hydraulic circuit.

These devices are intended for deployment close to shore in relatively shallow water (10–15

m). Apart from size (the Oyster is larger) and detailed design, there are some conceptual

228

differences between them. The Oyster (under development in UK) has a surface piercing flap

that spans the whole water depth and the fluid is sea water powering a Pelton turbine located

onshore, whereas the WaveRoller (a Finish device) is totally submerged and uses oil as

working fluid. Several swinging flaps can feed a single onshore generator, attached to a single

manifold pipeline. A 3.5 m high, 4.5 m wide prototype of the WaveRoller was deployed and

tested in 2008 close to the Portuguese coast at Peniche. A large Oyster prototype was built in

Scotland (Fig. 4.35) and is planned to be tested in the sea in 2009. [24]

Figure 4.35 Oyster Prototype(Ref:24)

f. Many-body Systems

In some cases, the device consists of a large set of floating point absorbers reacting

against a common frame and sharing a common PTO. This is the case of FO3 (mostly a

Norwegian project), a nearshore or offshore system consisting of an array of 21 axisymmetric

buoys (or ‗‗eggs‘‘) oscillating in heave with respect to a large floating structure of square

planform with very low resonance frequency and housing a hydraulic PTO. The Wave Star,

developed in Denmark, consists of two rectilinear arrays of closely spaced floaters located on

both sides of a long bottom-standing steel structure that is aligned with the dominant wave

direction and houses a hydraulic PTO consisting of a high-pressure-oil hydraulic circuit

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equipped with hydraulic motors. The waves make the buoys to swing about their common

reference frame and pump oil into the hydraulic circuit. A 1/10-scale 24 m long 5.5 kW model

with 10 buoys on each side was deployed in 2006 in Nissum Bredning, Denmark, and tested

with grid connection for a couple of years. The Brazilian hyperbaric device is based on a

similar concept, the main differences being that the reference frame about which the buoys are

made to swing is a vertical breakwater, and water is pumped to feed a Pelton turbine. A 1/10-

scale model of the hyperbaric device was tested in a large wave tank.[24]

3) Overtopping Converters

A different way of converting wave energy is to capture the water that is close to the

wave crest and introduce it, by over spilling, into a reservoir where it is stored at a level

higher than the average free-surface level of the surrounding sea. The potential energy of the

stored water is converted into useful energy through more or less conventional low-head

hydraulic turbines. The hydrodynamics of overtopping devices is strongly non-linear, and,

unlike the cases of oscillating body and OWC wave energy converters, cannot be addressed

by linear water wave theory.

The Tapchan (Tapered Channel Wave Power Device), a device developed in Norway

in the 1980s, was based on this principle. A prototype (rated power 350 kW) was built in

1985 at Toftestallen, Norway, and operated for several years. The Tapchan comprises a

collector, a converter, a water reservoir and a low-head water-turbine (Fig. 4.36). The horn-

shaped collector serves the purpose of concentrating the incoming waves before they enter the

converter. In the prototype built in Norway, the collector was carved into a rocky cliff and

was about 60-m-wide at its entrance. The converter is a gradually narrowing channel with

wall heights equal to the filling level of the reservoir (about 3 m in the Norwegian prototype).

The waves enter the wide end of the channel, and, as they propagate down the narrowing

channel, the wave height is amplified until the wave crests spill over the walls and fill the

water reservoir. As a result, the wave energy is gradually transformed into potential energy in

the reservoir. The main function of the reservoir is to provide a stable water supply to the

turbine. It must be large enough to smooth out the fluctuations in the flow of water

overtopping from the converter (about 8500 m2 surface area in the Norwegian prototype). A

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conventional low-head Kaplan-type axial flow turbine is fed in this way, its main specificity

being the use of corrosion-resistant material.

Figure 4.36 Schematic Plan View of the Tapered Channel Wave Power Device (Tapchan) (Ref:24)

In other overtopping converters, the incident waves overtop a sloping wall or ramp and

fill a reservoir where water is stored at a level higher than the surrounding sea. This is the case

of the Wave Dragon, an offshore converter developed in Denmark, whose slackmoored

floating structure consists of two wave reflectors focusing the incoming waves towards a

doubly curved ramp, a reservoir and a set of low-head hydraulic turbines (Fig. 4.37). A 57 m-

wide, 237 t (including ballast) prototype of the Wave Dragon (scale 1/4.5 of a North Sea

production plant) has been deployed in Nissum Bredning, Denmark, was grid connected in

May 2003 and has been tested for several years. Another run-up device based on the slopping

wall concept is the Seawave Slot-Cone Generator (SSG) developed (within the framework of

a European project) for integration into a caisson breakwater. The principle is based on the

wave overtopping utilizing a total of three reservoirs placed on top of each other. The water

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enters the reservoirs through long horizontal openings on the breakwater sloping wall, at

levels corresponding to the three reservoirs, and is run through a multi-stage hydraulic turbine

for electricity production.

Figure 4.37 Plan View of Wave Dragon(Ref:24)

4) Electrical Equipment

In most wave energy converters, a rotating electrical generator is driven by a

mechanical machine: air or hydraulic turbine, hydraulic motor. The electrical equipment,

including variable rotational speed and power electronics, is mostly conventional and largely

similar to wind energy conversion. If the driving machine is a variable displacement hydraulic

motor, it is possible to keep the rotational speed fixed while controlling the flow rate and

power by adjusting the motor geometry.

This is not the case of direct drive conversion, without mechanical interface, by a

linear electrical generator. The first prototype equipped with a linear electrical generator

(rated 2 MW) was the bottomstanding Archimedes Wave Swing (AWS), tested in the sea in

2004. More recently, heaving buoys equipped with linear generators were sea-tested off

Sweden and Oregon, USA. In these buoys, the force that drives the generator is provided by a

taught mooring line.

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Direct drive has the advantage of not requiring a mechanical interface and avoiding

the non-negligible losses that take place in the mechanical machines (turbines and hydraulic

motors) in more conventional PTO systems. On the other hand, linear electrical generators for

wave energy applications are subject to much more demanding conditions than high-speed

rotary ones, and are to a large extent still at the development stage in several countries:

Holland, UK, Sweden, USA. The generator consists of a stator and a translator (rather than a

rotor). In wave energy applications, the generator reciprocating motion matches the motion of

the actual device, at speeds two orders of magnitude lower than the velocities typical of high-

speed rotary generators. At such low speeds, the forces are very large, which requires a

physically large machine. The phase-control of a wave energy converter (like the AWS)

equipped with a linear generator raises special problems.[24]

2.4.3.4 Wave Energy Transmission Concepts for Linear Generator Arrays

1) System Description

a. Base Unit

Figure 4.38 Linear Generator with Point Absorber(Ref:28)

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In a base unit, the following components are included: a buoy, a linear generator with

a permanent magnet rotor, a cable wound stator, and a rectifier. The buoy is connected to the

rotor with a non-stretching rope. Springs are connected to the rotor, to enhance the rotor

motion by pulling it down, as shown in Fig. 4.38. The generator is enclosed in a watertight

construction with a gravity foundation to keep it in place.

In Fig. 4.39, the single line diagram for the base unit is shown. The arrow through the

generator symbol indicates variable voltage and variable frequency.[28]

Figure 4.39 Single Line Diagram for Base Unit(Ref:28)

b. System Options

The base units can be connected in various ways.

Figure 4.40 System Option 1. Without Transformer, 1.1; with Transformer, 1.2. (Ref:28)

In system option 1 (1.1 and 1.2), a number of base units are connected on the DC side,

and thereafter a transmission line connects the cluster to land. A converter onshore forms a 50

or 60 Hz AC, which can be connected to the grid. A transformer with a tap changer is used to

234

take grid voltage variations into account in system option 1.2, as indicated with dashed lines

in Fig. 4.40.

Figure 4.41 System Option 2. Without Transformer, 2.1; with Transformer, 2.2. (Ref:28)

The second system option is very similar to the first, the difference is that the

converter has been moved offshore, see Fig. 4.41. This increases the complexity and may

decrease the availability as maintenance will be more weather dependent. The converter can

be placed on a platform or enclosed in a watertight container on the seabed. System option 2.1

is connected directly to the grid, whereas 2.2 includes a transformer.

A transformer has also been installed offshore in system option 3, as shown in Fig.

4.42. Resistive transmission losses, I2R, will be lower, compared with system 2, as the

transmission voltage is higher and the current is lower.

Figure 4.42 System Option 3(Ref:28)

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The fourth, and final, system option includes a high voltage DC, HVDC, transmission,

see Fig. 4.43. With this system, the degree of complexity is high, but transmission losses are

kept at a minimum.

Figure 4.43 System Option 4(Ref:28)

The systems can be categorized in a loss vs. complexity scheme, as illustrated in Fig.

4.43.

Figure 4.43 System Option Cable Cross vs Complexity(Ref:28)

It is preferable, for simplicity, to avoid controlled active objects at sea. Therefore, the

last option is limited to very large installations at a great distance from the grid connection

point. The first two system options are virtually the same, but in the second system, a

236

controlled part is moved to sea: the converter. The second and third systems could be of

interest if, for some reason, it is impossible to fit the equipment near the grid connection, or a

condition from the customer states that all equipment have to be on the same location.[28]

c. Connection Schemes

There are various ways of connecting large amounts of base units, i.e. linear

generators with rectifiers, for transmission. Firstly, each base unit can have its own cable to

shore (a), see Fig. 4.44.

Figure 4.44 One Cable from Base Unit to Shore (a) (Ref:28)

The availability is then very high, but so are also the cable installation costs. Secondly,

all the base units can be connected at one point, with one cable to grid (b), see Fig. 4.45.

Figure 4.45 One Cable from Farm to Shore (b) (Ref:28)

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This could lead to availability problems as the whole farm is lost, should the

transmission cable or grid connection equipment fail in any way. Another idea is to connect a

small amount of base units, in socalled clusters, each with its own transmission cable (c), see

Fig. 4.46.

Figure 4.46 One Cable from Cluster to Shore (c) (Ref:28)

An intermediate solution is to have clusters, which are connected offshore to one

transmission cable (d), see Fig. 4.47. With this solution the complexity is quite high, while the

cost for transmission cables is lower than for the cluster-to-shore (c) approach. The

availability is also higher than for the farm-to-shore (b) solution. It is possible to expand the

levels further, i.e. a scheme (d2) could consist of clusters of subclusters, each with a

transmission cable to shore. A scheme (d3) could combine sub-subclusters in subclusters and

clusters, and so on.[28]

Figure 4.47 Subclusters and Clusters with Cable to Shore (d)(Ref:28)

238

2.4.3.5 Conclusion

Unlike in the case of wind energy, the present situation shows a wide variety of wave

energy systems, at several stages of development, competing against each other, without it

being clear which types will be the final winners.

In the last fifteen years or so, most of the R&D activity in wave energy has been

taking place in Europe, largely due to the financial support and coordination provided by the

European Commission, and to the positive attitude adopted by some European national

governments (especially in the last few years). However, in the last few years, interest in

wave energy utilization has been growing rapidly also in other parts of the world.

