Cigre-tb 483 Guidelines Design And Construction- Ac Offshore Substations- Wind Power Plants

483 Guidelines for the Design and Construction of AC Offshore Substations for Wind Power Plants

Working Group B3.26

December 2011

Guidelines for the Design and Construction of AC Offshore Substations for Wind Power Plants

Working Group B3.26

Copyright © 2011 “Ownership of a CIGRE publication, whether in paper form or on electronic support only infers right of use for personal purposes. Are prohibited, except if explicitly agreed by CIGRE, total or partial reproduction of the publication for use other than personal and transfer to a third party; hence circulation on any intranet or other company network is forbidden”. Disclaimer notice “CIGRE gives no warranty or assurance about the contents of this publication, nor does it accept any responsibility, as to the accuracy or exhaustiveness of the information. All implied warranties and conditions are excluded to the maximum extent permitted by law”.

ISBN: 978- 2- 85873- 174-9

WGB3.26 Guidelines for the Design and Construction of AC Offshore Substations for Wind Power Plants

Members J S Finn (Convener) J MacEnri (Secretary) R Szewczyk M Osborne Martijn de Ruiter I Tigchelaar A Neumann J C S Álvarez S E Rye M Ono K Taketa G Q Varela D Hackwell P Sandeberg A Jawad S G Dastidar G Nichol B Johnnerfelt R L King A J Hernandez Manchola T Boehme A Hjerling B J Tait

Corresponding Members UK Ireland Poland UK Netherlands Netherlands UK Spain Denmark Japan Japan Spain UK Sweden UK Belgium UK Sweden UK Venezuala UK Denmark UK

F Schettler H E Abdallah A F Alvarez H Koch K P Knol T Flindt T Kobayashi G Hentschel M Esken C Olerud L Cuen S Grattage R Brandstrup D Meadows J Berger

Germany USA Spain Germany Netherlands Denmark Japan Germany Germany Norway USA UK Denmark UK Germany

GUIDELINES FOR THE DESIGN AND CONSTRUCTION OF AC OFFSHORE SUBSTATIONS FOR WIND POWER PLANTS Table of Contents Page 13 19

Glossary of Abbreviations and Special Terms Executive Summary 0.

Introduction 0.1 AC Offshore Substation 0.2 Reading these Guidelines 0.3 Future Development Trends 0.3.1 Alternative Transmission Configurations 0.3.2 The Wider Long Term Picture: Offshore Grid 0.3.3 Relevance of this Brochure to Future Offshore Wind Power Plants

22 23 23 24 24 26 27

1.

Fundamental Considerations 1.1 Risk Management and Assessment Process 1.1.1 Risk Considerations which Affect the Single Line Diagram 1.1.2 Risk Considerations Affecting the Offshore Substation Physical Design 1.1.2.1 Basic Design Concept 1.1.2.1.1 Personnel Aspects 1.1.2.1.2 Assets 1.1.2.2 Operational Aspects 1.1.2.3 Commercial Aspects 1.2 Maintenance 1.2.1 Accessibility within the Substation of Equipment Needing Repair 1.2.2 Equipment Tagging 1.2.3 Diagnostics and Communication to Allow Focused Maintenance 1.2.4 FMECA and RCM in Maintenance Planning 1.2.5 Minimising the Need for Routine Maintenance 1.2.6 Over Designing to Reduce Unplanned Maintenance 1.2.7 Availability of Suitable Transport for Staff, Equipment and Spare Parts 1.2.8 Availability of Maintenance Specialists with Offshore Training 1.3 Verification and Certification 1.3.1 Engineering Design Studies and Design Basis 1.3.2 Structures, Foundation and System Fabrication and Components 1.3.3 Transportation and Installation Phase 1.3.4 Commissioning Onshore and (Hook Up and Commissioning) Offshore 1.3.5 Operation and Maintenance Phase

28 28 32 34

1

34 34 35 35 35 36 36 36 36 37 37 37 37 37 37 38 38 39 39 39

2.

System Considerations 2.1 Reliability, Availability and Maintenance (RAM) 2.1.1 Availability and Reliability 2.1.2 Redundancy 2.1.2.1 Inter‐array Cable Considerations 2.1.2.2 Export Cable Considerations 2.1.2.3 Interconnecting Wind Power Plants 2.1.3 Maintenance 2.2 Overloading Capability 2.2.1 Overloading in Normal Operation 2.2.2 Overloading in Case Of Failure 2.3 Substations Size and Number Required 2.4 Grid Code Compliance 2.4.1 Point of Common Coupling 2.4.2 Grid Code Requirements 2.5 Reactive Compensation and Voltage Control 2.5.1 Reactive Power Balance 2.5.2 Wind Turbine Contribution 2.5.3 Dynamic Voltage Response 2.5.3.1 Use of On Load Tap‐Changers (OLTC) 2.5.3.2 Use of Wind Turbine Reactive Capabilities 2.5.4 Fault Ride Through 2.5.5 Transformer Tap‐Changers 2.5.6 Flexible AC Transmission Systems 2.5.6.1 MSC and MSCDN 2.5.7 Harmonic Performance and Filters 2.5.8 Background Harmonics and Active Filters 2.6 Fault Level 2.6.1 What is the Limiting Factor on Fault Level? 2.6.2 Three Phase and Single Phase Levels 2.6.3 Make and Break Fault Levels 2.6.4 Infeed from Grid System 2.6.5 Infeed from Wind Turbines 2.6.6 Transformer Impedance choice (including Interaction with Reactive Design) 2.6.7 Consideration of Two or Three Winding Transformers 2.6.8 Effect of Cable Impedance and Stored Charge 2.6.9 Effect of External Faults 2.6.10 Operating Scenarios 2.7 General Substation Configuration 2.7.1 Choice of HV and MV Voltages 2.7.1.1 Medium Voltage Level 2.7.1.2 High Voltage Level 2.7.2 MV Busbar Layouts 2.7.3 HV Busbar Layouts 2.7.4 Power Transformer Connections 2.7.4.1 High Voltage Connections 2

40 40 40 41 43 45 45 46 46 46 47 47 49 49 50 52 53 54 56 56 56 59 60 61 62 69 71 72 72 72 73 73 74 75 75 76 77 77 78 79 79 80 82 83 87 87

2.7.4.2 Medium Voltage Connections 2.7.4.3 Internal Connections 2.7.5 Compensation or Filters Required on the Offshore Platform 2.8 Neutral Earthing 2.8.1 Alternatives for Neutral Point Earthing in the Collection Network (e.g. 36 kV) 2.8.2 Transmission Network (e.g. 145 kV) 2.8.3 Trapped Charges and Location of Circuit Breakers 2.9 Insulation Co‐ordination 2.9.1 Continuous Operating Voltage 2.9.2 Very Fast Front Transients 2.9.3 Fast Front Overvoltages 2.9.4 Slow Front Overvoltages 2.9.5 Temporary Overvoltages 2.9.6 Mitigation Strategies 2.9.7 Conclusions and Further Work 2.10 Flicker and Voltage fluctuations 2.10.1 Flicker 2.10.2 Levels of Flicker 2.10.3 Sources of Flicker 2.10.4 Mitigation of Flicker 2.10.5 Voltage Fluctuations 2.11 System Studies Required 2.11.1 Load Flow Study 2.11.2 Short Circuit Study 2.11.3 Harmonics Study 2.11.4 Insulation Coordination Study 2.11.5 Electromagnetic Transient Studies 2.11.6 HV Export Network Transient Studies 2.11.7 Flicker and Voltage Fluctuation Study 2.11.8 Dynamic Stability Study 2.11.9 Safety Earthing Study 2.11.10 Neutral Grounding Study 2.11.11 Protection Coordination Study 2.11.12 Electromagnetic Field (EMF) Study 3

Electrical Equipment Considerations 3.1 Introduction 3.1.1 Parameters Coming from the System Studies 3.1.2 Parameters Defined by the Operation and Maintenance Regime 3.1.3 Parameters Specific to the Type of Plant Itself 3.1.4 Important Items to Define to the Platform Supplier Associated with Regard to the Accommodation for the Equipment 3.2 MV Switchgear 3.2.1 Aspects of Specification which come from System Studies 3.2.1.1 Voltage and Current Ratings 3.2.1.2 Fault Level Ratings 3

88 88 88 89 90 92 92 94 94 94 95 95 100 101 103 103 103 104 104 105 105 106 106 106 107 107 107 107 108 108 109 109 109 109 110 110 110 110 110 110 110 110 110 111

3.2.1.3 Lightning Impulse Withstand Level (LIWL) and Surge Arrester Ratings 3.2.1.4 Configuration 3.2.1.5 Types of Circuit to be Switched 3.2.2 Aspects of Specification which come from Generic Operation and Maintenance Considerations 3.2.2.1 Operational Considerations 3.2.2.2 Maintenance Considerations 3.2.2.3 Condition Monitoring 3.2.2.4 Remote Monitoring 3.2.2.5 Spares 3.2.2.6 End of Life Replacement 3.2.3 Aspects of Specification which are Plant Specific 3.2.3.1 Environment 3.2.3.2 Vibration and Transport Forces 3.2.3.3 Special Technical Considerations 3.2.3.3.1 Circuit‐breakers 3.2.3.3.2 Interlocking 3.2.3.3.3 Accommodation for Cable Terminations 3.2.3.3.4 Specification – Other Factors 3.2.3.4 Physical and Interface Considerations 3.2.4 Specific Requirements for Rooms or Enclosures 3.3 Main Transformers and Reactors 3.3.1 Aspects of Specification which come from System Studies 3.3.1.1 Voltage Ratio 3.3.1.2 MVA Rating 3.3.1.3 Impedance 3.3.1.4 Tap Change Range and Tap Steps 3.3.1.5 LIWL Levels 3.3.1.6 Two or Three Windings 3.3.1.7 Neutral Earthing 3.3.2 Aspects of Specification which come from Generic Operation and Maintenance Considerations 3.3.2.1 Maintenance Strategies 3.3.2.2 Oil Management 3.3.2.3 SF6 Management 3.3.2.4 Condition Monitoring (CM) 3.3.2.5 Tapchanger 3.3.2.6 Bushings 3.3.2.7 Cooling 3.3.3 Repair and Replacement 3.3.3.1 Major Replacement Strategy 3.3.3.2 Spares 3.3.4 Aspects of Specification which are Plant Specific 3.3.4.1 Environment 3.3.4.1.1 Paint Finish, Main Tank/Radiators 3.3.4.1.2 Deterioration of Plastic Material by Ultra Violet Ray 4

111 111 112 113 113 113 114 114 114 114 114 114 116 117 117 118 119 119 120 121 124 125 125 125 125 126 126 126 127 127 127 128 130 131 132 132 133 134 134 135 135 135 135 136

3.3.4.1.3 Ambient Temperature Offshore 3.3.4.2 Vibration and Transport Forces 3.3.4.2.1 Forces Related to Land Transportation 3.3.4.2.2 Forces Related to Transport of Transformer Fully Assembled on The Platform to the Offshore Destination 3.3.4.2.3 Vibrations from Earthquakes, Wind Gusts and Waves 3.3.4.2.4 Vibrations from Transformer 3.3.4.3 Special Technical Considerations 3.3.4.3.1 Early Requirement for Substation Design Information 3.3.4.3.2 Need for Minimizing the Total Cost 3.3.4.3.3 Insulation Systems in Power Transformers 3.3.4.3.4 Alternative Solid Insulation (Aramid) for Higher Overload Capability and Extending the Life of Insulation System 3.3.4.3.5 Method of Cooling 3.3.4.3.6 Air cooled Radiators Tank Mounted or Separate 3.3.4.3.7 How to Remove a Single Radiator Element 3.3.4.4 Physical and Interface Considerations 3.3.5 Specific Requirements for Rooms or Enclosures 3.4 Earthing/Auxiliary Transformers 3.4.1 Aspects of Specification which come from System Studies 3.4.1.1 Connected to Transformer or Busbar 3.4.1.2 Required to Provide Auxiliary Power for Platform only or also for Turbine Strings 3.4.1.3 MVA Rating 3.4.1.4 Off Load or Off Circuit Tap Range 3.4.1.5 Impedance 3.4.1.6 Number Required 3.4.2 Aspects of Specification which come from Generic Operation and Maintenance Considerations 3.4.2.1 Oil Management 3.4.3 Repair and Replacement 3.4.3.1 Major Replacement strategy 3.4.3.2 Spares 3.4.4 Aspects of Specification which are Plant Specific 3.4.4.1 Special Technical Considerations 3.4.4.1.1 Insulation System 3.4.4.1.2 Oil Conservator Type or Sealed Type 3.4.4.1.3 Avoiding Excessive LV voltages during HV Earth Faults with Earthing/Auxiliary Transformers 3.4.4.2 Physical and Interface Considerations 3.4.5 Specific Requirements for Rooms or Enclosures 3.5 HV Switchgear 3.5.1 Aspects of Specification which come from System Studies 3.5.1.1 Voltage and Current Ratings 3.5.1.2 Fault Level Ratings 3.5.1.3 LIWL Level 5

136 136 137 137 139 140 141 141 141 143 151

152 153 155 155 156 158 158 158 159 159 159 159 160 160 160 160 160 160 161 161 161 161 162 163 164 165 165 165 165 165

3.5.1.4 Surge Arrester Ratings and Location 3.5.1.5 Configuration 3.5.1.6 Requirement for Point on Wave Switching 3.5.2 Aspects of Specification which come from Generic Operation and Maintenance Considerations 3.5.2.1 SF6 Management 3.5.2.2 Condition Monitoring 3.5.2.3 Operating Mechanism 3.5.3 Repair and Replacement 3.5.3.1 Major Replacement Strategy 3.5.3.2 Spares 3.5.4 Aspects of Specification which are Plant Specific 3.5.4.1 Environment 3.5.4.2 Vibration and Transport Forces 3.5.4.3 Special Technical Considerations 3.5.4.3.1 Selection of Type of Equipment 3.5.4.3.2 Design of Voltage Transformers 3.5.4.3.3 Location of Current Transformers 3.5.4.4 Physical and Interface Considerations 3.5.5 Specific Requirements for Rooms or Enclosures 3.6 Export and Inter Array Cables 3.6.1 Aspects of Specification which come from System Studies 3.6.2 Aspects of Specification which come from Generic Operation and Maintenance Considerations 3.6.2.1 Maintenance 3.6.2.2 Spares 3.6.2.3 Replacement Strategy 3.6.3 Aspects of Specification which are Plant Specific 3.6.3.1 Physical and Interface Considerations 3.6.4 Specific Requirements for Rooms or Enclosures 3.7 Site Tests and Commissioning 3.7.1 Overall Strategy 3.7.2 Pre‐energisation Onshore Commissioning 3.7.2.1 On Site High Voltage Tests 3.7.3 Pre‐energisation Offshore Commissioning 3.7.3.1 High Voltage Tests for Power Cables 3.7.4 Post Energisation Commissioning 3.7.4.1 Energisation of Sub‐Circuits 3.7.4.2 Post Energisation 3.7.4.3 Transformers 3.7.4.4 Switchgear 3.7.4.5 Export Cables 3.7.4.6 Control & Cable Marshalling Panels 3.7.4.7 Diesel Generator 3.7.4.8 Monitoring for Power Grid Connection Compliance Commissioning

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165 166 166 166 167 167 167 168 168 168 169 169 169 170 170 171 171 171 173 175 175 175 179 179 180 180 181 183 184 184 185 187 187 189 190 190 191 191 191 192 192 192 192

4.

Physical Considerations 4.1 General 4.1.1 About Design Considerations 4.1.2 History and Development of Offshore Platforms 4.2 Overall Health and Safety Aspects 4.2.1 Vessel Access‐Normal Activity Boat Access 4.2.2 Emergency Evacuation‐by Sea and/or by Air 4.2.3 Emergency Evacuation of Injured Persons/Stretcher Cases 4.2.4 General Safety Equipment 4.3 Fundamental Design Parameters 4.3.1 Functional Requirements 4.3.2 Environmental Conditions 4.3.3 Risk, Safety and Rules 4.3.4 Economics 4.3.5 Lifetime Operational Cost 4.4 Additional Design Inputs 4.4.1 Electrical Equipment 4.4.2 Topside Layout 4.4.2.1 General 4.4.2.2 HV Transformers 4.4.2.3 HV Switchgear and MV Switchgear 4.4.2.4 Tariff/Settlement Metering 4.4.2.5 Protection, Control (SCADA) and Telecommunication Panels 4.4.2.6 Auxiliary Generators 4.4.2.7 Accommodation and Emergency Shelter Rooms 4.4.2.8 LV Supplies 4.4.2.9 Workshop and Storage Rooms 4.4.2.10 Standby Supplies and Battery Rooms 4.4.2.11 Platform Cranes 4.4.2.12 Fire System 4.4.2.13 Helicopter Access 4.4.2.14 Security 4.4.3 Topside Lift 4.4.4 Ownership Boundaries and Separation 4.4.5 Reactive Compensation Plant 4.4.6 Future Expansion and Expandability 4.4.7 Spare Philosophy and Redundancy 4.4.8 Cable Deck 4.4.9 Routes for Walkways, Minimum Walkway Sizes 4.4.10 Fabrication Site 4.5 Development of Design 4.5.1 Design codes 4.5.2 Structural integrity 4.5.2.1 Truss vs. Stressed skin 4.5.3 General Arrangement 4.5.4 Material Handling 4.5.4.1 Construction Phase 7

194 194 194 196 197 198 198 199 199 199 200 201 202 203 203 203 203 203 204 204 205 205 205 206 206 206 207 207 207 207 208 208 208 210 210 210 210 211 211 212 212 213 217 219 221 223 223

4.5.4.2 Operating and Maintenance Phase 4.5.4.3 Material Handling Assessment 4.5.4.4 Manual Handling 4.5.4.5 Material Handling Aids 4.5.4.6 Pedestal Crane 4.5.4.7 Portable Devices 4.5.4.8 Decommissioning 4.5.4.9 Storage Areas 4.5.4.9.1 Typical Equipment Stored Onshore 4.5.4.9.2 Typical Items Store Offshore 4.5.4.9.3 Hazardous Substances 4.5.4.9.4 Extended Storage 4.5.5 Primary Access and Egress Systems 4.5.5.1 Helicopter Deck 4.5.5.2 Boat Landing 4.5.5.3 Ladder Access/Egress Systems 4.5.6 Emergency Response 4.5.7 Platform Auxiliary Systems 4.5.7.1 Diesel Generators 4.5.7.2 Inert Gas System, SF6 Gas Detection 4.5.7.3 Electrical Design i.e. Lighting and Small Power 4.5.7.4 Lightning Protection for the Platform 4.5.7.5 Earthing and Bonding 4.5.7.6 Ventilation and HVAC 4.5.7.7 Water Handling, Sea and Fresh Water 4.5.7.8 Drainage for Grey and Black Water 4.5.7.9 Auxiliary System Control and Monitoring 4.5.7.10 Public Address, Navigation and Aviation Aids, SCADA, UPS, Fire Detection & Alarm 4.5.7.11 Oil System and Containment‐Separator Tank 4.5.8 Corrosion Protection System 4.5.8.1 General 4.5.8.2 Topside 4.5.8.3 Substructure 4.5.8.4 Export Cables 4.5.9 Operation 4.5.9.1 Operational Modes 4.5.9.2 Operations with Personnel Offshore 4.5.9.3 Emergency Accommodation 4.5.9.4 Permanent Accommodation 4.5.9.5 The Separate Accommodation Module or Platform 4.5.9.6 Workshops 4.5.10 Commissioning of Plant Onshore 4.5.10.1 Platform Installation 4.5.10.1.1 Immediately after Installation 4.5.10.1.2 Initial Works 4.5.10.1.3 Removal of Transportation Aspects 8

224 224 225 225 226 228 228 229 229 229 231 232 232 232 234 235 235 237 238 239 240 240 240 240 241 242 242 242 242 243 243 243 243 244 244 244 245 245 245 246 246 246 247 247 247 248

4.5.10.1.4 Pre‐Commissioning 4.5.10.1.5 Telecommunications and Fibre Optics 4.5.10.1.6 Helideck 4.5.10.2 Energisation 4.6 Platform Concepts 4.6.1 Container Deck 4.6.1.1 General Description 4.6.1.2 Topside Fabrication 4.6.1.3 Interfaces 4.6.2 Semi Enclosed Topside 4.6.2.1 General Description 4.6.2.2 Topside Structure Fabrication 4.6.3 Fully Enclosed Topside 4.6.3.1 General Description 4.6.3.2 Topside Fabrication 4.7 Substructure 4.7.1 General 4.7.2 Monopile 4.7.3 Jacket 4.7.4 Gravity Based Foundation 4.7.5 Gravity Based Caisson Foundation 4.7.6 Self Elevating 4.8 Load out, Transportation and Installation 4.8.1 General 4.8.1.1 Overview of Available Lifting Vessels 4.8.1.2 Load Out 4.8.1.3 Sea Transportation 4.8.2 Hook Lift 4.8.3 Self Installing 4.8.4 Float Over 4.8.5 Installation Hook Up 4.8.5.1 Hook Up‐Traditional Jacket and Topside 4.8.6 Removal/Replacement of Large Plant Items 4.9 Fire and Explosion Design 4.9.1 Introduction 4.9.2 Fire and Explosion Hazards 4.9.3 Design Process 4.9.4 Fire and Smoke Detection 4.9.5 Active Fire Protection 4.9.6 Passive Fire Protection 4.9.7 Explosion Protection 5.

Substation Secondary Systems 5.1 Power Supplies 5.1.1 Statement of Requirements 5.1.2 LVAC Supplies 5.1.2.1 LVAC System Loads 9

249 249 250 250 251 251 251 251 252 252 252 252 252 252 253 253 253 255 257 259 261 262 265 265 265 266 267 268 269 271 272 272 272 273 273 273 274 275 276 277 278 279 279 279 280 280

5.1.2.2 Essential Loads 5.1.2.3 Non Essential Loads 5.1.3 LVAC System Operation 5.1.3.1 Normal LVAC Operation 5.1.3.2 Source of Auxiliary Supply 5.1.3.3 Separation of “Essential” and “Non Essential” Loads 5.1.3.4 Abnormal LVAC System Operation 5.1.4 Construction and Installation 5.1.4.1 LVAC Board Construction 5.1.4.2 LVAC Cable Systems and Routing 5.1.4.3 Protection, Control and Automation for the LVAC System 5.1.5 Black Start Capability 5.2 DC Supplies 5.2.1 LVDC Supplies 5.2.2 LVDC System Loads 5.2.2.1 LVDC Essential Maintained Loads 5.2.2.2 LVDC Operational Loads 5.2.3 LVDC System Operation 5.2.3.1 Normal LVDC Operation 5.2.3.2 Source of Auxiliary Supply for Battery Charging 5.2.3.3 Separation of “Essential” and “Non Essential” Loads 5.2.3.4 Abnormal LVDC System Operation 5.2.4 Construction and Installation 5.2.4.1 LVDC Board Construction 5.2.4.2 LVDC Cable Systems and Routing 5.2.4.3 Protection, Control and Automation for the LVDC System 5.2.5 The DC Supplies One Line Diagram 5.3 Protection 5.3.1 Statement of Requirements 5.3.2 Plant Protection 5.3.3 System Protection 5.3.4 Operation with Degraded Communications 5.3.5 Particular Technical and Protection Application Issues for Offshore Connections 5.3.5.1 General Requirements for Protection 5.3.5.2 Protection Technology 5.3.5.3 Protection Discrimination 5.3.5.4 Protection Testing 5.3.5.5 Test and Isolation Facilities 5.3.5.6 Grouping and Accommodation of Protection 5.3.5.7 Environmental Requirements 5.3.6 Wind Power Plant Networks 5.3.6.1 Main Protections 5.3.6.2 Back Up Protection 5.3.7 Unusual Settings Considerations 5.3.7.1 Normal Direction of Power Flow 5.3.7.2 Performance Similar to a Generator 10

280 283 283 283 284 284 284 285 285 286 286 287 291 291 291 292 293 294 294 294 294 294 295 295 296 296 296 298 298 298 298 299 299 299 299 300 300 300 301 301 301 302 302 303 303 303

5.3.7.3 Increased Potential for Low Fault Currents 5.3.7.4 Turbine Reactive Power Capabilities/Reactive Power Compensation 5.3.7.5 Fault Clearance Time Required at the PCC 5.3.7.6 Turbine Transformer Protection 5.3.8 Collection Array Protection 5.3.9 36 kV Busbar Protection 5.3.10 Platform Transformer Protection 5.3.11 Export Cable Protection 5.3.12 Breaker Fail Protection 5.3.13 Tripping Philosophy 5.3.14 Interface with Operational Intertrip Schemes 5.4 Control and Supervisory Control and Data Acquisition (SCADA) System Requirements 5.4.1 Introduction 5.4.2 Structure of the SCADA Systems 5.4.3 Functionality of Each System 5.4.3.1 Wind Turbine SCADA 5.4.3.2 Collection System Scada 5.4.3.3 Offshore Transmission System Operator SCADA 5.4.4 Interoperability of the Systems 5.4.5 High Speed Signalling 5.4.6 Operation with Degraded Communications 5.5 CCTV and Security Systems 5.5.1 Statement of Requirements 5.5.2 Alarm System 5.5.3 CCTV System 5.5.3.1 Personnel Surveillance 5.5.3.2 Security Surveillance 5.5.3.3 Plant Surveillance 5.6 Navigation Aids 5.6.1 Statement of Requirements 5.6.2 Navigation Aid Power Supplies 5.6.3 Lamps 5.6.4 Foghorn 5.7 Communications 5.7.1 Statement of Requirements 5.7.2 Communication Routes and Usage 5.7.2.1 Routes 5.7.2.2 Voice Communication 5.7.2.3 Data Communications 5.7.2.4 High Speed Communications 5.7.3 Interfaces 5.7.4 Communications Technology 5.7.4.1 SDH Communications using Optical Fibre Links 5.7.4.2 SDH Communications using Leased Satellite Links 5.7.4.3 SDH Communications using Point to Point Microwave Links 11

303 303 303 304 304 306 308 308 309 309 309 310 310 311 319 319 319 319 321 321 321 322 322 322 322 322 323 323 323 323 323 324 324 324 324 325 325 325 326 326 326 327 327 327 328

5.7.4.4 Radio Systems for Voice Communications 5.7.4.5 Back Up Satellite Phone or Mobile Phone Systems for Voice Communications 5.7.5 Communications System Monitoring and Maintenance 5.8 Equipment Accommodation and Environmental Management 5.8.1 Statement of Requirements 5.8.2 Constructional Requirements and Equipment Accommodation 5.9 Maintenance Management 5.10 Metering

328 328 329 334 334 334 335 335

6.

Areas for Further Consideration

337

7.

Concluding Remarks

340

References Appendix 1 Example of the Use of Weibull Distribution Appendix 2 Failure Modes, Effects and Criticality Analysis (FMECA) Appendix 3 Power Transmission with Long AC Submarine Cables Appendix 4 Codes and Standards per Discipline

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341 344 350 354 364

Glossary of Abbreviations and Special Terms This section comprises of two tables. The first shows abbreviations which have been used throughout this brochure and the second shows words and phrases which may have special meaning within this brochure.

Table of Abbreviations Used Abbreviation ABEX AC AFP ALARP ASVC BIL BSL CAPEX CB CBM CCTV CM CO2 COG COV CT DC DEF DFIG DNV DOC DT DTS EAT EMF EMT EMTP ES FACTS FC FCG FEED FEM FMEA FMECA FOC FRA

Full Text Abandonment Expenditure Alternating Current Active Fire Protection As Low As Reasonably Practicable Advanced Static VAr Compensator Basic (Lightning Impulse) Insulation Level Basic Switching Impulse Insulation Level Capital Expenditure Circuit Breaker Condition Based Maintenance Closed Circuit Television Condition Monitoring Carbon Dioxide Centre Of Gravity Continuous Operating Voltage Current Transformer Direct Current Directional Earth Fault Doubly Fed Induction Generator Det Norske Veritas Directional Overcurrent Definite Time Distributed Temperature Sensing Earthing/Auxiliary Transformer Electromagnetic Field Electromagnetic Transient Electromagnetic Transient Program Earth Switch Flexible Alternating Current Transmission Systems Fixed Capacitor Full Converter Generator Front End Engineering and Design Finite Element Method Failure Mode and Effect Analysis Failure Modes,Effects and Criticality Analysis Fibre Optic Cable Frequency Response Analysis 13

FRT FTA GCB GIB GIS GIT GPS GSC GTO H2 HAZID HAZOP HSE HSOC HV HVAC HVDC IEC IDMT IED IGBT IGCT IMO IP ISO LAN LCC LIWV LV LVAC LVDC MCB MCCB MCS MSC OHVS MSCDN MSR MV NMI NUI O&M OFAF OFTO OLTC ONAF

Fault Ride Through Fault Tree Analysis Gas Circuit Breaker Gas Insulated Busbar (busduct) Gas Insulated Switchgear Gas Insulated Transformer Global Positioning System Grid Side Converter Gate Turn Off (thyristor) Hydrogen Hazard Identification Hazard and Operability Study Health Safety and Environmental High Set Overcurrent High Voltage Heat Ventilation and Air Conditioning High Voltage Direct Current International Electrotechnical Commission Inverse Definite Minimum Time Intelligent Electronic Device Insulated Gate Bipolar Transistor Integrated Gate Commutated Thyristors International Maritime Organization Internet Protocol International Standardization Organization Local Area Network Life Cycle Cost Lightning Impulse Withstand Voltage Low Voltage Low Voltage Alternating Current Low Voltage Direct Current Miniature Circuit Breaker Moulded Case Circuit Breaker Metal Clad Switchgear Mechanically Switched Capacitor Offshore High Voltage Substation Mechanically Switched Capacitor with Damping Network Mechanically Switched Reactor Medium Voltage Normally Manned Installation Normally Unmanned Installation Operation And Maintenance Oil Forced Air Forced Offshore Transmission Operator On Load Tap Changer Oil Natural Air Forced 14

ONAN OPEX OTSO PCC PFP QRA RCM REF RMIS RMS RSC RTU SCADA SCIG SDH SF6 SIWL SIWV SLGF SO SOLAS STATCOM SVC SWATH SWL TCR TEMPSC TO TOV TSC TSO VCB VLAN VLF VSC VT WTG XLPE

Oil Natural Air Natural Operational Expenditure Offshore Transmission System Operator Point of Common Coupling (grid connection) Passive Fire Protection Qualitative Risk Assessment Reliability Centred Maintenance Restricted Earth Fault Risk Management Information System Root Mean Square Rotor Side Converter Remote Terminal Unit Supervisory Control And Data Acquisition Squirrel Cage Induction Generator Synchronous Digital Hierarchy Sulphur hexafluoride Switching Impulse Withstand Level Switching Impulse Withstand Voltage Single Line to Ground Fault System operator Safety Of Life At Sea Static Compensator (usually VSC type) Static VAr Compensator Small Waterplane Area Twin Hull Safe Working Limit Thyristor Controlled Reactor Totally Enclosed Motor Propelled Survival Craft Transmission Owner Temporary Overvoltage Thyristor Switched Capacitor Transmission System Operator Vacuum Circuit Breaker Virtual Local Area Network Very Low Frequency Voltage Source Converter Voltage Transformer Wind Turbine Generator Cross‐Linked Polyethylene

15

Table of Special Terms as Used in this Brochure Word or Phrase Accommodation area

Definition Space used for cabins, offices, lavatories, galley, etc. Service spaces and control stations may be included within the accommodation space Active Fire Protection Fire fighting system starting action by means of signal from surveillance i.e. heat, smoke detectors etc. Corrosion Protection Preventive action to avoid corrosion on offshore installations. Davit Crane A crane that reaches over the side of an installation used for carrying cargo and/or personnel. Developer/Owner/Operator The organization responsible for developing, owning or operating a whole or part of a wind power plant. In some cases this may be the same organization who does all three functions whilst in other circumstances this could be three separate organizations. Emergency response Action to safeguard the health and safety of persons on or near the offshore installation. This usually includes all actions through alarm, escape, muster, communications and control, evacuation and rescue. Escape routes Clearly identified routes for egress from a room or enclosed space in the event of a dangerous incident. Export cable A cable connecting the offshore substation to the system onshore used to export the power from the wind power plant. Fatigue Degradation of material caused by cyclic stress. Float‐over Type of installation method of substation topsides. Foundation The part of an offshore substation structure which secures the substation to the sea bed. Gravity Based Foundation A static stable foundation standing on sea bottom and ballasted by heavy stone and rock and own weight Grid Code A set of rules and regulations governing the operation, maintenance and development of a transmission system Hazardous Areas Areas on the offshore substation which may be subject to hazardous conditions. These hazards may arise from fire risks from hydrocarbon materials or from the storage of materials which may harmful to health. Heli‐deck or heli‐pad A deck specifically designed for the safe landing and taking off of helicopters. Heli‐hoist An area on the offshore platform which has been specifically designed for the safe transfer of materials or, in emergency conditions, personnel from a helicopter by means of a winch line. Integrity Ability of the installation to remain safe and stable to safeguard personnel and facilities on board. Integrity is generally taken to mean structural soundness, strength and stability required to fulfil these actions. Inter array cable A cable used to collect the power from the individual wind turbine generator step up transformers (usually 36 kV) J‐tube A J‐shaped tube mounted inside or outside the substructure in 16

Lay down area Material / Mechanical/ Equip. handling Monopile Muster Point Normally Manned Installation Normally Unmanned Installation Offshore Installation

Offshore Substation

Passive Fire Protection

Physical Consideration

Platform Platform Auxiliary Systems Platform Installation Prevailing Wind Self Installing

Semisubmersible vessel Splash zone Stressed skin

order to guide a cable between the seabed and cable deck on the topsides. The purpose is to protect the cable from environmental loads (wave, current, wind etc.) Special area designed for on/offloading of various goods, supply and spare parts. The process by which the landing and movement of materials or equipment can be safely and effectively carried out on the offshore substation. A single large pile made from steel which is driven into the seabed to support a structure. A place where everyone on the platform is ordered to go when there is an emergency situation. An installation which is normally manned continuously during its operation. An installation which is normally not manned during its operation This usually refers to the complete wind power plant which is located offshore, consisting of the wind turbine generators, the offshore substation and the interconnecting cabling. An offshore substation is a substation designed for the purpose of transforming the voltage from the collection voltage to a suitable transmission voltage for efficiently exporting the power to the onshore network. A coating, cladding, or free standing system like e.g. a rated fire wall that provides thermal protection in the event of a fire and that requires no manual, mechanical or other means of action. In this brochure physical considerations are those aspects of the design and installation concerned with the layout, structure, transport and installation of the offshore substation. This is the steel structure on which the offshore substation equipment is mounted. Systems not directly a part of the electrical MV/HV systems (substation) but for the platform itself. This is the process of installing the platform complete with the substation equipment onto the foundation located in the sea bed. Dominating wind direction with the highest probability of occurrence. A self installing platform is one which may incorporate its own foundation or be able to be installed onto a prepared foundation by means of jacking the platform using jacking legs which are part of the platform. A ship which can ballast its own cargo area below sea level The part of the installation that is periodically exposed to sea water by means of waves and tidal variations. A stressed skin design is one in which the covering or skin also 17

Sub structure Topside Truss brace

Utility Area

provides an integral part of the structural strength. Structure that carries the topside, e.g. jacket or monopile Structure or building placed on a sub structure to provide housing of the HV equipment included for an offshore substation. A truss usually consists of one or more triangular units constructed with straight members which come together at nodes. With a truss braced design the structural strength is totally in the frame and the covering or skin is not required to provide any structural strength. Areas for auxiliary power supply, power conversion, batteries, LV switchboards, workshops, storage areas and general machinery.

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Executive Summary Present developments show a growing interest in renewable and clean energy sources. Rising temperatures, rising sea level and increasing occurrence of extreme weather conditions have led people to believe we need to change our ways. European countries have committed themselves to decrease emissions and to invest in renewable energy. By 2020, 20% of the energy in Europe has to be produced by renewable sources and the goal is set for 20% reduction of greenhouse gases. Elsewhere in the world similar goals are being pursued. A popular renewable energy source is wind. Worldwide hundreds of gigawatts of wind power have been installed successfully on land. Recently the wind energy industry has moved offshore where the winds are stronger and more consistent and more space is available. The North Sea is a particularly attractive area where water depth is limited and wind energy is abundant, but also the Baltic Sea and shallow coastal areas near the US and China are being considered. These new offshore wind power plant developments have led to the need for offshore high voltage substation platforms. Offshore substations have been previously constructed and installed for the oil and gas industry but there are some major differences between the oil and gas substations and those required for wind power plants both from the technical and economic view points. The wind power plant substations involve much higher power levels, of the order of 500MVA with a number of large power transformers and from the economic view point there is not as much money available to solve the problems as there generally is in the oil and gas sector. Furthermore, because of the intermittency of the energy source a completely new approach is required to the redundancy requirements compared to that which is the norm for onshore substations (N‐1 etc,). This means that before beginning the design process there are some fundamental policy decisions which need to be made by the Developers/Utilities and these involve risk assessment, maintenance policy and certification. These fundamental considerations are addressed in the first Chapter of the brochure. Arising from these fundamental considerations a policy for the total development of the offshore wind power plant should be established which will provide the framework for the design of the offshore substation. When this framework is firmly established the design work for the offshore substation can begin. However, with the unusual conditions such as long submarine cables with significant generation of reactive power, necessity to comply with Grid Codes, the development of the single line diagram for the wind power plant will usually involve looking at the overall system. The next Chapter describes the offshore AC substation design issues that involve more than one component or even the complete system. This involves reliability, availability and maintenance issues as well as system properties like total substation power, reactive power management, applied voltages and harmonics. Focus is on the electrical system. The purpose is not to provide standards nor solutions for the design issues, but to provide guidance in the considerations that need to be taken into account when designing an offshore substation. The Chapter concludes by including a list of the studies which will normally be required. The completed studies will lead to the final single line diagram and provide some of the key parameters for the primary plant to be installed on the offshore substation. Chapter 3 gives guidance on the writing of the technical specifications for the main electrical equipment to be located on the offshore substation. When considering the specification aspects for equipment these can generally be divided into four main sub groups as follows:‐ 19

‐ Parameters coming from the system studies These parameters are technical requirements such as the short circuit level, full load current, lightning impulse withstand level, transformer impedance etc. ‐ Parameters defined by the operation and maintenance regime These parameters are the requirements for modularity, any requirements for condition monitoring, need for special tools e.g. tap changer removal tools. ‐ Parameters specific to the type of plant itself These are items specific to the type of plant itself and could cover environmental considerations, vibration and transport forces, special technical considerations and physical and interface requirements. ‐ Important items to define to the platform supplier associated with regard to the accommodation for the equipment It may well be necessary for the equipment supplier to define to the platform supplier specific requirements for the room in which the equipment is to be accommodated. The next Chapter 4 explains design considerations with respect to the High Voltage AC Substation platforms and their associated substructures and foundations including environmental impacts, remote location, maintenance issues, access management, etc. Commencing with an overview of the platforms and the different technologies used today followed by a brief discussion of the most important parameters that need to be considered. It continues with one of the most important subjects when working offshore, i.e. Health Safety and Environment (HSE). HSE must be considered in all aspects of the substation and from the very beginning permeate the thinking and be part of the fundamental design strategy. The boundary conditions for the design are then set. These are typically parameters or inputs that are external to the design and cannot be easily changed, e.g. local and global legislations, site location and ambient conditions such as temperature, currents, wave heights, wind speed etc. Unlike boundary conditions that are to be considered as more or less fixed, the next section discusses parts or aspects of the transmission system that will have a significant influence on the platform design but may be subject to discussion and/or iteration. Examples of such equipment or parameters are electrical components and secondary systems, substructure interface, cable installations and installation programme, commissioning tests, etc. Having “set the scene” in the previous sections, the actual design philosophies, design parameters and issues within its own discipline that will have a major influence on the final platform design are discussed. Aspects related to structural integrity, what to consider for the general arrangement layout, primary access and egress systems, emergency response and platform auxiliary systems are considered. Furthermore, a comparison of stressed skin vs. clad truss braced design is provided and corrosion protection, operation and installation and commissioning of plant onshore are discussed.

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This leads on to different types of platform concepts like container deck, semi enclosed and fully enclosed topsides. To some extent pros and cons of self installing concepts like floating and jack‐up solutions are discussed and compared. Having thoroughly dealt with the topside, the next section covers what is underneath, i.e. the substructure. Different concepts are compared and pros and cons discussed. Aspects of load out, transportation, installation and hook up and the consequences these may imply on the overall design of the topside and substructure are covered. A brief overview of the available lifting vessels is included for information. Finally, an assessment of fire and explosion design, together with fire detection/alarm and passive/active fire suppression is presented. Chapter 5 deals with the substation secondary systems which are those systems which provide the functionality necessary to „ ensure safety of personnel engaged in operation of the substation and associated systems „ permit operation of the substation primary circuits. „ monitor the performance of the installation „ detect and manage abnormal conditions on the system and in primary equipment. „ manage the environment in which the equipment operates. The detailed functionality depends on the specific installation and the way in which it is operated. The guidelines set out in this Chapter assume that the offshore substation is classified as a normally unmanned (unattended) installation but allows for the use of the substation as a marshalling point for staff involved in maintenance of the substation and associated systems. It also looks at how the secondary equipment requirements differ from what we are all familiar with in onshore substations. This includes how the normal aspects such as protection, control and metering are addressed as well as those new items such as CCTV, navigation aids, aeronautical aids which are not normally associated with onshore substations. The final Chapter briefly summarises the work which is now required, from a new Working Group, to address the aspects associated with AC collector substations for wind power plants which will be connected by HVDC links which was expressly excluded from the content of this brochure. It is sincerely hoped by the whole team involved in the preparation of this brochure that this document will assist all Utilities, Developers and Contractors to achieve satisfactory solutions for the offshore substations required for their wind power plants.

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0. Introduction

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The Stone Age did not end because people ran out of stone and the age of fossil fuels will not end because we run out of fossil fuels, it will end sooner. This is coupled with the recognised global dependence on the finite energy resource which is fossil fuel and that alternative and sustainable sources of electrical generation are required. Present developments show a growing interest in renewable and clean energy sources. Rising temperatures, rising sea level and increasing occurrence of extreme weather conditions have led people to believe we need to change our ways. European countries have committed themselves to decrease emissions and to invest in renewable energy. By 2020, 20% of the energy in Europe has to be produced by renewable sources and the goal is set for 20% reduction of greenhouse gases. Elsewhere in the world similar goals are being pursued. A popular renewable energy source is wind. Worldwide hundreds of gigawatts of wind power have been installed successfully on land. Recently the wind energy industry has moved offshore where wind speeds are generally higher than on land, larger machines with higher energy yields can be installed, and where constraints from land area and planning are reduced. The North Sea is a particularly attractive area where water depth is limited and wind is abundant, but also the Baltic Sea and shallow coastal areas near the US and China are being considered. The development of worldwide offshore wind power plant capacity is shown in Figure 0‐1.

Cumulative capacity (MW)

Wind Farm Capacity (MW)

0 2012

Year

Figure 0‐1. Worldwide development of offshore wind power plant capacity The distance from shore of the new offshore wind power plant developments has led to the need for offshore high voltage AC substation platforms. A number of these platforms have already been installed and many more are being designed or constructed. This brochure presents guidelines for the design of offshore AC substations, based on the lessons learned 22

so far. It is not our goal to provide answers to all the questions that one might have on offshore AC substations, but to discuss the specific issues encountered when building an offshore substation and point out potential problems and their respective solutions.

0.1

AC Offshore Substation

In order to be clear on the scope of this brochure this section presents a short description of a typical offshore wind power plant. (The figures and numbers used are typical for current wind power plants under development, but will be discussed further in this brochure and may not represent the optimal configuration. This is an example.) Most wind power plants existing or under development consist of between 40‐300 turbines. These turbines will each generate a maximum of about 3 to 5 MW, though these numbers are subject to rapid change as development progresses. The turbines all produce energy at a nominal voltage of 36 kV (after internal transformation) and together these turbines form the wind power plant. Strings of MV cables with up to 10 turbines connected to them form an (mostly radial) inter array cable network. Wind power plants located further (>10 km) from shore, will normally be equipped with one or more offshore HV substations where a transformation from 36 kV to 132, 150 or 220 kV takes place for more efficient transmission to shore. This AC offshore substation (also referred to as Offshore HV Substation, OHVS) is the subject of this brochure.

Figure 0‐2. Typical layout of an offshore wind power plant

0.2

Reading these Guidelines

This brochure gives guidelines for the design of AC offshore substations as part of an AC interconnection to shore. The design of the substation will have to be considered in the context of the total system including the cable, the wind power plant itself and the onshore grid situation. This brochure however restricts itself to the offshore substation. Section 2 of the brochure describes system aspects. These are considerations that involve more than one piece of equipment, the whole substation or even the complete system. In this chapter issues concerning interaction with other parts of the wind power plant system (outside the substation) are considered as these may have an impact on the substation design and single line diagram. The challenges encountered when designing an offshore substation can be divided into three main areas; the primary equipment, secondary equipment and layout, civil works and HSE considerations (physical). The primary electrical equipment resembles the equipment in an onshore substation, but will require some adaptation. Section 3 elaborates on the choice of equipment, the specific

23

adaptations needed for the harsh offshore environment and the modular approach required to minimise the maintenance intervention time. The physical aspects (i.e. issues related to the physical environment an offshore platform is exposed to) are described in Section 4. A lot of knowledge about this is already present in the offshore oil and gas industry, but recent experience shows that not all that applies to oil and gas can be adopted for offshore substations for wind power plants. This section describes the challenges of building a substation offshore and the precautions taken to protect people and equipment. Offshore substations demand more from their secondary equipment in terms of reliability. When communications are lost or emergency power does not function, there is no easy way to go and check on the substation. Secondary equipment is therefore a vital part of the offshore platform and must be well designed. Section 5 gives some design guidelines and considerations to support the design of a robust secondary system. It is intended that this brochure will provide useful guidelines to anyone designing and constructing AC offshore substations for wind power plants and thereby support the development of a successful offshore infrastructure and hence the transition to a cleaner energy supply.

0.3

Future Development Trends

0.3.1

Alternative Transmission Configurations

When wind power plants are located further offshore, different configurations from the one described in Figure 0‐2 are considered. For longer cable route lengths, HVDC transmission becomes a viable option1 [1]. The particular cable length above which HVDC transmission becomes more economic than HVAC transmission is called the AC/DC break‐even point. (Currently, this break‐even point is between 50 and 100 km depending on wind power plant size and several other factors). For wind power plants above around 200 MW in size, the HVDC option tends to have the fewest cables connecting the wind power plant to shore. Therefore for long distances, HVDC will be cheaper in terms of investment costs (see Figure 0‐3).

Figure 0‐3. Investment costs of AC and DC compared 1

Koch, H. and Retzmann, D. Connecting large offshore wind power plants to the transmission network. in Transmission and Distribution Conference and Exposition, IEEE PES, pp 1‐5, 19‐22 April 2010. 2010.

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A similar picture can be drawn when losses and transmission capacity are considered. HVDC converters have high losses, but the cable losses are only the resistive losses which are low compared to the total losses (capacitive and resistive) encountered in long AC cables. Especially for higher voltages (which may seem attractive because of lower current and thus lower losses) AC cables produce a lot of reactive power, limiting the active power transport capacity. Projects with 100km cable lengths have solved this with large compensation stations onshore or with equipment on an offshore substation on the way to shore. The choice between AC and DC transmission depends on a number of factors, such as distance from shore, nominal power of the wind power plant (cluster) and local grid situation. The comparison changes all the time due to the development of HVDC and cable technology. The break even distance is also influenced by the price of copper and aluminium as it is the cost of cables that defines the slope of the curves in the diagram above. Currently, one might expect the break‐even distance between AC and DC transmission to be between 50 and 120 km. Some innovative solutions are being considered such as Gas Insulated Lines2 [2] or High Temperature Superconducting Cables3 [3], which could provide bulk power transmission over large distances. It is not the purpose of this brochure to discuss these techniques in detail, nevertheless a short explanation is included. For bulk transmission over large distance, it is expected that multiple wind power plants or large wind power plants with multiple substations are connected to one offshore power hub. The wind power plants still have their individual AC substations, but instead of a direct cable connection to shore, these are connected to the offshore power hub, where the AC/DC converter is located. The power is transmitted to shore using HVDC and there will be an onshore converter station to convert back to AC.

Figure 0‐4. Possible configuration with HVDC transmission In the future an alternative solution to HVDC connection could possibly be Gas Insulated Lines, which require gas filled pipes that are buried under the seabed or installed in tunnels. Alternatively, High Temperature Superconducting Cables (HTSC) could be used. HTSC requires cooling stations to maintain superconductivity, but will save an offshore transformer (high voltage transmission is not required because I2R losses are negligible).

2 APPLICATION OF LONG HIGH CAPACITY GAS INSULATED LINES IN STRUCTURES – H.Koch – 42nd CIGRE Session 2008 3 OPTIMIZING CABLE LAYOUT FOR LONG LENGTH HIGH TEMPERATURE SUPERCONDUCTING CABLE SYSTEMS – A.Geschiere – 42nd CIGRE Session 2008

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0.3.2

The Wider Long Term Picture: Offshore Grid

A growing number of interconnectors and a need to efficiently transmit energy from offshore wind power plants to the shore, have lead to numerous ideas about offshore grids (Figure 0‐5 to Figure 0‐8 show just a few examples). Offshore grids may help us to efficiently transport wind power to shore and support optimal use of offshore infrastructure. The integration of North Sea energy markets will enable higher amounts of wind power to be incorporated in the electricity network.

Figure 0‐5. Econcern's offshore grid:

Figure 0‐6. TenneT vision on offshore grid

Poseidon

Figure 0‐7. EWEA 20 year offshore network

Figure 0‐8. Greenpeace offshore

development plan

grid

The first steps towards the offshore grid are already completed in the form of submarine interconnectors and wind power plant connections. A possible next step is to combine these two and connect wind power plants directly to interconnectors. The business case for these wind interconnectors depends on the distance between the wind power plants and shore and the expected congestion rent of the interconnection. Technically, this configuration is feasible using HVDC VSC technology. In addition to the technical challenges of developing a HVDC breaker for example, the alignment of regulatory and legal frameworks is necessary. This non technical issue is especially challenging when more than two countries are involved, therefore it can be expected that an offshore grid will be primarily based on 26

bilateral connections. One could also argue that (large) connections between wind power plant nodes are generally not efficient because main transport flows will be between production and load centres and not between production facilities4 [4]. It is expected that the new Working Groups B4.56 to B4.60 will provide more detailed discussions of issues related to HVDC Grids.

0.3.3 Relevance of this Brochure to Future Offshore Wind Power Plants At present most of the future developments being considered still utilise an AC offshore substation as a collector substation. Consequently, much of the content of this brochure will also be valid for these future systems. However, some aspects will need to be reconsidered in the revised role of collector substations for HVDC transmission such as the protection philosophy and reactive compensation considerations. It is proposed that the adaptation of these guidelines to suit AC collector substations be the work of a future CIGRE Working Group.

4 LONG‐TERM GRID PLANNING IN THE NETHERLANDS – M.v.d.Meijden – 43th CIGRE Session 2010

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1. Fundamental Considerations This section introduces key considerations of risk, maintenance and certification which will produce a significant impact upon the design of the substation.

1.1 Risk Management and Assessment Process It is essential to continuously identify, assess, and mitigate risks by using effective risk management and assessment processes in the offshore substation design. This will assist in the development of the Health and Safety strategy to be applied by the Owner/Operator (see Section 4.2). To do so, it is recommended that a risk management best practices process be applied which utilizes logical and systematic methods for: • Communication and consultation throughout the process • Establishing the context • Identifying, analyzing, evaluating and treating risk associated with any activity, process, function, project, product, service or asset • Monitoring and reviewing risks • Recording and reporting the results appropriately Once an effective risk management and assessment process has been implemented, all substation design risks can be taken into consideration and fully support the ability to: • View risks as they truly impact all areas of the substation design • Apply a step 1‐5 risk assessment process of: - Identification (careful examination of what could cause harm) - Impact analysis (qualitative methods where consequence and probability are determined purely qualitatively and quantitative methods where consequence and probability are fully quantified, e.g. by a Quantitative Risk Assessment (QRA) - Evaluation, development and implementing risk reduction methods - Documentation controls - Reviewing and reassessment of risks for applying improvement • Provide access to critical risk data that represents a substations ‘risk‐profile’ including the more evasive supply chain threats within its daily operations • Apply risk reduction methods that reduce the probability of occurrence to zero and eliminates the incident, lowers the probability of occurrence to prevent the incident, limits the extent and duration of events to control the incident and reduces the consequences to mitigate its effects • Implement an automated Risk Management Information System (RMIS) tool that : - Captures and manages substation design risks - Produces standard measurement reports - Provides risk maps and matrixes - Provides advanced risk analysis capability

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- Verifies that the risk reduction strategies used are efficient, cost effective, and the right ones - Validates and reports that the risks are decreasing significantly • Train staff on risk management processes which will improve the understanding and practice of risk management including the essential skills needed to effectively identify and manage substation risks proactively One method which may be required to fulfil national requirements is to perform a hazard identification study (HAZID) for the substation. The primary objective of this HAZID is to identify specific potential hazards, operability problems, environmental considerations, impacts associated with the design concept and, where appropriate, to recommend actions to resolve findings that are identified. The objective of the HAZID is to obtain a complete list of such events including: • Structural integrity or foundation failure • Electrocution • Fire • Explosion • Physical danger • Release of toxic or other hazardous substance • Radiation • Escape and rescue • Transfer and access Process The execution of the HAZID itself should be performed using a suitably qualified independent chairman. The majority of the team members should have suitable levels of technical knowledge, technical experience and technical familiarity with the design under study. The HAZID team should consist of the following members as a minimum: 1. Chairman 2. Secretary 3. Project manager 4. Engineering manager 5. QHSE engineer 6. HV engineer 7. LV engineer 8. O&M engineer 9. Structural engineer It is recommended to work out a safety philosophy for the substation, describing; transfer, access, evacuation, fire protection/detection etc. This philosophy, layout drawings and single line diagrams may be basic material for the HAZID. During the HAZID actions will be assigned to the participants (3‐9). The participant can sub‐delegate the action close‐out, but is still responsible to ensure actions are adequately closed out by fulfilling an action sheet how to implement the

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mitigation and safeguards to avoid/minimize the hazardous event. The action sheet is returned to the project manager. If Failure Modes, Effects and Criticality Analysis (FMECA) is undertaken as a part of the design process, as this is also a risk management tool, the results from it should feed into the wider risk management framework of the project itself. This necessitates that there be close co‐ordination between these two activities. This is most efficiently done by having personnel overlap between both activities with the FMECA results being one of a number of inputs to the HAZID risk management process. Risk rating The identified hazards can be ranked according to the description given below. The ranking is used in order to identify the important hazards that may be analysed further and which hazards can be neglected. The risk may be evaluated by using a risk matrix and an example is given below: Probability of failure scale / year Consequence Unlikely Low Moderate High Catastrophic Severe Moderate Low Indicative 1/10 000 – 1/1000 – 1/100 1/100 – 1/10 > 1/10 values only 1/1000 The applied general risk acceptance principle is based on qualitative risk assessment and a risk ranking concept expressed by a coloured Risk Matrix. The risk matrix is the overall tool for checking and documenting whether the risk is acceptable (green), unacceptable (red), or tolerable (yellow) when reduced to ALARP level. Legend: Area Risk Criteria Red High Unacceptable Yellow Medium Tolerable if ALARP Green Low Acceptable Generally medium risks are tolerable once all reasonable practicable actions have been taken to reduce them. Further reduction action is needed, unless the costs are grossly disproportionate to the benefits A flow diagram for a HAZID is shown in the diagram below:

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As a result of the risk management and assessment process, specific risks, hazards, and safety concerns can now be addressed and fully communicated. Listed below is a brief highlighted list of those associated risk items which are further addressed within this brochure.

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Category of Risk

Risk Title / Description of Risk

Covered in Section

Electrical Design

• High voltage stresses - High overvoltage exposure of equipment

2

Physical Environment

• Main Transformers & Reactors - Transformer failure, fire hazard and explosion - Gas Insulated Transformers (GIT) 3&4 • Equipment arrangement - Load handling and dropped object damage to systems and structures - Location of storage area

Systems

• Inter array cables - Minimum cable length, optimal configuration - Puncturing electrical insulation • Harmonic Performance 2&3 - Interactions between cable resonances, existing harmonics and control systems • Earthing transformers - Effective grounding in transformer fault

Operational Aspects

• Maintenance of Offshore substations - Unplanned maintenance - Oil management • Health and Safety - Access to and egress from substation - Fire and explosion hazards

2, 3, 4 & 5

Environmental

• Oil handling & spillage

3

Table 1‐1. Substation design associated risks

1.1.1 Risk Considerations which Affect the Single Line Diagram Optimal Levels of Redundancy For onshore substations associated with conventional generation there are well defined rules for the level of redundancy to be applied (for example N‐1) However, when considering wind generation the generation capacity cannot be considered to be available all the time, in fact the average capacity factor will be of the order of 30‐40%. This means that in order to decide the level of redundancy to be applied the client will need to decide the risk of curtailment of the available energy. This has led in many of the wind power plants built to date of a redundancy of N (i.e. just sufficient to carry the full load power of the wind power plant) and in some circumstances to N+”a little bit” (meaning not quite enough to 32

carry the full load output of the wind power plant). In many cases this decision has been made by intuitive feel rather than a quantitative risk assessment of the likelihood that the available energy will need to be curtailed. In order to perform a simple economic comparison of different network configuration options, the following formula may be applied for each component (or network corridor) under scrutiny: Lost Generation (MWh) = MTTR x r x G Where MTTR is the mean time to repair (in hours), r is the probability of component failure, and G is the lost generation when component failure occurs (in MW). The expected load factor for the wind power plant could be applied to calculate the lost generation when the failure occurs. The marginal cost of component redundancy should then be compared with the cost of energy not delivered from the above calculation in net present value terms over the lifetime of the development. Another quantitative assessment could use a statistical assessment tool for assessing the likely available energy of the wind power plant throughout the year. Such an assessment may use the Weibull distribution method. Given certain data about the wind conditions at the wind power plant location it is then possible to calculate the probability of a certain wind speed existing and hence the number of hours per year for which that wind speed will exist. If the power curve of output power of the wind turbine generator against wind speed is known the likely output of the wind power plant may be calculated to show the output power profile across a year. This enables quantitative calculation to be made of the risk of energy curtailment (loss) in the event of loss of a particular network component. Optimal Circuit Ratings Furthermore such calculations can also assist in assessing the optimal size of export cables to be used to get the best compromise between initial capital cost and the cost of losses over the lifetime of the plant. An example of such a calculation utilizing the Weibull distribution function is included as Appendix 1. The feeder loss‐load factor represents a translation factor between energy and power losses method that may be employed, as an alternative to the above described method, to calculate the actual annual energy losses in any feeder circuit. This method of energy loss calculation is used for conventional transmission and distribution planning calculations to quantify the cost of losses and feed into techno‐economic optioneering analyses. Annual energy losses can be calculated using the following equation: Annual Energy Losses (MWHr) = Loss Load Factor (LLF) x Peak Power Losses (MW) x 8766(hours in a year) The peak power losses through the feeder can be calculated by hand or more accurately using a power systems simulation model, assuming maximum output of the generation connected along or to the end of the feeder. The LLF for a feeder can be calculated from the prevailing generation profile data, using the following equation: LLF = 1/n x ∑ (Demand2 / Peak Load2) Where n = number of discrete generation outputs over the period (per annum for example) This type of assessment should also be combined with other availability calculations using established procedures such as failure modes, effects and criticality analysis (FMECA) in order to reach the correct level of redundancy to be used for any particular wind power

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plant. Please refer to Appendix 2 for a description of FMECA study and how it is used as a reliability assessment and improvement tool.

1.1.2 Risk Considerations Affecting the Offshore Substation Physical Design In this section some of the key risks are identified and the way in which these will be dealt with are expanded upon in the appropriate section of the brochure. 1.1.2.1 Basic Design Concept There is a fundamental point to be clarified before beginning the design of the offshore substation namely:‐ is the platform to be designed to ensure the safety of the personnel who need to operate and maintain the substation only, (this is a minimum consideration) or is it also to be designed to protect the assets and the overall integrity of the platform in the event of a catastrophic failure of some items of plant? The design of the layout and some of the systems provided will be greatly affected by which of these considerations is to be taken into account. Let us consider these below. 1.1.2.1.1 Personnel Aspects In this section a number of bullet points to consider are given. These will be covered in more detail in Section 4 of the brochure with regard to how these aspects are covered in the design of the platform. • Transport to and from the substation Access for personnel to and from the substation may be either by boat or by helicopter. Depending upon the location of the platform, the sea conditions such as swell etc. and wind speeds may mean that boat access to the platform may be completely impractical for significant periods during the year. This needs to be taken into account when deciding whether the access to the platform will be only by boat or whether a helideck should be provided. Consideration can also be given to providing a heli‐hoist for material and emergency evacuation purposes. For transport by sea a clear definition of when works will cease due to significant sea states should be agreed. The lifting equipment installed on the offshore platform should be designed to operate within the agreed sea state constraints. It is common to use the Douglas Sea Scale to define the limiting sea conditions for transport and personnel transfer purposes. For transport by helicopter the prevailing wind patterns need to be considered and the helideck positioned so that the helicopter approach for landing is into the wind. Wind speed vs wind direction tables and diagrams (wind rose) should be prepared for the specific location to assist the positioning of the helideck on the platform. It is common to use the Beaufort Scale to identify wind speeds in an offshore environment • Transfer from and to the transport at each end If boat transfer is to be used then the means of approaching the platform, the number of boat landing locations and the ladder and climb assist facilities to be provided need to be considered. Transfer procedures would need to be developed by the operator together with suitable training procedures, management of training logs and health and safety systems. • Emergency evacuation – by sea and /or by air

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The emergency evacuation of persons from the offshore platform must be considered at the design stage of the offshore platform as it will influence the facilities to be included on the platform, typically Type and location of liferafts and means of lowering them to the sea Type and location of descent systems to the sea/liferaft for persons Type and location of other life saving equipment Muster area and public address systems Evacuation routes and markings etc • Emergency evacuation of injured persons / stretcher cases The emergency evacuation of injured persons / stretcher cases from the offshore platform must be considered at the design stage of the offshore platform as it will influence the facilities to be included on the platform, typically Width of access walkways and stairways to evacuation points Provision of suitable stretchers Cranes with access to boat landings should have an emergency man riding facility to lower a stretcher to a vessel or alternatively a davit crane may have a suitable padeye to which a descent system can be fitted for emergency use. • Exposed locations on the substation platform (walkways and staircases) • Restricted working areas due to compact design • Electrical hazards when testing or operating • Unfamiliarity with the layout and equipment • Loss of services such as lighting, heating or communications • Working in confined spaces • Fire • Explosion 1.1.2.1.2 Assets If the assets are to be protected against certain catastrophic events then the following contingencies need to be considered:‐ „ Fire „ Explosion „ Collision from shipping „ Security (protection against malicious acts) 1.1.2.2 Operational Aspects The following operational risks may be encountered and these will be expanded upon in the following sections „ Depletion of protection systems (Section 5) „ Deterioration of equipment due to uncontrolled accommodation environments (Section 3) „ Fouling of cooling or ventilation system intakes and exhausts (Section 4) „ Increased down time due to spare parts availability (Section 3) „ Increased downtime due to inaccessibility of defective elements (Section 3) 1.1.2.3 Commercial Aspects The following commercial considerations may have an impact upon design decisions „ Uneconomic repair costs

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Repair of any item of plant offshore will be much more costly than performing the same repair onshore. This will generally mean that repairing equipment offshore will very rarely be a cost effective option. This will mean that replacement modules will need to be considered as the normal method of carrying out repairs. „ Loss of production This should already have been taken into account in the considerations regarding redundancy as mentioned in Section 1.1.1 above with regard to the choice of the single line diagram. „ Insurance costs /claims for accidents As the risks associated with offshore substations are so much higher than for onshore ones then the cost of insurance is likely to be substantially higher. Consideration may need to be given to the design of the plant to enable insurance to be obtained at a reasonable cost or even at all. This may well be true for aspects such as fire fighting. „ Transport / repair equipment costs These considerations will affect the choice of spare parts, accessibility, modularization etc. which will be expanded upon in Section 3.

1.2 Maintenance Any activity to be carried out on an offshore substation platform will typically cost approximately ten times that of a similar activity carried out onshore. This means that the amount of maintenance intervention must be kept to a minimum compatible with reasonable capital investment. Consequently, the design of the equipment and the substation layout must take this into account. The following paragraphs highlight some of the aspects

1.2.1 Accessibility within the Substation of Equipment Needing Repair The layout of the substation must take account of access requirements for the different types of equipment installed on the substation platform. In this brochure these requirements are defined in Section 3 for implementation within the layout design which is covered in Section 4.

1.2.2 Equipment Tagging A detailed equipment tagging system should be developed such that all items of equipment, including light fittings, switches, fans and other small items can be specifically identified at the time of reporting a defect. The aim of this tagging system is to ensure that when a spare component is taken to the offshore platform it is guaranteed to be the correct device and will be readily interchangeable with the defective device. There is currently no agreed Standard to define a tagging system so a suitable system should be developed and agreed at the early stages of the design process so the nomenclature can be added to drawings and technical documents as they are being developed.

1.2.3 Diagnostics and Communications to allow Focused Maintenance Consideration should be given to the use of condition monitoring equipment and communication of the information using the SCADA system. This needs to be carefully evaluated as the reliability of some monitoring equipment can be lower than the equipment

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it is actually monitoring. The need for condition monitoring is covered in Section 3 and for the communication systems is covered in Section 5.

1.2.4 FMECA and RCM in Maintenance Planning FMECA is an important prerequisite to effective maintenance planning and maintainability analysis. The effects of failure modes (costs, safety implications, detectability, etc.) must be considered in determining optimum scheduled maintenance requirements. FMECA is also a very useful input for preparation of diagnostic procedures and checklists, since the causes of failure symptoms can be traced back using the FMECA results. The systematic approach to maintenance planning, taking account of these reliability aspects, is called Reliability Centred Maintenance (RCM). In this method the degradation, failure effects and detectability of components or sub‐systems is factored in when determining the cyclical maintenance, replacement or the testing of the components or sub‐systems. RCM (based on the FMECA study carried out during the design phase) is very widely used in the commercial aircraft maintenance business.

1.2.5 Minimising the Need for Routine Maintenance Clearly the equipment installed on the platform should have the minimum need for maintenance intervention. The design to ensure this aspect is covered for the main equipment in Section 3 and for the auxiliary systems in Sections 4 and 5.

1.2.6 Over Designing to Reduce Unplanned Maintenance In some cases it may be economic to overdesign the main equipment in order to minimize the maintenance requirements. This is covered in Section 3.

1.2.7 Availability of Suitable Transport for Staff, Equipment and Spare Parts It is essential that consideration is given within the design of the substation platform to enable the safe landing of equipment and spare parts and the staff required to install them. This may consist of boat landing, davit and platform cranes, laydown areas, heli‐hoist facilities or possibly a helideck. These considerations are detailed in Section 4.

1.2.8 Availability of Maintenance Specialists with Offshore Training In order to work offshore, staff must have specialist training to ensure that they are fully prepared for the additional risks associated with the work and the access requirements. This means that for any person who needs to access the platform to perform maintenance or repair activities must have had this substantial safety training. This may mean that the substation owner/operator may wish to consider employing a specialist maintenance contractor to carry out this work on their behalf. This type of decision should be taken quite early in the substation design development.

1.3 Verification and Certification In the process of performing a good, top quality design process that conforms to the relevant national and international health & safety requirements and best industry practice, the developer of the substation will perform a number of verification activities. These could include internal assessments based on the Owner’s or Engineering Company's internal quality system or independent, 3rd party verification including certification. Certification is mandatory in countries such as Denmark and Germany, and commonly follows the 37

requirements set out in IEC 61400‐22. According to this standard, Statements of Compliance (or Conformity Statements) are issued for individual phases of a project, while a Project Certificate is issued for the entire (substation) project based on the individual conformity verification activities. The HV electricity rules and certification regimes is not discussed in this chapter. The common practice in this field shall be followed or possibly be enhanced for offshore installations.

1.3.1 Engineering Design Studies and Design Basis. The safety aspects of the project, and the development/achievement of specific acceptance criteria for loss of life, environmental impact and damage to asset that were established in engineering studies may be independently verified. One example of good practice is to verify the study for fire protection, incl. detection, fire escape and fire extinguishing systems. The Design Basis and relevant engineering studies are issued for verification and if the design studies comply with referenced standards, or achieve the referenced requirements, a Statement of Compliance (or Conformity Statement) is issued. Engineering Design. For offshore oil/gas platform it is often required to obtain a certificate of design compliance to regulations, rules and standards. The suitability of the offshore rules has been widely discussed in connection with Offshore Substations. One set of rules from DNV is the result from working with oil/gas offshore rules and moulding them in to suit Offshore Substations. More sets of rules targeted for the offshore wind industry platforms are likely to emerge, as it is the case for wind turbines, turbine towers and foundations. One example of good practice is to have, as a minimum, the steel design of topside and substructure verified. This will include the assessment of the site‐specific soil condition for evaluation of the foundation design and the structural integrity during transport and installation. The design documents are issued for verification to the certifying body, and if the design complies with referenced standards, or achieves the referenced requirements, a Statement of Compliance (or Conformity Statement) is issued.

1.3.2 Structures, Foundation and Systems Fabrication and Components. The usual scope of work for fabrication certification is to document that the fabricated hardware complies with the design documents and the fabrication rules/standards referenced in the design. Component (type) certification can be expensive, depending upon the type of component. The value of a component certificate (compliance to design and rule/standard) should be weighted against its importance and risk of failures during fabrication. One example of good practice for fabrication certification is to certify the fabrication of topside steel structures and substructures, including corrosion protection such as coating and cathodic protection. Typical offshore certifying companies have these certificates among their products, but they have competition from institutes specialized in material, special systems and component certification. Commonly surveyors of the certifying body are carrying out inspections during the entire fabrication phase. The fabrication documents/ welding records are issued for certification to the certifying agency, and if the fabrication records comply with referenced standards, or 38

inspections and tests proves that the referenced requirements are achieved, a Statement of Compliance (or Conformity Statement) is issued.

1.3.3 Transportation and Installation Phase. An example of good practice for marine operation is to use a marine warranty surveyor to issue a Marine Warranty Certificate. The certificate's original purpose was for insurance, but it is good practice to order it for this highly specialized task of marine operations. The surveyor will review the installation design and should therefore be ordered before the design is finalized. The installation procedures and drawings are issued for certification to the surveyor, and if the documents comply with the design and the surveyors' standards, and the installation is performed accordingly, a marine warranty certificate is issued.

1.3.4 Commissioning Onshore and (Hook Up and Commissioning) Offshore. The Hook up phase requirements can be compared to fabrication requirements and certification. The commissioning phase onshore and offshore is however especially important for offshore projects. Certification activities during commissioning could focus on ensuring the completeness of the installation. Another possibility is to verify that all commissioning activities/criteria required by the contract are accomplished. The benefits will especially be accomplished by maximizing onshore commissioning and thereby minimizing the offshore commissioning work. The commissioning procedures are issued for certification and witnessing to the certifying agency, and if the procedures comply with referenced standards and the actual test results comply accordingly, a Statement of Compliance (or Conformity Statement) is issued.

1.3.5 Operation and Maintenance Phase. Certification of operational requirement can be used either as the follow up on requirements set out in the design phase or as a separate assessment of operational or maintenance programs. A maintenance program could include condition monitoring programs that ensure timely preventive maintenance. Subject to review could be: „ Structure integrity „ Passive safety systems „ Active safety systems „ Navigation systems „ Communication systems „ Aerial and sea access control system

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2.

System Considerations

This section describes the offshore AC substation design issues ranging from those that involve more than one component up to the complete system. This includes reliability, availability and maintenance issues as well as system characteristics like total substation power flows, reactive power management, applied voltages and harmonics. Focus is on the electrical system. The physical (offshore) aspects are covered in section 4. This section does not provide standards or solutions to design issues, but it seeks to provide guidance and highlight considerations that should be taken into account when designing an offshore AC substation.

2.1

Reliability, Availability and Maintenance (RAM)

Reliability, availability and maintenance considerations in an offshore system differ from those of their onshore counterparts. The main differences are the high investment costs for offshore infrastructure and the fact that most installations are distant with access depending on the prevailing weather conditions. When designing an offshore substation, it is important to realise the consequences of the design on upfront capital investment costs, operational costs and the impact on overall system availability. A balance has to be found between reducing capital investment and operational costs and achieving the required system availability. To maximise revenue, some general guidelines are listed below: • No redundancy of expensive and/or reliable components • Minimisation of offshore installation and maintenance work • Smart planning of maintenance (prevention rather than repairs) • Maximise availability in terms of energy transmission (not time)

2.1.1

Availability and Reliability

Availability and reliability of an offshore system can be determined the same way as that of an onshore system. The combination of expected failure rates and repair time of the components will determine the system reliability. The difference between availability and reliability is in the interpretation of the figures. Availability is mostly measured relative to time. However, when the demand for energy transmission varies, the value of availability varies with it. When there's no energy production there is little need for high availability; but in times of high wind and energy production, availability is extremely important. Even more so in the absence of marginal production costs. Figure 2‐1.shows a wind power duration curve. (Note: Figure 2‐1 shows a duration curve for an average wind power plant on the North Sea with the current state of technology and a capacity factor of 0.4. Wind turbine development will cause this shape to change, possibly into a flatter line in which case the numbers given in this section also change. Therefore the statistical numbers referred to in this section must be regarded as illustrative, not as a fact.) Since there is no offshore energy storage, the demand for energy transmission will result in this same duration curve with the power generated being evacuated to shore. The curve shows that there are almost 1000 hours a year with no power production due to too much or too little wind.

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Figure 2-1. Wind power duration curve expresses demand for power transmission

When measuring the availability of an offshore wind power plant substation, it is advised to express availability relative to production. The relevant question being: What percentage of the energy produced can be transmitted? This way of thinking has a large impact on the redundancy considerations and maintenance philosophy, which will be described in the next sections.

2.1.2

Redundancy

Introducing redundancy in a system is a cost versus risk decision. Introduction of redundancy will reduce operational risk, but will also increase costs. The risk is determined by the chance of failure of a certain component and the impact of failure of a certain component. The cost of redundancy is normally the investment needed to install a second system that can cover failure of the first system. In case of high risks, higher cost of redundancy will be acceptable. In offshore systems the cost of redundancy is usually higher than for onshore installations, which can influence the level of redundancy to be built into the system. High risk

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Figure 2‐2. Typical risk matrix Redundancy in grid systems is often expressed in terms of (N‐1) or (N‐2) indicating that one or two components of the system (consisting of n components) can fail without influencing the performance of the system. To make a wind power plant substation truly (N‐1) redundant would introduce relatively high marginal investment costs. The resulting strategy is therefore to minimise the chance of failure of the complete system by prioritising component redundancy. Redundancy is most efficient in components with a high chance of failure and/or a high impact of failure that have low procurement and integration costs. For offshore AC platforms this includes HVAC systems, cooling pumps, secondary systems and communication infrastructure.