In general, the development, from concept to commercial stage, has been found to be a

difficult, slow and expensive process. Although substantial progress has been achieved in the

theoretical and numerical modelling of wave energy converters and of their energy conversion

chain, model testing in wave basin — a time consuming and considerably expensive task — is

still essential. The final stage is testing under real sea conditions. In almost every system,

optimal wave energy absorption involves some kind of resonance, which implies that the

geometry and size of the structure are linked to wavelength. For these reasons, if pilot plants

are to be tested in the open ocean, they must be large structures. For the same reasons, it is

difficult, in the wave energy technology, to follow what was done in the wind turbine industry

(namely in Denmark): relatively small machines where developed first, and were

subsequently scaled up to larger sizes and powers as the market developed. The high costs of

constructing, deploying, maintaining and testing large prototypes under sometimes very harsh

environmental conditions, has hindered the development of wave energy systems; in most

cases such operations were possible only with substantial financial support from governments

(or, in the European case, from the European Commission).[24]

239

2.4.4 Ocean Thermal Energy Conversion


The sunlight that falls on the oceans is so strongly absorbed by the water that

effectively all of its energy is captured within a shallow "mixed layer" at the surface, 35 to

100 m (100 to 300 ft) thick, where wind and wave actions cause the temperature and salinity

to be nearly uniform. In the regions of the tropical oceans between approximately 15° north

and 15° south latitude, the heat absorbed from the sun warms the water in the mixed layer to a

value near 28°C (82°F) that is nearly constant day and night and from month to month. The

annual average temperature of the mixed layer throughout the region varies from about 27°C

to about 29°C (80 to 85°F).

Beneath the mixed layer, the water becomes colder as depth increases until at 800 to

1000 m (2500 to 3300 ft), a temperature of 4.4°C (40°F) is reached. Below this depth, the

temperature drops only a few degrees further to the ocean bottom at an average depth of 3650

m (12,000 ft). Thus, a huge reservoir of cold water exists below a depth of 3000 ft. This cold

water is the accumulation of ice-cold water that has melted from the polar regions. Because of

its higher density and minimal mixing with the warmer water above, the cold water flows

along the ocean bottom from the poles toward the equator, displacing the lower-density water

above. The result of the two physical processes is to create an oceanic structure with a large

reservoir of warm water at the surface and a large reservoir of cold water at the bottom, with a

temperature difference between them of 22 to 25 degrees Celsius (40 to 45 degrees

Fahrenheit); this structure is found throughout the entire area of the tropical oceans where the

depth exceeds 1000 m (3300 ft). The temperature difference is maintained throughout the

year, with variations of a few degrees Fahrenheit due to the seasonal effects and weather, and

day-to-night changes on the order of one degree.

240

Figure 4.48 Ocean Temperature Resource for OTEC(Ref:26)

The ocean thermal energy conversion (OTEC) process uses this temperature difference

to operate a heat engine, which produces electric power. Calculations show that OTEC plants

sited in the tropical oceans can be operated continuously, without significant environmental

effects, if the power generated is limited to approximately 0.5 MWe (net) per square mile of

ocean surface (0.19 MWe/km2). This amount of power corresponds to the conversion of

0.07% of the average absorbed solar energy to electricity.

A map prepared by Wolff for the U.S. Department of Energy showing the temperature

difference in the tropical oceans between the surface and a depth of 1000 m (3287 ft) is

241

presented in Fig. 4.48. The regions most suitable for OTEC operation, in which the change in

temperature (ΔT) exceeds 22 degrees Celsius (40 degrees Fahrenheit), have a total area of

approximately 60 million km2 (23 million miles2). Thus, if floating OTEC power plants were

uniformly spaced throughout the useful tropical ocean area, the total power generated on

board would exceed 10 million MWe; if each plant generated 200 MWe of net power, the

plants would be spaced 32 km (20 miles) apart. For comparison, the total U.S. electricity-

generating capacity in 1987 was 165 thousand MWe.[26]

2.4.4.2 Design Requirements for OTEC Systems

The OTEC power plant uses the heat in the surface water of the tropical oceans to

generate electricity for on-land facilities or for ship-mounted plants that produce fuels or other

products.

Figure 4.49 Diagram of Closed-cycle OTEC Plantship(Ref:26)

The major subsystems of an OTEC system, shown schematically in Fig. 4.49, are:

1. A heat engine or power plant, including heat exchangers, turbines, electric generator,

water and working-fluid pumps, and associated piping and controls ;

242

2. A water ducting system, which includes a cold-water pipe (CWP) through which

water is drawn from a depth of about 900 to 1000 m (3000 ft) and warm water inlet

and exhaust flow pipes;

3. An energy transfer system to carry the energy produced on board to on-land users as

either electricity or fuel;

4. A position-control system, including propulsion or mooring equipment, controls, and

standby power systems; and

5. A platform to support the power plant, ducting systems, auxiliary ship equipment, and

accommodations for operating personnel, along with safety equipment and other

habitability requirements (on-land buildings may serve some of these functions for

near-shore or shore-based systems).

Where deep water exists near the shore, for example, at tropical islands and coral

atolls and at some continental sites, OTEC plants may be on shore or shelf mounted.

2.4.4.3 OTEC Power Systems

OTEC power systems may be divided into two categories: closed cycle and open

cycle. In closed-cycle operation, the working fluid is conserved (i.e., pumped back to the

evaporator after condensation), as shown in Fig. 4.49.

Figure 4.50 Diagram of Open-cycle OTEC Power System(Ref:26)

243

In the open-cycle system, the working fluid is vented after use, as shown in Fig. 4.50.

In this case, the working fluid is water vapor. Warm seawater is pumped into a chamber in

which the pressure is reduced by a vacuum pump to a value low enough to cause the water to

boil. The low-pressure steam, after passing through a turbine, is condensed by cold water in a

similar chamber and is then discharged into the ocean. Instead of being condensed by direct

contact with cold water, the vapor may be directed to a heat exchanger cooled by the cold

seawater. In this case, the condensed vapor becomes a source of fresh water.

A complete closed-cycle OTEC system (Mini-OTEC) was tested by Lockheed at sea

in Hawaii in 1979 at a 50-kWe gross power output. A cold-water pipe (CWP) of 0.71 m

diameter (28 in.) and 670 m length (2200 ft) was successfully deployed and operated in this

experiment. In early 1981, an ocean-based OTEC power system (OTEC-1), including a 670-m

(2200-ft) CWP of 2.55 m diameter (8.4 ft), and cold- and warm-water ducting equipment, was

deployed and operated at 1 -MWe scale, also in Hawaii. A layout diagram are shown in Fig.

4.51. These successful tests demonstrate that closed-cycle OTEC is ready for the next major

step: scale-up to a size large enough to provide detailed engineering data on performance and

cost for the design of commercial OTEC systems.

Figure 4.51 Layout Diagram of OTEC-1 Subsystems (Castellano, 1981)(Ref:26)

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Open-cycle OTEC systems are still in the research and development phase but offer

promise of competitive performance, particularly if fresh water, and/or mariculture products,

produced along with or instead of electric power, are marketable products at the plant site.

In the hybrid cycle, the warm seawater is flash evaporated under vacuum to steam (as

in OC OTEC systems. The heat in the resulting low-pressure steam is then transferred via a

heat exchanger to ammonia in a conventional closed Rankine cycle system and condensed in

the ammonia evaporator. The drop in the condensation temperature is due to the combined

effects of noncondensable gas evolved from the seawater and steam-side pressure drop.

Evaporating ammonia is passed through the turbine and is condensed in a surface condenser.

Cold seawater is sensibly warmed in passing through the condenser.

Figure 4.52 Hybrid-cycle OTEC Power System(Ref:26)

The schematic diagram of the hybrid OTEC power system is illustrated in Fig. 4.52.

Warm seawater is pumped from a depth of about 10 to 15 m. It is flash evaporated, and about

0.5% of the water flow is converted into low-pressure steam. During the flash evaporation,

dissolved gases evolve. The low-pressure steam flows to the ammonia evaporator, where

about 95% of the steam is condensed. All of the steam cannot be condensed due to the

presence of noncondensable gases that reduce the condensation temperature. Therefore, an

optimum fraction of steam that should be condensed in the ammonia evaporator needs to be

determined for a given set of operating conditions. [26]

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2.4.4.4 Applications for OTEC

The main goal of this system is to output electric power and, secondly, desalinated

water (2-megawatt electric plant could produce about 4300 cubic meters of desalinated water

each day) for some cycles. But OTEC technology offers others possibilities, like support for

deep water mariculture (deep waters rich in nutrients) and air conditioning. It also can be used

to produce ammonia (the working fluid), hydrogen, aluminum, methanol and others

chemicals.[27]

Figure 4.53 Block Diagram of All Applications from OTEC Technology(27)

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2.4.4.5 Advantages and Disadvantages of OTEC System

1) Advantages

OTEC systems can produce fresh water as well as electricity. This is a significant

advantage for an island, such as the Virgin Islands for example, where fresh water is

limited.

There is enough solar energy received and stored in the warm tropical ocean surface

layer to provide most, if not all, of present human energy needs.

2) Disadvantages

OTEC plants must be located where a difference of about 40 degrees Fahrenheit

occurs year round. Ocean depths must be available fairly close to shore-based facilities

for economic operation.

Construction of OTEC plants and laying pipes in coastal waters may cause localized

damage to reefs and near-shore marine ecosystems.

2.4.4.6 Perspectives

Figure 4.54 Futurist Project Based on OTEC Technology(27)

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A competitive market could be a target in the next decade for OTEC plants. The small

island nations could benefit because the cost to generate power from diesel fuel is high; the

supply of fresh water could also be an advantage. Essentially land-based, open-cycle or

closed-cycle coupled with a desalinated process would be appropriate.[27]

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2.5 Biomass Energy and Electric Generation

2.5.1 Introduction

Broadly defined, biomass is organic material produced on a short timescale by a

biological process. Types of biomass for energy production fall into three broad categories:

(1) wood/plant waste; (2) municipal solid waste/land fill gas; and (3) other biomass, including

agricultural by-products, biofuels, and selected waste products such as tires. Dedicated energy

crops are at present an insignificant portion of the U.S. biomass energy supply. However,

there is increasing interest in biomass for alternative liquid transportation fuels (biofuels),

which is already beginning to change the methodology of documenting biomass usage.

Biomass is abundant, accounting for almost 50 percent of the national renewable

energy resource in 2005, the largest single source of renewable energy. In 2005, biomass

provided about 10 percent (9,848 MW) of the renewable electricity capacity in the United

States, second only to hydroelectric power as a source of renewable electricity. From this

installed capacity, 60,878 million net kWh of electricity was generated (17 percent of all

renewable electricity generation, or 1.5 percent of total electricity generation). However,

development of this renewable electricity source has not seen much recent growth. The nature

of biomass use is such that electricity and heat are often co-generated. An attractive feature of

biomass is that, as a chemical energy source, biomass energy is available when needed, which

also makes it attractive for competing applications, such as transportation fuel.[5]

2.5.2 Biomass Technologies

2.5.2.1 Gasification-based Biomass

The conversion of biomass to a low- or medium-heating-value gaseous fuel (biomass

gasification) generally involves two processes. The first process, pyrolysis, releases the

volatile components of the fuel at temperatures below 600°C (1,112°F) via a set of complex

reactions. Included in these volatile vapors are hydrocarbon gases, hydrogen, carbon

monoxide, carbon dioxide, tars, and water vapor. Because biomass fuels tend to have more

volatile components (70-86% on a dry basis) than coal (30%), pyrolysis plays a proportionally

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larger role in biomass gasification than in coal gasification. The by-products of pyrolysis that

are not vaporized are referred to as char and consist mainly of fixed carbon and ash. In the

second gasification process, char conversion, the carbon remaining after pyrolysis undergoes

the classic gasification reaction (i.e. steam + carbon) and/or combustion (carbon + oxygen). It

is this latter combustion reaction that provides the heat energy required to drive the pyrolysis

and char gasification reactions. Due to its high reactivity (as compared to coal and other solid

fuels), all of the biomass feed, including char, is normally converted to gasification products

in a single pass through a gasifier system.

Figure 5.1 Biomass Gasification Combined Cycle (BGCC) System Schematic(Ref:29)

Below characterizes a biomass gasification combined cycle (BGCC) system as

depicted in Figure 5.1. A high pressure, direct gasifier shown inside the dashed line within

Figure 5.1 is considered here. Several other gasifier options are possible, specifically low

pressure direct gasifiers (Figure 5.2) and indirect gasifiers (Figure 5.3). Depending on the type

of gasifier used, the above reactions can take place in a single reactor vessel or be separated

into different vessels. In the case of direct gasifiers, pyrolysis, gasification, and combustion

take place in one vessel, while in indirect gasifiers, pyrolysis and gasification occur in one

vessel, and combustion in a separate vessel. In direct gasification, air and sometimes steam

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are introduced directly to the single gasifier vessel (Figures 5.1 and 5.2). In indirect

gasification, an inert heat transfer medium such as sand carries heat generated in the

combustor to the gasifier to drive the pyrolysis and char gasification reactions. Currently,

indirect gasification systems operate near atmospheric pressure. Direct gasification systems

have been demonstrated at both elevated and atmospheric pressures. Any one of the gasifier

systems can be utilized in the larger system diagrammed above and have been utilized in at

least one recent system design study.

Figure 5.2 Low-pressure Direct Gasifier(Ref:29)

There are several practical implications of each gasifier type. Due to the diluent effect

of the nitrogen in air, fuel gas from a direct gasifier is of low heating value (5.6-7.5 MJ/Nm3).

This low heat content in turn requires an increased fuel flow to the gas turbine. Consequently,

in order to maintain the total (fuel + air) mass flow through the turbine within design limits,

an air bleed is usually taken from the gas turbine compressor and used in the gasifier. This

bleed air is either boosted slightly in pressure or expanded to near atmospheric pressure

depending on the operating pressure of the direct gasifier.

Since the fuel-producing reactions in an indirect gasifier take place in a separate

vessel, the resulting fuel gas is free of nitrogen diluent and is of medium heating value (13-

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18.7 MJ/Nm3). This heat content is sufficiently close to that of natural gas (approx. 38

MJ/Nm3) that fuel gas from an indirect gasifier can be used in an unmodified gas turbine

without air bleed.

Figure 5.3 Indirect Gasifier(Ref:29)

Gasifier operating pressure affects not only equipment cost and size, but also the

interfaces to the rest of the power plant including the necessary cleanup systems. Since gas

turbines operate at elevated pressures, the fuel gas generated by low pressure gasifiers must be

compressed. This favors low temperature gas cleaning since the fuel gas must be cooled prior

to compression in any case. Air for a low pressure gasifier can be extracted from the gas

turbine and reduced in pressure (direct, low pressure gasifier) or supplied independently

(indirect gasifier). High pressure gasification favors hot, pressurized cleanup of the fuel gas

and supply to the gas turbine combustor at high temperature (~ 538ºC o r 1,000ºF) and

sufficiently high pressure for flow control and combustor pressure drop. Air for a high

pressure, direct gasifier is extracted from the gas turbine and boosted in pressure prior to

introduction to the gasifier. Cooling, cold cleanup, and fuel gas compression add equipment to

an indirect gasifier system and reduce its efficiency by up to 10%. Gasifier and gas cleanup

vessels rated for high pressure operation and more elaborate feed systems, however, add cost

and complexity to high pressure gasification systems despite their higher efficiency. Results

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from several recent studies indicate that, at the current, preliminary grade of estimates being

performed, there is little discernable difference in cost of electricity (COE) between systems

employing high and low pressure gasification.

As stated earlier, for the purposes of this analysis, a high-pressure, direct gasification

system was selected. The resulting system is very similar to that evaluated in a pre-feasibility

study conducted by Northern States Power for NREL and EPRI, reported in NREL/TP-430-

20517, and referenced here as "DeLong". This study examined a 75 MWe power plant that

would gasify alfalfa stems to provide electricity to the Northern States Power Company and

sell the leaf co-product for animal feed. A departure from the DeLong study is the use here of

wood as the biomass feedstock. Wood feedstock allows for a more generic plant

representation. Alfalfa separation and leaf meal processing steps in the original DeLong study

would have added complexity and cost to the plant and have complicated the economic

analysis.

The fuel gas is combusted in a Westinghouse "ECONOPAC" 251B12 gas turbine,

producing electric power and a high temperature exhaust stream. A heat recovery steam

generator (HRSG) is employed to recover this heat to generate high temperature, high

pressure steam that is then expanded in a steam turbine to produce additional power. Steam

for the gasifier is extracted from the steam cycle. Finally, electricity for the plant is sent to a

substation for voltage step-up . As noted above, the total net electricity output from this

system is 75 MWe. [29]

2.5.2.2 Direct-fired Biomass

The technologies for the conversion of biomass for electricity production are direct

combustion, gasification, and pyrolysis. As shown in Figure 5.4, direct combustion involves

the oxidation of biomass with excess air, producing hot flue gases which in turn produce

steam in the heat exchange sections of boilers. The steam is used to generate electricity in a

Rankine cycle; usually, only electricity is produced in a condensing steam cycle, while

electricity and steam are cogenerated in an extracting steam cycle. Today's biomass-fired

steam cycle plants typically use single-pass steam turbines. However, in the past decade,

efficiencies and more complex design features, characteristic previously of only large scale

steam turbine generators (> 200 MW), have been transferred to smaller capacity units.

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Today‘s biomass designs include reheat and regenerative steam cycles as well as supercritical

steam turbines. The two common boiler configurations used for steam generation with

biomass are stationary- and traveling-grate combustors (stokers) and atmospheric fluid-bed

combustors.

All biomass combustion systems require feedstock storage and handling systems. The

50 MW McNeil station, located in Burlington, Vermont, uses a spreader-stoker boiler for

steam generation, and has a typical feed system for wood chips. Whole tree chips are

delivered to the plant gate by either truck or rail. Fuel chips are stored in open piles (about a

30 day supply on about 3.25 ha of land), fed by conveyor belt through an electromagnet and

disc screen, then fed to surge bins above the boiler by belt conveyors. From the surge bins, the

fuel is metered into the boiler‘s pneumatic stokers by augers.

Figure 5.4 Direct-fired Biomass Electricity Generating System Schematic(Ref:29)

The base case technology is a commercially available, utility operated, stoker-grate

biomass plant constructed in the mid-1980's, and is representative of modern biomass plants

with an efficiency of about 23%. Plant efficiency of the stoker plant increases to 27.7% in the

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year 2000 through the use of a dryer, and in 2020 plant efficiency is increased to 33.9% due to

larger scale plants which permit more severe steam turbine cycle conditions, e.g. higher

pressure, higher temperature and reheat.[29]

2.5.2.3 Biomass Co-firing

Figure 5.5 Biomass Co-firing Retrofit Schematic for a Pulverized Coal Boiler System(Ref:29)

Co-firing is the simultaneous combustion of different fuels in the same boiler. Many

coal- and oil-fired boilers at power stations have been retrofitted to permit multi-fuel

flexibility. Biomass is a well-suited resource for co-firing with coal as an acid rain and

greenhouse gas emission control strategy. Co-firing is a fuel-substitution option for existing

capacity, and is not a capacity expansion option. Co-firing utilizing biomass (see Figure 5.5)

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has been successfully demonstrated in the full range of coal boiler types, including pulverized

coal boilers, cyclones, stokers, and bubbling and circulating fluidized beds. The system

described here is specifically for pulverized coal-fired boilers which represent the majority of

the current fleet of utility boilers in the U.S.; however, there are also significant opportunities

for co-firing with biomass in cyclones. Co-firing biomass in an existing pulverized coal boiler

will generally require modifications or additions to fuel handling, storage and feed systems.

An automated system capable of processing and storing sufficient biomass fuel in one shift

for 24-hour use is needed to allow continuous co-firing while minimizing equipment operator

expenses. Typical biomass fuel receiving equipment will include truck scales and hydraulic

tippers, however tippers are not required if deliveries are made with self-unloading vans.

Biomass supplies may be unloaded and stored in bulk in the coal yard, then reclaimed for

processing and combustion. New automated reclaiming equipment may be added, or existing

front-end loaders may be detailed for use to manage and reclaim biomass fuel. Conveyors will

be added to transport fuel to the processing facility, with magnetic separators to remove

spikes, nails, and tramp metal from the feedstock. Since biomass is the ―flexible‖ fuel at these

facilities, a 5-day stockpile should be sufficient and will allow avoidance of problems with

long-term storage of biomass such as mold development, decomposition, moisture pick-up,

freezing, etc.

Fuel processing requirements are dictated by the expected fuel sources, with incoming

feedstocks varying from green whole chips up to 5 cm (2 inches) in size (or even larger tree

trimmings) to fine dry sawdust requiring no additional processing. In addition to woody

residues and crops, biomass fuel sources could include alfalfa stems, switchgrass, rice hulls,

rice straw, stone fruit pits, and other materials. For suspension firing in pulverized coal

boilers, biomass fuel feedstocks should be reduced to 6.4 mm (0.25 inches) or smaller particle

size, with moisture levels under 25% MCW (moisture content, wet basis) when firing in the

range of 5% to 15% biomass on a heat input basis. Demonstrations have been conducted with

feedstock moisture levels as high as 45%. Equipment such as hoggers, hammer mills, spike

rolls, and disc screens are required to properly size the feedstock. Other boiler types

(cyclones, stokers, and fluidized beds) are better suited to handle larger fuel particle sizes.

There must also be a biomass buffer storage and a fuel feed and metering system. Biomass is

pneumatically conveyed from the storage silo and introduced into the boiler through existing

injection ports, typically using the lowest level of burners. Introducing the biomass at the

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lowest level of burners helps to ensure complete burnout through the scavenging effect of the

upper-level burners and the increased residence time in the boiler. Discussions with boiler

manufacturers indicate that generally no modifications are required to the burners if the

biomass fuel is properly sized.

The system described here, and shown in Figure 5.5, is designed for moderate

percentage co-firing (greater than 2% on a heat input basis) and, for that reason, requires a

separate feed system for biomass which acts in parallel with the coal feed systems. Existing

coal injection ports are modified to allow dedicated biomass injection during the co-firing

mode of operation. For low percentage co-firing (less than 2% on a heat input basis), it may

be possible to use existing coal pulverizers to process the biomass if spare pulverizer capacity

exists. If existing pulverizers are used, the biomass is processed and conveyed to the boiler

with the coal supply and introduced into the boiler through the same injection ports as the coal

(i.e., the biomass and coal are blended prior to injection into the boiler). Using existing

pulverizers could reduce capital costs by allowing the avoided purchase of dedicated biomass

processing and handling equipment, but the level of co-firing on a percentage basis will be

limited by pulverizer performance, biomass type, and excess pulverizer capacity. The

suitability of existing pulverizers to process biomass with coal will vary depending on

pulverizer type and biomass type. Atritta mills (pulverizers which operate much like fine

hammermills), for example, have more capability to process biomass fuels.

Drying equipment has been evaluated by many designers, and recommended by some.