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An alternative to complete redundancy of a system component, where you install two components capable of 100% of nominal capacity, is to install two times 50% or two times 70%. This will still result in loss of capacity when one component fails, but not all capacity is lost. In many cases a choice for two times 70% also results in lower stresses during operation (since there is over‐capacity, the components will not be fully loaded) and therefore an extended lifetime of substation components. For critical components which would have a high impact if not available (e.g. cooling pumps), even three times 70% configurations are considered. In [5] the lifetime cost associated with different transformer configurations are compared taking into account lower losses, extended lifetime and reduced energy losses5.

Figure 2‐3. Ownership costs for 20 year operating lifetime [5] In case of transformers, another possibility would be to install single phase transformers. A spare transformer phase unit could be installed to enable rapid reconfiguration in case of failure of one phase. In case of wind power transmission systems, it is useful to study different approaches to redundancy because (N‐1) redundancy can be prohibitively expensive (not only the cost of extra equipment, but also increased platform weight and space are an issue) and the load factor is well below 100%. In many cases loss of part of the transmission capacity due to failure of a component will not impose a constraint on the energy transport. The load duration curve in the previous section Fig 2‐1 shows that in fact 70% of the time the actual power production is below 50% of maximum production. As a result, if one assumes a 50% system availability and integrate the energy under the curve in Fig 2‐1 this shows that approximately 80% of the energy can be transmitted. Continuing this train of thought; one could reason that installation of less than 100% of the nominal system capacity is perhaps economically feasible. For instance transformers or cable systems can be temporarily overloaded, so when only 90% of nominal system capacity 5

A. R. Henderson, L. Greedy, F. Spinato, C. A. Morgan, Optimising Redundancy of Offshore Electrical Infrastructure Assets th th by Assessment of Overall Economic Cost, European Offshore Wind Energy Conference, Stockholm, Sweden, 14 – 18 September 2009

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is installed, the peaks in wind power can still be transmitted for limited periods utilising the overloading capacity of the system components. Overloading system components will reduce the life expectancy of the equipment. The idea of installing less than nominal is often referred to as (N + 'a little bit') redundancy. In practice, most systems are not designed with complete redundancy, but some critical components will be (N‐1) redundant, e.g. secondary equipment and communications, HVAC and cooling systems. Primary and secondary plant on the platform itself will be discussed later on in this brochure. Two main components that connect to the platform, that have a considerable impact on system design and reliability are the MV and HV cables. Each project will have to determine the desired risk profile and optimise redundancy for the complete system. 2.1.2.1 Inter array Cable Considerations The cables that connect the wind turbines to the platform are referred to as inter array cables. Inter array cables can be configured in different ways. Usually a configuration with minimum inter array cable length is preferred, but configurations with limited redundancy and minimized risk are also considered A logical starting point would be a radial configuration with the maximum number of turbines connected to each string. To save costs, the cables further from the platform will be of a smaller diameter than the ones close to the platform. This is illustrated by Figure 2‐4.

Figure 2‐4. Radial inter array cable system One disadvantage of this configuration is that a cable fault at the beginning of the string will cause loss of all the turbines on the string. To add redundancy to the inter array cable system, ring structures can be introduced as shown in Figure 2‐5. This however, causes considerable extra costs because all cable diameters will have to be larger. Therefore most wind power plants only make use of ring structures to provide emergency power for wind turbines in case of an inter array cable fault. This allows the cable size to decrease along the array and the cable connections at the end of the strings, which are not normally in service, are not rated to carry the full turbine generation in case of fault, but can be used as emergency power supply. This will provide power for communications and HVAC systems of the disconnected turbines, but cannot transmit the produced power (Figure 2‐6).

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Figure 2-5. Ring based inter array cable system

Figure 2-6. Ring structures only for emergency power supply

An alternative way to reduce the risk of loss of a large number of turbines is to connect fewer turbines to one string. Taking all these considerations into account, an optimal wind power plant could be configured as shown in Figure 2‐7.

Figure 2‐7. Combination of different configurations can lead to an optimum

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For every wind power plant the optimal configuration is different depending on the number and output rating of turbines, the geography of the area, the number of substations, the acceptable risk profile etc. 2.1.2.2 Export Cable Considerations Most offshore AC substations are connected to shore (or to an HVDC system) by one or two export cables, usually 3 phase 132 kV or 150 kV XLPE cables. Most of these cables are between 10 and 60 km in length, making them costly assets. Cables generally have low rates of failure, but long repair times and high impact when not available. As a result of the high cost of the offshore cable and their installation, full redundancy on the export cable is rarely an option. However, installing two cables with less than 100% rating or three cables instead of two could be worthwhile; this is comparable to the earlier example of transformer redundancy. As the vast majority of the export cable failures are due to some kind of physical damage, the cables should ideally be installed in cable traces separated by some distance from each other in order to take full advantage of the redundancy aspect. 2.1.2.3 Interconnecting Wind Power Plants Another method of providing redundancy in export cable systems is by interconnecting adjacent wind power plants. If one wind power plant’s export cable fails, the adjacent cable can be used to export energy from both wind power plants. Another advantage is the possibility to provide emergency power in case of failure of the export cable. However, since the nominal capacity of the export cable of a wind power plant is usually equal to the wind power plants maximum capacity, it will be possible to export part of the energy from the other wind power plant with only one cable during cable fault at one of the wind power plants. Interconnecting wind power plants will only be viable when wind power plants are located close together, which is related to the costs of installing the connection cable. As a consequence of this geographical proximity, the production profiles of both wind power plants will be alike as will the power duration curves Figure 2‐8 shows power duration curves for an average 200 MW wind power plant (blue) on the North Sea and the combined curve for two such wind power plants (green). Power duration curves

Figure 2‐8. Power duration curves for a single wind power plant (blue) and two wind power plants (green).

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Figure 2‐9. Transmitted (blue and green areas) and lost (red area) energy.

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Figure 2‐9 shows the situation when only 200 MW of export capacity (one cable) is available. In this case the power from one wind power plant can always be transmitted (blue area) as well as part of the power from the other wind power plant (green area). The red area represents the power that is still lost due to limited transmission capacity. Note that this will only occur for about 3000 hours a year. Statistically, 40% of the energy produced in the second wind power plant can be transmitted through the export cable of the first wind power plant during a cable fault. Figure 2‐9 also shows that the maximum useful capacity of the connection cable is theoretically 200 MW in this case. In this example some factors like overloading of cables and different load profiles due to maintenance or forced unavailability are not taken into account. The investment decision for the connection cable mainly depends on the distance between the wind power plants, cost of constrained energy and the reliability of the export cables (in case of high reliability the connection cable will not be economical).

2.1.3

Maintenance

Offshore maintenance, like all offshore work, is expensive and should therefore be minimized. On top of the costs, offshore maintenance involves a hazardous working environment, long travel times and is highly dependent on the prevailing weather conditions. Platforms can only be accessed by boats when the wave height is less than 1.5 m to 2.5 m, depending on the access system being used. For exchange of large equipment or cable repair, an extended period of calm weather is necessary. Historical data from the North Sea shows that average waiting time for a 7‐day weather window is about 17 days. However, due to seasonal changes, expected waiting time from October through December is close to 45 days. One positive feature of offshore maintenance work in relation to the weather is the fact that maintenance weather windows are commonly related to low electricity generation; another reason to encourage planned preventative maintenance. On the other hand, when a failure occurs in a period with high wind, chances are that maintenance will not be possible due to the weather and production losses will be substantial. When availability is measured in percentage of energy transmitted, the logical consequence is to plan maintenance in times of low wind power production. Planned maintenance can be conducted during low wind periods, while unplanned maintenance due to failures has a tendency to occur in high wind periods when repair works are most difficult. This results in a strong preference for planned maintenance compared to unplanned maintenance. When developing operation and maintenance plans, it may be more appropriate to increase levels of planned maintenance to reduce the risk of costly unplanned maintenance.

2.2 2.2.1

Overloading Capability Overloading in Normal Operation

Due to the high investment costs of offshore equipment and the characteristics of wind energy, overloading of equipment can be an attractive option. The equipment for transmission of energy from the wind power plant to shore is only utilised at 40‐50% on average. By overloading the equipment, i.e. specifying equipment at 80‐90% of full capacity, the investment costs of offshore substations and cables can be reduced. Equipment most commonly considered for overloading are cables and transformers because of their high investment costs. The main disadvantages of this option are the shorter life‐

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time of the equipment (or if life‐time is seen as a design parameter, the need for higher robustness), which will mitigate some of the investment cost advantage. During the life time of the equipment the losses will also be higher due to a higher utilisation, thus causing higher operational costs. These disadvantages will have to be taken into account during the design phase. Secondary equipment like water pumps, cooling systems and HVAC installations can also be considered for overloading. These systems are often already redundant because of their importance and relatively low costs. Still, space and money may be saved when for instance a 2 x 70% scenario is applied. In this case, both installations can accommodate 70% of the platform needs and in normal operation will only be loaded for about 70% (50% of total platform need). In case one installation is unavailable, the other is overloaded for a limited period to accommodate the needs of the complete platform (or at least it's most important parts). This provides a compromise between the low security of a 1 x 100% system and the high costs of a 2 x 100% system. Naturally, a number of other variations can be developed based on specific situations.

2.2.2

Overloading in Case of Failure

In regular onshore substations the (N‐1) rule is normally used, which means that failure or planned disconnection of one piece of equipment does not affect power capability of the substation. This can normally be realised by installing spare capacity of equipment, which can take over the load from de‐energised equipment. In the offshore environment, where cost of installation and space available is critical, obeying the (N‐1) rule is more difficult. Ensuring the full capacity in emergency or maintenance cases will likely require increased overload capacity from equipment remaining in operation. For example, if a substation consists of two main transformers working in parallel and designed for taking the full capacity of wind power plant when working together, the case of one transformer being disconnected would require the other one to take over entire load. It has to be considered at early design stage to which continuous and which overload capacity such a transformer should be designed. In general, it is unlikely that all turbines within the wind power plant would work with full power capacity simultaneously. This might be related to availability of all turbines in the specific moment, or to the wind conditions. Hence, each transformer may not need to be designed for this full capacity of the wind power plant. Even if the full power availability scenario is more likely (e.g. due to very good wind conditions), it might still be beneficial to consider a design taking into account overloading the equipment for short periods of time. The specified overload capacity of the equipment should be thoroughly analysed at the stage of system design studies, and should include probability of overload situation, level of overload and its expected duration. Nevertheless, it seems to be worth to provide built‐in overloading capacity to the offshore equipment rather than applying (N‐1) rule or overdesigning the equipment by providing spare capacity needed only in rare cases.

2.3

Substations Size and Number Required

The question of determining the optimal number and location of substations in an offshore wind power plant should be based, like any other engineering matter, on a techno‐ economic assessment, although the marine environment poses additional factors to be considered to make the best decision.

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In general terms, the following key factors should be considered to choose the optimal place for an offshore wind power plant substation: • The size and shape of the wind power plant area. • The position of the onshore grid connection point and requirements of the grid owner. • The route of the export cables. • The possibility of a common energy export along with neighbouring wind power plants. • Permitting and legislation issues. • Water depth and seabed characteristics. • Project installation plan. • The arrangement of the wind power plant internal collection system. • Shipping lanes • Access by boat/helicopter Given the constant increase in the installed capacity (MW) of new offshore wind projects, it is necessary to go further and assess the possibility of installing more than one offshore transformer platform, and therefore some additional factors have to be considered‐ • The length of the collection system circuits, involving the maximum acceptable voltage drops and electrical losses. • The installation procedure, involving the availability of technical means and their cost. • Operation and maintenance issues. The decision about the optimal number of substations (commonly one or two) to be installed in an offshore wind power plant should be the result of considering all the previous factors for each one of the different alternatives by means of a techno‐economic study to choose the best option. Such a study will entail a comparison between the capital expenditures (CAPEX) plus the operation expenditures (OPEX) required by every alternative versus their respective electrical losses assessed along the whole life of the installation. Any of the options considered in the comparison should comply as a prime condition with the grid connection requirements and voltage regulation in the internal collection system. To carry out this kind of study it is necessary to have a large amount of information, mainly regarding pricing of equipment and installation works, but it is the only way to make a decision based on objective criteria. The result of the abovementioned study should be delimited with some restrictions regarding size and weight of both the topside of the substation and the foundation. Obviously, the number of transformers will drive the dimensions and weight of the platform, but the number of transformers is driven by the maximum current admissible for the medium voltage switchgear (presently 2,500 A at 33 kV is the maximum rating of the switchgear), that limits the maximum power to 280 MVA for a three winding transformer. Considering the most common procedure, important heavy‐lifting operations are required for assembling the offshore substations on site (at least one for the foundation and another for the topside), and therefore large crane vessels are needed (either sheerlegs or revolving cranes). In this way, the size but mainly the weight, are key factors in order to assess the availability and cost of the required vessel. Only as general data, there are less than 20 vessels around the world with a lifting capacity over 1,000 tonnes (refer to Section 4.8.1.1 for more details) and it is an almost impossible mission to find a free slot in their work planning. The situation is worse if a big substation with several transformers is considered

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(weighing over 1,500 tonnes), because the range of available crane vessels is even smaller. Additional information to be taken into account is the daily cost of this kind of vessel (where a daily rate of over € 500.000 may well be applicable). In practice, one of the biggest offshore substations currently designed and in operation features an installed power of 400 MW (although there are others planned for larger capacity, under consideration). For wind power plants with an installed capacity over 400‐ 500 MW two transformer platforms are likely to be required although the previous factors have to be considered. Currently there are a few projects including several smaller substations, where substations have only handled approximately 80‐90 MW. Nevertheless, in most of these cases, the division of the projects into different construction phases or separated areas has entailed the need of several substations in order to export energy to the grid as soon as possible, and therefore this is not the result of a techno‐economic assessment. As a conclusion, the decision about the location and number of substations in an offshore wind power plant should be based on a thorough techno‐economic assessment that compares the different alternatives in terms of CAPEX+OPEX vs. electrical losses along the life span of the installation, taking into account the technical factors and restrictions previously mentioned. In this way, the decision is made on an objective basis.

2.4

Grid Code Compliance

Because of the volatility of their source, in many countries wind power plants do not have to comply with all grid code requirements that apply to conventional production facilities. In countries where wind power contributes significantly to the national power production, there are specific grid code requirements for individual wind turbines or for wind power plants as a whole. The location of the connection point where the grid codes apply, differs per country. This section will describe some common grid code requirements for wind power plants and how the grid code can be applied to offshore wind power plants. No recommendations are made for the exact contents of the grid code, since this is highly dependent on the regulatory situation in each country.

2.4.1

Point of Common Coupling

For relatively large offshore wind power plants, it is important that some grid codes consider requirements with regard to power system stability. The grid code requirements should provide the necessary controls for the system operator to maintain stable grid operation while taking into account the specifics of wind power plants’ power generation. The main issue in this is the question of where the grid codes apply: at the connection point to the onshore grid, at the individual turbines, or at the connection point to an offshore substation. This point is called the point of common coupling (PCC) and its location will affect the form and location of reactive compensation and other equipment and can therefore introduce extra costs. It is recommended that these considerations be taken into account when grid codes for offshore wind power plants are designed or adjusted. One logical connection point for application of grid codes would be the location where the wind power plant is actually connected to a grid node which affects multiple parties (e.g. an onshore grid or an offshore substation connecting multiple wind power plants). Figure 2‐10 and Figure 2‐11 give an overview of different possible connection points in two situations.

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Figure 2‐10. Recommended PCC for single wind power plant situation

Figure 2‐11. Recommended PCC for multiple wind power plant situation with Offshore TSO

2.4.2

Grid Code Requirements

Sometimes Systems Operators (SOs) can economically encourage or punish wind energy producers according to their collaboration toward secure system operation. For example, the Spanish SO determines which should be the desired power factor according to the grid load level. Moreover there are requirements regarding voltage stability and minimum reactive power contribution levels. Therefore, during high load periods capacitive behaviour is required while the opposite for low load periods.

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This section gives an overview of common grid code requirements for wind turbines or wind power plants. Fault ride through Low voltages can be caused by faults in the network. Because of the potential harm that low voltages may cause to turbines, most turbines prefer to disconnect from the grid in case of low voltages. This however, will cause further decrease in voltage, potentially causing grid instability. To avoid this, grid codes define a minimum time in which the turbine should stay connected to the grid in case of certain voltage dips. Wind turbines are often excluded from these requirements. However, this is rapidly changing, especially in countries with significant wind power penetration. Figure 2‐12 gives an overview of fault ride through requirements in some European countries. Fault Ride Through requirements

1,2

Poland

Relative Voltage

1 Spain

0,8 Germany

0,6 0,4

Ireland

0,2

Netherlands (only single turbine >5 MW)

5250

4950

4650

4350

4050

3750

3450

3150

2850

2550

2250

1950

1650

1350

1050

750

450

150

0

Time (ms)

Figure 2‐12. Example of FRT requirements in grid codes (EWIS study 2008) Frequency response To maintain a stable grid frequency, conventional turbines have a primary reaction to frequency deviations in the grid. When frequency is low, production will increase, when frequency rises, production should decrease. This way, the grid balance is quickly restored in case of large changes in production or demand and the frequency remains stable. Wind turbines are often excluded from this system, because it requires that production is limited to 90% of the possible output. In case of wind energy with a low marginal cost, this is considered a waste. Only in countries with high wind energy penetration or islanded systems, wind turbines are required to provide frequency response, this is sometimes limited to a reduction of active power when in presence of a frequency increase. Voltage and reactive power Voltage support is realised by production or consumption of reactive power by turbines. Not all wind turbines are capable of setting their exact power factor, neither are they able to control it in every desired way. Wind turbines are often required to stay within certain power factor limits, but usually do not actively support grid voltage. This is different in countries with high wind penetration or island systems. In these systems wind power plants are normally required to be able to perform continuous voltage control at the Point of Common Coupling (PCC), with a Setpoint Voltage and Slope characteristic as

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illustrated in Figure 2‐13. The wind power plant should be able to operate with different setpoint voltages and slopes, according to Grid Code requirements.

PCC voltage %

Slope: Percentage change in voltage, that results in a change of reactive power from 0 to Qmin or 0 to Qmax

Vref

Qmax Capacitive Mvar

Qmin inductive Mvar

Figure 2‐13. Voltage control droop characteristic at the PCC The Grid Code requirements determine the Qmax and Qmin values (see Figure 2‐13) and these are dependent on wind power plant rated active power. In case of offshore wind power plants, the grid connection will be realised by submarine cables, producing reactive power. To compensate for this reactive power, static or dynamic compensation can be used, but it is also possible to use the wind turbines to (partly) compensate for the reactive power of the cable connection. This however is only possible if grid code does not apply at the turbine, but at the actual connection point to the grid. Active power control and remote operation In most countries, the philosophy is to get as much energy as possible out of the wind turbines, but in some countries, this is not desirable at all times because of the variable characteristic of wind energy or the limited fault ride through capabilities. In Spain for example, a real time system monitors system stability in case of faults and compares this to residual import capacity. When a single fault can cause a disconnection of an amount of wind power, greater than the residual import capacity, wind turbines in the area will be constrained in order to maintain secure grid operation. In this case, remote operation of the wind power plants by dedicated control centres is also a requirement.

2.5

Reactive Compensation and Voltage Control

Reactive compensation and voltage control require special attention when considering offshore installations. This is mainly caused by the fact that cables are used for the transmission of power. Cables behave capacitive over their full load range. Due to changing wind speeds, and therefore active power variations, the capacitive behaviour of the cable will constantly change and therefore reactive power control is necessary.

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This chapter will elaborate on the need for reactive power compensation and evaluate tools that can be applied to control the reactive power balance.

2.5.1

Reactive Power Balance

The need for compensation within offshore wind systems is determined mainly by two aspects, the compliance with grid code requirements and the achievement of an optimal utilization of the electrical infrastructure. Compensation is related to system stability and thus to reactive power and voltage control concepts. Bus voltages undergo continuous fluctuations owing to power flow changes or sudden contingencies. The injection of reactive power increases voltage level and the absorption reduces it. The reactive power control is used to keep or restore power factor and voltage to the desired targets. A series of requirements regarding reactive power and voltage control must be fulfilled in order to allow any connection to the grid. These requirements are defined by the grid codes in order to ensure stable system operation and they can differ from country to country. For example, busbar voltage should stay within a defined range and the system response to changes in reactive power or voltage should have a certain characteristics. On the other hand, in relation to an efficient delivery of energy, the excess of reactive power reduces the amount of active power injected to the common point of connection. The need and rating of the compensation equipment depends on the system configuration, wind power plant power capacity, distance to shore (length of the cable between the onshore and offshore substation), voltage and power rates, type of wind turbines, transformer impedance and other electric devices such as harmonic filters. It is essential to understand the reactive power behaviour of the main components of the system in order to identify the need for compensation. Basically, the export cable can be considered as a net generator of reactive power owing to its dominant capacitive behaviour; transformers absorb reactive power through the internal reactance and wind turbines can generate or absorb reactive power depending on the technology used. The compensation can be done through the reactive capability of generators and the use of transformers tap changers. Other additional devices which can be applied to the wind turbine (distributed compensation), to the offshore and onshore substations (centralized compensation) or to both (mixed compensation). As mentioned above, AC cables have as a natural characteristic the capacitance due to their insulation6,7,8 (see references [6], [7] and [8]). The ampacity, the maximum current for a certain cross section, is mainly determined by the ability to remove heat from the conductor. It depends on the thickness of the insulation, the conductivity of the conductor and thermal properties of the soil and the ambient temperature in which the cable is buried. For long cable connections, this capacitance generates a charging current (complex) that reduces the load current (real) available before exceeding the ampacity. Therefore, through compensation it is possible to improve the utilization of the cable, increase the transmission length and prevent early overloading. This is important given the significant costs associated with submarine cables. Taking into account the actual trends of increasing

6

M. Pavlovsky, P. Bauer. “Cable selection and Shunt Compensation for Offshore Windparks”, Delft University of Technology, The Netherlands 7 G. E. Balog, N. Christl, G. Evenset, F. Rudolfsen. “Power Transmission over long distances with cables”. CIGRÉ, B1‐306, Session 2004 8 J. Overton, “Study on the Development of the Offshore Grid for Connection of the Round Two Wind power plants” Pag 21. Econnect 2005

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both distance to shore and voltage levels the need for compensation is becoming more relevant because of the higher charging current generated.

2.5.2 Wind Turbine Contribution The wind turbine generation technologies that are being deployed offshore include directly connected fixed speed wind turbines, variable speed generators with partially rated power converters and variable speed generators that connect to the network through full‐scale power converters. These three generator system configurations are described below, including reference to their reactive power generation capabilities: Fixed Speed Wind Turbine This configuration employs a squirrel cage induction generator (SCIG) which is directly connected to the grid through a transformer (see Figure 2‐14). This design utilises capacitor banks to compensate for the reactive power consumed by the generator and allow a reactive power operating range for the generator. Whilst the generator design is relatively simple, low cost and has low maintenance requirements, disadvantages include low wind energy conversion efficiency, high mechanical stress on wind turbine components and lack of reactive power generation capability.

Figure 2‐14. Schematic representation of the fixed speed induction generator Variable Speed Wind Turbine with Partial‐Scale Power Converter (DFIG) This wind turbine generator design employs a doubly fed induction generator (DFIG) with pitch control (Figure 2‐15). The generator is connected to the grid through a three‐winding step‐up transformer. The stator is directly connected to one of the LV windings of the transformer, with the rotor connected to the other LV winding through a partial‐scale IGBT power converter. The power converter is typically rated at between 25 and 30% of the generator rated power, and provides reactive power support and grid connection of the rotor windings. The generator’s variable operating speed range is approximately ±30% of synchronous speed.

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Figure 2‐15. Schematic representation of the DFIG The reactive power operating range of the DFIG (at full output) is dependent on the size of the converter with a typical reactive power operating range between 0.98 (capacitive) to 0.96 (inductive) achievable from a DFIG with a 25% rated converter. Wider reactive operating ranges may be achieved by increasing the converter capacity. Variable Speed Wind Turbines with Full‐Scale Power Converter The third type of system is a full variable‐speed, pitch controlled wind turbine with a full‐ scale power converter (Figure 2‐16), also called Full Converter Generator (FCG), which utilises a synchronous generator. The variable speed operating range can be from 0 to 100% of the synchronous speed, which allows increased wind energy conversion efficiency. In addition the mechanical stress on the turbine/generator components is greatly reduced relative to the SCIG, and reactive power compensation is provided via the power converter. However, higher power losses and increased cost result from the full‐scale power converter relative to the partial‐scale converter of the DFIG.

Figure 2‐16. Schematic representation of the generator with full‐scale power converter The optimal points for reactive power generation in offshore wind power plants very much depend on the configuration of the overall power system. When a wind power plant is connected to the network through long AC submarine cables the utilization of wind turbines for reactive power generation may not be the optimal solution considering the reactive power losses along the length of the cable. When a reactive power operating range for a wind power plant (as specified by the grid code) is required at the point of connection to the onshore network, additional sources of reactive power (e.g. SVC, STATCOM) may be required at this point.

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2.5.3

Dynamic Voltage Response

Large offshore wind power plants connected to the onshore grid through long high voltage AC export cables present special characteristics that should be taken into account when designing the voltage control scheme. Wind power plants are normally required to be able to perform continuous voltage control at the Point of Common Coupling (PCC) as described in the section on Grid Code requirements. Other Grid Code requirements like maximum dead time before wind power plant response begins; allowed overshoot and speed of response have an impact on the design of the voltage control scheme. The number of challenges varies according to the different Grid Code requirements; however a summary of these challenges can be found below. First of all the long AC export cables inject a significant amount of reactive power into the PCC. Some of this injected reactive power has to be compensated somehow, either by onshore reactors, through a reactive compensation plant or by using WTG reactive absorption capabilities (park controller). Secondly, submarine high voltage export cables can be subject to significant de‐rating factors when arriving at the shoreline (sea defense) as well as when arriving at the offshore platform (J‐tube). These de‐rating factors have to be taken into account when designing the reactive power voltage control scheme, so that they are not violated. Finally, Grid Codes often require fast response times, which rules out the transformers’ on load tap changer (OLTC) as a means to provide support during transients. When evaluating the dynamic voltage control response of the wind power plant, transformer tap positions should remain as they were in steady state in order to evaluate whether the wind power plant has enough reactive power capabilities to meet Grid Code requirements. There are several voltage control strategies that can be used in order to comply with Grid Code requirements, all of them having different impact on compensation plant rating and dynamic performances, a number of these options are discussed below. 2.5.3.1 Use of on Load Tap Changers (OLTC) OLTC both at the onshore substation and at the offshore platform transformers may be considered, to keep the voltages throughout the wind power plant within certain limits taking into account cable current ratings and WTG voltage operating range. When a voltage step of significant magnitude occurs at the PCC, this could cause major voltage drops (or increase depending on the direction of the voltage step) throughout the wind power plant. If this is the case, export cable currents will considerably increase, until the actions of the OLTC sets the voltage back into its normal range. This condition could last several seconds, which is normally within the bounds set by thermal time constants when J‐ tube and sea defense de‐rating factors are concerned. During voltage steps WTG operating voltage limits could be reached, preventing the generators from exchanging the necessary reactive power needed at the PCC in the time required by the grid code. 2.5.3.2 Use of Wind Turbine Reactive Capabilities Wind turbine participation in the voltage control scheme is important for the dynamic performance of the wind power plant since it can have positive influence in reactive

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compensation plant rating, as well as voltage fluctuation throughout the wind power plant during transients. Through the control actions of an overall park controller wind turbines can make use of their reactive power capabilities. In general two different control modes are used. 1. Reactive power control When through the actions of an overall park controller the wind turbines perform reactive power control, the goal is to control the reactive power flowing through a branch to a fixed value of MVars. There are several reasons that can lead to the use of this strategy, among them: • The need to absorb some of the reactive power generated by the long export cables. • The need to operate a certain branch at unity power factor, in order to reduce active power losses (for example in the inter‐array network). A disadvantage from this strategy is that a higher rating of compensation plant might be needed when compared with a voltage control strategy. The reason is that when a voltage step occurs at the PCC the voltages throughout the wind power plant will be affected, however the reactive power contribution of the wind turbines will be the same and thus the compensation plant will have to reach the operating point on the slope characteristic without help from WTGs. 2. Voltage control When through the actions of an overall park controller the wind turbines perform voltage control, the goal is to have a V/Q slope characteristic at a specific busbar in the wind power plant (See Figure 2‐13). The selection of the busbar where voltage control should be performed (onshore, offshore, PCC) has different impacts in the dynamic performance. There are several reasons that can lead to the use of this strategy, among them: • The need to rapidly support / limit voltage fluctuations throughout the wind power plant. • The need to reduce rating / size of the reactive compensation plant. The advantages of this control strategy can be summarized below • Better voltage profiles during transients when compared to fixed reactive power control, which translates into better support/limitation of voltage fluctuations throughout the wind power plant. • Size/rating of the reactive compensation plant can be reduced, since when a voltage step occurs at the PCC the voltages throughout the wind power plant will be affected. The park controller will control wind turbine reactive power injection / absorption to react in the correct direction and therefore assist the reactive compensation plant to reach slope characteristics. It should be mentioned that if the Wind turbines are performing voltage control at any point different than the PCC, a separate reactive compensation plant must be used to perform voltage control at the PCC. Reactive compensation plant In order to meet dynamic Grid Code voltage control requirements a reactive compensation plant performing voltage control at the PCC can be used. It is during dynamic simulations that the weaknesses of a voltage control scheme based only on the use of the reactive power capabilities of the wind turbines (No reactive compensation plant) through the park controller actions are exposed.

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A reactive power compensation scheme using only the reactive power capabilities of the wind turbines will in some cases not be enough to comply with the dynamic voltage control Grid Code requirements, since after a large step in voltage at the PCC, both onshore and offshore transformer taps will be in a wrong position. The response time is often too slow compared to the timescale of the Grid Code requirements, causing limitations in the reactive power that can be provided by the wind turbines. These limitations in the reactive power capabilities of the wind turbines could prevent the wind power plant from reaching the slope characteristic requirements at the PCC when large voltage steps occur. Different types of reactive compensation plants can be used to perform voltage control at the PCC and comply with dynamic Grid Code requirements. A description of the benefits and drawbacks of the different options can be found below. 1. Switched reactive compensation plant Switched reactive compensation plants (consisting of only switched branches MSC, MSR and MSCDN) can be considered. However, depending on Grid Code dynamic voltage requirements their limitations should be examined. In order to perform continuous voltage control at the PCC and comply with dynamic requirements, the reactive compensation plant needs to work together with the overall park controller. Reactive compensation plant switching logic control and interactions with the overall park controller should be carefully studied, since purely switched solutions could suffer from repetitive on/off switching of individual branches, that will compromise the ability to meet the dynamic voltage control Grid Code requirements and cause other negative effects like increased aging of Circuit Breakers and flicker. In order to meet Grid Code dynamic voltage control requirements, it is essential that through the actions of an overall park controller, the wind turbines perform voltage control at the PCC. The speed of response of the park controller is critical to comply with the dynamic response requirements, and should be studied. Drawbacks from this dynamic voltage control strategy include: • Possible hunting issues • Slower reaction times • Stepwise delivery of reactive power. • No power oscillation damping features available. 2. SVC / STATCOM The SVC/STATCOM solution should be considered when the reactive power needs to be continuously and smoothly delivered. Other reasons to consider the SVC solution could be that the amount of necessary switched branches is too high, and/or the speed of response of the mechanical breakers is too slow. Other advantages of using an SVC solution to perform voltage control at the PCC are: • Better voltage profiles throughout the wind power plant during transients. • Power oscillation damping feature available. Harmonic filters Harmonic filters might be necessary to avoid amplification of background harmonics and at the same time to reduce wind power plant harmonic injections to the PCC. Harmonic filters

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have an impact in the design of the reactive compensation voltage control strategy, an example of the areas affected by harmonic filters are: • Reactive compensation plant size and rating • Settings of the overall park controller, which determines wind turbine reactive power contribution. The extra reactive power injection caused by harmonic filters, can be counteracted by appropriate settings of the overall park controller, which can set the wind turbines to absorb any extra reactive power injected by the filters. If this is the case, currents at the offshore end of the cable should be looked at so that they do not exceed their limits.

2.5.4

Fault Ride Through

Normally a fault or another event in electric networks leads to voltage drops. Depending on the severity of that contingency, some of the protections (over speed, over current…) of wind turbines can be activated disconnecting the machines. Owing to the fact of the significance of this energy source within the actual energy framework it is essential to ensure that the generation stays connected during voltage drops or to recover it as soon as possible. The wind turbine technology plays an important role at this point. SCIGs derive their steady‐state reactive power from locally connected capacitors (Figure 2‐ 14). However, these are ineffective under fault conditions (i.e. reduced system voltage), and the SCIG is therefore unable to offer significant support to the networks in the case of a prolonged fault. FRT performance is therefore poor, especially for extended faults. Since IGBT semiconductors are very sensitive to overload and the DFIG’s DC link can only sustain a limited fault duration, additional protection measures are required to protect the system under fault conditions. In the case of a grid fault, high voltages are induced in the rotor windings that cause excessive currents in the rotor and a rush of power from the rotor terminals to the converter. The converter reaches its limits and loses control of the generator during the fault, and protection is required to break the high currents and control the energy flow. A simple method of protection is to short circuit the rotor through a “crowbar”, which limits the rotor current (Figure 2‐17). Crowbar Power Converter Control

Blade

~ ~ Partial-Scale Converter

Gear-Box

Grid

DFIG Transformer

Figure 2-17. DFIG wind turbine – crowbar control

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When the crowbar is triggered, the rotor is short‐circuited via the crowbar impedance, the rotor side converter (RSC) is disabled and the DFIG acts as a SCIG. The grid side connector (GSC) remains connected and can therefore produce limited reactive power during the fault. Previously, the DFIG would have been tripped as soon as the crowbar protection was activated, but now FRT is required. Improvement of the FRT capability of DFIGs can be implemented in the following ways: • By implementing a control strategy where the grid voltage (reactive power) control is taken over by the GSC. Once the crowbar protection is removed, the RSC will operate again as normal. The removal of the crowbar protection can be performed based on different criteria, e.g. magnitude of grid voltage or rotor currents. • With the addition of a “chopper” module into the DC link that activates before the crowbar to avoid DC link overvoltage during grid fault conditions. Following the voltage depression, if the DC voltage is maintained by the chopper, the RSC goes back into operation after a few milliseconds and the DFIG can be controlled even if it is operating on a low voltage level. If the grid fault voltage depression is severe and the chopper is unable to control the DC link voltage, the crowbar is fired and the rotor is short circuited as above. Converters and choppers could theoretically be designed to withstand even terminal short‐circuits but economic considerations normally limit these designs to lower ratings. Use of the full‐scale power converter, in particular the voltage source converter (VSC) type of link, may lead to improvement of fault ride‐through capability of large wind power plants [9]9. VSC has been developed over recent years, and utilises power electronics devices such as IGBTs, IGCTs and GTOs. The advantages of VSC include the fact that reactive and active power can be controlled independently and additional reactive power compensation may not be required. For improving the fault ride‐through of the wind power plant, it is important to implement a good control strategy for the VSC station. In [9], a three‐phase fault was applied, and the system was found to recover 0.5s after the fault, and the wind turbines remain connected to the network. Whilst the DFIG is currently the wind turbine type with the greatest market share, relatively complex and expensive design strategies are required to improve its FRT capability. For large offshore wind power plants fully variable speed wind turbines connected by full‐scale power converters may gain popularity because of their favourable properties concerning black start and reactive power. Recent research has shown that these configurations are capable of providing better FRT support as compared to SCIG and DFIG.

2.5.5

Transformer Tap Changers

Transformer tap changers are utilised for the following purposes: • Adjustment of the transformer terminal voltage to maintain the voltage within a given deadband. On load tap changers (OLTCs) on offshore substation transformers may be considered to keep the voltages throughout the wind power plant within limits taking into account cable current ratings and WTG voltage operating range. • Control of reactive power flows between points on the offshore network • To offset the voltage regulation of the offshore substation transformers under varying loading conditions. 9

Livani, H., Bandarabadi, M., Alinejad, Y., Lesan, S., Karimi‐Davijani, H, “Improvement of fault ride‐through capability in wind power plants using VSC‐HVDC”, European Journal of Scientific Research, Vol. 28, No.3, 2009 pp 328‐337

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•

Where over‐voltages are likely on lightly loaded capacitive networks, creation of “artificial reactors” through tap staggering on parallel transformers has been applied to absorb reactive power. This however, will only provide limited reactive power absorption and parallel operation may not always be favorable due to fault level considerations. Routine maintenance requirements however make OLTCs an unattractive component of the offshore substation with the majority of outages associated with substation transformers caused by mechanical failure, primarily a result of failure of the on‐load tap changer. This situation may be partially alleviated by the use of “vacutap” tap changers where the number of operations between maintenance is increased by a factor of three. With this in mind, the decision of whether or not to include tap changers in the design of an offshore substation should be based on the results of comprehensive steady state and dynamic system studies, and consultation with the relevant system operator. Alternatives to on‐load tap‐changers include: • specifying the wind turbines to be able to operate with a wide voltage range, so that voltage control at the substation is no longer necessary; • fitting off‐load tap‐changers, which are cheaper, smaller and have less frequent maintenance requirements. The operator must then accept that occasionally it will be required to shut down the wind power plant for a few minutes in order to adjust the tap position. Solid‐state load tap changers for medium power transformers (15 kV to 34 kV) are being investigated, and it is claimed that they could reduce maintenance costs by 50‐80% while increasing safety, reliability and power quality. Increased losses would be a disadvantage, but techno‐economic optimisation of the offshore substation design should include consideration of efficiencies and flexibility gained with the introduction of such devices (potentially reducing the need for reactive compensation on the offshore substation).

2.5.6

Flexible AC Transmission Systems

State of the art Wind Turbine Generators (WTG) are often equipped with power electronic converters allowing them to provide within their ratings precisely and fast controlled reactive power independently from the active power generated. The reactive power capabilities differ with the type of the WTG, e.g. Doubly Fed Induction Generators (DFIG) or Full Converter Generators (FCG). While some DFIG machines can typically exchange up to about 30% of the nominal current rating for reactive power FCG often feature reactive current exchange up to nominal apparent power. Besides their capability to draw reactive current in addition to active current certain voltage limitations apply in the range of overexcited operation of the WTG. This is due to the maximum ac network side voltage output of the converters being limited. To achieve capacitive current the ac voltage of the WTG needs to be higher than those at the connection point. As a consequence, the capacitive current capability decreases with increasing voltage at the connection point. In some cases the combined contribution of the WTGs may not be sufficient to comply with the grid‐codes reactive power requirements. Possible reasons could be: • The overall reactive power rating of the wind park including cables and transformers is not sufficient to reach the required inductive or capacitive output under the respective voltage conditions.

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•

The reactive power output of the wind park cannot be adjusted fast enough, e.g. because of the communication time between central wind park reactive power controller and WTGs or because of slowly acting devices like transformer tap changers. • Due to the internal impedances of the wind park (cables and transformers) some of the WTGs reach their voltage operating limits before they can supply the reactive current required. In cases like these the reactive power output of the wind park needs to be complemented by extra reactive power devices, as there are: • Mechanically switched capacitors (MSC) • Mechanically switched capacitive damping networks (MSCDN), also known as C‐Type Filters • Mechanically switched reactors (MSR) • Thyristor based Static VAR Compensators (SVC) • VSC based SVCs or Synchronous Static Compensators (STATCOM) The devices mentioned above are summarized under the terminology Flexible AC Transmission Systems (FACTS). FACTS can be used at the PCC of the wind park or inside the wind park network. The different types of FACTS devices are explained in more detail in the following paragraphs. The technology choice depends on how rapid the response of the system has to be. Therefore, for steady state compensation such as power factor control, mechanically switched might be enough. However, for more demanding circumstances such as restoration after voltage drop, static compensators seem more appropriate because of a faster response. Fixed or mechanical compensation requires less space than static compensation. Therefore, if it is essential to locate some compensation offshore the fixed or mechanical compensation is principally used.. 2.5.6.1 MSC and MSCDN In cases where the capacitive output of the wind power plant alone is not sufficient MSCs can be used. Figure 2‐18 shows a simplified single line diagram of a typical MSC branch.

C RHP L Arr

Figure 2‐18. Principle single line diagram of a MSC branch

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3

MSC Impedance (Ohms)

1×10

100

10

1

10

100

Harmonic Order 20 Mvar, n0=18, 132 , RHP=100 ohm

Figure 2‐19. Typical MSC impedance characteristic A MSC branch can comprise the following components: • Circuit breaker • Capacitor bank • Tuning reactor • High pass resistor • Arrester The MSC branch is switched by the circuit breaker which has to be designed considering the special duties of capacitive switching taking into account whether or not the capacitor bank is effectively grounded. During MSC turn‐on the maximum di/dt capability of the circuit breaker may require the MSC to be equipped with a di/dt limiting reactor. This is of special importance in cases where more than one MSC is to be connected at the same location (back‐to‐back switching). The di/dt limitation usually results in tuning frequencies of the MSC branches being quite high, e.g. 900 Hz or above. Special attention should be paid to possible resonances at low harmonic frequencies of the power system, i.e. at frequencies of 300 to 350 Hz and below. In that frequency range the MSC branch would be capacitive while many power systems have an inductive impedance characteristic. Under such conditions the MSC and the power system may form a resonance circuit which could cause magnification of harmonic frequencies existing in the power system or generated by the WTGs. Magnification of harmonics can be reduced by introducing a resistive impedance characteristics leading to attenuation of the resonance. Therefore, the MSC may be equipped with a high pass resistor. Figure 2‐19 shows an MSC branch with high pass resistor and typical impedance frequency characteristics. It can be seen that the damping effect of the resistor starts around the tuning frequency of the MSC. Somewhat below the tuning frequency the impedance characteristics becomes purely capacitive, i.e. the resistor is not effective there.

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If attenuation at a certain harmonic frequency is important the tuning frequency of the MSC has to be chosen low enough to have the high pass resistor effective at the lowest frequency of interest. The high pass resistor not only carries harmonic currents where its attenuating effect is desired, it also carries current of the network power frequency (fundamental frequency current) according to the impedance conditions in the MSC branch. Fundamental frequency current through the resistor is undesired because of the fundamental frequency power losses and corresponding power rating of the resistor. Lower MSC tuning frequencies tend to result in higher fundamental frequency power losses and resistor ratings. The power loss issue can be solved using MSCDN technology. Figure 2‐20 shows a MSCDN tuned to quite a low frequency of 145 Hz. In this case, however, the high pass resistor is connected in parallel with a LC resonance circuit tuned to the fundamental frequency. Under ideal conditions the resistor is thus bypassed at fundamental frequency and becomes increasingly effective at higher frequencies. MSCDNs are often used if tuning frequencies equal or lower than the 5th harmonic are required. Low MSC tuning frequencies are often used together with wind park applications because of the extended ac cable networks being prone to form low frequency resonances with the adjacent power networks. An arrester can be used to achieve economic insulation levels of the reactor and resistor in cases, where the MSC branch is to be connected to a high voltage level, e.g. greater than 100 kV.

C1 C2 RHP L Arr

Figure 2‐20. Principle single line diagram of a MSCDN branch

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3

MSCDN Impedance (Ohms)

1×10

100

1

10

100

Harmonic Order 20 Mvar, n0=2.9, 132 , RHP=300 ohm

Figure 2‐21. Typical MSCDN impedance characteristics MSR In cases where the inductive output of the wind power plant alone is not sufficient MSRs can be used. Figure 2‐22 shows a simplified single line diagram of a typical MSR branch.

L Arr

Figure 2‐22. Principle single line diagram of a MSR branch A MSR branch can comprise the following components: • Circuit breaker • Reactor • Arresters The MSR branch is switched by the circuit breaker which has to be designed considering the special duties of inductive switching, especially switching of low inductive currents. To limit

65

possible over voltages due to circuit breaker re‐strikes arresters can be used. In case of vacuum breakers, the use of special RC damping circuits may be needed. Depending on the voltage level or space restrictions, e.g. at platforms, the MSR may be of air core or iron core type. More than one MSR can be connected in parallel to achieve the required MVAR step size. Thyristor based SVC In cases where too many switched branches are needed, the response of the mechanical breakers is too slow or reactive power needs to be provided smoothly SVC installations may be used. Regarding the technology used SVCs can be distinguished in: • Thyristor based SVCs • Voltage Sourced Converter (VSC) based SVCs Both types of SVCs are used today with the VSC type becoming more and more important. Regarding the controllability of their reactive power output SVCs can be distinguished in: • continuously controllable SVC solutions • switched SVC solutions Thyristor based SVCs are available in both technologies while VSC type SVC are normally operated in continuously controlled mode only. Figure 2‐23 shows a single line of a Thyristor based SVC together with its components. A typical SVC comprises: • Step down transformer • Thyristor controlled reactor (TCR) • Thyristor switched capacitor (TSC) • Fixed capacitors (filters) (FC) • Controls The required capacitive power will be installed in capacitive branches which may be permanently connected (Fixed Capacitor, FC) or switched by Thyristor valves (Thyristor Switched Capacitor, TSC) at the medium voltage (MV) bus. FC branches are typically tuned by series reactors for harmonic filtering purposes.

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HV

MV

Controls

TCR

TSC

FC

Figure 2‐23. Principle single line diagram of an SVC The inductive power is installed in reactors, the fundamental frequency impedance of which is smoothly controlled by Thyristor valves (Thyristor Controlled Reactor, TCR). Each valve is built up by anti‐parallel connected Thyristors connected in series as needed to achieve the required blocking voltage. The MV SVC branches are connected to the high voltage (HV) system via a dedicated SVC transformer adjusting the transmission system voltage to a level optimized to Thyristor valve capabilities. Instead of a separate SVC transformer, a specifically designed tertiary winding of the wind park connecting transformer may be considered. The digital control typically includes a voltage control path as the main control function. Besides that also other control functions can be implemented, e.g. for coordinating the reactive power output with the wind park. The controls determine the firing angle for the TCRs and the switching status of the TSC branches. VSC based SVC or STATCOM VSC based SVCs, also referred to as Advanced SVC or STATCOM, use power electronic devices that do not only have controlled turn‐on capability like Thyristors but also support controlled turn‐off. Examples are Gate Turn‐Off Thyristors (GTO), Integrated Gate‐ Commutated Thyristors (IGCT) or Insulated Gate Bipolar Transistors (IGBT), with the latter becoming increasingly important today. Figure 2‐24 shows the principle equivalent circuit of a VSC based SVC, Figure 2‐25 explains the operation principle with capacitive (overexcited) operation as an example.

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IN

UN

∆U

UVSC Controls

Figure 2‐24. Principle equivalent circuit of a of VSC based SVC

{Im} maximum VSC current IN

UVSC

{Re}

UN ∆U

Figure 2‐25. Operating principle of a VSC based SVC (example showing overexcited operation) The major power components of a VSC based SVC are: • Voltage sourced converter (VSC) • Coupling reactor or transformer • Controls The VSC generates the voltage UVSC at its ac terminals. Magnitude and phase angle of that voltage are determined by the SVC controls with respect to the actual system voltage UN achieving a requested current IN. In principle, the current IN can be anywhere within the circle marked "maximum current of converter". For reactive power compensation purposes, however, the current will be controlled to be either leading or lagging the system voltage UN by about 90 deg. Angles different than 90 deg cause active power exchange with the ac system. In an SVC this feature is used covering power losses of the converter.

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The operation principle of a VSC allows maintaining a required current magnitude within a wide range of system voltages. This behavior is illustrated and compared against the characteristics of a Thyristor based SVC in Figure 2‐26. The VSC based SVC has advantages at system undervoltages because it behaves like a constant current source while the Thyristor based SVC output current decreases in direct proportion with the voltage according to its impedance characteristic.

Thyristor based SVC

VSC based SVC UN

UN

capacitive

inductive

ISVC

capacitive

inductive

ISVC

normal SVC operating range temporary SVC operating range Figure 2-26. Principle V/I characteristic of SVC and STATCOM

2.5.7

Harmonic Performance and Filters

The total harmonic distortions at the PCC and within the wind power plant are the overall effect of harmonic injections from the wind turbines, dynamic reactive power plant (SVC, STATCOM) and interactions with the onshore grid. These interactions pose new challenges to utilities and the industry in understanding the individual phenomena, developing appropriate study methods, identifying economic countermeasures for the identified points of concern and proving effective technical solutions. Issues associated particularly with offshore wind power plants include: • A possibility of magnification of low order harmonic voltages from the main grid (inherently 3rd, 5th and 7th) due to the large capacitance of long AC cables. Some of these harmonics may amplify and cause significant stresses down to the offshore MV wind power plant array as well as increase distortion levels at the PCC, causing Grid Code compliance problems. • An increased risk of complex interactions between cable resonances, existing harmonics and control systems. These interactions could result in instability within the wind power plant and unpredicted equipment tripping [10]10.

10

C. Smith and N. Hayward, ‘Use of STATCOM for offshore wind stability and grid compliance’, European Offshore Wind conference, Stockholm, 2009

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•

The harmonic content of transformer inrush current can excite the system resonant frequency. This could result in over‐voltages that may last for a substantial period of time [11]11. • The resonant frequency may shift significantly according to the number of wind turbines energised and the configuration of the circuits connected to the offshore MV wind power plant array. The harmonic resonant frequencies vary in frequency and magnitude dependent on the number of cables and turbines in service. • Given the significant application of power electronics in offshore wind power plants, inter‐harmonics may become important. Guidelines regarding the measurement of inter‐harmonics are given in IEC 61000‐3‐6. • Harmonic studies are required to assess the level of the offshore wind power plant harmonic emission into the point of common coupling (PCC). Standards suggest that power electronic converters for the purpose of harmonic analysis can be simply represented by a harmonic current or voltage source. These simple models have however been shown to give inappropriate results [12]12. Harmonic studies determine whether or not passive filters are necessary as well as their rating and frequency characteristics. The filters could have a significant impact on the wind power plant’s reactive power compensation scheme, and may require large space, affect magnetic contour distances in the substation and noise levels. Therefore harmonic studies should be carried out at the earliest possible stage in the project. Harmonic study methodologies for offshore wind power plants taking into account amplification of background harmonics as well as distortion caused by wind turbine and SVC harmonic injections are presented in [13]13. Requirements and guidelines place maximum limits on various current and voltage harmonics generated and drawn at the PCC. When connecting large offshore wind power plants to the AC system, filters may be required in order to ensure that the injection of harmonics into the grid is limited to acceptable levels. Filtering is required due to the following effects of harmonics: • Additional Stresses; the waveform distortion causes losses, resulting in additional heating and stresses in the equipment. • Malfunction of electronic equipment; harmonics may cause unpredicted equipment tripping within the wind power plant. • Telecommunication system disturbance. There are two main types of filter; passive and active. Traditionally, passive filters have been installed in power systems; however interest in active power filters has grown over a number of years due to more stringent requirements. Passive Filters Passive filters are designed to operate at distinct frequencies and are usually shunt elements creating a low impedance path for the harmonics to be filtered. The filter comprises capacitors and inductors which make up a resonant circuit. 11

R. A. Turner, K. S. Smith,’Resonance excited by transformer inrush current in Inter‐connected offshore power systems’, IEEE, 2008 12 L. Kocewiak, J. Hjerrild, C. Bak, ‘Harmonic models of a back‐to‐back converter in large offshore wind power plants compared with measurement data’, Proceedings of Nordic Wind Power Conference, 2009 13 A. Shafiu, A. Hernandez, F. Schettler, J. Finn, E. Jørgensen “HARMONIC STUDIES FOR OFFSHORE WINDPOWER PLANTS” Published in ACDC 2010 The 9th international conference on AC and DC transmission. October 2010 London UK

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Resistors are included in most cases to give the filter a more ‘soft’ damped characteristic so that impedance variations of the filter (caused by manufacturing tolerances, changes in temperature, frequency variations, etc.) can be taken into account. The resistor not only carries the harmonic currents as desired, but also the fundamental frequency current, resulting in high losses, heating and a possible requirement for forced ventilation. A C‐type filter provides significant reduction in fundamental frequency loss, as the resistor is in parallel with a LC resonant circuit tuned to the fundamental frequency. Active Filters Active filters can cover a range of frequencies, including inter‐harmonics and non‐ characteristic harmonics. They use power electronics to produce a voltage or current waveform to mitigate selected harmonics. Active filters reduce each particular harmonic just by injecting a controlled voltage or current with the frequency of that harmonic. To achieve a specific harmonic performance active filters have smaller space requirements and simpler filter arrangements in comparison to passive filter solutions. Active filters for HV systems are typically shunt connected and equipped with a capacitive coupling impedance. The coupling impedance allows the fundamental frequency voltage at the active filter converter to be considerably reduced. As a side effect the active filter branch provides reactive power and adds resonances with the power system at frequencies that are not actively filtered. The design of the coupling impedance depends on the voltage and current ratings of the converter as well as the harmonics to be filtered. The active filter converter can be bypassed for fundamental frequency current reducing the fundamental frequency loading to a minimum. They can also provide flexibility for changing frequency characteristics within their rated capability. As a power electronic component, an active filter is more complex than a passive filter. As a consequence the reliability of an active filter branch tends to be lower than those of a passive filter. In practice, harmonic performance may therefore be required to be acceptable temporarily with the active filter out of service or adequate redundancy may be required. Active damping functionality could be added to a STATCOM [10]. This technique has been used in the steel industry in MV and LV networks.

2.5.8

Background Harmonics and Active Filters

In principle, active filters can have one of the following two control targets: a) Controlling the harmonic currents of a dedicated branch, e.g. the wind park feeder, to Zero b) Controlling the harmonic voltages at a dedicated network bus to Zero. When successfully implemented, control target a) would make the dedicated branch together with the active filter look like an open circuit at the controlled frequency. That means the harmonic conditions as seen from the network would not change when the dedicated branch together with the active filter is connected to the grid. Pre‐existing harmonic distortions will stay the same as before. It is worth mentioning that adding the active filter will affect the targeted harmonic currents flowing in the dedicated branch, e.g. inside the wind park network. Control principle a) can be applied to as many frequencies (harmonic and inter‐harmonics) as possible within the power rating and control capability of the active filter. All frequencies

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that are not actively controlled can be calculated according to the principles applied for passive filter branches. When successfully implemented, control target b) would make the dedicated network bus look like a short circuit at the controlled frequency. Considering a given voltage distortion at a busbar, an active filter cannot distinguish regarding the sources contributing to that distortion. The individual harmonic frequency voltage distortion will be minimized. At the same time this affects the targeted harmonic currents in the network. The resulting harmonic currents may be important, e.g. with respect to possible telecommunication interference. Control target a) or b) can be preferred depending on the specific requirements of a project. In general, the requirements should allow for certain residual harmonic currents or voltages respectively, which cannot be avoided due to measuring tolerances.

2.6

Fault Level

2.6.1

What is the Limiting Factor on Fault Level?

Electrical networks are characterized by a particular design short circuit capacity, relating to the rating of the switchgear and network equipment. Large wind power plants are typically connected to HV networks and therefore contribute to the total fault level of the network, determined by the combined short circuit contributions of the upstream grid and the various wind turbine sources within the wind power plant. The internal impedance of all generators and system impedance, i.e. cable, transformer impedances will limit the fault level. In order to limit the short circuit to a reasonable value it may be necessary to increase the reactance between the source and the fault, this can be done by avoiding the use of parallel feeds wherever possible, although such practice may not be appropriate and may result in interconnection being lost. The following methods are typically used to limit three‐ phase fault levels associated with offshore AC substation installations: • Use of three‐winding transformers with secondary windings feeding split busbars to effectively split the number of generators connected in parallel at the offshore AC substation. Three‐winding transformers are further discussed in Section 2.6.7 of this document. • If a ring design is implemented in the collector strings, the cable impedance can be used to effectively increase the loop impedance (and reduce the fault currents) with either end connected to an isolated busbar connected through one winding of a three‐winding transformer. • Use of substation transformers with higher impedance to reduce the system fault level contribution at the generators’ point of connection. Introducing additional reactance into offshore power systems in the form of series reactors or fault current limiters is a solution that is not commonly adopted offshore, but has been used to limit fault currents at onshore installations. This family of solutions may however be appropriate for inclusion into future offshore AC substation designs.

2.6.2

Three Phase and Single Phase Levels

When a fault occurs on a power system the usual effect is to cause abnormal currents to flow through the various branches of the system. These currents must be detected by the protective equipment and, if necessary, interrupted by the circuit breakers. If these two items of equipment are to perform their functions correctly it is important that the values of

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the fault currents be known. The types of fault occurrence will fall into one of two categories. Three phase faults All three phases are shorted to each other and often to earth also. The conditions in each of the three phases are similar and the system may be treated from a single phase point of view. Generally it can be regarded that the currents for this type of fault are the highest met and used in the determination of the ratings of the circuit breakers in the system. Phase A

Phase B

Phase C

Figure 2‐27. Three phase fault Asymmetric faults Asymmetrical faults involve only one or two of the phases and comprise of either phase‐ phase‐earth faults, phase‐phase faults or 1‐phase‐earth faults. The magnitude of the currents are generally less than the three phase case, but the calculations are more complex since the system is no longer balanced. An understanding of the magnitude of these currents is necessary for the purpose of calculating the settings of the protective equipment.

Pha se to ph ase fau lts

S ing le p ha se to e ar th fa u lts

Ph ase A

P ha se A

Ph ase B

Pha se B

Phase C

Pha se C

Figure 2-28. Asymmetric faults

2.6.3

Make and Break Fault Levels

Fault currents decrease over time. The make fault level relates to the ability to withstand the mechanical forces caused by the flow of current. The relevant value is the peak short‐ circuit current (Ip) which is defined as the maximum possible instantaneous value of the prospective (available) short‐circuit current (IEC60909‐0 Clause 1.3.8). The break fault level relates to the ability of circuit breakers to interrupt the fault current. The relevant value is the symmetrical short‐circuit break current (Ib) which is defined as the root mean square (rms) value of an integral cycle of the symmetrical AC component of the prospective short‐circuit current at the instant of contact separation of the first pole to open of a switching device (IEC60909‐0 Clause 1.3.9).

2.6.4

Infeed from Grid System

The fault contribution from the upstream grid can be calculated from the PCC equivalent impedance and the cable and transformer impedance, up to the fault point. As wind power plants increase in size, their location will move further offshore and therefore the cable

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impedance will increase. This will decrease fault levels slightly at the expense of increasing transmission losses. More significant however, will be the type of transformer used and its corresponding impedance. If fault levels on the wind power plant prove problematically high, the transformer design can be adjusted to give optimum fault reduction and power losses. Typical fault infeeds from the grid vary depending on the voltage level and grid situation at the PCC, i.e. for voltage levels of 400 kV, 275 kV and 132 kV the 3 phase rms fault levels (break duty) may be up to approximately 63 kA, 40 kA and 40 kA, respectively. With the infeed from most wind turbine generators decaying rapidly with time (as described in the following sub‐section), high fault level design considerations are mostly focussed on the make fault level for offshore AC substations and the limiting of the fault levels at the point of connection of the individual generators. This connection point can be a critical factor for the rating of the switchgear installed in the turbines.

2.6.5

Infeed from Wind Turbines

The type of wind turbines (WT’s) used in the wind power plant will determine the magnitude of fault contribution. Double fed induction generators (DFIG’s), connecting to the collector circuit via a partially rated power converter, would give an instantaneous fault contribution from the DFIG of approximately 6 times normal rating of the machine. Permanent magnet synchronous generators, connecting to the collector circuit via a full scale converter, would give an instantaneous fault contribution from the generator of approximately 1.2 times normal rating of the machine. Rule of thumb assumptions for rms instantaneous fault level contribution from the different generator types is as follows:

Load

Synchronous

SCIG

DFIG

Full scale convertor

In

In

In

In

6 In

6 In

1.2 In

Contribution to Make 7 In fault levels

Table 2‐1. Fault level contribution from the different generator types The fault contribution of these generators reduces with time, and the break fault current contribution can be assumed to be negligible for the SCIG, DFIG and full scale convertor connected generators. A synchronous generator can however contribute up to 4.5 times rated current to the rms system break fault current at its terminals. The greater the number of WT’s per array and the greater number of arrays in total will have an impact on the total fault contribution. The fault contribution from the WT’s are determined from the cable and / or transformer impedance, up to the fault point. As discussed in Section 2.6.4, if fault levels on the wind power plant exceed equipment design levels, the transformer design can be adjusted to give optimum fault reduction and power losses.

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2.6.6

Transformer Impedance Choice (including Interaction with Reactive Design)

Transformer internal impedance is usually expressed as a percentage value (%ZT), which represents a percentage of rated terminal voltage required to circulate full load current in a short‐circuited secondary winding. This internal impedance comprises a reactance derived from the effect of leakage flux in the windings (%XT) and an equivalent resistance (%RT) that represents losses to the current flow (e.g. copper and stray eddy‐current losses). The transformer impedance has a major effect on system fault level since it determines the maximum current flow through the transformer under fault conditions. Essentially, a transformer with a low impedance value leads to high system fault levels, and vice versa. In reality , the actual fault level is also affected by the grid source impedance, the impedance of cables between the transformer and the fault, the type of generators connected and the fault impedance itself, which will be discussed later. Standard designs from manufacturers have an inherent value of impedance determined by established arrangements of core and windings. It may however be desirable to decide on a transformer with impedance greater than standard to limit the short‐circuit duty on downstream switchgear, or to select a transformer with lower impedance to relieve plant energisation by reducing the voltage drop. Transformers with non‐standard impedance characteristics can result in a substantial increase in capital cost. In general, larger core cross‐section and longer winding length minimises the leakage reactance. Since the physical weight and size of the transformer relates to the size of the core; a larger core results in a larger and more expensive transformer. The choice of internal impedance must be based on system and plant fault study results, and should take into account the effects on short‐circuit current and selection of the interrupting capacities of substation and generator circuit breakers, limitation of load losses and on the ability of the generators to aid in voltage regulation. Unfortunately, the task for a substation designer is not straightforward since variation of any of the principal parameters impact the others which will in turn also affect the fault levels. It should be noted that lower impedance values, specifically ac reactance, result in lower voltage regulation, which is generally desirable. However, this is at the expense of increasing fault current. Additionally, voltage regulation increases as the power factor of the LV side becomes more lagging (inductive), therefore, consideration of the wind power plant reactive capability also must be taken into account. There are additional variations to consider with regard to transformer taps and shunt reactive power compensation in order to ascertain the maximum fault currents. Dynamic compensation devices could also contribute fault currents similar to a full‐converter wind turbine. Complete representation of the WPP dictates that the contributions of dynamic reactive devices be included when carrying out fault level calculations.

2.6.7

Consideration of Two or Three Winding Transformers

At present WT’s generate at a voltage level between 690V – 2.4 kV that is transformed to the collector voltage level of 36 kV via 2 or 3 winding transformers. Higher collector system voltage levels may be an option in the future. On the offshore substation, the collector circuit voltage must then be stepped up for onward transmission to shore. These step up transformers used in wind power plant design

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are either 2‐winding or 3‐winding. A 2‐winding transformer is of simpler design marginally cheaper than a three winding equivalent. Transformer tapping on the HV winding can be easily incorporated and the appropriate tap setting chosen to adjust the LV voltage to 1.0 p.u. if required. However this design is, in general, characterised with the highest available fault duties on the MV collector busbar. A 3‐winding transformer offers the opportunity for the collector circuits to be split between the two secondary windings. The parallel impedance of these two windings can be comparable to a two winding equivalent, but when the secondary windings are run split the impedance is increased. This has the advantage of reducing the fault levels at the collector circuit level. A 3‐winding configuration can also offer a better interconnection in terms of redundancy as shown in the figure below. If voltage control using transformer taps is required, it is preferable to have a balanced load on each of the LV windings to ensure balanced secondary voltages.

Figure 2‐29. Typical Three winding connection arrangement For 3‐winding configurations, care must be taken in specifying the impedances between windings as manufacturers have many options which might not necessarily suit the service requirements. Different winding configurations are used in the industry, each with different inherent impedance characteristics that substation designers must be aware of. Such configurations might be: Low‐High‐Low (LHL); Tightly‐Coupled Stacked Secondary (TCSS) and Loosely‐Coupled Stacked Secondary (LCSS) designs. Among other factors to consider in relation to a 2 or 3‐ winding transformer is the fault current contribution from the offshore wind turbines, which, as previously explained is dependent on the generator technology employed.

2.6.8

Effect of Cable Impedance and Stored Charge

As previously mentioned, fault level is further affected by the impedance of cable connection elements between the transformer and the fault. Cable resistance is dependent 76

on a number of factors that include length, material and cross sectional area of the conductor, temperature and burial depth, among others. Cable reactance is dependent on the spacing of the phase conductors and shielding between them. In general, larger spacing between phases increases the reactance and lower shield resistance increases the positive‐ sequence impedance because shield currents and losses are higher. Thinner insulation also increases the positive‐sequence impedance because there is increased coupling between the phase conductor and the shield hence shield currents are higher. The insulation of the cable acts as a capacitor when energised and the core screen has to transfer the associated charging current, distributed along the complete cable length, to the insulation on every half‐cycle of the voltage. This capacitive component will impact on the reactive component of the fault current and its X/R ratio.

2.6.9

Effect of External Faults

The actual fault level at the offshore substation is dependent on the strength of the system source, which has inherent system impedance. A deeper understanding of the fault behavior of the system can be derived from an analysis of the source impedance angles, expressed as an X/R ratio. A stronger grid (i.e. a grid connection close to a major utility substation) will have lower source impedance whilst a weaker grid (e.g. when connecting to a remote distribution line) will have higher source impedance. By adding % Zs (including cable impedance) to %Zt the strength of the source is taken into account when calculating the fault level at the substation MV level.

2.6.10

Operating Scenarios

The presence of two (or possibly more) main transformers at the substation, and a possible bus‐tie on the MV side, allows the system to be managed with the transformers in parallel. One possible operating scenario is having two transformers which operate in parallel on the same busbar. In this case it is possible to use two transformers with lower rated power (e.g. 50/50 per cent of the wind power plant rated power). Higher short‐circuit currents could be generated for faults in the MV system (in comparison with the scenario of a single transformer) due to reduction of the %Zt. In addition a further consideration should be taken into account for protection coordination, due the fact that overcurrent on the MV side is divided between the two transformers. A second option is having two transformers operating simultaneously on two separate busbars (providing a bus‐tie and an interlock). Assuming the same rated power of the transformers installed, this operating scenario allows a lower value of the short‐circuit current on the busbar, i.e. each individual transformer establishes the short‐circuit level of the busbar it is connected to. Considering the possibility that one of the transformers is out of service or faulted, closing the bus‐tie allows changing to a system with a single busbar supplied by the single transformer alone, the change on fault level must be taken into account. Moreover, a control logic must be provided to curtail generation, depending on the power production and the rated power of the remaining transformer. As previously mentioned, the use of a three‐winding transformer allows specification of a low value of “through” impedance and thus increasing the stability limits of the system. In this way, a high value of impedance between the two secondary windings can be achieved, which reduces the interrupting capacity requirements of the generator breakers. Three‐ winding transformers are particularly suitable for offshore wind power plants connected to strong HV grid systems capable of delivering high fault currents. An alternative busbar

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configuration in 3‐winding transformers is to have cross‐connected secondary windings (as shown in Figure 2‐31). This configuration can be operated either permanently or during faulted condition, i.e. in case one of the secondary windings fails, the systems downstream can be reconfigured to operate at reduced load through the unfaulted winding. Fault level change at the MV side should be taken into account.

2.7

General Substation Configuration

The configuration of a conventional substation onshore is mainly determined by the importance of the functionality that the installation is going to develop within the power grid, always following the basic principle of the power distribution business: security of supply for the clients. In this way, the power distribution substations use redundant configurations and automatic transfer systems for a quick adaptation and response of the installation to fault conditions, always in order to provide a continuous power flow according to each utility quality standards. Of course, these design requirements should always be considered along with safety of personnel and environmental issues. The approach for the offshore substations is different since they are step‐up substations of renewable power plants with a variable resource and no marginal costs, so a deeper analysis is necessary to determine the optimum degree of redundancy in every case. The main design guideline for an offshore substation is not keeping a continuous power flow but to achieve a high level of availability for the installation to be ready to convey the available power when it is there. In most of the offshore wind power plants developed to date, this analysis has not taken place and therefore little redundancy has been implemented either for the collector system or the substation configuration; only vital and less costly systems like communications, cooling and fire fighting systems are redundant. As a consequence, some of these installations have faced important losses of income when some important failure has happened. A typical case is the transformer failure at Danish Nysted Offshore Wind power plant in 2007 that caused an outage of the entire installation (165.6 MW) for more than 4.5 months with an assumed loss of energy over 100 GWh. If it is considered that the transformer was disassembled and transported to shore for repair by means of a floating crane and then the inverse process repeated to return the repaired transformer to the offshore platform, this is a very short period. Even then, taking into account the Danish tariffs for this type of generating plants, the lost energy could have provided easily for an additional transformer and the extra cost of the platform to house it. Fortunately, these types of failures are not very common, so a thorough analysis simulated along the life span of the installation should be developed to carry out an optimum redundancy‐driven design as is illustrated in Section 2.1. The purpose of this section is not developing a decision support tool, but to pinpoint and describe the key factors to be considered when designing the configuration of an offshore substation, focusing on the specific characteristics that make it different from an onshore installation. Both the matters related to physical distribution of equipment on the topside and to the electric diagram will be described. The physical platform configuration will be covered in more detail in Chapter 4 In general terms, the configuration of an offshore substation should be designed on the same basis as an onshore one, although this basis has some specific requirements imposed by the marine environment.

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2.7.1

Choice of HV and MV Voltages

It is one of the basic principles of electric transmission and distribution to raise the voltage to reduce proportionally the current for a given power and therefore reduce the losses with the square of the current. In practice, the voltage levels should be adapted to each specific application, taking into account the available range of products complying with the project requirements and making a balance between the higher cost of using a higher voltage and the savings due to the lower power losses. The voltage levels within the electric infrastructure of a wind power plant comprise commonly a medium voltage level for the internal collection system and a high voltage level for the export circuits. In most of the initial offshore wind power plant projects the high voltage level was omitted because of low installed power and short distance to the grid, which allows to feed directly into the grid the energy yield at medium voltage level. Nevertheless, with the continuous increasing in installed power this possibility became unfeasible in practice due to the high number of cables necessary to transport power to shore and therefore a current offshore wind power plant normally includes an offshore substation to step‐up the collection system voltage to the transmission voltage for connection to the power grid onshore. 2.7.1.1 Medium Voltage Level The voltage level of the collection system has been driven mainly by the availability of switchgear and transformers that fit inside the wind turbines. For onshore wind power plants, it is common in many countries to place the switchgear and the step‐up transformer outside the wind turbine, avoiding these kinds of problems. However, this is not possible for offshore wind turbines and the important space restrictions inside the tower and the nacelle of an offshore wind turbine, or even the reduced dimensions of the tower door (which are normally the “go‐no go” criterion for elements to be located inside the tower), the wind turbine manufacturers and installers chose from the beginning SF6 insulated, metal‐ enclosed, secondary distribution switchgear. This is a cheap and widely deployed solution both for power distribution and onshore wind power plants, covering the required switching and protection functions, although with important limits in voltage and current ratings. Given that most of this kind of switchgear is designed, manufactured and tested under IEC standards, the maximum rated voltage is 36 kV thus determining the collection system voltage, which for offshore wind power plants is commonly established at 33 kV to make the maximum use of the switchgear voltage rating (considering a 9% safety margin for voltage regulation along the lines). As mentioned above, the main drawback of the secondary distribution switchgear is the restrictive limit both for maximum voltage and current, which establishes a limit regarding the maximum power that can be conveyed by each one of the internal circuits of the wind power plant. This circumstance entails a big amount of inter‐array cables for offshore wind power plants of several hundred MW of installed power, as well as hindering the possibility of using ring configurations in the collection systems (due to the high current rating needed). This problem can be partially solved by using primary distribution switchgear which provide much higher current ratings (commonly 1,600 or 2,000 A and up to 4,000 A in some cases), although at similar voltage ratings (40.5 as a maximum). By increasing the current rating, more power could be conveyed by each cable although using bigger cable sections and increasing the power losses (the decrease in cable resistance cannot balance the increase in the square of the current).

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Theoretically, it seems of common sense to apply the basic principle of increasing the voltage level for reducing the losses and the cable amount at the same time. Nevertheless, in practice this is not so easy mainly due to aforementioned size issues. There is currently only one manufacturer offering SF6 metal enclosed switchgear up to 52 kV with sizes that could possibly be installed inside some wind turbine towers. If this possibility is assumed as valid the collection system could be designed for 48 kV approximately, although in this case new problems arise, like scaling up the transformer or the internal cabling of the wind turbine to this voltage level. This possibility is intended as feasible in the future, although is currently immature due to the retrofitting process that the wind turbine manufacturers should carry out in collaboration with electric equipment suppliers. In practice this process means time to design, time to implement and time to test and certify so if this possibility was demanded by the market, it could not be implemented immediately. According to [14] the use of higher voltage levels (up to 66 kV) for the collection systems of offshore wind power plants can be profitable for wind power plants near shore (4 km) or with moderate installed power by eliminating the need of an offshore substation14. Anyway, taking into account the current trends of the offshore wind sector, the wind power plants will be bigger and further from shore so an offshore substation will be required. This should not be an obstacle to consider the possibility of using higher voltages for collection systems by means of a techno‐economic analysis, although at the present moment this is not a market reality. It seems that for several years the preferred voltage level of the offshore wind power plant collection systems will remain at 36 kV. Probably the new generation of offshore wind turbines over 5 MW (currently under developing) will contribute to highlight the need for using higher voltages for collection systems (and will provide more internal space for installation of such equipment). Finally, it is necessary to remark that the voltage level of the collection system has a negligible influence on substation design, since the differences between 36 kV and 52 kV switchgear are not significant from either technical or economic points of view within the whole substation. On the other hand, the feasibility of the use of 72.5 kV switchgear for collection systems requires considerable consideration, given the important step both in size and cost regarding the lower levels. 2.7.1.2 High Voltage Level The voltage level of the transmission side of an offshore substation is theoretically driven by minimizing electric losses, taking into account the standardized existing values and optimizing the infrastructure both according to the power to be transmitted and the distance to the grid connection point. Nevertheless, there are other parameters (both technical and non technical) determining the high voltage level of an offshore wind power plant, even more influential than the aforementioned technical ones. In most of the offshore wind projects in operation or under construction, the voltage level for the export system is the typical sub‐transmission one from every country, commonly between 132 kV ‐ 150 kV AC. This range of voltages is a direct consequence of the following reasons: • For the first projects with an offshore substation with installed power around 100 MW, this was the optimum voltage level considering their moderate distances to the shore. 14

R. McDermott, ‘Investigation of Use of Higher AC Voltages on Offshore Wind Power plants’, Garrad Hassan and Partners Ltd, available from www.gl‐garradhassan.com

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•

The grid connection point provided by the transmission or distribution network operator is normally within this voltage range, although in some cases of high installed power it is necessary to install additional onshore step‐up transformers to link the installation with the transmission grid (for example 132/400 kV), and thus provide a suitable way to convey the generated energy. • There is a technical limitation in practice to install three‐core submarine cables over 170 kV given their high diameters and weights. The first 245 kV three‐core submarine cable has been recently ordered for the 400 MW Anholt Wind Power plant (25 km off the Danish coast). This is a significant milestone, which probably will mean the beginning of a wide use of this voltage level for projects of several hundreds of MW in the future. As mentioned above, the voltage level for connection to the grid is not just a technical driven decision. It is to be highlighted that the 132‐150 kV range allows the installation of more than one export line (providing redundancy), which will be less feasible with higher voltages. On the other hand, the next step of AC voltage levels, 400 kV, does not seem to have a very promising future in offshore wind sector due to the following reasons: • The 400 kV switchgear and transformers are quite bulky and not easy to arrange on an offshore platform. • It is impractical to manufacture a submarine three‐core 400 kV cable because it is unfeasible to install even with most advanced of the existing cable ships given its diameter, weight and bending radius. This means that either a lot of development work has to take place in installation techniques or three single‐core cables should be installed. The last option entails an important installation cost increase and a wider right of way on the seabed (which can be a trouble source regarding environmental permits). • Theoretically, a 400 kV AC offshore installation seems to be competitive for installed power over 350/400 MW and for distances above 40/50 km. However, at these distances 400 kV cables will generate a lot of reactive power, making active power transmission very inefficient and is therefore not an attractive option. As a function of the previous reasoning, the following conclusions can be established: The sub‐transmission voltage levels (110‐150 kV AC) will remain as a common solution for energy export systems for the offshore wind power plants under different ways: • Direct connection to the distribution grid onshore. • Indirect connection to the transmission grid onshore by means of an additional step‐ up transformer (for example 132/400 kV). • Connection to an offshore HVDC transmission system by means of an offshore converter substation. This will be a very common solution for bulk wind power transmission in extensive areas of the UK´s Round Three and German North and Baltic Seas. The 245 kV AC level will gain importance for projects up to 350/400 MW and distances to grid connection point above 30/40 km. The HVDC voltage source converters will become the most common solution for development of offshore wind in UK and Germany, including the deployment of Pan‐ European submarine transmission grids mainly in the North Sea.