Dryers are not included here for three reasons: (1) the benefit-to-cost ratio is almost always

low, (2) the industrial fuel sources that supply most cofiring operations provide a moderately

dry fuel (between 28% and 6% MCW), and (3) biomass is only a modest percentage of the

fuel fired. Although drying equipment is not expected to be included initially, future designs

may incorporate cost effective drying techniques (using boiler waste heat) to maintain plant

efficiency while firing a broader range of feedstocks with higher moisture contents.[29]

2.5.3 Status of Technology

Because biomass includes a wide variety of resource types with a wide variety of

characteristics (solid vs. liquid vs. gas; moisture content; energy content; ash content;

emissions impact), a variety of electrical energy generation technologies are employed in

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biomass use. Despite differences, several commonalities exist. Production of electricity from

biomass occurs in much the same manner as from fossil fuels. Similar to coal-fired power

plants, the vast majority of biomass-fired power plants operate on a steam-Rankine cycle in

which the fuel is directly combusted and the resulting heat is used to create highpressure

steam. The steam then serves as the working fluid to drive a generator for electricity

production. With a gaseous fuel, electricity is produced with a more efficient turbine engine

using the gas-Brayton cycle ,in a manner similar to natural gas-fired power plants. In addition

to a gas turbine, a gas-reciprocating engine is also frequently used for <5 MW installations

where a turbine would be too expensive.

A key difference between dedicated biomass power plants and coal-fired power plants

is the size of the power plant, with wood-based biomass power plants (accounting for about

80 percent of biomass electricity) rarely reaching 50 MW, as compared to the 100 MW to

1,500 MW range of conventional coal-fired power plants. Similarly, land-fill gas (LFG)

power plants have capacities in the 0.5 MW to 5 MW range, whereas those operating on

natural gas average about 100 times larger, in the 50 MW to 500 MW range. Because of their

smaller sizes, dedicated biomass power plants are typically less efficient than their fossil fuel-

fired counterparts (in the low 20 percent range as opposed to the high 30 percent range for

coal), since the cost of implementing high-efficiency technologies is not economically

justified at the small scale.

The size difference of coal and biomass plants results, in part, from the high cost of

shipping low-energy-content biomass. For example, typical wood has a moisture content of

about 20 wt-percentage and an energy content, even after drying, of about 9,780 Btu/lb (18.6

MJ/kg), compared to about 14,000 Btu/lb (25 MJ/kg) for coal. In the case of landfill gas,

shipping costs are eliminated by locating the power plant directly at the landfill site. The size

of the power plant is determined by the rate of LFG production, which, in turn, is determined

by the overall size of the landfill. Co-location and size matching are also characteristics of

biomass power plants operated on black liquor, the lignin-rich by-product of fiber extraction

from wood. The power plant, a key component of the paper mill, is sized to match the waste-

product stream to meet the overall electrical and process steam needs of the pulping operation,

often supplemented by purchases of grid electricity.

An increasing use of biomass is in co-fired power plants that burn coal as the primary

fuel source and solid, typically woody, biomass as a secondary source. In cofired plants, high

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efficiencies owing to large size are combined with the benefits of reduced CO2 emissions

from use of a renewable fuel input. With optimal design, co-fired plants can operate over a

range of coal-to-biomass ratios, providing for attractive economics as the cheaper input fuel

can be used when it is available. Co-fired plants tend to produce lower SOx and particulate

emissions and ash residue compared to purely coalfired power plants, although NOx

emissions can be higher due to the presence of nitrogen in the biomass. The environmental

tradeoffs depend on the specific characteristics of the biomass. An important unresolved issue

is the impact of biomass co-firing on the effectiveness of selective catalytic-reduction

technologies.

Although municipal solid waste (MSW) contains substantial energy content,

designation of this fuel source as renewable is not justified, because much of the carbon in

waste products derives from petroleum sources. Storage of that carbon in landfill sites can be

viewed as a ―carbon sequestration‖ solution. As a consequence, several states do not include

MSW in their renewable portfolio standards. Nevertheless, the use of MSW for electricity

production follows that of typical biomass power plants, relying on direct combustion to

create steam that subsequently powers a generator. Landfill gas (LFG) is the gaseous product

that results from the anaerobic decomposition of solid waste and contains about 50 percent

CH4, 50 percent CO2, and trace components of other organic gases. In contrast to solid waste,

LFG by definition cannot be sequestered in a landfill, and the released methane is about 20

times more potent than CO2 as a greenhouse gas. As of December 2007, approximately 445

LFG energy projects operated in the United States, generating approximately 11 billion kWh

of electricity per year and delivering 236 million cubic feet per day of LFG to direct-use

applications, amounting to just under 20 percent of biomass electricity generation.[5]

2.5.4 Biomass Future

Technological advances in the short term would likely relate to power plant design to

ensure fuel flexibility, particularly in co-fired plants, which in turn implies designing fuel feed

and emissions control systems that can adjust to the variable characteristics of biomass fuel.

Strategies include premixing coal and biomass in a single-feed system or providing separate

coal and biomass inlets. With such advances, production of biomass electricity at competitive

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prices (depending on input fuel prices), high efficiency (about 30 percent), and high capacity

factors (reaching 100 percent) could become widespread.

Some fossil fuel plants are being converted to 100 percent biomass combustion plants.

These tend to be smaller-scale plants (e.g., the 24 MW Peepekeo plant near Hilo, Hawaii), but

this trend may be accelerated in the United States, particularly if policy initiatives put a price

on carbon. Progress here could also have ramifications in the medium term, if carbon capture

and sequestration technologies are applied to biomass combustion plants. Capturing this

carbon would result in net reductions of greenhouse gas emissions, and while no

demonstration plant now exists, this potential is being reflected in modeling scenarios,

notably in the European Union.

In parallel with improved use of woody biomass, the use of landfill gas for electricity

production can be expected to increase in the near future, because it not only generates

electricity in urban settings close to demand points, but also mitigates the release of methane,

an extremely potent greenhouse gas. However, over the 2001 to 2005 time period, the portion

of biomass capacity due to MSW/LFG has not changed to reflect these environmental

benefits, suggesting the existence of other barriers. Furthermore, methane emissions from

landfill sites have steadily decreased in the past decade, largely as a consequence of flaring

the recovered methane (simply burning to convert the methane to carbon dioxide and water)

rather than using the energy content. The EPA has identified approximately 560 candidate

landfills as of 2007 with a total annual electric potential of 11 million MWh, amounting to

just over one-quarter of 1 percent of the current U.S. electricity demand.

In the medium term, it is likely that new biopower capacity, if pursued, will

incorporate a pretreatment step in which the biomass is converted to a gaseous or liquid fuel

more suitable for power generation, rather than direct-firing as is the norm today. As with all

thermal power plants, higher operating temperatures generally result in higher efficiencies.

Engines based on steam cycles (Rankine cycle) are inherently restricted to maximum

temperatures of 580°C, due to the nature of the working fluid, water. In contrast, those based

on open-air systems have a high exhaust gas temperature, due to the nature of the working

fluid, air. These differences imply a maximum Rankine cycle efficiency of about 42 percent,

whereas for the Brayton cycle (gas turbine engine), it is approximately 50 percent. A

combined cycle, which uses the hot exhaust gas of the Brayton cycle to operate a lower-

temperature Rankine cycle (steam engine), can potentially obtain a combined efficiency of

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~65 percent. A solid fuel cannot be directly used for operation of a gas turbine engine and

thus must be converted to a gas or liquid by a method commonly called gasification.

Therefore, the efficiency of a biomass gasifier has a direct impact on the electricity production

through this route. Biomass gasifiers would require improvement to be a viable option, as the

present efficiency of biomass gasifiers is low (~30 percent) compared to the efficiency levels

(~75 percent) of today‘s coal gasifiers, which are generally larger.

A power plant operated on a solid fuel but incorporating these three components

(gasification, high-temperature Brayton cycle, low-temperature Rankine cycle) is known as an

integrated gasifier combined cycle (IGCC) power plant (Figure 5.6).

Figure 5.6 Integrated Gasifier Combined Cycle (IGCC)(Ref:5)

While large-scale IGCC systems address the need to enhance system efficiency, at smaller

scales (< 25 MWe) efficiency gains are lower. To obtain high efficiency at the scales typical

of biomass power plants, one potential alternative is a fuel cell, in which chemical energy is

directly, through electrochemical reactions, converted to electrical energy. Fuel cells are

modular in nature, and their efficiency is largely independent of size. Consequently, they can

be well matched to biomass power plants. Hightemperature fuel cells have chemical-to-

electrical conversion efficiencies of ~50 to 60 percent, and, like the gas turbine, the high-

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temperature fuel cell exhaust can be supplied to a steam engine for even higher system

efficiencies.

Mid-term developments of biopower can be anticipated in two primary directions:

biomass gasification to enable widespread IGCC implementation; and improvements in

lifetime and unit costs of fuel cells. In parallel, lower-cost high-temperature materials for both

steam engines and gas turbines are potential development areas. In all cases, such advances

would also benefit fossil-fuel-fired power plants, and substantial technology leveraging from

those industries for biomass use may be possible, although some of the unique characteristics

of biomass may not enable direct transfer between industries. It is noteworthy that biomass is

generally more reactive than coal and hence easier to gasify. Furthermore, the lower sulfur

content of biomass renders the produced gases more amenable to use in a fuel cell. Both

molten carbonate and solid oxide fuel cells can efficiently use the fuel mixture derived from

biomass gasification.

Potential long-term breakthroughs in biopower lie in two distinct areas. The first, and

perhaps more tractable, is in advanced biological methods for converting raw biomass into

clean fuels. Essentially, the high-temperature catalytic steps of gasification, or pyrolysis, are

replaced by ambient-temperature steps through the use of bacteria. Here, natural consortia of

bacteria decompose organic matter into methane in the absence of oxygen in closed reactors.

This process, anaerobic digestion, is similar to the natural decomposition of waste in landfills,

from which methane can also be harvested. Many farm- and community-based systems

(particularly in Germany, Denmark, and several developing countries, but also in the United

States.) already use anaerobic digestion to produce biogas from wastes such as manure, food,

and other organics. The biogas is then used in an internal combustion engine to produce

electricity, or used directly for heating and cooking. Although much of the biomass resource

might be dedicated to biofuel production (thus diminishing its role in electricity generation),

biogas technologies could provide a small but nontrivial part of a renewable electricity

portfolio, particularly given their flexibility and potential for distributed generation.

The second, more speculative, potential breakthrough is in bioengineering new plants

to radically enhance the efficiency of photosynthesis. The solar-to-biomass conversion in

typical plants is only ~0.25 percent; subsequent conversion from biomass to electricity

proceeds with another efficiency penalty of at least 50 percent. Thus, solar-to-electric energy

conversion efficiency is on the order of 0.1 percent, which is far below the 10 to 20 percent

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efficiency achievable with state-ofthe- art photovoltaics and concentrating solar power

systems. It is unclear, however, whether agricultural practices using bioengineered plants

would be sustainable, even if photosynthesis could be enhanced through genetic modification.

Even with today‘s candidate energy crops (e.g., willow, miscanthus, poplar, and switchgrass),

it is unknown how much of the biomass must be left in the fields to ensure soil health. A

complete evaluation of these uncertainties is beyond the scope of this analysis.[5]

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2.6 Hydropower Energy and Electric Generation

2.6.1 Introduction

Among all renewable energy sources, hydroelectricity is the most expanded one over

the world. It represents almost 94% of the renewable energy production and 20% of

worldwide energetic needs. In fact, this is due to high power hydroelectric stations, each of

them producing several hundreds of megawatts, which have been built for approximately one

century.

Nowadays, it is nearly no more possible to settle such a plant in many countries

because of suitable site rareness and of environmental concerns. Nevertheless small-scale

hydropower has a quite large potential of development because of the increasing interest in

renewable energies and dispersed electrical generation. This type of hydroelectricity ranges

from 0 to 10MW in Europe, 25W in Canada and 30MW in the United States. It is divided in

four items (small, mini, micro and pico hydropower), relative to utility rated power, whose

definition lies on the considered country and may also vary from one author to another. It is

generally agreed that, in France, micro hydroelectricity ranges from 0 to 5MW. In 2001, the

worldwide small hydrocapacity reached 37,000MW. A 48% growth is previewed until 2010.

In Europe, the small hydrocapacity is over 10,300MW, representing 1.7% of european

electricity production capacity and 10% of hydroelectric power. The growth potential reaches

about 6000MW.

Therefore, small-scale hydropower will play a significant role in renewable energy

source development.[31]

2.6.2 Hydropower Plant Models and Control

The large diversification in behavior of nonlinear plants across its operating points

requires different control objectives and thus different control actions to be taken for each

variation in operating point. The nonlinear dynamic characteristics of hydro plant largely

depend on internal and external disturbances, set point changes, leading to shift from its

optimum operating point. The schematic of hydropower plant is illustrated in Fig. 6.1. A key

item of any hydro power plant is the governor. This governing system provides a means of

264

controlling power and frequency. The speed governor includes all those elements, which are

directly responsive to speed and position or influence the action of other elements of the speed

governing system. The speed control mechanism includes equipment such as relays,

servomotors, pressure or power amplifying devices, levers and linkages between the speed

governor and governor-controlled gates/vanes. The speed governor normally actuates the

governor-controlled gates/vanes that regulate the water input to the turbine through the speed

control mechanism.

Figure 6.1 General Layout Form of a Hydropower Plant(Ref:30)

Figure 6.2 Block Diagram Form of a Hydropower Plant(Ref:30)

Conventionally, hydraulic-mechanical governor and electro-hydraulic type with PID

controllers are popular in use. The technologies of these governors have developed

considerably over the past years.

In recent years, digital governors have gradually replaced these analog controllers.

Recent developments in the field of control technologies impose a new approach in the

265

turbine control systems with application of artificial intelligence (AI). One of the most

discussed applications of artificial intelligence in turbine governing is the replacement of a

standard Electro-hydraulic governor with fuzzy logic or neural network or hybrid controller-

fuzzy logic and neural network.[30]

2.6.3 Hydroelectricity

Hydroelectricity is any electricity generated by the energy contained in water, but

most often the word is used to refer to the electricity generated by hydroelectric dams. These

dams harness the kinetic energy contained in the moving water of a river and convert it to

mechanical energy by means of a turbine. In turn, the turbine converts the energy into

electrical energy that can be distributed to thousands, even millions, of users.[2]

Figure 6.3 Huge Turbine Engines inside the Hoover Dam in Black Canyon, Nevada(Ref:2)

266

A hydroelectric dam consists of the following components:

• Dam: The dam is built to hold back water, which is contained in a reservoir. This water is

regarded as stored energy, which is then released as kinetic energy when the dam operators

allow water to flow. Sometimes these reservoirs, such as Lake Mead, are used as recreational

lakes.

Figure 6.4 Aeiral View of Hoover Dam, Nevada, creating the Reservoir Lake Mead(Ref:2)

267

• Intake: Gates open to allow the water in the reservoir to flow into a penstock, which is a

pipeline that leads to the turbine. The water gathers kinetic energy as it flows downward

through the penstock, which serves to ‗‗shoot‘‘ the water at the turbine.

• Turbine: A turbine is in many ways like the blades of a windmill or the veins of a pinwheel.

The water flows past the turbine, striking its blades and turning it. The most common turbine

design used in large, modern hydroelectric power plants is the Francis turbine, which is a disc

with curved blades.

In the largest hydroelectric plants, these turbines are enormous, weighing up to 170

tons or more. The largest ones turn at a rate of about 90 revolutions per minute.

• Generator: The turbine is attached by a shaft to the generator, which actually produces the

electricity. In a hydroelectric plant, the mechanical energy is supplied by the turbine, which

in turn is powered by the kinetic energy of moving water.

• Transformer: A transformer converts the alternating current produced by the generator and

converts it into a higher voltage current.

• Power lines: Power lines transmit the power out of the power plant to the electrical grid,

where it can be used by consumers.

• Outflow: Pipes called tailraces channel the water back into the river downstream.[2]

Hydroelectric power plants come in three basic types:

• High head: ‗‗Head‘‘ refers to the difference in level between the source of the water and the

point at which energy is extracted from it. Assuming other things are equal, the higher the

head, the more power is generated. A high head hydroelectric plant is one that uses a dam and

a reservoir to provide the kinetic energy that powers the plant. Most major hydroelectric

plants are of this type.

• Run-of-the-river: In contrast, a run-of-the-river plant requires either no dam or a very low

dam. It operates entirely, or almost entirely, from the flow of the river‘s current. No energy is

stored in a reservoir. These hydroelectric plants are generally small, producing less than about

25 kilowatts.

• Pumped-storage: Some hydroelectric plants rely on a system of two reservoirs. The upper

reservoir operates exactly as the reservoir does in a high head plant: Water from the reservoir

flows through the plant to turn the turbines, then exits the plant and reenters the river

downstream. In a pumped storage plant, the water exiting the plant is stored in a lower

reservoir rather than reentering the river. Using a reversible turbine, normally during off-peak

268

hours (or hours when power usage is low, usually at night), water is then pumped from the

lower to the higher reservoir to refill it. This gives the plant more water to use to generate

electricity.[2]

2.6.4 Micro Hydropower Station

A small hydropower station is usually a run-of-river plant, which consequently does

not need any water reservoir such as large dams. Only a minor part of the river water flow is

deviated to the turbine. This leads to a good agreement of these plants with the environment.

Moreover, as civil work and functioning costs are not restrictive and because of their

reliability, small stations are suited to feed areas situated in isolated and/or poor locations.

Technically speaking, they are well utilized to supply power to passive loads. Water

turbines are of the same type as these used in high power hydroelectric stations. It may be

noticed that small-scale utilities are frequently renovated plants, which were abandoned in the

1950s as they were considered unefficient. For example, in Europe, 68% of micro

hydropower stations are based on ancient structures and therefore involve classical

electromechanical sets.

These drives are based on a fixed speed synchronous machine or a squirrel cage

induction generator. In both configurations, no use is made of power electronic devices. In the

first case, speed is necessary fixed; in the second one, speed may vary in a small range

according to active power demand changings or the additional capacitor and load equivalent

impedance variations if the asynchronous machine supplies a passive network, i.e. if the

station is islanded. For both generators, the turbine rate of flow regulation allows to supply

the necessary active power and to control the frequency when the station is connected to

isolated loads.

2.6.4.1 A Hydropower Station under Study

The proposed structure, well suited to feed isolated loads, is shown in Fig. 6.5. As said

previously, this micro hydropower station, like most plants, is a run-of-river one. This leads to

the use of a Kaplan hydraulic turbine, whose structure recalls that of a boat propeller, which is

a reaction turbomachine well suited for low water heads. Blades and upstream guide vanes of

269

this turbine may be pitch controlled like a wind turbine leading to an additional degree of

freedom comparing to other water wheels. The aim of these mechanical controls is to

optimize the turbine efficiency according to the water rate of flow. The turbine is associated

with a gear box because of its small rotating speed. This turbine drives a doubly fed induction

generator (DFIG) whose excitation is supplied, on its rotor, by a permanent magnet

synchronous machine (PMSM) mounted on the same shaft. Two back-to-back PWM power

electronic converters carry out the electric link between the machines. This type of tandem

arrangement, when the synchronous machine is a wound rotor one, is known as a static

Kraemer drive. This DFIG based structure is different from those used in wind generators in

which the rotor is connected to the grid by way of converters.

Figure 6.5 Autonomous Variable Speed Micro Hydropower Station(Ref:31)

It is worthy to notice that the presented structure is also considered in the field of

aeronautics, the hydraulic turbine is then replaced by a jet engine.[31]

2.6.5 Hydropower’s Future in a Fluid Energy World

To predict the future is comparable to purchasing a lottery number and then mortgage

the expected winnings to a dwelling anticipating to win the pot. Time parameters need to be

clearly identified to impart meaning to the prediction of hydropower‘s future. Hydropower in

different countries is in varied phases of utilization of the respective states‘ hydroelectric

potential. Myanmar in 2000 had 365MW of installed hydropower, but plans call for installing

270

39,600MW in the next two decades. Hydropower as a domestic electricity resource has and

continues to serve as an incubator energy source to change the standard of life of the state that

turns to harnessing it. Hydropower‘s past is instructive to evaluate its future while the

installation process has been significantly changed.

Data are like guardrails in uncertain mountain terrain. Data serve to project future

electricity demand and the construction response is in the form of hydroelectric project

construction schedules to meet the anticipated electricity need. Hydroelectric projects are

capital demanding and schedule sensitive. Projected construction values provide a road map

how different systems anticipate to serve future electricity needs within a given time frame.

The world‘s hydroelectric systems will add 157.8 GW in 2008, and nearly 83% of this

expansion is placed in Asia. Of the 130 GW in Asia, China builds 80 GW, or 61%. These data

serve to illustrate unevenness in distribution globally and regional electricity planning policy

differences on how to foster energy autonomy. The dominance of the hydroelectric sector in

Asia and South America points to the introduction of energy availability and the

industrialization process in these two regions since WWII. Power and change gravitate

towards each other.

Norway and Switzerland turned early to hydropower as coal-poor states and turned

this energy source into a major agent to change the standard of life for their citizens. In 2000,

Norway‘s reported per capita annual electricity use was 27,600 kWh, Switzerland‘s 8500

kWh. Currently in Africa, the per capita electricity consumption per year in 2000 was 524

kWh while the world averaged 2475 kWh/p/y. These few selected values as reference markers

illustrate the impending force of pressure to use local electricity sources—hydropower—to

further socioeconomic change. Additional pressure in this process will come out of the

urbanization process in Africa. Increased fossil fuel prices contribute their influence to

enhance hydropower‘s rising role in the electricity generating sector. Africa in 2000 had

22,104MW of installed hydropower, comprising 21.7% of the continents‘ electricity supply,

or 112.2 kWh out of 524 kWh/p/y were hydropower generated. Economic pressures to change

this condition can be identified in Ethiopia, which in 2000 had 378MW of installed

hydropower. Two percent of Ethiopia‘s hydropower potential is actually in use. In 2006,

791MWwere on line, by 2010/11 this is to reach 4000MW. In 2005 the per capita

consumptionwas 28 kWh/p/y, and 80% of the country‘s population had no access to

electricity. The exploitable potential is 30,000MW, 4461MW are under construction or

271

‗‗committed‘‘ for construction. The future of hydropower opens the path to change consistent

with local conditions and possibly including options similar to those observed in Norway and

Switzerland when they got the light.

Hydropower‘s future in Asia parallels its current economic change. China, India, Iran,

and Turkey are turning into major hydropower states. Hydropower development originated in

the US and Europe, hence to expect contemporary parallel applications obliges to include the

varied time frames of project construction periods. While the Chinese system will be the

world‘s largest, the Indian, Turkish, and Iranian systems are impressive for their respective

magnitudes. Also to be included are the S.E. Asian states with significant hydropower

resources. It is useful to refer once again to available water volumes in km3 and m

3/s to

identify local hydropower resources.

Hydropower‘s future is inseparable from economic evaluations. Cash flow goes into

construction without return for the time until a certain quantity ofMWs enter service. Cash

and interests rates act as constraints upon profligate spending schedules. However, projects

today are projected to generate for 100 years+ and the repayment schedule is somewhere from

12 to 25 years. Not included in this assessment projection are transmission and transforming

installations. In the economic sphere, it is not only project costs, but also money market

conditions within each economic system, hence prediction ismade in an unstable economic

climate. This leaves the question, how can an economic system function without an effective

electricity generating system?