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2.7.2

MV Busbar Layouts

The medium voltage switchgear will be made up of metal enclosed, SF6 insulated modules, each one representing a complete bay itself, since it includes all the switching, breaking and protection elements, as well as instrument transformers. Therefore, this system allows very high flexibility to define the configuration of the medium voltage system with low space requirements within the offshore substation. The medium voltage busbar arrangement should be approached considering the general design philosophy of the whole installation regarding functionality and redundancy. On the other hand, the switchgear itself should be defined according to the voltage rating (commonly 36 kV), but mainly according to current ratings both for continuous or short‐ circuit operation. For the first offshore substations, the preferred medium voltage configuration has been a single busbar to which are connected all the array circuits by means of breakers, even for wind power plants with moderate installed power like Horns Rev 1 (160 MW) or Lillgrund (110 MW). In the following generation of offshore wind power plants, like UK´s Round 2 or German projects, the power has been increased to several hundred MW and this has called for more elaborated designs of the electric layout of the substations, including the medium voltage system. Many of these new substations are equipped with two power transformers, so the single busbar has been divided into two parts for connection to the two transformers and, in some cases, the transformers have two secondary windings so each one of the medium voltage semi‐busbars has been again divided into another two parts for connection to the two windings.

Figure 2‐30. Single busbar configuration (Lillgrund Wind Power plant).

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Figure 2‐31. Single busbar configuration with two switchable sections for each transformer (Thanet Wind Power plant). It can be observed the cross connection of the semi‐busbars to the three‐winding transformers to avoid loss of supply to one half of the substation in case of a transformer failure. By means of dividing the busbars into switchable sections (normally disconnected) for three‐ winding transformers, it is possible to reduce the short circuit ratings both for the busbars and for each one of the connected bays given the increased impedance of this configuration. For this configuration to provide better availability in case of failure, one could oversize both the power ratings of the transformers and of the export cables. In this way, when a transformer fails, it is physically possible to connect the whole wind power plant to one of the transformers, although the maximum power will be limited by the rating of the windings. The degree of oversizing should be decided as a result of an optimization study in every case. In distribution network installations, the power managed in medium voltage switching stations is very small compared to an offshore wind power plant, but even so is quite common to use double busbars. This may be the next step for medium voltage systems of offshore substations, given that the additional cost is not very significant within the total cost of the substation and the additional redundancy provides total system availability in case of failure of a bay or even of a busbar.

2.7.3

High Voltage Busbar Layouts

The equipment used in offshore substations is not particularly special but their specific environment gives rise to layout challenges. As previously established, the equipment should be gas insulated (GIS) in order to achieve space savings and prevent any contact of live elements with surrounding air or humidity. Regarding the electrical configurations, the design concept for the existing offshore substations in Europe has been driven by simplicity. Therefore, the single busbar or even transformer‐export line joint bays have been the most common configurations in offshore substations. The pioneering offshore substations have a very simple configuration without circuit breakers in the high voltage side of the power transformer. Although this is the cheapest option, it is necessary to guarantee in each case that the onshore breaker is able to interrupt the reactive currents of the joint made up of the export line and the offshore transformer. It is clear that the design of the initial offshore substations was driven by simplicity and economic reasons, showing few redundant elements. From this point of view, if the onshore network can be managed correctly with such configurations, then these could be the most cost‐effective solution for small wind power plants.

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Figure 2‐32. Lillgrund Electric System. Simple Configuration.

Figure 2‐33. Horns Rev I Electric System It is evident that such switching schemes do not provide optimum solutions regarding flexibility in switching operations, redundancy, and selective protections. By this reason, for the new projects involving several transformers in the same platform, different configurations should be considered, like two semi‐busbars separated with circuit breaker or a double busbar or ring for projects with more than one export line. It is important to consider that the high voltage system, in many cases, will be influenced by the utility´s criteria and the final arrangement could be a consequence of the onshore network needs and requirements. Anyway, it does not seem that more complex configurations like breaker and a half or double busbar (common in onshore transmission systems) are going to be used in offshore HV substations, mainly due to size issues. Reference may be made to a new CIGRE brochure on Circuit Configuration Optimisation shortly to be published for possible switching configurations. When multiple export cables are necessary, some redundancy can be provided by placing a number of breakers between the cables and the transformer and between the cables. The configuration in the Figure 2‐34 enables you to isolate either a cable or a transformer separately. In case of a cable failure, one could utilize, maybe even overload, the other cable without overloading the transformers.

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Figure 2‐34. Highly flexible (and expensive) HV configuration

Figure 2-35. Proposed HVAC Electrical design using two semi-busbar separated with circuit breaker.

Besides the aforementioned reasons, to carry out a techno‐economic assessment is strongly recommended, to consider the trade‐off between the initial capital investment, and the lost energy due to unavailability for both scheduled and unscheduled maintenance (which can be of particular concern in the marine environment due to the intrinsic difficulty of working at sea). This may result in some form of redundancy, either partial or full, to be considered in design phase, which will add to the CAPEX, but will increase the availability and thus reduce the lost energy along the lifespan of the installation. Another key factor for selecting a configuration is the capacity of the offshore wind power plant and their distance to the onshore connection point that rules if a conventional HVAC solution will be cost‐effective or, other case, a HVDC solution would be more convenient. Figure 2‐36 shows a solution proposed for a 500 MW wind power plant in the connection study developed for Round 3 wind power plants, comprising two offshore AC substations and two three‐core, 245 kV export cables. On the other hand, Figure 2‐37 shows a possible solution from the same study for a high capacity installation (1100 MW) with a significant distance to the coast. This configuration consists of two HVAC offshore platforms with three

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220 MVA power transformers and two power export cables each one for connection to a HVDC offshore converter station.

Figure 2‐36. Proposed HVAC Electrical design used for the 500 MW wind power plants for U.K. Round 3 (Source: “THE CROWN ESTATE. Round 3 Offshore Wind Power plant Connection Study. Version 1.0”)

Figure 2‐37. Proposed HVDC and HVAC Electrical design used for the 1100 MW wind power plants for U.K. Round 3 (Source: “THE CROWN ESTATE. Round 3 Offshore Wind Power plant Connection Study. Version 1.0”) In the first of the previous cases, the busbars of the two substations are connected by means of breakers. The idea of using two platforms for the same wind power plant could be

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suitable when the area occupied by the wind power plant is very wide and therefore the medium voltage circuits are very long (with high losses and important voltage drops). Given the high cost of an offshore platform, again, it is necessary to develop a study to determine the boundary from which the use of a second platform is the best techno‐economic option. Regarding the configuration of the busbar and taking into account a significant installed power, it is advisable to have some kind of redundancy. It is considered that with a power of several hundreds of MW a double busbar or ring may be justified (mainly if the installation involves three or more transformers and two or more export lines). For installations with two transformers and their corresponding export lines, the semi‐busbars could be the best option. Anyway, none of this reasoning is useful considered alone, in the sense that for any redundant element to be useful, it has to be designed taking into account a design philosophy for the whole installation: from the wind turbines to the grid connection point.

2.7.4

Power Transformer Connections

The power transformers are the main element of the offshore substation due to their intrinsic function of stepping‐up the voltage for power transmission under optimal conditions and due to their size, weight and installation requirements that determines to a great extent the arrangement of the platform. Some of these issues were addressed in previous sections, so in this one the focus will be put on both external and internal connections. The external connections are determined by the use of GIS equipment, while the internal vector group of the transformer should be determined on the basis of the requirements of a power plant step‐up transformer, taking into account the specific operating conditions of both the wind power plant and the onshore network. There are some possibilities to carry out the external connections of the power transformers to both the medium and high voltage switchgear, as follows: 2.7.4.1 High Voltage Connections The connection of the transformer to the high voltage switchgear is determined by the use of GIS equipment. In this way, the connection can be either by cable or SF6 bus duct. If the transformer is close to the switchgear the bus duct can be a good option, although for longer runs it seems more suitable to use a cable connection to reduce the space needs inside the installation and the cost. If a cable connection is used, it will be necessary to design the cable route between the transformer and the GIS equipment, taking into account the minimum bending radii, the required support structures and the crossing or proximity with elements like heat sources, other cables or any equipment sensitive to interferences. On the other hand, the connection solution will determine the type of interface to be used with the transformer: • In case of using a bus duct, oil to SF6 bushings will be used for direct connection to the GIS equipment. • In case of using a cable connection, plug in type of cable connections will normally be used. Alternatively, a wrapped paper, epoxy resin impregnated busbar system can be used, suitable for voltages up to 170 . With this kind of solution the use of pressurized ducts is avoided (used by a common bus duct) although it requires the use of specific accessories (like the oil‐oil bushing needed for connection to transformer).

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2.7.4.2 Medium Voltage Connections The use of SF6 metal enclosed switchgear entails the use of a cable connection, and therefore, the secondary windings of the transformers will be fitted with plug‐in bushings for dry insulated cables. This is a very flexible solution although the route for the cables should be designed considering the mechanical characteristics of the cables along with interferences with other elements of the installation. In case of high currents (connection to big transformers) the use of several cables per phase will be required, although alternatively a solid bus duct system can be used for medium voltage level too. 2.7.4.3 Internal Connections The vector group of the step‐up transformers for offshore wind power plant substations should be selected considering the operation of the inter‐array medium voltage network on one side and the operation of the high voltage onshore network on the other side. The collection system of a wind power plant should be protected against high levels of short‐ circuit power in order to avoid the use of high ratings both for the switchgear or the inter‐ array cables. Given that the usually high installed power of the offshore wind power plants requires the connection to a high capacity grid onshore, the short circuit power on the offshore platform is quite elevated in the high voltage side and, depending on the transformer vector group, in the medium voltage side too. In this way, it is advisable to use star/delta connections that feature a higher impedance than star/star arrangements as well as to reduce the size and weight of the transformer (since a tertiary winding is not needed). Anyway, the vector group should be decided according to the specific conditions of the project.

2.7.5

Compensation or Filters Required on the Offshore Platform

In the case that studies determine that reactive power compensation in the form of reactors or capacitors is needed at the offshore substation, then the connection point should be analyzed. At the offshore platform two possible connection voltages are available for reactive power compensation, namely the high and medium voltage levels. When the purpose is only reactive power compensation, then the medium voltage level offers many advantages, since the equipment requires less space in the platform, less insulation levels and therefore lower price. If harmonic studies determine that filters are required in the offshore platform with the purpose of keeping distortion levels in the offshore platform within certain limits, then the location of such filters has to be carefully analyzed. If for example a high frequency distortion level at the HV side of the platform is above the given limit, and the problem is caused by a background harmonic amplification, the solution to such a problem is to change the impedance seen by this background source through the use of filters in the platform. It may be difficult to influence the impedance seen by the background source at high frequencies by connecting a filter at the MV side of the platform, since at high frequencies the transformer impedance is very dominant. If there are distortion limits to be complied with at the offshore platform, harmonic performance studies (See section 2.5.7) should determine the rating, type and location of such filters, taking into account that connection of filters to HV levels might be costly and challenging.

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2.8

Neutral Earthing

A proper grounding scheme is a vital component of any power system. Improperly grounded systems can result in equipment failures, over‐voltages, and flashovers. The system earthing is designed to limit the maximum earth fault current, in order to avoid dangerous step and touch voltages. To achieve this, different earthing designs have to be used depending on the capacitive coupling to earth of the system. In offshore wind power plants the type and length of cables determine the capacitance of the system and are therefore important for the choice of system earthing design. In three phase systems, the neutral point of a star connected transformer winding is usually used for grounding. In the case of delta connected systems, a special grounding arrangement such as Earthing Transformers or Zig‐zag transformers are used. On the basis of the grounding used, Power Systems can be classified into:‐ • Ungrounded Systems • Direct Grounded Systems • Low Resistance Grounded Systems • High Resistance Grounded Systems • Isolated systems These methods have different properties and give different features to the network, especially at earth‐faults. One method may be suitable for one type of grid while quite inconvenient for another. Traditionally, the direct grounding system is used for HV systems, in transmission networks (above 100 kV) effective grounding is commonly used [15]15. The isolated alternative is typically used for smaller LV and MV networks [16]16. The neutral earthing influences the current and voltage stresses during double and single phase faults with ground connection. Table 2‐2 shows typical levels of voltage rises on healthy phases for different methods of system grounding in networks [15]. Grounding Method Isolated Solid Resistance Reactance Earthing transformer

PhaseEarth voltage 1.73 pu <1.4 pu <1.73 pu <1.73 pu <1.73 pu

Table 2-2. Typical voltage rise on healthy phases for different grounding methods.

In offshore wind power plants the higher repair costs as well as the longer down times in comparison with onshore substations are especially important; therefore there are different priorities to those in classic transmission substations when considering the earthing method. For this goal to be achieved a fast and selective clearing of the fault is needed, at the same time the temporary over voltages in the healthy phases must be effectively limited. Thus, a phase to ground fault in the offshore wind power plant must not lead to a

15

P.Hansen, J.Ostergaard, J.Christiansen, “System Grounding of wind power plant medium voltage cable grids”Nordic Wind Power Conference, November 2007, Roskilde, Denmark 16 th B. Franken, H.Breder, M.Dahlgren, E. Nielsen, ‘Collection grid topologies for offshore wind parks’, CIRED 18 international Conference on Electricity Distribution, Turin, June 2005

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cascade tripping of the wind turbine generators or to endangerment of other offshore network components [17]17.

2.8.1

Alternatives for Neutral Point Earthing in the Collection Network (e.g 36 kV)

Isolated Neutral An earth‐fault in an isolated system may not be selectively detectable. In the case of offshore wind power plants due to long cable lengths the zero sequence impedance is almost a pure capacitance, which is much larger than the short circuit positive and negative sequence impedances. As a consequence the ground fault current in isolated systems is much smaller than 3‐ph short circuit faults and is determined by the capacitance to ground. In systems with very long cable networks the capacitive coupling of the network to earth is significantly increased and as a consequence the capacitive earth fault currents can reach magnitudes which are not allowed by standards [18, 19]18,19. The high voltage stresses caused by the temporary overvoltage (earth fault factor 1.73) during the earth fault in combination with long fault clearing times, can be dangerous for the isolated network and its equipment (e.g. Surge arresters, cables). Furthermore temporary over‐voltages between the conductive and semi‐conductive layers of the cables, caused by faults and transient events, increase the risk of puncturing the cable’s electrical insulation [20]20. Transient over‐voltages caused by single phase to ground arcing faults followed by arc re‐ignition can reach very high values and cause significant damage to offshore equipment [15]. Earthing transformers Earthing transformers are used to provide a ground path to either an ungrounded "Y" or a delta connected system. Earthing transformers are typically used to: • Provide a relatively low impedance path to ground, thereby maintaining the earthing transformer neutral at or near ground potential. • Limit the magnitude of transient over voltages when re‐striking ground faults occur. • Provide a source of ground fault current during line‐to‐ground faults. • Permit the connection of single phase loads when desired. • Allow location and therefore selective clearing of ground faults. Grounding transformers are normally constructed either with: • A ZigZag (Zn) connected winding with or without an auxiliary winding or • As a Wye (Ynd) connected winding with a delta connected secondary that may or may not be used to supply auxiliary power

Wye connected earthing transformers, require a delta connected secondary. The Zig‐Zag connection can be used without a Delta connected winding or the 4‐ or 5‐leg core design normally used for this purpose in distribution and power transformers. Eliminating the need for a secondary winding can make this option both less expensive and

17

R. van de Sandt et al, “Neutral Earthing in Offshore Wind Power plant Grids” IEEE, Bucharest, Power Tech Conference 2009 18 Maßnahmen bei Beeinflussung von Fernmeldeanlagen durch Starkstromanlagen, DIN VDE 0228‐2:1987 19 A.Guldbrand, O.Samuelsson, ‘Central or Local Compensation of Earth‐Fault Currents in Non‐Effectively Earthed Distribution Systems’ 20 S. Johansson et al, ‘AC Cable solutions for Offshore Wind Energy’. Copenhagen Offshore Wind, 2005

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smaller than a comparable two‐winding grounding transformer, and therefore provide grounding with a smaller unit than a two‐winding Wye‐Delta transformer. It is important to understand that Zig‐Zag transformers can also have the ability to provide auxiliary power, and this can be either a Wye or Delta connected load. A solidly grounded system using a grounding transformer offers many safety improvements over an ungrounded system. However, the ground transformer alone lacks the current limiting ability of a resistive grounding system. For this reason, neutral ground resistors are often used in conjunction with the grounding transformer to limit neutral ground fault current magnitude. Their ohm values should be specified to allow high enough ground fault current flow to permit reliable operation of the protective relaying equipment, but low enough to limit thermal damage. Earth fault factors using earthing transformers can reach values of 1.73. When a solidly earthed earthing transformer is used the magnitude of the phase to ground short circuit current can be influenced through: • Changing the zero sequence impedance of the transformer. • The number of grounded transformers. An optimisation is possible as a compromise between the magnitude of the phase to ground short circuit current and the earth fault factor. There is the risk of losing the earthing transformer and thus the effective grounding in case of a transformer fault. In order to reduce this risk redundant earthing transformers or busbar couplers to neighboring earthed busbars should be considered. The grounding impedance using earthing transformers can be tuned by adjusting the transformer’s zero sequence impedance. This type of grounding has been applied in several UK wind power plants as well as in Denmark. Solid Earthing A solid earthing leads to higher phase to ground short circuit currents, which can be quickly cleared with high selectivity with a simple protection concept. Special attention has to be paid to: • The high short circuit current magnitudes which may cause damage at the fault location as well as unacceptable cable sheath currents in case of offshore wind power plant collection grids • Dangerous step and touch voltages. The advantages of solid earthing are: • Fast and selective clearing of faults. • Lower voltage stresses caused by temporary overvoltages. Resistance Grounded System In Resistance Grounding the transformer neutral point is grounded through a series resistance. The resistance is intended to limit the fault current when there is an earth fault. Two methods are used High resistance and Low resistance grounding. Low Resistance grounded systems are used to keep earth fault currents within cable sheath current limits, but high enough to enable quick identification and clearing of a fault. High Resistance grounding, similarly to isolated networks has low ground fault currents, but if properly designed the over‐voltages associated with isolated systems can be avoided [15].

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Reactance grounded system In isolated systems with a strong capacitive connection to ground the capacitive earth fault currents may become problematic. In reactance grounded systems the earth fault current is decreased by using neutral point reactors called Petersen Coils. A special case of reactance grounded system is when the reactance is designed to exactly compensate the capacitive earth fault current, for this case single phase to ground fault currents can be reduced to a very small resistive component, this is called resonance grounding. Resonance grounding sometimes used on overhead distribution systems is not used in wind power plants because of other disadvantages. The disadvantages include • The resulting over voltages in the healthy phases (earth fault factor can reach 1.73 or higher). • The relatively small fault current which is critical with respect to fast selective fault clearing.

2.8.2

Transmission Network (e.g. 145 kV)

Direct grounding in high voltage systems is a common practice [21]21 and avoids over‐ voltages during earth faults. In order to simplify and increase the effectiveness of the export cable protection scheme both onshore and offshore transformer neutral points should be solidly earthed. With this solution the earth fault factor can be kept low (<1.4). Both onshore and offshore ends need to be grounded in order to avoid losing neutral connections to ground during staggered fault clearing (e.g. first clearing of offshore CB then clearing of the onshore CB), which would cause an isolated system for a short time [17].

2.8.3

Trapped Charges and Location of Circuit Breakers.

In case of offshore windpower plants there is a large presence of long Export cables and therefore trapped charges need to be considered. When de‐energising a long submarine cable, due to the capacitance of the cable trapped charges may remain on the cable for a very long time, unless additional equipment is installed to drain the charges (See Figure 2‐38).

Figure 2‐38. Trapped charges when de‐energising export cable. In some cases the offshore end of the cable may be equipped with a disconnector instead of a circuit breaker. In this case when opening the onshore end circuit breaker, the cable will discharge its energy through the offshore end transformer since the transformer neutral is normally earthed (See Figure 2 39). The resulting oscillations will discharge the cable. In case the offshore end transformer is not grounded one of the options below needs to be considered.

21

Anna Guldbrand, ‘Earth faults in Extensive Cable Networks’, Licentiate Thesis, Lund University, Sweden 2009

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Figure 2‐39. Cable discharge when de‐energising export cable.

Y

If the offshore transformer is not earthed at the star point or a circuit breaker is used at the offshore substation, then any voltage transformers fitted on the cable circuit at either end can effectively discharge the cables. Figure 2‐40 shows that a voltage transformer located at the onshore or at the offshore end, can lead to the discharge of the cable after opening of the circuit breakers. The voltage transformers need to be designed so that they can withstand the electromechanical and thermal stresses of the cable discharge, even if this is not their primary purpose (e.g. Voltage transformer for point on wave switching at the offshore end of the cable).

Y

Y Y

Figure 2‐40. Cable discharged through voltage transformers. If the offshore transformer is not earthed at the star point or a circuit breaker is used at the offshore substation, and there are no voltage transformers at either end of the cable circuit then another option to discharge the cables is through the cable earth switch. After opening the onshore and offshore end circuit breakers, an earth switch can be used to create a path to ground for the cable to discharge (See Figure 2‐41). The discharging current has to be regarded for the design of the earthing switch regarding in magnitude and di/dt.

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Figure 2‐41. Cable discharged through earth switch.

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If GIS/AIS equipment is used at the onshore end then the cable earth switch will be a fault making earth switch and it would be recommended that after de‐energising the cable circuit the cable earth switch is closed to discharge the cable and then re‐opened before re‐ energising. This can be made an operational procedure to ensure that the cable is never energised when it still has trapped charge. 2.9 Insulation Co-ordination A detailed overvoltage analysis is necessary to determine the risk of exposing equipment to high overvoltages. The overvoltages can be either short duration (fast front & slow front overvoltages) called transient overvoltages or longer duration temporary overvoltages (TOV), both of which can occur in offshore networks. The practice of insulation coordination for offshore wind power plants follows IEC 60071‐1 and 60071‐2, although the types of overvoltages experienced by electrical equipment are different to those in typical onshore networks. The main source of transient overvoltages in offshore wind power plants is switching operations, unlike overhead line systems where lightning is the predominant source of transient overvoltages. The extensive cable systems in offshore wind power plants combined with a large number of step‐up transformers at the wind turbines also results in many surge impedance boundaries, where voltage reflections can occur and possibly cause flashovers. This means that there will be different levels of stress on the insulation of electrical equipment depending on its location within the system [22]22. A key point to note about cable systems is that the surge impedance is around 40Ω which is much less than overhead lines, where it is typically 300 ‐ 400Ω. This difference has an impact on the time derivative of transient overvoltages, as a lower surge impedance results in a higher time derivative of the transient overvoltage. Proper coordination of surge‐protective devices with the insulation strength of electrical power equipment is essential for protecting the offshore substation from overvoltages. System operating voltages can be classified into five groups according to the IEC 60071‐1. These are Continuous Operating Voltage, Temporary Overvoltages, Slow Front (switching), Fast Front (lightning) and Very Fast Front.

2.9.1

Continuous Operating Voltage

With respect to the Continuous Operating Voltage, the remote ends of radial array cables may operate at higher voltages when the grid voltage is high and the wind power output is high. The arrester Maximum Continuous Operating Voltage (MCOV) has to be selected according to this high operating voltage including the effects of harmonics which could increase the system peak voltage. The export cables will also see a steady state voltage rise when one end is opened. Typically shunt reactors may be required to keep the voltage down to acceptable levels.

2.9.2

Very Fast Front Transients

Whilst Very Fast Front transients are usually associated with the switching of disconnectors in GIS, they could occur in offshore wind power plants due to the reflections within the network. Very Fast Front transients are not covered by standards. A number of mitigation

22 Lars Liljestrand, A. S. (2007). Transients in collection grids of large offshore wind parks. Wind Energy, Volume 11, Issue 1 , 45‐61.

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methods were tested in an Elforsk report [23]23, with the combination of surge capacitor protection and surge arresters performing best.

2.9.3

Fast Front Overvoltages

Often the Lightning Impulse Withstand Voltage (LIWV, also known as BIL) and Switching Impulse Withstand Voltage (SIWV, also known as SIWL or BSL) are already given for equipment, and verification of the standard insulation levels is required rather than the selection of them. This is usually the case for offshore wind power plants, where the equipment may have been ordered well in advance. In this situation, an inverse approach to the insulation coordination procedure given by the IEC may be required. The usual insulation coordination process for wind power plants is to select the insulation level of the transformers, select the surge arresters required to protect that insulation level, and then determine the amount of transient over voltage which can be withstood [24]24. The direct influence of fast front overvoltages from lightning is unlikely to occur in the closed cable systems associated with offshore wind power plants. The same is of course true for backflashovers as there are no overhead lines. However, induced voltages due to lightning strokes on the wind‐turbine towers themselves will occur, but the induced voltages hardly go above 300 kV peak. Today there is too little service experience of these lightning induced phenomena to conclude whether special precautions are necessary or not.

2.9.4

Slow Front Overvoltages

Slow front overvoltages are mainly coming from switching operations or capacitor discharges if filters are used. Slow front overvoltages could occur during energization and during disconnection in normal operation or during a fault. Ground faults could also produce transient overvoltages in a similar way to switching operations, so they are included here. Switching studies need to be carried out on both the MV collection network and the HV export network. Typically, the transformer is a buffer but the transfer of overvoltages via the transformer interwinding capacitance should be examined. Collection or array studies Vacuum circuit breakers (VCB) are often selected for the MV networks in offshore wind power plants, due to their high reliability and very good switching properties. Vacuum circuit breakers are however able to interrupt high‐frequency currents, which can cause multiple pre‐strikes and multiple reignitions in some cases. The SIWV is not specified in the IEC standard for rated voltages of 245 kV and below, because normally the level of switching surges is much less than the level of LIWV and covered by it. Test conversion factors given in IEC 60071‐2 can be used to convert required switching impulse withstand voltages to short‐duration power‐frequency and lightning impulse withstand voltages. The conversion factors are 1.0 for solid insulation, 1.1 for liquid insulation and 1.25 for GIS. This means that by dividing the equipment LIWL by the conversion factors as well as safety factors, the maximum permissible transient

23

Reza, M. and Breder, H., (2009) Cable System Transient Study, Vindforsk V‐110. Experiments with switching transients and their mitigation in a windpower collection grid scale model, Elforsk report 09:05. Available from http://www.vindenergi.org/Vindforskrapporter/09_05_rapport.pdf 24 IEEE PES Wind Plant Collector System Design Working Group (2009). Wind Power Plant Grounding, Overvoltage Protection, and Insulation Coordintion. IEEE Power & Energy Society General Meeting. Calgary.

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overvoltages can be obtained. Below the typical causes for transient overvoltages in offshore wind power plants are listed. Array cable energisation Energisation transients within the wind power plant will be different depending on how many radial feeders are already connected and energized. The surge impedance at the source side of the VCB reduces for each feeder which is already energized. This results in a lower voltage drop at the MV busbar, as seen Figure 2‐42.

Figure 2-42. Three phase voltages at the MV platform during energisation of a radial. A) when no other radials are connected. B) when all other radials are already energized.

The lower surge impedance at the source side of the VCB also means that any reflected voltage wave coming from the feeder being energized sees a lower surge impedance when it reaches the busbar, resulting in a reflection back into the feeder. The effect of this can be seen Figure 2‐43. The voltage magnitude at the terminals of the wind turbine transformer is higher when the radial is energized with no other radials connected. The rate of change of voltage at the terminals of the wind turbine is higher when the radial is energized with all other radials already connected.

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Figure 2-43. Voltage in phase B at the terminals of a wind turbine in a radial being energized. A) when no other radials are connected. B) when all other radials are connected.

The travelling wave characteristics of the cable system can be seen Figure 2‐44. There is a high rate of change of voltage close to the vacuum circuit breaker at the platform. As the wave reaches each successive turbine in the radial, it becomes rounded due to the damping in the cable. When the wave reaches the last wind turbine in the radial (WT8 in the example shown), the wave is visibly rounded and the voltage is nearly doubled due to the wave meeting the open end of the radial. Due to this doubling effect within the radials, surge arresters located within the offshore substation may not provide good overvoltage protection for the equipment located along the radial. For this reason, surge arresters may need to be located at the ends of each radial.

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Figure 2‐44. Voltage wave in one phase as it propagates through a wind turbine radial during energisation when all other radials are already energised. The red waveform represents the voltage at the array side of the circuit breaker. The other waveforms show the voltage seen at the base of each wind turbine. The different coloured circles from wind turbine 1 (WT1) to wind turbine 8 (WT8) correspond to the colours in the graph. Ground Faults in the Array A single‐line‐to‐ground fault will cause the unfaulted phase voltages to rise if the X0/X1 ratio at the fault location is greater than one. Very fast transient voltages could occur if a single‐ line‐to‐ground fault occurs in a location where there is a short length of cable connected to a transformer. This could be the case if a single‐line‐to‐ground fault occurs at the base of a wind turbine and there is a short length of cable to the transformer. The fault would cause a step voltage and travelling waves similar to the case shown for energization, however there would be a much higher repetition frequency due to the shorter cable length to the first reflection point. An example of this situation can be seen in Figure 2‐45. The frequency of the voltage wave between the fault location and the closest transformer can reach hundreds of kHz. The wave has a lower frequency and is heavily damped once it reaches the last transformer in the radial.

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Figure 2‐45. Phase‐to‐ground voltages at the first wind turbine transformer (red) and last transformer in a radial (blue) after a single‐line‐to‐ground fault has been applied at the base of the first wind turbine. Array cable disconnection The step voltages caused by opening a vacuum circuit breaker which connects a radial to the offshore substation are similar to those that occur during energization. The main difference between energization and disconnection transients is the magnitude of the overvoltage. In the disconnection case, multiple reignitions may occur, resulting in an escalation of voltage due to the increasing dielectric strength of the vacuum circuit breaker as it opens. An example of this is shown in Figure 2‐46, where there are a total of 5 reignitions (2 in one phase and 3 in another phase).

Figure 2‐46. Three phase voltage and current across a VCB which is clearing a SLGF in a radial.

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Reactor switching Switchable reactors can be used to compensate cable charging currents in offshore wind power plants with long cables. To limit possible over voltages during disconnection due to circuit breaker re‐strikes or re‐ignition, controlled switching and arresters can be used. When using vacuum breakers, high frequency voltage oscillations in the reactor can occur during disconnection due to circuit breaker re‐strikes. The use of special RC damping circuits may be employed to avoid current zero crossing after the first re‐strike and therefore prevent high frequency voltage oscillations and damage to the reactor. For HV export cables it is unlikely that vacuum CBs will be used, although the principles are still valid. Circuit breakers can be tested for transient recovery voltage (TRV) associated with fault clearing, however routine switching will cause the generation of very fast transients which if unchecked will damage insulation and contacts. In both cases, the designer needs to be confident that the condition and capability of the CB is not compromised for both fault clearing and routine switching when operated near reactors. Phase to phase faults The extensive use of three phase cable and GIS results in a greater possibility of phase to phase faults occurring, more so than on phase segregated technologies used at 300 kV and above. These can be onerous but more importantly, difficult to protect using surge arresters which are generally specified for phase to earth operation. Where the risk of over‐voltages is identified then phase to phase arresters may be required and requirements should be discussed with the manufacturer.

2.9.5

Temporary Overvoltages

While fast front and slow front overvoltages typically recede to normal steady state levels within a few cycles a temporary overvoltage (TOV) can last for seconds. Below the typical causes for TOV in offshore wind power plants are listed. Transformer Energisation Inrush currents occur during transformer energisation when the core becomes saturated. Inrush currents can have a very high magnitude and significant harmonic content. The harmonic rich transformer inrush currents can interact with the harmonic resonances of the power system and result in overvoltages lasting several seconds [25]25. In the case of offshore wind power plants high inductances (relatively weak power systems) and higher capacitances (long cables) yield lower resonance frequencies and a higher chance of TOV. In addition the more extensive use of cable is likely to result in longer duration resonance conditions (many tens of seconds) Ground Faults As described in section 2.9.4 ground faults can cause transient overvoltages, however they can also cause temporary overvoltages lasting for seconds, depending on the system protection settings and grounding strategy. For more details refer to Section 2.8.

25

Turner, R.A. and Smith, K.S. (2008) Resonance Excited by Transformer Inrush Current in Inter‐Connected Offshore Power Systems. in Industry Applications Society Annual Meeting, IAS '08. IEEE

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Load rejection Temporary overvoltages could occur immediately after the main circuit breaker at the onshore connection point disconnects the wind power plant from the rest of the transmission network, so the wind power plant and Export cable goes into isolated operation [26,27]26,27. Depending on the protection system of the wind turbines, they may continue to inject active current into the isolated network, charging its capacitance. Once the turbines disconnect, the energy stored in the long AC cable capacitance and the shunt reactor inductance could oscillate with a low frequency, leading to high overvoltages lasting for several seconds. In this case, overvoltage protection which is able to absorb the energy from the cable/reactor system may be applied.

2.9.6

Mitigation Strategies

Protection setting review A full transient analysis review should identify the extent to which transients will affect equipment at the onshore point of coupling to the existing network. Attention tends to be paid to the primary equipment withstand capability, however it is the sensitivity of protection settings which is more likely to result in inadvertent tripping and the associated loss of supply. A subsequent review of the historical protection settings to the new offshore network should prevent un‐necessary problems during commissioning and faults. This may obviate the need for POW switching and some surge arresters. Point on Wave Switching Point on Wave switching is one method employed to reduce transients by controlling each of the three poles in the circuit breaker individually, closing (or opening) each pole with a certain time delay. Different time delays are used depending on whether the load is capacitive or inductive. It may be difficult to derive suitable synchronization parameters in cases where there is both capacitive (the Export cable) and inductive (the offshore transformer) loads [28]28. Many circuit breakers use a common operating mechanism for all three phases, so point on wave switching would not be possible for these circuit breakers. Furthermore, the method also requires Voltage Transformers (VTs) at the circuit breaker. If the VT is on the cable side of the circuit breaker it will provide a discharge path once the circuit breaker has opened, so it will be necessary to ensure that the VT is suitably rated to routinely discharge the cable and still be able to operate within its thermal capability following any fault conditions. Selection of Surge Arresters The rated voltage of the surge arresters should be selected based on the actual Maximum Continuous Operating Voltage (MCOV), the temporary overvoltages in the system. Modern gapless metal oxide surge arresters conduct currents at all levels which makes them TOV sensitive. The currents are largely capacitive for operating voltages below the MCOV. At 26

Akhmatov, V. (2006). Excessive Overvoltage in Long Cables of Large Offshore Wind power plants. Wind Engineering, Vol. 30, No. 5 , 375‐383. 27 W. Wiechowski, P. B. (2008). Selected Studies on Offshore Wind Power plant Cable Connections ‐ Challenges and Experience of the Danish TSO. Power and Energy Society General Meeting ‐ Conversion and Delivery of Electrical Energy in the 21st Century (pp. 1‐8). Pittsburgh, PA: IEEE. 28 Larsson, A. (May 2008). Practical Experiences gained at Lillgrund Offshore Wind Power plant. Wind Integration Workshop. Madrid: Energynautics.

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higher voltages the arrester starts to absorb energy according to its VI characteristic. All the expected TOV magnitudes and durations should be compared with the manufacturer’s TOV capability curves (power frequency voltage vs time characteristic Figure 2‐47) for the surge arresters installed. Typical TOV causes in offshore windpower plants are described in section 2.9.5.

Figure 2‐47. Power frequency voltage vs time characteristic of a surge arrester The surge arresters’ energy capability is determined by the IEC line discharge classes, which assumes that switching surges occur in a system with surge impedances of several hundred ohms (i.e. overhead transmission circuits). Offshore networks exhibit a low surge impedance due to the extensive cable networks, consequently the energy capability of metal oxide surge arresters may be reduced if the currents are significantly higher than the values stated for typical line discharge currents. These energy stresses have wave shapes more similar to capacitor discharges. Unless manufacturers’ catalogues give those energy capabilities, manufacturers should be consulted if higher energies than those given for the line discharges are needed and it may be necessary to consider special designs of arrester. Phase‐to‐Phase Overvoltages Arresters are typically installed phase to ground, so they may not provide adequate phase‐ to‐phase protection for delta connected transformer windings. Increasing the phase‐to‐ phase insulation strength (LIWL) of the transformer may not be possible due to the fact that the transformer may have been ordered a few years in advance. Phase to phase surge arresters could be installed in either of the arrangements shown in Figure 2‐48. If they are required, consideration of their location should be made as there is limited space on the offshore platform. The energy handling capability for phase to phase of phase to ground faults needs to be studied.

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Figure 2‐48. Configurations for phase‐to‐phase surge arresters.

2.9.7

Conclusions and Further Work

Detailed electromagnetic transient simulation (EMT) studies are required for each particular case. These are described in 2.11 System studies required. Further Work The waveforms experienced within an offshore wind power plant can be significantly different to the test waveforms specified by the IEC. This raises the question as to whether the standard waveforms are appropriate. CIGRE WG C54‐142 “Electrical Environment for Transformers” is currently looking at this issue and will be including recommendations on standards for waveforms. The work of CIGRE WG A2/C4‐309 “Electrical Transient Interaction between Transformers and the Power System” may also be relevant. It is very difficult, if not impossible, to obtain models of wind turbines from manufacturers for transient studies. It has been suggested to form a new CIGRE working group with the aim to produce a ‘benchmark’ transient model for DFIG and full converter wind turbines.

2.10

Flicker and Voltage Fluctuations

2.10.1

Flicker

Voltage flicker is an entirely human perception/irritation problem. A cyclically varying voltage source supplying the power to incandescent bulbs will cause a cyclical variation in the bulbs’ luminescence which above a certain level will be perceived by many people and may cause irritation. This generally results in complaints to the electric utility operators to alleviate or remove the problem. Scientific studies have shown that the level of variation of luminescence that people will tolerate is a function of the frequency it is occurring at. This is defined in the international flicker curve (shown below) and it is defined from 1mHz up to 15Hz and varies from 3% voltage variation at 1mHz and a minimum of 0.3% variation at 8.8Hz (a particularly sensitive frequency as it coincides with the brain’s alpha waves as is associated with inducing hypnosis in some people subjected to it)

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Figure 2‐49. Tolerance level for Voltage variation against frequency.

2.10.2

Levels of Flicker

The perception by people of variation in an incandescent bulb’s luminescence is a complex process that involves the bulb, eye and brain and whilst being a function of frequency it is also a function of duration of its occurrence. In order to standardise the measurement of flicker levels that took account of all of these processes a standardised flickermeter was developed as is defined under IEC61400‐4‐15 ‘Flickermeter – Functional & Design Specifications’. This meter ultimately produces 2 metrics of the level of flicker being measured. Pst is the short‐term flicker level over a 10 minute period and a value of 1 means it is at the level defined in the international flicker curve above. Plt is the long‐term flicker level over a 2 hour period and is essentially the cubed root of the average of the cubed Pst values in that 2 hour period. Typically in an electric grid today there would be background Pst & Plt flicker levels of between 0.2 and 0.4. In grid code requirements for generators or loads connecting to the HV system, typically they would require it to have a Pst value of less than 0.8 and a Plt value of less than 0.6.

2.10.3

Sources of Flicker

In the past, flicker was a problem of varying loads in industrial processes. Arc‐furnaces and welders were typical causes of significant flicker problems. Traditional generators such as hydro, gas and steam plants caused almost no flicker as they had very stable outputs but with the advent of wind power generators these are now also becoming a source of flicker. This is because wind turbines have a variable output which is due to the natural variation in wind input, wind turbulence and the wind turbine’s uneven power output as it completes each rotation. IEC61400‐21 defines how to measure and report a wind turbines flicker performance under continuous and switching operations. The total flicker of a number of wind turbines is generally accepted as the quadrature sum of their individual flicker contributions, but only if they are completely independent of each other. In general, whilst the flicker performance of early fixed speed wind turbines with simple control systems was poor, modern large wind turbines have improved their performance with variable speed operation, back‐to‐back converters and pitch regulation. Also for a given change in output

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power from a wind turbine the actual level of flicker produced is a function of both the short circuit level and the grid angle (X/R ratio) of the connection point. As early wind turbines were connected in remote locations with weak grids and low X/R ratios the level of flicker being produced was higher.

2.10.4

Mitigation of Flicker

Taking into account the sources of flicker, the following are typical measures employed to reduce flicker to acceptable standards at the grid connection point (PCC ‐ Point of Common Coupling): • Specification of the best flicker‐performing wind turbines possible (should be in their evaluation criteria) • Increase the short circuit level at the PCC (and grid angle if possible) • Modify the wind turbines back‐to‐back converter control system to improve flicker performance • Use of an SVC or similar device to smooth windpower plant output to acceptable levels • Limit and optimise switching operations in order to maintain flicker levels within gridcode limits

2.10.5

Voltage Fluctuations

Apart from the reasons mentioned in Section 2.10.3 Voltage Fluctuations in offshore windpower plants take place due to: • Energisation of main electrical components • Variation in wind speeds (wind turbine output) The magnitude of the voltage fluctuations at the point of common coupling (PCC) are normally limited by Grid Codes or connection agreements, therefore studies need to be conducted in order to determine their magnitude and possible countermeasures. In some Grid Codes (e.g. UK grid code engineering recommendation P28) the maximum limit of the voltage fluctuation may vary depending on the frequency of occurrence. This could affect for example the energisation procedure waiting times, between switching of main electrical components. • Energisation of transformers: A typical case to be considered is the energisation of power transformers. When energizing transformers, large inrush currents could cause voltage fluctuations which may exceed Grid Code limits at the PCC. Both onshore and offshore transformers should be investigated. In case the inter‐array cable strings are energized with all wind turbine transformers, this should also be included in the investigations. Worst case switching instant, as well as worst case transformer residual flux and system strength should be taken into account. The voltage fluctuations due to saturation of a transformer can cause subsequent saturation of other transformers which may lead to extended saturation effects inside the network. It is therefore recommended to include all relevant transformers into the corresponding transient system studies. • Energisation of export cables / Filters: The energisation of export cables or filter units may also cause voltage changes at the PCC which should also be investigated.

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Apart from the mitigation strategies mentioned in Section 2.10.4, the following may be considered in order to reduce voltage fluctuation at the PCC during energisation of main electrical components. • Pre‐inserted resistors • Point on wave switching

2.11

Systems Studies Required

In order to bring together all the relevant aspects in the complex process of designing large offshore wind power plants, several system studies need to be carried out. The Design aspects can be summarized as follows: • Grid Code compliance • Reactive power • Harmonic Performance • Static and Dynamic Stability Performance • Wind Power plant and export circuit component ratings • Protection and Safety All of these aspects should be addressed through comprehensive system design studies. These studies are listed below followed by their main objectives.

2.11.1

Load Flow Study

The main objectives of a Load Flow study should be: • To determine reactive power capability requirements at the Point of Common Coupling (PCC) and identify the requirements for a reactive compensation plant in order to comply with the Grid Code. • To check current ratings of cables and transformers for violations of their limits in order to establish correct cable cross section and transformer ratings. • To calculate voltages at various points in the Wind Power plant to ensure they are within acceptable limits. • To calculate active power losses throughout the Wind Power plant • Determine tap changer range of both onshore and offshore transformers.

2.11.2

Short Circuit Study

The main objectives of a Short Circuit study should be: • To calculate maximum Short Circuit currents in order to determine the required rating of cables and switchboards at different voltage levels and locations within the Wind Power plant network. In case these switchboards are already selected the maximum SC currents are used to check whether their ratings are exceeded or not. • To determine the settings of overcurrent protection devices by calculating maximum and minimum SC currents in order to correctly detect symmetric and asymmetrical faults at any location within the Wind Power plant network. • To calculate maximum and minimum single phase to ground currents within the Wind Power plant in order to determine ground fault protection settings.

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•

2.11.3

To determine maximum short circuit contribution from the wind turbine generators to the point of common coupling.

Harmonics Study

The main objective of this study is to assess the voltage harmonics to be expected at the grid connection point when the Wind Power plant is connected in order to demonstrate conformity with the Grid Code. Additional objectives are: • To derive the resonance behaviour given by the cables, transformers, reactors and WTGs connected to the network • To calculate harmonic impedance frequency scans for various system configurations to identify any resonance problems. • Identify countermeasures to eliminate / mitigate the encountered resonance problems • Verify and provide the necessary measures to limit the harmonic distortion at the PCC • Evaluate WTG converter interactions with the grid as well as existing control systems, in order to examine possible resonance conditions that may cause instability and unexpected tripping

2.11.4

Insulation Coordination Study

The purpose of insulation coordination study is to specify the necessary insulation withstand levels for all the primary components within the Wind Power plant. Further objectives are: • To calculate maximum voltage stresses on the Wind Power plant components through EMT simulations. • To identify and specify protective measures such as surge arresters in order to avoid dangerous transient over voltages that can cause equipment damage.

2.11.5

Electromagnetic Transient Studies

Detailed electromagnetic transient simulation (EMT) studies are required for each particular case. There is a reasonable amount of information and guidelines available regarding the modeling of MV and HV equipment for EMT studies IEC60071‐4 ‘Computational guide to insulation coordination and modelling of electrical networks’ is a good source. The credibility of these studies relies on the quality of information available, which is often limited, and the models being used. The magnitude and wave shape of the overvoltages depend upon the instant that the investigated event (Energisation, disconnection, fault, load rejection, switching impulses etc.) occurs, therefore many simulations should be made with different instants of occurrence for the same event. There are usually many more scenarios (they can easily reach hundreds) required for offshore wind power plants than for onshore because of the different configurations of the wind park network. Since TOV such as overvoltages caused by transformer energisation are largely determined by system resonances, scanning the wind park impedance helps identifying the most critical conditions with respect to the TOV.

2.11.6

HV Export network transient studies

The configurations chosen for the connection of the export cables to shore will determine the nature of transients to consider. Vacuum circuit breakers are not employed on the HV 107

network, so chopping and re‐ignition are less of a concern, however the capacitance trapped in the long cables and high operating voltage generate some onerous condition when energised. The nature of the transients generated during switching or faults in a predominantly cabled network will be quite different in shape and amplitude to that of an overhead line network (longer in duration and possible higher in energy). The combination of transformers and cables provide a very harmonic and resonance rich spectrum of transients that could affect protection, particularly if it is based on traditional OHL design principles. The key points to consider include: • The size of inrush currents and the energy handling requirements of surge arresters, prior to specifying any surge arresting equipment. • The impact of transients where export cables connect to the mature onshore network – The studies should identify the profile of the transients generated within the onshore substation, existing protection settings sensitivity should be checked particularly with regard to the duration of inrush currents and overvoltages associated with resonance. Where point on wave is considered, the impact of incorrect VT wiring or timing failure should be examined on the adjacent plant.

2.11.7

Flicker and Voltage Fluctuation Study

During continuous operation each WTG in the wind power plant experiences a continuously changing mechanical input power. This is caused by the variability of the wind itself, as well as by phenomena such as tower shadow (mechanical torque pulsation caused by the blades passing the tower) and wakes. Voltage flicker is the distortion of the voltage waveform resulting from these variations in mechanical input power. The study aims to assess the voltage flicker emission at the point of common coupling (PCC) resulting from continuous operation and from switching actions of the WTG in the wind power plant. Calculations of the summarized flicker emission at the PCC should take into account IEC standards 61400_21 and 61000‐3‐7. Additional objectives of the study are: • To calculate the voltage drop at the PCC resulting from the energisation procedure of the wind power plant’s main electrical components and check for Grid Code compliance. • To identify and specify measures (e.g. Point on wave switching, pre‐inserted resistor switchgears) in order to comply with Grid Code requirements for voltage fluctuations at the PCC

2.11.8

Dynamic Stability Study

The main objectives of a Dynamic stability study should be: • Simulate how reactive power output of the wind power plant module(s) reacts to positive and negative voltage changes at the PCC • To determine whether the simulated reactive power output of the wind power plant module(s) is Grid Code compliant with regard to steady‐state value and dynamic response • To determine whether the wind power plant module(s) behave(s) stably for voltage steps beyond the reactive power limits • To simulate the response of the wind power plant module(s) to symmetrical and asymmetrical voltage sags at the PCC of various depths and duration.

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•

2.11.9

To assess whether the wind power plant module(s) are able to ride through these voltage sags and show a stable post‐fault behaviour (in accordance with Grid Code Fault Ride Through requirements)

Safety Earthing Study

High voltage installations require an earthing system to protect human life against excessive touch voltages and to keep transferred potential to a minimum. Therefore the main objectives of the Earthing Study should be: • Calculation of required cross section for different components of earthing system with regard to thermal stress • Determination of tolerable touch voltages • To keep tolerable limits given in Standards IEEE, IEC, BS • To control dissipation of fault currents to ground • Determination of impedance to earth of the earthing system • Calculation of ground potential and Hot Zone

2.11.10 Neutral Grounding Study The study should recommend adequate types of neutral grounding after investigating current stress and voltage stress as well as interconnection to the onshore HV network. The main objectives of the study are: • To check the design parameters concerning earthing of HV, MV transformers and earthing transformers if applicable. Alternatively, design parameters can be determined considering required limitation of short circuit currents or voltage stress or other requirements out of specification • Calculation of zero sequence current contribution of transformer neutrals • Calculation of power frequency voltage stress during 1_phase short circuit

2.11.11 Protection Coordination Study The protection coordination study is of great importance to personnel and equipment safety. The main objectives of a protection coordination study should be: • Design of the protection philosophy and selection of the individual protection devices • Dimensioning of current transformers • Determination of the settings of the individual protection devices

2.11.12 Electro Magnetic Field (EMF) Study The main objective of this study is to evaluate electromagnetic fields at the station(s) with respect to human exposure. It should give a quantitative description of the levels of electromagnetic fields associated with the operation of the station(s). The levels of electromagnetic fields should cover: • Magnetic flux density at the power frequency (e.g. DC / 50 Hz) • Electric field strengths at the power frequency (e.g. 50 Hz) The study should describe the field sources, the levels of electromagnetic fields in the areas under consideration and the assessment of the field strengths with respect to requirements concerning human exposure.

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3.

Electrical Equipment Considerations

3.1

Introduction

This section gives guidance on how to write the technical specifications for the main electrical equipment to be located on the offshore substation. These are MV Switchgear, Main Transformers and Reactors, Auxiliary transformers, HV Switchgear and Export and Array Cables. When considering the specification aspects for equipment these can generally be divided into four main sub groups as follows:‐

3.1.1

Parameters coming from the System Studies

These parameters are technical requirements such as the short circuit level, full load current, lightning impulse withstand level, transformer impedance etc.

3.1.2

Parameters Defined by the Operation and Maintenance Regime

These parameters are the requirements for modularity, any requirements for condition monitoring, need for special tools e.g. tap changer removal tools.

3.1.3

Parameters Specific to the Type of Plant Itself

These are items specific to the type of plant itself and could cover environmental considerations, vibration and transport forces, special technical considerations and physical and interface requirements.

3.1.4

Important Items to Define to the Platform Supplier associated with regard to the Accommodation for the Equipment

It may well be necessary for the equipment supplier to define to the platform supplier specific requirements for the room in which the equipment is to be accommodated. In the following chapters of this section these four basic aspects will be considered for each of the main items of equipment. 3.2

MV Switchgear

3.2.1

Aspects of Specification which come from System Studies

3.2.1.1 Voltage and Current Ratings The voltage of the array collection system will have been studied and decided in the system studies described in Section 2 of this brochure. For virtually all offshore wind power plant systems which have required an offshore substation the voltage has been 33 kV nominal i.e. 36 kV IEC rated voltage. For further information on collector voltage considerations please refer to Section 2.7.1. If we consider the current rating of the array collection circuits then 40MVA would require a current of approximately 700A thus requiring the use of 1250A panels. If the array collection MVA is limited to 36 MVA then 630A panels could be used. For the transformer incomer circuits, most manufacturers will manufacture panels rated up to 2500A maximum. This means that the maximum transformer winding rating which can be connected via a single circuit breaker is 142 MVA. It is possible to connect higher winding ratings by means of connecting two panels in parallel to achieve the higher rating but adequate allowance has to be made for the unequal sharing between the two panels. It is expected that ratings up to approximately 250 MVA could be accommodated in this way. The next current consideration is the current rating of the busbar. Certain manufacturers may offer a busbar rating up to 4000A. This equates to a rating of 228MVA. This does not

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mean that the maximum load which can be accommodated on the switchboard is 228MVA but it does mean that the relative placing of the circuit breakers on the board needs to be taken into account. Based on the considerations above the current ratings of the array cable circuits, the transformer incomer circuits (including if two are required in parallel) and the busbar rating can be defined in the specification. 3.2.1.2 Fault Level Ratings The fault level required for the switchgear will have been defined by the short circuit study. Fault level rating of the 36 kV switchgear in the substation is never a problem, as switchgears with short circuit ratings up to 40kA at 36 kV are fairly readily available on the market. The normal limitation on short circuit level is the rating of the ring main units at the transition pieces on the WTGs which frequently are rated at 20kA. The fault level rating at the substation switchboard should therefore generally be rated at the same rating as the WTG switchgear to avoid paying for an unnecessarily high value of short circuit rating. 3.2.1.3 Lightning Impulse Withstand Level (LIWL) and Surge Arrester Ratings Usually if the switchgear is rated at 36 kV then the LIWL rating of the equipment in accordance with IEC will be 170 kV peak. However, from experience on some wind power plants the phase to phase surge voltages can give rise to high switching surge voltages. Some manufacturers have extended the capability of their 36 kV equipment to operate at 40.5 kV and this may have a LIWL rating of 185 kV peak associated with it. If the results of the insulation coordination are showing that higher than normal LIWL are required then this may be a possible solution. Usually, it is the phase to phase overvoltages which are a problem rather than the phase to earth voltage so that another way of dealing with this is to specify switchgear which is fully phase segregated. In order to control the overvoltage on the 36 kV system transferred through the transformer it’s often required to fit surge arresters on the 36 kV system. These surge arresters may sometimes be fitted at the LV terminals of the transformer but in some cases it is necessary to fit these arresters at the incomer circuits of the 36 kV switchboard. If these are to be accommodated in the switchboard then the rated voltage of the arrester and its energy capability as derived from the insulation coordination studies must be specified. If needed from insulation level point of view, arresters may also be installed phase‐to‐phase. 3.2.1.4 Configuration There are various different configurations which can be used for the 36 kV switchboards. In this section only a few of the basic options will be mentioned. The first choice is should the switchboard be a double busbar design or a single busbar design? A double busbar design means that every circuit either incomer or array cable can be selected to either busbar. The two busbars can either be run separate with the bus coupler circuit breaker open or run coupled with the bus coupler breaker closed. If the substation has two transformers then one transformer can be run normally connected to the main busbar and the other connected to the reserve busbar. In theory the double busbar arrangement has the advantage that if a busbar fault occurs to one busbar all circuits can be connected to the other busbar. The reality of this very much depends upon the physical construction of the busbar. However, double busbar switchgear is more costly and requires more space because the switchboard is deeper than the single switchboard option.

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In the majority of offshore substations built to date the switchboards have been of single busbar design. If single busbar design is chosen then the next question is how many separate sections of switchboard are required? This decision will be driven by the type of transformer being used. If the transformers are two winding then each transformer gets its own section of 36 kV switchboard. Another consideration is whether or not these two separate sections of switchboard are to be located in two separate rooms to avoid a fire from affecting both switchboards. If one room is acceptable then the two switchboards will normally be connected via a bus section panel, whilst if separate rooms are required then an interconnector possibly using bus duct connections will be required. If the transformers being used are three winding type then for a station having two transformers it would be normal to have four separate sections of busbar, with one winding from a transformer connected to each busbar. This cross connected configuration with bus section circuit breakers between the two sections enables all of the inter array cables to be connected to either transformer in the event of loss of one transformer. This type of configuration has been used and proposed for various wind power plants. Another possibility with the single busbar arrangement is to connect the separate sections of busbar round in a ring. This configuration has been used with three off three winding transformers where the three winding transformer was used to more evenly share the load currents rather than for fault current limiting. Clearly there are various different options which can be chosen but the option selected must align with the assumptions used in both the load flow and short circuit studies and also take account of the reliability and availability calculations. If the wind power plant is relatively small the offshore substation may only have one transformer. In such a case the transformer may be three winding in order to limit the fault levels arising from the fault infeed from the WTGs. In this case there would be two separate sections of 36 kV busbar. Another possibility is the use of a single two winding transformer with two connections from the secondary winding one to each side of the bus section in a 36 kV two section busbar.This would be acceptable depending on fault level contribution and by having two separate sections would mean that a busbar fault would only lose half of the WTGs. 3.2.1.5 Types of Circuit to be Switched As a minimum the types of circuit to be switched from the 36 kV busbars will consist of the main transformer incomers and the inter array cable outgoers. There will also usually be either bus sections or bus couplers depending upon the choice of single or double busbar switchgear. However, additional switch panels may be required for shunt compensation elements such as reactors or capacitors if these are shown to be necessary from the load flow studies. As the switching duty for some of these components can be problematical, then, for example with shunt reactors, it may be necessary to use RC elements to ease the switching duty and avoid restrikes. If the harmonic studies show that filters are required on the offshore platform then these may also be connected to the 36 kV switchboard. Finally, if the earthing transformers are connected to the busbars rather than to the transformer LV windings then these will also need to be switched.

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3.2.2

Aspects of Specification which come from Generic Operation and Maintenance Considerations Experience with offshore installations to date has shown that the cost of maintenance and the downtime during faults or equipment failures are two of the most significant differences when it comes to the specification of MV switchgear for offshore installations compared to onshore installations. In the first instance, a very high level of reliability is an economic imperative and this is achieved through very exacting and accurate specifications. Additional component redundancy is also an important consideration to achieve very high levels of availability. A very rapid repair time is also necessary to achieve minimal revenue losses during equipment failures. A further consideration is the harsh corrosive environment that the equipment will be located in. Whilst it is assumed in this guide that the MV switchgear will be housed in environmentally controlled switchrooms, an allowance for additional corrosion protection would be recommended as inevitably the external environment will have some impact on the equipment during any downtime of the environmental control units and when the switchroom is exposed to the elements during major maintenance activities. 3.2.2.1 Operational Considerations The long cables and transformers introduce large electromagnetic stresses when switched which can produce long term damage to plant resulting in the need for enhanced maintenance or early replacement. Although space is at a premium a balance between equipment overstressing control (surge arresters or additional CBs) and cost needs to be considered. The ability to reconfigure the substation to isolate and safely maintain or replace bays while keeping the remainder energised is important. One of the major challenges faced by switchgear is for it to function correctly after very long periods of non‐functioning. To this end consideration should be given to the regular operation of switchgear and the interval of such operations should be agreed during the FMECA and RCM studies at the point that gives maximum reliability. To achieve this, it should be co‐ordinated with the substation configuration design and other maintenance activities. It could also be an automated function that operates during periods of low wind non‐production at the specified intervals so as to minimise revenue loss as well as minimizing switchgear wear as interrupted currents will be very low under these conditions. 3.2.2.2 Maintenance Considerations Modular construction will help with maintenance by enabling fast changeout. This also keeps the skills required to effect a replacement basic, reducing the need for specialist engineers on the platform. Smaller modules are easier to transport and move around the platform. Where possible it would be recommended that a full failure mode effects and criticality analysis (FMECA) study be carried out on the major switchgear components and to be most effective it should have substantial input from the switchgear manufacturer. Following this study, the equipment specification should be prepared and using this specification and the FMECA study the reliability centred maintenance (RCM) study should be carried out in order to achieve maximum switchgear reliability over its lifetime. It is economically desirable to specify as low a maintenance design as can practically be achieved. Manufacturer claims of ‘maintenance free switchgear’ should be substantiated!

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On offshore platforms space is normally at a premium and the user should try to minimise the space required for racking in/out of switchgear and other maintenance activities. In order to achieve minimal repair times, detailed consideration should be given to the handling and storage of spare components, tools and the breakers themselves and also the ease with which they can be moved around and on and off the platform. 3.2.2.3 Condition Monitoring There are a number of areas where CM can assist in the determination of switchgear performance and avoid intrusive procedures or un‐necessary visits to the platform. Manufacturers claim long periods between CB maintenance, however circuit breaker timing monitoring will provide an idea of any problems developing in the contacts, particularly since these could be switching large capacitances. Where possible trending of the switchgear condition (timing, contact resistance, partial discharging level, thermal imaging, etc. and data made available onshore) should be employed, rather than remote alarms as these may mal‐operate and incur un‐necessary emergency offshore visits. 3.2.2.4 Remote Monitoring The remote monitoring of many parameters of switchgear is also desirable however, the user should be aware of the significantly higher level of failures generally of monitoring equipment and this monitoring equipment, if it is not carefully specified and designed, may in itself become a significant maintenance cost and reliability issue. Sensors should be kept simple and robust. It also requires knowledgeable resources onshore to observe and analyse the data from the platform. 3.2.2.5 Spares In order to minimise repairs on board the platform itself, it is recommended that the switchgear be highly modularised to minimise the work required to be carried out offshore and enable any detailed or intricate repair work to be carried out onshore as much as possible. Most of the components in a bay are common, so generally keeping a spare bay onshore will address most issues. Transport facilities to get the bay onto the platform and lifting must be thought out in advance, including the loading procedures and transfer from the platform laydown area to the MV hall. Lifting equipment and logistics on the platform need to be considered on the fully commissioned offshore installation and not during construction. 3.2.2.6 End of Life Replacement The platform has a normal design lifetime of 25‐40 years depending on the developer's requirements. After the lifetime the platform is either abandoned (dismantled and turned into scrap) or returned to shore for overhaul. The lifetime of the MV switchgear should exceed or align with the lifetime of the platform and, therefore, consideration of end of life replacement should only arise (excepting major fault) if the platform is returned to shore for major overhaul.

3.2.3

Aspects of Specification which are Plant Specific

3.2.3.1 Environment Most or all of the MV switchgear employed in offshore substations will inherently be designed for controlled indoor switchroom environment. To specify outdoor switchgear as a contingency measure at the voltages concerned is not a practical or economic solution offshore.

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For MV offshore wind networks – which to date tend to be dominated by 36 kV service voltage and associated products for the array connections – the situation is more onerous, as the designs of available switchgear products have evolved from an indoor service requirement and there is no consideration for outdoor duty in their underpinning development. Establishing and maintaining adequate and reliable control of switchroom environmental conditions is a critical issue for offshore substations. Despite a tendency to specify gas‐ insulated switchgear designs in this voltage range (and by this eliminating any influence of air content on dielectric performance) any inadvertent exposure of the switchgear assembly to the highly onerous saline content of ambient marine air can rapidly deteriorate switchgear condition. This is not limited to cosmetic corrosion alone, as most gas‐insulated designs still employ air‐insulated components to some extent (operating mechanisms; closing and tripping coils; protection devices; secondary circuits and terminations; local controls and instrumentation). A recommendation is therefore to install salt filters in any air inlets and let the indoor environment be slightly over‐pressured compared to the outside or install heating systems to avoid any condensation. Close attention to the design and layout of switchrooms on offshore platforms can also significantly reduce the susceptibility of switchrooms to inadvertent harmful ingress of salt saturated air. Examples include appropriate ingress protection ratings for switchroom doors and proper location of door entries to minimise any risk of water ingress when access is required during storm conditions. Sequential door layouts for exterior points of access with an intermediate “porch” area between them to avoid direct exposure of switchroom contents to the prevailing weather, may appear obvious but are not necessarily employed. In marine environment, the equipment is exposed to extreme weather conditions such as high humidity and the prevailing offshore winds that make fog and mist. For this reason, it will be important to select an adequate medium voltage switchgear for the offshore platforms. It seems evident that SF6 Gas Insulated Switchgear (GIS) or cubicle type Gas Insulated Switchgear (C‐GIS) will be desired rather than air insulated Metal‐Clad Switchgear (MCS) which has potential risk of primary insulation deterioration by oxygen and moisture. Also the space required for the switchgear with the Gas Insulated Switchgear is lower than the air insulated medium voltage Switchgear. This aspect is important to take into account on offshore platform where the space is limited It will be important to consider what should be the measures against different environmental agents like corrosion, condensation and combination of them. Different factors such as high humidity, the appearance of condensation or an increase in the amount of pollution in the atmosphere can cause atmospheric corrosion. This is a process that takes place in a film of moisture on the metal surface. A solution against the corrosion that may take place in the medium voltage switchgear is to apply an anticorrosion coating system in accordance with the current issue of the ISO 12944 standard series. For the very high corrosive conditions in the marine environment, the paint system category should be C4 for indoors. Some of the typical materials for these anticorrosion paintings are chlorinated rubber, epoxy, polyurethane, coal tar vinyl, coal tar epoxy, polyvinyl chloride among others. It is important to realise that the medium voltage switchgear employed in offshore substations is commonly installed protected from the direct environmental impacts, inside enclosures or buildings with controlled conditions, and therefore not

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exposed to humid and saline air. In this way, the finishing of the switchgear surfaces for use in offshore platforms can be the manufacturer’s standard. 3.2.3.2 Vibration and Transport Forces It is recognised that some standards for switchgear (e.g. IEC) do not include any dedicated provisions for specification or type testing to demonstrate insensitivity to prospective mechanical impacts to be seen by electrical apparatus on offshore platforms, such as wind gusts or wave loads. Requirements published in IEC switchgear standards tend to be limited to localised impact tests, and are applicable only when specifically agreed between the purchaser and the manufacturer. They only refer to points of suspected weakness in the structure of the switchgear (e.g. ref. IEC 60694 and 62271‐1). These requirements are not adequate for the case in question when vibrations to the entire switchgear structure could be expected on a long term basis. One particular example of susceptibility would be the reliability of latching in operating mechanisms. Insisting on seismically‐qualified apparatus would mean introduction of a substantial cost premium. As a consequence, suitable product availability would be significantly reduced unless substantially more manufacturers invested in seismic qualification. On top of that all these seismic requirements would only make sense if vibrations of offshore structures would be proven to be equivalent to seismic effects. However, there is no evidence for this at the moment. Seismic events are characterised by large magnitude and short duration while wave interaction in comparison is characterised by lower magnitude and long duration. If we consider that we deal with low frequency vibrations in case of equipment installed on the platform, the focus should be made to two important factors: 1) the type of foundation, and 2) the rigidity of complete switchgear base frame. It is assumed that vibrations transferred to the top side module caused by wind, sea and boat landings are 100 times lower when comparing a monopile foundation with a jacket and concrete structure. The monopile foundation will inevitably introduce a risk in itself during the lifespan of the system. The weak line when looking at 36 kV GIS appears to be the busbar assembly point between the individual bays. As mitigation, a very rigid floor frame should be considered to prevent from deformation during the lifespan of the equipment. With the planned pan‐European growth in offshore generation and transmission, it is suggested that vibration topic should be an area for more thorough investigation. Consideration should be made for the feasibility and merit of defining a series of dedicated type test criteria. This could be similar to the rigorous "marine classification" regime for other offshore air‐insulated switchgears for mobile offshore units and vessels. Risks and mitigations for electrical apparatus associated with ocean transportation are relatively well understood, and substantial experience exists ‐ particularly with ever‐growing market pressures to manufacture final switchgear assemblies in countries remote from equipment final installation location, such as the Far East and Asia supplying to Western Europe. However, offshore wind applications once again present their own specific challenges. The switchgear cannot be transported to its offshore installation in pieces but must be fully assembled onshore. Only after that is it transported, and exposed to all kinds

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of forces and vibrations. This is especially critical for connections and interfaces between components. They are normally designed for static conditions. During the sea transportation the platform may be subjected to roll, pitch and heave which will impose forces onto the parts of switchgear. The magnitude of these forces will be dependent on the degree of roll and pitch, the duration of transport, the location of the platform on the barge/vessel, the height above the centre of gravity of the barge/vessel. The limiting motion criteria for the sail out should be confirmed at an early stage of the substation design process. This topic is discussed in more detail in Section 4.8 – Load out, transportation and installation. The design of the switchgear should make due allowance for these additional external forces and this may require special attachments to facilitate the fitting of sea transport fastening. The design should also consider any forces that may be introduced at the time of lift for moving to the vessel and the final lift process necessary to install a substation platform on its foundation.

Figure 3‐1. Enclosure of containerised offshore substation The stresses that can be critical for specific equipments may also be critical for connections between them (e. g. busbar systems). It is one of the reasons to consider some smaller busbar systems in different modular switchgear rooms instead of only one longer busbar systems inside one switchgear room. Another advantage of this possible design would be to isolate one busbar system from the other in case of one fault and to avoid the stresses in the connections of longer busbars. 3.2.3.3 Special Technical Considerations 3.2.3.3.1 Circuit Breakers Currently there are 2 types of medium‐voltage circuit‐breakers available on the market with SF6 or vacuum interrupter technology. For offshore installation with difficult access for inspection, maintenance and service, especially on unmanned substations, vacuum breakers

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are preferred. They allow a very large number of switching operations (up to 30,000 at rated current, i.e. 3 times higher than SF6‐breakers) without any inspection or maintenance. As this technology is available up to 36 kV this is the highest voltage level applicable for installation on offshore substations. Considering the new rated voltage of 40.5 kV which is under consideration as future standard voltage in IEC 60071 and IEC 60038 (mainly due to its wide application in China) the service voltage can be increased to 38 kV. But it has to be considered that currently there are fewer manufacturers of GIS with vacuum breakers at 40.5 kV than at 36 kV. The use of vacuum breakers has further advantages for the application in offshore substations. The medium‐voltage distribution grid of a wind power plant is a cable grid and therefore often requires switching of capacitive currents of no‐ or low‐load cables. This task can be done by vacuum breakers in an excellent manner. The generation of overvoltages caused by chopping of the small currents during switching today is reduced in state‐of‐the‐ art vacuum breakers by the selection of suitable contact material and its mechanical design. 3.2.3.3.2 Interlocking During normal operation the complete offshore wind power plant is remote controlled from a central control room located onshore (unmanned substation) or offshore (manned substation). Faulty operations, e.g. earthing of a live cable or connection of asynchronous parts of the grid is avoided by the control and protection system, and additional hardwired (or software acc. IEC 61850) electrical interlocks typically employing blocking solenoids. For maintenance purposes manual operation of the switchboards is required. A project key decision is the application of manual maintenance interlocking for use as part of a safe system of work ‐ e.g. "permit system". Within the substation this is a less complex issue, where the presence of personnel enables manual interlocking schemes to be practically implemented. However, where such schemes are introduced between the substation platform and downstream array circuits to connected wind turbines, these introduce additional sea‐based transportation which in itself bears a safety risk in addition to added process downtime. Project decisions are necessary on how this balance of commercial and human risk is to be balanced. Although many UK onshore transmission and distribution network operators would typically rely on procedures, training and competency where substantial distances are involved in managing remote isolations, it should be recognised that offshore operators may emanate from other sectors ‐ such as generation ‐ which may not necessarily have evolved from the same sector of industry, and where such a purely procedural approach may be seen to depart from their recognised working practices. A related issue that faces the use of maintenance interlocking, particularly in the UK, is the increasing difficulty in applying solely mechanically‐derived key interlocking to many types of the indoor gas‐insulated switchgear that dominates the product base for all onshore and offshore installations at and above 24 kV ‐ key interlocking being critical to interface "mechanically" with remote plant and locations where maintenance interlocking is required. An important point is the scope for misinterpretation of a "mechanical" coded key seen mounted in some switchboards or key exchange boxes as being part of a truly mechanical interlock. There are many examples where these could be mistaken for a traditional fully‐ mechanical scheme ‐ whereas they are reliant on solenoids or limit switches which are not visible externally, but in the UK would be considered invalid as a maintenance interlock in many operating company's Safety Rules.

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In the UK all this leads to a tendency to have to use such interlocking systems to support procedural safe systems of work, rather than depend directly upon them. This in turn requires additional padlocking and human intervention, along with focused training and awareness. 3.2.3.3.3 Accommodation for Cable Terminations The medium voltage switchgear cubicles in an offshore substation will accommodate the terminations for incoming feeders from the collection system of the wind power plant or the outgoing cables to the power transformers. Given the continuous growth of the installed capacity of both the medium voltage circuits and the power transformers, the natural tendency is towards the use of larger cable cross‐sections or even two cores in parallel. In this sense, the separable connectors (suitable for cross‐sections up to 630 mm2), will be progressively less utilized in favour of other solutions suitable for larger sections. This is applicable to the switchgear inside turbine towers too, although in this case the key problem is to adapt primary distribution switchgear for installation inside the tower. 36 kV GIS can be specified with inner or outer cone cable connections which means that the GIS has provision for the connection of either a plug‐in connector or a T‐connector (not considering the bus‐duct solution here). The plug‐in connector will be plugged into the GIS and will therefore be more restricted in the amount of possible connections per phase. The T‐connectors can be plugged onto one another (typically up to three connectors per "outer cone" bushing) ‐ and this means that adding another cable later such as wind power plant extension is straight forward. The T‐connector system will, however, introduce bolted 36 kV connections which is why provisions for arc detection in the cable compartment should be made available. 3.2.3.3.4 Specification – Other Factors It is well understood that country‐specific practices and legislation can lead to the need for national standards and specifications to supplement harmonised international documents. In addition to examples mentioned earlier, the UK also faces an added complication of adoption requirements for offshore transmission assets. These requirements may influence plant and switchgear specifications. Construction of offshore substations may need to be undertaken by wind project developers who may not be familiar with, or ultimately responsible for, the final operation and maintenance protocols for these new network assets ‐ however, these assets must be designed to meet the requirements of an adopting network operator from the outset of their specification. Increasing moves to distance operators from switchgear during live switching has led to some users specifying “distanced local” control stations for all such devices. These are preferably hardwired, static control stations mounted at a safe distance, replacing the need for local electrical controls at the switchgear which can then be locked off or decommissioned. This practice is equally relevant offshore, and may not be limited to UK markets. Some 36 kV switchgear is sealed and largely non‐maintainable, limiting the practicalities of any significant in‐situ overhaul or replacement. Operating experience may increase the demand for modular gas‐insulated designs with removable gas zones that can be replaced on site. The above includes some examples of where compliance with national statutory requirements is relevant starting from the outset of the project design stage: ‐ the UK

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Construction Design and Management Regulations require a formal identification and addressing of such issues at the design stage, though the role of CDM Designer defined in the Regulations. 3.2.3.4 Physical and Interface Considerations Space within an offshore substation platform is always at a premium and increases in sizes produce a large financial penalty, therefore, GIS switchgear would generally be the best choice, since air insulation is avoided and SF6 has excellent insulation performance coupled with long term reliability. Whilst the aim is to provide a reliable and compact switchboard there are factors which need to be considered in the design of the switchboard, typically:‐ z Protection relays can be mounted within the top chamber of the switchgear front, however, these will need to be accessible for commissioning, manual interrogation and/or maintenance activities. Any necessary access platforms, whether fixed or temporary, will need to be designed into the substation layout and provided for use offshore. z The protection relays should include basic SCADA and fault recording facilities z The platform layout may dictate that the control cables may need to approach vertically from above the switchgear so the top chambers would need to be designed to suit this arrangement z The switchgear should be a modular construction to assist building in the fabricators yard onshore, and also to assist any remedial works which become necessary during its lifetime offshore. z The switchgear and any connected power cables will need to be electrically tested so provisions should be included within the design for suitable bushings and/or cable test sockets. z If VT’s are required on the turbine feeder circuits then they may need to be mounted remotely and cable connected to the switchgear. Due allowance must be made for the cable connections and VT mounting space. The switchgear will generally be connected to the system via power cables or busducts and due allowance needs to be made for these connections. Generally these connections would approach the switchgear vertically from below and there are factors which need to be considered in the design of the switchgear, typically:‐ z Disconnectable cable terminations would be preferred with the female portion of the termination and insulator included in the switchgear cable chamber. This allows the chamber to be conditioned and hermetically sealed in the manufacturer’s works with no need to open the chamber to the elements during cable installation. This is of particular importance for the sub‐sea turbine cables which will be installed offshore. z The minimum bending radius for the cables needs to be considered together with working space adjacent to the switchgear bay for the cable installers. This can be particularly important when the switchgear is mounted to the deck plates and the space directly below is an open area exposed to the marine environment. The operatives in this instance would be working from below the switchgear through access areas in the deck plates. The position of the cable head on the switchgear will influence the facilities which need to be built into the room/enclosure where the cable connections enter.