While hydropower has its limitations, there are two options to enhance this energy

source: one by turning to run-of-the-river bulbar generation; and two by pumped-storage. This

second system is a practical approach to enhance the ‗‗hydropower energy bridge.‘‘ It needs

to be noted, the electricity system as in place in 2009 will be notably different in 2050 as

technology introduces changed electricity systems in most likelihood phasing out the fossil

fuel era in the electricity sector. The run-of-the-river bulbar units can be placed without any

dam, notably in very large rivers like the Amazon, Yangtze, Orinoco, Parana, Congo, Lower

Mekong. The pumped river projects are already in use and serve as stand-by for peak load

demand.

As the world has turned multi-energy source dependent, the need for energy has

reduced states‘ energy autarchy and source options. Additional energy sources have become

the norm in the 1930–2009 period. This will foster the search for a more universal energy-

272

electricity source replacing the energy system familiar in 2009. Hydropower will outlast most

of the currently known energy sources because of its favorable economics. It also may be

helped by change water management, notably urban–industrial water supply systems, and

significantly the dams needed for irrigation projects. Irrigation currently provides 40% of the

worlds‘ food production. To start a hydropower project is expensive, to operate it, it out

competes all comers.

Hydropower has played a prominent part in the electrification phase of the

industrialization process. As the less industrialized states of the world expand their secondary

sector, low cost electricity will be sought to further this phase of domestic change. Economy

in investment strategy and the inherent advantage of long term low cost electricity supply and

rising urbanization rates use hydropowered electricity to service local energy needs. India

plans to integrate the national fluvial system by ‗‗interconnecting‘‘ its key rivers to enhance

hydrological management and enlarge its hydropower system by 55,000MW by 2012. In

China hydropower serves as a key link in its evolving energy matrix. Chinese plans call for

158 GW installed in 2010 and 270 GW by 2020. If each kW installed averages $1200, that

bill by 2020 will be $134,400,000,000, and this is for 112 GW, not 270 GW. Iran and Turkey

pursue a comparable course of action. Brazil has to plan on 4500 MW/year to avoid

brownouts or blackouts. The options are limited. China currently (2009) burns annually 43%

of the world‘s coal production, this may illuminate the future for hydropower in China.

Current limitations for clean bulk low cost electricity make hydropower the ‗‗electricity

bridge‘‘ to that electricity source four to five decades hence. Electricity‘s future is in the

oceans and the sky not in cane sugar or corn fields. Hydropower for its part contributes to

ease newcomers to the industrial world into functional electricity depending energy

systems.[32]

273

2.7 Hydrogen Energy and Electric Generation

2.7.1 Introduction

Fossil fuels (i.e., petroleum, natural gas and coal), which meet most of the world‘s

energy demand today, are being depleted fast. Also, their combustion products are causing the

global problems, such as the greenhouse effect, ozone layer depletion, acid rains and

pollution, which are posing great danger for our environment and eventually for the life in our

planet. Many engineers and scientists agree that the solution to these global problems would

be to replace the existing fossil fuel system by the hydrogen energy system. Hydrogen is a

very efficient and clean fuel. Its combustion will produce no greenhouse gases, no ozone layer

depleting chemicals, little or no acid rain ingredients and pollution. Hydrogen, produced from

renewable energy (e.g., solar) sources, would result in a permanent energy system, which we

would never have to change.[33]

2.7.2 Electrical Energy Storage

An energy system dominated by electrical power has to be as flexible as the present

fossil fuel system (Fig. 7.1). The required new storage and transportation system has to meet

the requirements of the customers. The energy carrier hydrogen fits into this system;

hydrogen can be used in almost all paths of our energy system (Fig. 7.2).

Following the generation of electricity the production of hydrogen by electrolysis

offers some benefits to power utilities: Electrolysers as a load in the electrical network can be

used for frequency control or load management, thereby saving reserve capacity, and power

plants can be operated at rated power with the best efficiency and highest revenues. Hydrogen

can be utilised, for example, in fuel cells with a high efficiency to produce power.

In island networks or areas with a weak grid and/or growing power demand, a

hydrogen system with electrolyser, storage and fuel cell or customers with a reliable power

supply. Hydrogen can be produced at the supply site via electrolysis during low load periods

and reconverted to power in peak load periods. Especially for the use of renewable energies

like wind or solar power the temporal discord between production and demand of energy can

be compensated for.[34]

274

Figure 7.1 Energy Supply Structure(Ref:34)

Figure 7.2 Paths for Hydrogen(Ref:34)

275

2.7.3 Electrolyser

Technically, electrolyser is a vital component that electrolysis the hydrogen, and the

developments in the electrolysers improve total hydrogen energy system concept.

The GHW (Gesellschaft fur Hochleistungselektrolyseure zur Wasserstofferzeugung

mbH), a joint enterprise of the German companies HEW, Norsk Hydro Electrolyser and

Motoren-und Turbinen-Union Friedrichshafen GmbH (MTU), has developed an electrolyser

with superior features adapted to the production of hydrogen from electricity sources which

have strongly variable power generation.

The electrolyser has a high degree of efficiency, excellent part-load performance and

high gas puritywith fast intermittent operation. The technology of the GHW electrolyser is:

low-cost PSU electrode diaphragm

operating pressure: 30 bar

efficiency: 80% rated load up to 90% (20% load)

load range: 20% - 110%

typical power units: 0.5 to 2.5 MW and more.

A high-performance electrolyser is a key component in future hydrogen energy

systems. Projects and studies with the new electrolyser cover the following fields at GHW,

HEW or CONSULECTRA:

Harvest of PV-solar energy in the 'Solar- Wasserstoff Bayern Project'.

Harvest of fluctuating wind energy in 'weak grid systems with a relatively large

amount of wind power generation.

Power grid load control (Fig. 7.3). Because of its extremely fast regulating behaviour

the electrolyser can be used as a variable load which draws power anticyclic to the

power production, regulating the needs of a utility and thus replacing some of the

necessary regulating and reserve power plant capacity. If such systems are installed on

a large scale for future commercial hydrogen production, the following additional

advantages could be envisaged for the utility: (i) fewer losses in power plant operation

(ii) less wear on power plant regulating components (iii) improvement of regulating

response time and grid stability.[34]

276

Figure 7.3 Hydrogen Filling Station Network with Electrolyser as Controllable Load(Ref:34)

2.7.4 Hybrid Systems

2.7.4.1 Solar-hydrogen Energy Systems

If solar energy, in its direct and/or indirect forms (e.g., hydro, wind, etc.), is used to

manufacture hydrogen, then the resulting system is called the ‗‗solar-hydrogen energy

system‖. In this system, both the primary and secondary energy sources are renewable and

environmental1y compatible, resulting in a dean and permanent energy system. Fig. 7.4

presents a schematic of the solar-hydrogen energy system.

In this case, it is assumed that the conversion to the hydrogen energy will take place,

and one-third of hydrogen needed will be produced from hydropower (and/or wind power)

and two-thirds by direct and indirect (other than hydropower) solar energy forms. The same

percentage of energy demands by sectors as the above systems will be assumed. It will further

be assumed that one half of the thermal energy will be achieved by flame combustion, one-

quarter by steam generation with hydrogen/oxygen steam generation and the last quarter by

catalytic combustion; electric power will be generated by fuel cells; one-half of the surface

277

transportation will use gaseous hydrogen burning internal combustion engines and the other

half will use fuel cells. In air transportation, both subsonic and supersonic, liquid hydrogen

will be used.

Figure 7.4 Solar-hydrogen Energy System(Ref:33)

A hybrid system schematic from the system in Denizli is shown in Figure 7.5 and Figure

7.6.[36]

Figure 7.5 System without Hydrogen (Ref:36)

278

Figure 7.6 System with Hydrogen(Ref:36)

2.7.4.2 Wind to Hydrogen System

The project carried out in Minnesota is expecting to realize an integrated wind-

hydrogen system in order to produce hydrogen via electrolysis.

Figure 7.7 Construction of the 1.65 MW Wind Turbine at the Morris Research Center(Ref:35)

The wind turbine is a Vestas NM 82 with a rated capacity of 1.65 MW that is expected

to produce 5.6 million kWh of electricity annually at this site. The turbine was installed in

early 2005 and is now supplying power to the University of Minnesota.

279

This phase will incorporate a 400 kW electrolyzer, hydrogen storage tanks, and an

internal combustion engine that will use the hydrogen for ―on-demand‖ electricity.[35]

280

3 FINANCIAL AND ECONOMIC VIEW OF RENEWABLE ENERGY

3.1 Cost of Renewable Energy Systems

Below tables illustrate the current cost assumptions for renewable technologies in 2007

and 2020 cost projections and comparisons:

Technology Overnight

Capital

Cost ($

per KW)

Capacity

Factor

Variable

O&M

(+ Fuel

Costs) ($

per MWh)

Fixed

O&M

($ per

KW)

Levelized

Cost of

Energy

($ per

KWh)

Biopower

Biopower-

IGCC

3,766 83% 6.71(+$15)^

64.45 $0.080

Biopower-

Stoker

3,520 85% 3.74(+35)#

91.79 $0.0977&

Biopower-50

MW

Fluidized Bed

3,629 85% 4.26(+35)#

94.49 $0.101&

Biopower 2,596 85% 7.27(+28)#

166.13 $0.090

CSP

CS 3,645 65% 8.10 0.00 $0.071**

CS 5,021 31% 0.00 56.7 $0.200

CS 34%

$0.170

CS-Trough 3.271 34% 0.00 60.2@

$0.130

CS 4,153 43% 31.20 34.3 $0.170

CS-Trough $0.160-

$0.190

PV

PV 4,050 21% 0.00 10.4 $0.220**

PV- $0.260

281

Distributed

PV Flat Plate 5,487 25% 0.00 19.5 $0.251&

PV 2-Axis 8,876 32% 0.00 46.6 $0.330&

PV-

Distributed

$0.150

PV-

Distributed

$0.080

PV-Central 6,038 22% 0.00 11.7 $0.320

Wind

Onshore

Wind

1.923 36% 0.00 30.3 $0.069+

Onshore

Wind

1,052 45% 0.00 26.2 $0.033**

Onshore

Wind

927 46% 0.00 25.3 $0.029**

Onshore

Wind

32.5% $0.100

Onshore

Wind

1,820 42% 0.00 72.7 $0.068&

Onshore

Wind

1,765 33% 0.00 26.0 $0.073+

Onshore

Wind

1,713 35% to

50%Φ

5.70 11.9 $0.064 to

$0.047Φ

Onshore

Wind

1,983 34% 0.00 16.5 $0.071+

Onshore

Wind

3,851 34% 0.00 89.5 $0.157+

Onshore

Wind

2,388 37% to

52%Φ

15.60 18.7 $0.094 to

$0.071Φ,+

Conventional

Pulverized 2,058 85% 4.64(+16.7)^

27.53 $0.050

282

Coal

Conventional

Gas

Combined

Cycle

962 87% 2.09(+$45.1) 12.48 $0.060

Conventional

Combustion

Turbine

670 30% 3.60(+$69.3) 12.11 $0.100

Table 8.1 Current Cost Assumptions for Renewable Technologies (2007)(Ref:5) &Calculated from inputs based on 20 year economic life and real cost of capital of 7.5%

+Levelized costs here are generic and do not include site specific development costs or cost of

facilitating delivery #Fuel cost per MWh imputed from EPRI summer study levelized cost and TAG specifications for CFB

biomass plant *Fuel cost per MWh reported by source

^Fuel cost imputed from AEO2009 Early Release model solution. AEO2009 Energy Prices (2007$/mmBtu) in 2012 are $1.91 for coal, $6.63 for natural gas, and $1.96 for biomass

**EERE numbers are for 2010 @

This estimate comes from a personal communication with Steve Gehl of EPRI ΦDepending on wind class