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z

The switchgear design should take due note of the fact that the cable entries will generally need to be effectively sealed, where they enter the room/enclosure, against fire and possibly the marine environment. Again the position of the cable head on the switchgear will influence the facilities which need to be built into the room/enclosure where the cable connections enter. The location of the switchgear bays within the switchboard should be reviewed with the substation platform layout to determine the approach routes for the cable/busduct connections. The physical locations of the sub‐sea cable entries at the platform cable deck and relative positions of connected plant items will generally dictate a preferred cable route. The bays should be arranged to mitigate external cable crosses where possible. The switchgear base will normally be fixed directly to steel floor plates or rails on the platform and the floor should be of a simple design to facilitate this type of fixing.

3.2.4

Specific Requirements for Rooms or Enclosures

As stated in 3.2.3.4 space within an offshore substation platform is always at a premium and increases in room/enclosure sizes produce a large financial penalty, therefore, the pressure is to keep the room dimensions to a minimum. The following items should be considered in the design of the room/enclosure:‐ z The switchgear manufacturer must confirm the minimum amount of space around the switchboard to permit all aspects of planned and unplanned operation, maintenance and repair works z If the switchgear includes a withdrawable circuit breaker (CB) then sufficient space must be allowed for the CB and any necessary handling device z Sufficient space must be allowed for handling of any large sized test equipment z When GIS switchgear is used sufficient space must be allowed for a gas cart to be used during filling and/or maintenance operations z Sufficient space must be allowed for any necessary fixed or temporary access platforms required to access specific parts of the switchgear As stated in 3.2.3.4 the power cables and/or busducts would generally approach the switchgear vertically from below and if the cable head is close to the floor level space may need to be allowed below the floor level. This may involve fitting a false floor some distance below the natural floor. Where the cables pass through this false floor the penetration may need to be effectively sealed against the marine environment or to limit the spread of fire. All penetrations through walls, floors and ceilings will be suitably sealed during installation in the onshore fabricator’s yard, however, it must be remembered that the array cables will be installed and the penetration sealed offshore. Temporary seals would need to be installed into the penetrations prior to sail out and these would be replaced by the final seals after cable installation. Similar requirements apply to control and multicore penetrations. The cable installer would need to be able to work through the penetration in this false floor to lay and terminate the cables/busducts, hence the opening must be sized to suit.

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Figure 3‐2. Example of 36 kV busduct entry to switchgear bottom

Figure 3‐3. Example of 36 kV busduct entry to switchgear with transit sealed

Figure 3‐4. Example of control cable transit in steel floor to room As stated in 3.2.3.4 the switchgear base will normally be fixed directly to steel floor plates or rails on the platform floor. The floor fixings/rails must be suitably designed to accept the static and dynamic loads resulting from operation of the switchgear plus any imposed loads during the sea transport and offshore lifting operations, where applicable. When dimensioning access doors into the room/enclosure they should consider equipment access during initial installation and lifetime maintenance or repairs, together with 122

personnel access. Large steel doors used offshore may be excessively heavy so incorporation of removable panels in the enclosure may be an effective alternative to keep the doors to an acceptable or standard size. The switchroom should contain a fire detection/alarm system and the substation fire plan will detail if the switchroom/enclosure is to be designed as a passive fire protection or contain an automatic fire suppression system. Where a fire rating is assigned to the switchroom wall then any access doors within the wall must be suitably fire rated to match that of the wall. The room/enclosure layout should consider emergency egress from the room in the event of an incident. Consideration needs to be given to the room dimensions and positioning of the switchgear to provide suitable escape routes and doors. For other than small rooms this normally means there should be at least two points of access/egress. In certain circumstances an escape hatch can be provided to replace a second full size door. All hinged doors and escape hatches should include panic bars on the internal face. During an internal fault, or failure of a gas zone within an SF6 switchboard, high pressure gasses may be vented into the room/enclosure. The volume and pressure of these gasses when vented into the room will cause an overpressure within the room. This overpressure needs to be evaluated and if necessary suitable pressure relief devices built into the room to prevent mechanical damage to walls, doors etc and injury to people who may be in the room at the time of the discharge. It is common on offshore structures to identify areas which may be subject to an unplanned release of gasses and to include in the design a gas detection system for identified areas. Where GIS switchgear is used there has sometimes been a requirement from Clients to include an SF6 gas detection system separate from the switchgear. This independent detection system would typically initiate an alarm to a SCADA system and a warning beacon with sounder external to the room. Given the SF6 alarm systems integral to the switchgear the beacon & sounder could be initiated from the switchgear negating the need for an independent scheme. This solution should be investigated where practical. The electrical equipment which will be housed in these rooms has been designed for indoor use in Normal Service Conditions where:‐ a) The ambient air temperature does not exceed 40 oC and its average value, measured over a period of 24 hours, does not exceed 35 oC The minimum ambient air temperature is –5 oC for class “minus 5 indoor” as defined in clause 2 of IEC Standard 60694:1996 b) The conditions of humidity are as stated in clause 2 of IEC Standard 60694:1996 The heating system to these areas should maintain a minimum ambient air temperature of +5 oC The ventilation system should incorporate maintainable salt filters Reliance on watertight substation designs, accompanied with adequate and reliable heating, ventilating and air conditioning (HVAC) systems is of paramount importance, and in turn places great emphasis on the performance of substation HVAC systems. Consideration should be given to using redundant systems. Whilst some HVAC manufacturers may state that their products are designed to withstand sea‐going environments, their ability to do so reliably should be subject to increased inspection and maintenance frequencies compared to onshore. This leads to a conflict with inherent pressures across the offshore wind industry to extend intervals between substation inspection and maintenance activities in 123

order to minimise cost and risk associated with the offshore transportation of field service personnel. Effective remote monitoring of substation operating conditions is therefore a crucial factor in mitigating against exposure of offshore switchgear to any degradation in the control of the switchroom service environment. Sole reliance on fault alarms from HVAC systems is limited in effectiveness. Continuous measurement of actual switchroom temperature and humidity employing low‐set alarm thresholds with remote annunciation is essential to provide any opportunity for effective early response for unmanned offshore platforms.

3.3 Main Transformers and Reactors The main transformers are the largest single equipment installed on the platform and they affect the overall electrical and physical layout. There are many aspects to the transformers design, but most importantly the system characteristics will define the winding configuration as for a conventional substation. This suggests that the same method of designing a conventional transformer can achieve the required performance. However, this conventional method may not satisfy all the criteria. The environment of offshore substation is very different from a conventional onshore one. The environmental impact of a transformer installed on an offshore platform may require special consideration. Similarly, the fire safety issue may be much more severe in offshore location, compared to conventional onshore installation. Hence, all the risks related to the use of conventional oil‐ filled transformers, such as environmental pollution, fire or explosion risk, must be carefully evaluated as they contain many thousands of litres of oil. To reduce the risk from hazards and the cost of building a substation, the transformer is the key component. These requirements on an offshore substation are not the same as for onshore. Reactors may also be installed on the platform to absorb reactive power. There are two types of structure for reactors. One is radial core block type another is air core type. Other parts (coil, tank, radiator, conservator etc.) are the same as transformer structure. Therefore in this section, we will show the transformer example. But those are also applicable to reactors. Magnetic Shield

Magnetic Shield

Coil Spacer

Radial core block Coil

Radial core block reactor Figure 3‐5. Core structure of reactor

Air core Reactor

A risk of transformer failure or a platform fire is a major problem, since the compact nature of the platform is such that it is very likely adjacent equipment may be damaged.

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Liquid‐immersed transformers or other liquid‐immersed components filled with mineral oil may be major contributors to fire risks by acting as fire sources. Other substation components, like diesel fuel storages or other electrical apparatus are also important contributors to fire risks in the confined substation space. In this case, the transformer could become subject to the fire. Oil leaks from transformers may result in environmental pollution when not collected properly by dump tanks. This together with other health and safety issues may be a driver for the type of insulation system to be chosen for transformer to be installed on the platform (e.g. gas or alternative fluid). Transformers on the platform ideally need to be light weight, small, low maintenance and reliable for reducing the building and operational costs. This section describes the major considerations in transformer specification for offshore substations. Various design options are discussed.

3.3.1

Aspects of Specification which come from System Studies

3.3.1.1 Voltage Ratio At present for the majority of offshore wind power plants the collection voltage is 36 kV so this tends to set the value for the low voltage side of the transformer. In many cases the HV side voltage is set by the system that the wind power plant will connect into onshore, e.g. 110 kV, 132 kV, 150 kV or 220 kV. However, if the wind power plant is to connect at a higher voltage such as 400 kV and thus require further onshore transformation then the wind power plant developer has to choose which intermediate voltage to adopt for the transmission of the power from the offshore substation to the shore. This choice is likely to be dominated by the availability of suitable cables. The system studies may have looked at different options and what has finally been selected in the studies will form the open circuit voltage ratio for the transformers. 3.3.1.2 MVA Rating The MVA rating of the transformer will often be closely linked to the rating of the submarine cables connecting from the offshore substation to the shore. The final choice will take account of the load flow studies including making allowance for the reactive power as well as the real power to be transmitted. Furthermore the developer will have to decide about the redundancy policy and this will also have a significant effect upon the final choice of MVA rating to be used. (refer to Sections 1.1.1, 2.1.1 and 2.1.2) The transformer rating will depend on the design requirement for spare capacity or the requirement for short or long‐ time overloading capability (refer to Section 2.2 “Overloading capability”). As indicated in Section 2.5.7 “Harmonic performance” the power generated in wind turbine power plant will likely have high content of current harmonics. This will have an impact on heating of transformer parts and should be considered in the design of loss and the cooling system. Therefore the Purchaser should specify the magnitude of the harmonic currents to the manufacturer. 3.3.1.3 Impedance Usually a dominant factor in choosing the impedance of the transformer will be the need to limit the fault level to that which can be accommodated by the 36 kV ring main units associated with each Wind Turbine Generator (WTG). Naturally allowance has to be made for the infeed from the WTGs and this varies significantly between different designs of WTG. These issues will have been investigated in the short circuit studies referred to in Section 2. 125

However, the impedance of the transformers also has a significant impact on the system’s reactive compensation requirements. A high impedance value will mean that the reactive power loss variation from no load to full load due to the I2X loss through the transformer will be large requiring a larger installed capacity and wider operating range in the reactive compensation plant. Also the impedance may have an effect upon resonant frequencies occurring within the wind power plant thus impacting on harmonics. Hence the final choice of the transformer impedance may depend upon the results of the load flow, short circuit and harmonic studies. 3.3.1.4 Tap Change Range and Tap Steps The transformers on the offshore platforms often have tapchangers fitted to control the voltage at which the 36 kV collection system operates. The 36 kV system is usually impedance earthed such that on the occurrence of an earth fault the voltage to ground rises to phase to phase value. To avoid this from causing problems and possible damage to surge arresters the voltage on the 36 kV system may need to be regulated to approximately 1.0pu (33 kV ) voltage. The number and size of taps required to achieve this will be determined by the load flow studies and will be affected by the policy adopted for voltage control including reactive compensation. If fairly tight control is required of the 33 kV voltage then the tap steps should be quite small (e.g. 1.25% steps) as the deadband for the tap change control equipment will normally be set at two tap steps to avoid over‐frequent tapchanger operation. The number of taps will be affected by the range of VAR flows; for example if the WTGs are being used to provide significant contribution to system compensation, the reactive power flows through the transformer can be high and may vary significantly with differing load conditions. One other factor to be considered if three winding transformers are being used is that the tapchanger will normally be located on the high voltage winding. Consequently only the voltage on one of the two secondary windings can be controlled by the tapchanger. Alternatively, the tapchanger can respond to the average of the two LV voltages. In either case the sensitivity of the voltage control is significantly reduced. 3.3.1.5 LIWL Levels The LIWL levels will be defined by the insulation coordination study. Usually there will be surge arresters on both the HV and LV terminals so phase to earth surges should not present any difficulties. Information should be obtained from the transformer manufacturer for information on relative strength against phase to phase surge voltages. On occasions a slightly higher LIWL may be specified to cover phase to phase surge voltages on the 33 kV windings. 3.3.1.6 Two or Three Windings There are two reasons normally for using three winding transformers. The first is to help to limit the fault levels when one transformer is out of service as the ZL1‐L2 will help to reduce the fault level when all turbines are connected to one transformer. The other reason is to share the load current more equally to two parallel LV breakers. This load sharing reason only becomes critical if the size of the transformer is such that the 33 kV current is close to the rating of two circuit breakers in parallel. If there is a reasonable margin between the secondary current rating and the rating of the two circuit breakers in parallel then a two winding transformer will be satisfactory. 126

3.3.1.7 Neutral Earthing The usual vector group for these offshore transformers is star/delta with the star winding on the HV side. In most countries the HV star winding will be solidly earthed. However in some countries to avoid the earth fault level from exceeding the phase fault level; some transformer neutrals may be left unearthed. In this case the transformer winding will need to be fully insulated rather than using graded insulation. The decision on earthed or unearthed star windings will need to be agreed with the system operator of the system into which the wind power plant is connecting. The 33 kV delta systems will normally be earthed either by resistance earthing or by using the zero sequence impedance of the earthing transformer to limit the earth fault current to an acceptable level such as 1kA. This will help to reduce the cost associated with the inter‐ array cable sheaths.

3.3.2

Aspects of Specification which come from Generic Operation and Maintenance Considerations

It is important to consider all eventualities that can occur to a transformer once the platform is installed offshore and commissioned. The asset management strategy must be consistent and consider the whole life‐cycle. Equipment size, weight and maintenance requirements will be much more critical than onshore. Various options need to be explored and analysed, particularly to the choice of the insulating medium for the power transformers to manage weight and safety. In addition to the transformer tank, there are a number of auxiliary components to a transformer which are vital in providing a fully functional and rated unit, namely the tapchanger, cooling system and bushings. The prudent use of condition monitoring will be important in the overall design and construction. Since time and space is at a premium, adopting a modular design principle to facilitate easier replacement would be a very prudent approach, particularly where routine replacement is anticipated. It is also recommended to keep any routine maintenance procedure simple so specialists are not required on the platform. Health and safety considerations will stipulate challenges not only for the substation design but also for the offshore access and transport. There are substantial differences in some areas (e.g. marine, oil and gas industry) and to fully adopt the sometimes stringent requirements from the oil and gas business may lead to unnecessary and costly solutions. The key O&M issue is based around establishing the asset condition and determining whether maintenance is required and what is the risk associated with not carrying out the traditional time based regime adopted onshore. Other major issues include accessibility, space limitation and general inability to bring in third party services without incurring a massive cost penalty. 3.3.2.1 Maintenance Strategies A transformer can be a long life asset (50 years or more onshore) if sensibly specified, operated and looked after. This long lifetime refers mainly to network transformers loaded relatively low during their operation. But an offshore substation transformer has a different operational condition. Loading factor of it will vary quickly according to wind from low to full power. They will be also exposed to frequent overloads related to turbines operation. Hence, proper design for achieving required life expectancy may be critical, and may affect selection of transformer external components and internal design solutions. Offshore, 127

equipment requiring low or zero maintenance and a long‐life is preferred, inevitably this will result in a more expensive front end cost, however this should be balanced against the lifetime ownership cost and risk. The offshore O&M regime is likely to be a combination of time based and condition based maintenance (CBM), where condition monitoring and risk assessments will be overlaid on a rudimentary time based plan, to minimize the need for site visits. The permitting process and safety rules for an offshore environment will need to take account of any changes in O&M practice. The designer must consider how any activity associated with either preventative or corrective maintenance can be achieved. This includes developing the method statements, tools, work space and spare part provision necessary to successfully carry out the process without a return trip to shore. Where necessary, special tools should be kept on the platform. It is very important to consider how remote services can be best utilized, since it will not be possible to send specialists offshore unless they have the appropriate training and constitution (sea sickness can be a major obstacle). Just like onshore, recommissioning following any maintenance will require skilled resource and procedures. All personnel on the platform will need to be suitably authorized or supervised (possibly remotely) to carry out and return to service all equipment associated with any fault or corrective O&M procedure. Moving parts and operating mechanisms will require periodical maintenance. Where possible, maintenance free solutions are desired such as employing solid lubrication or grease‐less pins and shafts. Transformer tank painting may or may not be required during the platform specified lifetime and the paint specification should be chosen to avoid re‐coating where possible. The final layout needs to take account of all anticipated activities, in particular access and the space to perform all necessary operations. This may include hatches and removable panels to facilitate replacements and the installation of any fixing points or support services which may be used to manoeuvre parts or equipment into position. 3.3.2.2 Oil Management Oil management for liquid‐immersed transformers includes all the operations and strategies involving oil filling and draining, oil preservation and its treatment if needed. All these operations may be required at the transformer installation stage, during transformer normal operation or during repair and maintenance activities. Apart from ensuring the right quality of oil filled into the transformer and maintaining it throughout its operation, one important aspect of oil management is to reduce the risk of any oil leakage from the transformer for the whole life of the unit and during all the operations involving oil. Offshore, the key is to protect the oil sealing flange from corrosion, since exposure to a corrosive environment will result in deterioration of the gasket and this will lead to oil leaks from the tank and also moisture getting into the oil. This is a key maintenance activity which must be considered for all stages of a transformer’s life. It is important to note that it will not be possible to follow onshore practice regarding oil handling, so the different lifetime phases which involve movement or oil changes need to be considered and what impact this has on the mechanical design. 1. Delivery from the manufacturer’s works to the quayside (normal practice)

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2.

Transfer from the quayside to the platform (this is fraught with risks and unconventional) since the transformer will be filled with oil while in transit, so the transformer designer and transporter will need to consider how the movement of oil will be affected by the risks of sea transport and what internal impact this may have on sensitive components like oil membranes, bladders or breathers. 3. Platform based inspections and repairs (post fault forensic testing, changing out radiators, tap changer, bushings) 4. Replacement (transformer fault) It is essential that the status and condition of the oil can be monitored, in addition to more sensitive components on the transformer, such as breathers, bellows, barriers etc which could be damaged if the oil movement is uncharacteristic for the design. Oil handling presents a major environmental risk, however this needs to be facilitated since a tank fault would result in the transformer replacement and removal of the oil from the dump tanks to a transport vessel. The process of draining the oil from liquid‐filled apparatus always brings a danger that some spillage may happen. Where possible the insulating oil should be kept in the tank since moisture will lead to degradation of the insulation performance. Separating valves or double valves should be used between critical components filled with insulating fluid. Whatever method of cooling is employed with liquid‐immersed transformers, double valves should be used between the transformer tank and cooling (e.g. radiators etc) such that, when disconnection of a radiator is required for repair, there is no need to drain the oil from the radiator or the main tank. This does however result in transportation of oil filled equipment and the inherent risk this brings. The anticipated life of an offshore transformer is estimated to be between 25‐40years, so it is possible that with the selection of liquids that are biodegradable and are less sensitive to aging processes and typical aging catalysts, like moisture or oxygen (e.g. ester fluids), the need for oil processing facilities (drying, degassing) can be minimal or possibly removed for any routine activity. In the case of a major fault, the oil will need to be reclaimed if the tank ruptures and transferred to a ship. This procedure must be considered, since pumping either to a vessel or reprocessing for any new equipment will be necessary. Adequate power supplies, access and space will be required for the processing unit Oil processing facilities There are two aspects to consider; z Drying and removing moisture from oil z Removing air and/or gas from oil(oil conservator type) z Reclaiming oil and replacing with new oil If these facilities are deemed necessary by the design chosen, a strategy needs to be agreed at the design stage since it will have an impact on the construction, sea transport (since the transformer will generally be transported full of oil). Where oil processing is required it will be necessary to bring in a vessel and moor adjacent, therefore the interfaces to the transformer and vessel will be a key feature of the solution. z Power supply requirements (platform and vessel) z The head or height (height difference between transformer and vessel) the oil will need to be pumped, especially if the drying and filtering occurs on the vessel

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z

Storage facilities for emergency conditions – dump tank capacity for multiple transformer platforms z Oil processing facilities if a number of transformers are located together. z The processing requirements for maintained equipment should be minimised as much as possible (oil processing, vacuum filling, etc.), Dump tanks will need to be checked for leaks and corrosion. The choice of material and anti‐ corrosion protection system can be a major consideration here. The system includes many valves and pipework which will be exposed to a corrosive environment at sea. There are pressure relief valve detector systems which can be specified to prevent the collateral damage associated with fires, however the inadvertent operation or testing must be considered. Transformer breathers enable volume changes in the oil to occur without letting moisture absorb into the oil. There are a number of devices ranging from a free breathing design (which maintains a nitrogen blanket/bag over the top of the oil to a drycol breather which uses silica gel to absorb moisture. The latter requires regular changing while the former is maintenance free. In both cases transportation with the transformer full of oil could potentially damage the sensitive equipment installed in the conservator tank, like bladder or oil level indicator. 3.3.2.3 SF6 Management SF6 is a green house‐gas and eliminating or reducing the emission of any SF6 is a very important issue for onshore and offshore substations. The fundamental point for SF6 gas management is to keep the gas permanently in a closed cycle, avoiding any deliberate release and preserving the environment. In other words, SF6 gas can be eternally used for electrical equipment by the use of a suitable procedure. There are many technologies for gas recovering, reclaiming and recycling which have been developed. State‐of‐the‐art technologies and procedures are described and suggested to minimize SF6 emissions down to the minimum functional level for the electric power equipment. SF6 gas management is explained in the CIGRE Technical Brochure 430 “SF6 Tightness Guide”, 2010 [29]29. Gas handling is explained in the CIGRE Technical Brochure 276“Guide for the preparation of customised practical SF6 handling instructions”, 2005 [30]30. And recycling is explained in the CIGRE Technical Brochure 234 “SF6 recycling guide”, 2003 [31]31. CIGRE Technical Brochure 430 presents data about field experiences in reduction of SF6 emission in GIS examples from Japan and Berlin. (1) the leak rate of state of the art equipments is very low (example) The accumulation method was used to measure the absolute leakage rates at 300 points in 40 GIS/GCB installations. The absolute leakage rate and the gas quantity in the compartment were then normalised to the sealing length. It was found that for each measurement point the great majority of them was below the limits of detection. When SF6 could not be detected, the value of the minimum detection sensitivity of the measurement method was adopted. As a result, no difference between categories of before 1980 and after 1981 in the 29

CIGRE Technical Brochure 430 “SF6 Tightness Guide”, 2010 CIGRE Technical Brochure 276 “Guide for the preparation of customised practical SF6 handling instructions”, 2005 31 CIGRE Technical Brochure 234 “SF6 recycling guide”, 2003 30

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distribution of the leakage rate was very low under suitable design. (detail please refer to Cigre technical brochure) To reduce the emission from the equipment, z Controlled pressure systems should not be used z Only equipment having a leakage rate below 0.5 % p.a. should be installed.(IEC standard requires it) z Corrosion has to be prevented by strictly following the manufacturer’s instructions. The part of gas sealing (e.g. Flanges) is weak for corrosion. Each manufacture should indicate how to protect it from the corrosion in offshore. z To monitor the SF6 gas density (pressure and temperature) is useful. These sensors are very common, and it is easy to procure a suitable one. (2) SF6 handling loss is important The experience of Vattenfall Europe Berlin, under normal service conditions, the handling losses account for 70 % of the annual total emissions and SF6 leakage for the remaining 30 %. (Other countries report a similar tendency.) To reduce the handling loss, z On‐site maintenance and repair work as well as decommissioning of equipment containing SF6 must be performed by suitably trained personnel or under their supervision in order to minimise SF6 emissions during the whole life of equipment. z Some areas (e.g. EU), it is established by regulations. 3.3.2.4 Condition Monitoring (CM) A well specified and maintained transformer will last for many years. The challenge with transformer operation is to understand the internal condition of the windings and insulation. This is only possible through secondary measurements such as temperature measurements, oil analysis and Frequency response assessment (FRA). Monitoring the condition of key elements of the transformer is necessary particularly the insulating medium, the cooling plant and the tapchanger. While CM can significantly improve the understanding and therefore performance of the transformer, the real purpose here is to avoid visits to the platform, therefore only CM which can reliably achieve this should be considered. Monitoring the oil flow, temperature and core temperatures will help to minimise unnecessary maintenance intervention. Key rules of thumb z If the application is either unreliable or ineffective on shore, then do not employ it offshore.(applies to any equipment not only condition monitoring) z Do not couple or send CM alarms with control or protection alarms to the system control (SCADA), as this may result in un‐necessary alarms being acted upon and important protection alarms ignored. z Keep it simple on the platform. z Process and analysis software should be kept onshore. z Only use CM where it adds value and/or negates/reduces the overall volume of visits to the platform. Dissolved gas analysis (DGA) is one of the best methods to establish the status of the core and insulation performance. Experienced engineers will be able to predict when a transformer should be switched out or replaced prior to failure, by means of trending of the transformer condition thus reducing the risk of tank rupture (oil spill) and possible fire. If an on‐line unit is employed to perform this function, the designer needs to 131

consider how credible the unit is and how remote alarms can be responded to and the ‘so what factor!’ if nothing material can be achieved’. It should also be noted the mal operation of CM alarms on shore tends to incur un‐necessary emergency visits. Any monitoring installed should only provide important information and have clearly understood responses, in addition any sensors and comms need to be simple and robust. Specific sensors to consider include a core temperature fibre and winding temperature indicators. These do not necessarily need to be hooked up at first. However, the designer needs to consider how they will be used in the future. The key issue around CM or any form of remote monitoring is the reliability of the communication media used to relay the information to onshore. This is where the O&M effort needs to be concentrated. Need to dedicate resource to checking and repairing. Keep any specialist requirements on‐shore and utilise simple status signals with remote comms where possible, rather than house the processing & intelligence on the platform. Most online tools require some form of regular calibration, these should be avoided as they introduce an expensive and specialist burden to the O&M programme. Stick to traditional tools like annual DGA sampling as a minimum, and decide whether any more than this is beneficial. One application which may be more relevant offshore than on shore is consideration of an accelerometer to detect major impacts which could move or damage winding or tapchanger components. This may need to be transformer specific other wise it would be difficult to locate potential damage. For advice on obtaining value from condition monitoring refer to Cigre brochure 462 [32]32. 3.3.2.5 Tapchanger There are a number of different designs of TC, depending on the degree and accuracy of voltage regulation as determined by the system studies. The remoteness of platforms is such that an on‐load tap changer (OLTC) is likely to be required. Only the diverter switch requires maintenance work so it is installed in a separate compartment. This has a significant impact on the O&M. Historically, these require a degree of maintenance throughout the lifetime, since conventional OLTCs are using arcing contacts in oil with moving parts. And contacts are worn out by operation. Vacuum switch tapchangers are now available, which offer the potential to significantly increase the interval between maintenances, however even if the maintenance is eliminated the possibility of a fault and repair or replacement must be catered for. The manufacturer will provide special tools which will be necessary for tap changer removal. The platform design and transformer chamber will need to have an allowance for how to get the tool in place and set down space for the inspection and if necessary replacement with a spare. 3.3.2.6 Bushings Transformers are not generally transported on‐shore with bushings installed, so accelerometers to ensure transportation does not exceed design forces (needs to be carefully considered at the specification stage). Vibration associated with an offshore environment is a relatively new area for power transformer design. Marine specialists 32

CIGRE Brochure No.462 Obtaining Value from On‐Line Substation Condition Monitoring

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should be consulted when identifying typical conditions to design for. The HV connections will normally be either cable or gas insulated busduct (GIB). If cable is used, then usually proprietary plug in connectors will be used. If GIB the bushings will be gas to oil bushings. Generally these are maintenance free since there is no exposure to pollution. However, spares and the replacement procedure should be established to change out any suspect or failed bushings needs to be established. Suspect bushings can only be identified through tan delta tests or p.d monitoring. The units should also be specified to enable oil samples to be taken, if required. The LV connections may either be cable or solid busducts. For cable, again proprietary plug in connectors will normally be used but for solid busducts oil/air bushings are used and then enclosed in a suitable housing. 3.3.2.7 Cooling The cooling system is going to take up most of the transformer maintenance requirement due to the many moving parts required to circulate cooling fluids and the heat exchange mechanism (air or sea water). The reliability and availability tends to be dictated by the cooling plant and in practice is the source of most alarms. Eliminating them by use of natural cooling would provide a significant improvement to reliability and maintenance requirements, however this would expose the unit to the severe marine environment and require a much larger footprint. Unfortunately, power transformers with natural cooling are not typically used for the range of power rating typical for offshore collecting substations. Forced cooling is likely and this will have a big impact on auxiliary power demand, change over facilities will be necessary to manage redundant cooling systems. Table 3‐7 summarises the differences between different cooling designs. The interface between radiators and the cooling systems should generally be protected from the severe marine environment to prolong lifetime and minimise corrosion risk. In a marine environment, water cooling systems can be used, eliminating the impact of the harsh atmosphere on the moving parts. However, maintenance of pumps is still required in such a case. Cooling capability shall also include additional losses caused by harmonics which need to be dissipated from the transformer. This should be addressed in the thermal calculations of the transformer and considered in the heat run test. Fan cooling Both direct air cooling and closed water cooling systems retain the use of fans. Where fans have to be used, a level of redundancy may be a good practice to avoid endangering the system capacity when some of them fail. Switching of fan groups operating also helps to distribute their wear evenly and reduce the maintenance required. Where fans are used infrequently, a control system (using robust PLCs) should be programmed to switch them on periodically to keep moving parts operational and avoid collecting extensive saline deposits on critical elements. Elements of the transformer cooling will be exposed to the atmosphere, in particular the radiator units will need to be either regularly cleaned or replaced. This will require isolation, the location of isolation valves will make the difference between maintaining the unit on or offline. Sea Water cooling This technique is widely employed offshore in fixed installations and vessels and advice should be sought from the Marine industry to benefit from their experience. The key O&M

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points to note are that the system is compact and complex so accessibility to carry out maintenance needs to be carefully thought through. The main factors affecting O&M will be:‐ • Redundancy is essential to allow routine maintenance to be carried out. • Filtration ‐ regular filter changes since debris and material will clog up the systems if not removed • Saline pollution and corrosion is going to be one of the main issues to manage. • Automated cleaning systems are prone to failure. In addition this is likely to reduce the transformer availability. Segregating or redundant modules may be an option. •

Physical access to clean heat exchanger units and radiator fins will be required. Care needs to be taken with regard to personnel safety during this operation, since this is likely to be difficult to access.

•

Where sensitive parts are concerned then a closed loop system using de‐ionised water should be used together with a water to water heat exchanger.

•

As the natural cooling capability will be quite low, monitoring of the cooling system will be essential.

3.3.3

Repair and Replacement

A fault is likely to result in a long outage since the replacement time will be between 2‐18 months depending on whether a spare unit is available. Not every transformer fault will necessitate the replacement of the transformer. The routine replacement of components will be required so it is important to have a good QA system which can easily identify and tag components so the correct part is transported to the platform, since ‘popping back to shore’ is not really an option. 3.3.3.1 Major Replacement Strategy The initial design phase should allow for the emergency replacement of main items of equipment, in particular the power transformers, which could involve replacement of cooler elements, complete cooler banks or the transformer tank. To date the only known incident where the main offshore transformer has failed and needed to be replaced occurred on the Nysted offshore substation platform located in the Baltic Sea. The 132/33 kV transformer failed in service and tests indicated the unit needed be returned to shore for repair. This process involved a number of critical processes and these provide guidelines to the work elements that must be considered, typically:‐ z Electrical and mechanical disconnection of the transformer from the system z Removal, to a separate vessel, of approximately 20 tonnes of oil z Booking of a suitable heavy lift vessel (floating crane) z Repair capacity at a transformer manufacturer and availability of spare parts z Suitable handling facilities at the selected dock z Creation of suitable access zones in the roof on the platform to allow removal of the transformer using the crane z Oil handling facilities to refill the transformer after re‐assembly on the platform z Availability of suitably qualified personnel to undertake the works The faulted winding was replaced with a spare winding (purchased together with the transformer) and following successful testing the unit was prepared for return for

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installation on the offshore substation, the complete process taking approximately 4½ months The paper prepared by Andersen, Marcussen, Jacobsen & Nielsen [33]33 provides a detailed summary of the events and experience gained by this major transformer failure at an offshore platform and provides a good base document for strategy planning. 3.3.3.2 Spares The platform design is determined by the size and weight of components, therefore since only essential equipment will be kept on the platform the storage of spare parts will be on shore. The size, weight and storage of spare parts should be determined by transportation and platform access limitations. To minimize the variety of spares, standardization of parts and units should be taken into account. Necessity and manufacturing lead times should be considered for spares volume. Strategic spares Retaining strategic spare parts will be an important economic decision, since offshore, full redundancy of primary plant is unlikely. However a spare transformer and reactor may be a requirement. In addition the project should order an extra set of bushings, TC components, radiators and/or heat exchanger and earthing transformer. The number depends on the total number of that design in the whole wind park. Routine spares Routine spares are just as important as strategic spares. Pumps and motors for the cooling, fans, breather depending on the design chosen End of life replacement. The platform life is determined by the jacket which has a design life of 25‐40 years depending on the developer’s requirements. As such the whole platform will return to shore for overhaul. Therefore end of life replacement offshore is not anticipated but only replacement in the case of a fault.

3.3.4

Aspects of Specification which are Plant Specific

3.3.4.1 Environment 3.3.4.1.1 Paint Finish, Main Tank/Radiators If the transformer is located outdoors, the material should be resistant to such conditions. Offshore atmospheric conditions contain abundant traces of salt. Therefore, rust on transformer tank will likely appear. The Purchaser should specify the required paint specification and thickness. The transformer is installed on the upper floor of the platform. Consequently, seawater does not come in contact with the transformer directly. Therefore, the rust prevention processing of the transformer is not as severe as that of the platform jacket. In general, it is similar to the substation and facilities in the power plant constructed in the vicinity of the coast.

33 Andersen, N., Marcussen, J.H., Jacobsen, E., and Nielsen, S.B., Experience Gained by a major Transformer Failure at the Offshore Platform of the Nysted Offshore Wind power plant, in 7th International Workshop on Large‐Scale Integration of Wind Power into Power Systems as well as on Transmission Networks for Offshore Wind power plants. 26 ‐ 28th May 2008, Energynautics: Madrid, Spain.

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Transformers could be located indoors to protect from the environment. However, there are heat dissipation issues (except water cooling). Radiators or coolers should be located outside and the painting of the radiators should also be considered. Because the structure of the radiator is complex, it is painted by immersion in a paint tank. With this process, it is difficult to control the painting film thickness and sometimes differences in the painting film thickness occurs. Therefore, it is necessary to check the thickness of painting film. The Manufacturer should also consider the tank structure to prevent the build‐up of water. It is necessary to apply a gradual inclination to the upper part of the tank so that rain water will not be retained. 3.3.4.1.2 Deterioration of Plastic Material by Ultra Violet Ray The ultra violet rays offshore are stronger than onshore. Therefore, life time of some plastics or synthetic rubbers may be affected by it. For example, Polyethylene is a typical plastic which is degraded by ultraviolet irradiation. Hydroperoxide group, carbonyl group etc. is excited by ultraviolet radiation. Oxidation will occur by a radical generated in the reaction. Oxidation degradation will continue and physical strength of polyethylene will be reduced by rupture of main chain. 3.3.4.1.3 Ambient Temperature Offshore According to IEC 60076‐1, the normal ambient temperature is indicated as not below ‐25°C and not above 40°C. The average yearly temperature is assumed to be 20°C. These temperatures determine design of transformer active part and cooling system by enforcing specific temperature rise limits for oil and windings. The cooling system of the transformer has to be designed based on the transformer losses and ambient conditions to keep these temperature rises within the given limits. It is common to increase ambient temperature for transformers to be installed in hot regions. But the temperature range in offshore location may be different. Generally the change in the temperature of the ocean is known to be smaller than on land. The highest ambient temperature offshore is lower than onshore. Moreover, the wind power plant can be located in specific geographical regions with climatic profiles analysed in detail, including yearly temperatures. Hence, transformer specifications may reflect the expected temperatures more precisely compared to regular network transformers located throughout the countries and typically described by common ambient conditions. It is desirable to show the real ambient temperature of the place where the substation will be installed to design the equipment optimally for the given location. For example, if average yearly temperature is estimated to be lower by 10°C compared to the normal 20°C, the oil and winding temperature rise could be calculated by 10°C higher to allow operation of the transformer at the same absolute temperature. This could bring significant savings not only on the cost of the cooling equipment but also on the weight and size of the transformers. It is not necessary to reduce the specified ambient temperature, but it is an item that one may examine. The final technical solution may be more cost effective when specifying the real parameters existing in the specific environment. 3.3.4.2 Vibration and Transport Forces Normally, transformers are exposed to vibrations and transport forces during their transportation from manufacturer to the installation site. Due to large size and weight of 136

transformers these are usually transported without oil and with all large external components disassembled (bushings, radiators, etc.). Once filled with oil and fully assembled on site, they may still experience small movements related to final positioning in place. In case of transformers for offshore substations, the transport forces and vibrations are expected to be more complex and can be divided in five major groups, depending on their frequency and duration: z forces related to land transportation, z forces related to transport of transformer fully assembled on the platform to the offshore destination, z forces of lifting platform from the barge and locating on the foundation out at sea z vibrations from earthquakes, wind gusts and waves when installed on the platform, z vibrations from electrical equipment transferred through construction components. Consideration for all modes of the forces or vibrations should be taken into account at the design stage of the transformer. The platform designer should specify the expected level of vibrations arising from environmental impacts and the transformer manufacturer should indicate the maximum permissible level of forces or vibrations allowed for the given design. 3.3.4.2.1 Forces Related to Land Transportation These forces are not different for offshore transformer than for any other conventional design for onshore application. Transformer has to withstand forces coming from road, train or ship transportation in the conditions prescribed by the manufacturer. Normally, transformer is not filled. The maximum accelerations in each direction are normally indicated by the manufacturer and recorded during transport. Keeping them within acceptable limits guarantees no damage to the transformer structures and internal components. 3.3.4.2.2 Forces Related to Transport of Transformer Fully Assembled on the Platform to the Offshore Destination This type of mechanical stress on the transformer structure is not usual for regular onshore applications. Once the transformer is installed on the platform, it has to be fully assembled and filled with oil. Normally, commissioning and site test are performed at this stage. However, the transformer has not reached at its final destination, yet. All liquid‐immersed transformers have tanks normally designed for static mechanical loads coming from oil weight. However, when the complete substation is deployed to the offshore location, transformer has to withstand all the stresses existing during platform lifting, tilting, and transfer to the offshore site. This is unusual for all the components which are normally disassembled during land transportation, like bushings, radiators or conservator. The movement and three‐dimensional accelerations of the components may have different character: roll, pitch or heave. Assessment of the transformer transportation should be performed at the design stage to investigate if additional support or temporary bracing is required. These may be required to external coolers or separate radiators.

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Figure 3‐6. Example of Temporary Bracing on a Transformer for Sea Transportation The critical component exposed to unusual mechanical stresses can be conservator and its supporting structure. A conservator by nature will allow for fluid free movement and therefore will allow the oil to move significantly during transformer transportation. This inertia from the oil movement can produce additional forces on the supporting structure which is not experienced on a transformer which is installed onshore. In addition this can cause damage to the bladder, if installed in the conservator tank. The stress and dangers related to oil free movement within the conservator volume should be assessed. If needed the temporary solution for transport phase should be proposed. If the conservator is not equipped with the bladder, filling it up to the top for transportation could help reducing oil movement. It would still create significant forces of conservator supporting structure, as the oil weight would increase. The other option could be reducing level of oil in conservator to provide some more space below the bladder level. The images below illustrate the assessment of the stress distribution during transportation and illustrates a typical example where the stress concentration is around the fastening points and welds.

Figure 3‐7. Stress Analysis of Conservator Support The sea transport and lifting of the platform may also introduce significant forces and differential movements between connected items of plant and equipment, typically: 138

z

Between the transformer tank and a separate radiator bank which is connected by oil pipes, z Between the transformer and HV/LV primary connections (GIS busducts, solid insulated busbars, etc.). The design of topsides and equipment interfaces needs to consider this problem to mitigate any possible transport damage. Interconnections between the main plant components should provide enough flexibility to accommodate for reasonable movement which is inevitable during lifting and transport. 3.3.4.2.3 Vibrations from Earthquakes, Wind Gusts and Waves When the substation is set up in an area of sea, within an earthquake zone, it is necessary to consider an earthquake resistant design. Platform designer should indicate the effect on the platform of an earthquake, and the transformer designer should propose suitable fixing bolt number, size and position to platform designer. There is no doubt that the supporting structure of an offshore substation provides more movement and vibration to electrical equipment. Waves hitting supporting structure continuously and gusts of wind generate mechanical stress on the structure causing vibrations of various frequency and strength. However, these topics are not really covered in existing standards, and there is no specification, which considers the effect of low frequency vibration for electrical equipment to be installed on platforms. Specifications refer mainly to mechanical stresses related to impacts during transportation of equipment on land or by ship. Then, maximum levels of acceleration can be specified. In existing standards, there is no description about vibration of transformer foundation. This is different from seismic requirement. In offshore substation, we should consider low frequency sustainable vibration. The Purchaser should clearly indicate the amplitude and frequency of platform vibration caused by wave or wind. The Manufacturer should then consider and calculate the effect of the vibration. Particularly, fatigue fracture of structure (for example radiator, conservator supports, long and small diameter pipe etc.) and force of inertia of mineral oil or other kind of liquid would be considered for long term reliability and mechanical strength of the tank if necessary. Gas insulated transformer and/or dry type of transformer don’t need to consider the force of inertia coming from fluid, and the relative density of cooling medium is very small in their case. For the main transformer technologies the winding clamping structure does not need to be reinforced to ensure proper clamping of heavy windings over the time for environmental source vibration. It is able to withstand a short circuit stress and stress of low frequency vibration is relatively small. The tank is also very stable. Main transformer is very heavy and its tank can support it during transportation or earthquake. However, in small transformers (earthing or auxiliary transformer) the clamping structure design or transformer tank design may need to be checked to avoid leakages after being exposed to long term vibrations. The possible vibrations would depend on the type of supporting structure. The distinction should be made between jacket and monopile structures. Due to different principles of construction and different size of components the vibration characteristic and frequency is expected to be different.

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Another issue is mechanical strength of insulation material in case of resin encapsulated transformers. Although this type of technology would be unlikely to be used for main transformers, it could happen that cast‐resin transformers could be used as auxiliary transformers. Some wind turbine manufacturers specify vibration tests to ensure that design of a given cast‐resin transformer can withstand long time vibrations without cracking when installed inside the nacelle of wind turbine. Installation of transformer on the platform may result in similar effects with regard to mechanical fatigue of encapsulated insulation system. 3.3.4.2.4 Vibrations from Transformer Because the transformer is excited by 50 or 60Hz, the vibration of the transformer tank is at the fundamental frequency 100 or 120Hz while operating. When the vibrating tank is installed on the platform directly, the vibration of the transformer is transmitted to the platform. In addition, the vibration spreads to other equipment which is installed in surroundings, and it may cause malfunctions in the long time perspective. Moreover, the noise in the platform might increase by the transmitted vibration. Therefore it may be important to use the well proven and effective measures to set up the anti vibration isolator between the transformer and platform to intercept the transmission route. Particular attention is required when selecting the material. Normally transformers are installed outside where the environmental conditions are very severe. To select the material with weather resistance is important. If the material deteriorates, it would require a serious maintenance effort to exchange the rubber vibration isolators from under the transformer due to the weight of the transformer. When seismic design is required, with onshore transformers locking down attachments are fitted however, offshore mitigation of vibration transmissibility is difficult. There are some differences between the onshore substation and the offshore substation. (1) For the onshore substation, the base of transformer is very stiff. For offshore substation the base of the transformer is not stiff. (2) For the onshore substation, the use of stiff rubber vibration isolators can be chosen For the offshore substation stiff rubber vibration isolators cannot be used. In onshore substation case, to make vibration transmissibility sufficiently low, the natural frequency of the transformer and vibration isolator system should be tuned to well below the operating frequency of 100Hz or 120Hz. But this causes significant inconvenience as the natural frequency is very close to the dominant frequency range of earthquakes. Seismic ground motion may be amplified by resonance and may cause significant damage to the transformer. To reach a compromise between vibration transmissibility and seismic strength, the transmissibility is unavoidably set to a conservative level and the rubbers chosen for isolators are relatively stiff. Thus the effect of locking attachments does not destroy the effect of the stiff rubbers and transmissibility reduction is limited. The offshore substation base is not stiff. Therefore it is difficult to get adequate vibration transmissibility reduction by utilising stiff rubbers Within an offshore substation, to reduce the vibration transmissibility and also make fixing for seismic design are conflicting requirements. It is therefore necessary to make a balance at the design stage of the substation from several points of view (economical efficiency, liveability and safety).

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3.3.4.3 Special Technical Considerations 3.3.4.3.1 Early Requirement for Substation Design Information Ideally, all the appropriate technical options should be considered already in the early design phase of an offshore substation. To allow this, it is important that the equipment provider has the possibility to suggest different design alternatives. The specification of the electrical equipment should indicate that weight (and size) of the equipment has got special importance in the given installation, and this specification should not limit the choice to one solution only, as different alternatives might be advantageous for a given substation. When a new design concept is introduced some additional tests may be required to prove its performance. Sometimes, they are costly and time consuming, so they may not be preferred by equipment providers. However, it must be remembered that the implementation of such new concepts may bring specific technical or economical benefits to offshore substations. Then again, the proper evaluation of concept is necessary on the side of equipment provider and substation designer. It may happen that some offshore solutions do not have to be introduced specifically for offshore wind power plant substations. There is much more experience in the oil and gas industry, and a number of solutions developed before could be copied. Still, copying of solutions should be wise, and should take into account the specifics of the application. These new innovations cannot be done within a normal project programme and must be carried out in advance of the start of an actual project. The data on transformer weight and dimensions is critical to platform designers, so it is extremely important that physical characteristics of transformer resulting from chosen design concept will not be changed later, when platform design or construction is already in progress. NO. Required information item note 1 Transformer weight Guaranteed value 2 Transformer dimension Guaranteed value 3 Mineral oil / Liquid volume Guaranteed value 4 Auxiliary power for cooling etc. Table 3‐1. Required information for platform design 3.3.4.3.2 Need for Minimizing the Total Cost Apart from the environmental conditions, other factors specific for offshore platforms must also be considered. The total weight of the offshore topside and support structure is the major cost driver and limiting factor for manufacturing, transport and installation. Hence, specific attention needs to be paid to the weight and size of the electrical equipment, as it will have both a direct and indirect effect on the total weight. Limiting the weight of all electrical equipment to be placed on the platform will reduce the cost of the foundation and supporting structure. Individual weights of electrical components will also be critical for future handling and access management of the equipment during repair and/or maintenance. The research shows that achievement of overall lower weights of the electrical equipment and the platform is very important and therefore the weight reduction techniques should be given major consideration during front end engineering studies and conceptual design. The topsides structural steel may represent half of the topsides weight. Furthermore, a weight similar to the topsides is needed for jacket or pile to support it. Hence, reduction in 141

electrical equipment weight by 1 ton could further reduce the topsides and supporting structure weights by 3 tons [34]34. Obviously, the weight of the jacket or piles depends on many other factors like water depth or environmental conditions, as well. The impact of these is different in different regions. For example, the North Sea presents much more severe conditions compared to the Baltic Sea. Still, the equipment weight is a key factor for the structure complexity. To get a full picture of the platform cost, including costs of supporting structure and electrical equipment for specific projects, good communication between the electrical equipment supplier and the platform manufacturer is essential. A close cooperation is also crucial in order to achieve an optimal design solution and proper evaluations against different alternatives. NO. 1 2

LCC Items for OSS Equipment cost Weight for equipment

3

Dimension of equipment

4 5 6

Foot print area Volume for equipment Maintenance area/Volume Transportation cost for equipment Installation cost for equipment Required facilities cost

7

Dimension of substation

Foot print area Volume for equipment Maintenance area/Volume

8 9 10 11 12

Loss for operation Maintenance cost Life time Reliability Risk cost

note Transformer/reactor Transformer/reactor Cooling equipment Control panel For each equipment

Fire wall, Blast wall Drainage tank Diesel generator capacity Total system +Directly connect between GIS and Tr. +common maintenance area etc.

Fire and/or explosion Oil leakage A tidal wave(tsunami) Etc.

Table 3‐2. Examples of LCC items What cannot be forgotten is the huge cost of the transportation of the platform to its installation site. Then, it is not only the cost of electrical components and the supporting 34 N.G. Boyd, Taylor Woodrow: “Topsides Weight Reduction Design Techniques For Offshore Platforms”, Paper Number 5257‐MS, Offshore Technology Conference, 5‐8 May 1986, Houston, Texas

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structure which must be considered in design evaluation, but also the cost of transportation and installation. Including this element at the design stage is not natural for substation designers, who do not have this issue in case of conventional onshore installations. Hence, it is also difficult to estimate what can be the impact of specific components on the transportation and installation cost. Anyway, the designers should give some thoughts to this topic when evaluating different design concepts. The pros and cons must be evaluated for a given solution by the transformer designer, and transformer designer can propose them to reduce the initial cost and maintenance cost (the life cycle cost). We need to change the view point for evaluation from conventional thinking because of the unique situation of an offshore substation. For example transformer weight is an important item for conventional substation. The base of transformer size is decided by its weight. In offshore substation, transformer weight also affects transformer base, platform size and weight and jacket or mono pile structure. The examples of LCC items, which should be considered for minimizing, are indicated in Table 3‐2. To minimize the life cycle cost (LCC), the transformer designer should discuss with the system designer and the platform designer. The objective is to obtain the overall optimum solution for the transformer, platform and foundation. 3.3.4.3.3 Insulation Systems in Power Transformers There are three major technologies available in transformer construction: z liquid‐immersed transformers z gas insulated transformers (GIT) z dry‐type transformers Each of them has got their advantages and drawbacks. Some limitations or special requirements are applicable for each technology. (1) Liquid‐immersed transformers The liquid‐immersed transformers are the most common type of technology. The principle is based on solid impregnable insulation materials (paper and board) used for insulating and spacing electrical parts and then immersed in dielectric fluid. The fluid impregnates the solid insulation components providing a good electrical insulation system. Apart from its dielectric role, the fluid transfers heat from windings to tank surface and coolers. With a long history of use in onshore substations, the liquid‐immersed transformers are commonly used in a wide range of rated powers, from small pole‐type distribution units up to large network, GSU or HVDC units, including highest voltage classes. Mineral oil is the most common insulating and cooling medium used in transformers. Naturally, the same technology is commonly adopted for offshore substations, and that is why most of the references in this document refer to liquid immersed transformers. However the operating conditions found in offshore substations are very different from those found onshore. When considering the application of oil filled transformers for offshore substations, the purchaser and manufacturer will need to check that the transformer design is suitable for the service conditions that will be experienced in the offshore substation. Use of oil in large quantities in each large transformer results in specific issues related to its handling and maintaining it in good condition. This can be a major issue in offshore installations as it combines aspects related to maintenance, impact of harsh environment and safety problems (both fire and environmental). 143

Performance of oil is critical for the correct performance of the transformer. The oil has to be protected against oxidation and moisture access. At the same time the thermal expansion must be allowed when temperatures inside the transformer tank are changing. The systems used for protection of oil against the environmental impacts from the air include according to IEC 60076‐1 [35]35: z freely breathing systems with dehydrating breathers, z diaphragm or bladder‐type liquid preservation systems, z inert gas pressure systems, z sealed‐tank systems with gas cushion, z hermetically sealed completely filled tanks. Hermetically sealed tanks provide best protection against moisture and oxygen access to the transformer fluid. However, allowing sufficient tank expansion for hot liquid has limited their typical application to smaller transformers only (common solution for small distribution transformers). For bigger units a nitrogen cushion can be used over the oil level to allow for required oil expansion. The development in the application of hermetic transformers has continued towards larger sizes and transformers up to 60 MVA, 110/33 kV have already been successfully installed on offshore substations. The majority of transformers installed so far use more conventional oil protection systems – conservators allowing expansion of oil. Access of air over the oil surface in the conservator is enabled through dehydrating breathers, which remove moisture from the incoming air. In free breathing systems the air in conservator has got direct contact with the oil and transfer of oxygen and moisture between the air and oil is possible. This process is harmful for the transformer insulation system as it causes degradation of oil and solid insulation in the long term perspective. Moreover, the dehydrating breathers normally require periodic maintenance or replacement. The disadvantage of free breathing systems can be more pronounced in an offshore environment, where moisture and salinity content in the air is dramatically higher than onshore. The degradation processes in such transformers may be more visible, or more frequent maintenance of dehydrating breathers can be required, which should be rather avoided in case of offshore installations. The use of rubber bags or bladders in conservators prevents direct contact of oil with the air and limits access of moisture to oil by about ten times. In such solution the space over the oil is normally protected by the dehydrating breather, too. This is for the occasion of bladder to be damaged or moisture penetration through the bladder material. Consequently, the undesired periodic maintenance is still required to the breather, however, low maintenance breathers are available and these should be used for offshore substations. Performance of oil in the given system and related maintenance required should be thoroughly considered when specifying transformer for offshore application. The environmental impact and fire safety of an offshore transformer is related to the type of insulating liquid used. Since the total quantity of oil present in an offshore substation may reach hundreds of tons, considerations of the environmental protection and fire safety become paramount. Transformers filled with mineral oil are notorious for their fire behaviour. Mineral oil used commonly in conventional liquid‐immersed power transformers is flammable. Electrical failures in the area of transformer active part or bushings can result in oil spillage and fire. The transformer can also be a victim of fire occurring at the platform and related to 35

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malfunction of other components. The fire protection systems are necessary to limit damages resulting from oil fires. This issue is critical in case of offshore installations, where the quick access of fire fighting personnel is not possible. This is described in more detail in Section 4. Tank rupture or even transformer explosion could result from high energy failure inside the transformer. The high energy arc created in transformer oil generates large volumes of oil vapours. The pressure building up quickly may lead to violent tank expansion resulting in its rupture. Oil can be spilled and result in fire as mentioned before. There are various strategies for prevention of tank ruptures. They are based on pressure relief valves installed on the tank surface. When pressure builds up, the valve opens allowing for evacuation of oil excess and prevents tank walls or radiators from mechanical damages. The modern protection strategies include solutions collecting oil evacuated from the tank and filling emptied volumes of the tank with nitrogen to prevent oxygen access to the failed transformer. This eliminates the possibility of fire. SERGI is system commonly known and using this principle, although they do not have any offshore experience yet. Some studies show that evacuating of pressure and oil excess in one location is not sufficient and it is critical to have the pressure relief device located as close as possible to the location of internal failure inside the transformer tank. Hence, it may be preferred to have a number of pressure relief devices distributed on tank walls and transformer cover. Some solutions use more than twenty pressure valves. In such cases they are all connected to an oil collection tank by a piping system. Apart from dangers related to fire or explosion risks, the environmental safety is also critical. Mineral oil used in transformers is harmful to the environment and is not biodegradable. For that reason, all transformer installations with transformer oil contain oil collection systems to prevent oil spillage. The simplest way of preventing environmental damage from fluid leakage or spillage is to build collection trays under the equipment to collect the fluids. The leaked fluid could then be piped to sump tanks, which will be designed to contain, as a minimum, the amount of fluid from the single largest piece of fluid filled equipment (transformer). The planned collection of spilled fluid as described above, can only occur if this spillage has not been caused by some violent event such as an explosion. Given the large volumes involved, planning to minimize the likelihood of catastrophic unexpected events in the substation should be part of the basic design. In order to reduce the environmental and fire safety hazards posed by mineral oil, it is possible to build in these safety features by the use of fire resistant biodegradable alternative insulating fluids. Historically, the application of alternative fluids was limited to small capacity transformers. They are widely used in application for wind turbine transformers and within the same range of MVA capacity could be applicable for auxiliary transformers in the offshore substations. However, recent developments recognising benefits of these fluids move towards higher MVA and voltage ratings. The electrical equipment design is similar to that used with mineral oil, although some adjustments may need to be made to allow for the difference in the performance characteristics of these fluids from mineral oil. These considerations are most evident in the design of the larger volume, higher capacity alternative fluid transformers. A full discussion of the properties of these alternative insulating fluids can be found in the CIGRE Technical Brochure 436 “Experiences in Service with New Insulating Liquids”, 2010. 145

(i) specific issues related to alternative fluids, advantages: less flammable, biodegradable, disadvantages: higher viscosity, higher thermal expansion, gelling at lower temperatures (natural esters), dielectric performance, suitability for tap changer operation There are a number of alternative fluids available as alternatives to mineral oil for transformer insulation and details can be found in IEC‐60076‐14. The most common and commercially available fluids fall into three main categories: z synthetic ester, z natural ester, z silicone fluid. Table 3‐3 gives a brief overall comparison of the broad properties of these fluids. Mineral oil Synthetic ester Natural ester Silicone fluid Fire safety Low High High High Environmental safety Low High High Low Corrosive sulphur Possible None None None Paper longevity Moderate Good Good Unknown Oxidation stability Moderate Good Poor Good Moisture tolerance Poor V. High High Poor Table 3‐3. Comparison of properties of major fluid types From the categories listed above, the properties of silicone fluid are the least suitable for application in larger power transformers. Also, this type of fluid is not biodegradable to the level presented by esters. Fluids which are both fire safe and biodegradable fall into synthetic esters and natural esters. The physical properties of most common representatives of these groups are summarized in Table 3‐4. An inherent feature of ester fluids used in power transformers is their ability to operate in temperatures higher than normally allowed for mineral oil. By this the cooling system of equipment could be reduced, in consequence reducing the volume of fluid in the equipment. If the designer decides not to reduce the cooling system, and prefers to operate the fluid at conventional temperature typical for mineral oil, the additional thermal capability of esters gives a good safety margin for unexpected overloading or other abnormal working conditions for the equipment. Properties of alternative fluids could then compensate partially for problems potentially experienced in cooling systems, providing some kind of redundancy and helping in improving the reliability of the entire power system. (ii) impact of biodegradable fluid on requirements for oil collection and on environmental issues A number of biodegradable dielectric fluids (natural or synthetic esters) are commercially available. In the event of a spillage they do not leave any toxic residues that could be harmful to the environment. They are all readily or fully biodegradable. This effectively means that if leak occurs, and leaked liquid flows into the sea, they are rapidly degraded in a short time by naturally occuring bacteria, resulting in their low environmental impact. Those fluids are safe and green products.

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Table 3‐4. Properties of selected dielectric ester fluids used in the transformer industry (as per CIGRE Brochure 436) With these alternative fluids, a responsible attitude should be adopted, but it does mean that when a volume of liquid leaks to sea their environmental impact would be much less than with the equivalent leak of mineral oil. With present legislation a large amount of environment friendly material, which is not a material of a natural origin, cannot be thrown into the sea. Moreover, even if it is natural material (ex. rapeseed oil etc.) originating in the natural world, a large amount of leaked material causes harm to the natural world in the short term and so it needs to be treated the same as for mineral oil.

Figure 3‐8. Comparison of biodegradation rates (from CIGRE Technical Brochure 436) 147

The issue of environmental safety related to alternative dielectric fluids still requires further studies and development of international regulations accordingly. (iii) impact of less flammable fluids on requirements for fire protection systems Equipment filled with less‐flammable fluid is less vulnerable to burn in case of overheating or electrical fault. If it happens that the fire starts, the fire will either extinguish by itself or it will be less violent compared to the fire of mineral oil. Also the equipment filled with less‐ flammable fluid will be less sensitive to fires in its vicinity. On the other hand, even if conventional mineral oil was used in the main transformers, the less‐flammable fluid could be used in auxiliary units to eliminate risks in the main unit surroundings. International Standard IEC 60695‐1‐40 “Fire hazard testing: guidance for assessing the fire hazard of electrotechnical products ‐ insulating liquids” [36]36 illustrates and confirms the good fire safety record of liquid‐filled transformers, and that fire incidents with such fluids are very rare. Conventional transformers have a mineral oil class O1 liquid (liquid with fire point <300°C and a net calorific value >42MJ/kg). For comparison, the synthetic esters and silicone liquid are classified class K3 (liquid with fire point >300°C and a net calorific value <32MJ/kg). Natural esters are classified as K2, due to their slightly higher net calorific value. It is realised that it may be difficult to completely remove the fire‐extinguisher system by using less flammable fluids in place of mineral oil at present. It may not be permissible to remove the fire extinguishing system because, in albeit extreme circumstances, they may catch fire. Less flammable fluids cannot eliminate the fire risks completely and they retain an explosive risk similar to that of a transformer filled with mineral oil. The specific allowance reduction of fire fighting requirements still depends on national regulations. For example in Japan, in the fire service law, no permission is given for reducing the fire protection equipment when using less‐flammable fluids. However in USA, the less‐ flammable fluids are recognized as a fire safeguard by Section 15 of American National Electrical Safety Code (NEC) [37]37. National Fire Protection Association (NFPA) provides the reduction condition of the fire fighting equipment and the electric protection device of the substation by using less‐flammable fluids for transformer having a rated voltage of not more than 35 kV. A recent study by the Swiss Institute for the Promotion of Safety and Security has assessed different fire safety situations and compared the risk where a synthetic ester filled transformer is compared to an equivalent mineral oil filled transformer. [38]38: “Equivalence study for transformer fire protection using “ester‐based” insulating fluid” Swiss Institute for the Promotion of Safety and Security, Zurich, Switzerland, June 2011. Assessment was made for the likelihood of the following situations: a) The transformer affected is totally destroyed by fire; neighbouring plant sections or transformers should remain thermally intact. b) Fire damage due to an electrical fault of a transformer should be avoided or should be regarded as highly unlikely. c) A fire with a capacity of 10 MW in the immediate area should not impair the function of the transformer With the conditions in place where: 36

IEC 60695‐1‐40 “Fire hazard testing: guidance for assessing the fire hazard of electrotechnical products ‐ insulating liquids”

37

American National Electrical Safety Code (NEC) Equivalence study for transformer fire protection using “ester‐based” insulating fluid” Swiss Institute for the Promotion of Safety and Security, Zurich, Switzerland, June 2011

38

148

1 Transformer outdoors with protective screen 2 Transformer outdoors without protective screen with little safety clearance 3 One transformer in the room (fire sector) 4 Several transformers in the same room (fire sector) The safety assessment outcomes were recorded as Y Target can probably be reached N Target can probably not be reached The full assessment table is presented below From the point of view of practical application, scenarios a) and b) are the most significant, as they represent the situation where the fluid filled transformer is the source of the fire. In these cases, the assessment table below clearly shows that the use of synthetic ester is at least as good as using mineral oil with fire protection systems. Indeed, in scenario b), the table shows that even with a variety of fire protections systems in place, the use of mineral oil is unlikely to be safer than using synthetic ester without an extinguishing system. Only in scenario c), which represents the situation where the transformer is not the source of the fire, is there some assessment equivalence. This is entirely logical as the fluid inside a transformer, however fire safe, cannot influence events outside the transformer and prevent nearby objects burning, and in this situation, a deluge system may be appropriate. What can be said is that a fire safe fluid such as synthetic ester will not contribute to the spreading of such a fire. “conventional” No extinguishing “conventional” deluge system gas extinguishing water systems systems (nitrogen/CO2)

Spray – high‐ pressure extinguishing system (> 75 bar)

1)

2)

3)

4)

1)

2)

3)

4)

1)

2)

3)

4)

1)

2)

3)

4)

a) Oil a) ester

Y Y

N Y

Y Y

N Y

Y N

N Y

Y Y

N Y

Y Y

Y Y

Y Y

Y Y

Y Y

Y +

Y Y

Y Y

b) oil b) ester

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

N Y

c) oil c) ester

Y Y

N N

Y Y

N Y

Y Y

N N

Y Y

Y Y

Y Y

Y Y

Y Y

Y Y

Y Y

Y Y

Y Y

Y Y

Table 3‐5. Swiss Institute for the Promotion of Safety and Security fire safety assessment ‐ synthetic ester filled vs. mineral oil filled transformers (iv) alternative insulation systems in liquid‐immersed transformers as per IEC 60076‐14, By use of alternative insulation systems in liquid‐immersed transformers, performance characteristics can be modified. For example, use of aramid fibre for winding insulation allows for higher temperatures and reduction of cooling system. Or, using insulation of higher thermal capability can reduce insulation thermal degradation and improve long term reliability of equipment.

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Table 3‐6 shows comparison of medium size power transformer insulated with hybrid insulation system using aramid insulation as per IEC/TS 60076‐14 [39]39 vs. conventional transformer of the same voltage and power rating. In the example presented, the weight reduction is about 11%. In extreme cases, when the weight is more critical and higher load loss increase could be accepted, the weight reduction achieved by using hybrid insulation system could be up to 25%. hybrid system

insulation conventional insulation

Rated power [MVA] 36 Average winding rise [K] 85 65 No‐load loss [kW] 16 17 Load loss [kW] 142 109 Weight [kg] 57 600 65 000 Table 3‐6. Comparison of transformer with hybrid insulation system and conventional design of the same power rating [40]40 The hybrid technology was historically developed for mobile transformer substations, where weight and size of equipment was critical for substations mobility. As a result, the majority of related data refers to medium size power transformers from the range 15‐60 MVA, however, recent developments focus on larger transformers in the range of 200 MVA. The pros and cons must be evaluated for a given solution, and the life cycle cost should be analysed. For the electrical performance, the compact hybrid insulated transformer, as presented in the table, has higher load loss than a conventional design. This is of course a disadvantage in any distribution or transmission network. However, in an offshore demanding environment, the reduced weight and simplified maintenance may be evaluated that such a hybrid solution might be of interest anyway. (2) Gas insulated transformers This transformer was developed for indoor and/or underground substation in urban areas. In 1956, the first unit of gas insulated transformer (GIT) was developed further in USA. In those days, ironically, PCB oil was used for safety purpose. Therefore, this technology was not developed in USA. The first GIT in Japan was put into commercial operation in 1967. Since then, more than 10,000 GITs have been installed and are currently operating in the field. More than twenty 300MVA‐class GITs have been provided, including the largest‐ capacity units in the world: the 330‐400MVA GIT. By the same technology, 275‐150Mvar gas insulated shunt reactor (GIR) has been provided in 1994. These facts indicate that GIT/GIR technology is reliable and proven. The GIT/GIR has some advantages; non‐flammable and, non‐explosive. It is useful for building smaller substations by using gas insulated technology. Because this transformer is non flammable, it is not necessary to take the fire prevention distance between transformer and other equipments. GIT has lighter weight than oil transformer. Because core and coil weight of GIT is the same as conventional transformer. But SF6 gas and mineral oil weight is 39

IEC 60076‐14 Power transformers, Part 14: Design and application of liquid‐immersed power transformers using high‐ temperature insulation materials 40 K. Leuridan, J. Declercq, R.P. Marek, J.C. Duart “Compact power transformers for substation in urban areas using hybrid insulation system”, CIGRE A2 Colloquium, Brugge, 2007

150

different. And GIT has small risk of low frequency vibration from wind gusts and waves, Because the relative density of cooling medium is very small. (Refer to 3.3.4.2.3) Its superior characteristics are very useful to reduce the risk, dimensions and weight of offshore substation. Of course this transformer has some disadvantages, such as: (i) Auxiliary loss is bigger than conventional transformer (ii) Natural cooling rating is smaller than conventional transformer (Low pressure transformer can apply radiator for natural cooling but there is a limitation. Maximum natural cooling rating is approx.30MVA. More than 30MVA, transformer will be much bigger.) To draw out its ability and reduce the total cost for building offshore substation, it is desirable that purchaser and manufacture discuss the most suitable specification of transformers for offshore substation. (3) Dry type transformers Dry‐type technology is normally used for low voltage and small capacity transformers. Air being the insulating medium for main insulation and the manufacturing technology are the limiting factors for expansion of the technology to the range of large power transformers. Although the advantage of the technology for offshore application could be oil‐free, and no issues related with its handling, the disadvantages related to sensitivity of dry‐type systems to harsh environment exclude it from offshore applications. Dry‐type transformers would normally require hermetic enclosures in offshore application which would make them significantly bigger compared to liquid‐immersed units of the same power capacity. Another issue is mechanical strength of insulation in case of resin encapsulated transformers. Any crack in the insulation system of cast-resin type transformers may lead to breakdown and catastrophic failure. Moreover, cracking of cast structure cannot be detected before the failure unless partial discharge measurement is made on the transformer during periodic maintenance. The support part or the lead of winding should be inspected carefully in regular inspections. With application on offshore platforms which are exposed to various vibrations modes, the sensitivity to mechanical impacts is another disadvantage. 3.3.4.3.4 Alternative Solid Insulation (Aramid) for Higher Overload Capability and Extending the Life of Insulation System The reliability of offshore equipment is a key issue, as maintenance or repair works are very costly. Although, thermal failures of insulation in regular network transformers do not happen very often, all the means should be taken to ensure good long term performance of insulation system of the transformer. Specifying reduced maximum hot spot for windings used sometimes in onshore applications, is not practical offshore, as it would require more cooling to be installed on the transformer. Application of insulation materials of higher thermal class than conventional cellulose could be a suitable solution. For all the transformer technologies the aramid conductor insulation could be utilised. Additionally, some other materials can be applicable in specific transformer technologies. For example, thermally upgraded papers could also be used in liquid‐immersed transformers, and polyimide films in gas insulated units. Higher thermal class of conductor insulation material provides extended insulation life not only in case of operating of transformer in rated conditions, but also in case of unexpected overloads. Hence, it can be considered as extra safety measure for the equipment, built into its design (example 200 MVA main transformer in Belwind project).

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3.3.4.3.5 Method of Cooling Different options can be used for air cooled equipment. One example is conventional radiators, with or without forced air flow, which can be used to dissipate heat from the transformers. The forced air flow could reduce size of cooling system but it requires fans. It is a trade off between the more space consuming alternative without forced air or the relatively compact alternative requiring fans. Using even more compact solutions (including water coolers) may be preferable in terms of saving space on the platform. However, coolers with water require pumps and piping which are both slightly costly and space consuming. Water cooling can be considered in two ways, one is using sea water (open water) cooling and another is closed water cooling. Sea water cooling, marine debris/obstacles adhere inside of pipes, water coolers, pumps. Therefore cleaning will be required to keep the cooling capability during the operation. Normally to protect the transformer’s cooling system water should be divided into two systems. Primary water system uses sea water, secondary water system uses pure water (closed system). Another system is closed water cooling, which doesn’t use sea water. This system requires the air cooler, which is located outdoors in a severe condition, to dissipate the transformer heat. This cooling system is a little complicated, but after long operation, when cooling system reaches the end of its life span, it can be changed without oil treatment. (refer to Table 3‐7) All these systems are available for both liquid‐immersed and gas insulated transformers. The typical cases of equipment requiring maintenance are parts of the cooling system, such as fans and pumps. Eliminating them by the use of natural cooling would provide a significant improvement in reliability and maintenance requirements. Although power transformers with natural cooling are not typically used for the range of power rating typical for offshore collecting substations, the ONAN cooling could be considered from maintenance perspective. To eliminate the fans water cooling systems can be used, eliminating impact of the harsh atmosphere on the moving parts. However, maintenance of pumps is still required in such a case. (refer to Table 3‐8)

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AIR COOLING INDOOR

CLOSED WATER COOLING OUT　SIDE Severe environment

SEA WATER COOLING INDOOR

INDOOR

Configuration

Outside Severer environment

Sea

Heat exchanger can be changed easily without OIL handling. The area of the equipment is small.

Heat exchanger cannot be changed easily. The area of the equipment is large.

System is slightly It is necessary to remove redundant and marine debris/obstacles, complicated. Initial cost is it is more complicated with high redundancy. high. Running cost is high.

Advantage Disadvantage

Compact and highly preserved feature under the severe environmental condition The area of the equipment is small.

Simple structure Initial cost is low.

TABLE 3‐7. Comparison with cooling methods (1) Natural air ∆ X O ∆

Forced air O O X ∆

Initial cost Transformer size of weight Auxiliary power Big maintenance (ex. exchange of coolers) Small maintenance O ∆ (ex. exchange of fan bearing) Good: O ∆ X : Bad TABLE 3‐8. Comparison with cooling methods (2)

Forced water X O X O ∆

3.3.4.3.6 Air cooled Radiators Tank Mounted or Separate Pros and cons are described in Table 3‐9 between air cooled radiators which are mounted on transformer tank and separated.

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advantage

Tank mounted air cooler Overall footprint is smaller

Separated air cooler Only coolers need high levels of ventilation: 1) Making fire suppression around transformer tank easier 2) Allowing a more controlled environment around the transformer tank No issues with differential movement Transformer tank assembly is smaller of tank and radiators during and lighter reducing the necessary capacity of the support structure. transport or in service. Significantly less platform volume More flexibility in platform design? required if we assume the coolers need both enclosure (to prevent oil spills) and maintenance access to the coolers Should be easier to assemble on site The transformer and coolers are lifted separately and empty which reduces the capacity of the crane required. Easier access for maintenance of radiators than for tank mounted version, radiators could be more easily exchanged (?) More suited to an enclosed topsides concept – e.g. floating platforms which self install, as the transformer space can be almost completely enclosed. Potential to locate the coolers at a relatively higher level to the transformer, and as a result use the platform space better. Separate coolers means we can replace individual cooler cartridges at a time while keeping the whole transformer live, and not entering the transformer space. Option to address the amount of enclosure of the coolers. Some suppliers have been designing the coolers to stand in the open on the platform. Separate coolers allow to consider alternative forms of oil cooling. This will be more important for HV/DC platforms which have an inherent 154

disadvantage

Concentrated load requires stronger platform structure (cost?)

need for more cooling of equipment. Additional support structures are required for the oil pipes between tank and cooler. Filling of the transformer and coolers with oil is more difficult as the location of the transformer is typically a number of metres above ground level in the shipyard.

Whole of transformer space has to have high levels of ventilation: 1) Making fire suppression more difficult 2) Exposing the transformer tank to more salt corrosion and contamination Larger crane will be required for lift Needs careful design of the piping especially if it is filled with oil at systems. ground level. Access for maintenance of the coolers is more difficult. Heavier transformer means a heavier offshore installation vessel should the transformer need to be replaced. TABLE 3‐9. Comparison between tank mounted radiators and separated

3.3.4.3.7 How to Remove a Single Radiator Element The radiator can be removed by partitioning oil or the gas with butterfly valves, which are installed between the main body tank and the radiator. Figure 3‐10 shows the steps of removing work for a single radiator from the transformer. To install the butterfly valves and drain valve for each radiator is costly for small transformer. The maintenance strategy needs to be fully considered at the design stage.

conservator butterfly valve

radiator Main tank

drain valve

(1) (2) Figure 3‐10. Step to remove a single radiator

(3)

3.3.4.4 Physical and Interface Considerations If it is planned that personnel access to the transformer room will be permitted whilst the equipment is “live” then the statutory safety clearances, minimum height to insulation, as defined in the relative IEC Standards needs to be maintained 155

The high voltage connections to the transformer HV windings would generally be made using either cables or gas insulated busbars (GIB) and the method of connection needs to be identified at an early stage to allow the mechanical design of the transformer to proceed. If the design incorporates GIB connections then as stated above the possibility of differential movement during sea transport needs to be considered. Also where the GIB passes through any enclosure panels it must be suitably sealed against the environment and/or fire consistent with the rating of the enclosure. The connections to the transformer LV windings would generally be made using either cables or solid insulated busducts and the method of connection needs to be identified at an early stage to allow the mechanical design of the transformer to proceed. If the radiators are to be mounted separate from the transformer then traditionally the transformer manufacturer provides the control cables between the transformer and the radiators. At the time of order for the transformer the route for these cables may not be known, hence this interface needs to be identified and managed. If the design incorporates cables then the problem of differential movement may not be so onerous, however, the approach of the cables must be carefully considered and may need to be varied depending upon whether the transformer tank is located in an open position or within a covered room. Cables approaching horizontally or vertically from above may be acceptable if the transformer is housed within a covered room, however, they may not be suitable if the transformer is in an open position. For a transformer in an open position cables approaching vertically from below would be preferred. There are factors which need to be considered in the design of the transformer, typically:‐ z Interconnecting cables between the transformer and items of switchgear would normally be installed and tested in the onshore fabricator’s yard prior to sail‐out of the platform. z Disconnectable cable terminations would be preferred with the female portion of the termination and insulator included in the transformer cable chamber. This allows the chamber to be conditioned and hermetically sealed in the manufacturer’s works with no need to open the chamber to the elements during cable installation. z The minimum bending radius for the cables need to be considered together with working space adjacent to the transformer for the cable installers. This can be particularly important when the transformer is mounted to the deck plates and the space directly below is an open area exposed to the marine environment. The operatives in this instance would be working from below the transformer through access areas in the deck plates. The position of the cable head on the transformer will influence the facilities which need to be built into the room/enclosure where the cable connections enter. As stated above the switchgear interconnection cables would normally be installed and tested during the onshore assembly in the fabricator’s yard. To permit electrical testing of the cables the transformer cable boxes may need to include removable links.

3.3.5

Specific Requirements for Rooms or Enclosures

If the design of the transformer includes open terminal connections the statutory safety clearances, as defined in the relative IEC Standards should be maintained. (Usually transformer terminals for offshore substations are not open terminal and live parts are not exposed)

156

During the early stages of the substation platform design process the physical parameters of the transformer must be identified, typically weight, oil volumes, footprint, cable entry points, type of HV and LV connections and direction of approach of connections. Whilst the overall weight is an important factor in the design of the primary steel members for the platform the footprint is vital to determine the actual locations for the main steel deck members. The steel deck members must be located to match the points where the transformer load is transferred into the deck, typically beneath the anti‐vibration pads and jacking points. The locations for cable entry points need to be identified to ensure that the support steel for the deck does not interfere with the cable access. The design should identify access positions for HV power cables or GIB ducting, LV power cables or solid insulation busducts, multicore control cables to the transformer, tap changer, fans etc. As stated in 3.2.3.4 space within an offshore substation platform is always at a premium and increases in room/enclosure sizes produce a large financial penalty, therefore, the pressure is to keep the room dimensions to a minimum. The following items should be considered in the design of the room/enclosure:‐ z The platform designer must determine the minimum amount of space around the transformers to permit all aspects of planned and unplanned operation, maintenance and repair works z Sufficient space must be allowed for handling of any large sized test equipment z Access should be considered to permit maintenance of the tap‐changer and fitting of the extraction tools z Sufficient space must be allowed for any necessary fixed or temporary access platforms required to access specific parts of the transformer (typically the tap‐changer, Buchholz relays etc). If a permanent platform is to be installed with an access ladder or stair then access may need to be prohibited whilst the transformer is in service. This may involve interlocking a climbing preventer with the electrical switchgear. The design must allow for future replacement of radiator elements, a complete radiator bank and also the replacement of a transformer tank. The following items should be considered in the design of the room/enclosure:‐ z The radiator elements will generally be in an open location, however, access needs to be allowed for removal either by the platform crane, suitable lifting beams, or a vessel mounted marine crane. If the radiators are covered by a roof section then this may need to be removable z The transformer should be positioned such that removal can be effected by the use of a vessel mounted marine crane/jack‐up crane. To facilitate this procedure the roof of the transformer room may need to be removable z The design will need to consider the draining and re‐filling with oil which will necessitate suitable 400 Volt electrical supplies to power the filtration equipment and space to position the equipment together with the oil When dimensioning access doors into the room/enclosure they should consider equipment access during initial installation and lifetime maintenance or repairs, together with personnel access. Steel doors used offshore may become excessively heavy so incorporation of removable panels in the enclosure may be an effective alternative to keep the doors to an acceptable or standard size. The room/enclosure layout should consider emergency egress from the room in the event of an incident. Consideration needs to be given to the room dimensions and positioning of 157

the transformer to provide suitable escape routes and doors. All hinged doors and escape hatches should include panic bars on the internal face. Heat will be generated by both the transformer tank and the radiators during service and the room dimensions, ventilation systems will need to allow for the dissipation of this heat in their design. A typical fan assisted radiator bank may require up to 100m3 /second of cooling air for a 200MVA class transformer so the room/enclosure will need to permit a free flow of air to and from the radiators. If the enclosure has walls then they could typically comprise open mesh, louvers or a similar construction. If the radiators are in an open location then measures should be taken to discourage roosting sea birds with their attendant guano pollution. The transformer room/enclosure needs to be constructed with an oil retaining bund which would prevent any escape of oil from entering the sea. The bund deck/floor should be constructed with falls (typically 1:80 or 1:100) to direct fluids into drains to a remote oil containment tank. The system should consider and allow for:‐ z The collection of general oil spills from the transformer or radiator together with any maintenance activities. z The collection of oil from a transformer or radiator leak where there is a pressure head to cause it to spray (typically near to the bottom of a radiator) z A serious leak where, at worst all of the oil from the transformer could be discharged z A catastrophic failure where burning oil is discharged to the deck/floor causing a pool fire. z The drainage system should include flame traps to prevent burning oil from reaching the remote storage tank z Rain water from the radiator area z Water from an automatic, water based, fire suppression system where fitted z Separation of the oil from water The oil containment tank must be suitably dimensioned to accept as a minimum the full volume of oil from the largest oil filled device plus the full volume of water from an automatic fire suppression system plus spare capacity (suggest 15%). The method of specifying the tank capacity may vary to meet local regulations. The drain pipework between the transformer bund and the containment tanks should discharge fluids at a minimum rate of 7,000 litres per minute The transformer room should contain a fire detection/alarm system and the substation fire plan will usually detail if the transformer/enclosure is to be designed as an active fire protection zone and contain an automatic fire suppression system. Where a fire rating is assigned to the transformer room walls then any access doors within the wall must be suitably fire rated to match that of the wall. Requirements for the transformer lighting, small power, heating and ventilation systems are detailed elsewhere in these guidelines

3.4

Earthing/Auxiliary Transformers

3.4.1

Aspects of Specification which come from System Studies

3.4.1.1 Connected to Transformer or Busbar There are two places where an earthing/auxiliary transformer can be connected to the 36 kV network. One location is to connect it to the busbar but this will usually necessitate that it has a circuit breaker to disconnect the transformer in the case of a fault on the unit. It 158

may be that connecting to the busbars will reduce the number of earthing transformers required. However, if the bars are run split for fault level control then the same number will be required as if they were connected to the 33 kV windings of the main transformers. Connecting to the 33 kV windings of the main transformer saves on the need for a circuit breaker but does mean that for an earthing transformer fault the main transformer will be disconnected. However if the earthing transformer was on the busbar then it is unlikely that the system would be allowed to run for any length of time without an earth connected if it were to be out of service. The other reason for considering connecting the earthing/auxiliary transformer to the busbar is discussed in the following paragraph. 3.4.1.2

Required to Provide Auxiliary Power for Platform only or also for Turbine Strings Usually the earthing transformers will have secondary windings allowing them to also act as auxiliary transformers for the platform supplies. This saves the cost and weight of providing separate auxiliary transformers. On the majority of offshore substations built to date the auxiliary transformers have only been rated to supply the auxiliary supplies of the offshore substation itself and have not been designed to allow powering up the 36 kV array strings to feed auxiliary power for the WTGs when the AC supply from the shore is lost. If this powering of the WTGs is to be provided then this needs significant consideration. Usually it will not be recommended to use the normal earthing auxiliary transformers as this would require:‐ a) that they are connected to the 36 kV busbars b) that they are rated for a high kVA to allow for the reactive power of the array strings unless additional reactors are provided for this purpose c) The normal platform diesel would need to be designed very large with the associated requirement for the fuel storage If powering of the WTGs in system black conditions is required it is recommended that this is a separate specially designed system. 3.4.1.3 MVA Rating The MVA rating of the transformers will be decided by the loads to be supplied and the number of transformers to be operated to supply the auxiliaries simultaneously. It is often designed such that all earthing transformers are equipped with secondary windings but only one feeds the auxiliaries at any time. This decision is dependent upon the redundancy strategy. An alternative is to run with two transformers feeding separate LV boards with an interconnector in case of failure of one of the transformers. In either case each of the transformers will have to be rated to carry the full load of the substation auxiliary system. 3.4.1.4 Off Load or Off Circuit Tap Range Normally, off circuit taps will be sufficient and the use of a tap range of +/‐5% in 2.5% steps as is common for onshore auxiliary transformers will suffice as the 33 kV voltage is usually controlled by an automatic voltage control scheme. 3.4.1.5 Impedance The zero sequence impedance will be determined by which type of earthing scheme is used to limit the earth fault current. If resistance earthing is to be used then the zero sequence 159

impedance of the earthing transformer will normally be designed as low as possible. If however the current is to be limited by the earthing transformer then the zero sequence impedance will be chosen to limit the current to the chosen value. The positive and negative sequence impedances will normally be similar to those used for onshore auxiliary transformers in the range 5‐9%. 3.4.1.6 Number Required The number of earthing transformers will be dictated by the running arrangements as to how many separate sections of system will require earth connections. The number to be used as auxiliary transformers can be decided by the redundancy requirements for the auxiliary system.

3.4.2

Aspects of Specification which come from Generic Operation and Maintenance Considerations

The key issues which must be taken into consideration when specifying the auxiliary transformer will be determined by the level of redundancy and supply configuration. Safety criteria will determine what can be maintained when. Redundancy will enable O&M to be carried out while keeping supplies on line, however interlocking and isolation from the a.c. supply board will be required to ensure personnel cannot inadvertently work on live backfed equipment. 3.4.2.1 Oil Management If the auxiliary transformer is of oil/liquid design then they are normally hermetically sealed so there is very little to manage in terms of oil handling. These are small capacity devices, however since they are adjacent to the main tank, a high temperature flashpoint insulating fluid should be considered.

3.4.3

Repair and Replacement

A fault is likely to result in reduced auxiliary power or more importantly an unearthed transformer, therefore this affects the transformer availability. 3.4.3.1 Major Replacement Strategy The design phase should cater for the emergency replacement of an auxiliary/earthing transformer. The unit is approximately 1‐2 tonnes in weight so could possibly be lifted from a vessel using the platform crane, however it still needs to be moved around the platform. Access hatches may be necessary. If it is hermetically sealed there should not be any need for oil management, unless the faulted unit experienced a rupture and clean up is required. 3.4.3.2 Spares Strategic spares A spare earthing/auxiliary transformer should be considered. Along with a set of bushings, the number depends on the total number of that design in the whole wind park. Routine spares None

160

End of life replacement. The platform life is determined by the jacket which has a design life of 25‐40 years depending on the developer’s requirements. As such the whole platform will return to shore for overhaul. Therefore end of life replacement offshore is not anticipated only in the case of a fault.

3.4.4

Aspects of Specification which are Plant Specific

3.4.4.1 Special Technical Considerations 3.4.4.1.1 Insulation System Capacity of earthing/auxiliary transformers is relatively small. From the perspective of required power capacity and voltage level all transformer technologies any of the types of insulation systems as described in Section 3.3.4.3.3 could be applicable. The environment condition of offshore substation should be considered, however. The dry‐type transformer, without environmental shield like a closed tank, may not be suitable with its sensitivity to environmental impacts and relatively larger size compared to liquid‐immersed designs. Another issue with dry type is the mechanical strength of insulation in case of resin encapsulated transformers. Any crack in the insulation system of cast‐resin type transformers may lead to breakdown failure. Moreover, cracking of cast structure cannot be detected before the failure unless partial discharge measurement is made on the transformer during periodic maintenance. The support part or the lead of winding should be carefully inspected regularly. 3.4.4.1.2 Oil Conservator Type or Sealed Type Any type of oil preservation systems could be used for earthing/auxiliary transformers, but hermetically sealed system is preferred in offshore environment as it completely disconnects insulation systems of transformer from environmental impacts. Also, the construction is normally more compact. An important feature is smaller requirement for oil maintenance. Table 3‐11 shows comparison of characteristics for both types of oil preservation systems. Oil conservator type

Sealed type

More complicated x (higher cost) Atmospheric pressure O head

Simpler (lower cost) Pressuring temperature

O

according ∆

Possible air and O Possible much air ingress ∆ moisture ingress to oil to oil Opened to severe ∆ Closed from severe air O environment environment atmosphere by air breather Good : O ∆ X : Bad Table 3‐11. Comparison of Oil Preservation Systems

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Hermetically sealed type Simpler (lower cost) O Tank internal volume O changing with temperature (small pressure rise) No ingress of air and O moisture to oil Closed from severe O air environment

3.4.4.1.3 Avoiding Excessive LV Voltages during HV Earth Faults with Earthing/Auxiliary Transformers In case of an earth fault the earth fault current in the HV‐system of the earthing/auxiliary transformer flows via the neutral of the earthing/auxiliary transformer and is limited by the zero‐sequence impedance. As the earth fault current runs in all 3 phases/limbs, the earth fault current causes a magnetic zero‐sequence stray flux which is acting in the same direction (in all three limbs). Depending on its mechanical arrangement, the LV‐winding (e.g. 400V, 415 V) is influenced to a higher or lower degree by one of the two parts of this zero‐sequence stray flux, which induces an additional voltage (zero‐sequence voltage) in the LV‐winding. As this happens in all three limbs of the earthing/auxiliary transformer, the result is a displacement of all the three phase to ground voltages (in relation to the grounded and therefore fixed neutral of the LV‐winding). Note: The phase to phase voltages are not affected by this voltage displacement. This is illustrated in the following diagrams, figures 3‐9 and 3‐10.

Figure 3‐9. LV‐connection

Figure 3‐10. LV‐voltage‐positions The solution to this problem is to install an additional Neutral Coupler in order to form a new independent neutral for the LV‐winding of the earthing/auxiliary transformer. The Neutral Coupler will be externally mounted to the earthing/auxiliary transformer in a separate tank. The connection diagram and LV‐voltages are shown in Figure 3‐11 and Figure 3‐12.

162

Figure 3‐11. LV‐connection

Figure 3‐12. LV‐voltage‐positions 3.4.4.2 Physical and Interface Considerations The auxiliary/earthing transformers may be located within a separate enclosure or within the main transformer room. They could be mounted on cantilever brackets from the side of the main transformer tank and the HV connections made using busduct, or alternatively they may need to be mounted separately and either cable connected or busduct connected. If it is planned that personnel access to the transformer room will be permitted whilst the equipment is “live” then the statutory safety clearances, minimum height to insulation, as defined in the relative IEC Standards should be maintained. Care needs to be taken to determine the mounting height of the auxiliary/earthing transformer. The connections to the transformer LV windings would generally be made using either cables or solid insulated busducts and the method of connection needs to be identified at an early stage to allow the mechanical design of the transformer to proceed. As with the main transformer the approach of the cables must be carefully considered and may need to be varied depending upon whether the transformer is located in an open position or within a covered room. Cables approaching horizontally or vertically from above may be acceptable if the transformer is housed within a covered room, however, they may not be suitable if the transformer is in an open position. For a transformer in an open position cables approaching vertically from below would be preferred. There are factors which need to be considered in the design of the auxiliary transformer, typically:‐ 163

z

z z

Interconnecting cables between the transformer and items of switchgear would normally be installed and tested in the onshore fabricator’s yard prior to sail‐out of the platform. Disconnectable cable terminations would be preferred with the female portion of the termination and insulator included in the transformer cable box. The minimum bending radius for cables need to be considered together with working space adjacent to the transformer for the cable installers. The position of the cable box will influence the facilities which need to be built into the room/enclosure where any cable connections enter.

3.4.5

Specific Requirements for Rooms or Enclosures

If the design of the transformer includes open terminal connections the statutory safety clearances, as defined in the relative IEC Standards should be maintained The earthing auxiliary transformer may be located within the same room as the main transformer or reactor, in which case the oil containment conditions for the main plant would be adequate for the smaller earthing/auxiliary transformer. If however, the earthing/auxiliary transformer is located within a separate room then facilities will need to be provided to handle any fluid spills. The locations for cable entry points need to be identified to ensure that the support steel for the deck does not interfere with the cable access. The design should identify access positions for HV and LV power cables or solid insulation busducts, multicore control cables etc. As stated in Section 3.2.3.4 space within an offshore substation platform is always at a premium and increases in room/enclosure sizes produce a large financial penalty, therefore, the pressure is to keep the room dimensions to a minimum. The following items should be considered in the design of the room/enclosure:‐ z The platform designer must determine the minimum amount of space around the transformer to permit all aspects of planned and unplanned operation, maintenance and repair works z Sufficient space must be allowed for handling of any large sized test equipment The design must allow for access to install the transformer initially and also access for future replacement of a defective transformer. The transformer should be positioned such that removal can be effected by the use of a vessel mounted marine crane/jack‐up crane or the integral platform crane. To facilitate this procedure the roof of the transformer room may need to be removable When dimensioning access doors into the room/enclosure they should consider equipment access during initial installation and lifetime maintenance or repairs, together with personnel access. Steel doors used offshore may become excessively heavy so incorporation of removable panels in the enclosure may be an effective alternative to keep the doors to an acceptable or standard size. The room/enclosure layout should consider emergency egress from the room in the event of an incident. Consideration needs to be given to the room dimensions and positioning of the transformer to provide suitable escape routes and doors. All hinged doors and escape hatches should include panic bars on the internal face. Heat will be generated by the transformer during service and the room dimensions, ventilation systems will need to allow for the dissipation of this heat in their design.

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If the transformer is mounted in an open location then measures should be taken to discourage roosting sea birds with their attendant guano pollution. The fire rating of the enclosure may be influenced by the filling medium for the earthing/auxiliary transformer and its fire characteristics. A transformer filled with mineral oil may require a different enclosure rating to one filled with a synthetic ester which would not support burning after the ignition source is removed. A transformer filled with mineral oil may require an automatic fire suppression system whilst one filled with a synthetic ester may not require any automatic fire suppression system. This should be detailed within the fire plan for the substation. As a general rule it would be appropriate for the earthing/auxiliary transformer to be either a dry design or filled with a synthetic ester. Requirements for the switchroom lighting, small power, heating and ventilation systems are detailed elsewhere in these guidelines

3.5

HV Switchgear

As a general introduction to HV switchgear, it should be said that the high voltage switchgear utilized on offshore platforms will be the metal‐enclosed SF6 (Sulphur Hexafluoride) type which is often referred to as GIS (Gas Insulated Switchgear). SF6 is the standard insulating medium in these applications as it is a very good electrical insulator (and it can effectively extinguish arcs) which means that electrical distances can be minimized and the switchgear can be as compact as possible.

3.5.1

Aspects of Specification which come from System Studies

3.5.1.1 Voltage and Current Ratings The voltage to be used for the transmission of power from the offshore substation to the shore will have been decided largely based upon optimising the submarine cable. Typically the voltage will be 110 kV, 132 kV, 150 kV or 220 kV. Voltages in excess of this are unlikely to be utilised unless gas insulated lines become feasible. The current ratings will be identified by the load flow studies, however, a typical standard rating of 2000A is likely to suffice for most cases, but ratings of up to 4000 A are available in the market. 3.5.1.2 Fault Level Ratings The fault level will be confirmed by the short circuit studies. If the wind power plant is being connected directly into the onshore system then the fault level of the switchgear is likely to be dictated by that utilised by the utility onshore. If onshore transformers are used to connect into a higher onshore voltage system then the impedance of the onshore transformers will have the biggest impact on the fault level required for the HV switchgear on the offshore substation. Normal values are 31.5, 40, 50 and 63 kA. 3.5.1.3 LIWL Level The LIWL level for the HV switchgear is likely to be that normally used for that voltage level in accordance with IEC60071. The value will be confirmed by the insulation coordination studies. 3.5.1.4 Surge Arrester Ratings and Location Surge arresters will normally be required on the connection to the offshore transformers. The surge arresters in some cases may be connected directly on the transformer but in 165

many cases they will be located in the switchgear. If high energy rating is required additional matched arresters may be used on the cable connection side also. The surge arrester ratings and energy ratings will be confirmed by the insulation coordination studies. 3.5.1.5 Configuration The simplest switching configuration found on offshore platforms is simply a disconnector between the submarine cable circuit and the transformer. Earth switches either side of the disconnector will also normally be required. If this configuration is to be used it should be checked by the voltage fluctuation study and insulation coordination studies to ensure that the surges and voltage fluctuations on energisation are acceptable. Also, it should be considered that with this configuration, the submarine cable and the transformer will be one common protection zone. The next most common configuration is to simply add a circuit breaker between the submarine cable and the transformer. This avoids the need for intertripping to clear a transformer fault and also means that the switching surge associated with the cable is separated from the switching surge associated with energising the transformer. The main factors to consider with regard to configuration is the amount of submarine cables and transformers. A design with one submarine cable and two transformers will typically give a configuration with one GIS bay for the submarine cable, a busbar and two transformer GIS bays. A design with two submarine cables and two transformers will typically give only two GIS bays (one for each transformer) as very often the transformer and the submarine cable are rated the same, which means transformer cross connecting switchgear is located on the MV side. There are numerous different design scenarios and the requirement for any more complex switching arrangement will depend upon the reliability and availability study. It is worth noting, that there has been at least one offshore substation where a five switch switchboard has been required. 3.5.1.6 Requirement for Point on Wave Switching If the HV switchgear is used for energising transformers or switching shunt reactors then there may be a requirement for point on wave switching facilities to be specified. The requirement for the transformer energisation condition will generally be derived from the voltage fluctuation studies. The reactor requirement may be derived from the switchgear switching conditions to make the switching actions more satisfactory. 3.5.2

Aspects of Specification which come from Generic Operation and Maintenance Considerations Remote operation and asset condition is an essential part of offshore substations, so it is important to ensure these systems are reliable and robust. In most cases it is these ancillary systems which will drive the O&M, so techniques should be put in place to remotely reset or test the status of any monitoring or supervisory systems. GIS is relatively maintenance free and typically it has a low failure rate. (onshore!) Arguably offshore networks are relatively simple from a SLD perspective, however the long cables and transformers introduce large electromagnetic stresses when switched which can produce long term damage to plant resulting in the need for enhanced maintenance or early replacement. Although space is a premium a balance between equipment overstressing control (surge arresters or additional CBs) and cost needs to be considered. The ability to

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reconfigure the substation to isolate and safely maintain or replace bays while keeping the remainder energised is important (but in some cases not always possible to achieve). Some degree of standardization for offshore platforms would help to address O&M challenges associated with spares management, replacement procedures, transport, tools and training. GIS can be made very compact, however sufficient space should be provided between bays and gas barriers to allow any repair or replacement to be physically and safely carried out by typical fitters. Modular construction will help with O&M enabling fast changeout. This also keeps the skills required to effect a replacement basic, reducing the need for specialist engineers on the platform. Smaller components are easier to transport and move around the platform. 3.5.2.1 SF6 Management SF6 gas density monitoring is increasingly being used to provide indicators as to the GIS condition. Leaks can be detected, location and time to lockout, giving a longer window of opportunity to carry out preventative topping up rather than having to deal with a lockout. As it will be impractical to transport a cart each time degassing is required so a gas handling facility should be kept on the platform. Although leaks should be rare, a gas bottle should be stored on the platform, but clarification on the DNV definition of gas bottles which require firefighting and segregation is required. Working adjacent to pressurised gas barriers; there is a need to ensure there is sufficient space between bays to get safe physical access to inspect or replace components. 3.5.2.2 Condition Monitoring There are a number of areas where CM can assist in the determination of switchgear performance and avoid intrusive procedures or un‐necessary visits to the platform. Manufacturers claim long periods between GIS maintenance, however circuit breaker timing monitoring will provide an idea of any problems developing in the contacts, particularly since these could be switching large capacitances. Where possible trending of the switchgear condition should be employed rather than remote alarms as these may mal operate and incur un‐necessary emergency offshore visits. Keep the sensors simple and robust. This does however require knowledgeable resource on shore to observe the data from the platform. The key issue around CM or any form of remote monitoring is the reliability of the communication media used to relay the information to onshore. This is where the O&M effort needs to be concentrated. Need to dedicate resource to checking and repairing CM and coordinate with routine platform visits. 3.5.2.3 Operating Mechanism Moving parts such as the operating mechanism will require periodical maintenance. Designs aiming to be maintenance free will be desired with applying solid lubrication or grease‐less pins and shafts. For the parts or units for which periodical maintenance or replacement is required, design to minimize maintenance work time should be taken into account. Options like cartridge replacement would be one solution.

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3.5.3

Repair and Replacement

The routine replacement of components will be required, so it is important to have a good QA system which can easily identify and tag components so the correct part is transported to the platform, since ‘popping back to shore’ is not really an option. Any access into the GIS needs to ensure trapped charge is dissipated, therefore the design and de‐energisation sequence should take this into account regarding VT location and earth switch location. The procedure to replace each major component should be established at the design stage to ensure sufficient space is available for both the failed and replacement in the enclosure. At design stage, it is also important to consider if any temporary facilities need to be provided such as I‐beam in the ceiling, permanent crane support etc. The supplier will know what needs to be in place to keep future maintenance, repair time at a minimum. 3.5.3.1 Major Replacement Strategy If there is an internal GIS fault, then there will be toxic residues produced during the arcing. The polluted gas will need to be cleaned, so must be collected and processed. The outage and clean up necessary is very time consuming requiring specialist equipment and training. Guidelines to the work elements that should be considered, typically:‐ z Collection and storage of contaminated gas z Wash down facilities and disposal of contaminated materials z Electrical and mechanical disconnection of the faulted compartment z Removal, to a separate vessel, of faulted bay components z Booking of a suitable heavy lift vessel (floating crane, hopefully smaller than the one required for a transformer) z Suitable handling facilities at the selected dock z Availability of suitably qualified personnel to undertake the works 3.5.3.2 Spares Most of the components in a bay are common, so generally keeping a spare bay onshore will address most issues. Some suppliers, however, don't generally recommend to have any spare parts as the components (and even bays) are very standardized and can quite quickly be sourced from the supplier. It is recommended to discuss this thoroughly with the supplier and then evaluate the need for a spare bay/spare parts. A breakdown service agreement could also be considered. Transport facilities to get the bay onto the platform and lifting must be thought out in advance, including the loading procedures and transfer from platform landing gantry to the HV hall. Lifting equipment and logistics on the platform need to be considered on the fully commissioned offshore installation and not during construction. It is not easy to recommend a general list of spare equipment, but the below can be used as guidance. Strategic spares ‐ Spare GIS bay incorporating CT, VT, CB disconnector and ES. (remember that all bays on the platform may not have a similar configuration ‐ so 1:1 replacement may not always be an option). ‐ Spare set of surge arresters 168

- Mech box for each moving part Routine spares ‐ Gas density monitors, breaker contacts. Flange sealant. Control cabinet heater elements End of life replacement. The platform life is determined by the foundation which typically has a design life of 25‐40 years depending on the developer’s requirements. As such the whole platform will return to shore for overhaul. Therefore end of life replacement offshore is not anticipated only in the case of a fault. The lifetime of GIS will be in excess of 30 years. End of life replacement is not often considered for GIS substations since in‐situ replacement is not really an option. If the transformer and GIS lifetime can be aligned it may be better to refit the platform in port rather than in‐situ.

3.5.4

Aspects of Specification which are Plant Specific

3.5.4.1 Environment The GIS will typically be installed indoor in the offshore substation in a room with HVAC. This will eliminate many of the considerations to be made, if the GIS were to be installed in the very harsh offshore climate. GIS types for outdoor and indoor environment are readily available in the market and if the GIS is chosen to be installed outdoor, one should consider to ask for marine‐type painting system (for example ISO C5M ‐ "Marine"). The considerations on installing heaters, dehumidifiers etc. to prevent dew condensation in the control cable cabinet apply as they do for onshore applications. When the technical specification is made, one should follow the applicable standards (like IEC 62227‐203 [41]41 “Seismic qualification of GIS assemblies”) and be sure to specify environmental factors such as: • range of ambient temperature, • solar radiation, • pollution class, • ice coating, • wind, and • vibrations 3.5.4.2 Vibration and Transport Forces It is known that offshore substations will vibrate, even if they are in a non‐earthquake zone. The severity of these vibrations will depend heavily on one major factor ‐ the type of foundation for the substation. When comparing monopile and jacket foundations, one will find that the monopile foundation will tend to be more sensitive to send vibrations to the topside (substation). The vibrations are generated by the wave motions on the monopile which are then transferred through the structure. Also, vibrations will be generated by the wind impact on the topside. With a jacket foundation, vibration issues tend to be a hundred times less compared to that of the solution with a monopile. Another issue is the direct impact forces equipment can experience during transport (move to the offshore site). 41

IEC 62227‐203 “Seismic qualification of GIS assemblies”

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The question now is, how these vibrations/forces should be coped with when considering the GIS. The offshore shipping and oil/gas industry invented a so‐called "marine classification" that switchgears can obtain if they (among other tests) can pass vibration tests with given frequencies and accelerations. These switchgears, however, are up until now all air‐ insulated and only up to approx. 12 kV. The same rigorous regime does not exist for high voltage GIS. The HV GIS IEC standard 62271‐203 [42]42 "HV GIS above 52 kV" refers to a vibration standard which "is not applicable to metal enclosed circuit breakers". However, in 2007 an IEC standard was published (IEC 62271‐207 [43]43 “Seismic qualification of GIS assemblies”) which stipulates testing methodologies for seismic withstand capability and (maybe more importantly) a vibration response investigation. The testing covers frequencies from 0.5 to 35 Hz and the generation of an artificial earthquake wave. There is an example known when a special base frame has been designed for a floating offshore platform (oil/gas) with a HV GIS application installed ‐ with the one goal of limiting vibration and impact forces. It is currently not known if this solution will be available in the market in the future. It is typically understood that GIS has a lower centre of gravity compared to AIS (air insulated switchgears) at the same voltage level. Still the important measure which should be taken into consideration is to take care of a very rigid connection between the GIS bays, the GIL (Gas Insulated Line to transformer ‐ if that's applied) and the base frames of the bays. The source of high frequency dynamic vibrations will be the circuit breaker and all GIS should have been tested by means of thousands of make/break cycles to prove the mechanical endurance. These dynamic forces should also be taken into account when designing the foundation/deck and structure under the GIS. The local control panel of the GIS (which can be mounted on the GIS or separately) should also take vibrations into account and self‐tightening cabling terminals, bolt solutions for vibrating enviroments should be considered as standard. Transport forces can typically only be minimized by the carrying vessel and offloading units. The GIS will presumably have to be de‐gassed to atmospheric pressure, which will then provide the GIS with a higher resistance to impacts. In any case, the complete substation will have to be monitored with shock recorders and any impacts higher than accepted should be discussed thoroughly with the supplier of the GIS. The best a buyer can do is to closely discuss seismic withstand capabilities and vibration responses of the GIS in question ‐ and compare with what the substation is thought to have (can be very hard to assess). The coming years will tell us, if special measures should be taken when placing GIS on offshore platforms. 3.5.4.3 Special Technical Considerations 3.5.4.3.1 Selection of Type of Equipment For the total construction cost of offshore substation, increase of size of platform causes a big cost impact. For 145 kV which is a common voltage for the higher voltage side of the 42 43

IEC 62271‐203 “HV GIS above 52 ” IEC 62271‐207 “Seismic qualification of GIS assemblies”

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offshore substation, SF6 gas circuit breaker (GCB) is normally used, because of excellent interrupting performance and insulation performance. All three phases in a common tank type GIS is widely used for 170 kV class and below. Isolated phase type for feeder units is common for 245 kV and above. Either three phases common or isolated phase is used for the main bus. 3.5.4.3.2 Design of Voltage Transformers Instrument transformers used as a component in GIS are generally winding type voltage transformers. When the transmission line is opened by the circuit breakers of both ends, residual voltage may be trapped. In case of overhead transmission line, the trapped charges are normally discharged in a short period through air insulation devices. However, in the case of power cables, the trapped charges will remain for a long period without being discharged. Power cables have a large capacitance with its insulation sheath, and when the length of the submarine cable becomes larger, the charging capacity of the cable becomes bigger. When a voltage transformer is equipped at the line side of the circuit breaker, the cable charge will be discharged through the voltage transformer. The discharge current causes electro‐magnetic force and temperature rise in the windings. The voltage transformer must be designed so that it ensures mechanical force and thermal capacity of these discharges. One will typically have to remember to specify, if it should be possible to disconnect the voltage transformer on the primary side. If this is not possible, the voltage transformer can cause a problem if DC cable testing is to be used. 3.5.4.3.3 Location of Current Transformers Location of current transformers may impact a design of GIS. Current transformers are located on both sides of a circuit breaker or located on one side, which is determined by the policy of the protection system. To eliminate blind spots for the protection relays, current transformers are often located on both sides of the circuit breaker to cover the area of opposite side of the breaker. However, from economical reasons, current transformers are sometimes located only on one side. In case of three phases common GIS, spaces for current transformers impact the size of the GIS enclosure compared to isolated phase type. For 170 kV and below, compact type GIS in which various components are integrated in one enclosure is widely used. In such application, current transformers are often installed on one side. To eliminate space for current transformers in GIS, installing current transformers outside of GIS at export cable entrance may be an option. 3.5.4.4 Physical and Interface Considerations Whilst the aim is to provide a reliable and compact switchgear arrangement there are factors which need to be considered in the design of the equipment, typically:‐ z Will the connections to the transformer be made via GIB or cables? z The switchgear should be a modular construction to assist building in the fabricators yard onshore, and also to assist any remedial works which become necessary during its lifetime offshore. z The switchgear will need to be electrically tested after conditioning and filling. The method of test should be identified at an early stage so if the test equipment needs to be attached to the switchgear the room space is suitably sized and manual handling facilities for the test equipment are made available 171

z

Any connected power cables will need to be electrically tested so provisions should be included within the design for suitable bushings and/or cable test sockets. Consideration should be given to testing the power cables through the switchgear as the clearances required to an open terminal bushing may not be achievable. z When positioning the power cable box the physical size of the cable termination, external; to the box, should be noted and ideally the complete termination should be within the GIS switchroom to make sealing of the cable penetrations more practical. z All operating mechanisms which require maintenance or manual operation should be accessible. If they are positioned at a high level then the design should consider the necessity to fit suitable access platforms (either permanent or demountable). Also, temporary/fixed provision for crane/lifting equipment in the room should be considered. The switchgear will generally be connected to the system via power cables or busducts and due allowance needs to be made for these connections. Generally these connections would approach the switchgear vertically from below and there are factors which need to be considered in the design of the switchgear, typically:‐ z Disconnectable cable terminations would be preferred with the female portion of the termination and insulator included in the switchgear cable chamber. This allows the chamber to be conditioned and hermetically sealed in the manufacturer’s works with no need to open the chamber to the elements during cable installation. This is of particular importance for the sub‐sea export cables which will be installed offshore. z The minimum bending radius for the cables need to be considered together with working space adjacent to the switchgear bay for the cable installers. This can be particularly important when the switchgear is mounted to the deck plates and the space directly below is an open area exposed to the marine environment. The operatives in this instance would be working from below the switchgear through access areas in the deck plates. The position of the cable head on the switchgear will influence the facilities which need to be built into the room/enclosure where the cable connections enter. z The switchgear design should take due note of the fact that the cable entries will generally need to be effectively sealed, where they enter the room/enclosure, against fire and possibly the marine environment. Again the position of the cable head on the switchgear will influence the facilities which need to be built into the room/enclosure where the cable connections enter. z The physical locations of the sub‐sea export cable entries at the platform cable deck and relative positions of connected plant items will generally dictate a preferred cable route. The bays should be arranged to mitigate external cable crosses where possible. The switchgear base will normally be fixed directly to steel floor plates or rails on the platform and the switchgear support frames should be of a simple design to facilitate this type of fixing. The footprint for the support frames and their static and dynamic loads must be identified at an early stage as each of the support pads needs to sit on a section of support steel, not simply the deck plate.

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Figure 3‐13. Example of cable entry to Figure 3‐14. Example of export cable 132 kV switchgear entry with transit sealed As stated in section 3.2.3.2 the equipment will be subject to external forces due to the sea transport and lifting. The switchgear design needs to allow for these and include any necessary attachment points for fitting of external sea fastening straps. Consideration needs to be given to the recommended SF6 pressure within the switchgear during transport. For certain, simple switchgear arrangements it may be possible to transport the platform on the barge with the switchgear at working pressure, however, recommendations must be obtained from the switchgear designers before this is considered. The switchgear designers should make every effort to provide an arrangement which will be suitable for transportation at working pressure to mitigate the need to pressurize and HV test offshore.

3.5.5

Specific Requirements for Rooms or Enclosures

Space within an offshore substation platform is always at a premium and increases in room/enclosure sizes produce a large financial penalty, therefore, the pressure is to keep the room dimensions to a minimum. The following items should be considered in the design of the room/enclosure:‐ z The switchgear manufacturer must confirm the minimum amount of space around the switchboard to permit all aspects of planned and unplanned operation, maintenance and repair works z If the switchgear includes a removable circuit breaker interrupter then sufficient space must be allowed for the removal process and any necessary handling/lifting device z Sufficient space must be allowed for handling of any large sized test equipment z To assist with installation and any unplanned operations requiring dismantling of switchgear components the design of the room should consider the inclusion of a simple overhead bridge crane. This would have a minimum hook height and safe working load appropriate to handle the largest disassembled unit and a travel envelope sufficient to lay this unit safely to the floor or trolley.

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z

When GIS switchgear is used sufficient space must be allowed for a gas cart to be used during filling and/or maintenance operations. A suitable electrical supply should be included in the room to power the gas cart. z Sufficient space must be allowed for any necessary fixed or temporary access platforms required to access specific parts of the switchgear. This may result is separation of the switchgear bays to permit access to all mechanisms. Separation may also be required to comply with local operators requirements. The switchgear base will normally be fixed directly to steel floor plates or rails on the platform and the switchgear support frames should be of a simple design to facilitate this type of fixing. The support points should be designed to accept the static and dynamic loads imposed by the switchgear. With the agreement of the switchgear manufacturer it may be acceptable to weld the support frames directly to the deck plates in preference to bolting. The power cables may approach the switchgear vertically from below and if the cable head is close to the floor level the space may need to be allowed below the floor level, This may involve fitting a false floor some distance below the natural floor. Where the cables pass through this false floor the penetration may need to be effectively sealed against the marine environment and to limit the spread of fire. Floor openings for the HV power cables may need to be of sufficient size to permit access for installation of the cables and fitting of terminations where the operatives are working from below the deck. All penetrations through walls, floors and ceilings will be suitably sealed during installation in the onshore fabricator’s yard, however, it must be remembered that the submarine cable(s) will be installed and the penetration sealed offshore. Temporary seals would need to be installed into the penetrations prior to sail out and these would be replaced by the final seals after cable installation. Suitable earth bosses should be welded to the steel deck plates at appropriate locations, particularly local to the Export cable boxes. These earth points are required to fix bonding leads from the cable terminations which will be installed offshore. When dimensioning access doors into the room/enclosure they should consider equipment access during initial installation and lifetime maintenance or repairs, together with personnel access. Steel doors used offshore may become excessively heavy so incorporation of removable panels in the enclosure may be an effective alternative to keep the doors to an acceptable or standard size. The switchroom should contain a fire detection/alarm system and the substation fire plan will detail if the switchroom/enclosure is to be designed as a passive fire protection or contain an automatic fire suppression system. Where a fire rating is assigned to the switchroom wall then any access doors within the wall must be suitably fire rated to match that of the wall. The room/enclosure layout should consider emergency egress from the room in the event of an incident. Consideration needs to be given to the room dimensions and positioning of the switchgear to provide suitable escape routes and doors. For other than small rooms this normally means there should be at least two points of access/egress. In certain circumstances an escape hatch can be provided to replace a second full size door. All hinged doors and escape hatches should include panic bars on the internal face. During an internal fault, or failure of a gas zone within an SF6 switchboard, high pressure gasses may be vented into the room/enclosure. The volume and pressure of these gasses when vented into the room will cause an overpressure within the room. This overpressure 174

needs to be evaluated and if necessary suitable pressure relief devices built into the room to prevent mechanical damage to walls, doors etc and injury to people who may be in the room at the time of the discharge. It is common on offshore structures to identify areas which may be subject to an unplanned release of gasses and to include in the design a gas detection system for identified areas. Some use a SF6 gas detection system separate from the switchgear. This independent detection system would typically initiate an alarm to a SCADA system and a warning beacon with sounder external to the room. Given the SF6 alarm systems integral to the switchgear the beacon & sounder could be initiated from the switchgear negating the need for an independent scheme. This solution should be investigated where practical. The electrical equipment which will be housed in these rooms has been designed for indoor use in Normal Service Conditions where:‐ a) The ambient air temperature does not exceed 40oC and its average value, measured over a period of 24 hours, does not exceed 35oC The minimum ambient air temperature is –5oC for class “minus 5 indoor” as defined in clause 2 of IEC Standard 60694:1996 b) The conditions of humidity are as stated in clause 2 of IEC Standard 60694:1996 The heating system to these areas should maintain a minimum ambient air temperature of +5oC The ventilation system should incorporate maintainable salt filters Requirements for the switchroom lighting, small power, heating and ventilation systems are detailed elsewhere in these guidelines

3.6

Export and Inter Array Cables

3.6.1

Aspects of Specification which come from System Studies

The cable ratings should be dimensioned for the voltage, the power requirement at the generating end, plus the load factor. After this information the conductor diameter and material are best selected by the cable manufacturer. Conductor material can be either copper or aluminium. Typical maximum lengths of export cables versus voltage drop and power losses are shown in Appendix 3; Power transmission with long AC submarine cables. The inter array cables are typically for 36 kV system voltages, although with increasing generating capability of the turbines 69 kV cables may be used in the future. In most cases it is more economical to have two or three different conductor diameters for a larger wind power plant. The system voltage for the export cables will come from the system studies and may be any IEC system voltage. Up to 245 kV systems these cables are typically three‐phase design. Communication is needed due to the offshore application and both array and export three‐ phase cables have integrated fibre optic cables (FOC). Although integrated FOC have lesser risk of being damaged during installation the number of fibres needed should include enough redundancy back‐up.

3.6.2

Aspects of Specification which come from Generic Operation and Maintenance Considerations

Both cable types are to be installed on platforms with hang‐offs for the armouring and J‐ tubes often with bend restrictors. Typical terminations at the platforms are of the plug‐in 175

type for the GIS substations. Maximum temperatures at the sea‐bed, in the water and ambient air are needed for proper dimensioning. Maximum temperature on the sunny side of the J‐tube may not be that significant as the cables themselves are very good heat conductors. But installation of J‐tubes on the south side is preferably avoided. The design of the j‐tubes should meet the requirements of the cables inside them, mainly regarding minimum internal diameter and bend radius of the bottom part. In this sense, the minimum internal diameter of the j‐tube should be, at least, 2.5 times the overall diameter of the submarine cable to avoid it getting stuck. On the other hand the j‐tube bow radius should be substantially larger than the minimum bending radius of the cable, taking into account that this value depends on the mechanical tension of the cable, and the cable will be pulled into the j‐tube for installation. The j‐tubes are normally made of carbon steel and protected against corrosion by means of a suitable coating, although some models are manufactured with polymer material. Once the cable has been pulled up to the platform, the bellmouth of the j‐tube is commonly sealed in order to avoid water motion inside the tube, which would favour the corrosive process. In this way, the bottom part of the j‐tube is filled with sea water while the upper part remains filled with air. From a thermal point of view, the j‐tube may be one of the most critical points for the cable design given that the heat flow between the cable and the environment is hindered by the tube, the upper part of the tube being the most unfavourable (air filled). The air circulation would be improved if two openings were perforated in the j‐tube wall (chimney effect) but, on the other hand, the air current would increase the oxygen content inside the tube and thus increase the corrosion risk. Therefore, it is important to assess and consider the thermal reduction factor due to the j‐tube for the design of the submarine cable. Besides the j‐tubes, the other indispensable element to terminate a submarine cable entering an offshore platform is the hang‐off. Any power cable needs to be solidly anchored to a fixed structure in order to follow the designed route and to avoid any movement under short‐circuit events. For a submarine cable accessing an offshore platform the concept is the same, although the termination is separated in two parts: a mechanical termination and an electrical termination. The mechanical termination (known as hang‐off) is located immediately above the j‐tube, fixed to the deck of the platform, and it could be described a sophisticated connection flange between the cable armour and the cable deck structure. The metallic armour is the structural element of a submarine cable and therefore is the element that provides anchoring of the power cable to the platform structure in order to transfer all mechanical loads directly from the armour to the structure without endangering any of the internal elements of the cable (conductor, insulation, and screen). Given that the submarine power cables and umbilicals have been used for decades by the offshore hydrocarbons industry, the hang‐offs are well known accessories improved along many years and with multiple designs adapted to specific cable requirements of every project. Anyway, the main structure of a cable hang‐off remains unchanged and could be described essentially as two concentric metallic rings bolted to the structure by means of a flange, acting as a clamp for the cable armour; the internal ring has an internal hole and a conical external surface, while the external ring has an internal surface with the complementary shape of the internal ring to fit with it. The wires of the cable armour are bent (folded back) over the internal ring so they are trapped and fixed between the two rings. From this basic design there have been several improvements in order to reduce the stress on the wires, which sometimes caused their premature wear and rupture. In this 176

sense the bending of the wires has been eliminated in some designs, making the internal surfaces grooved in order to avoid movement of the wires once fixed. In case of using several armour layers (like in dynamic cables), the hang‐off should have a pair of rings for holding each one. In the second image shown below, it can be observed that the hang‐off structure has two parts: permanent and temporary. The temporary hang‐off is used as a clamp to fasten the cable to the structure prior to clamping the armour wires (permanent clamping). This temporary hang‐off works commonly by means of friction on the submarine cable oversheath, while the permanent hang‐off works by fixing the armour wires. The aforementioned is the typical arrangement of a hang‐off device for power cables commonly used in offshore wind power plants, although in the hydrocarbon sector there are other different mechanical terminations, although normally for smaller cables (for example to fix the armour wires inside a chamber by means of epoxy resin injection). For three‐core cables, the hang‐off devices include a chamber for trifurcating the cores that will run for connection to the bushings of the switchgear. In any case the hang‐off should seal the top of the j‐tube to avoid saline air circulation that would accelerate the corrosive process (due to oxygen supply). The hang‐off itself should be protected against corrosion by means of suitable coating. The hang‐off clamp should be adapted to the cable to be anchored, in order that the armour wires and the anchoring device form a single block and therefore all mechanical loading (static and dynamic) is transferred from the armour to the platform without the conductors having to withstand any stress that could damage them immediately or increase the possibility of a breakdown. Single or double armouring of the cables is depending on water depth and cable weight. The main differences between export and array cables are that the export cables have a metallic sheath of e.g. lead for water tightness, while the array cables are of the wet design. Many times the cables are pulled in through the J‐tubes ahead of the actual installation of the terminations. All cables have a minimum bending radius which must never be violated. During the cable installation in the j‐tube it is necessary to pull enough over‐length of cables over the platform before anchoring in order that the cores, once trifurcated, can reach the bushings of the switchgear without any additional joint, and that this is coordinated with the substation and platform layout. ´It is important to design a suitable arrangement of the equipment on the platform, trying to place the switchgear as close as possible to the vertical over the hang‐off blocks (both for the medium voltage switchgear and for the high voltage GIS). In this way, the cables can run easily from the hang‐off at the cable deck to the upper deck on which the switchgear is located. The connection of the cores to the switchgear can be performed with conventional connectors, as applicable for medium or high voltage cables. In the same way, the connection between the switchgear and the power transformers can be done by means of conventional insulated cables and connectors, always looking for the most suitable routing.

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Figure 3‐15. Two types of cable hang‐offs, being the first a very simple design and the second a more elaborated one, similar to that used in offshore wind power plants. It may be beneficial to deliver the array cables coiled (or on a turntable), hooked up with one another with e. g. Chinese fingers in order to reduce both number of laying trips and waste/return handling of drums. The export cable is delivered either coiled or on a turntable as the maximum length the selected laying vessel can load, in order to reduce the number of joints. Special consideration may be needed for the landfall which depends on the actual conditions like shallow water, cliffs, distance to switchgear, etcetera. The termination may either be a plug‐in type for GIS, or outdoor/indoor type with a polymeric/porcelain housing for connection to a switchyard or over‐head lines. In other cases a land cable via a transition 178

joint will be connected just at the landfall. Today there are also dynamic cables for floating platforms available.

Figure 3‐16. Hang‐off block anchoring a high voltage three‐core cable (left) and entry for connection to a GIS substation 3.6.2.1 Maintenance Typically cables are maintenance free. However, it is possible to measure temperatures with special fibre optic cables that indicate the conductor temperature of the cable with an accuracy of around 5 degrees K. These DTS-systems may give an indication of overloading risks or failure/problems of the cable. They must be installed together with the original installation. For cables with separate FOC, these systems may have a somewhat worse accuracy. 3.6.2.2 Spares Normally spares ordered together with the delivery include one or two terminations, some submarine repair joints, and spare cables of length for at least two repairs. These repair joints should also include splice boxes for the FOC, if used. The spare cable length should account for the double water depth plus a long enough replacement length to be laid. Spare cables for the array cables should be of the largest core diameter used as there are joints available that work for somewhat different core diameters so this works for any array cable repair. The length of spare cables and number of repair joints may also depend on how busy the cable route is with ships. It is important that the spare cables are easily accessible for loading on to the repair ship. Depending on the design they can either be stored coiled or on a turntable for larger export 179

cables. A storage house with the possibility of lifting off the roof for crane access at a quay makes this possible. 3.6.2.3 Replacement Strategy The vast majority of submarine cable failures come from outside influences like anchoring or fish trawling. First one needs a prelocation method to find the place of failure within several hundred metres that can be done by sending a TDR‐signal (Time Delay Reflection) into the cable from one end with an ECO‐meter or with measurement of a fault location bridge. These equipments are portable and do not need any special installation. The final location of the fault is through use of equipment measuring the magnetic flux close to the cable in the vicinity of the prelocated fault when current pulses are injected at the end of the cable. In some cases a high frequency current is injected at the end of the cable. In nearly all cases you repair the existing cable by cutting away the faulty section and replace it with a length of spare cable sufficient to allow jointing at the surface. In very few cases the faulty cable may be replaced with a new spare cable. This will only be economical when you have very short and small array cables. Failure of the export cable should be attended to at the earliest possible time as this will stop the production, but the time to repair will strongly depend on availability of a repair vessel and spare cable. Failure of an array cable will lead to reduced power output. How much depends on where the failure is and how the array cable layouts are configured.

3.6.3

Aspects of Specification which are Plant Specific

The installation in the sea‐bed is strongly depending on the softness of actual sea‐bed materials if they can be buried directly or not. The thermal resistivity of the sea‐bed is important as ideally you try to bury the cables roughly half a metre to one metre down in the sea‐bed. The installation of the subsea cables in the j‐tubes until reaching their corresponding bushings in the switchgear requires a preparatory work in order that the operation can be completed successfully. First of all it is necessary to review the calculations to establish the cable load limits during the pulling operation. Then a thorough analysis should be carried out to decide the best places for locating the pull‐in equipment on the deck: this includes the winch, the pulleys, the load‐monitoring device and any other associated equipment. The mechanical ratings of this equipment should be suitable for the characteristics of the pull‐in operation to be developed and the position of the different elements should be such as to avoid exceeding any of the mechanical limits of the cable. It will be necessary to pull a cable overlength on the deck enough to reach the switchgear, commonly located in an upper deck regarding the hang‐off block. Depending on the geometrical shape of the cable routing from the hang‐off to the upper deck, probably it will be necessary to carry out two pulling operations: first to recover the required cable length to the lower deck for hang‐off anchoring and second to pull the overlength to the upper deck through the cable glands in the floor for entering the switchgear room. Besides, performing two pulling operations makes it easier to control the cable bending as well as to reduce the mechanical tension. In this way, the cable terminations and connectors can be executed inside the switchgear room, and therefore under controlled conditions without exposure to the marine environment. During the initial design phase, both the hang‐off blocks for export and array cables should be located as close as possible under their corresponding switchgear in order to minimize the path inside the substation through trays or any other clamping device. If any fire division is penetrated by the cables in their run towards the switchgear, special 180

measures should be adopted to keep the integrity of this barrier by means of suitable glands/transits that will maintain the isolation from the external environment too. 3.6.3.1 Physical and Interface Considerations Interfaces for the sub‐sea cable installation may vary dependent upon the design of the substation and this could comprise a) A conventional foundation (jacket or monopile) with topside where the cable deck forms part of the topside. In this design the final cables to the substation must be pulled in after the substation platform is installed into its final position.

b)

A conventional foundation (jacket or monopile) with topside where the cable deck forms part of the jacket foundation. In this design the final cables to the substation may be pulled in and laid on the cable deck before the substation platform is installed into its final position.

c)

A jack‐up type construction where the cables must be installed after the substation is elevated into its final position. In this design the final cables to the substation are pulled in after the substation platform is installed into its final position.

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d) A jack‐up type construction where a separate cable tower is pre‐installed before the substation is elevated into its final position. In this design the cables may be pulled into the separate tower before the main platform is installed and link cables to the substation are pulled in and laid between the tower and substation after the substation platform is installed into its final position.

Arrangement a) To meet constraints imposed by the heavy lift of a jacket foundation it may be specified that the top of the J tubes only extend to the top level of the jacket. Again to meet the constraints imposed by the heavy lift of the topside it may be specified that there should effectively be no projections below the lowest deck construction. In this case after positioning of the topside on the jacket there may need to be filler sections installed for each J tube to bridge the gap between jacket and topside and complete the J tube. Access facilities need to be considered to permit these J tube extension sections to be installed offshore.

Figure 3‐17. Example of J tube filler sections being Figure 3‐18. Example of Completed J Tubes installed between jacket & topside Arrangement b) With this arrangement the J tubes are fully installed to the cable deck. The three core sub‐ sea cables can be pulled into place and laid out on the cable deck prior to arrival of the topside. Temporary measures need to be designed for use at this stage to preserve the cable minimum bending radius of the three core, armoured cables until their final installation after the topside arrives. Sealing of the cable ends and mechanical protection may be required during the period between cable pulling and topside installation. Arrangement c) The sub‐sea cables would be installed after the self elevating platform is installed in its final location with the cable hang‐off being made at the J tube top.

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If the self elevating platform is a four leg design then the J tubes may be able to be pre‐ installed into one, or more, of the legs. Arrangement d) The separate cable tower(s) would allow the sub‐sea cables to be installed prior to the arrival of the self elevating platform. The aim would be to pull and terminate the sub‐sea cables into a suitable cable box which would provide a through joint for the link cables to the later installed substation platform. Whilst self elevating platforms have been used in other areas of offshore activities they are relatively new to the offshore substations and only limited experience is available to date. The sub‐sea cable contains a fibre optic cable for use in the overall control and communications scheme. It may be that a relatively short length of power cable is required, typically 15‐20m, to route between the point of hang‐off on the cable deck and the point of termination into the switchgear, however, the route length between the point of hang‐off and the termination panel for the fibre optic may be typically 30‐40m. In this case a pre‐ installed interface panel may be required to be mounted close to the point of hang‐off. The cable terminations should be a suitable for the marine environment

3.6.4

Specific Requirements for Rooms or Enclosures

Arrangement a) For most of the offshore substations installed to date the cable management area in the final substation arrangement is between the cable deck and equipment deck and would be open to the elements. For the purpose of this discussion this “space” is classed as the enclosure, however, the cable deck could be completely enclosed if necessary and become a cable room. Sufficient height needs to exist between the two decks to permit the sub‐sea cable to be pulled into the J tube and make due allowance for the pulling equipment, pulley blocks, formers etc, operatives and the minimum bending radius of the armoured cable. Sufficient working space needs to be allowed around the J tubes and in the general work area for the installation equipment and operatives. Allowance needs to be made for the winch location(s) on the topside and suitable anchor points may need to be welded into the deck to securely mount the winch. Allowance needs to be made to install padeyes on the topside for the fitting of pulling equipment. These padeyes can be permanent fixtures on the steel structure or demountable as necessary. The routes for the winch cables need to be included in the 3D model to ensure there will be no clashes with other installed items of plant, pipework or fittings during the cable installation process Arrangement b) As stated above the aim of this arrangement is to install the sub‐sea cables into the J tubes and lay them onto the cable deck prior to the arrival of the topside. The cable deck design needs to include suitable padeyes and anchor points for the winching and cable pull in operations. Temporary measures need to be designed for use at this stage to preserve the cable minimum bending radius of the sub‐sea cables until final installation after the topside arrives. At this stage this is the minimum bending radius for the complete three core armoured cable, which could be in the region of 3.5 ‐ 4m for an export cable.

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This temporary steelwork must be sufficiently robust to withstand the environment, cable deadweight and wind loads during the intervening period between pulling and arrival of the topside. The temporary steelwork needs to be removable after installation of the topside to permit final stripping, laying‐up and termination into the switchgear. Sealing of the cable ends and mechanical protection may be required during the period between cable pulling and topside installation. As these pre‐installed cables will project above the level of the cable deck their presence will have an impact upon the interface between the jacket and topside. Consideration needs to be given to mitigate the possibility of cable damage during the final lift operations for the topside. After the topside is installed the cables need to be stripped and the support system completed. The topside design would need to consider the installation, or replacement, of any of the sub‐sea cables after installation of the topside on its foundation. This would require suitable padeyes, winch mountings and a detailed pull‐in procedure similar to that listed for the topside inclusive of a cable deck. Arrangements c) and d) Similar considerations need to be included into the design of the platform as discussed for arrangements a) and b). The cable support system needs to make allowance for the planned laying arrangement for the cable power cores, the minimum bending radius, cable deadweight, short circuit forces etc. The point of entry into the equipment deck needs to allow sufficient working space for the operatives to feed cables through the penetrations. As stated in earlier sections the penetrations would need to be sealed, after cable installation, to resist the marine environment and/or fire. Suitable earth bonding points need to exist local to each cable hang‐off. The penetrations below each of the switchgear bays should be labelled to assist identification from below on the cable deck.

3.7

Site Tests and Commissioning

3.7.1

Overall Strategy

The cost of carrying out any work offshore is approximately ten times the cost of the same activity performed onshore. This dictates the overall strategy for performing installation and commissioning activities. Everything that can be done onshore before the substation platform leaves the construction yard should be done so that only those activities which can only be performed offshore are left to be completed when the platform is installed on its foundation. The onshore testing should be as comprehensive as possible to find out any problems before the substation is transported. Furthermore, all equipment should be as completely installed as possible onshore. Dismantling of any parts of the equipment for transport on the barge and the re‐assembling offshore should be avoided. The equipment needs to be designed such that it can withstand the forces which it will experience when being transported on the barge. This is particularly relevant to oil filling of transformers and gassing up of GIS switchgear equipment. There are some activities which can only be completed when the substation is installed on its foundation offshore. Such activities include termination of the submarine cables and their associated fibre optics. The testing of these parts has to be performed offshore. With 184

regard to equipment which has been thoroughly tested onshore then the testing to be carried out on this equipment should be kept to the absolute minimum to ensure that the equipment has not been damaged in transit and that it is functioning correctly.

3.7.2

Pre-energisation Onshore Commissioning

Commissioning of an offshore substation can be broken into two aspects which follow the principles of an onshore substation. These can be referred to as Stage 1 and Stage 2 commissioning, i.e. ‘pre’ and ‘post’ HV energisation. The significant issue which faces an offshore substation is that the Stage 1 pre‐ commissioning is performed onshore, typically within a fabricators yard or dockside area. The substation is then transported before Stage 1 activities can be fully completed and the project progress onto Stage 2 Commissioning. As with onshore substation commissioning, the pre‐energisation typically requires proving of the individual equipment functionality and circuitry connection prior to inter‐system checks. It is not the aim of this document to provide a detailed explanation of a commissioning process but to illustrate key differences between the commissioning of an onshore facility to that of an offshore substation. Pre‐commissioning onshore will be preceded by the equipment Factory Acceptance Tests (FAT), including Routine Tests. These will have been completed in accordance with the standards to which the equipment is manufactured. After the installation of the individual equipment and manufacturer checks on the respective equipment, the pre‐commissioning can be broken down into the general areas of: ‐ transformers ‐ switchgear ‐ building services (including lighting, heating and ventilation, CCTV, fire and safety systems) ‐ LV systems ‐ DC systems ‐ scada and control systems ‐ telecommunication (including VHF, UHF radios) As the tests are performed at the dockside the space for test equipment can be limited and must also be coordinated with other dock side activities which are being undertaken to complete the substation. The ideal scenario is to have a completed fabrication and installation prior to commissioning. However the reality is often that due to programme commitments, in particular the lift and vessel to the offshore location, that final installation of equipment will be ongoing during commissioning of other equipment. Transformer On the delivery and assembly of the transformer the supplier will perform detailed checks on the assembly. These will include primary insulation tests of the magnetic circuit and windings (including core to frame, core to tank, and tank to frame), ratio and vector group confirmation, auxiliary checks, and the operation checks of tapchanger, cooling fans etc. An oil sample test can also be performed. Fingerprint tests can also be carried out on the dockside. This includes a Frequency Response Analysis (FRA) where a plot of the transformer impedance against frequency (10 Hz to 10 MHz typically) for each winding is recorded. This provides a base set of readings

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which can be repeated at chosen later occasions where changes in the FRA can indicate winding damage or movement. Switchgear The pre‐commissioning of the switchgear will follow typical onshore practice with general activities of (i) Inspection Schedule (checks on multi‐core cabling, insulation resistance tests, panel checks), (ii) CT Mag curves, flick and loop burden checks, (iii) functional tests, (iv) transducers, (v) interlocking, (vi) trip and control checks, (vii) alarm, indication, trip audit. On SF6 Switchgear (typically at 132 kV) the performance of timing tests will require full working pressure to be established on the switchgear. Consideration is required on the requirements of the testing of the Export cable (i.e. components require to be removed during test) and also the suitability of the equipment to be transportation at working pressure requires to be considered otherwise the switchgear can be gassed and degassed an unnecessary number of occasions resulting in a longer commissioning programme. Building Services Building Services can be completed as part of the pre‐commissioning on the dockside. The equipment will typically be supplied from the LV switchboard which can be connected to site supplies rather than supplied from the LV winding of the power transformer (as the connection to an HV system is very unlikely to be available on the dockside). The activities generally include the commissioning of: • internal and external platform lighting, • heating and ventilation systems, • power sockets, • security systems, • fire and SF6 detection, • CCTV systems, • Navigational Aids, • Oil and bund pump systems, DC System Battery systems can be commissioned dockside. These will be supported by the auxiliary generator offshore until power is established. It is important that the running time of the diesel generator and period until energisation is known. If the diesel generator is only operated for short durations (to minimise the hours between re‐fueling) this will result in the batteries discharging and charging to maintain supplies to equipment until a permanent ac supply is available. In this situation, if VRLA batteries are installed they are typically not designed for cycling load. The extent of ampere hours removed and the available time to replenish the deficit will impact on the battery life. Similarly if the platform is left for a period without power the batteries will be discharged. In this condition they will sulphate which will greatly reduce their charge current acceptance, leading to a reduced capacity/autonomy. Alternatively, if the philosophy is to leave the batteries initially disconnected offshore a refreshing charger would be required typically every six months. SCADA The SCADA system can be tested to available points in the substation however a true end‐ to‐end test cannot be performed until the main export power cable (containing the fibre) is installed to the offshore location. Typically on an offshore wind power plant there are two

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SCADA systems, one system will control the substation equipment and the other control the Wind Turbines (refer to Section 5.4.1) Typically the substation SCADA system will feature an onshore based server with offshore client and RTUs / IEDs. The testing of alarms, indications, and controls can be tested to the offshore RTU during pre‐commissioning. Similarly the testing of the onshore RTUs to the main control server can be completed during the onshore pre‐commissioning. It is the connection between both systems which cannot be commissioned prior to load‐out. The option does however exist to connect the offshore system to the onshore system via temporary connection (either by physical short fibre length and the onshore equipment brought to the dockside or via establishment of a VPN connection). This can be used to pre‐ commission, in so far as is practical, a close resemblance of the final system however final testing of the complete system will still be required. Telecommunication The telecommunication system provides the back‐bone for the SCADA system and voice systems where the telecommunication to offshore will be via fibre optic and LAN topology (refer to Section 5.7.). The pre‐commissioning of the telecoms system at the dockside can typically include: • internal and external multicore and coaxial cable installation tests, • equipment tests between devices installed equipment on the platform, • power supplies to panel to prove equipment operation, • installed fibre optic cable from panels to junction boxes where the sub‐sea fibre will terminate (For Insertion Loss of the cable cores and the Optical Time Domain Reflectometer (OTDR)). • CCTV cameras (viewing only typical as recording medium will be located onshore) • LAN cables to the Telephone Kiosk and the Welfare facility, • UHF and VHF Radio transceivers, antenna, and portable radios. As noted with the SCADA system, the testing of the offshore equipment on a temporary set‐ up could be established to further prove connectivity to the onshore equipment and offshore equipment. This is a risk based analysis as the test will require to be repeated between the two systems with the final installation however a temporary connection arrangement may highlight problems which can be corrected before the equipment is located in the harder to access offshore location. 3.7.2.1 On Site High Voltage Tests On the offshore substation platform the HV and 36 kV switchgear will be HV pressure tested. This will also include any bus‐duct installed to the power transformer. The interconnecting cables between the transformer and items of switchgear would also normally be installed and tested in the onshore fabricator’s yard prior to sail‐out of the platform. These include from the HV switchgear to transformer HV windings, and from the transformer LV winding to the 36 kV switchboard (s).

3.7.3

Pre-energisation Offshore Commissioning

The initial task offshore after the substation installation is a visual inspection to assess any damage, or obvious changes, to equipment conditions and contents (i.e. SF6 or oil levels). During the transportation of the substation platform the installed equipment may experience acceleration forces. The extent of the acceleration forces should be provided

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early in the project to ensure that the equipment is specified to withstand this force, either through permanent or temporary measures. In addition to the acceleration forces, the positioning of the topside onto the substructure can present an opportunity for shock forces to arise as contact is made between the two structures. To measure the transportation and acceleration forces an impact recorder can be installed on equipment prior to transportation. A data logging system for sampling the acceleration in the X‐Y‐Z planes, the angle / tilt, and the vibration can be used. At pre‐ commissioning the result of a logging sequence will provide an initial assessment if the transportation remained within the expected parameters during load out. Prior to transportation offshore, the extent of the Test and Commissioning engineers which require to be fully offshore trained should have been assessed. This includes consideration of all parties who may realistically be required offshore. Once installed a Supplier of specific equipment who is not offshore trained cannot simply be contacted to attend the installation. Once the substation is located offshore the location can very often represent different ownership boundaries and responsibilities to that on the dockside. For example the fabrication of the topside and installation of equipment can be contracted to a third party however once installed on the offshore structure (or lifted from the dockside) the ownership can become the responsibility of a different party (often the owner). Therefore the works to under take final commissioning tests when the platform is installed offshore must be clarified in advance. Activities undertaken on the dockside under one permit system can be replaced over night by a new permit and operating system. After a visual inspection is performed, an assessment of the safety systems should be undertaken. This is required to ensure that any further persons who will be present on the platform are protected from any SF6 leakage or fire situation. The operation of the auxiliary generator during transportation should be considered. Alternatively, the duration between leaving the dockside and running of the auxiliary generator should be assessed for impact on equipment preservation requirements in uncontrolled temperature environments. The checks will also include inspection of any alarms on equipment or the SCADA system and confirmation of the HVAC system operation. The pre‐commissioning works offshore will then focus upon: • securing any gratings which were lifted for transportation (for example gratings lifted at padeyes), • the removal of any transportation bracing or temporary supports, • Removed door locking plates (or similar to ensure doors remain closed during transportation) to provide access to rooms. • Testing of platform and internal lighting, • Erection of lightning masts and antenna (if fitted and lowered during sea transportation), • Fitting of any ventilation units removed during sea transportation. • Operation check of the platform cranes. (See also Section 4.5.10.1) The electrical pre‐commissioning will then re‐check a number of items which were tested on the dockside. This is required to ensure that no changes have occurred during the load‐out. Items include: • Commissioning the UHF and VHF radios, 188

•

Insulation resistance checks for primary equipment and main supplies to confirm there was no change from transportation. This will include tightness checks on terminal wiring, • Functional and operational checks on the switchgear locally and from the SCADA system, • Tap changer operation and transformer auxiliaries (i.e. cooling fans). In general a pressure test of the 36 kV and export cables, or the switchboards will only be required offshore if there is evidence of damage to the equipment or changes in SF6 levels. The project programme may facilitate the connection of the export and array power cables on delivery of the topside. The power cables may have been installed and placed on the cable installation deck prior to the topside delivery. Alternatively this activity may follow the installation of the substation. Consideration is therefore required in relation to the establishment of the telecommunication system to shore. As the communication fibres are typically located within the power cable, the connection of the power cable is a pre‐requisite. However if a micro‐wave, VSAT, or similar, is installed as part of the telecommunication system, i.e. to provide back‐up communications during a fault on the export cable, this would provide the opportunity to commissioning this aspect of the communication system at an early stage. Once fibre optic connection to shore is established it will be possible to commission: ‐ The fibre optic communication, ‐ The operation and operation of the CCTV, ‐ The operation of the LAN network and telephones (IP telephones are typical), ‐ The communication between the offshore platform and the onshore control room ‐ Confirm control, alarms and indications via the control system to the onshore control room ‐ Confirm communication for the protection system (i.e. cable differential) ‐ Confirm inter‐tripping between offshore and onshore switchgear / protection, 3.7.3.1 High Voltage Tests for Power Cables The on‐site testing of power cables is generally performed to detect any defects that might occur during the cable installation. All cables will undergo a Factory Acceptance Test (FAT) before leaving the manufacturing plant to the required test standards. This can include dimension checks, partial discharge, voltage, capacitance of cable, and oversheath test. However defects in the cable may occur during storage, transportation or installation. In addition joints and terminations feature in a completed installation and can give rise to a weak point in the overall cable system. After installation, there are a number of options for the testing of the cable circuit which present various limitations and difficulties, including individual interpretation of the results which can be determined from the cable testing. Testing can include: 1. DC test on the oversheath, 2. AC insulation withstand test: Power Frequency Testing, Very Low Frequency (VLF) Testing, 3. Partial Discharge The common consideration is the use of the power frequency test of the subsea and array cables. This testing of the cables after installation typically follows the IEC 189

recommendations, including IEC60840 for power cables with rated voltages above 30 kV up to 150 kV. The testing of the cable at 50 Hz provides the advantageous scenario where the cable insulation, including accessories, is stressed comparable to the service condition. However for an offshore wind power plant the inherent nature of the cable capacitance results in a charging current which can be difficult to achieve the necessary values via a test set. For the ac voltage test, applied between the conductor and the sheath, the cable can be tested at Um for 1 hour. However due to the requirements (145 kV for an export cable) typically the testing of the cable is achieved through 24 hours of service voltage (U0 ) can be applied for 24 hours. This test utilising energisation from the electricity grid must be discussed with the transmission system owner at an early stage in the design process. This test is therefore achieved when the offshore platform is first energized. The testing at 24 hours is also relevant where both ends of the cable are offshore as an HV‐ test set with higher voltages is difficult to achieve with handling and delivery of test equipment to distant platform and/or wind‐turbine towers a costly activity. The division of the contract placed by a wind power plant developer may influence the cable testing procedure where the cable and switchgear spans different contracts. Coordination of the cable testing and requirements / capability of the switchgear under the specified cable tests must be performed. The HV‐test utilised may also need special equipment configuration where, for example, it can be necessary that the switchgear voltage transformers and surge arresters must be disconnected during the test. This would require de‐gassing of SF6 compartments to allow components to be removed with vacuum and re‐ gassing required prior to test. However if testing is clearly known prior to load‐out the surge arrestor, VT etc could be removed dockside to allow the cable test to be performed prior to the equipment installation.