Technology Overnight

Cost (per

kW)*

Capacity

Factor

Total

Capital

Cost

(per

MWh)

Transmission

Cost

(per MWh)

Levelized

Cost of

Energy

($ per

kWh)+

Conventional

Sources

Pulverized

Coal

1,985 85% 52.30 3.61 $0.083

[$0.079]

IGCC 2,233 85% 60.64 3.61 $0.088

[$0.084]

IGCC with

Sequestration

3,171 85% 69.54 4.01 $0.103

[$0.099]

283

Combined

Cycle

928 87% 18.63

3.88

$0.083

[$0.079]

Advanced

Combined

Cycle

892 87% 17.98 3.88 $0.079

[$0.075]

Advanced

Combined

Cycle with

Sequestration

1,729 87% 34.64 3.93 $0.110

[$0.106]

Combustion

Turbine

647 30% 33.55 11.41 $0.138

[$0.127]

Advanced

Combustion

Turbine

587 30% 30.71 11.41 $0.121

[$0.110]

Renewables

Biopower

Biopower 3,390 83% 61.62 4.14 $0.097

[$0.093]

Biopower-

Stoker

85%

$0.096

Biopower-

Stoker

85% $0.101

Biopower 90% ~$0.080**

Geothermal

Geothermal 1,585 90% 75.44 5.00 $0.103

[$0.098]

CS

CS 2,860 72% 4.47 $0.050

CS 4,130 31% 180.02 11.00 $0.212

[$0.201]

CS 34% $0.170

284

CS 34% <$0.083

PV

PV 2,547 21% 135.81 $0.141

PV $0.220

PV $0.260

PV 5,185 22% 292.84 13.69 $0.313

[$0.299]

PV-

Distributed

$0.110

PV-

Distributed

$0.050

PV-

Distributed

$2.50/Wp

installed

cost

$0.075-

$0.010&

Wind

Onshore

Wind

1,896 35% 81.38 8.66 $0.100

[$0.091]

Onshore

Wind

1,076 46% $0.033

Onshore

Wind

916 49% $0.027

Onshore

Wind

42% $0.078

Onshore

Wind

33% $0.097

Onshore

Wind

1,630 38%-52%

(depending

on wind

class)

$0.05-

$0.043

Offshore

Wind

3,552 33% 154.36 9.31 $0.191

[$0.181]

285

Offshore

Wind

2,232 38%-52%

(depending

on wind

class)

$0.074-

$0.053

Table 8.2 2020 Cost Projections and Comparisons(Ref:5) +[] contain AEO estimates of busbar levelized cost of energy, i.e., without transmission related costs *The overnight cost includes the effects of technological learning but does not include other project

costs, which are reflected in the levelized cost estimate **Cost estimate is for 2015

&Interpolate between reported targets for 2015 and 2030

Estimates of the cost of energy from new generating facilities indicate that the

levelized costs of wind and other renewables are typically greater than the levelized cost of

energy from generators fueled by coal or natural gas. Table 8.3 shows estimates of the

national average levelized cost per MWh of new generation facilities constructed in 2012 in

the AEO2009 from the EIA by technology type.

Technology Capacity

Factor

Capital

Costs

Fixed

O&M

Variable

O&M /

Fuel

Costs

Transmission

Costs

Totala

Pulverized

Coal

85% 56.9 3.7 23.0 3.5 87.1

(58.1)

Conventional

Gas

Combined

Cycle

87% 20.0 1.6 55.2 3.8 80.7

(72.7)

Conventional

Combustion

Turbine

30% 36.0 4.6 80.1 11.0 131.7

(121.5)

CSP 31% 218.9 21.3 0.0 10.6 250.8

(166.1)

Wind 36% 73.0 9.8 0.0 8.3 91.1

(84.9)

286

Offshore

Wind

33% 171.3 29.2 0.0 9.0 209.5

(164.9)

PV 22% 342.7 6.2 0.0 13.2 362.2

(308.1)

Geothermal 90% 76.7 21.6 0.0 4.9 103.3

(66.8)

Biopower 83% 61.1 8.9 24.7 3.9 106.6

(84.0)

Table 8.3 Levelized Cost of Energy (in 2007 per MWh) for New Plants Coming Online in 2012(Ref:5) aNumbers for total LCOE from AEO2008 in parentheses

NOTES: Fuel cost imputed from AEO2009 Early Release model solution. AEO2009 Energy Prices (2007$/mmBtu) in 2012 are $1.91 for coal, $6.63 for natural gas, and $1.96 for biomass. O&M,

operating and maintenance

The levelized costs reported in the last column of this table include capital and finance

costs (including the cost of site development), variable O&M (including fuel), fixed O&M,

and the cost of transmission necessary to connect the new facility to the grid. The costs for

renewables do not reflect the renewable PTC. However, they do reflect the effects of state

RPS policies on the mix of wind resources and other renewables that are expected to come

on-line in response to those policies.

Table 8.3 shows that the three renewable technologies with the lowest cost of energy

are geothermal, biopower, and wind. Pulverized coal and conventional gas combined cycle

are less costly than all of the renewable technologies. According to the AEO2009 results, the

present $20 per MWh level of the PTC would basically close the gap between the levelized

costs of new wind and the LCOE of new coal plants, ignoring issues of relative

dispatchability. However, the costs of other technologies, particularly solar PV, concentrating

solar power, and offshore wind would remain higher than the other renewables, and additional

subsidies or set-asides in RPS policies would be necessary for these technologies to penetrate

the markets given existing costs.

Table 8.1 shows the levelized costs of renewable sources of generation from EIA

compared to those from the EERE Office at DOE; a recent report from Standard and Poor‘s

(S&P); the inputs to the American Wind Energy Association (AWEA) and NREL wind study;

and the Solar Energy Industry Association (SEIA). While the estimates in Table 8.2 include

the costs of installation and construction of transmission necessary to facilitate power

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delivery, Table 8.1 contains more generic estimates of costs relevant for today or for 2010, the

first year reported by many sources.

The snapshot of costs presented in this table does not reveal a number of important

factors that affect the estimates of levelized costs.

3.2 Wind Power Cost

Table 8.1 estimates of levelized cost of energy for onshore wind in 2010 range from

$0.029 to $0.10 per kWh, with EIA estimates falling in the middle at $0.069 per kWh. Most

estimates of the capital cost of new wind facilities are in the $1,750 per kW range, close to 10

percent lower than the EIA estimates of nearly $1,900 per kW.17 In addition, EIA estimates

that average capacity factors are somewhat lower than recent forecasts from EPRI.

A single national average estimate of the levelized cost of wind would not

communicate how wind costs depend on the capacity factor of new wind turbines, which in

turn depends on wind class. Figure 8.1 shows estimates from DOE of the amount of wind

capacity available at different levelized costs of energy, after netting out the PTC, and how

the cost of energy increases when moving from higher wind classes to lower wind classes and

from onshore sites to offshore sites.

Capacity factors differ across the country, as shown in the regional differences for

existing facilities in Figure 8.2. Capacity factors for wind have been improving over time due

to improvements in equipment performance, although this improvement may be offset as the

lower cost sites are taken.

The costs of offshore wind are likely much more uncertain as currently there are no

operating offshore facilities in the United States. As a result, we are several years from a point

where we can be more certain about what offshore wind generation costs would look like in

the future and how they would compare to the costs of other renewables.[5]

288

Figure 8.1 Projected 2010 costs of wind with production tax credit, $1,600/MW-mile

transmission, without integration costs of various wind classes(Ref:5)

Figure 8.2 Wind capacity factor in 2006 by region and vintage of wind facility (Ref:5)

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3.3 Solar Power Cost

3.3.1 Solar Photovoltaic Cost

The cost of energy produced using solar PV technology is a function of the efficiency

of the cell in producing electricity, which is typically 15 percent or less depending on the

material system and the total cost of installation. The capital cost of a PV cell module is

typically expressed as dollars per peak watt of production ($/Wp) and is determined by the

ratio of the module cost per unit of area ($/m2), divided by the maximum amount of electric

power delivered per unit of area (module efficiency multiplied by 1,000 W/m2, the standard

insolation rate at 25°C). In Figure 8.3, this cost per peak watt ($/Wp) is indicated by a series

of dashed straight lines having different slopes. Any combination of area cost and efficiency

on a given dashed line produces the same cost per peak watt indicated by the line labels. For

example, present singlecrystalline Si PV cells, with an efficiency of 10 percent and a cost of

$350/m2, have a module cost of $3.50/Wp. The area labeled I in Figure 8.3 represents the first

generation (Generation I) of solar cells and covers the range of module costs for these cells.

Areas labeled II and III in Figure 8.3 present the target module costs for Generation II

(thinfilm PV) and Generation III PV cells (advanced future structures) that are still in

development.

Table 8.3 PV Power Costs as Function of Module Efficiency and Cost(Ref:5) For PV or PEC to provide full level of C-free energy required for electricity and fuel-solar power cost

needs to be 2 cents/kWh($0.40/Wp)

290

In addition to module costs, a PV system also has costs associated with the

nonphotoactive parts of the system, called balance of system (BOS) costs, which are in the

range of $250/m2 for Generation I cells. The total cost of present PV systems is about $6/Wp.

Taking into account the cost of capital, interest rates, depreciation, system lifetime, and the

available annual solar irradiance integrated over the year (i.e., considering the diurnal cycle

and cloud cover, which reduce the peak power by a factor of about 1/5), the $/Wp figure of

merit can be converted to $/kWh by the following simple relationship: $1/Wp ~ $0.05/kWh.

This calculation leads to a present cost for grid-connected PV electricity of about $0.30/kWh.

The estimates of levelized energy costs for PV generally are distributed around the 30 cents

per kWh level, as shown in Table 8.2. The one exception was a 2004 SEIA study of levelized

costs that predicted the cost of energy from PV would fall to about $0.14/kWh by 2010, in the

absence of aggressive policies to promote the technology and to $0.08/kWh with such policies

in place.

Table 8.4 Fractional energy PV rooftop supply curves for three U.S. interconnections(Ref:5)

The costs of supplying electricity from rooftop PV installations will vary across

different locations and depend on factors such as the cost of land, options for orienting the

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installation (particularly on roof tops), and amount of energy produced in a particular location.

A study of the factors affecting supply curves for solar PV from rooftops used data on

building stock, roof top orientation, solar insolation, and other factors to construct relative

supply functions for solar PV for three U.S. electric interconnections as shown in Figure 8.4.

These supply curves relate to the system with the greatest yield, which results from the best

orientation in the most productive location. The supply curves show the higher costs of

producing electricity using solar PV in the east compared to the west, and the resource limits

in different locations.

Table 8.5 Price, customer cost after subsidy, and number of PV installations per year in

California under California Energy Commission incentive programs(Ref:5)

Largely as a result of state-level policies to promote the use of solar PV, the number of

installations is growing. As shown in Figure 8.5, in California, about 130 MW of the

cumulative PV capacity installed by 2007 was under incentive programs administered by the

California Energy Commission (CEC), more than double the total amount installed under

these programs as of 2004. This increase in capacity coincided with the 2006 launch of the

California Solar Initiative with a funding level of about $3.3 billion for subsidy payments

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available to new solar PV installations. Data from the CEC on total costs and costs to

customers of PV installations suggest that costs per kW for consumers rose slightly over this

period, a period of only slight increases in consumer costs per Watt of PV installations, due in

part to the subsidies afforded by the California policy. The CEC PV database contains

information on about one-third of the total amount of PV capacity installed in California.