3.7.4

Post Energisation Commissioning

3.7.4.1 Energisation of Sub-Circuits An energisation procedure should adopt sequential and time spaced switching of individual circuits that energise transformers, reactors and capacitor banks so as to minimise voltage fluctuations on the system. This is particularly relevant in the switching of wind turbine array circuits where multiple turbine transformers may be energised together. Therefore, switchgear interlocking should be capable of facilitating individual switching of circuits. This will be covered in a Commissioning Switching Programme. Typical stages through the switching and energisation for a single cable and two transformer system will be: 1. Confirm all wind power plant equipment is ready for energisation Configure grid connection point for commissioning activities (more sensitive protection settings, adopt grid commissioning operational state to limit disturbance in case of faults)* * This is executed by/together with the transmission/distribution system owner. 2. First energisation of the connection assets located onshore. 3. Energisation of the subsea cable. The charging current of the cable can be used to prove the stability of the onshore upstream differential protection. 4. Perform Export cable test (refer to Section 3.7.3.1). 5. Energisation of the HV switchgear 6. Energisation of first transformer including tap changer and soak test 190

7. Energisation of second transformer including tap changer and soak test 8. Energisation of 36 kV switchgear busbars and auxiliary transformer from HV system. 9. Energisation of WTG arrays and test. 10. Carry out final commissioning control schemes on the offshore platform. 11. Reconfigure power system to meet operational requirements At each stage of energisation the equipment recently energised should be inspected for signs of distress and whilst under load, various checks can be carried out. This includes current/voltage transducers, remote indications of current differential scheme, phase rotation checks, protection relay indications (V, A, f, MW, MVar) and power quality monitoring systems. All checks performed should be recorded in a commissioning record. During energisation the system must feature proven protection. When dealing with a long length of ac cable the commissioning protection for the first energisation must be sensitive to a fault in the subsea cable but be stable for the steady state charging current of the subsea cable. As noted in Section 3.4 the connection configuration of the earthing / auxiliary transformer must be considered. In the situation where the auxiliary transformer is providing the earth connection the installation of a commissioning overcurrent protection would not be required as the auxiliary transformer provides an earthing path and must remain connected. Until energisation the protection scheme at the onshore and offshore substations cannot be proven. This includes as appropriate; busbar differential, subsea cable protection, transformer differential, directional overcurrent, earth fault and circuit breaker fail schemes. 3.7.4.2 Post-energisation When the system has been energised for a few days, one should attend the substation to inspect (see, hear, smell, touch) all equipment, cables and associated plant. In some cases, the supplier of each equipment will have a clear instruction on post‐energisation checks ‐ but in most cases, one will have to use/invent their own checks. A few guidelines can be found below. 3.7.4.3 Transformers Following energisation, it will be necessary at some point (e.g. within one month of taking load) to obtain a sample of transformer oil for dissolved gas analysis and other tests for monitoring the condition of the transformer oil. Always observe and follow the manufacturer's instructions. Provisions on the transformer (e.g. bleed valves etc.) for drawing oil samples from the transformer tank should be made so that they are easy and safe to access. This isn’t a problem when initial tests are carried out at the manufacturer’s premises, but substation layout design should ensure that oil draw off facilities do not become obstructed by other features when the transformer is installed. 3.7.4.4 Switchgear Safe access by personnel to switch rooms is required for a visual inspection of the switchgear following an initial period of energisation. Check the system and cable connections for any signs or sounds of partial discharge.

191

3.7.4.5 Export Cables When load from the wind power plant is present, check all cables for any signs of overloading ‐ visually and by infra‐red spectrum cameras (e.g. thermovision) 3.7.4.6 Control & Cable Marshalling Panels Portable recording devices may need to be connected for load testing, power grid system connection compliance testing, or other monitoring purposes. Connection points for this should be readily available, ideally via front of panel sockets, without having to make wiring changes inside panels. Scaling parameters for such connection points should be clearly identifiable e.g. engraved labelling, particularly where transducers are employed. Attempting to obtain this information from manufacturer’s name plates on transducers and other components inside panels is time consuming and can sometimes be very difficult if not impossible e.g. devices installed close to mounting plates that obscure manufacturer’s labelling. Given the comparative high cost of mobilising personnel and test equipment offshore, consideration should be given to the provision of permanently installed recording equipment. Equipment so installed would then be available for power quality monitoring and recording of events beyond load and power grid system connection compliance testing. Hardware and software provisions should be made at the substation so that portable, or permanently installed recording devices may be time synchronised with the turbine control system. 3.7.4.7 Diesel Generator Where a diesel generator is provided at the substation for the purpose of back energising wind turbines during an outage of the connection to the power grid system, careful consideration should be given to the electrical interlocking system that prohibits turbine operation when the diesel generator is connected to turbine arrays. Interlocking the diesel generator LV circuit breaker would be preferable to the diesel generator HV circuit breaker so as to permit energisation and testing of the diesel generator step‐up transformer whilst the turbines are energised from the power grid system. 3.7.4.8 Monitoring for Power Grid Connection Compliance Commissioning In many cases, the substation will include the point where a power generating facility is connected to a power grid system. Where this is the case, connection compliance commissioning tests would need to be performed following energisation of the substation. All circuits and generation facilities that are connected to the substation would need to be fully commissioned prior to the compliance testing. Where power grid system connection compliance is applicable, the following commissioning tests are likely to be undertaken. Equipment provisions should be included to facilitate monitoring of the appropriate parameters during these tests. The parameters to be measured are those existing at the defined point of connection. Turbine control systems are likely to have their own data loggers, but there may be requirements for independent monitoring to verify results. Voltage control This is usually performed using software injection of step voltage changes using the master control system for the turbines. A range of these tests are carried out, during which voltage and reactive power are monitored over a set period. 192

Frequency control Again, this is usually performed using software injection of frequency changes using the master control system for the turbines. Monitoring of frequency response is carried out throughout the range of tests that are conducted. Harmonics Harmonic analysis is based on voltage and current waveforms recorded over an agreed period of time, typically a week or more. Voltage fluctuation Switching operations are performed on all circuits that are likely to produce voltage fluctuations and the effect on voltage at the connection point is recorded. Typical parameters to be monitored during load testing and connection compliance testing are as follows: MW – Active power MVAr – Reactive power System voltages Frequency Harmonics

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4

Physical Considerations

The main objective with Section 4 is to elucidate design considerations with respect to the High Voltage AC Substation platforms and its associated substructures and foundations including environmental impacts, remote location, maintenance issues, access management, etc. Section 4.1 provides an overview of the platforms and the different technologies used today followed by a brief discussion of the most important parameters that need to be considered. Section 4.2 discusses one of the most important subjects working for offshore, i.e. Health Safety and Environment (HSE). HSE must in all parts and from the very beginning permeate the thinking and be part of the fundamental design strategy. Section 4.3 is to set the boundary conditions for the design. These are typically parameters or inputs that are external to the design and cannot be easily changed, e.g. local and global legislations, site location and ambient conditions such as temperature, currents, wave heights, wind speed etc. Unlike boundary conditions that are to be considered as more or less fixed, section 4.4 discusses parts or aspects of the transmission system that will have a significant influence on the platform design but may be subject to discussion and/or iteration. Examples of such equipment or parameters are electrical components and secondary systems, substructure interface, cable installations and installation programme, commissioning tests, etc. Having “set the scene” in the previous sections, section 4.5 discusses the actual design philosophies, design parameters and issues within its own discipline that will have a major influence on the final platform design. It considers aspects related to structural integrity, what to consider for the general arrangement layout, primary access and egress systems, emergency response and platform auxiliary systems. Furthermore, comparison of stressed skin vs. clad truss braced design, corrosion protection, operation and installation and commissioning of plant onshore are considered. Section 4.6 discusses different types of platform concepts like container deck, semi enclosed and fully enclosed topsides. To some extent it also discusses and compares pros and cons of self installing concepts like floatover and jack‐up solutions. Having thoroughly dealt with the topside, section 4.7 covers what is underneath, i.e. the substructure. Different concepts will be compared and pros and cons discussed. Section 4.8 will cover aspects of load out, transportation and installation and the consequences these may imply on the overall design of the topside and substructure. A brief overview of the available lifting vessels is included for information. In conclusion, Section 4.9, assessment of fire and explosion design, together with fire detection/alarm and passive/active fire suppression are discussed.

4.1

General

The main objective of Section 4.1 is to give an overview of the platform design and the different technologies used today; also to discuss the most important parameters and requirements that will need to be considered as a consequence of building platforms far out on remote locations and being exposed to harsh and hostile environments.

4.1.1

About Design Considerations

The overall purpose of an Offshore High Voltage Substation is to form a part of a reliable electrical transmission system of wind generated energy from offshore wind power plants to 194

the onshore grid. This means that we need to develop a robust, safe and highly reliable design for the purpose of evacuating the produced wind power in an optimal way while at the same time meeting demanding requirements such as e.g. strict Grid Codes set by the Transmission System Operator (TSO), minimum maintenance and remote operational requirements. When designing HV substations offshore there are additional requirements that need to be taken into consideration as compared to designing an onshore station; example of these are ▪ Strict HSE requirements including fire fighting, evacuation plans, emergency shelters, sump tanks, drainage systems etc ▪ Offshore safety; today we lack offshore wind specific standards meaning that we often see the standards from oil & gas industry being adopted. The one specific standard produced for offshore substations for wind power plants is the DNV standard DNV‐OS‐J201 [44]44 ▪ Harsh ambient conditions such as salt, wind, waves, currents, bird excrements, etc. Corrosion protection, heat and ventilation, water jets and other means to withstand the stresses coming from the environmental conditions are crucial ▪ Compactness and weight of platform including HV specific equipment; weight is a primary cost driver ▪ Support structure (if applicable), i.e. jacket, monopile or similar; all loads needs to be transferred into few supporting points ▪ Installation methods; transport by sea of the completed substation topside, lift‐ install, self‐installing, float‐over, jack‐up, gravity base or floating ▪ Lifetime; it must last for at least 25‐30 years and be cost optimized ▪ Reliability, Availability and Maintainability; offshore work is very expensive and downtime means loss of revenues for the owner ▪ Material Handling will have a major impact on the overall layout ▪ Cost efficient solutions with respect to both investment and operational costs ▪ Remote operation (Normally Not Manned platform); keeping permanent personnel offshore is very costly ▪ Access and egress systems from the sea (by boat) and from the air (by helicopter) There is a wide offshore experience and knowledge within the oil and gas sector which should be thoroughly considered wherever possible and it is of course tempting to benchmark a design for offshore wind power plants against the oil and gas business. However, there are substantial differences in some areas and to fully adopt the sometimes onerous requirements from the oil and gas business may lead to unneeded and costly solutions. In the end this may jeopardize the wind power plant overall economics.

44

Det Norske Veritas (DNV), Offshore Standard DNV‐OS‐J201 “Offshore Substations”

195

The approach must be to maintain a wide perspective considering many different aspects in order to gain an optimized overall system performance – all the way from the turbines to the mainland grid.

4.1.2

History and Development of Offshore Platforms

Offshore platforms have been around since 1891 when the first submerged oil wells were drilled from platforms on piles in the fresh waters of the Grand Lake St. Marys in Ohio. Since then locations like the Mexican Gulf and the North Sea have been exploited with numerous examples of platforms on piles. Since the earliest platform offshore there has been continuous development as understanding and appreciation of the environment and issues faced develops. Unfortunately this is often as a result of incidents. In the early 1960’s the offshore industry began exploration for oil in the North Sea. This involved the use during construction of floating barges and oil rigs offshore with one of the first in the UK being the Sea Gem. This was a barge which featured steel legs which made it possible to raise the barge fifteen metres out of the water hence creating a platform for 34 crew. When the barge was required to move to a new location the rig could then be lowered back into the water and sailed to wherever required. However in 1965 two of the legs failed when the rig was being lowered, resulting in the platform capsizing into the sea, sinking people and equipment. Thirteen people lost their lives and the safety on offshore rigs was improved through the requirement to be able to rescue crews in the event of an incident, including the use of stand‐by boats. Another significant development in the design of offshore platforms followed the Piper Alpha disaster in the North Sea. This was a fixed platform for the Piper oilfield approximately 190 km from the coast. In July 1988 a massive leak of gas condensate resulted in a fireball engulfing the platform and killing 167 people. The accident resulted in a number of significant changes to work practices offshore and the design of platform due to the immediate issues which were apparent on Piper Alpha, for example automatic fire deluge systems which had been deactivated, gas compression rooms located adjacent to the control room, personnel areas were not smoke proof, and escape routes to life boats were blocked. One of the most significant outcomes was the new legislation requiring compulsory safety management systems (safe cases) be in place for offshore installations, to identify risks and mitigate them to as low as reasonably practicable. Other aspects included the use of temporary safe refuge areas, more than one route to helicopters and life boats must be present to ensure evacuation with secondary escape routes also available (i.e. ropes, ladders and specialised descent‐to‐sea systems). For further information on risk assessments offshore please refer to Section 1 of this document. Most of these supporting platforms are based on truss design. When the first floating platforms, so called semi submersibles, were developed they adopted design principles from the fixed platforms. The most well known is probably Alexander Kielland, a five leg platform which collapsed in 1980 causing 123 casualties. The investigation showed that a fatigue crack developed into a failure in one of the underwater bracings and the redundancy of the structure was not enough to take a single loss of a bracing. While the truss structure is certainly effective in transmitting shear forces, this is one typical drawback with truss structures. When optimized for lightweight the truss structure is dependent on the structural stability of each singular member out of numerous bars and rods. Members may 196

fail in buckling when exposed to compression and in fatigue when exposed to pulsating axial forces or bending.

Figure 4‐1. The salvage of Alexander Kielland Since the accident with Alexander Kielland other concepts have been developed. One alternative is to use a so called stressed skin design. The platform consists of a stiffened shell structure which is watertight up to a certain level. The skin of the superstructure is effectively acting as a load carrying structure. It takes global bending moments and shear forces and gives the structure a robust behaviour. The idea to integrate the skin with the load carrying structure follows a long historic development of vehicles from space frames and trusses to stiffened shell structure, i.e. stressed skin, for cars, busses, and wagons for trains and aero planes. The most commonly used solutions within the offshore wind business so far have been to use truss braced designs. These can be divided into container deck solutions like Barrow, semi enclosed topsides such as Horns Rev A and fully enclosed topsides like Prinses Amalia. Furthermore, platforms can be designed for different installation methods. An approach often used today is to have separate topside lifted onto a substructure by a heavy lift vessel. The substructure can either be of a jacket construction or a monopile. They are fixed to the seabed either by means of gravity based solutions or by driving piles into the seabed through skirt or leg piles. There are not many heavy lift vessels that can install topsides with a weight exceeding 1500 metric tones. These vessels tend to be heavily booked and the installation, i.e. the lift and hook‐up works, are very exposed and heavily influenced with respect to weather conditions. Amongst other things this means that installations in the North Sea can most often not take place during the winter season. In order to avoid being dependent on these vessels other types of concepts have been developed, so called self installing platforms. There are different types of self‐installing concepts. These are float‐overs, jack‐ups and floating. For a more detailed description see section 4.8.3 below.

4.2

Overall Health and Safety Aspects

The Heath and Safety requirements for the wind power plant as a complete system will need to be considered and an overall strategy developed by the Owner/Operator. This overall procedure must consider events which influence the design of the offshore platform such as normal access, normal egress, abnormal events and emergency response 197

for the offshore structures. The designers of the offshore substation must be aware of these procedures to include suitable facilities and should be involved in the overall HAZID/HAZOP process. Safety aspects of offshore platforms are covered by national and international standards to a varying degree. Offshore installations are of such a complex nature that simple compliance with prescriptive requirements may not lead to an acceptable level of safety. Instead, it will generally be necessary to evaluate safety aspects of each platform in detail. When choosing such a performance based approach, safety assessment is applied throughout the design process to ensure that the health and safety of personnel, the environment and the installation itself meet minimum safety targets. Demonstration that certain risks have been controlled can be an iterative process. Part of the process is the setting of performance requirements (statements), derived from regulation or company guidance. Suitable performance requirements are measurable and can be used to provide evidence that the component/system can prevent or limit the effect of an unplanned event. Health and Safety procedures developed by the Owner/Operator which may have an impact on the platform design could typically comprise: ▪ Electrical safety ‐ working with low, medium and high voltages ▪ Work at height ‐ Scheduled and unscheduled maintenance work on the platform ▪ Vessel access – normal activity boat access, procedures for visitor access ▪ Helicopter access – normal activity access, procedure for visitor access ▪ Emergency ‐ fire in the platform, accident on platform, stretcher casualty ▪ Emergency – stranding by inclement weather, man overboard, incapacitated transfer vessel ▪ Emergency – bomb threat management / intruder ▪ Provision for stranded mariner

4.2.1

Vessel Access – Normal Activity Boat Access

Statistics show that one of the high risk areas for personnel injury is the transfer of people from a vessel to an offshore structure so this activity requires careful consideration. There are a number of techniques available and these are being constantly improved, however, the most common system for accessing a Normally Unattended Installation (NUI) remains the transfer from a vessel to a vertical ladder. For transport by sea a clear definition of when works will cease due to significant sea states should be agreed. The lifting equipment installed on the offshore platform should be designed to operate within the agreed sea state constraints. See also section 4.3.2.

4.2.2

Emergency Evacuation – by Sea and/or by Air

The emergency evacuation of persons from the offshore platform must be considered at the design stage of the offshore platform as it will influence the facilities to be included on the platform. It is usual to consider Persons on board (POB). Life saving equipment should be dimensioned for the maximum POB at any time, e.g. including additional persons during helicopter‐based shift changes. The Health and Safety Plan should identify the planned means of escape following an incident and typically these could be:‐ 198

▪ Primary

via helicopter and/or via the transfer vessel which may be close to or docked at the platform

▪ Secondary

to the sea by free fall lifeboat

▪ Tertiary (if needed) to the sea by liferaft For common types of liferaft and means of lowering them to the sea, see Section 4.5.6.

4.2.3

Emergency Evacuation of Injured Persons / Stretcher Cases

The emergency evacuation of injured persons / stretcher cases from the offshore platform must be considered at the design stage of the offshore platform as it will influence the facilities to be included on the platform. The width of access walkways, stairways and corners along the escape routes must be suitable for negotiation by two people carrying a stretcher. Suitable stretchers should be located at specified positions around the platform. Where a davit crane is to be positioned above a boat landing for off‐loading of packages, tool bags etc it can often be provided with a padeye suitable for man‐riding emergency descent. The controlled descent equipment could be stored on the platform or carried in the transfer vessel. The platform crane may be specified to include a man‐riding emergency facility.

4.2.4

General Safety Equipment

A functional evaluation of the offshore substation should be undertaken to determine the requirements for general health and safety equipment, typically: ▪ Fire extinguishers, their type and locations ▪ General first aid kits, electrical burns first aid kits as necessary ▪ Life jackets and containers ▪ Life buoys and hangers located at intervals around the platform periphery. Consideration should be given to indelibly marking each of life buoys with the unique identification numerals for the platform. ▪ Spare exposure suits and container, ideally located near the muster area. ▪ Scoop type and basket stretchers as necessary ▪ Safety labelling and signage

4.3

Fundamental Design Parameters

The governing parameters for design of the platform have the following headings: ▪ The overall functional requirement of the platform systems is the design starting point. The platform should support and protect the specified main electrical components, auxiliary equipment and systems needed for electrical input and output requirements. The functions should be commissioned within the required start up date. ▪ The Environmental conditions ▪ Requirements from the operational risk and safety assessment should be catered for at an early stage of the design. The impact from the assessment report will impact operational safety levels and cost. Also, requirement from the Authorities, Insurers, Company policies and standards/certification are important as they will determine 199

the design process and goals/limits. In order for the project to get through the permit process, all relevant rules and regulations should be listed and impact investigated.

4.3.1

Functional Requirements

The functional requirements are the main purposes of the platform. It can be the required MW throughput of the platform, voltage levels and the number of radials from the wind power plant. A transformer platform can also function as an offshore hub for gathering energy on different voltage levels from more than one wind power plant. The next important requirement is the availability, which influences redundancy and maintenance philosophy for the platform operations. The operational and availability requirements will result in the selected redundancy level for the components configuration. Redundancy aspects are covered in Sections 1& 2. Each system and component configuration will have a set of requirements that are derived from the operational requirements combined with the parameters from the safety, risk, and authorities' rules. In order to sustain the same level of operability in the harsh environment offshore, stringent quality and maintenance programmes will be required. The topside and structural design layout is governed by how the connected import and export cables are configured, and the extent of equipment and their configuration on the platform. There can often be 10‐20 incoming and 2‐3 outgoing cables. Furthermore, requirement for permanent or temporary accommodation, material handling, etc. will also have considerable impact on layout and cost. A rescue‐ or transport helicopter flying pattern is a parameter that will have an impact on the position and layout orientation of the platform, particularly with respect to the direction of the prevailing winds. The transport to and from the platform of personnel and goods by sea will influence the orientation of the supporting structure and position of the boat landings with respect to the current directions. The wind power plant and cable field layout, together with the risk of vessel impact determine the platform position. In order to find the right position, it will be a compromise between the array cable cost and platform "cost of position" (water depth, soil, cables to shore, etc.). The arrangement of the incoming array cables and the outgoing high voltage cables (J‐tubes layout) are determining factors for the supporting structure design. The J‐tube design should accommodate and protect the cables without excessive heat build up during operation and also be directed to mitigate the need to cross cable circuits on the sea bed. There should be space for support and installation equipment on the lower deck and the cables should be adequately protected between the J‐tube bell mouth outlet and the seabed. There are many criteria to base the platform selection on. Cost is obvious but also other requirements will have different levels of achievement depending on what type of platform is evaluated. The different platform concepts (see Section 4.6) can be given different scores, depending on how they combine the functional and other requirement's achievements and cost. To start with, the alternatives can be sketched, listed and scored using engineering judgement. The assessment should also include material evaluation (concrete, steel, stainless steel, composites etc.). The decision on the concept, with the right number of platform parts, good foundation, effective purchase philosophy and installation technique with acceptable level of risk is difficult but critical for the project success.

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4.3.2

Environmental Conditions

The layout of the platform and the structural design should make sure the equipment is adequately supported and protected for the duration of the design life. The fundamental design parameters are the harsh environmental conditions offshore with waves, wind, humidity, ice and fluctuating temperatures. There are several offshore design codes and practices that will guide the designer in the consequences of the environmental parameters to the platform design. It is however recommended that the parameters are thoroughly checked, and additional investigations are made to find and select the correct conditions. Water depths, wave data and ice conditions may have a significant impact on the platform cost. Early investigations on these parameters are recommended as well as studies on their impact on the platform's conceptual design. Other aspects of the design related to environmental conditions and particularly with relevance to fatigue are vibrations and oscillations. Vibrations from wind and waves as well as oscillations from equipment such as the main transformers or diesel generators may affect the long term withstand capability of both the mechanical structures and the electrical equipment. The substructure stability may need to be strengthened and the equipment could be mounted on special absorbing mounts if necessary. When the first platform concept has been sketched, the foundation method and the suitable platform concepts need to be assessed. The environmental conditions are again major factors, particularly water depth and soil conditions. It will be necessary to make sea bottom and soil condition surveys on site and the results should be used in the foundation design. It is common to use the Douglas Sea Scale to define the sea state for design and operational purposes and typically a marine crane may be designed and rated to lift a specific load in a specified sea state 3. In design specifications and calculations, however, significant wave height is commonly used when describing waves. The Douglas Scale has two codes, one code is for estimating the state of the sea, and the other code is for describing the swell of the sea. Degree

Height (m)

Description

0

No wave

Calm (Glassy)

1

0 – 0.10

Calm (Rippled)

2

0.10 – 0.50

Smooth

3

0.50 – 1.25

Slight

4

1.25 – 2.5

Moderate

5

2.5 – 4.00

Rough

6

4.00 – 6.00

Very Rough

7

6.00 – 9.00

High

8

9.00 – 14.00

Very High

9

14.00+

Phenomenal

Table 4‐1. Wind Sea 201

Degree

Description

0

No Swell

1

Very Low (short and low wave)

2

Low (long and low wave)

3

Light (short and moderate wave)

4

Moderate (average and moderate wave)

5

Moderate rough (long and moderate wave)

6

Rough (short and heavy wave)

7

High (average and heavy wave)

8

Very high (long and heavy wave)

9

Confused (wave length and height indefinable)

Table 4-2. Swell

4.3.3

Risk, Safety and Rules

The platform and the equipment, or system, will have a configuration and set of requirements that is deduced from the functional and availability requirements. These requirements and their consequences on the equipment selection and the platform layout are also influenced by the safety and risk philosophy, and the rules defined by the authorities. Risk and safety assessments and the rules regime will continue to govern the design throughout the project. The rules set by the authorities, are often related to personnel risk, but there are also rules that control the equipment quality or required limits to be followed for environmental impacts. It is necessary to be fully aware of, and have the necessary resources and time available, to obtain the approvals from the specified Authorities. Requirement from the Legislation Authorities with respect to the installations, the operation of the installations, and the approvals needed from affected authorities and interest groups (fishing, maritime operations, and sea bottom recourses) will have a big influence on the project. The environment on a transformer platform is different from an oil platform. On the positive side is the lack of dangerous hydrocarbons, but there are High Voltage items of equipment which if they fail may lead to significant short circuit heat energy being released and may subsequently explode. Further there may be effects from magnetic fields and radar beams to take due care of. Each system and component may also adhere to national, European, US or other area legislation. With regard to a helideck design or personnel transfer in general it is important to take due care from the beginning. A landing sector for a helicopter may be required with up to 210° / 1,000 m free space. The authorities' rules usually refer to standards or approval procedures applicable in the respective countries. The rules may include a requirement for 3rd party certificates of compliance. The list of rules and regulations may be long, and likewise are there many companies offering Certification services. The list of applicable

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rules and the range of certification chosen for the project will have significant influence of the cost. Guidance on the certification possibilities and process is covered in Section 1.

4.3.4

Economics

Economics has a significant influence on the concept design and solutions because the investors may have a stringent requirement for return on equity and investment. The project schedule can change considerably in order to meet an earlier start up date, or a later delivery date to meet the marked optimum. The financing and insurance can be influenced by the magnitude of certification of the platform project. Insurance Companies are dependent on the certification documentation in order to cover their risks appropriately.

4.3.5

Lifetime Operational Cost

The lifetime operational cost will be a factor for typically 20‐30 years. The operational/maintenance requirements need to be part of the design from the beginning, and the operational requirements may change during the lifetime. Future operation modes, control systems and maintenance for the future could possibly be prepared from the start and in that way, save modification cost at the time of implementation

4.4

Additional Design inputs

As noted in section 4.3 above there are a large number of fundamental boundary conditions which are set on the project. These impact on the design of the offshore platform; for example the site sea depth, the wind turbine and cable locations, or the voltage and primary equipment which is required on the platform. These cannot be easily changed and are therefore termed as the fundamental design parameters. However there remains a large number of design factors which can significantly influence the final platform design, these are referred to as additional design parameters. The designer(s) must consider the impact of the additional factors as part of the final platform design to optimise both the CAPEX and OPEX perspective whilst ensuring safety in design. The additional design inputs are often established through an iterative process and are not generally considered to be fixed as the fundamental parameters. The following Sections outline a number of the key interactions which should be considered with the design of the offshore ac platform. These are arranged in a general timeframe of consideration however it should be noted that although an item is listed later it does not necessarily mean that this is of minor importance. It is not unusual that the smaller items end up having a significant impact on the overall design.

4.4.1

Electrical Equipment

The overall project design basis will outline the voltage levels and primary equipment required to be housed on the offshore platform. Sections 2 and 3 provide a detailed explanation of the factors influencing the project Single Line Diagram (SLD) and equipment which should be selected in the offshore environment. This includes aspects of equipment physical size and weight, the rating and number of power transformers, the number of export cable and array circuits etc.

4.4.2

Topside Layout

Once the project SLD is known the starting point for the design will be to clearly assess the number of rooms and areas required on the offshore platform. This will require interaction 203

with the substructure design (monopile, jacket, gravity based, or self installing) which will likely have been established prior to the topside design. See also Section 4.7 for further details on the substructure. Provided below is a general overview of typical equipment rooms which may be required with key points for consideration with the design. 4.4.2.1 General The location of equipment and rooms should consider which contain hazardous materials and those which could be habited during normal operations. For example the situation of the control room adjacent to transformer rooms may require blast and fire wall considerations. The layout must also allow for the fundamental principle that escape routes are designed to ensure that personnel can leave by at least one safe route to a designated muster / evacuation area. For a multi‐level platform, the location of equipment requires the designer to consider the connections required between equipment. For example the HV side of the transformer(s) will be connected to the HV switchgear by cabling or busduct. HV and MV cabling requires a lot of space and hence, a more compact arrangement will be possible if there is a natural connection flow between equipment. The use of multi‐decks may introduce restrictions to the options available for removal of equipment during either maintenance or change out. If equipment rooms are stacked above one another it may impose difficulties to vertically remove equipment through the roof using a platform crane. This will dictate that equipment is removed in a horizontal direction from the room and then accessed from the crane, possibly via vertical access shafts or outside the platform boundary. The height required in each room will also impact upon the layout and choice of equipment placed on each level, for example, an HV switchgear room will be higher than an MV switchroom. The safety assessment of equipment and room locations can also influence the design where, for example, the location of a control room over a power transformer would typically require consideration of blast and fire events if the transformer was to have a catastrophic event. Where cables and/or services pass through penetrations in walls/floor/ceilings between one zone and another the penetrations should be effectively sealed against fire and/or the environment as applicable. The platform layout should also consider routine maintenance and how these tasks will be achieved. The offshore platform is such that traditional methods for working at heights or recognised access methods are not readily available. Therefore the layout of the equipment on the platform should consider the tasks which are to be performed and to ensure that measures are included in the initial layout which minimise any restrictions or difficulties in performing tasks during the life of the platform. 4.4.2.2 HV Transformers The power transformer can be located indoors, outdoors, or a combination (where radiators are mounted externally and the tank internal). The positioning of the transformer(s) on the platform is important as the units are likely to be the heaviest items of plant on the offshore platform. The positioning will also be influenced by the type of cooling system adopted for the transformer, tank mounted, air 204

cooled radiators, separately mounted air cooled radiators, water cooled system etc and this will determine how much of the transformer can be located indoors. (Refer to Section 3 for more detail) Often transformers and other heavy items are located on the upper deck so they can be accessed through roof hatches in the event of major works becoming necessary. The positioning will impact on the centre of gravity as explained in detail in Section 4.5.2 below. The maintenance of the unit (including tap changers) and any oil processing through the life of the unit can also influence the area required around the transformer in addition to the extent of bunded areas and location of oil drain tanks. 4.4.2.3 HV Switchgear and MV Switchgear Typically HV and MV switchgear will be located within individual temperature controlled rooms. The location and extent of the switchgear (i.e. number of bays) will be determined by the system configuration, however the location of the rooms on the platform should consider the connection from the export cable(s), to and from the transformer, the outgoing array cables to the WTGs, and busduct if it is used. Detailed aspects, including access required around the equipment, are provided in Section 3. The system architecture or equipment parameters will not provide information on the installation timing of the equipment. In particular, HV GIS is typically delivered in pre‐ assembled bays. The design of the topside must consider if this equipment can be rolled, or lowered, into the switchgear room. If this is not possible, then the switchgear room may require to be partially constructed to allow the equipment to be delivered, prior to the room being completed to enclose the switchgear. At an early stage this can be integrated into the platform fabrication and equipment delivery to provide a workable solution, however if this is not considered there could be significant consequences if the equipment requires to be disassembled to allow it to be installed into the switchgear room. The platform designer must also consider possible replacement of switchgear components during the lifetime of the platform and this may necessitate oversize access doors to the room, removable wall or roof panels etc. If cable connections are unitised (i.e. plug in connectors) the access area directly below the equipment should be considered to ensure that this area is available (i.e. a local basement type area). Further details are provided in Section 3. The initial HV test of the unit, and any subsequent test, will also require to be included in the room design to allow for connection and ease of test. 4.4.2.4 Tariff / Settlement Metering The inclusion of tariff / settlement metering can require dedicated rooms offshore as the equipment can be owned and operated by a meter operator. Obviously this ownership boundary needs to be identified at an early stage of the project prior to commencement of the platform design. 4.4.2.5 Protection, Control (SCADA) and Telecommunication Panels This range of equipment could be located in a single room, in individual function rooms, or located within other rooms (i.e. protection mounted on the switchgear is common for MV switchboards). The number of panels required on the platform should be clearly identified, including any panels issued or required by third parties. In providing a layout of panels the access requirements should be determined as this will significantly impact on the room layout. For example, the room layout may be reduced if 205

panels are front access only, however, due to type of equipment located within the panel, very often the design is such that front and rear access is required. The cabling to and from the panels must also consider if top or bottom access is possible. This has a direct impact upon the extent and routing of cable tray/ladder and if bottom entry the floor design. 4.4.2.6 Auxiliary Generators There are two fundamental requirements for auxiliary generators to be located on the offshore platform: 1. To provide emergency power for the substation platform in the event of loss of grid power. The rating of the emergency generator should take account of start up load, running load and power factor and minimum load conditions for the platform supplies 2. To provide power to the WTG’s in the event of loss of grid power. Depending upon the WTG’s which are to be installed, they may not able to survive without auxiliary power for a certain time. Therefore in the scenario where the connection to shore is lost, the auxiliary loads of the WTG’s may require to be supplied as well as of the main substation platform itself. This requires assessment of the power of generation required hence the size, and number of, auxiliary generators required on the platform, also the generator scheme needs to take account of the capacitance of the sub‐sea cable circuits in the WTG strings. This also relates to the fuel storage facilities required to provide the necessary power for a period of time until supplies can be restored or the frequency of fuel re‐fills which is acceptable or can be achieved due to the accessibility of the platform.(Refer also to Section 3.4.1.2) 4.4.2.7 Accommodation and Emergency Shelter Rooms The strategy and requirements for any accommodation offshore will be driven by the fundamentals of the platform location and the maintenance requirements. The extent of the accommodation and welfare facilities will have an obvious impact on the platform layout. This must be clearly established at an early stage to ensure that the functionality is suitable and safely integrated into the design. The inclusion of emergency overnight accommodation and temporary refuges/safe haven imply different design requirements. The requirement should be clearly established early in the design process to ensure that the layout of the platform meets the specific needs and that the legislative aspects are covered. 4.4.2.8 LV Supplies The location and number of LV transformers will largely be dictated by the system design. However the units can be oil filled or dry‐type and this will impact upon the location requirements on the platform and any system redundancy. The location of the main LV distribution board(s) and their sub‐distribution boards should also be considered. (refer to Section 5 for more detail) Given the number of water, firewater and fuelling pumps that may be installed on the platform, motor control and start up facilities must also be considered in the LVAC scheme.

206

4.4.2.9 Workshop and Storage Rooms The maintenance strategy will determine if a workshop is required offshore, however the extent of the workshop and storage needs to be established. This can range from the storage of simple maintenance activities (for example fuses and bulbs), to medium strategy spares (for example air filters for HVAC, or protection relays), to significant items (for example 36 kV circuit breaker). Depending on the operational philosophy the platform may also provide the additional function of a storage area for the WTGS (rather than the basic function as only a substation). If the platform is to be the hub for the wind turbine maintenance activities additional storage capacity for spare parts and consumables will require to be considered. 4.4.2.10 Standby Supplies and Battery Rooms The platform will require back‐up supplies for the loss of the onshore connection. This can consist of DC batteries and UPS systems. The extent of this requirement will also be a factor with the auxiliary generator stand‐up time and systems connected, including the separation of ‘essential’ and ‘non‐essential’ supplies. A dedicated UPS system could be installed or smaller, individual units could be installed in the base of panels depending upon the autonomy time required. For DC battery systems, the potential gassing of batteries during charging, and if open terminals are present, may drive the design to an independent battery room. Refer to Section 5 for further details on the battery system design considerations. 4.4.2.11 Platform Cranes The installation of a platform crane, or a number of, is likely to be required on the platform to facilitate equipment movement around the platform and also for service tasks to / from vessels. In addition, if a multi‐level platform is utilised the crane may require to access different levels through service hatches. Section 4.5.4 provides further details on the material handling on an offshore platform and illustrates that the crane, or cranes, position and capacity should be carefully determined including the loads which are required to be carried and the pivot‐range. This is an iterative process on the platform layout as the equipment position in relation to the crane will impact on the permissible loads that the crane can carry (as at long crane reach the capabilities are lower than with shorter boom lengths). This may drive the design to a larger crane capacity or location of the crane at a short reach to this item of plant. The platform crane should also be able to access the relevant laydown areas of the platform in conjunction with unloading from the vessel. The optimum crane location and boom movement to the vessel from the laydown areas may conflict with the equipment rooms and primary plant locations. The rating will be influenced by the significant wave height (sea state) that can exist during the lift operations. 4.4.2.12 Fire System The requirements of the fire system will be governed by the safety assessment of the platform however this will be a significant factor of the topside layout. The fire system may require water storage (either through water cylinders or a water tank) if a water mist, deluge, or similar is required. The volume of water will also be dictated by the system to be deployed. In addition, inert gas could be required for equipment rooms which will require either to be centralised or de‐centralised depending upon the redundancy required in the 207

system. A key factor is that the fire cylinders will require to be replaced in approximately seven years and therefore provision for this activity will feature in the topside layout. The fire systems are dealt with more fully in section 4.9. 4.4.2.13 Helicopter Access To date the majority of offshore platforms have been installed a distance from the shore which permits access via vessels. However a number include the option for helicopter access and also as distance increases from shore, the only viable access is via helicopter. If this is a requirement, the layout of the platform should therefore consider the access legislation and performance standards for helicopters. There is a documented need within the UK to ensure that helicopters are afforded sufficient space to be able to operate safely at all times in the varying conditions experienced offshore. This broadly includes helideck dimensions, emissions and exhausts, areas where obstacles are permitted, areas where obstacles are prohibited, and visual aids which are required. Within the UK, the HSE offshore helideck design guidelines [45] 45 and the accompanying Civil Aviation Authority guidelines (CAP 437) [46]46 provide comprehensive design information into the requirements of helicopter landing areas. This should be considered as part of the topside design at an early stage in the design process. Further details on the implications of helicopter access is provided in Section 4.5.5 4.4.2.14 Security An offshore platform will be, by the nature of the location, inaccessible to a large number of people. However security to prevent unauthorised access will be required. This will typically feature security systems similar to an onshore substation. However legislation at sea requires that the facility provide shelter from the sea for any distressed mariner. The design of the platform should therefore be such to allow access from the sea however prevent access to upper equipment levels. This is of relevance where multiple escape routes from the platform are included in the design for safety however the route may provide access for unauthorised personnel if suitable barriers cannot be easily installed.

4.4.3

Topside Lift

The yard which is to be utilised for the topside construction requires to be taken into consideration and also the lift vessel capability. This may dictate that the topside cannot be assembled and lifted in one complete portion and may require the offshore platform to be installed in sections out at sea which will impact on the layout design to permit this activity. The capability of the vessel will also provide a design input into the topside through the lifting requirements. For example at the dockside, is the offshore platform lifted or driven onto the sea barge? For the latter, consideration must be given to the base area to allow for a clear access route and lift points for the trucks. This includes cable tray and power cable routes which are installed on the dockside, and also any equipment installed on the lower decks (for example CCTV cameras, floodlight, junction boxes). Consideration must also be given to the final lift from the barge to the sub‐structure. This lift technique may also be used to lift the topside from the dockside onto the barge initially. This can be achieved via different techniques, including lifting eyes at the top of the 45 46

Health and Safety Executive (HSE)’Offshore Helideck Design Guidelines’, John Burt Associates Limited Civil Aviation Authority,’ CAP 437‐Offshore Helicopter Landing Areas‐Guidance on Standards’, August 2010

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structure or lifting from the base of the structure. This lift may also feature spreader beams or be a single hook lift. The route and angle required for chains / slings during the lift should be considered to ensure that the lift is not restricted by platform equipment. The topside should also consider any areas around the lifting eyes to ensure hooks and slings can be connected. This can also require sizable laydown areas for chain/slings and should be included in the design. The lifting chains / slings for an offshore platform can be substantial as the lift can easily be in excess of 1,000 tonnes.

Figure 4‐2. Lift rigging laid on topside prior to sea transport

Figure 4-3. Typical lift shackle arrangement

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4.4.4

Ownership Boundaries and Separation

The ownership boundaries for equipment must be clearly established for the project as this can have an impact on the layout. Equipment may need to be installed in an individual, sometimes lockable, area due to the ownership of this equipment differing. For example equipment owned by the TSO (such as protection and control cubicles for the export cables), or tariff / settlement metering, may need to be housed in a completely separate area/room from the equipment owned and operated by the WTG Owner. This may lead to specific rules and technical requirements for this equipment and can include specific AC / DC supply requirements, independent rooms, or dedicated access requirements.

4.4.5

Reactive Compensation Plant

A significant design item is the inclusion of the reactive compensation equipment (for example shunt reactors and SVCs). This requirement can vary depending upon the ownership boundaries and the Point of Common Coupling (PCC). If the PCC is located onshore this may provide an opportunity to reduce the amount of equipment required offshore. The system studies will need to fully assess voltage profiles to determine if this can be achieved. Alternatively, if the PCC is located at the offshore busbars, the extent of reactive compensation required offshore will need to be identified from the system studies. This could be a combination of fixed reactors or support from the WTG reactive power.

4.4.6

Future Expansion and Expandability

Once the primary and secondary plant is established, the project should determine if there is likely to be any future expansion to the equipment. In an onshore substation it is common practice to allow for the inclusion of an additional circuit breaker bay at either end of a switchboard to allow for possible future expansion. In an offshore substation however, this could be termed as a ‘nice to have’ and would result in additional costs. A realistic assessment should be made judging if a new circuit such as a WTG array or an export cable to shore is likely to be installed in future. The trend going in the direction of larger offshore wind power plants, multiple platforms and offshore grids may bring a new perspective to building in capacity for future circuit connections.

4.4.7 Spare Philosophy and Redundancy The requirements for operational and reliability spares are often left until later in a project once maintenance teams become involved, however advantages can be gained if the spare parts philosophy is known at the time of platform design. A platform designer may provide small areas for storage on the offshore platform however this may not necessarily align with the project risk profile and acceptable down time. As noted in Section 4.4.2.9, the spares can range from small items to strategic items. For the latter the platform will require to be designed to accommodate storage areas for this equipment / spares. Furthermore the equipment procured for use offshore may not be ‘off the shelf’ and therefore may not be readily available without long lead times. The necessity to have a complete, or partial, exchange of equipment will result from the consideration of different failure scenarios. The probability of the specific failure, its effect on the function of the 210

platform (e. g. limiting of the wind power plant power infeed), and the necessary efforts for the restoration of the fault will impact on the arrangement of the equipment on the platform and its decks. If, for example the failure of a transformer is considered, the loss of income can be equated against the additional costs associated with redundancy (i.e. the costs associated with a redundant transformer, the extension of MV and HV switchgear, and the additional maintenance). The choice of the nominal power of the transformers installed may be influenced by the time required to provide and install a spare transformer. The layout of the substation is important as the location and accessibility of the equipment will have a major impact on the efforts required to exchange the faulty equipment (i.e the necessity to shut down or dismantle additional parts of the platform). Section 3 provides further detail on the major replacement strategy and spares associated with primary equipment offshore.

4.4.8

Cable Deck

The cable deck, or installation area for the subsea cables, is a concept which is generally not encountered within an onshore substation. This is largely driven by the feature of the offshore platform where the primary plant (i.e. transformers and switchgear) is not present offshore until the topside is delivered. This therefore creates a design aspect which can dictate the programme of works. In a number of previous installations the cable deck is part of the sub‐structure. Hence, the cable deck is therefore installed at the offshore site before the delivery of the topside. The export and wind power plant array cables can be laid onto the sea bed, installed in the J tubes and placed on the cable deck prior to the delivery of the topside. It must be borne in mind that cable pull in facilities need to be designed into the cable deck and temporary supports will be required to maintain the minimum bending radius (MBR) of the installed sub‐sea cable. The topside installation needs to allow for removal of these temporary supports after installation of the topside. The topside must also be designed to include suitable padeyes and anchorage points to allow for replacement of a sub‐sea cable with the topside in place. Alternatively, if the cable deck is part of the topside, the cable installation works cannot commence until the topside is installed. In this scenario the cables from the sea bed, via the J tubes, will require to be winched into position with the complication of the topside being in position. For both approaches, the area available on the cable deck cannot be underestimated. Cable winches, formers, pulley blocks, winch wires and operatives are required to pull the cables into position, particularly if the cable deck was part of the topside delivery, and then into their respective cable termination locations. This can require considerable lengths of armoured cable to be coiled on the cable deck. The bending radius of this armoured cable (for example a 132 kV 630 mm2 cable can have a bending radius in excess of 2.5 – 3.0 metres) which will determine the height between decks even though the installed MBR of the individual power cores after installation may only be in the region of 1.5 – 2.0metres. The facilities for cable installation are discussed in more detail in Section 3.6.

4.4.9

Routes for Walkways, Minimum Walkway Sizes

The design layout of the platform can have a fundamental impact on the safety of the platform during normal operation, maintenance activities and also emergency situations. 211

The NORSOK safety standard highlights this design aspect as ‘the layout of an installation should reduce probability and the consequences of accidents through location, separation and orientation of areas, equipment and functions’ [47]47. It should however be noted that the standard refers to the petrochemical industry and although safety is no less important on an offshore electrical substation a number of the hazards (in particular the hydrocarbons) are not present in a similar manner on an electrical installation. Whilst this standard provides a good basis for design the extent to which it is applied will be subject to agreement between the Operator and the Designer In can be very easy to reduce the overall area of an offshore platform, and thus cost, through the reduction in access areas around equipment and access routes. The minimum area recommended by the Suppliers of equipment is discussed in detail in Section 3 of this document and this will follow the basic standards in onshore applications, such as IEC 61936‐1, and present the fundamental requirements to the substation design for universally accepted safety measures. In an offshore environment, the Designer needs to take into account the space required to perform testing, commissioning and maintenance tasks. The minimum dimension of escape routes also presents a fundamental design principle which can impact upon the substation layout. An escape route with a minimum of 1 metre in width and 2.3 metres in height is a dimension published in Safety Standards [46]. This requirement increases with the number of persons present on the platform. The Designer should also consider that all doors can be easily opened by one person and open in the direction of escape. This could block the outside escape route if this route is only 1 metre wide.

4.4.10

Fabrication Site

The basic dimensions (width, length, height) of the platform or at least the topside of the platform must not exceed the capacity of the fabrication site. The bigger dimensions the less number of available fabrication sites. There is a certain number of ship yards available worldwide which can handle units up to the so‐called PanaMax (or PanMax), a class of ships, which can pass the Panama‐Canal. The main limitation is the width which must be less than 33.5 m. If the yard is connected to the sea via channels, the passage through these channels may be a limiting factor. A narrow channel limits the width, at least for the wet part of the transportation unit; above the waterfront the size may exceed the channel width slightly. In the same way, narrow bridges may limit the width and the height. If for this reason the length of a self‐floating platform would be increased, care must be taken not to jeopardize the platform seaworthiness. The draught during transfer to the final site may also be restricted which may direct the design towards certain buoyancy. Hence, a comparable heavy construction such as e.g. a self‐floating and/or self‐installing platform may not be possible for some fabrication sites.

4.5

Development of Design

This section will discuss important design philosophies, design parameters and issues within its own discipline that will have a major influence on the platform design. The final design may be developed through several stages with different names and meanings. Typical stages are: 47

NORSOK STANDARD, ‘S‐001, ‘Technical Safety’. Edition 4, February 2008

212

▪ Feasibility Study ‐ evaluates the feasibility of a project or parts of it ▪ Concept Study ‐ evaluates different concepts and/or develops a preliminary design (concept) ▪ Front end engineering and design (FEED) and Pre engineering design ‐ outlines a design with a level of details somewhere between concept and detail design ▪ Detail Design ‐ Design of the elements that proves it can be built, and produces detail design drawings used for fabrication It is recommended to plan the stages based on what is required with respect to decisions, budgets and contracts. The development of the design is closely linked to the contracting philosophy described and gathered in the overall project execution plan.

4.5.1

Design Codes

Standards are consensus documents. In the context of offshore substations, standards should help to produce a “safe” plant. However, not all cases or configurations of offshore platforms can be anticipated; therefore standards have to be supplemented by formal safety assessment, design guidelines and industry best practice. For this reason, regulations have generally evolved from prescriptive to performance standards. In prescriptive standards specific rules, technical measures and solutions are defined; in performance standards a specific objective (the standard to be achieved) is defined with the technical solution left to the designer. Due to the variety of design issues to be addressed, both types of standards play an important role in offshore substation design. In general, international standards are preferable over other guidance. However, national regulations and standards applicable in the place where a platform will be used can be different. Furthermore, national regulations can differ for onshore and offshore locations, in the latter case they may also depend on the distance from shore. Historically, design codes for the maritime industry were developed first; they were then leveraged for the offshore oil & gas industry. Although there can be significant differences due to the absence of hydrocarbons, guidance for offshore oil & gas is highly applicable to offshore wind. With the growth of the offshore wind industry, dedicated guidance such as, for instance, the present document and DNV‐OS‐J201, Offshore Substations for Wind Power plants, becomes increasingly available. The following table shows a selection of relevant standards and guidelines which will aid the designer in the process of decision making and design. The table is not exhaustive, but will serve as a starting point to look for further guidance. For a more comprehensive list see also Appendix 4. ID Name Arrangement and safety considerations ISO 17776 Petroleum and natural gas industries ‐ Offshore production installations ‐ Guidelines on tools and techniques for hazard identification and risk assessment ISO 13702

Contents and application

Different tools and techniques can be used to identify and assess hazards and risks. This standard identifies some of the tools and techniques that may be used for this purpose in the offshore exploration and production industry. Example: Escape, evacuation and rescue analysis (EERA). Petroleum and natural gas Describes the objectives, functional 213

industries ‐ Control and mitigation of fires and explosions on offshore production installations ‐ Requirements and guidelines ISO 15544

Petroleum and natural gas industries ‐ Offshore production installations ‐ Requirements and guidelines for emergency response

SOLAS, consolidated edition 2004

Safety of life at sea

MODU Code, consolidated edition 2001 NORSOK C‐001

Code for the construction and equipment of mobile offshore drilling units Living quarters area

NORSOK S‐001

Technical safety

DNV‐OS‐A101

Safety principles arrangements

DNV‐OS‐J201

Offshore substations wind power plants

Structural design ISO 19900

ISO 19902

and

for

requirements and guidelines for the control and mitigation of fires and explosions on offshore installations used for the development of hydrocarbon resources. Particularly useful: Arrangements to mitigate explosion effects. Guidelines on escape, refuge, evacuation and rescue is consistent with ISO 13702 but address in more detail how these aspects are built into development of emergency response measures. Based on an approach where the selection of measures is determined by the evaluation of hazards. Regulations applicable to ships of 300 to 500 gross tonnage and above; emergency power, fire protection, life‐ saving arrangement and communications requirements. Design and operational guideline for mobile offshore drilling units of the semi‐submersible type. Defines the requirements for the architectural design and engineering of the LQ area on offshore installations in the petroleum industry. Describes the principles and requirements for the development of the safety design of offshore installations for production of oil & gas. Provides general safety and arrangement principles for offshore units and installations. General platform design guidance based on safety assessment principles.

Specifies general principles for the design and assessment of structures (bottom‐founded and floating) subjected to known or foreseeable types of actions. Applicable to the design of complete structures including substructures, topsides structures, vessel hulls, foundations and mooring systems. Petroleum and natural gas Contains requirements for planning and

Petroleum and natural gas industries ‐ General requirements for offshore structures

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industries ‐ Fixed offshore structures

ISO 19903

ISO 19905

NORSOK N‐004

NORSOK M‐501

NORSOK

DNV‐OS‐C101

DNV‐OS‐C401

steel engineering of the following tasks: a) design, fabrication, transportation and installation of new structures as well as their future removal; b) in‐service inspection and integrity management of both new and existing structures; c) assessment of existing structures; d) evaluation of structures for reuse at different locations. Specific guidance on actions, structural analysis, foundation design, corrosion control, welding, QA, sea transportation, etc. Petroleum and natural gas Specifies requirements and provides industries ‐ Fixed concrete recommendations applicable to fixed offshore structures concrete offshore structures and specifically addresses a) the design, construction, transportation and installation of new structures, including requirements for in‐service inspection and possible removal of structures, b) the assessment of structures in service, and c) the assessment of structures for reuse at other locations. Petroleum and natural gas Part 1: Jack‐ups industries ‐ Site‐specific Part 2: Jack‐ups commentary assessment of mobile offshore units Design of steel structures Specifies guidelines and requirements for design and documentation of offshore steel structures Surface preparation and Gives the requirements for the selection protective coating of coating materials, surface preparation, application procedures and inspection for protective coatings. Cathodic protection Gives requirements for CP design of submerged installations and seawater containing compartments, and manufacturing and installation of sacrificial anodes. Design of offshore steel General guidance for design of offshore structures, general (LRFD steel structures by load and resistance factor design method. method) Fabrication and Provide a standard to ensure the quality 215

construction structures

DNV‐OS‐C502

Offshore structures

of

offshore of all welding operations used in offshore fabrication, through identifying appropriate welding procedures, welder qualifications and test methods. concrete General guidance for design of offshore concrete structures by load and resistance factor design method.

Access and transfer CAP 437 Offshore helicopter landing Guidance on CAA criteria in assessing areas ‐ Guidance on offshore helicopter landing areas for world‐wide use by helicopters registered standards in the UK. Accepted as de‐facto standard in many countries. NORSOK C‐004 Helicopter deck on offshore Defines the basic requirements for installations design, arrangement and engineering of helicopter decks on offshore installations. DNV‐OS‐E401 Helicopter decks Design loads, load combinations, strength requirements, safety requirements. Fire protection ISO 13702 Petroleum and natural gas Describes the objectives, performance industries ‐ Control and requirements and guidelines for the mitigation of fires and control and mitigation of fires and explosions on offshore explosions on offshore installations used production installations ‐ for the development of hydrocarbon Requirements and resources. guidelines Safety of life at sea Regulations applicable to ships of 300 to SOLAS, 500 gross tonnage and above. consolidated edition 2004 MODU Code, Code for the construction Design and operational guideline for and equipment of mobile mobile offshore drilling units of the consolidated semi‐submersible type. offshore drilling units edition 2001 NORSOK S‐001 Technical safety Safety design of offshore installations incl. fire detection, active and passive protection. DNV‐OS‐D301 Fire protection Fire protection for offshore structures, drawing from both SOLAS and MODU Code. IEEE Guide for Substation Fire Fire protection for electrical equipment Protection (based on onshore installations) NPFA Fire protection Fire protection for electrical equipment (based on onshore installations)

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4.5.2

Structural Integrity

For the establishment of an offshore substation the same basics are needed to be met as in an onshore substation, i.e. there has to be area for the location of the substation equipment to be installed in the electrical system as well as auxiliary systems. The areas needed for equipment and auxiliary systems are different from substation to substation depending on the actual electrical equipment and location of the station. The floor areas will be established on a topside structure which will be supported on a substructure standing on the sea bed. In section 4.7 different types of substructure concepts are described. Regardless of the type of concept chosen the substructure and topside has to be seen as one installation which has to withstand the loads from equipment as well as the natural forces of wind, waves and unforeseen accidental scenarios. The selected design codes (see 4.5.1) will define the structural calculations and inputs for the design. As the final structural design is an outcome of the design codes to be followed, considerations should be made for several different inputs into the design. For optimization of the structures, and their integrity, two parameters are to be considered: ▪ Centre of gravity ▪ Fail safe design For an optimal utilization of the structural steel a well placed centre of gravity is most important. A centre of gravity not placed ideally can result in an oversized substructure compared to what could be achieved, resulting in unnecessary costs for material and fabrication. The physical location of heavy components on the topside will impact both on the topside structure and the substructure. Ideally located equipment and the following load distribution in the topside structure with respect to the substructure interface will result in an optimal utilization of the structural steel. In other words, uneven load distribution may result in an oversized topside structure as well as resulting in an unfavourable location of the centre of gravity. The main objective with the fail safe design is that the structural integrity should respond in such a way that it will not cause a collapse of the structure or that a limited damage will not lead to a total collapse should a failure like e.g. overstress occur. A basic input for structural design and integrity is the overall lifetime for the substation in respect of fatigue calculations. Centre of Gravity and Load distribution (covering: Integral or separate decks (i.e. separately transported) It is necessary already in the overall project planning, evaluating conceptual design together with Purchase philosophy of the different part of the platform, to evaluate and define the first go at COG and load distribution. As mentioned above, the weight and COG of each platform part is essential for the feasibility and cost of the transformer platform project. It is recommended to put in a shift of centre of gravity for the topside module in a radius of 1.5m in the initial calculations. The COG and load distribution design is closely related to the project overall philosophy for design, operation and maintenance. A layout starting point can be tested for compliance with these philosophies, whereas the ability for safe construction, maintenance and replacement of large component will play a significant role regarding COG and optimum load distribution. The platform must also be designed for change out of heavy equipment e.g. the power transformers. It may be necessary to confirm that the design can withstand a 217

displacement of the COG by running a complete worst case load design calculation without one of the main transformers. Collision withstanding capability The design requirement for collision of vessels in the vicinity of the platform will be deduced partly from vessel traffic pattern from the platform's own service vessels, vessels servicing other offshore installations, or other merchant ships sailing pattern. Systematic ways of establishing the collision impact criteria, is by an engineering study investigating the vessels expected in the area with all the planned installations taken into consideration, and decide what vessel and risk should be the design criteria. Clearly, there is a practical limit to what kind of ship impact a platform can survive. For instance, no platform will withstand the impact of a drifting tanker. Local maritime and coastguards agencies would possibly have design criteria for ship impact design and evaluations and must be investigated. Scenarios for ship impacts and possible consequential environmental hazards to be investigated may differ from one country to the other. An example of such local requirements is the requirement to choose a structural design which is less likely to damage the hull of a tanker (e.g. in Germany) Typically a collision analysis consists of two steps; collision and post analysis. E.g. members experiencing plastic strains between 5% and 15% during ship impact will be omitted in the post damage analysis. The post damage analysis typically has a return period of 1 year, i.e. 1 year to repair. Weight and size of components The weight control is an important part of the platform design and requires a systematic approach already from the very beginning. The main objective is to have control over the weight and its impact and to ensure that all the necessary consequences from the components weights to other parts of the platform with regard to local reinforcements as well as global structural design and lifting design is considered. Another way to use the weight controlling is to establish bonus or penalty tools in the component purchase orders and include requirement for certified (2nd or 3rd part) weight certificates upon delivery. It is also recommended to develop a "material handling study". This study systematically analyses the operations involving handling of materials (not only mechanical). The study should take all component maintenance and change out operations into consideration. The most important design process involving COG and size evaluation is the layout study. The study purpose is to evaluate the interaction of components and room functions, and from different layouts proposals choose the optimum solution. Oscillations and accelerations The design of structures may have a major effect on platform equipment in terms of oscillations and accelerations. The structures are exposed to forces that unavoidably will introduce stresses that the equipment on the platform will have to withstand. This may have consequences on the overall concept of the structural foundation and design. Generally all offshore structures are analysed for their stiffness and period for 1st eigen mode for evaluation of human wellbeing and structure fatigue loads. As a recommended threshold value for human beings 2.5s as 1st eigen mode period is widely used and for avoiding unnecessary fatigue loading the period value should not exceed 3‐4s. As a substation will be manned during crew visits (or with permanent manning) a low value should be preferred but must also in the design phase be weighted against fabrication and installation costs. The stiffer the structure, the higher the total fabrication weight, and cost, possibly resulting in higher costs for offshore installation. Regarding acceptable 218

accelerations for equipment has shown that up until today it could be difficult to find a specific value. Experiences from some operating substations/wind power plants have shown problems with equipment needing replacement due to induced loading leading to operating faults due to accelerations. Dynamic loads Dynamic loads include wind‐, wave‐, current‐, fatigue‐ and ice loads. International design standards cater for proper care of the wind, wave, and current loading. One should be aware that the consequences from these condition parameters depend on decision on platform position, orientation, layout and structural initial design. The design of structures with regard to ice is often based on insufficient data, but has a significant influence on the design and cost. The cooperation with other disciplines may possibly avoid problems and cost. Before deciding on the design requirements with respect to ice loads, a thorough analysis of the ice frequency should be conducted and the result analysed and evaluated. Worst case scenarios based on loose facts may result in cost going up unnecessarily. When the right unavoidable amount and frequency of ice is decided, then the way to handle it should be decided. Two factors can be mentioned, structural main members and boat landing. The main structural member design will meet the ice, and should be optimized with this fact taken into account. Cost can be reduced by the right size, form and not least elevation. Furthermore, the value of a permanent boat landing must be evaluated. There are ships that can be designed to service a platform without a boat landing arrangement. 4.5.2.1 Truss vs. Stressed Skin Considerable experience has been collected over the years for some evident applications of the two principles; truss braced and stressed skin solutions. The key word to success is “synergy” between different functions. The functions related to the structure that are required can be summarized in the following list • to provide protection against the environment (barrier function) • to provide support for heavy equipment locally (local support function) • to carry loads from one location to support pillars (force transmission) • to provide stiffness (to avoid vibration or excess deformation) • to provide easy installation (low weight, small dimensions) • to provide robustness over time (good structural redundancy) • to provide space for the equipment (large spaces around some equipment) • to provide access for maintenance (space around some equipment) • to provide safe working conditions over time (barriers, stiffness and space) • to provide easy manufacturing processes (many manufacturers) Table 4‐3 below makes a comparison of the overall functions between a design based on Stressed Skin and a design based on Truss.

219

Function

Stressed skin solution

Barrier

The plate between 5‐10 mm is welded all around to a robust and tight box.

Local support functions

Each deck is a platform with strong girders. Shear force distribution and Side walls and bulkheads force transmission both divide the platform volume into separate rooms and provide shear force stiffness for heavy equipment and transmission to support pillars. Stiffness to reduce The stress skin is inherently vibrations stiff around all side walls and bulkheads by synergy between the barrier function and structural function. Easy installation on site. Installation benefit from light weight and small dimensions, and provides better robustness. The design is also more flexible for late changes. Robustness. The stressed skin is more robust than the truss as it is more damage tolerant. Provide space. Non significant difference Manufacturing process. Ship yards may utilise their robotized welding systems for stiffened panels

Cladded truss braced solution Corrugated panels are attached to the truss by screw or rivets. May require maintenance to remain tight. Each deck is a platform with strong girders. Special arrangement is needed with truss structure and separating walls. No synergy.

Stiffness does not benefit from the synergy between the barrier function and the stiffness provided by the truss. Less robust and less flexible in case of late design changes.

Less damage tolerant.

Non significant difference Manufacturing includes complex joints with expert welding.

Table 4‐3. Comparison Stressed skin vs. Truss braced solution From manufacturing point of view the stressed skin can be produced at many ship yards at reasonable cost. One can assume that a truss structure would be rather complex to handle for a ship yard used to doing a lot of the welding with robots running in straight lines for stiffeners on flat plates. The robotized production is an effective way of making large thin walled steel boxes. On the other hand the platform yard is usually not in possession of robotized welding system meaning that there is a risk that they are not as efficient as ship yard producing stress skin solutions. The most important difference is of course how shear load is handled by the structural elements involved in the configuration. Specific parametric studies on shear behaviour show that the stressed skin is not superior in transmitting shear. The conclusion is that truss 220

structure is specialized in taking shear and good at it. When the thickness is motivated by external lateral load on a structure (hydrostatic pressure) the stressed skin, i.e. the shell structure, is obviously advantageous. From an application point of view, i.e. the location of apparatus in separate rooms with rather large free spans and few penetrations of bulkheads/decks the stressed skin can be advantageous as the separation walls have synergies with structural functions, providing stiffness and strength all along the bulkheads and side walls without extra cost of material. The lifting during the installation on top of the pile structure may give the highest stresses and strains if there are special requirements, such as ability to carry all of the loads over a diagonal of the structure. Then of course the shear loads will double and thicknesses will increase for both the truss structure and the shell structure. An alternative to transportation on barge is to float out the platform itself for simple transport on own displacement and installation without “heavy lifters”. Then there is also a demand for the “box” to take lateral pressure on the skin and the stressed skin is then the preferred solution. In such case the corrugated panel on a truss structure is simply not useful. From an installation point of view a stressed skin solution could possibly give higher flexibility as there may be more ways to carry out the installation due to robustness and easy adaptation to a floating body. As the installation includes lifting operations low weight is of interest. Considering platforms of significant size, neither of the two structural arrangements could beat the other on weight saving. Studies based on parametric evaluation of the structural steel weight concludes that unless lateral load (water pressure against side walls and bottom or liquid pressures in tanks) are significant the competition between truss structures and stressed skin can not be judged easily without a thorough design comparison. However, there may be other aspects influencing the preferred solution.

4.5.3

General Arrangement

The overall layout of the platform, i.e. the General Arrangement (GA), will have a major influence on the total weight and hence the cost of the topside and the substructure. There are many other parameters that will affect the final layout of the platform. The “main process” on an offshore substation for wind power is the HV power flow (transformation). It would be natural to start finding an optimal “process flow”, beginning with the incoming MV cables (J‐tubes, cable hang‐offs etc.) further on to the MV switchboards and the power transformer to end with the HV GIS Switchgear and the outgoing export cables. A typical layout arrangement will include separate areas for the main equipment starting with MV switchboards, main transformer(s), HV GIS unit(s) and possibly also shunt reactors and harmonic filters. These units are the basic equipment for the transformation of the MV electricity to a higher HV level suitable for export to on shore grid. If a wind park is divided into parts (normally two halves) for redundancy of electrical production, one should also consider arranging the main equipment in such a way that the objective with respect to redundancy will be maintained. For utility systems as well as substation and wind park control, fire and safety issues and operability of systems must be evaluated. The table below lists typical rooms within an offshore platform for an AC substation.

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Platform space (room) Transformer Rooms Emergency Generator Room Wind Park Control room Control & Protection room Air Lock Crew Lockers Toilet Kitchen and Staff room Emergency Shelters HV GIS room Auxiliary transformer room MV switchgear room Emergency food & water store HVAC room WTG spares storage Filter banks (if applicable) LV switchgear room Fire fighting room Lay down areas Staircases Life raft with davit Fuel tank emergency generator AC/DC distribution room Battery room Table 4‐4. List of platform rooms But first and foremost the HSE perspective must permeate the design in all its aspects; the location of accommodation and/or emergency shelters and muster points in relation to access and egress provisions must be carefully considered. Furthermore, fire and explosion, evacuation plans and escape routes must be planned in an adequate way. From a structural integrity point of view the GA will need to allow for mechanical load distribution down to the supporting structure. An important consequence of the GA is the location of Centre of Gravity. A low and centralized position is preferable. This can however be in opposition to the requirement that heavy equipment such as power transformers should be replaceable by heavy lift vessel and may therefore be located on upper, or at least on an intermediate deck. The GA will also need to take into account the operability and maintainability of the platform; walkways and stairs must be located in such a way that they will render it practically possible for the personnel to move around on the platform not only in case of an 222

emergency situation but also under normal circumstances. Special measures may have to be taken to facilitate inspections and maintenance. As the main transformer (and in some cases the GIS unit) is a very large piece of equipment normally with a height of 6.5 to 7.5m, a layout with multi storey buildings, 2 or 3 storeys in height is a way of optimizing total outline of the topside. The multi storey buildings will include the secondary and utility systems and be either of containerized type or purpose designed incorporated into the topside structure. 4.5.4 Material Handling The layout of any electrical substation must take into account the range of requirements and design consideration for material handling. This is often referred to as a material handling philosophy. This philosophy must consider the complete life cycle of the project including installation, testing, maintenance, replacement, and decommissioning of the equipment. Material handling is an essential consideration of an offshore ac substation as changes to the philosophy at a later stage, or identification of shortcomings in the design once offshore, can have significant impact on the ability to perform the works. Whereby an onshore substation can implement modifications or alternative methods of material handling with relative ease the impact of a small change after installation in an offshore environment after installation can have a large and costly impact. This can cascade to the requirement for additional equipment and modifications offshore with the added implication of how this can be achieved with limited access and support equipment. The material handling can be considered in three areas (i) construction and installation phase, (ii) performing operating and maintenance procedures, and (iii) transferring equipment and supplies. 4.5.4.1 Construction Phase Initial consideration of material handling must be completed early in the design and include the requirements within the construction and equipment installation. An element of the construction phase may integrate equipment deliveries with partially completed structures or facilities available on the dockside / yard. This generally applies to primary plant, for example power transformers, HV switchgear, reactors, and diesel generators. A partially completed installation philosophy can present a number of advantages including reducing material handling during construction. However the design basis must consider the worst case scenario where a complete replacement is required on final build. The description and methodology for removal at sea, which can likely require a heavy lift vessel and potential partial disassembly of the platform structure, must be clearly established at an early stage. The risk assessment will provide input into the strategy for the material handling of large primary plant items. For example, a transformer core failure could be classified as unlikely however if this was to occur could the equipment be removed? And would a lengthy removal of enclosure sections be acceptable to the project to allow the unit to be lifted to a barge from a separate vessel heavy lift crane? In addition, the design and layout of the primary steel must ensure that plant items can be removed by heavy lift vessel cranes and that equipment is not trapped. Alternatively a fast removal could be required by the project where an immediate replacement is possible, i.e. through a spare unit on the dockside. This could be achieved by 223

the lifting of the complete transformer unit via a heavy lift crane to a support vessel or removal of the transformer through an innovative project specific solution. 4.5.4.2 Operating and Maintenance Phase The material handling philosophy is critical for the operational phase of the project. The fundamental design basis to ensure that the substation provides a safe environment for operational and maintenance work must be adhered to whilst personnel are protected against the offshore environmental conditions. As a result the concept for an offshore platform is to locate most of the equipment in an indoor environment. This creates an inherent issue to remove equipment to a supply vessel or helicopter for removal to an onshore location. Details of the material handling through this phase of the project will primarily evolve through a material handling assessment. 4.5.4.3 Material Handling Assessment To accurately assess the material handling an assessment should be undertaken early in the design process to provide information on the handling of equipment, devices to be used and routes to laydown areas. This will include consideration of the moving of equipment between levels on the platform. A general assessment could utilise: (i) Item. The piece of equipment under consideration (ii) Weight. Weight of equipment relevant to the status of movement. For example dry weight where diesel is removed from diesel tank prior to lifting. (iii) Dimensions. Length, width, height of equipment to be moved (iv) Maintenance Frequency – Recommended routine maintenance interval for item under assessment or historical duration between expected failures. (v) Handling Equipment. Lifting method and devices required (vi) Route to Laydown Area. Transportation route to laydown / activity area considering the above point. The proposed material handling may have an impact on the platform layout. Item

Dimensions (m)

Weight

Frequency

Handling Equipment

Route to laydown area

kg

l

w

h

1000

2

2

3

Significant failure

Internal Gantry crane to equipment Pedestal crane from external door exit and trolley. Traverse load equipment door to vessel. external.

132 kV SF6 Gas Cart 400

1.5

0.8

1

Commissioning. 10 year Service

Integral trolley wheels inside equipment room. Pedestal crane from vessel

Protection Panel

0.8

0.8

2.2

Equipment Failure

Individual Components removed by For panel replacement, trolley to hand. Full panel replacement by laydown area. Pedestal crane to trolley vessel

0.15 0.6

0.4

Approx 7 years

Two person lift onto trolley from battery cubicle.

132 kV Switchgear

400

110 V DC battery (12 60 V monoblock)

Stored onshore. Loaded from vessel to equipment doors via pedestal crane.

Trolley from battery room to laydown area. Grouped into storage crate. Pedestal crane to vessel.

Table 4‐5. Example of material handling assessment The above assessment will provide an integration of lifting aids (for example pedestal and gantry cranes, pad‐eyes, trolleys) with the location and number of laydown areas required to suitably permit material handling on the offshore platform.

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4.5.4.4 Manual Handling As with work related tasks on an onshore substation, a clear understanding of the limitations of manual handling must be known. In general mechanical handling aids are required for all activities that require a lift / movement of components in excess of 25kg. This is shown in Figure 4‐4. One method of assessing work tasks is via the ‘TILE’ principle. This relates to consideration of: 1. T ‐ Task involved 2. I ‐ Individual/s involved in task 3. L ‐ Load to be moved 4. E ‐ Environment in which the operation will be conducted. The ‘Task’, ‘Individual’ and ‘Load’ are undertaken on an activity by activity basis with the significant difference on an offshore substation being the environment which the activity will be conducted. The introduction of additional equipment or the movement of equipment to an alterative location for loading / lifting does not have the flexibility in an offshore substation.

Figure 4‐4. Individual handling weights 4.5.4.5 Material Handling Aids To assist with material handling a number of handling aids can be used. These include: (i) Padeyes. For lifting specific items of equipment the padeyes can be included welded or bolted to primary or secondary members and designed for a specific Safe Working Limit (SWL). Access is required in order to fit the portable rigging equipment required to conduct the lifting activity. (ii) Gantry Crane. A permanent gantry crane can be provided for all routine maintenance lifting activities within a specific room. To date this is generally only provided for the HV switchgear. The crane will have a SWL suitable for all routine maintenance lifting activities on the equipment (typically around 1.5 tonnes) and a range of travel/motion consistent with the foreseen lifting activities. A chain hoist can be suspended from a moveable gantry beam to access all components of the switchgear and provide a straight lift. Given the infrequent use of this crane it may be acceptable to provide a manual hoist/manual travel device. 225

(iii)

(iv)

A dropped object analysis should be carried out for the switchgear room to pre‐ determine the consequences of damage resulting from this un‐planned event. Pedestal Cranes. The design consideration of the pedestal crane is of great importance. As this crane would be used to lift loads directly from a vessel it must be rated for use in an agreed sea state. This sea state will vary dependent upon where the platform is located and under which significant sea state it is practicable to lift in. This crane may be called upon to lower a stretcher casualty to a service vessel and as such would need to be rated for this man‐riding emergency descent. This is covered in more detail in the Section 4.2. Davit and Davit Crane There are numerous techniques available for lowering life‐ rafts from the platform to water level and one of the most common is the davit lowered design. This davit would be designed for the liferaft duty but it could be adapted to provide an anchorage point for man‐riding emergency descent. For this evacuation technique the receiving vessel would not be moored at the boat landing but would be held in position by the master. Rather than constantly use the main pedestal crane to access the deck of a transfer vessel moored against the fender system of the boat landing it may be practical to locate a davit crane on the platform suitably positioned to access the vessel. This davit crane can be utilized to lift relatively small packages, tool‐bags etc direct to the platform. Typically this davit crane would have a rating around 1.0 Tonne and be suitable for use in the specified sea state. Davit cranes are now available for the offshore environment, which provide features making them more flexible for regular use, typically: ▪ Worm driven manual slew mechanism for rotation ▪ Low voltage pendant or radio controlled hoist unit ▪ Suitability for man‐riding emergency descent (to BS EN 50308) ▪ Safety systems inclusive of manual and automatic overload protection systems ▪ Testing and Certification to European Standards

Figure 4‐5. Example of Davit crane 4.5.4.6 Pedestal Crane In general the pedestal crane will undertake two functions, (i) for the loading and unloading of the supply vessel in accordance with design standards, for example BS EN 13852‐1 2004, and 226

(ii)

transferring equipment and supplies from the laydown area to areas inboard, for example the Lloyds Register of Shipping code for Lifting Applications in a Marine Environment, 2003. A range of pedestal cranes are available which include (i) fixed boom, (ii) knuckle boom, (iii) telescopic boom.

Figure 4‐6. Fixed Boom Figure 4‐7. Knuckle Boom The layout of the platform must consider the reach and capacity of the crane, coupled to any restriction in crane travel imposed on the platform structure or equipment heights. Consideration should also be given to moving routes from equipment areas to laydown areas, and from laydown areas to below support vessels. If an object is dropped from the crane this event can have significant impact if the ‘drop’ is directly above equipment or areas where critical equipment is contained. Protection of exposed equipment or enhanced protection can be considered. As noted above, the crane(s) should be designed to be able to reach all areas of the substation and lift the heaviest item deemed necessary within the manual handling philosophy. For example this will typically exclude the lift of the main power transformer but may include the auxiliary transformer. Consideration that the Safe Working Limit (SWL) decreases as the load distance from the crane fixing point increases must also be taken into account. The range of crane manufacturers and type available provide a range not suitable for inclusion in this document. However an example of de‐rating can be the capacity of 30 tonnes at 6 meters to 5.5 tonnes at 24 meters. As the crane would be used to lift loads directly from a vessel it should be designed for lifting in a specified sea state, typically sea state 3. Lifting in this sea state would also apply a de‐rating factor to the SWL of the crane. The use of the Douglas Sea Scale to specify sea conditions is discussed further in sections 4.2.1. and 4.3.2. For multi‐level platforms the use of equipment hatches provide access to lower deck levels but must be coordinated such that the pedestal crane can access the hatch location and the hatch be of a suitable size to allow the equipment to be vertically removed. This includes the ability to lift cable winches to and from lower decks which can be required if the array and export cables are not installed prior to the topside being installed offshore. The location of the boat loading location in relation to the pivot range of the crane(s) must be taken into account. This will ensure that items can be lowered from the topside to the vessels. A design consideration is to ensure that there are no power cables laid directly below the transfer area where possible damage could occur from swinging or dropped loads. 227

As discussed in section 4.2.3, this crane may be used for man‐riding emergency descent. This design feature would need to be specified at the time of ordering. 4.5.4.7 Portable Devices To assist with the movement of equipment around the platform and to laydown area typical items are: (i) Trolleys, (ii) Specific equipment trucks / wheels, (iii) Pallet lifters, (iv) Chainblocks, pull lifts, lifting tackle. The above are useful for small loads and as they are portable can be utilised in all areas of the platform. To achieve this equipment must be able to traverse the deck plate and for grated areas the wheel size must be such to allow easy movement over the grating. The use of steel plate or boards can be laid on top of the grating in order to allow the lifting device (and load) to be wheeled however the route to be travelled must be considered as a significant route could require to be covered, or covers transposed along the route. An example of a 36 kV trolley onshore is shown below, however offshore this wheel size will present difficulties over grated walkways. It should be considered that some of these devised may not be practical to move between decks unless there is an elevator. Moreover, fork lifts or the like may need a charging station if powered by batteries.

Figure 4‐8. Example of Installation Trolley 4.5.4.8 Decommissioning The material handling at the end of the project life will follow a reversal of the installation procedure. For example if the substation is loaded to sea as a complete unit it is likely, subject to condition assessment, to be returned to shore as a complete unit.

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4.5.4.9 Storage Areas The storage areas required on an offshore platform requires an early philosophy to be developed on the materials that should be stored on the platform and those which will be carried to the platform by transportation vessel as, and when, required. Input to ascertain this information will come from the maintenance programme including the frequency of activity and equipment required to perform the task. The cost of the offshore platform in relation to the size and the importance of optimisation of the layout is obvious. Storage of equipment, tools and spares may have a significant impact on this as, although storage offshore minimises the issues associated with transportation, the cost of the platform can easily escalate if storage is not considered. The reverse can also be true whereby storage requirements are ignored and the operation cost escalates if equipment is not available offshore. As with an onshore substation, the positioning of the storage area must follow a risk based approach and ensure the segregation of high risk areas to hazardous materials. This includes the transfer of personnel to and from the offshore platform with consideration of the access routes (by boat or helicopter) used. 4.5.4.9.1 Typical Equipment Stored Onshore Larger items and Strategic Spares are typically expected to be stored at the onshore location primarily on the basis that (i) these are required infrequently, (ii) are only required as a result of significant failure of equipment, (iii) they carry a long lead time and (iv) will require a large storage area which has significant impact on platform layout, size and cost. The items could include power transformer, auxiliary transformer, and switchgear components. 4.5.4.9.2 Typical Items Stored Offshore The equipment to be stored offshore is centred around equipment which is required to allow operators to perform routine tasks and maintenance. In addition, any safety critical tasks must be able to be performed offshore without the requirement for the helicopter or vessel to return to shore for the necessary part or equipment. (i) Operating handles and equipment specific tools. Switchgear will feature a number of operating handles to allow for manual operation. These must be stored offshore and typically close to the equipment. (ii) Trolleys. To allow for the movement of equipment around a substation platform, either to perform replacement or to a laydown area will require the use of equipment trolleys. Consideration must be given to the frequency of event against the space required for storage. (iii) Lifting Frames. Mechanical aids which allow for the removal of equipment components can be stored offshore. For example for racking out circuit breakers, removal of UPS and battery systems at height, or the replacement of HVAC units. Where possible consideration should be given to utilising a single unit for multiple tasks and hence reduction in the number required. (iv) SF6 gas handling truck. A gas handling truck to allow the SF6 gas to be ‘captured’ if removed from the switchgear. The size of the handling truck can vary from a smaller unit, capable of top‐up and capture, to larger units which can be used for maintenance through air extraction, filling times and gas volume handling. (v) Fire Suppression Water/Inert Gas. The fire suppression of the platform may incorporate a water mist system for the power transformers. This system will 229

(vi)

(vii)

(viii)

(ix)

(x)

(xi)

commonly require storage in the form of a number of pressurised water and gas cylinders to provide the extinguishing medium. Consideration of this storage area must take into account that once operated the cylinders (in excess of 100 kg when full) will require to be replaced and that the cylinders are pressure vessels (in excess of 40 bar pressure). Transformer oil bund dump tank. In the event of a mineral oil filled transformer failure the recognised onshore philosophy must remain where the oil must be captured to prevent impact to the environment. To also minimise fire risk the transformer oil is normally drained to a ‘dump’ tank rather than remain within a bunded area. To achieve a rapid emptying of the bund the dump tank will be located such that oil drain is gravity fed and sized to capture in excess of the full oil content of a single or multiple units dependent upon the risk assessment results and/or client specification. This oil should be stored until mechanisms are in place to remove the contents to shore. Transformer bund rain water tank. In the situation that the power transformers are located outdoors any rainwater in contact with the unit must be assessed for oil content. An option exists to capture this rainwater in a storage tank with transportation to shore at required intervals. Alternatively, an oil‐water separator can be used to capture the oil content and the uncontaminated water passed into the sea. This significantly reduces the volume stored offshore. Platform wash‐down storage. Due to the harsh environment the life of the platform can be assisted through the washing down of exposed items with ‘fresh’ water to reduce the salt content and corrosion. If a helicopter landing deck is fitted the removal and washing of bird excrement can be via stored wash down. The effectiveness of this should be assessed at the design stage as significant water storage could be required through the life of the project and associated transport requirements. The issue of stagnant water and bacteria must also be considered. Spares and Workshop. Within the offshore platform an area will be assigned to perform minor repair functions. This could be within a combined store and workshop area. A wide range of spares could be stored on the offshore platform to undertake ‘simple’ repairs to equipment. The purpose of this document is not to provide an exhaustive list as this extent will be dependent upon the equipment installed and the maintenance arrangements. Typical examples of equipment which could be stored include transducers, test blocks, protection relays, local/remote switches, push buttons, lamps, resistors, push buttons, fuses and links, and terminal blocks. Platform Welfare. Suitable dry storage may be required for food, blankets etc associated with the platform welfare facilities. The extent of the storage will be dependent upon the status of the facility (manned or unmanned) and the number of people to be catered for together with the planned duration of their stay. An unmanned platform will require considerably less storage areas for food and water, drying areas, food preparation, survival suits etc than a manned platform. Design and Operation Documentation. In addition to the above, documentation must be available offshore to allow operators access to equipment instructions

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and details. This may take the form of electronic information with supporting hard copies of key systems. 4.5.4.9.3 Hazardous Substances On the offshore platform a number of hazardous substances can be expected to be present. It should be noted that in general the substances will be contained within the equipment and storage would only be required for additional ‘top‐up’ or where quick replacement is required, for example fire suppression system. In accordance with published guidelines hazardous substances should be removed in order not to endanger health or safety of persons on the installation. This includes that the storage of hazardous substances is segregated at a safe distance from areas which feature a high occupancy rate (for example accommodation areas and control rooms). Similarly, for fuel storage the area should be designated in a location remote from occupied areas, escape routes and sources of ignition. The below would require to be listed on an inventory of hazardous material (carrying out a COSHH assessment) and require consideration for storage. (i) Switchgear Insulation Gas (GIS): SF6. The insulating gas is contained within the switchgear and separate storage bottles could be stored. All SF6 switchgear is designed for long intervals periods. SF6 gas should not require ‘top‐up’ as this indicates a problem with the equipment if the gas levels are dropping. (ii) Auxiliary Generator: Diesel. The generator will require a fuel storage tank of sufficient capacity to maintain the designed running time. This can be achieved through an integral fuel tank within the generator unit or a separate fuel tank. (iii) Fire Suppression Gas: (for example FM200, IG‐55, Inergen). The equipment and storage rooms will typically be protected through an inert gas fire suppression system. This can be achieved through a centralised system (i.e. where a number of cylinders are grouped together to then feed the protected areas) or de‐ centralised (where fire cylinders are located in the room to be protected). (iv) Transformers: oil (mineral or synthetic). The power transformer (i.e. 132 /33 kV) and reactors (if fitted) will typically contain oil as the insulating medium. The auxiliary transformers may also feature oil if cast‐resin is not used. In general the top‐up of transformer oil is not a frequent task and drop in oil level indicates a fault with the unit. (v) Battery systems: The dc power supply to provide supplies to the LVDC systems will require storage batteries. These can be Plante cells, Valve Regulated Sealed Lead Acid, or Nickel – Cadmium. The replacement of a battery, or bank of batteries, is generally a planned activity and therefore may not be stored offshore. (vi) Diesel engine consumables: Lubricating Oil, Hydraulic oil, Engine Coolant (i.e. Ethylene Glycol). The stand‐by auxiliary generator contains a number substances which are required due to the mechanical moving part nature of the equipment. The volume stored will depend upon the operating hours run and service intervals required. (vii) Welfare Facilities: The welfare facilities on the platform by recognised design will not feature hazardous substances. However the chemical toilet, if fitted, will require to be handled and maintained. The philosophy may utilise the take out

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(viii)

and removal of the facility with each visit. Alternatively additional chemicals could be stored offshore for replacement subject to usage. Aviation Fuel: As the offshore platforms become more remote from the shore there may be a requirement to store aviation fuel on the platform. Storage of aviation fuel on the platform introduces an extreme hazard and has to be evaluated carefully. In the offshore oil & gas industry, aviation fuel storage is only used in a few locations, e.g. due to the remoteness of the installation. There are no requirements to have spare fuel on the platform, but once introduced, there are a range of safety regulations to be complied with, e.g. related to zoning, fire and explosion protection.

4.5.4.9.4 Extended Storage In addition to the above, the operational philosophy of the overall wind power plant must be taken into account. The basic substation function is continually expanding and may be required to include additional functions within the storage areas in addition to the AC substation platform. This is not included within the scope of this document and may require consideration for larger projects where the below are expected to feature. These can include: (i) maintenance base for the entire wind power plant including the wind turbines, (ii) maintenance base for a number of wind power plants including a number of ac substation and wind turbines, (iii) permanent accommodation,

4.5.5

Primary Access and Egress systems

An offshore substation needs to be accessed from time to time by persons for routine or breakdown inspections and maintenance. Large platforms far away from the shore may be permanently manned and thereby requiring more frequent access. During the construction, commissioning and run‐in periods daily transfers are not uncommon. Basic means of transport and access include helicopters and vessels. As of 2011, boat fendering is still a commonly used method of access, while helicopters are becoming an interesting option with increasing distance to the shore. For emergency response reasons it is important that the access system used on the offshore substation is compatible with that used for the wind turbines, even if just as a backup. Access to and egress from the offshore installation is generally perceived as the highest risk to people involved in an offshore wind power plant. Hazard identification and risk analysis can provide designers with useful information for the design process (see Section 1.) Some issues are covered by applicable design standards while others need to be addressed case‐by‐case. A thorough analysis will identify hazards and potential safeguards. With risks being lowered as much as practicable, the onshore (and possibly offshore) operations team(s) will assess the risks for every planned transfer. On approach, the pilot (helicopter) and captain (vessel) have the ultimate decision to go ahead with the transfer or not. 4.5.5.1 Helicopter Deck Helicopter transfers of personnel are becoming more and more accepted as a means of transportation in offshore wind power plants. The offshore substation may be equipped with a helicopter deck onto which a helicopter can land. As a minimum, the platform should 232

have a heli‐hoist area onto which personnel can be lowered or from which they can be winched up. Local requirements exist in most countries, but standard CAP 437 is an internationally applied guidance document. Helicopter decks and heli‐hoist decks used for transfer of personnel and cargo by helicopter must be fit for purpose. Decks have to be located with a view to minimising hazards from obstructions, turbulence or vents, whilst providing a good approach path during prevailing weather conditions. The helicopter should not be required to cross the platform during such approaches. For transport by helicopter the prevailing wind patterns need to be considered and the helideck positioned so that the helicopter approach for landing is into the wind. Data relating to wind speeds, direction and time frequency should be collected to assist with determination of the optimum positioning of the helideck. This information is often displayed graphically in the form of a wind rose. The location of the helideck on the platform must also consider the position of any heat sources such as diesel generators, transformer cooler fans etc. Specifically, helicopter decks should ▪ be placed at or above the highest point of the main structure ▪ be preferably located in a corner of the installation with as large overhang as possible ▪ have an obstacle free approach and take‐off sector with 210° / 1,000 m being normally required ▪ be reachable by the installation’s main crane ▪ have an air gap under the deck encouraging a relatively linear and clean air flow ▪ have a minimum of 2 access/egress routes ▪ be located above accommodation or emergency shelter area to guarantee shortest escape times ▪ conform with local requirements regarding equipment, marking and lighting Specific concerns in wind power plants include the turbulence caused by multi‐turbine wake effects; a potential requirement to shut‐down adjacent turbines to allow safe helicopter transfer; grounding of the helicopter to avoid electric shock during winching; low visibility/fog flying limits and “good prospect of recovery” for helicopter passengers and crew in the event of ditching in the wind power plant as well as worsening weather conditions preventing recovery of maintenance technicians. The helicopter deck size and strength depends on the helicopter(s) which will use it. Helicopters are characterised by a dimensional “D” value and their weight which serve as input for the structural design of the deck. Common D values for helicopters used in offshore service range from 12 m to 23 m and the weights range from 2.4 tons to well above 10 tons. The helicopter deck adds significant weight to the topside structure, therefore the deck should not be oversized without reason. Refuelling facilities are used on some far offshore oil & gas installations but, to date, not on any offshore substation. Introducing refuelling facilities has a massive impact on zoning, fire fighting, etc. and should be avoided where possible. Helicopter decks require fire fighting equipment with foam‐based deck integrated fire fighting systems (DIFFS) being very common. Commissioning activities related to the helicopter deck include a test of the lighting and the fire fighting system. The

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latter may have to be carried out offshore as such test may not be allowed in the construction yard / onshore. While helicopter decks are highly regulated, little guidance exists for heli‐hoist areas. CAP 437 provides only some guidance. Consequently, some current designs do not facilitate emergency operations. Generally, winching should not be used as a normal means of transfer (but rather for emergency purposes). The main difficulty in wind power plant maintenance is hovering for some 2.5 minutes when lowering one technician carrying tools onto the heli‐hoist area. Besides few limitations to helicopter operation, a design criterion for heli‐hoist areas should be whether a stretcher casualty can easily be brought to the winching area. Helicopter operations require that communication is established between helicopter and substation. Some maintenance has to be planned for the helicopter deck. Bird fouling can be a serious problem and regular cleaning may be required. Consideration should be given to a deck wash system, possibly part of the overall deck cleaning arrangement. 4.5.5.2 Boat Landing Offshore installations allow access by vessel in more or less sophisticated ways. The most basic approach for a boat landing is a ladder with impact protection bars which allows the vessel fenders to contact impact bars and personnel to step from the vessel directly onto the ladder. In more exposed locations the boat landings could be supplemented by docking systems which are used on oil & gas platforms. Motion compensated gangway systems are also being introduced. An alternative used in oil & gas are crane lifted personnel carriers. Together with the vessel, all marine access systems have a limit regarding the sea states they can operate in, including wave height, wave direction and currents. Facilities themselves must be maintained to avoid fatigue and coating failure. The design of the transfer vessel should be considered by the substructure designer as it will influence the geometry of the fender system and the “step” distance from the vessel foredeck to the vertical access ladder on the substructure. Marine access systems using the fendering technique have a maximum safe wave height operating limit taking account of vessel motion, thrust and fender friction. Boat landing can normally be used only to 1.2 or 1.5 m significant wave height for single hull vessels. Transfers from catamarans may be possible at higher significant wave heights. SWATH (small waterplane area twin hull) vessels have very high stability in extreme sea states, but they are also much heavier, which can require a stronger platform substructure. For the orientation of the fendering system it is important to consider the dominant current and wave (swell) directions as the boat landing may not be usable when the currents or waves are more than 30° off the bow or stern as the boat may not be able to lock itself in place. In areas with strong tidal currents, these determine the orientation while waves have a secondary effect. In order to maximise opportunities for transfer, there may be more than one boat landing (e.g. two) spaced around the foundation in positions that are found to be most suitable from current and wave studies. Preferably, no J‐ or I‐ tubes for the cables should be positioned where fendering takes place. Alternatively (e.g. on monopiles), the system must be designed so that the chance of damaging the tubes during access operations is as low as reasonably practicable. The maximum vessel size (e.g. 4 ton limit) and approach speed should be clearly marked on the leg. Many designs incorporate a fall arrest system a person can attach to when transferring and climbing up or down the ladder. The technician stepping over between vessel and 234

ladder must always be supported by trained vessel crew. Site‐specific procedures will specify that a technician should only transfer if he / she feels safe to do so. Opinions are divided on whether people transferring are allowed to carry any tools or equipment when stepping over. One or more davit cranes are standard on platform installations. These can be used to transfer any cargo, light or heavy. Sea‐state limitations, however, apply for the use of davits as well and care has to be taken not to overload the crane due to vessel movement (snag load) or create a hazard through swinging loads. Gangway systems (e.g. ‘Ampelmann’) are now being used on some oil & gas installations, increasing the access window to a significant wave height of 3 m. Some systems require a locking pin on the platform installation while a heave compensating gangway is located on the vessel which is equipped with a dynamic positioning (DP) system. This implies larger vessels compared to the transfer boats used in today’s near‐shore wind power plants. However, access using such systems is deemed to be safer than the fendering technique and is expected to become more common in offshore wind applications. 4.5.5.3 Ladder Access / Egress Systems Ladders and access platforms should conform to relevant Standards applicable to the location of the platform, however, some general guidelines are detailed below: Ladders should be positioned to suit optimum wind and tidal conditions. Where ladders extend more than nine metres from the mean sea level a rest platform should be fitted (this distance can vary dependant upon local Standards). Ladders should be fitted with a fall arrest system (ideally same system throughout the wind power plant). Ladder rungs should be square with an edge facing upwards. Consideration should be given to recovery of a suspended person from the ladder.

4.5.6

Emergency Response

Emergency response in connection with offshore substations is the sum of efforts by persons and systems to mitigate the impact of an incident on human life (workers, public), the (marine) environment and property (the offshore substation asset and associated equipment such as means of transport). Hazard identification and risk analysis (HAZID) can provide designers with important information for the design process. Instead of adding solutions at the very last design stage, consideration at an early stage will generally lead to more fit‐for‐purpose and cost effective solutions. A thorough analysis will identify hazards such as man over board, loss of primary escape route, loss of escape route back to shore and lack of signage of escape route. A suitable tool to evaluate emergency response is an Escape, Evacuation and Rescue Analysis (EERA) as described in ISO 17776. It is a technique to “evaluate the performance of the emergency response facilities and procedures ... and consists of a structured review of the performance of the escape, evacuation and rescue facilities and procedures in representative scenarios”. From the hazards and the risks identified in the HAZID scenarios should be selected for further analysis. The facilities and procedures addressed commonly include: ▪ Hazard detection and alarm procedure ▪ Escape routes (including bridge links) 235

▪ Mustering and temporary safe areas ▪ Evacuation procedure and facilities e.g. helicopters, life boats, life rafts, and other rescue arrangements such as stand‐by and other vessels ▪ Man over board rescue The various systems are assessed regarding their adequacy, availability and survivability in the chosen emergency situation scenarios. Redundancy of systems is taken into account. When using qualitative analysis, the shortcomings can be identified and improvements can be implemented. For instance, a smoke‐ingress analysis is frequently carried out to ensure that a temporary refuge can remain smoke‐free for an adequate period in the case of a fire. A cost‐benefit analysis can show the viability of any proposed improvement. Simple and unambiguous communication and alarm systems must be provided to alert all persons on the installation, at any location, of an emergency. External communication arrangements and systems should remain effective in an emergency. With electrical isolation of the substation certain functions must remain available on the platform for some time. In general, the uninterruptible power supplies should be capable of e.g. 1 hour of continuous operation. Certain features like navigation aids should be powered for longer periods as determined by local regulations or the safety assessment. Safe, direct and unobstructed exits, access, and escape routes must be provided from all normally manned areas of the installation to muster areas and embarkation or evacuation points. When an installation is unmanned, such escape routes must still be available for all those areas where maintenance personnel may be in case of an emergency. Muster areas must be located close to the embarkation stations (or helicopter deck / helihoist area) with direct and ready access to survival craft or other life saving appliances to enable a safe and efficient evacuation or escape from the installation if required. A primary muster area should provide protection from hazards to allow controlled muster, emergency assessment, incident evaluation, and implementation of control emergency procedures and evacuation. The primary muster area should be provided with adequate command communication facilities to address an emergency and organise safe evacuation if necessary. Such an area should be suitably arranged for persons to don PPE and to enable movement of stretchers. Muster areas, embarkation areas, launching arrangements and the sea below life saving appliances must be adequately illuminated by emergency lighting. To the extent necessary, arrangements must be made for provisions on the offshore substation (or with suitable persons beyond) which will ensure, as far as is reasonably practicable, the safe evacuation of all persons and transfer to a place of safety. All offshore substations should have at least one launchable life raft which can take the maximum number of persons on the installation. Various types are in use, e.g. davit‐launchable (rigid or inflatable), free‐fall, and additional, self‐inflating rafts. When choosing the location of the life raft(s) or boat(s), prevailing winds, waves and tidal currents must be taken into consideration (i.e. to have a high likelihood of moving the raft / boat away from the platform). The potential of a stretcher casualty has to be given particular attention, i.e. such a stretcher must be recoverable by helicopter or, for transfer to a vessel, a crane with “man‐ riding capability” is required Arrangements should be made to rescue persons from the sea or near the installation such as persons falling overboard or being involved in a helicopter incident. Such arrangements include rescue facilities on the installation, e.g. fast rescue or man‐overboard craft as well as facilities and external to the installation, e.g. vessels and public sector and commercially provided search services. 236

Common types of liferaft and means of lowering them to the sea are: • Self‐inflating liferaft – Davit‐launched This design of liferaft would be stored in a container on deck and be connected to the davit, inflated, boarded and then lowered to the water level • Self‐inflating – Throw‐overboard This design of liferaft would be stored in a container on deck and would inflate in the water when the painter line is pulled. A descent system would be required to lower the people to the water level/liferaft. • Enclosed, rigid boat or totally enclosed motor propelled survival craft (TEMPSC) The rigid boat would normally be suspended over the side of the deck and lowered to the water level via davits, whilst a TEMPSC could be “drop” launched free fall or “skid” launched free fall. As the inflatable designs of liferaft do not have any power the location on the platform should be selected with due cognizance to the prevailing winds and tidal patterns such that the craft when launched will be naturally carried away from the structure. Muster areas should be suitably sized for the planned maximum number of people likely to be on the platform (SOLAS, Chapter III, Regulation 25 recommends a minimum of 0.35m2 per person)

4.5.7

Platform Auxiliary Systems

The platform auxiliary systems are defined as all the secondary systems (in opposite to the primary which is the MV and HV systems) that are required to safety operate the platform. Examples of these are: ▪ Auxiliary Power Supply including Diesel Generator, LV, MV, batteries, converters and switchboards ▪ Lighting and small power ▪ Earthing and Lightning protection ▪ Heat, Ventilation and Air Conditioning system ▪ Submersible pumps and heat exchangers ▪ Water handling; fresh water, sea water ▪ Drainage system; Black water, grey water ▪ Oil containment; bunded areas and dump/sump tanks ▪ Oil / water separation ▪ Fire Detection and fire fighting systems ▪ Navigational Lights and day identification ▪ Aeronautical systems ▪ Fuelling systems ▪ Water Jet to clean the decks ▪ Crane ▪ Life boat / rafts ▪ Public Address (PA) system

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4.5.7.1 Diesel Generators The inclusion of the standby generator on the platform is a key design consideration and must consider a number of different scenarios. A standby generator would be used to provide longer duration power supply to the auxiliary systems on the platform. This occurs in the scenario when there is no wind generation and/or a supply from shore is lost. The standby generator should not be confused with battery and UPS systems which provide a secure supply but limited in energy storage durations. The rating of a standby generator will depend upon a number of factors. These are covered briefly below. Platform Auxiliary Supply Section 5 provides comprehensive details on the LV loads which will require to be supported on the platform. This ranges from platform lighting to safety critical systems. On the loss of generator or connection to shore (i.e. the export cable) the standby generator will be required to support the platform load. Usually the fire water pump or the platform crane will set the maximum design limit for of the Diesel Generator. The LV (typically 400 V) system design, the seawater pump design, and the Diesel Generator system are primary auxiliary designs. In general the standby generation will commence on the loss of the LV supply and consideration must be given to the size of the generator (kVA / MVA rating) and also the size of the fuel tank required. The size of the fuel tank must reflect the duration with which the standby generator could be expected to operate before supplies are restored or would be acceptable to re‐fill the fuel tank. An over‐sizing of the generator and its fuel storage will have an immediate impact on the physical platform area required. In addition, if the generator capability significantly exceeds the load this will have a negative operational impact as generators do not operate efficiently and may be damaged when lightly loaded. Wind Turbine auxiliary supply In the scenario where the connection to shore is lost the platform design may also consider the auxiliary supply to the wind turbines. Wind turbines may not be able to suitably operate if there is no auxiliary supply available over a long period of time. This power can be provided by a number of different sources, including via a small diesel‐ generator housed in each turbine. However the amount of diesel fuel which can be stored in the turbine and the practicalities of refuelling each turbine diesel tank, especially in case of severe weather conditions, would need to be evaluated. An alternative to an individual visit to each wind turbine may result in a strategy where a centralized supply is preferred. This could be achieved through a standby generator set (gen‐set) on the platform. Such an approach may also provide advantages for the maintenance activities associated with the gen‐set as well as for the cyclical exchange of aged diesel fuel. Provided that the Gen‐sets for both the platform and the wind turbines, henceforth called the loads, are located on the platform two alternative solutions can be explored. Either a solution with a common gen‐set for both loads, or two separate gen‐sets each rated for its purpose. There is also a third option, i.e. to go for a permanent installed generator for the platform and make provisions for a re‐locatable standby generator for the wind turbines that can be installed with limited efforts should a longer outage occur.

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To define the power of the gen‐sets the consumption of the wind turbines must be known, typically the different auxiliary modes of the turbines which are possible. It is known that the maximum power consumption occurs during the yawing of the turbine. To economically size the gen‐sets the wind power plant control system should ensure sequential yawing of the turbines when running on the auxiliary supply source. This sequence must be coordinated with the turbines ability to withstand stormy winds for a certain time. Depending on the construction and the operational strategy of the platform the total power of a typical wind power plant consisting of about 80 WGT’s (of 5‐MW size) can be in range of 2 to 4 MW. Generator set sizing Network studies should be carried out to find the optimum solution for such a large cable network which features a number of transformers connected and fed by a comparably small apparent power of the gen‐sets. Initially load flow studies will assess the power required to compensate for the capacitive reactive power of the cable network. This can typically be in the range of 7 to 10 MVar. The studies will assess the stability of the grid under all load flow situations. An option to energise the whole array cable network is to only energise one array string (feeder) at a time. The will significantly reduce the requirements on the gen‐sets. As noted earlier, where a centralized supply of auxiliary power is deployed, it is essential to supply the wind turbines on a N‐1‐principle design (e.g. the number of gen‐sets should be chosen based on the N‐1‐principle). This is a requirement as maintenance requirements increase with the running hours of the gen‐sets and over a long running period the system will require to be able to cope with the outage of one of the gen‐sets. The partial outage of the equipment for reactive power compensation must be considered as well. The short circuit level must also be observed when the gen‐sets are operating on the LV‐ busbar. This is important if parallel operation of the gen‐sets is possible or if a gen‐set is operating in parallel to the power grid (e.g. when the gen‐set have to be tested regularly (e.g. monthly) under load conditions). If parallel operation is required the gen‐sets will require to include measures to achieve synchronization and load balancing. Alternatively the gen‐set can be exercised against a load bank which does not require synchronizing to the electricity network. 4.5.7.2 Inert Gas System. SF6 Gas Detection Inert gas on the platform can be used as fire fighting of fire from electrical component failure. The inert gas will displace the air in the room and is therefore hazardous to humans in confined spaces. There are codes and standards for these systems, which gives guidance and requirement for the inert gas system. The systems require a separate inert gas room, a distribution system and detection and release control. The fire zone division on the platform determines what rooms' sizes are required for the inert gas system capacity limit. SF6 is commonly used in the Gas Insulated Switchgear, a control system will give an alarm or inhibit switching, if the internal SF6 gas pressure gets below a certain limit. If there is a SF6 leak, gas detection equipment may be required to avoid persons entering the room when gas has been detected.

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4.5.7.3 Electrical Design i.e. Lighting and Small Power The general platform lighting should be switched on when the platform is manned during visits, with on/off push buttons lighting control and indication lamp for switching off the lighting placed at the boat landing and on the Heli‐deck (and possibility of remotely control) Luminaries and floodlights should either be supplied from the normal power supply with UPS supplied power for evacuation lights in emergency situations or when normal power supply is down. Power supply for indoor socket outlet rated at normal domestic power on land. Power supply for outdoor socket outlet assemblies is higher voltage (for example 400VAC), these sockets should be used for maintenance equipment on the platform. The electrical design issues are covered in detail in section 5. 4.5.7.4 Lightning Protection for the Platform The lightning protection of the platform, dimensioning and protection, is proposed to follow the instructions in code EN/IEC 61024. (Class 1). The metallic structures on the platform are used as both air termination system and down conductors. 4.5.7.5 Earthing and Bonding On the platform it is necessary that all exposed and extraneous conductive parts of the electrical installations should be earthed, and metal parts of the structures should be bonded to the main earthing system for safety and for protection against electric shock. Further should the metallic structures all around on the platform be bonded if they do not have safe connection to the other neighbouring parts of structure. The earthing and bonding should be made according to the platform earthing philosophy, which is discussed in Section 2 and will form the basis for design of the system. Earthing systems that may function well on a conventional oil and gas installation may not be suitable for a transformer platform. It is also important to consider the interrelation with the corrosion protection system during the earthing system design. 4.5.7.6 Ventilation and HVAC The main objective of the HVAC system is to provide a controlled environment to safeguard the platform equipment against corrosion, humidity, cold and heat. Furthermore it should also provide comfort for personnel onboard. A slight overpressure inside the room can be used, to reduce the concentration of saltwater aerosols, and dust from outside. The overpressure design is used on oil & gas platforms to prevent gas from entering the room. Hence, it may not be required on a transformer platform for safety reasons but assists in limiting corrosion effects on electrical equipment. The HVAC system can consist of independent AC units, centralized system or a mix with two or more area HVAC units combined with electrical heaters. Heating can alternatively be provided by local heaters on the wall. The unit(s) may be split in two, with an air Handling Unit placed in a HVAC room and a Condensing Unit placed on the deck outside. It is not recommended to have a water cooled condenser on the platform. The HVAC channel system design has consequences on other systems when it penetrates the walls. The penetrations in the wall can connect the room space in two different fire zones. The HVAC system openings may therefore be fitted with fire dampers that close in case of a fire, or if an inert gas system is released. A fire damper system is often a 240

comprehensive system, both controls and the mechanical parts. The channel system should be able to withstand a release of inert gas, and react correctly in case of pressure increase from the GIS. Monitoring of the HVAC status and individual important room temperature is recommended. Status monitoring should target a failure beyond a "General System failure" indication, for example filter block and cooling circuit failure. With remotely set point adjustments one can avoid unnecessary visits offshore. HVAC material selection is important to reduce maintenance of the mechanical parts as well as small electrical components. Equipment suitable for high temperature could be an economical solution, to reduce capacity of cooling and risk if it is lost. The following equipment/rooms are recommended to be climate controlled: ▪ 36 kV (from the wind power plant) switchgear rooms ▪ LV Switch panels ▪ Emergency shelter rooms ▪ SCADA rooms ▪ HVAC unit rooms. ▪ Workshop and storage room. ▪ Kitchen and staff room. ▪ Emergency switchgear room. ▪ Diesel generator room. ▪ Battery rooms, with separate exhaust Rooms/ areas that can be natural ventilated: ▪ Main transformer ▪ Auxiliary transformer ▪ Reactor ▪ Water handling; fresh water, sea water ▪ Gas insulated switchgear (GIS) room. 4.5.7.7 Water Handling, Sea and Fresh Water The potable water system may be solved with a dedicated desalination plant. As such a plant requires regular maintenance, water may be chosen to be "carry on” when there are limited number of personnel onboard at any one time, or if ships with water supply always on standby. It is important that a safety shower is installed near the rooms containing acid batteries. The value of a pump and piping systems will have to outweigh the cost of complexity with pumps and piping. All water supplies should be kept free from fouling /bacteria growth. Fresh water quality for toilets and sinks/showers, and miscellaneous cleaning purposes is usually not suitable as drinking water and must be separate systems, or as mentioned contained locally without a piping distribution system. Sea water for fire fighting or wash down purposes (helicopter deck or oil drain) requires heavy duty pumps and costly piping systems. The design of this system has an impact on all main cable routing and on the platform as such. Hence, a proper specification and design is crucial, and will have consequences on the LV distribution system and the Diesel Generator capacity.

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4.5.7.8 Drainage for Grey and Black Water Drain from toilets and sinks/showers should be directed overboard to the sea or a sewage treatment unit according to the legislation in the area. The option for overboard dumping of waste for small vessels and commercial ships is regulated by Marpol rules. Marpol rules are recommended as a minimum where no national rules apply. Chemical toilet types are options but only low maintenance types similar to WC is recommended. The system should be designed to comply with the regulations, (usually a grinder will be required for grey waste water). 4.5.7.9 Auxiliary Systems Control and Monitoring The auxiliary systems should be equipped with level transmitters and level gauges and necessary valves for operation and maintenance. The safety system (firewater supply pump) or primary systems (cooling system pumps) should be monitored by the SCADA system. For the oil separator it is recommended to include; evaluate level switches for high and low level alarm and oil content alarm. 4.5.7.10 Public Address, Navigation & Aviation Aids, SCADA, UPS, Fire Detection & Alarm Fire safety systems are described in this section while the detection & alarm is discussed in section 5 which also covers the public address, navigation Scada and UPS system. Aviation aids are required when helicopter platforms are installed. 4.5.7.11 Oil System and Containment – Separator Tank Diesel fuel oil system supply fuel oil to the Diesel Generator(s) Unit , and consist of a storage tank, a day tank (can be part of Diesel Gen. Unit) piping and pumps (if needed). The lubrication oil system consists of a tank and diesel motor feed piping. Bunkering of Diesel Generator fuel or lubrication oil is a comprehensive operation offshore, and needs to be thoroughly designed, with piping and bunkering station in connection with a boat landing area. The bunkering station should be designed with the right interface couplings and possibly hoses. Helicopter fuel systems are usually avoided as it constitutes a different more stringent safety regime. An open drain system for collection of drain water from deck drains and bunded areas on the platform will be needed. It is designed to collect oil spill from the diesel motors, crane hydraulics, the auxiliary transformers and the main transformers. It consists of drip trays or bunded areas below the equipment which collect the spill in headers and route it to the oil separation tank. The drain system and the oil separation tank should be designed for the maximum amount of oil spillage (for example 0 ‐ 2 l/sec) and a mix with water (rain, fire fighting water, foam, cleaning water) dependent on selected operation scenarios. Usually an overflow system caters for heavy rainfalls/deluge water flows. The legislation regime in the area will govern the allowable oil water separation requirements. (The maximum allowable oil content in the separated water is usually 15 ppm. governed by MARPOL rules). The disposal of oil should also be catered for in the design. The oil separator tank system should be prepared for cleaning and for oil and cleaning water transport to shore for disposal (for example transportable pump interface).

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4.5.8

Corrosion Protection System

4.5.8.1 General Corrosion is the disintegration of an engineered material (typically steel for substructure) into its constituent atoms due to chemical reactions with its surroundings. It means that if a construction is not protected, corrosion will occur. Generally an offshore substation is exposed to extreme environmental conditions which include saline and moist air, extreme winds and waves tearing on the surfaces of the structures (topside and substructure). As a result of this and to minimize maintenance for touch‐up painting or repair/replacement of structural parts, piping systems and components after long time wear and tear different types of corrosion protection can be used depending on structure/substation part in mind. 4.5.8.2 Topside For the topside, normally all exposed surfaces are protected by coating (paint) systems developed and thoroughly tested during many years in offshore oil and gas installations worldwide. Different types of coating systems are specified and coating procedures are described in several codes and standards, e.g. in the North Sea area where the NORSOK M‐ 501 is widely used. For specific building related items such as stair treads and walkway grating, HVAC ducting etc., galvanized products are normally used. Another approach to protect the topside is to select non‐corrosive materials resulting in virtually no maintenance at all throughout the lifetime of the substation. This may however be an expensive alternative. The non‐corrosive material solution can be used for external piping system and components (valves etc.) but can also be an adequate solution for external wall areas minimizing amount of coating at fabrication. An initial material and fabrication cost has to be weighted against annual maintenance. Another alternative could be to use a design with a corrosion allowance corresponding to the installations design lifetime. However, this is normally not used for topside structures and it will most probably limit the possibilities for future life extension of the installation. 4.5.8.3 Substructure Corrosion on the substructure can be dealt with in two ways; either corrosion control and/or corrosion allowance. Corrosion control is a technique and method to prevent or reduce corrosion damage (corrosion protection), while corrosion allowance means adding extra steel during design (typically 3‐10mm) to compensate for any expected reduction in wall thickness during operation. The amount of extra steel can be reduced by a corrosion protection system The corrosion protection system can further be divided into two systems; ▪ Painting ▪ Anodes (cathodic protection) For the substructure of the substation installation a combination of coating systems and a cathodic protection system is normally used. The cathodic protection may be a galvanic system consisting of several sacrificial anodes installed on the structure below sea level resulting in minimal corrosion on the structure members. The anode system has to be carefully calculated and size and amount of anodes depends mainly on water salinity,

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protected surface area and water temperature. A correctly designed anode system lasts over the installation lifetime without maintenance. An alternative system is the so called Impressed Current Cathodic Crotection (ICCP) systems which use anodes connected to a DC power source. This arrangement will however require control systems and maintenance and is not very often seen offshore. Coating of substructures is normally limited to structure above sea level and just below the zone where water is in wave motion (splash zone) and coating systems is described in the same way as for the topside structure in several codes and standards. The painting system will typically be epoxy based or polyurethane. In the design of a combined system different alternatives have to be weighted towards fabrication costs. One extreme is to coat the complete substructure to minimize the number of anodes (can not be avoided completely though). To partly avoid coating system a corrosion allowance for the structure lifetime may also be considered. The corrosion of the substructure is normally divided into zones: ▪ Splash Zone: Vertical extension of substructure being alternately in and out of the water due to the influence of tides and waves ▪ Atmospheric zone: Vertical extension of offshore structure located above the ‘splash zone’ ▪ Submerged zone: Vertical extension of offshore structure located below the ‘splash zone’ In the North Sea it can generally be assumed that the corrosion rate in the splash zone will be in the range 0.3 to 0.5 mm per year, where it is approximately 0.1mm per year near sea bed and in the range 0.1mm to 0.3mm per year in atmospheric zone. The cathodic protection system should be designed to protect substructure and J‐tubes (including future) as well as caissons. It should be ensured that an electrical connection is established between jacket and all installed items that are to be protected by the protection system. It is recommended to combine all three above ‘solutions’ for corrosion protection. This means that depending on the area, parts of the substructure will be painted, anodes may be attached, further extra steel thickness may be added. 4.5.8.4 Export Cables The Export cables typically use bitumen in the outer sheath which somewhat improves the corrosion resistibility. It is also possible to have armour wires from stainless steel instead of the standard galvanized steel, but at a cost increase.

4.5.9

Operation

4.5.9.1 Operational Modes With input from the operations crew, the modes of operation and the maintenance operations are set up and used as design basis for the control and remote operation of the platform systems. The finally commissioned control system and remote intervention features are designed to enable the platform systems to operate as specified. The onshore and offshore platform control personnel should be trained to follow the operational procedures defined in the Platform Operation Manual. The Platform Operation Manual will describe the platform and grid connection operation modes, the alarm system, alarm functions and the recommended actions necessary following an alarm.

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The mode of operation may change over time if the platform will later be modified, and used as a hub for other wind parks, or intercontinental connections. The proper initial design can reduce modification cost, as thorough controls/operations commissioning and simulations onshore is a significant cost saver. The operator's safety officer will ensure that work operational procedures are followed onboard the platform, and that the control centre onshore is kept informed of all personnel activities offshore, a Work Permit system. Work Permits are necessary even on a "cold" platform isolated from the Grid. The transfer of goods to and from the platform is also thoroughly planned, and includes diesel bunkering, fresh water bunkering, other consumables and waste transfer, equipment hoist, heavy hoist, personnel transfer from boat, and helicopter operations. For the planning of hook up and commissioning phase, input from experienced operations personnel is important in order to design and plan for the work offshore. The requirement for communication, transport, resting areas, toilet, shower and catering service will be much more important during hook up and commissioning than in remote operation mode, and good planning gives saving as well as good quality work. 4.5.9.2 Operations with Personnel Offshore Based on the parameters for operations with regard to power flow and uptime, the operations and maintenance philosophy set the requirement for emergency or permanent accommodation areas on the platform. The response time, weather conditions, and transportation cost are the evaluation criteria for whether to include a helicopter landing platform or a hoist area. To include the possibility for transfer by helicopter hoist is recommended, either for emergency or quick component exchange reasons. Training requirement for hoisting personnel is however extensive. A medic room with Defibrillator /Medicine /Stretcher/ is recommended on the platform. One of the persons onboard should be trained as a medic. All transport and transfer operations offshore include risk and are costly operations. Planning is the key to efficient transfer of catering supply, equipment supply and waste return. Area on the platform is scarce, and tidy housekeeping of all work operations will improve safety and efficiency. 4.5.9.3 Emergency Accommodation Emergency facilities should be required as a minimum. Examples of equipments in an emergency accommodation is sleeping bags, mattresses, VHF communication/ Satellite telephone, emergency light, sanitary facilities, food/kitchen. The facilities should be reasonably comfortable as it is likely that the facilities will eventually be used. The platform will be a working place at some point in time, more or less intense, whether it is commissioning work, emergency repair or maintenance. A muster area should also be considered in connection with the accommodation area. 4.5.9.4 Permanent Accommodation If the platform will be used as a base for working with maintenance, modifications or as hub for wind power plants or other platform installations in the vicinity it may not be appropriate to certify it as a normally not manned platform. Hence, requirements on permanent accommodation, toilet and kitchen facilities will be required accordingly.

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The question of how the accommodation is integrated into the platform depends on the platform layout and size of accommodation. For safety reasons it is preferred to keep it sheltered from fire areas, mainly the transformer. On the other hand it is usually cost effective to integrate it into the transformer platform. One possible solution is to design the accommodation and the helicopter landing platform on the same side of the substation platform, and in that way the landing approach sector for the helicopter, and access to and from accommodation, can be kept separated from the "hot" side of the platform. The accommodation part can also be kept separated from the other "hot" side of the platform by a firewall. 4.5.9.5 The Separate Accommodation Module or Platform The separation between the accommodation platform and the substation platform may be an issue when one or more wind power plants in the area would like an accommodation module as a maintenance hub. The transfer of personnel between the accommodation module and the wind turbines are a costly operation, even over a short distance. One solution is to have the accommodation connected with a gangway to the substation. In that way the accommodation can operate as an emergency/ muster area for the transformer platform and vice versa. The advantage of using the transformer platform boat landing, cranes, storage facilities and other systems, supports the provision of the gangway connection as against separating the transformer platform and the accommodation platform completely. On a separate accommodation module or platform the crew must have separate sleeping rooms with shower and toilets ‐ kitchen with cooking‐wellness facilities‐(tv /‐ fitness/internet‐rooms. The fire and safety systems should be self contained on the accommodation module or separately (fire zone) contained on the nearby transformer platform. The helicopter deck should preferably be placed on top of the accommodation module. 4.5.9.6 Workshops It is emphasized that minimal work should be planned to be carried out offshore. However several issues as mentioned in this paper can argue otherwise. Required hook up and commissioning work can be chosen to be done offshore, or contingency plans can make such arrangements necessary. It is recommended that as a minimum a small workshop is designed, and that some storage space is reserved for mechanical and electrical spare parts. Due care should be taken to envisage contingency situations, redundancy requirements, and possible request for work facilities from other operators with service work being done in the vicinity, for example the wind park. 4.5.10 Commissioning of Plant Onshore Earlier in Section 3.7 the activities which should be performed dockside before load out of the substation platform were discussed. The key point covered in this earlier section was that the commissioning of plant onshore should be completed as comprehensively as possible. Works offshore is approximately ten times the cost of onshore works, can take considerably longer due to access opportunities to the platform offshore being weather dependent, and tasks which could be deemed ‘simple’ onshore can be more complex offshore.

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Prior to transportation offshore, the extent of the engineers which could require to be fully offshore trained should have been assessed. This includes consideration of all parties who may realistically be required offshore for final pre‐commissioning and energisation works. A Supplier of specific equipment, test engineers and commissioning engineers can relatively easily visit the onshore production areas to resolve any installation issues and complete final checks. However if they are not offshore trained they cannot simply be contacted to attend the installation once at sea. Once the substation is located offshore the location can very often represent different ownership boundaries and responsibilities to that on the dockside. For example the fabrication of the topside and installation of equipment can be contracted to third party however once installed on the offshore structure (or lifted from the dockside) the ownership can become the responsibility of a different party (often the owner). Therefore the works to under take final commissioning tests when the platform is installed offshore must be clarified in advance. Activities undertaken on the dockside under one permit system can be replaced over night by a new permit and operating system. The following sections outline typical works which require to be completed offshore after installation and the issues which can be faced. 4.5.10.1 Platform Installation 4.5.10.1.1Immediately after installation The initial task offshore after the substation installation is a visual inspection to assess any damage, or obvious changes, to equipment conditions and contents (i.e. SF6 or oil levels). During transportation and installation the substation may experience acceleration forces and as a result the installed equipment may have suffered component movement or damage. The extent of the acceleration forces should be provided early in the project to ensure that the equipment is specified to withstand this force, either through permanent or temporary measures. In addition to the acceleration forces, the positioning of the topside onto the substructure can present an opportunity for shock forces to arise as contact is made between the two structures. Further information is provided in Section 3.3.4.2 for vibration and transportation forces. To measure the transportation and acceleration forces an impact recorder can be installed on equipment prior to transportation. This data logging system samples the acceleration in the X‐Y‐Z planes, the angle / tilt, and the vibration can be used. After initial installation this logging sequence will provide an initial assessment if the transportation remained within the expected parameters during the process. 4.5.10.1.2Initial Works Auxiliary generator During transportation of the topside to the final location it is unlikely that the auxiliary generator will continue to operate due to the risk associated with transporting a platform with a live electrical system and rotating plant. Consequently the duration between leaving the dockside and gaining first access to the installed platform is likely to be such that all auxiliary systems are depleted. The design should consider the impact on equipment preservation requirements in uncontrolled temperature environments for this duration. The principal activity, after checks to ensure that it is safe to do so, is the re‐establishment of the auxiliary generator. This then provides platform LV supplies for lighting, heating, safety systems, and operation of the platform crane. 247

Safety systems After a visual inspection is performed, an assessment of the safety systems should be undertaken. This is required to ensure that any further persons who will be present on the platform are protected from any SF6 leakage, fire detection, evacuation/warning systems are in place, and that radio communication on the platform and to the vessel is established. Building Services Once an LV supply is established the basic building services will be established (heating, lighting etc). Checks can then be performed on this system and also inspection of any alarms on equipment , indication to the local SCADA system and confirmation of the HVAC system operation. Platform Crane The platform crane is essential to allow supplies and equipment to be loaded to the offshore platform. Checks will be required to ensure that there has been no damage during the transportation and that any actions are taken to ensure that the crane certification for carrying load remains valid. This may require a repeat of the load test on the crane. 4.5.10.1.3Removal of Transportation Aspects The next stage of works offshore will then focus upon removal of transportation aspects which were required. These can include: ▪ Securing any gratings, ladder or handrails which were lifted for transportation (for example gratings lifted at padeyes). Depending upon the location this may require to be completed before LV supplies are established. ▪ Removal of any transportation bracing or temporary supports ▪ Removing any other sea fastening measure (for example measures to ensure doors remain closed during transportation, additional panel bracing, or physical protection added) ▪ Erection of lightning masts and antenna (if fitted and lowered during sea transportation), ▪ Fitting of any ventilation units removed during sea transportation.

Figure 4‐9. Gratings must be replaced over exposed pad eyes

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Figure 4‐10. Transportation bracing or temporary supports to be removed 4.5.10.1.4Pre-Commissioning The electrical pre‐commissioning will then re‐check a number of items which were tested on the dockside. This is required to ensure that no changes have occurred during the load‐out. Items include: ▪ Commissioning the UHF and VHF radios, ▪ Insulation resistance checks for primary equipment and main supplies to confirm there was no change from transportation. This will include tightness checks on terminal wiring, ▪ Functional and operational checks on the switchgear locally and from the SCADA system, ▪ Tap changer operation and transformer auxiliaries (i.e. cooling fans). In general a pressure test of the MV and Export cables, or the switchboards will only be required offshore if there is evidence of damage to the equipment or changes in SF6 levels. 4.5.10.1.5Telecommunication and Fibre Optics The project programme may facilitate the connection of the export and array power cables on delivery of the topside. In this situation the power cables will have been winched through the J tubes and placed on the cable installation deck prior to the topside delivery. This situation provides the opportunity to terminate the fibre optic cores at an early stage and provide a communication link to shore. However it is very common for the power cables to be installed after the completion of the substation topside hook‐up. As the main communication to shore is through the fibre‐optic cables this cannot be completed until the power cables are installed. Consideration must be given to the offshore works which can be completed before the communication system to shore exists. Once fibre optic connection to shore is established it will be possible to commission: ▪ The fibre optic communication, ▪ The operation of the LAN network and telephones (IP telephones are typical), ▪ The communication between the offshore platform and the onshore control room ▪ Confirm alarms and indications via the control system to the onshore control room 249

▪ The operation and operation of the CCTV (if fitted), ▪ Confirm communication for the protection system (i.e. cable differential), and ▪ Confirm inter‐tripping between offshore and onshore switchgear / protection. However if a micro‐wave or satellite link is fitted to provide back‐up communications, for example during a fault on the export cable, this system would provide the opportunity to commission this aspect of the communication system at an early stage. 4.5.10.1.6Heli Deck If a helicopter deck is fitted to the platform this will require to have the fire system verified before flight operations can commence. The design standards generally agree that foam systems are currently the best methods to be installed for helicopter decks. However due to the nature of a fire associated with the helicopter and aviation fuel the system can be very extensive on discharge. This may prohibit testing of the system onshore at the deck fabricators and would be require to be performed offshore. Once the helideck is in the final location and ready for operation the necessary certification body (for example British Helicopter Advisory Board in the UK) will undertake an initial inspection of the helideck and its systems prior to the commencement of flight operations. 4.5.10.2 Energisation As with all onshore facilities, the HV energisation procedure should adopt a sequential and time spaced switching of individual circuits. This will include onshore assets, reactors, capacitor banks, subsea cables, offshore HV switchboards, transformers, MV and LV‐ switchboards, array cables and then WTGs. The switching programme will be project specific and dependent upon the arrangement and equipment configuration. However in all programmes the aim is to minimise voltage fluctuations on the system. This is particularly relevant in the switching of wind turbine array circuits where multiple turbine transformers may be energised together. Therefore, switchgear interlocking should be capable of facilitating individual switching of circuits. Typical stages through the switching and energisation for a single cable and two transformer system could be as listed below. This does not include details of proving the protection systems at the various stages. (i) Confirm all wind power plant equipment is ready for energisation (ii) First energisation of the new connection assets located onshore. (iii) Energisation of the subsea cable. The charging current of the cable can be used to prove the stability of the onshore upstream protection. (iv) Perform Export cable test (refer to Section 3.7.3.1) (v) Energisation of first transformer including tap changer and soak test. (vi) Energisation of MV switchboard busbars and auxiliary transformer from HV system. (vii) Energisation of second transformer including tap changer and soak test. (viii) Energisation of first WTG array. (ix) Energisation of remaining WTG arrays. (x) Carry out final commissioning control schemes on the offshore platform. (xi) Reconfigure power system to meet operational requirements At each stage of energisation the equipment recently energised should be inspected for signs of distress and whilst under load checks can be carried out. This includes 250

current/voltage transducers, remote indications of current differential scheme, phase rotations checks. During energisation the system must feature proven protection. When dealing with a long length of ac cable the commissioning protection for the first energisation must be sensitive to a fault in the subsea cable but be stable for the steady state charging current of the subsea cable. As noted in Section 3.4 the connection configuration of the earthing/auxiliary transformer must be considered in the switching programme. In the situation where the auxiliary transformer is providing the earth connection this must be present during energisation of the MV switchboards as this provides the earth path. Until energisation the protection scheme at the onshore and offshore substations cannot be proven. This includes as appropriate, busbar differential, subsea cable protection, transformer differential, directional overcurrent, earth fault and circuit breaker fail schemes.

4.6

Platform Concepts

This section describes three different principal topside concepts; Container deck, Semi enclosed and fully enclosed topside.

4.6.1

Container Deck

4.6.1.1 General Description A container deck type topside should be understood to be a single or multi level deck structure supported by a lattice structure extending from the substructure interface. On this deck several containers (standard or purpose built) containing electrical and auxiliary systems as well as crew areas are placed and fixed. The containers are in most cases preassembled by the different suppliers of equipment/system, and are installed by the deck fabricator in cooperation with the supplier and finally commissioned by the equipment supplier.

Figure 4-11. Topside with 2 Container Decks, Source: ALSTOM Grid GmbH

4.6.1.2 Topside Fabrication A container deck steel structure may end up being the most economical solution in respect of main steel structure fabrication, but in addition to the main structure fabrication, purpose made or standard containers must be added. As the containers are fixed, although 251

freestanding, on the support topside structure they have to be designed to withstand wind forces as well as excess forces in relation to sea transport and installation on site. 4.6.1.3 Interfaces As the containers can be outfitted at different locations (suppliers) and should be delivered with all components such as ventilation, heating panels, lights etc. installed a large number of different sub‐contractors and several different manufacturers of materials may be involved. Consequently there may be a large number of interfaces to coordinate.

4.6.2

Semi Enclosed Topside

4.6.2.1 General Description A semi‐enclosed topside should be understood as a structure with purpose built building facilities. These are integrated into the main topside structure supporting the structure integrity. They could also be combined with separate installed purpose fabricated containers and externally free standing equipment. Containers (if included in arrangement) are in most cases preassembled by the different suppliers of equipment/system, and are installed by the deck fabricator in cooperation with the supplier and finally commissioned by the equipment supplier. 4.6.2.2 Topside Structure Fabrication Depending on the extent of free standing equipment and containers included in the main arrangement, the semi enclosed topside can vary from almost a container deck solution with minor building parts included in the topside main structure, to the quite complex fully enclosed topside solution. The assembling of the multi level topside depends on the delivery schedule for the containers. Natural ventilated transformer One variant of the semi enclosed concept is that the transformer is out in the open, just sheltered from the deck below and with potential louvers on the side. The other rooms are enclosed with access walkways louvered or in the open. The argument is mainly that the transformer is naturally ventilated with no rotating machinery. The only mechanical part is the tap changer (if any). The coolers are mounted on the transformer with no problem with interfacing piping. A foam system for fire fighting is not suitable because the foam will not be detained within a confined space. The fire system may be a spray deluge system for cooling of transformer and adjacent structure to preserve the unit in case of fire. With regard to cost, the system cost item is the fire pumps and auxiliary hereby. Another cost item is the corrosion protection maintenance of the exposed equipment. Relatively easy access to the transformer for change out, or equipment handling is another plus. The walkways do not need to be louvered. One could discuss how open it should be in the top, and how enclosed in the bottom, but with cooling air flow maintained. (Refer also to Section 3.3.4.3.6)

4.6.3

Fully Enclosed Topside

4.6.3.1 General Description A fully enclosed topside should be understood as a structure with completely designed and purpose built buildings to fit equipment, integrated into the main topside structure and 252

supporting the structure integrity. All areas are purpose sized for equipment and systems and the whole topside is fabricated with indoor areas for all equipment. The indoor areas could either be natural ventilated or controlled by air conditioning. 4.6.3.2 Topside Fabrication A fully enclosed topside, either a stressed skin design or a truss braced type with cladding as environmental shielding, may be the most expensive type with respect to structural steel fabrication, potential cladding and outfit. However, due to the complexity and use of all dedicated space, it may turn out that this is the most attractive solution in the end as it is often possible to optimize the overall topside size resulting in lower weight and reduced costs for the fabrication of topside and substructure as well as for the installation.

4.7

Substructure

4.7.1

General

Today the best known substructure types are the monopile, jacket, gravity based and self elevation. Besides these four (4) “basic” substructures there are also combinations of them such as e.g. tripods, suction bucket, etc. The aim of this section is to describe the four (4) basic substructures, to give guidelines for the preliminary selection of the substructure and to discuss issues which may require specific attention during the design. The decision on which type of substructure to be used in the end must be based on further detailed studies. The evaluation starts with an overall economical evaluation combined with the technical solution found feasible with respect to platform type and site conditions. The economy should be evaluated from a life‐cycle cost perspective of the different concepts including CAPEX (capital expenditure), OPEX (operational expenditure) and ABEX (abandonment expenditure). Furthermore, it is recommended to evaluate a full life cycle risk analyses. The main purpose of the substructure is to transfer loads from the topside and support structure to the seabed. The type of substructure is primarily selected based on the ability to support the topside while meeting the environmental and seabed conditions at the specific site. There are also several other functional requirements e.g. supporting of J‐tubes and pull‐up equipment that needs to be considered. The Fundamental Design Parameters are explained generally in section 4.3. Information of site specific conditions like meteorological and oceanographic conditions (often called metocean) as well as the geophysical and geotechnical data is especially important. Environmental loads The environmental conditions should at least cover the following issues: ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪ ▪

Wind: Operational and extreme, directional distribution Wave: Operational and extreme, directional distribution, periods and spectrum Current: Operational and extreme, directional distribution Water level: Average depth, highs and lows, storm surges and tidal Temperature: Sea water and air temperatures Ice: Sea ice and icing of structure Salinity Seismicity and earthquakes Marine fouling 253

▪ Geophysical conditions The geophysical conditions describe the distribution of soil layers and seabed conditions. Before deciding the exact location of an installation it is important to make thorough surveys in order to locate possible objects e.g. boulders, wrecks, unexploded mines, bombs or the like. Examples of methods to do the surveys are magnetometer survey and/or multi beam, side scan, seismic and bore holes. The geotechnical survey describes the conditions necessary for the design of the substructure and should describe at least the following: ▪ Sea bed and soil description ▪ Characteristic data ▪ Stability, initial and long‐term settlements and inclination, subsidence ▪ Driveability ▪ Scouring requirements Operational loads The substructure must be designed to withstand loads during transport, installation and operation. For the substructure, the operation phase will typically size the major parts of the structure. The substructure must be designed to withstand the maximum load‐carrying resistance (ultimate limit state – ULS) further failures due to the effect of cyclic loading (fatigue limit state). Serviceability limit state (SLS) corresponds to tolerance criteria applicable to intended use or durability. It is recommended to minimise the critical frequency of the structure. “Rule of thumb” is that T (s) structure < T (s) for smallest waves. The critical frequency has an influence on the dynamic amplification further vibrations could damage the equipment and give bad operating conditions. Accidental loads Accidental limit state (ALS) corresponds to (1) maximum load‐carrying resistance for (rare) accidental loads or (2) post‐accident integrity for damaged structures. The structural integrity has an influence on the accidental limit state. Rare loads can involve ship collision damage. The ship size and loads are usually extracted from a designated ship impact report which include both operational loads from the normal support vessels and collision risk from these or merchant ships sailing in the area. Table provides a comparison of the substructure concepts. The concepts are compared by the following: ▪ Fabrication: Simple or complex structure ▪ Vibration issue: Issues due to dynamic, equipment and operational conditions ▪ Wind park interface: Poor, medium or good interface to wind park. ▪ Life extension: Possibility of life extension ▪ Water depth: Water depth ▪ Soil: Requirements to seabed conditions ▪ Topside weight: Operational weight of topside ▪ CAPEX: Fabrication and installation cost ▪ OPEX: Operational cost

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The comparison is based on a basic/typical construction. All concepts can be improved to achieve better results (higher water depth, more heavy topside, etc) which typically will result in higher CAPEX; therefore, the values are typical values. To be confirmed Monopile# Jacket Gravity Gravity Self elevation caisson Fabrication Simple Complex Simple Complex Complex Vibration issue Yes No No No Yes Wind park Medium/poor Good Medium Good Medium/good interface Life extension No Yes No Not on No bottom Water depth <20m <60m <20 Yard limit <50m Soil No No Yes ‐ Hard Yes ‐ Hard No requirements soil soil Topside weight <1200 tonnes <4000 <2000 Inst. range <4000 tonnes tonnes tonnes limit CAPEX* 1 3 1 3 3 OPEX* 2 3 1 3 4 Table 4‐6. Comparison of substructure concepts ‐ typical values *The economic assessment is given by a number between 1 and 5 – 1 is lowest budget and 5 is highest. # It should be noted for monopiles that normally "drivability" is a requirement, as drilling would be more expensive. In the sections below the concepts are presented in details

4.7.2

Monopile

The monopile is the simplest substructure which essentially is a single large pile made of steel that is driven into the seabed. The topside is supported by the monopile through a transition piece. The topside is either supported directly on the lower transition piece (yellow in the picture below) or by four (4) so called cow horns. The cow horns are a part of the upper transition piece (grey in picture below) that is bolted to the lower transition piece. The transition piece is jointed to the monopile through a grouted connection with shear keys. The monopile is ideal in terms of installation and manufacture, but has the drawback that it may become heavy as the amount of steel increases when used in waters with great depths. Focus areas This section will highlight areas/items which should be given extra attention during design: ▪ Connection between pile and transition piece (grout connection, suggest to have a failsafe solution) ▪ Dynamic fatigue analysis (time and frequency domain) ▪ Reliable metocean data (extreme data and scatter diagram) ▪ Critical frequency (normally overestimated (inherent in method), to be measured after installation, monitoring throughout service life) ▪ Dynamic amplification (sensitive to small changes in critical frequency and damping, sensitivity study suggested) 255

▪ Substructure‐soil connection (good estimate of stiffness important, suggest to investigate upper and lower bound)

Figure 4‐12. Gunfleet Sand, source: DONG Energy Geotechnical conditions The Monopile is versatile in terms of seabed conditions as it can be applied in almost all circumstances, even in hard soils/bedrock drilling can be used. However in soft soils the monopile has to be very long and thick in order to obtain sufficient bearing capacity and stiffness. Furthermore an important advantage of this foundation is that no preparations of the seabed are necessary. Metocean conditions The monopile solution is best fitted for shallow waters (<20 m) and smaller topsides < 1200 tonnes. Vibrations could be an issue, since the monopile is a large pile fixed at seabed (cantilevered beam with a mass). This issue needs to be further detailed and depends on the water depth and topside mass. Structural integrity The structural integrity is poor as a larger dent may result in a total collapse of the structure. The structure should be designed for collision with service vessel (<150 tonnes). Hence, the probability for a larger accident and collapse will have to be of an acceptable level. The possibilities for life extension are minimal since the substructure consists of one piece which is not easy to reinforce or change a part. Wind park cable interfaces The monopile has a diameter of approximately 5m; therefore, the space available for cables is limited, especially for larger wind power plants where numbers of feeders may often exceed 10. The J‐tubes for array and export cables can either be located inside or outside the monopile. By an outside location, the J‐tubes are sensitive to a potential ship collision. Therefore, an inside location is preferred. The drawback of an inside location is the limited space available as it is required to have sufficient distance between J‐tubes in order to take care of heat dissipation from the cables. Generally it is recommended to install an extra J‐tube. The J‐tubes can be used for future connections to shore, array cable or in case of refusal during cable pulling.

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Installation The installation time for a monopile is approximately one(1) day. Monopile and transition piece are transported to site on a barge. Depending on the subsurface conditions, the pile is typically driven into the seabed by either large impact or vibratory hammers, or the piles are grouted into sockets drilled into rock. Afterwards, the transition piece is installed by crane vessel. The transition piece is supported by brackets until the grout has sufficient strength. Typically, the lower part of the topside (topside transition piece ‐ grey) is bolted to transition piece (yellow), see figure below.

Figure 4‐13. Installation of monopile and topside, source: DONG Energy. Topside is transported to site on separate barge and installed by crane vessel and welded to cow horns. The advantage of this concept (split topside in two (2)) is to reduce reaction during sea transport. Alternative topside is bolted directly to transition piece as one (1) unit. Vibration Operational experience has revealed vibration issues due to wave interaction, leading to failure of electrical equipment. The structural design of a monopile‐based solution must be carefully evaluated with site‐specific marine condition data in order to verify the suitability of this foundation concept

4.7.3

Jacket

The jacket typically consists of four strong legs – supported by piles driven into the seabed – interconnected by cross bracings, all made in tubular pipe sections and welded together. The location where one or more braces are welded to a leg is called a joint. Such a welded joint has a number of weaknesses when it comes to fatigue loading as the stress concentrations become very high. However for a substation structure fatigue is relatively benign and hence there is a good balance between fatigue and ultimate resistance in the welded jacket. The ease and speed of fabrication is essential for the price of the jacket. Where the price split between materials and fabrication on a Monopile is approximately 60/40 a jacket has a split round 30/70 due the complexity and manual work to be done.

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Figure 4‐14. Walney 1, source: DONG Energy The meaning of this section is to highlight areas/items, which should have extra attention during design: ▪ Reliable metocean data (extreme data and scatter diagram) ▪ Hydrodynamic factors (J‐tubes and legs closely located) ▪ Substructure‐soil connection (good estimate of stiffness important, suggest to investigate upper and lower bound) Geotechnical conditions Like the monopile, the jacket concept is versatile in terms of seabed conditions, as it can be applied in almost all circumstances. Since four (4) piles must be driven, an installation in hard soils where drilling is required will have a price‐increase. The four (4) legged jacket is sensitive to an irregular seabed. The irregularity can be taken either by preparation of seabed before installation or by jacking systems through installation. Metocean conditions This concept is very flexible due to water depth < 60m and topsides and topside weight < 5000 tonnes. The concept can be extended by adding more legs to the structure. Structural integrity The jacket has good structure integrity. It is possible to reinforce the structure by adding extra braces or change part of the structure; therefore, life extension is not an issue either. Typically, the jacket is designed for removal of damaged sections from a ship collision and still be able to withstand loads from a 1‐year event. Inter Array cable interfaces Since the jacket has four (4) sides, the substructure has a good interface to the wind park cables. The array and export cables could preferably be located inside the jacket frame in J‐ tubes for protection against ship collision. Typically, the J‐tubes are to be located as close to jacket legs as possible in order to minimise the loads on the bracing system. Alternative array cable to be located in one (1) or two (2) caissons – this solution must be investigated due to heat problems. It is recommended to locate the caisson inside jacket frame too. Generally it is recommended to install an extra J‐tube for future cables (array or communication) or in case of a failure during cable pulling. Installation The jacket can either be installed on pre‐installed piles or piles through pile sleeves. Installation time for a typical 4 legged jacket without template and with 4 piles is approximately 2‐3 days including pile driving and grouting operation. 258

Jacket, piles and template, if necessary, are transported to site on barge.

Figure 4‐15. Transportation and installation of jacket with pile sleeve, source: DONG Energy. Pre‐installed piles; a template with footprint analogue to the jacket is placed on the seabed and piles are driven through. Afterwards, the template is removed and the piles are cut in order to obtain the same level on all four (4) piles. Afterwards, the jacket is located above and connection between piles and jacket leg is grouted. Smaller uncertainties can be taken either by jacks between pile and jacket or in the interface between jacket and topside. Pile sleeves; jacket is placed directly on the seabed (mud mats are installed on jacket), piles are driven through the pile sleeve and the connection is grouted. The jacket is levelled by jacks located above the pile sleeves; the jacket is to be levelled before grouting. The levelling system is removed after grouting has sufficient strength. The solution with pre‐installed piles gives a simpler jacket by avoiding the pile sleeves, but will be more costly due to fabrication of template for driving of piles. The solution is more beneficial, if the template can be reused. The installation can further be divided into two (2) steps, whereas the piles must be driven through pile sleeves after the jacket has been located on seabed.

4.7.4

Gravity Based Foundation

A gravity based foundation is a heavy substructure located directly on seabed. Gravity foundations are very cost optimal on lower water sites with strong soil conditions. However, the weight of a gravity foundation increases rapidly with increased water depth. The gravity structure is fabricated of reinforced concrete or steel. The gravity foundations may be filled with ballast weight, olivine or rocks to increase the weight and increase topside loads. Topside is located directly above the substructure or with a steel transition piece. Topside, transition piece, and substructure may be bolted, grouted, or welded together.

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Figure 4‐16. Rødsand 2, source: Energinet.dk The meaning of this section is to highlight areas/items, which should have extra attention during design: − Reliable metocean data (extreme data and scatter diagram) − Substructure‐soil connection (good estimate of stiffness important, suggest to investigate upper and lower bound) Geotechnical conditions A strong soil condition is required for installation of gravity based foundation. Site preparation and placement required for gravity caissons typically involves dredging several metres of generally loose, soft seabed sediment and replacing it with compacted, crushed stone in a level bed. Furthermore, the seabed must be smooth before installation. The seabed around the base of the foundation will normally have to be protected against erosion by placing boulders or rocks around the edges of the base in order to minimise scour and to retain bearing capacity of soil. This makes the foundation type relatively costly in areas with significant erosion. Metocean conditions The single tower gravity based foundation fits best for smaller water depths <20m. The structure is very stiff and is typically installed in shallow water; therefore, vibration/acceleration induced by wave loads is most probably not an issue. Structural integrity The structural integrity and possibilities for life extension are minimal. The substructure consists of one piece which is not easy to reinforce or change a part of. Therefore, a correct design life is important. On the other hand, since the substructure is located in shallow water, the probability for ship collision is very low. Wind park cable interfaces The interface to the wind park cables is similar to the monopile. The space for cable installation is very limited by the diameter of concrete column. For the transition piece one can increase the diameter or have J tubes on the outside. The J‐tubes for array and export cables will typically be located inside the substructure. It is recommended to have sufficient distance between J‐tubes in order to minimise heat problems.

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Generally it is recommended to install extra J‐tube. The J‐tubes can be used for future connections to shore, array cable or in case of refusal during cable pulling. Installation The installation time is very sensitive to the time for preparation of seabed. After seabed is prepared, the installation time is approximately one day. The seabed must be prepared. The structure is transported to site on barges and installed by crane. The advantage of choosing the steel structure is that a lightweight crane can be used for installation. The drawback is that ballast weight and scour protection must be placed afterwards, hereby requiring two (2) operations. Scour protection may be required by monopile and jackets as well.

Figure 4‐17. Installation of gravity foundation, Source: Energinet.dk.

4.7.5

Gravity Based Caisson Foundation

Many of the evaluations made on the mono tower type are similar for the caisson type. The foundation is a big floatable self installed caisson. The caisson could alternatively have been a multiple tower design. The Topside can be located directly above the concrete substructure, or a transition piece jacket structure can be used. Topside and jacket is welded together. Metocean conditions The gravity based foundation fits for all water depths. The structure is very stiff and is typically installed in shallow water; therefore, vibration is not an issue. Structural integrity The structural integrity and possibilities for life extension are minimal. The bottom concrete structure consists of one piece which is not easy to reinforce or change a part of. Therefore, a correct design life and accidental load design is important. Wind park cable interfaces The space for cable installation in the caisson is suitable for large wind power plants. The J‐tubes for array and export cables will typically be located inside the substructure. It is recommended to have sufficient distance between J‐tubes in order to minimise heat problems. Generally it is recommended to install extra J‐tube. The J‐tubes can be used for future connections to shore, array cable or in case of refusal during cable pulling. Installation The total installation time is highly dependent on the time for preparation of seabed. After seabed is prepared, the installation time is approximately two days. 261

The seabed must be thoroughly prepared and the cost is significant. The structure is floated to site and installed assisted by a crane vessel that ensures complete installation operation control.

Topside

Steeljacket Transition

Concrete Caisson Cable J-tubes

Figure 4‐18. Anholt, source: DONG Energinet.dk

4.7.6

Self Elevating

Once the self‐elevating platform is positioned, no cranes or lifting devices are required to install or raise the platform above sea level to its design‐specified height. The self elevation substructure consists of four (4) strong legs connected to the topside. The topside can be jacked along the legs by the associated jacking systems. Generally, two (2) models are available; with and without a base frame. The base frame is the foundation of the platform. The base frame can be a part of the legs or installed separately. The base frame has two (2) functions; shorten length of piles or/and serving as an interface with the piles driven into the seabed to connect the platform legs. Instead of piles, the legs can be designed with a footing system (mud mats, buckets, etc) versatile to accommodate a range of soil conditions in the field. This solution is useful for both models – with and without base frame.

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Figure 4‐19. Global Tech 1 Source: Overdick GmbH & Co. KG

Figure 4‐20. Central Lifting Self Elevating structure Source: tkb. Technologiekontor Bremerhaven GmbH By choosing the self elevating concept, some of the installation costs are moved to the fabrication and operation. One of the main advantages of the concept is the independence of heavy lift contractors resulting in fewer dependencies in the overall installation programme. A self elevating structure with a base frame requires that the topside is located within the leg matrix. This implies that the substructure will be large which in turn results in large topside consisting of the air ballast volume creating the complete structures buoyancy. The self elevating structure is compared to the other known concepts the heaviest with respect to structural steel. The connection of the substructure to the topsides should be designed taking into account the same rule and regulation as for those in other concepts. Wear and tear may have an influence on the jacking system, meaning that support conditions between hull and substructure could change by time. Focus on the jacking system and a relevant redundancy requirement is essential during all engineering phases. 263

Focus areas The meaning of this section is to highlight areas/items, which should have extra attention during design: Load pattern (to be transparent) Dynamic fatigue analysis (time and frequency domain) ▪ Reliable metocean data (extreme data and scatter diagram) ▪ Eigen frequency (normally overestimated (inherent in method), to be measured after installation, monitoring throughout service life) ▪ Dynamic amplification (sensitive to small changes in eigenfrequency and damping, sensitivity study suggested) ▪ Leg‐hull connection (good estimate of stiffness important, suggested to investigate upper and lower bound, changing stiffness due to wear and tear) ▪ Substructure‐soil connection (good estimate of stiffness important, suggest to investigate upper and lower bound) Geotechnical conditions The self elevating substructure is versatile in terms of seabed conditions, as it can be applied in almost all circumstances depending on the design. By choosing the system without base frame, the advantage is that no preparations of the seabed are necessary. Metocean conditions This concept is very flexible due to water depth <50m and topsides and topside weight <5000 tonnes. Structural integrity The main parts of the self elevation concepts are the four (4) legs and the central jacking structure. Reinforcement may turn out difficult, since the leg is fabricated as one piece and connected to the jacking system. Maintenance requirements are similar to those of a jacket structure. Wind park cable interfaces The cables are typically routed inside one (1) or two (2) caissons. It is recommended to have at least two (2), in order to obtain a better interface to the wind power plant. For protection against ship collision, it is recommended to locate caissons inside footprint of substructure. Since the cables are located inside caissons, heat from cables could lead to power loss. When the numbers of cables increase, the size of caisson will increase too. It means that the caisson can achieve same size or even bigger than the legs. Such a system has a number of weaknesses; the caisson will attract loads and act as 'leg', meaning that overloads could arise on unforeseen location and lead to damages. Therefore, focus must be on the support system between caisson and leg/hull structure. Generally it is recommended to install extra J‐tube. The J‐tubes can be used for future connections to shore, array cable or in case of refusal during cable pulling. Installation The installation time is depended on the jacking system and hence, a fast and reliable jacking system should be employed. The installation time for the self elevating concept depends on whether the base frame is pre‐installed or a part of the legs. If the base frame is a part of the legs, the estimated installation time is one (1) to two (2) days. The self‐elevation concept is positioned by tugs. After final position is achieved, legs are lowered. 264

Once positioned, no cranes or lifting devices are required to install or raise the platform above sea level to its design‐specified height. Separate installation vessels are required, if base frame is not a part of the substructure and if piles must be driven. Similar with caisson in case of post‐installed.