Most of the solar PV installations appear to be taking place in regions that have

aggressive pro-solar policies. According to solarbuzz.com, in 2006 California accounted for

63 percent of the grid-connected PV market, and New Jersey, which also has an aggressive

policy to promote PV, accounted for 19 percent. In general, achieving grid parity, the point at

which electricity from PV is equal to or cheaper than power from the electricity grid, would

require a two to three times improvement for costs per kWh for the whole system (PV

modules, batteries, inverters and other system components) as well as for installation and

O&M costs.[5]

3.3.2 Concentrating Solar Power

According to the EIA AEO2009 model runs, the levelized cost of generating

electricity using concentrating solar power is higher than the cost of wind, but lower than the

cost of solar PV as shown in Table 8.3. If technological learning for CSP is a function of

aggregate investment, as assumed by the EIA, then the economics of concentrating solar

power may be improved by policies that promote investment in this technology and provide

incentives for using it to generate electricity. Twelve states have set asides for solar

technologies in their RPS policies, and in nine of those states, which include Arizona, New

Mexico, and Nevada, solar thermal generating technologies qualify for the set aside. The set

aside typically requires that a specific portion of the RPS target must be met with a solar

technology. Some policies also include a credit multiplier for generation from solar such that

solar-produced electricity creates RECs at a ratio of greater than 1 to 1.

Estimates of the levelized cost of central station concentrating solar power have

typically been around 16 cents per kWh at the busbar. EIA reported a much higher levelized

cost of 25 cents per kWh in the AEO2009 forecast, reflecting increases in 2007-2008 in raw

materials costs. With the 16 cent cost as a starting point, the supply curve for concentrating

solar power in the southwestern United States shown in Figure 8.6 displays costs at the

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busbar. The total supply curve in this graph is the horizontal sum of the individual supply

curves for different levels of solar resource intensity. This cost curve is very flat at levels of

around 16 cents per kWh.

Table 8.6 Supply curves describe the potential capacity and current busbar costs in terms of nominal levelized cost of energy (LCOE) of concentrating solar power(Ref:5)

Colored lines indicate different amounts of insolation measured in kilowatt-hours per square meter per day.

Figure 8.7 shows a supply curve that goes beyond the busbar and takes into account

the costs of incremental transmission necessary to deliver power to load. This curve is based

on assumptions about the portion of local load that could be served by solar power, the

availability of transmission to move power from generation sites to load centers, and the cost

of expanding transmission at $1,000 per MW-mile, lower than the $1,600 per MW-mile used

in DOE wind study. As shown in Figure 8.7, the resulting aggregate supply curve for this

region has a bit of slope to it, rising to approximately 18 cents per kWh at or near 180 GW of

generation. The basic message from the fairly flat slope of this supply curve is that at this time

the constraining factor for concentrating solar power supply is not the amount of the resource,

which is widely distributed and available abundantly in the southwest, but the costs of

developing that resource.

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Table 8.7 Concentrating solar power supply curve based on 20 percent availability of city peak demand and 20 percent availability of transmission capacity(Ref:5)

Colored lines indicate different amounts of insolation measured in kilowatt-hours per square meter per day

How this cost picture might change over time depends on future adoption of

renewable technologies. According to the WGA study, technology learning and economies of

scale in manufacturing and installation indicate that the levelized cost of energy in 2015 for a

parabolic trough technology would decrease by 50 percent with an increase of 4 GW of

installed capacity. The American Solar Energy Society (2007) anticipates further decreases in

levelized cost of another 25 percent between 2015 and 2030. Research and development is

also expected to have an important effect on costs. DOE‘s Office of EERE anticipates that

both capital costs and capacity factors for concentrating solar power could improve

dramatically through its R&D program for concentrating solar power, including storage

capacity and location of new systems in the most productive sites. Levelized costs of energy

at the busbar could decrease by 50 percent as soon as 2010, as shown in Table 8.1, though this

sounds quite optimistic.[5]

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3.4 Geothermal Power

Most of the economic U.S. hydrothermal resources are located in the western states.

Recent studies sponsored by the WGA identify approximately 13,600 MW of geothermal

potential in the west that could be developed economically, at busbar costs of up to 20 cents

per kWh in $2005, and 5,600 MW that reasonably could be developed by 2015 at costs of less

than 10 cents per kWh in $2005. Both cost estimates omit the renewable PTC that would

reduce the costs of developing these resources.

The WGA report and one conducted by the CEC were used to update the geothermal

supply curves in NEMS. The supply curves are limited to the 80 most likely sites to be

developed and extend to include 8 GW of new capacity. The NEMS geothermal supply curve,

shown in Figure 8.8, is similar to the supply curves found in the WGA report. According to

EIA, this supply curve, added to the NEMS model with the development of AEO2007, would

not capture all potentially economic geothermal resources, but it is an important start and

likely does capture the most economic resources available (Smith, 2006). Enhanced

geothermal systems (EGS) may offer greater opportunity in the future, but this technology is

too early in its development to reliably estimate its cost.

Figure 8.8 Geothermal Supply Curve (Ref:5)

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Existing geothermal generating capacity is closer to 2.5 GW. One hurdle to the

development of geothermal resources is that, like wind, they may be located far from load and

require new transmission lines to facilitate delivery. However, geothermal energy provides

constant, baseload power, which is an advantage over solar and wind.[5]

3.5 Biopower Cost

The costs of new biopower generation will depend on two important factors: the

generation technology and the cost of the fuel. In its NEMS model, EIA assumed that any

new biopower generation would use gasification with a combined cycle technology. These

generators have high capital costs and lower heat rates than a conventional boiler. However,

none of these types of biopower generators are now in commercial operation in the United

States, so it is difficult to know how the predicted costs would compare to actual experience.

In its Technology Assessment Guide, EPRI reported costs for both stoker and circulating

fluidized bed boilers, technologies that are well suited to the small scale of most biomass

plants and that can handle the fuel well EPRI. Capital costs, including interest during

construction and project specific costs, would be on the order of $3,400 per kW for each

technology with capacity factors of 85 percent. The levelized cost of energy would depend on

fuel costs, but the EPRI summer study reports a cost of approximately 9.6 cents per kWh for a

fluidized bed generator in 2010, which, assuming similar fuel costs of $34 per MWh (about

$2.70 per MMBtu of high heat value), would yield a levelized cost estimate for a stoker of 9.4

cents per kWh.

The costs of biomass fuels are also subject to uncertainty and potential volatility.

Much of the existing biopower generation occurs as self-generation at facilities that have a

ready source of fuel (such as pulping operations, paper mills, or forest products plants).

Expanding capabilities beyond these generators could involve shipping fuel, which can get

quite costly, which suggests that future biopower generation capability would be located close

to fuel sources and use more economical biomass fuels that are concentrated locally and do

not face substantial competition for their use.

This uncertainty about fuel costs is reflected in the different estimates of levelized

costs of biopower reported in Table 8.1. The fuel cost assumptions in the recent EIA forecasts

are substantially lower than those assumed by other sources, including EPRI and S&P. These

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lower costs are a major factor in the substantially lower levelized cost of energy in the EIA

numbers, which are about 85 percent lower than those provided by other sources.

One option for greater use of biomass fuel is co-firing the fuel with coal. Biomass co-

firing of up to 10 to 15 percent of fuel on a heat-input basis is a potential way of reducing the

CO2 emissions associated with coal-fired generation. The costs of making a coal-fired

generation facility available for co-firing could be substantial and involve large investments in

new fuel-handling equipment. Certain types of boiler configurations are more amenable than

others. Even though co-firing counts as renewable generation under many state RPS policies,

co-firing has not increased much in response to state RPS policies. Placing a cap on CO2

emissions may be necessary to drive coal plants to start making the investment necessary to

co-fire, and then only when the facility can identify an economic source of biomass fuel.[5]

3.6 Costs in 2020

Table 8.2 provides estimates from a few different sources of the levelized costs in

2020 of a range of different renewable technologies.

Table 8.2 also includes levelized cost of energy projections for a number of fossil

generation technologies based on the AEO2009 forecasts. These forecasts all include the

effect of learning on reducing capital costs, where the potential cost reductions from learning

vary across technologies. The projections from EIA also include the effect of moving along

the supply curve, such as when less accessible or lower quality wind resources are tapped for

wind electricity generation.

Table 8.2 shows a wide range of forecasts on the future of renewables costs. Most of

the forecasts envision renewables as continuing to be more costly than the EIA forecasts of

generation using conventional coal and gas technologies. The exceptions are the EERE

forecasts that envision substantial improvements in costs for concentrating solar power and

wind, and the SEIA forecast for solar PV. The differences between the program scenarios and

the baseline scenarios for the EERE forecasts show how full funding of renewable energy

research at DOE is expected to affect the future costs of renewable generation.

The different forecasting groups and scenarios also envision different rates of change

in levelized costs of energy over the next decade as shown in Figure 8.9 and Figure 8.10,

which compares forecasts of costs for 2020 and 2010 for several sources for four of the

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technologies. This graph shows that EERE and EPRI Summer Study forecasts envision large

decreases in costs of wind generation between 2010 and 2020 while the levelized costs in EIA

increase as a result of the cost increases inherent in tapping increasingly difficult sites, which

are not reflected in the estimates reported by the other studies.

Figure 8.9 Levelized Cost Estimate for Biomass and Solar PV Systems in 2010 and 2020(Ref:5)

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Differences in cost projections for wind turbines appear to be at least partly due to

differences in assumptions about capacity factors. The predictions from EERE are largely the

result of improvements in engineering resulting from research and development in this

technology and greater deployment.

Figure 8.10 Levelized Cost Estimate for Wind and Solar Thermal Systems in 2010 and 2020(Ref:5)

300

In the AEO projections, capacity factor predictions for 2020 are based on where the

wind resource would be developed in that year. The model presumably would have used up

the better sites for the least-cost development of resources in earlier years. Incorporating

resources found in higher wind class regions, as suggested in Figure 8.1, would likely lead to

lower capacity factors at new facilities after the better wind sites are taken.

Wind study assumed that, as a result of technology improvements, capacity factors

would improve between 2005 and 2030 by 10 to 18.7 percent, with faster rates of

improvement anticipated in the lower wind resource regions. Most of this improvement is

expected by 2020. This study also assumed that capital costs of new onshore wind generators

would fall by 5 percent between 2005 and 2020, and that new offshore wind generators would

see capital cost decreases of just over 10 percent during the same period. This study also

anticipated a marked decline in variable and fixed O&M costs between 2005 and 2020,

particularly for offshore installations.

Figure 8.11 Learning curve for PV production (Ref:5)

Concentrating solar power (CSP) and photovoltaics (PV) also have a wide range of

future cost predictions, representing the large degree of uncertainty and differing opinions

about how solar costs are likely to evolve over this decade. Solar PV is expected to remain

more expensive than CSP, although the SEIA forecasts dramatic improvement in the cost of

distributed PV, and EERE anticipates decreases in PV costs, too. EERE also projects potential

301

cost improvements for solar thermal projects. But unlike other forecasters, EERE predicts

substantially lower costs in the near term, suggesting differences in what goes into their cost

measures. The DOE Solar Energy Technologies Program report envisions declines in CSP

costs of about 50 percent from present levels, similar to the aggressive technology case from

the EPRI Summer study. Analysis of the evolution of PV costs suggests that the prices of PV

modules have followed a historical trend along the ―80 percent learning curve.‖ That is, for

every doubling of the total cumulative production of PV modules worldwide, the price has

dropped by approximately 20 percent. This trend is illustrated in Figure 8.11. The final data

point for 2003 corresponds to about $3.50/Wp and a cumulative PV capacity of 3 GW. A

major reduction in the projected future cost of PV modules depends on the introduction of

thin films, concentrator systems, and new technologies. The graph projects the path of future

costs under historical learning rates as well as with slower and faster rates of learning.[5]

302

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