Figure 4-21. Self elevating installation, Source: Overdick GmbH & Co. KG.

4.8

Load Out, Transportation and Installation

4.8.1

General

This section will discuss aspects to consider with respect to load out, transportation and installation procedures. Generally for the design of the topside, is that the final installation weight is of a major importance due to the fact that heavy lift vessels are few worldwide and can be responsible for a disproportionally large sum of the total investment for the substation. A practical level for topside installation weights are in 2010 approximately 2000 tonnes opening up a window for a couple of more installation vessels. With topside weight above 3000 tonnes only a smaller handful of vessels can be used and with competition of lifting operations in the oil & gas segment they can be very expensive, all up to 40% of the total fabrication and outfitting costs. With this in mind considerations to establish topsides which are much optimized is of great importance. A decision to split the platform or foundation in different parts may introduce huge risks and cost of offshore work. On the other hand it may be beneficial from an installation point of view with regards to cost and programme, i.e. weather windows and availability of lifting vessels. Proper planning of offshore work can minimize risks, predict the cost, and prove if installation in many parts is the best solution. 4.8.1.1 Overview of Available Lifting Vessels The table below indicates available lifting vessels. It should be noted however that there may be new vessels under construction and that all vessels do not normally operate in European waters.

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Vessel

Capacity (mT)

Type

Thialf

14,200 (2x7100 tons)

Semi‐submersible

Saipem 7000

14,000 (2x7000 tons)

Semi‐submersible

Svanen

8,700

Catamaran

Hermod

8,165 (1x4536, 1x 3629)

Semi‐submersible

Lan Jing

7,500

Monohull

Balder

6,350 (1x3629, 1x2722)

Semi‐submersible

Borealis

5,000

Monohull

Oleg Strashnov

5,000

Monohull

Deep Water 4,000 Construction Vessel

Monohull

DB 50

3,992

Monohull

Rambiz

3,300

Catamaran

Asian Hercules II

3,200

Monohull

DB 101

3,175

Semi‐submersible

DB 30

2,800

Monohull

LTS 3000

2,722

Monohull

Sapura 3000

2,700

Monohull

Stanislav Yudin

2,500

Monohull

Saipem 3000

2,177

Monohull

Huasteco

2,000

Monohull

Tolteca

2,000

Monohull

Quippo Prakash

2,000

Monohull

Table 4‐7. Lifting vessels and their capacity. (Unverified data from internet) 4.8.1.2 Load Out The term load‐out is used to describe the process where the structure is transferred from a fabricators yard/quayside to the transport barge. For a traditional substructure & topside arrangement the Transport & Installation contractor would normally deliver the barge to the quay adjacent to the fabricators yard where the fabricator takes over control.

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Barge grillage designs would be prepared and the grillage manufactured and welded to the barge deck prior to load‐out. The load‐out procedure would be planned and fully documented in advance and it is common practice to weigh the structure prior to commencement of load‐out. With the barge moored against the quay the heavy lift must be transferred from the quay to the barge. For a heavy structure, such as the substation topside, the weight of the module would be taken on multi‐axle trailers installed at suitable points below the module. The module would then be gradually moved from the quay to the barge under tightly controlled conditions. As the weight of the module is slowly transferred to the barge the water filled barge ballast tanks would be sequentially emptied to maintain the trim. Once the topside has been located and lowered onto the grillage the module can be welded to the grillage to positively secure the load for transport. The barge would be finally trimmed using the water ballast and any remaining sea fastenings attached. Any necessary temporary access stairs/ladders and temporary navigation lighting etc would be completed prior to transport. 4.8.1.3 Sea Transportation Transportation of big structures is usually achieved by use of a barge moved by tugboats. There are also special transporting vessels with large barge like loading deck, some of them submersible. Big concrete gravity based foundation may also be floated out to site. Once the barge and its load are towed out to sea the whole structure may be subjected to external forces as a result of barge motion. The structure and any equipment within the structure, typically transformers, switchgear, fabricated buildings etc will be subjected to these forces resulting from vessel Roll, Pitch & Heave.

Figure 4‐22. Roll, Heave and Pich

The complete structure, including all topside equipment, needs to be designed to withstand these conditions hence the conditions need to be identified during the design phase of the works. If neither a motions study nor model tests have been performed then for standard configurations the motion criteria contained in Noble Denton 0030/ND – Guidelines for Marine Transportations may be acceptable. A typical unrestricted default motion for a common barge with dimension 140m x 30m would be 20o Roll 10o Pitch with a full cycle period of 10 seconds and a Heave of 0.6g. 267

Agreement needs to be reached at an early stage in the design process to allow all design parties to consider the effects upon their products, particularly items like transformers & gas insulated switchgear. The products may need to have additional padeyes/fixing points added to their housings for the fitting of sea fastening restraints. Should any component of the complete assembly not be suitable for the specified motion criteria then weather restricted operations may need to be considered. The transportation period would be generally planned to match the sea state trends for the particular time of year and availability, where required, of a suitable heavy lift vessel with the actual transportation being dependent upon an acceptable weather window.

4.8.2

Hook Lift

The bulk of experience to date relies upon the traditional hook lift by a heavy lift vessel for installation of substructures and topsides. Prior to arrival of a topside structure the substructure, either jacket legs or piles dependent upon arrangement, would be levelled, marked and cut to the design height. The cut planes would be surveyed and prepared for welding. The selection of the heavy lift vessel (HLV) would be dependent upon many factors some of which are listed below: • Water depth at the installation location • Weight of the structure to be lifted • Height of the lift • Physical dimensions of the structure to be lifted and lift radius • Centre of gravity of the structure to be lifted • Fixing points on the structure for attachment of the lift rigging • Hook height of the vessel and arrangement of any necessary lifting beams • Number and arrangement of the HLV jib(s) For any specific HLV the design of the structure could be developed to give the optimum lift conditions for the works, hence it is vital that the choice of HLV is made early in the design process, ideally at the concept stage. The illustration below shows a typical lift arrangement for a topside structure and from this the interdependency of the equipment can be visualised. It is imperative that the topside does not clash with the HLV jib during the lift.

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Figure 4‐23. Lifting arrangements A heavy lift vessel dual lifting jibs (typically the Rambiz) can influence the physical arrangement of topside structure to avoid clashes with the inner sections of the jibs. The spacing of the lifting points can influence the sling arrangement, rigging angles and the need for spreader bars. Generally if multiple spreader bars are incorporated in the lift arrangement the vertical height required for the rigging may be increased and this in turn would impact on the design of the structure. In some instances a multi‐deck topside structure may need to include an integral lifting frame so the structure will withstand the lift forces and negate the need for separate spreader bars. It is common practice for the Heavy Lift contractor to deliver the rigging to the fabricator’s yard prior to sail‐out together with a laydown design to allow the fabricator to install the rigging on the structure. Obviously the structure needs to be designed to accept the weight of this rigging. Where a jacket foundation includes a cable deck this deck may be suitable for use as a rigging laydown platform, however, where a cable deck is not included in the jacket design a temporary platform may need to be fitted. As with the transport the heavy lift operation is weather dependent and requires the same level of forecasting and planning.

4.8.3 Self Installing The self‐installing substation could either be wet towed or transported on a barge/ heavy lift carrier to the offshore installation site. The decision is a result of a techno‐economical study in which also risks due to bad weather, availability of emergency shelters, navigational restrictions and governmental requirements have to be taken into consideration. The towing route and towing procedure need to be approved by the Warranty Surveyor. Once arrived at the offshore site the self‐erecting substation will be positioned by means of tug boats or by a marine mooring/anchoring system for its final installation. The exact position of the platform is usually controlled by GPS. When wind turbines or other 269

structures have been installed already in the vicinity of the transformer substation a local positioning control system could be arranged which provides better accuracy of the platform position. Marker buoys could also be pre‐installed to indicate the installation site. The decision on the spread to be used for positioning the self‐erecting substation depends on the wind, wave and current situation and on the required installation tolerances. If the legs of the self‐erecting platform have to meet the contact points of a pre‐installed base frame the installation tolerances are smaller compared to the installation with seabed suction buckets. If required, a mooring spread consisting of pre‐laid anchors and mooring barges may have to be used. When the self‐erecting platform is correctly positioned the legs will be lowered down by the leg jacking system. The most critical phase during the installation process occurs when the legs of the floating platform have first contact with the seabed or with the pre‐installed base structure. Due to the relatively small size and mass of the platform movements like pitch and heave can lead to large leg contact forces as long as the platform is in the transitional situation from the floating to the fixed condition. A proper motion analysis should therefore be carried out to simulate the behaviour of the substation during this phase of the installation and to determine the limiting environmental conditions under which this operation can be performed. Especially the wave height is a sensitive parameter for the motion behaviour of the floating substation. A significant wave height of only 0.5 m has been specified for the installation of some of the self‐erecting substations. Depending on the sea area where the platform should be installed the waiting time for a suitable weather window with the specified limiting wave conditions can be considerable and represents a major risk and cost factor of this platform concept. In order to reduce the time period of the transitional situation from the floating to the fixed platform condition technical systems have been suggested allowing quick lowering of the platform during the critical phase of first contact with the seabed or pre‐installed base structure. When the legs are almost in contact with the fixed support the buoyancy forces of the floating platform could be quickly reduced by e.g. releasing air from buoyancy chambers. This means, the substation is partly floating on an air cushion and the air during the quick lowering process is suddenly released under controlled condition. A substation design that allows such quick lowering is shown in Figure 4‐24..

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Figure 4‐24. Self installing, self floating platform (source: IMPAC GmbH)

4.8.4

Float Over

An installation method not yet used in offshore wind projects is the so called float over operation. With this type of operation it is possible to avoid engaging the heavy lift vessel needed for the previously mentioned hook lift type of installation. The float over operation is used in oil and gas installations worldwide for topside structures, mainly as an alternative depending on specific circumstances, for example when no heavy lift vessel is suitable on the market or if the specific site conditions demands an alternative, shallow water can not be combined with large heavy lift vessels, or if the topside structure is of such a size that no existing lift vessel can be used. A float over operation can be executed by either an offshore transport barge or a special semisubmersible heavy transport vessel (ship). The operation principle is that the vessel transports the topside to the location where a substructure has been preinstalled, offloads the topside structure onto the substructure by ballasting the barge/ship to transfer the weight loading from the transport vessel to the substructure. The float over installation method is quite advanced and has basic needs different from the hook lift for example: ▪ The interface between the substructure and topside will be lower than the hook lifted topside to avoid a sea transport with a topside supported by a high sea fastening grillage resulting in a high positioned centre of gravity limiting acceptable transport seastate. A low positioned interface above LAT can limit the hook up weather window for the operation (topside/substructure welding work). If the topside needs to be installed higher additional jacking provisions could be 271

installed on the platform to (self) elevate the platform after offloading onto the substructure, similar to the self installing platforms. ▪ The float over operation is normally done by a vessel entering the site located substructure between the supporting legs, this demands a substructure designed and sized to suit the installation vessel. In practical terms this means that the substructure will be in the larger end of structures as offshore transport barges needs 20m and upwards free span for manouvering. For the design work of substructure and topside, decisions have to be made early in the process to define parameters for the installation procedure. Economical consideration has to be made and alternatives have to be weighed against each other in the overall project development. As offshore substations up until today have been of a moderate size (HVDC converter stations are not considered in this guideline) the float over operation has not been considered. Hook Lift Float Over Remark Substructure optimized size Smaller Larger Optimized towards installation concept Substructure Installation ‐ ‐ Considered equal Topside optimized size Yes No Optimized towards topside equipment Heavy lift vessel needed Yes No Semisubmersible vessel ship No Possible As alternative Semisubmersible barge No Possible As alternative Topside weight <14000 t <40000 t Table 4‐8. Comparison of installation concepts, hook lift vs float over

4.8.5

Installation Hook-up

4.8.5.1 Hook-Up – Traditional Jacket and Topside Before de‐mobilisation of the heavy lift vessel (HLV) the topside would be welded to the substructure. This may involve the fitting of crown shims, welding and non‐destructive testing of the arrangement. Also part of the hook‐up works would be the pulling into the J tubes of the sub‐sea cables followed by the stripping, fitting of clamp and hang‐off, followed by laying onto the support system, termination and sealing of penetrations. The design of the topside needs to make due allowance for the cable installation equipment, winches, tugger wires, cable minimum bending radius and the operatives. This is discussed in more detail within section 3.

4.8.6

Removal/Replacement of Large Plant Items

On an offshore substation it is inevitable that some equipment (most often the power transformers) cannot be readily replaced by the platform crane and normal material handling procedures. This means that measures have to be taken and procedures defined already from the beginning of the topside design on how to be able to replace those large items. A cable free zone on one side of the platform may be required should a jack‐up vessel be used for the heavy lift. Furthermore, the location of the large and/or heavy plant items is essential not only from a material handling perspective. It is also important that the Centre of Gravity is not jeopardized during the replacement operation. The repair time for e.g. a 272

transformer may be significant and thus, it is important that the construction can withstand the stresses caused by the dislocation of the CoG.

4.9

Fire and Explosion Design

4.9.1

Introduction

The intention with this section is to discuss different aspects with respect to fire and explosion protection, to elucidate parameters to consider during the design process and to give an understanding of the procedures employed when it comes to assessment studies and certification. The overall main objectives of the fire and explosion protection system are to − minimize the risk of fire and explosion − automatically monitor, detect and give alarm in case of smoke, fires or explosions − minimize the propagation and consequences of a fire and/or explosion In order to minimize the risk of fire and explosion a risk assessment study should be conducted early in the design process or even before the actual design phase commences. In practice this means that different hazards need to be identified. In the case of offshore substations electrical equipment containing fluids, diesel generator, fuel tanks and appliances related to the galleys are typical examples of possible sources of fire and explosion incidents. Considering the remoteness of an (most often unmanned) offshore substation, the need for a fully automatic monitor and fire detection system becomes obvious. When designing such system the platform layout including evacuation routes, the different types of sensors, CCTV systems, etc. need to be thoroughly assessed. In order to meet the objective of minimizing the consequences of a fire and/or explosion different solutions need to be considered. Fire protection can be divided into two categories; passive and active protection. Passive fire protection includes e.g. separation of equipment in cells by graded fire walls and floors. It can also mean that the platform is designed in such a way that essential equipment / systems can withstand a fire for a certain time period and that the integrity of the steel structure is maintained. Examples of active fire fighting are foam, deluge, sprinkler, water mist and inert gas system. The selection of system must take into account the object / area to protect and one system may not necessarily exclude the other. Most often a combination of passive fire protection and different systems of active fire protection should be used.

4.9.2

Fire and Explosion Hazards

Important source of fire and explosion incidents are LV and HV electrical equipment and cables used on the offshore substation. Transformer fire/explosion is commonly perceived to result in the highest consequence for an offshore substation. Other risks include maintenance activities involving heat sources and use of catering appliances found in the galley / accommodation section of manned installations. Flammable liquids commonly used on offshore installations include diesel fuel, various oils, paint, varnish and, rarely, helicopter aviation fuel. For a fire to be sustained, three conditions have to be met: heat, fuel and oxygen (also referred to as the “fire triangle”). Appropriate design measures try to eliminate one or more of these factors. Appropriate thermal design of equipment including cooling can, for 273

instance, eliminate the heat source. Other risk reducing measures include elimination of the fuel (e.g. by using non‐combustible materials) and limitation or elimination of oxygen (e.g. use of enclosures). Fire prevention measures include lightning protection, temperature sensing and condition (e.g. insulation) monitoring. Considering the remoteness of an (often unmanned) offshore substation, the need for a fully automatic fire detection system through sensors possibly supplemented by CCTV should be considered. Once ignited, active and passive protection can control and limit the fire. The selection of system(s) must take the object / area to protect into account. A combination of various measures is frequently used.

4.9.3

Design Process

Fire safety goals (or philosophy) generally include life safety, property protection, environmental impact limitation and provision of continuous operation. In the following, design objectives and associated performance criteria (quantitative measures) are defined. The objectives of fire and explosion protection are to minimise the risk of fire and explosion; to monitor, detect and give alarm in case of smoke, fire or explosions; and to control fires and limit consequences and propagation / escalation. In order to minimise the risk of fire and explosion a risk assessment study should be conducted early in the design process. In practice this means that fire and explosion hazards need to be identified and evaluated and the risks assessed, i.e. consequence and probability need to be estimated. Risk management then means that design measures are introduced to (in order of preference) eliminate, prevent, control and limit the risks. Examples for this process are: − Main transformer fire or explosion → Transformer design solutions (rating, choice of oil, pressure relief system, condition monitoring), fire detection, blast rated boundaries and extinguishing systems − HV, MV switchgear fire or explosion → Equipment design, arc detection, pressure relief system and extinguishing system − LV equipment and cable fire → Equipment design and rating, low smoke/fume cables, inspection and maintenance, fire detection and extinguishing systems − Fire in accommodation → Housekeeping, fire detection systems, sprinkler system, emergency response procedures − Diesel release from emergency generator, storage or day tank → Bunded areas, double skin tanks, inspection and maintenance, procedures and training The traditional prescriptive framework for fire safety makes users focus on compliance with codes but does not demonstrate achievement of fire safety goals, objectives or performance criteria. A performance‐based approach to fire protection is based on fire safety goals and objectives, deterministic and probabilistic analysis of fire scenarios and quantitative assessment of design alternatives. Fire scenarios are sets of conditions which define development of a fire called a design fire and the subsequent fire spread potential. Construction and quantification of design fire curves is the most important and most difficult aspect of the process. Trial designs consider again how fires are initiated and develop how fire protection features will work (smoke detection and management, fire detection, confinement and suppression) and how occupants may behave. If performance

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criteria cannot be met, modifications will be necessary. The finalised design should be well documented. Minimum requirements on offshore substations, independent of manning and geographical area, include fire detection & alarm, portable fire extinguishers and possibly some passive protection for a refuge area. Fire and explosion protection design is aided by a number of standards (see section 4.5.1) originally designed for maritime as well as oil & gas applications while dedicated guidelines for offshore wind have yet to emerge. For instance, current offshore codes do not provide clear guidance on the various substation areas, rooms and enclosures. Considered interpretations are therefore required.

4.9.4

Fire and Smoke Detection

Due to the at least temporary manning of offshore substations during maintenance, some fire detection system is always required. Table below lists suitable detection principles for various areas. In addition to these, CCTV images can provide valuable information. Area Suitable detection principle Mechanically ventilated utility areas, control rooms, HV, MV Smoke and LV switchgear rooms, MV capacitor rooms, battery rooms, instrument rooms, telecommunication or public address rooms, HVAC rooms, electrically driven crane engine rooms Main transformer / reactor rooms (e.g. units filled with > Smoke & Heat (around 2,000 l mineral oil) transformer) Auxiliary transformer rooms (units filled with mineral oil, Smoke (also Heat synthetic ester or dry insulated) around transformer) Rooms containing gas bottles (typically inert gas for fire Smoke suppression system) Fire water pump rooms Smoke and/or Flame Diesel generator or generator rooms Flame or Smoke Sack or bulk storage area, crane engine rooms, workshops Heat Paint store Heat or Flame Fuel oil storage, diesel engine room Flame Accommodation: cabins, corridors, internal staircases, public Smoke (and possibly rooms, radio room, laundry Flame) Accommodation: galley, galley hood or duct, washrooms, Heat toilets Void spaces above ceilings Smoke Manual call points (MCP) at exits from all areas, along escape MCP route, muster points, fire stations Table 4‐9. Detection Principles Above table simply refers to “smoke detectors”. Consideration should be given to the preferable type (e.g. defined in NORSOK S‐001) as detectors have to be suitable for the anticipated smoke particle size, i.e. high energy fires with “small” particles and smouldering fires with “large” particles. 275

4.9.5

Active Fire Protection

Active fire protection (AFP) systems are used to control or extinguish a fire. Many different systems exist which are suitable to protect different types of areas, rooms and equipment. Examples of active fire fighting are foam, deluge, sprinkler, water mist and inert gas system. System options and best practice are listed in DNV‐OS‐J201. Rules for the length of time to release exist for fire extinguishing media such as CO2 and other gases with lethal concentrations. Also, such systems may have to be disabled when certain (maintenance) activities take place on the installation. The disabling of the suppression system becomes unnecessary if inert gasses (typically InergenTM), as opposed to CO2, are used. These inert gasses whilst reducing the oxygen content in the room will still support human life. The areas defined in the table below are general and require interpretation for the particular design. For instance, main transformers may be provided with tank mounted or separate radiators. If the radiators are tank mounted, the AFP will cover the transformer tank, pipes and radiators. If the radiators are separately mounted then, besides AFP for the transformer tank, consideration should be given to active protection of pipes and radiators, although the transformer tank is the significant fire hazard.

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Area

Suitable Active Protection System

ALL

Portable Fire Extinguishers, various types

Mechanically ventilated utility areas, control rooms, HV, MV and LV switchgear rooms, MV capacitor rooms, battery rooms, instrument rooms, telecommunication or public address rooms, HVAC rooms, electrically driven crane engine rooms Main transformer / reactor rooms (e.g. units filled with > 2,000 l mineral oil) See note below Auxiliary transformer rooms (units filled with mineral oil) Auxiliary transformer rooms (units filled with synthetic ester or dry insulated) Rooms containing gas bottles (filled with flammable gas) Rooms containing gas bottles (filled with non‐ flammable gas, typically inert gas for fire suppression system, or SF6) Fire water pump rooms Diesel generator or generator rooms Sack or bulk storage area, crane engine rooms, workshops Paint store Fuel oil storage, diesel engine room

Water mist or gaseous system (gaseous more suitable to prevent possible water damage to electrical equipment) Water mist, water deluge, foam or gaseous system Water mist, water deluge, foam or gaseous system Portable Fire Extinguishers Water mist, water deluge or gaseous system Portable Fire Extinguishers Water mist or gaseous system Water mist or gaseous system Sprinkler system Sprinkler system Water mist, water deluge, foam or gaseous system

Accommodation: cabins, corridors, internal Sprinkler system staircases, public rooms, radio room, laundry Accommodation: galley, galley hood or duct, Sprinkler system washrooms, toilets Sprinkler system or gaseous system Void spaces above ceilings (depends upon main room system) Water monitors or deck‐integrated‐ Helicopter deck fire fighting‐system (DIFFS) – foam system Table 4‐10. Active Fire Protection Systems

4.9.6

Passive Fire Protection

The results from the risk assessment study, and fire case studies will determine the fire protection zone division. The fire case design specifies required survival time for the passive fire protection (PFP) separation material. The Passive fire protection (PFP) constitutes physical separation of areas and equipment in fire zones by graded fire walls and floors. The platform should be designed in such a way that essential equipment / systems can 277

withstand a fire for a certain time period and that the integrity of the steel structure is maintained. Often, the choice of PFP system is based on the type of area to be protected. Passive fire protection is classified according to (a) the temperature rise of the unexposed side within a specified time (e.g. 60 minutes, class “A”) and (b) its capability of preventing the passage of smoke and flame to the end of the standard fire test (e.g. 60 minutes). This example fire wall is then denoted “A‐60”. Selection tables for PFP are contained, for instance, in SOLAS and the MODU Code. However, the main transformers with some 40,000 litres of mineral oil constitute a major fire hazard and require case‐by‐case assessment which must take into consideration their design, arrangement, AFP and PFP. NORSOK S‐001 and DNV‐OS‐J201 imply that at least A‐0 fire divisions are required to separate the transformer from other areas that could be adversely impacted by a transformer fire. The heat flux may, however, easily exceed 100 kW/ m2, which points to the application of H‐rated divisions. For platform designs with multiple main transformers, such H‐rated divisions would for instance be used as wall between two transformers.

4.9.7

Explosion Protection

The objectives of explosion protection are to reduce the probability of explosions, reduce the explosion loads and to reduce the probability of escalation. Explosion events offshore include release of physical energy (e.g. pressure energy in gas, in particular for transformer explosions) and chemical energy (chemical reaction, e.g. for hydrogen explosion). Explosion loads are characterised by temporal and spatial pressure distribution with rise time, maximum pressure and pulse duration being the most important parameters. The following explosion hazards could happen on offshore transformer platforms: − Main (oil‐filled) transformer tank bursting − HV switchgear explosion − Hydrogen explosion associated with battery charging − Aviation fuel storage explosion Where possible, the severity of an explosion should be lowered by reducing the degree of congestion and by increasing the availability of venting. For some areas, blast walls could be an appropriate measure.

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5.

Substation Secondary Systems

The substation secondary systems are those systems which provide the functionality necessary to „ ensure safety of personnel engaged in operation of the substation and associated systems „ permit operation of the substation primary circuits. „ monitor the performance of the installation „ detect and manage abnormal conditions on the system and in primary equipment. „ manage the environment in which the equipment operates. The detailed functionality will depend on the specific installation and the way in which it is operated. The guidelines set out below assume that the offshore substation is classified as a normally unmanned (unattended) installation but allows for the use of the substation as a marshalling point for staff involved in maintenance of the substation and associated systems. Many of the functions listed above have been performed by systems selected as self contained, engineered packages from manufacturer’s standard production ranges. Whilst this ensures that a proven solution is employed for each of the functions it does not necessarily offer the most effective integrated solution as there may be several dedicated systems instead of a single multi‐function solution

5.1

Power Supplies

5.1.1

Statement of Requirements

The safety and security of the substation and personnel depends partly on the availability of auxiliary power supplies which support the operation of sub‐systems within the substation which manage and control its operation. The safety requirements for offshore substation platforms as they relate to the role and function of the auxiliary power systems can be found in DNV‐OS‐J201 Safety Requirements for Offshore Substations. The location of the substation is such that access for local operation, repair or maintenance is restricted by a number of factors some of which are outside the control of the operator. These factors may include: „ Weather conditions „ Availability of trained personnel „ Transport availability The latter two may be partially managed by the substation operator by investing in trained staff and the basic transport systems such as sea going support ships but specialist staff from manufacturers and special transport equipment required may need to be contracted out. It is therefore essential that the substation is able to operate safely, possibly in a restricted mode for a period of time determined by the duration of the restricted access. The cost of equipment accommodation on the platform and access difficulties mean that the size, weight and repair techniques used are a major factor in determining the type and rating of the auxiliary power supply systems. Clearly, a system of auxiliary supplies having a lower power and energy rating will cost less to accommodate but it must meet the operational needs of the installation and personnel. It is therefore very important to consider the auxiliary power needs of the equipment and where practicable make decisions 279

on the “integrated” design rather than treating the auxiliary power system as an “add‐on”. Selecting main equipment with a lower auxiliary power / energy demand but which has other drawbacks (size, weight or cost for example) may be overall the right choice if it supports a smaller, safer auxiliary power system design. Similarly, when considering the auxiliary power and energy needs of personnel the same “integrated” approach is required, for example with improved thermal insulation heating energy can be reduced. This is particularly true when considering the use of sub‐systems provided with specific, dedicated supplies such as uninterruptible power supplies (UPS). Whilst the discrete package approach may simplify procurement and avoid issues relating to performance guarantees it is not necessarily the most cost or space effective solution. In common with any other substation there is a need for both LVAC and DC power supplies and the detailed requirements and suitability of the LVAC and LVDC systems depend on a number of factors which are listed below:

5.1.2

LVAC Supplies

In order to operate the equipment within the substation a suitably rated Low Voltage Alternating Current (LVAC) supply is required, distributed throughout the substation to feed the associated loads. Typically this would be a 50/60Hz, three phase, 400V supply. The LVAC system is required to deliver the power under a range of operating modes and have the ability to store the energy required by the substation to provide for the operational needs of the substation both whilst connected to the main transmission system and when disconnected from it. The energy stored can be considered a consumable with a limited storage capacity hence the timing and means of replacing the stored energy must be considered in the design process. Typically, the system would be designed such that if the substation were energized from a transmission system incorporating redundant connections, all LVAC requirements would be supplied under an N‐1 security criterion. Only when the transmission connection was severed would it be necessary to consider a sub‐set of LVAC loads required for safety and protection of the installation (essential loads), with purely operational LVAC loads being left un‐served until normal supplies are restored. The capacity of the system and its energy storage requirements are determined by the loads imposed by the systems served by the LVAC system which are discussed in the following sections. 5.1.2.1 LVAC System Loads The loads which have to be supplied can be divided into two categories namely those loads which are supplied when the substation is connected to the grid (normal loads) and those supplies which need to be maintained when the connection to the grid is lost (essential loads), i.e. under abnormal or emergency conditions. The loads can also be further sub‐ divided into two types of load, load associated with the substation main plant and load required for “building services”. The following sections set out the requirements for “essential” loads and “non‐essential” loads, with the “normal” load being the sum of both. 5.1.2.2 Essential Loads As explained above, essential loads are those loads which will need to be supported when the normal AC supply from the grid system is not available. The LVAC distribution system must be designed to inherently segregate the essential and non‐essential loads, noting in 280

particular that many of these “building services” loads will be fed from distribution boards directly from the “essential bus” of the main LVAC board. These sub distribution boards must provide for the segregation of the “essential” load category from the “non‐essential” load category. The items listed below are for guidance and are not exhaustive. „ Fire protection supplies The fire detection and suppression systems applied to the substation must be supported by auxiliary supplies to ensure operation at all times and remain in service until the fire is extinguished and / or evacuation of the personnel is completed. Typically the fire protection systems would consist of: ‐ A water based fire systems for the suppression of fires in large oil containing equipment such as transformers and reactors ‐ Gaseous systems for other enclosed areas containing equipment such as switchgear, control and communication systems. (For more details see Section 4.9) „ Battery charger supplies The LVAC supplies to the battery charger under normal operation are continuously available and sized to allow the charger to recharge a depleted battery within the agreed time. The rating of the supply is closely coordinated with the design of the LVDC system and large batteries and short re‐charge times drive up the power and energy demands on the LVAC system. The LVDC system is designed to provide secure supplies for a designated period using the energy stored in the battery. During this period it is assumed that LVAC supplies are unavailable. In the event that LVAC power supplies are restored quickly (diesel start) the battery discharge will be minimal and the load on the LVAC system will remain low (float charge & standing load). Alternatively, in the event of loss of LVAC supplies, the restoration of LVAC supply may be delayed, should the diesel fail to start, possibly until the battery capacity has been used. „ Switchgear supplies The LVAC supplies required to the switchgear under abnormal conditions are limited. The supplies help maintain the switchgear in good operational condition and support the remote operation of the switchgear; it may not be essential for the heating and lighting supplies to be continuously available, provided the performance of the switchgear is unaffected but careful consideration is required. However, as it may be necessary to reconfigure the switchgear to assist with restoration of supplies the operational supplies are required. The systems supported may include: ‐ Anti‐condensation heating – normally on (may be thermostat or humidistat controlled) ‐ Cubicle lighting (normally off) ‐ CB mechanism spring charging (DC motors are an alternative) ‐ Disconnector drives (DC motors are an alternative) „ Transformers The LVAC supplies to the transformers may be considered as split between essential and non‐essential. The essential supplies are required to ensure that the equipment remains in serviceable condition when switched off and are not related directly to the on‐load function of the transformer. The systems supported may include: ‐ Mechanism and control kiosk anti‐condensation heating 281

Cubicle lighting Environmental control The environmental management of the substation accommodation is critical if the substation equipment is to be maintained in serviceable condition awaiting restoration of normal supplies. The LVAC supplies required for the environmental management systems under abnormal conditions are limited to protecting the equipment and personnel. The cooling load is limited to managing heat output from fixed loss sources such as battery chargers and relay panels such that the maximum operating temperature is not exceeded. Hence ventilation for systems which have load‐related losses may be stopped. Other systems which maintain clean dry conditions for equipment to prevent deterioration and unavailability for re‐connection should be supported. The systems supported may include: ‐ Air pressurisation and ventilation systems ‐ Limited heating for anti‐condensation purposes ‐ Drainage pumps Emergency accommodation In the potentially harsh environment associated with the offshore substation the safety and welfare of people must be paramount so heating and domestic services for the refuge area must be maintained under abnormal conditions. The load and duration will be determined by the number of people to be supported and the maximum duration of stay within the refuge. A typical duration is 18 hours but this may vary with the ruling statutory requirement, individual location and the operator’s preferences. Emergency and access lighting In order to provide for the safe movement of personnel a place of safety within the substation in abnormal conditions and to facilitate evacuation of the personnel from the platform dedicated emergency lighting is required. The control system, light levels, location and duration of the lighting will be determined by the safety assessments and may need to be considered in the overall LVAC demands depending on the particular system selected (stand alone self‐contained or centrally supported). Operational /repair The cause of loss of the normal LVAC supply may be related to the failure of a substation component but with properly designed redundant systems the probability of this being the case is low. However, it is considered prudent to ensure that items such as the substation crane and davit crane will need to remain operational to enable repair equipment and spares to be brought onto the platform. For installations having a single transmission connection, the probability of repair being required with depleted LVAC supplies is increased. Safety systems The majority of safety systems for offshore substations are derived from the systems used on other offshore installations and are well proven. The system performance requirements are dealt with in other sections of the document but from LVAC supply point of view the main issue is how the systems are supported under abnormal conditions. For systems which are self‐contained and incorporate their own back‐up power supply (battery / charger / inverter) the impact on the LVAC system (particularly energy storage) is small. Such systems include: ‐

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„

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‐ ‐ ‐ ‐

Public address system Navigation systems power supplies Video surveillance systems Communication systems

5.1.2.3 Non-Essential Loads „ Transformers If we consider the load associated with the plant, the largest individual loads will be associated with the transformers. The LVAC supplies to the transformers under normal operation are continuously available and sized to allow the rated performance of the transformers to be supported. The supplies are required to allow the transformers to be operated within their designed limits and in the case of cooling at substations designed for N‐1 security, are mainly required when one of the transformers is unavailable. The functions supported include: ‐ Cooling fan drives ‐ Oil pump drives ‐ Tap change drives As these operation‐related loads are not present when the main connection to the grid is lost then these loads can be considered as “non‐essential” loads. In the case of tap‐changer drives, the need to set the tap change to a specific position before re‐ energisation of the transmission feeders may change it to an essential load. „ Maintenance and testing supplies ‐ deck wash pumps ‐ welding and oil treatment socket outlets

5.1.3 LVAC System Operation 5.1.3.1 Normal LVAC Operation Under normal operational conditions the substation will be connected to the onshore transmission system by means of one or more export cables which provide a source of AC power. However the security of that LVAC supply is directly related to the number of transmission connections and the complexity (redundancy) provided in the substation LVAC system. As a consequence, it would be expected that the utilisation of any standby power systems would be considerably reduced as the number of transmission feeders increases. The LVAC system normally supplies all of the auxiliaries on the substation platform and the auxiliary loads of the substation equipment. There is usually no provision to support any auxiliary power loads associated with the wind turbine generators (WTG). In normal operation these derive their auxiliary power requirements from their main power connections to the substation (the array cables); however on loss of the connection to the grid substation or loss of the transmission connection to the main substation the WTG does not have a source of auxiliary power. Whilst not part of the substation LVAC demands and in many cases a commercially separate system it may be worth considering if benefit could be gained from consideration of the WTG and substation as an entity under abnormal conditions. (Refer also to Section 3.4.1.2)

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5.1.3.2 Source of Auxiliary Supply In order to provide this 400V supply, auxiliary transformers are required to step the voltage down from the (typically) 36 kV voltage used for the connection of the WTGs by inter array cables. The accommodation of large equipment on the offshore platform is expensive so the design, location and connection of these auxiliary transformers from both physical and functional aspects need to be considered when designing the auxiliary supply system. The 36 kV system interconnecting the main transformers and the WTG step‐up transformers is usually connected in delta and hence there is a need to provide facilities to provide a reference earth for the system. (Refer to Section 3.4.1) It will generally be found that sourcing the LVAC supplies from earthing auxiliary transformers (EAT) will provide the optimum solution in terms of space and weight. The number and connection of the earthing transformers required will depend on the substation connection arrangements and for larger installations it may not be practicable to parallel the secondary windings of the main transformers. In general one earthing transformer will be required associated with each secondary winding of the main transformers. This will usually provide sufficient redundancy in the source of supplies for the LVAC system. The transformer will normally have to be capable of supplying the normal (essential and the non essential) load of the substation. One solution frequently adopted is to ensure that there is an EAT rated to carry 100% of the normal load connected to the secondary side of each main transformer. For other configurations, where for operational reasons, more than two EATs are required the individual units may be rated such that N‐1 security is achieved. This will ensure that if at least one of the main transformers is in service then the auxiliary loads can be supported. 5.1.3.3 Separation of “Essential” and “Non Essential” Loads The separation of the “essential” loads from the “non essential” loads is usually achieved by having a separate section of LVAC board connected by a bus section switch. The physical design of the switchboard and isolation facilities must ensure that a fault in the bus section circuit breaker panel does not result in the loss of of the “essential” section of the board. In some instances it may be considered prudent to have the “essential” board completely segregated from the “non essential” board to avoid an incident affecting the main LVAC board from also taking out the “essential” services board. Under normal operating conditions the bus section switch is closed and the two types of load are fed by one of the auxiliary transformers. If the supply from the selected earthing auxiliary transformer is lost then an automatic changeover will take place to one of the other available earthing auxiliary transformers. If there is no available auxiliary transformer then the bus section will be automatically opened to separate the “essential” part of the switchboard from the “non essential” part and an emergency generator connected to the “essential” part will be started to supply the load. In the extreme case, it may be necessary to consider duplication of the “essential” services board for safety critical functions, with each “essential” board fed by one of the earthing auxiliary transformers. 5.1.3.4 Abnormal LVAC System Operation Under abnormal operating conditions the LVAC loads must be provided by a back up supply. In onshore substations this may be provided from the local distribution network. For 284

offshore substations this option is unavailable and the back‐up generator needs to be rated to supply the whole of the “essential” load from within the substation. The changeover and starting arrangements used for the back‐up supply system must be robust and monitored to provide indication advance warning of any condition which may prevent its immediate start‐ up and loading in the event of a main supply failure. In each case both the power and energy storage system must be considered. The back‐up source may be selected from a number of options, for example: „ Diesel Diesel generators are usually only rated to be able to supply approximately 60% of their rated load immediately after starting. In order to avoid oversizing the diesel generator a control system which sequences the connection of loads after loss of supply may have to be considered. Furthermore, diesels normally will only run effectively if the load is above a certain minimum value typically 30% of the rated value of the generator and this must be to be taken into account in the design of the system. The quantity of diesel fuel which will be required depends upon the duration for which the “essential” loads have to be maintained. The typical guideline in the DNV safety standard seems to indicate 18 hours as a minimum but individual operators may specify longer periods to meet their requirements, whilst still remembering the importance of keeping the space and weight down. „ Gas turbine Gas turbine generators are a direct alternative to diesel engine driven generators and whilst they offer an improved power to weight ratio, their specific fuel consumption, sensitivity to fuel quality and maintenance requirements need to be considered „ Wave generator A small wave generator system could be used as the back‐up energy supply which may save weight and space on the platform and reduce the fire risk from diesel storage by reducing the volume required. Care would be needed in assessing the available energy to ensure that the total available energy met the abnormal operational needs of the substation. „ Fuel cell This is a relatively new and unproven technology which may offer advantages in the future when reliability, fuel characteristic and fuel storage issues are well developed. „ Inverter backed AC supplies This would require energy storage in the form of batteries, which offer significantly lower energy densities than hydrocarbon fuels. Limiting reliance on inverter / battery systems should be considered.

5.1.4

Construction and Installation

5.1.4.1 LVAC Board Construction The configuration and construction of the LVAC system switchboard can have a significant impact on the overall availability of auxiliary power supplies. In assessing the configuration and construction the failure modes and consequences of the failure must be considered to achieve the performance required. „ LVAC single line diagram ‐ Number of busbar sections ‐ Position of standby supply incomer in relation to the normal infeeds 285

Bus section or interconnector ‐ Automation LVAC board – physical construction ‐ Separate boards for “essential “and “non‐essential” loads ‐ Segregation of the Bus section ‐ Construction class ‐ Degree of internal separation ‐ Access for cable connection ‐ Use of MCCB or fuse‐switches Supplies segregation ‐ Duplicate feeders to each essential load ‐ Provide a full “system 1” / “system 2” supply system ‐

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5.1.4.2 LVAC Cable Systems and Routing The complexity, length and installation details for cable systems are driven by the supply system required and the physical relationships between the elements of the systems and the equipment the system supports. The integrated design of the substation LVAC connections considering both substation equipment and “building services” offers the opportunity to minimize the number and length of the connections, saving cost, weight and installation time. Wherever practicable, auxiliary power supplies supporting “redundant” functions should be segregated, using diverse cable routes to avoid a single incident taking out both supplies. For example, where there are duplicate battery chargers the AC cables feeding them should be run on segregated routes. The design must also consider the provision of facilities for repair or replacement of cables in the event of a failure, particularly where routing results in restricted access. 5.1.4.3 Protection, Control and Automation for the LVAC System The LVAC system and its associated protection should be designed such that a fault on any part of the system can be cleared without taking out of service any un‐faulted equipment or adversely affecting the availability of the main transmission connections. This will require careful selection of the protection type, protection devices, and the frame size of the equipment as well as the Moulded Case Circuit Breaker (MCCB), Miniature Circuit Breaker (MCB) or fuse ratings protecting the load feeders. The LVAC board and back up supply system needs to be fully automated to ensure that a supply can be provided to “essential” loads at all times. This needs to be coordinated with any local “supply changeover” arrangements. It also needs to be interlocked to avoid paralleling of the diesel generator with the system. Protection systems for the generating sets should only cause tripping for faults which will cause immediate damage to the equipment. Other devices such as overload protection should only give an alarm initially with sufficient performance and time margins for corrective actions to be initiated manually by remote control or by automated systems if required. Sufficient information relating to the function of the LVAC system should be provided to the onshore control centre to allow operational decisions and corrective actions to be taken. A limited level of control necessary to manage the system in the event of failure of the automatic systems should be considered.

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The operational information provided, should be supplemented by a remote engineering / maintenance investigation facility to allow additional information to be collected and used to target support and maintenance tasks.

5.1.5

Black Start Capability

When the wind power plant is being installed initially there will be no grid supply. This is effectively the same condition as when the grid supply has been lost during service. Under these conditions the back‐up generator will have to feed the “essential” loads, possibly for a period of time much greater than the designed “abnormal operation duration”. For testing purposes, it may be necessary for the back‐up generator to supply a limited additional load, such as transformer cooling fans, for a short period. When deciding on the “essential” loads all of the loads required under a black start condition should be taken into account.

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Figure 5‐1. LVAC derived from collection system busbars 288

Figure 5‐2. LVAC derived from Main transformer LV connections 289

Figure 5‐3. Centralised UPS from essential services boards 290

5.2

DC Supplies

5.2.1

LVDC Supplies

In order to operate the equipment within the substation a suitably rated Low Voltage Direct Current (LVDC) supply is required, distributed throughout the substation to feed the associated loads. Typically this would be a secure 125V DC supply using a combination of storage batteries and chargers. The LVDC system is required to deliver the power under a range of operating modes and have the ability to store the energy required by the substation to provide for the operational needs of the substation both whilst LVAC supplies are available and during the “changeover period” when LVAC supplies may be disrupted. The energy stored can be considered a consumable with a limited storage capacity determined by the battery capacity and this capacity needs to be carefully selected based on the loads, the duration of “standby” operation and the performance of the LVAC system. Typically, the system would be designed such that if the substation LVAC supplies were available, all steady state LVDC requirements would be supplied from the charging system and the batteries would be maintained in a fully charged condition. Transient or short term temporary LVDC loads such as tripping of circuit breakers in excess of the charger rated output would be supplied from the battery. In the operational condition when the LVAC supply (from any source) was unavailable it would be necessary to consider the energy storage capacity required. To minimise the required battery capacity it is possible to consider the segregation of LVDC loads required for safety systems from purely operational LVDC loads. The capacity of the system and its energy storage requirements are determined by the loads served by the LVDC system and the dependability of the LVAC system which are discussed in the following sections. Typically, for onshore substations, the LVDC supply system consists of one or two batteries connected to one or two battery chargers which are connected to the load centres. Several voltage levels can be used for the battery such as 220V, 125V, 110V, 48V or 30 V depending on factors such as space available, interference and voltage regulation permitted. The DC system configuration used depends on the reliability requirements from the DC system. Several factors dictate the reliability requirements of a DC power supply in an offshore substation; these factors include the important role the offshore substation performs in delivering the generated power from the offshore generators to the system, the remote location of the substation, the high cost investment of the substation equipment and the high level of protection required for the equipment. A failure of the DC supplies during a fault condition in the substation or out on the connecting lines can result in a catastrophic failure and a possible loss of the substation.

5.2.2

LVDC System Loads

For onshore substations where space and weight are relatively unimportant, all LVDC loads are considered in the same way i.e. as essential loads. This arrangement is normally facilitated by the provision of a redundant fully rated system capable of supplying the total site demand for the defined standby period. For offshore applications where space and weight are important and access difficulties may dictate the “standby” periods are significantly longer, the loads which have to be supplied may be divided into two categories; namely those loads which are supplied when the LVDC system is energised from the LVAC system (normal loads) and those supplies which need to 291

be maintained when the LVAC supply is lost (essential loads), i.e. under abnormal or emergency conditions. This approach would allow the extended standby periods to be supported with significantly smaller battery capacity. The following sections set out the requirements for “essential” loads and “non‐essential” loads, with the “normal” load being the sum of both. 5.2.2.1 LVDC Essential Maintained Loads As explained above, essential loads are those loads which will need to be supported at all times irrespective of the availability of LVAC supply to the battery chargers. The LVDC distribution system must be designed to inherently segregate the essential and non‐ essential loads. The items listed below are for guidance and are not exhaustive. „ Communications, Control and SCADA ‐ Communications equipment ‐ DCS station level equipment ‐ DCS bay level equipment ‐ SCADA Remote terminal units „ Protection supplies – Substation auxiliary systems The electrical fault detection and isolation systems applied to the substation must be supported by LVDC auxiliary supplies to ensure operation at all times and remain in service. Typically the protection systems would consist of: ‐ Protection relays ‐ Tripping systems ‐ Circuit breakers ‐ Indicating lights ‐ Auxiliary relays „ Switchgear supplies – Substation auxiliary systems The LVDC supplies required to the switchgear under abnormal conditions are limited. However, as it may be necessary to reconfigure the switchgear to assist with restoration of supplies the operational supplies are required. The systems supported may include: ‐ Closing systems ‐ Tripping systems ‐ CB mechanism spring charging ‐ Disconnector drives „ Emergency and access lighting In order to provide for the safe movement of personnel a place of safety within the substation in abnormal conditions and to facilitate evacuation of the personnel from the platform dedicated emergency lighting is required. The control system, light levels, location and duration of the lighting will be determined by the safety assessments and may need to be considered in the overall LVDC demands depending on the particular system selected (stand alone self‐contained of centrally supported). „ Safety systems The offshore substation, in common with other large offshore structures, is required to have a number of safety systems designed to protect the structure, personnel and vessels in the vicinity of the substation. The majority of safety systems for offshore substations are derived from the systems used on other offshore installations and are well proven. The system performance requirements are dealt with in other sections of the document but 292

from LVDC supply point of view the main issue is how the systems are supported under abnormal conditions. For systems which are self‐contained and incorporate their own back‐ up power supply (battery / charger / inverter) the impact on the LVDC system (particularly energy storage) is small. Such systems include: „ Public address system „ Navigation systems power supplies „ Video surveillance systems However, consideration may be given to providing energy storage capacity for these systems from the central battery system rather than from dedicated individual batteries if this increases availability and simplifies and reduces the accommodation requirements. 5.2.2.2 LVDC Operational Loads As explained above, Operational loads are those loads which will need to be supported only when the HV or MV systems on the platform are energised. „ Protection supplies – Substation High Voltage and Medium voltage systems In the condition when all LVAC supplies are unavailable there is very high probability that the substation is completely isolated from all sources of AC power i.e. the onshore connection is lost (hence the normal LVAC supply is unavailable), the WTGs are unable to generate and the LVAC back‐up system is unavailable (e g. because the diesel has failed to start). Under these circumstances the electrical fault detection and isolation systems applied to the HV and MV systems are not required. Modern numerical relays have a significant auxiliary power demand even when quiescent and constitute a continuous drain on the storage batteries. Treating these loads as “non‐ essential” under dead platform conditions would assist in reducing the size of batteries required and /or allow longer standby times for a given battery size. The substation must be supported by LVDC auxiliary supplies to ensure operation when required to be available for service. Typically the protection systems would consist of: ‐ Protection relays ‐ Tripping systems ‐ Indicating lights, ‐ Auxiliary relays, ‐ Annunciator „ Switchgear supplies ‐ Substation High Voltage and Medium voltage systems The LVDC supplies required to the switchgear under abnormal conditions are limited. However, as it may be necessary to reconfigure the switchgear to assist with restoration of supplies the operational supplies are required. The systems supported may include: ‐ Tripping systems ‐ CB mechanism spring charging (AC motors are an alternative) ‐ Disconnector drives (AC motors are an alternative) ¾ Maintenance and testing supplies „

Test supplies for protection and control systems,

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5.2.3

LVDC System Operation

5.2.3.1 Normal LVDC Operation Under normal operating conditions the substation will be connected to the onshore transmission system by means of one or more export cables which provide a source of AC auxiliary power. Alternatively the LVAC back‐up systems also provide a power source which allows the LVDC system to remain in normal operation. The LVDC system normally supplies all of the direct current auxiliaries on the substation platform. There is usually no provision to support any direct current auxiliary power loads associated with the wind turbine generators (WTG). In normal operation these derive their DC auxiliary power requirements from their main power connections to the substation (the array cables); however on loss of the connection to the grid substation or loss of the transmission connection to the main substation the WTG does not have a source of DC auxiliary power other than that which is stored in the WTG local LVDC system. 5.2.3.2 Source of Auxiliary Supply for Battery Charging The battery charger supplies are derived from the LVAC system installed within the substation which are described in Section 5.1.2.2 of this brochure 5.2.3.3 Separation of “Essential” and “Non Essential” Loads The separation of the “essential” loads from the “non essential” loads in LVDC systems is unusual and is not done in on‐shore substations where saving weight and space is not so important, but may be achieved simply by having separate sections of LVDC boards connected by bus section switches. The physical design of the switchboard and isolation facilities must ensure that a fault in the bus section switch panel does not result in the unavailability of the “essential” section of the board. Alternatively, the essential load switchboard may be supplied from duplicate battery systems using “diode paralleling” to ensure that a single battery failure does not adversely affect the essential supplies. In some instances it may be considered prudent to have the “essential” board completely segregated from the “non essential” board to avoid an incident affecting the main LVDC board from also taking out the “essential” services board. 5.2.3.4 Abnormal LVDC System Operation Under abnormal conditions the LVDC loads must be provided by the battery system rather than the “charging system”. For onshore substations the battery system is normally rated to supply the whole of the LVDC load as there is no differentiation between LVDC load types. In the case of offshore substations where long standby (no LVAC supply available) periods are required there is a case for considering segregation of loads. The scheme used for transition from “charger fed” to “battery fed” must be robust and monitored to provide indication of potential problems. On restoration of supplies to chargers, the reinstatement of supplies to all DC loads must be monitored, for example confirming all DC supply supervision systems resetting to indicate supplies available. The energy source (battery) is selected based on a number of criteria: „ Energy storage capacity required ‐ Loads to be supported ‐ Redundancy provided 294

‐ ‐ ‐ „ ‐

‐ ‐ „ ‐ ‐ ‐ „ ‐ ‐ ‐ ‐ ‐ „ „

Restoration of LVAC supplies Time taken to mobilize and access the substation Spares availability Storage batteries ‐ Type Plante cells ‐ high maintenance, long life, additional costs for explosion proof lighting, acid spillage containment, etc. Valve Regulated Sealed Lead Acid – low maintenance but limited life (15 years) Nickel – Cadmium – high maintenance, robust, long life, high cost Storage batteries Location Segregated from other equipment Ease of access for replacement Incorporated with Protection and control Voltages 220V 125V 110V ‐ may be derived from, higher voltage by DC/DC converters 48V ‐ may be derived from, higher voltage by DC/DC converters 30V ‐ may be derived from, higher voltage by DC/DC converters Other energy storage devices Relationship between DC and LVAC system

5.2.4

Construction and Installation

5.2.4.1 LVDC Board Construction The configuration and construction of the LVDC system switchboard can have a significant impact on the overall availability of direct current auxiliary power supplies. In assessing the configuration and construction the failure modes and consequences of the failure must be considered to achieve the performance required. „ LVDC single line diagram ‐ Number of chargers ‐ Number of batteries ‐ Number of busbar sections on the distribution board ‐ Position of DC supply incomer ‐ Cross connection facilities ‐ Automation „ LVDC board – physical construction ‐ Separate boards System 1 and System 2 and for “essential “and “non‐essential” loads ‐ Segregation of the coupling switch ‐ Construction class ‐ Degree of internal separation ‐ Access for cable connection ‐ Use of MCCB or fuse‐switches ‐ Modular construction „ Supplies segregation ‐ Duplicate feeders to each essential load ‐ Provide a full “system 1” / “system 2” supply system

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5.2.4.2 LVDC Cable Systems and Routing The complexity, length and installation details for cable systems are driven by the supply system required and the physical relationships between the elements of the systems and the equipment the system supports. Wherever practicable, auxiliary power supplies supporting “redundant” functions should be segregated, using diverse cable routes to avoid a single incident taking out both supplies. For example, where there are duplicate relay panel supplies the DC cables feeding them should be run on segregated routes. The design must also consider the provision of facilities for repair or replacement of cables in the event of a failure, particularly where routing results in restricted access. 5.2.4.3 Protection, Control and Automation for the LVDC System The LVDC system and its associated protection should be designed such that a fault on any part of the system can be cleared without taking out of service any un‐faulted equipment or adversely affecting the availability of the main transmission connections. This will require careful selection of the protection type, protection devices, and the frame size of the equipment as well as the Moulded Case Circuit Breaker (MCCB), Miniature Circuit Breaker (MCB) or fuse ratings protecting the load feeders. The LVDC board and back up supply system needs to be fully automated to ensure that a supply can be provided to “essential” loads at all times and must be coordinated with any local “supply changeover” arrangements. Sufficient information relating to the function of the LVDC system should be provided to the onshore control centre to allow operational decisions to be taken and corrective actions taken. A limited level of control necessary to manage the system in the event of failure of the automatic systems should be considered. The operational information provided, should be supplemented by a remote engineering / maintenance investigation facility to allow additional information to be collected and used to target support and maintenance tasks. When deciding on the “essential” loads all of the loads required under a black start condition should be taken into account

5.2.5

The DC Supplies One Line Diagram

To achieve high reliability for the DC supply system, a redundant two‐battery system is required. The system consists of two equally rated batteries, the associated chargers and the other equipment that is required for system operations and maintenance. Both battery systems are connected to the load via a diode system. A loss of any of the battery systems will not affect substation operation, since the load will be served by the un‐faulted battery system. The above described system is represented by the one line diagram shown below.

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Figure 5‐4. Fully redundant LVAC / LVDC system 297

5.3

Protection

5.3.1

Statement of Requirements

The protection arrangements must be considered in the context of the cost and inconvenience of primary plant replacement in offshore substations and consideration given to systems which act to minimize the damage caused by faults. Traditionally the systems have reacted to a primary fault and disconnected the affected item, with the primary objective of protecting the remaining healthy equipment and the system from the effects of the fault. Taking into account the cost of replacement it may be beneficial to consider an increase in condition monitoring or “predictive systems” to minimize major repairs. The harsh environmental conditions experienced offshore must also be taken into account when selecting the protection equipment, its mounting and housing and the micro‐climate into which it is to be installed. It may be that equipment designed for use in on‐shore locations is not suitable for offshore applications, irrespective of the installation arrangements and additional protection or design changes to the protection equipment may be required. Where the protection system interfaces with the onshore substation, the relevant Grid Code needs to be considered to ensure that fault clearance times are compliant.

5.3.2

Plant Protection

The protection systems installed on offshore substation are required to detect faults and initiate disconnection of faulted equipment across three subsystems:‐ The transmission connection to the on‐shore substation which may comprise: ‐ Export cables ‐ EHV / MV transformers ‐ EHV shunt reactors ‐ EHV switchgear and busbars The power collection system from the generators ‐ Protection of MV cables forming the collection system from each array ‐ MV switchgear and busbars ‐ Wind turbine generator transformers ‐ MV Reactive compensation The auxiliary power system supplying the services of the platform ‐ Cable systems ‐ Auxiliary transformers ‐ Generators ‐ MV and LV switchgear and busbars

5.3.3

System Protection

In addition to the protection of equipment the system should also provide for the detection of faults which put the main transmission system at risk, such as faults on the offshore substation which are not detected or cleared by protection and switchgear operations local to the faulted equipment. For this reason the following facilities also need to be considered. ‐ Circuit breaker fail ‐ Remote back‐up protection ‐ Protection signalling ‐ Remote non‐unit protection

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5.3.4

Operation with Degraded Communications

Consideration needs to be given to the type of communication links that are available, the redundancy and the distance involved, which are considered under another section 5.7, when identifying protection systems. The protection will need to achieve fast clearance times and correct discrimination for faults, which will require the use of communications channels to the onshore substation. Should these communication channels become degraded or lost completely the protection will still need to operate correctly, and not trip unnecessarily, and clear local faults as necessary. Modern multi functional unit protection relays can introduce an impedance protection scheme, following the loss of communications channels, which allows for fault clearance, but may have limited system discrimination. ‐ Loss of communications channel(s) ‐ Operational actions

5.3.5

Particular Technical and Protection Application Issues for Offshore Connections

5.3.5.1 General Requirements for Protection Due to the high dependence of the substation on the availability and correct functioning of the protection systems together with the remote (sometimes inaccessible) location the level of redundancy provided needs to be carefully considered. The level of redundancy provided will need to be assessed for each particular system taking into account voltage level, performance, availability requirements, operational rules and cost. For example, the use of dual main protection has the advantage that should one device fail there will be a backup of equal performance allowing extended operation periods with one system unavailable, until access for repair is possible. Consideration should be given to common mode failures and long repair/replacement times due to accessibility restrictions. A dual main scheme should ideally be implemented in two discrete devices utilising alternate protection philosophies or implemented in different manufacturer platforms. For transmission voltages and critical circuits two separate and independent tripping channels, each with completely independent supervised power supplies, separate and independent trip circuits and separate and independent trip coils, i.e. on the associated circuit breakers, should be employed. The two separate tripping channels should be provided with independent supervised auxiliary supplies, so that should a fault occur an alarm will be raised. The trip circuits should also be supervised in the CB open and closed positions, with supervision of the pre‐closing circuit, i.e. full trip circuit continuity supervision. Failure of protection supplies, tripping supplies or trip circuit continuity should be independently alarmed. For collector circuits single tripping channels could be acceptable on the condition that back‐up protection provided by an upstream independent protection system should ensure that the duty on all plant is maintained within plant ratings. The requirements for auxiliary supply and trip circuit monitoring are as detailed above. Therefore no single failure on the protection system, including auxiliary relay failure, supply circuit failure, trip circuit failure etc, should prevent fault clearance. 5.3.5.2 Protection Technology In order to maximise the cost‐benefit of the protection in all groups and to reduce lifetime costs, all protection relays should be of numerical design wherever practical. Numerical

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relays provide the option to utilise developed logic functions to help overcome the challenges presented by the setting problems with offshore wind power plants. The main numerical relays should offer instrumentation, disturbance recording and event logging functions in addition to providing protection. Routine test requirements should be limited to basic function testing only, through the provision of comprehensive, continuous self‐monitoring with alarm and diagnostic functions. Numerical relays have the facility for connection to a communications network often referred to as the station bus, to allow the complete relay scheme to be interfaced to a central computer or laptop. This facility enables the remote interrogation of all numerical relays and schemes connected to the station bus to monitor and extract recorded data (including settings, measurement parameters, and disturbance records). It also allows for the remote adjustment of relay settings if required. When selecting protection relays, it is recommended that consideration be given to the minimum service life, which is typically 15 years and that variations in model types are reduced to avoid the need to manage strategic spares for various hardware and software versions over the stated minimum service life. 5.3.5.3 Protection Discrimination On the occurrence of an electrical fault on the EHV connection, collection system and auxiliary power system, the high speed discriminating protection systems (main protection) should rapidly detect the fault and initiate the opening of only those circuit breakers which are necessary to disconnect the faulted plant or circuit from the network. Protection equipment associated with adjacent plant or circuits may detect the fault, but there must be discrimination between this protection and that of the faulted plant or circuit. Time delayed tripping should not occur except where main protection has failed to clear a fault or where plant damage would otherwise occur. All back‐up protection systems should be able to discriminate with main protection systems, circuit breaker fail protection and with other back‐up protection systems installed elsewhere on the electrical system. 5.3.5.4 Protection Testing Due to the high costs involved in sending engineers offshore, the amount of testing required offshore should be kept to a minimum. Therefore the factory acceptance tests should be as extensive as possible to avoid the need to retest offshore. It is suggested that offshore testing is restricted to overlapping tests to ensure the interfaces and all new connections are correct and that no changes have occurred during transportation to the final position, by means of pre‐approved automated test scripts utilising computerised test sets to minimise test time. 5.3.5.5 Test and Isolation Facilities It is desirable that each functional protection relay is so arranged that operational and calibration checks can be carried out with the associated primary circuit(s) in service. The testing facilities should allow comprehensive testing to be performed in the minimum time with the minimum disturbance to connections or settings. Adequate test facilities need to be provided within the protection scheme to enable the protection and control equipment to be tested from the front of the protection equipment panel with the primary circuit(s) in service and ideally without opening the cubicle.

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Numerical relays usually include continuous self‐monitoring and supervision of all parts of the relay hardware, firmware and software. An alarm should be given for any detected failure. Adequate facilities need to be provided, preferably at the front of each protection equipment panel, to isolate all DC and AC incoming and outgoing circuits so that work may be carried out on the equipment with complete safety for personnel and without loss of security in the operation of the switching station. 5.3.5.6 Grouping and Accommodation of Protection It is recommended that protection and control cubicles should be of front access, swing‐rack design, with glazed and sealed front doors through which necessary equipment indications can be observed. The compact nature of numerical relays allows for a number of protection systems to be installed in one cubicle which assists in the reduction of accommodation volume on the platform. Hence, the protection and control equipment for several circuits may be accommodated within a common cubicle, but there should be proper segregation of wiring and terminal blocks to facilitate scheme testing and maintenance for one circuit without and risk of affecting scheme operation of other circuits whilst on load. The operational life of numerical devices is limited by a number of factors and it is likely that the protection systems used on offshore platforms will need to be replaced after 10‐15 years service. This replacement will have to take place offshore under less than ideal conditions therefore it is important to maximize the amount of pre‐work / testing that can be achieved on‐shore and that the installation design allows for the efficient replacement of the system. 5.3.5.7 Environmental Requirements For equipment installed in dedicated equipment rooms protection equipment complying with IEC standards may be considered generally acceptable for offshore applications. The notable exception which may need to be considered is the ability of the equipment to withstand vibration and shock loads generated by weather, waves and minor impact from docking vessels.

5.3.6

Wind Power Plant Networks

The typical single line diagrams for wind power plant networks have been developed in Section 2 of this brochure. The point of common coupling to the onshore network may be at either the transmission voltage such as 380/400 kV or at sub transmission voltage typically 132/150 kV. Generally this does not have much effect upon the protection on the offshore substation however having an extra voltage level for the transmission connected wind power plants may make the grading of the back‐up protection harder to achieve within the required timescales. The offshore substation will therefore for this section be considered as operating at a highest voltage of 145 (132 kV), having some sub transmission switchgear which may or may not include a circuit breaker, one or more transformers from this voltage to 33 kV , a 36 kV switchboard system and a number of 36 kV inter array cable circuits. In order to understand and set the protection on the substation it is necessary to consider the protection at the wind turbines and the onshore connection substation.

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5.3.6.1 Main Protections The protection systems for the primary EHV transmission system must provide fast and highly dependable clearance of any electrical fault in order to minimise the duration of severe voltage dips and to avoid loss of transmission system capacity due to back‐up tripping of any other circuits. A forced shutdown of any circuit for a single item of protection equipment failure should not be required. For a limited period, it should be possible to operate the EHV circuit with only one group of protection in service, while the other group is out of service for testing or while it is awaiting repair. During this period any fault must still be cleared quickly and the plant must still be protected against damage if exposed to abnormal operating conditions. To meet these dependability and redundancy requirements, all EHV plant and circuits should be provided with two fully independent, high‐speed protection systems for detecting and clearing electrical faults. Each independent protection group should also be driven from independent current transformers and independent VT secondary circuits. In general the main protections within the wind power plant network will be differential protections. For example the 132 kV Feeders will normally use numerical differential protection with fibre optic communications. 132 kV busbar or connections protection may use conventional high or low impedance protection or directional blocking. The Main Power Transformers will typically have biased differential protection. For onshore protection systems, it is normal practice to provide only one Main protection at sub‐transmission voltages however due to the remote location and difficult access two fully independent Main protection systems should be considered, operating in one out of two mode. However, for some plant differential protection is not practical for the main protection. For example it is not practical or economic to provide differential protection for the WTG step up transformers located in the transition piece, 36 kV collection array cables and sometimes for the 36 kV busbar protection. For these circuits overcurrent and earth fault which may be either directional or non directional as required will be used as the Main protection. The protection systems should provide comprehensive records for trip and alarm conditions, with local indications of which element has initiated a trip or alarm and of voltage and current vector parameters at the time of trip initiation. Voltage and current waveform disturbance recording and event‐logging should be included as part of the protection system. 5.3.6.2 Back Up Protection It is recommended that back‐up protection be provided to trip protected plant and circuits in the event of a sustained external fault condition or a sustained power system abnormality that would otherwise damage or significantly reduce the life expectancy of the protected plant. This will normally be achieved using overcurrent and earth fault protection or the plain distance elements integral with numerical differential protection. However, although the direction of real power flow is normally from the wind turbines to the grid the protection grading is set to achieve coordination from the turbines to the Grid Connection Point in much the same way as the back‐up protection in an industrial network. Furthermore, the back‐up protection is also set to enable it to clear a fault in the event of failure of the protection on the next zone downstream item of plant

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Each set of feeder protection should include remote back‐up protection for busbars to ensure that, in the event of busbar protection failure, a remote‐end busbar fault will be cleared within the switchgear internal arcing fault withstand time.

5.3.7

Unusual Settings Considerations

5.3.7.1 Normal Direction of Power Flow Unlike industrial applications where power flow is from the Grid Connection to the lower voltages and machines in a Wind Power plant the real power will flow from the turbines towards the Grid. The turbines however will not generate if they do not have a grid connection. Generally, the level of the fault current in‐feed is much greater from the grid than that from the WTGs depending upon the type of wind turbine generators being used This fact can be used to achieve discrimination of the direction of the fault or can be used together with directional relays if required. 5.3.7.2 Performance Similar to a Generator Within the Grid Codes in many countries a wind power plant or power park module if it is greater in capacity than 100 MW has to perform in the same way as a generator. This puts a requirement on the generator to be able to ride through faults and remain connected to the grid. This fault ride through requirement means that all large wind power plants are required to aid system stability by remaining connected during disturbances and contributing to fault current. 5.3.7.3 Increased Potential for Low Fault Currents Within the wind power plant there are relatively long undersea cables both at the sub transmission voltage (132 kV or 150 kV) and also at the generation collection voltage typically 36 kV. This may be exacerbated by the wind power plant being connected to the Distribution Network Operator (DNO) networks. This can lead to the fault currents, particularly on the 36 kV network being very low and these can in some cases even be less than the load current. 5.3.7.4 Turbine Reactive Power Capabilities/Reactive Power Compensation The wind power plant will probably contain long export cables which generate reactive power which must be compensated. Most Wind Turbines have a broad reactive capability in steady state giving them the capability to both generate and absorb reactive power. In some wind power plant designs use is made of this reactive power capability to minimize the amount of extra compensation plant to be connected to the network. This can lead to the direction of reactive power flow being the same as the direction of reactive fault current which at low fault currents can make it difficult to discriminate between the two. 5.3.7.5 Fault Clearance Time Required at the PCC The Grid Code or site specific connection conditions may specify the maximum fault clearance times for back‐up protection at the Connection Point which are less than one second. Achieving this requirement while preserving coordination across the wind power plant is a challenge as there are many steps down stream

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5.3.7.6 Turbine Transformer Protection The protection of the wind turbine generator is usually specified and set by the Turbine Manufacturer and will usually include overcurrent, earth fault, overload, under voltage, over voltage, under frequency and over frequency. The Transition Piece LV will often also feed an auxiliary transformer which will typically be protected by an MCCB This protection is designed specifically to look after the WTG and its converters. Each Individual WTG is connected to the collection array by a small step‐up transformer. These transformers are typically 3‐5MVA and 500‐1000V/33 kV with HV delta connected and LV star connected. On the HV side there is a circuit breaker. In many schemes the purpose of this 36 kV CB is purely to protect for step up transformer faults and it may have no remote control facilities. It is not usual to have CBs in the cable connections often there may be only disconnectors or even only cable plugs. The main protection for the transformer is provided by overcurrent and earth fault using a definite time characteristic. This protection will also provide back up for un‐cleared LV faults. The delta winding acts as a zero sequence trap –hence LV earth faults can only be detected by HV overcurrent. If the LV Earth Fault Levels are low it may be necessary to add an additional earth fault element in the LV star point neutral Usually, the 36 kV system has delta connected transformers on each wind turbine generator; also, the main in‐feed transformers from the grid also have delta windings on the 33 kV side. The 36 kV system is usually earthed through an earthing transformer which will be arranged to limit the earth fault current to approximately 750 – 1000A Hence the values of earth fault current on the 36 kV system are low.

5.3.8

Collection Array Protection

The power from the individual WTGs are collected via string or tree connections at 36 kV. Typically 6‐10 turbines would be connected to one string. (See Section 2.1.2.1). Frequently there will not be any circuit breakers in the cable circuits at the WTG transition pieces, CBs only being in the transformer connection. Fault passage indicators may be installed at the WTG locations to detect where in the string a fault has occurred. Some strings may be connected at their ends although they are not usually run as a ring. The connection is to provide conditioning supplies to generators on one string beyond a fault point. This can make the protection reach required for a string very long. The main protection for the strings is usually provided by overcurrent and earth fault relays. However, the use of distance protection with fault locators is becoming more common. The benefit of distance protection is that it provides protection for the cable, with backup protection to the WTG overcurrent and earth fault and Negative phase sequence overcurrent protection to detect un‐cleared earth faults on LV side of the WTG. Although the flow of real power is from the turbines to the offshore substation the main fault in‐feed comes from the grid system towards the generators. Non directional relays can often be used, depending upon the type of WTG being used, as the magnitude of fault current flowing towards the WTGs is larger than the fault current flowing towards the busbars from the WTGs.

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VA

VA

IA

IA =VBC

=VBC

Figure 5‐5. Real Power Flow towards circuit

Figure 5‐6. Reactive power away from circuit VA

VA

IA-Reactive

IA

= VBC

=VBC IA-Total IA-Real

Figure 5‐7. Reactive power towards circuit

Figure 5‐8. Load flow looks like fault

However for long strings the fault current at the far end may be low and for back up purposes for LV faults it will often require directional overcurrent and earth fault relays. However, the use of directional relays may not provide the answer to all of the problems. Depending on the compensation design for the wind power plant the flow of reactive current may be towards the WTGs making it difficult to differentiate between low fault currents and load currents making it necessary to use other techniques. (See diagrams 5‐5 to 5‐8) Depending upon the string configuration, See Section 2.1.2.1, a number of techniques can be used to energise the string. Each WTG CB could be closed in turn, or groups of WTG’s could be energised together. Usually the HV circuit breakers at each WTG will be closed when the string is energised. This means that up to ten transformers will be energised simultaneously. Consequently 2nd harmonic blocking has to be employed on the relays to avoid tripping on these transformer inrush currents. The protection relay for the Individual String is located in the Platform 36 kV Boards. Each relay is responsible for clearing faults located on its own string using a definite time characteristic. The relay also provides back‐up protection to the Transition Piece relays which must cover for the most remote WTG The protection provided may be either directional or non directional over current together with either directional or non directional earth fault. In order to be able to provide back‐up protection for faults on the LV side of the WTG transformers certain special features have to be employed. As explained in the preceding paragraphs it is not possible to set the directional overcurrent relays to very low settings. 305

Consequently for unbalanced faults use is made of the negative sequence protection feature in the relays to enable settings sensitive enough for these faults to be detected. However for balanced three phase faults this solution will not work. In this case the relay is equipped with some custom designed logic to make it act as a voltage controlled overcurrent. This enables it to distinguish between a low level fault current and a load current

5.3.9

36 kV Busbar Protection

Busbar Protection must provide fast fault clearance for both phase and earth faults located on the busbar. As the earthing of the 36 kV network is via Earthing Transformers limiting the 36 kV earth faults to as low as 750A. The limited earth fault current may mean that a traditional high impedance circulating current protection may not be feasible due to the achievable minimum primary operating current being too high if there are a large number of strings connected to the busbars. One possibility could be a low impedance protection scheme, which uses numerical relays, providing an even quicker fault clearance time (~12ms) and also providing breaker fail, backup overcurrent and earth fault protection which provides further options to remove common mode failures. In addition this scheme may enable a reduction in CT numbers and sizes, and reduce the amount of multicore cabling required as CT switching is not a feature, providing further savings in weight and cost compared to the high impedance protection. Another alternative is Reverse Interlocked Busbar Protection (RIBBP) which is an economical answer making the best use of the logic capabilities of modern numerical relays. RIBBP takes advantage of the significant fault contribution from the direction of the Grid Connection. Directional elements allow for the fault in‐feed to a busbar fault from the WTGs. The status of Directional Overcurrents from all relays attached to a 36 kV Board are sent to one master relay usually the main transformer incomer. This information is processed to reliably determine the location of the fault and operate the appropriate Circuit Breakers to clear the fault. The principle can be extended to work in several running arrangements with bus section CBs and interconnectors between boards. Bus Section CBs are fitted with two directional relays one looking in each direction. In the diagram below the arrows indicate the direction of the DOC / DEF relays at each location. Incomers H04 and H08 contain fast tripping (~50ms) Directional Overcurrent and Earth Fault Elements which are conditioned by the status of other relays attached to the same board. String Relays H01 and H06 contain fast directional elements but slower tripping (~400ms) direction elements.

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Incomer

BB1

Incomer

H04

H08

H01

BB2

H06

H05 String

String Bus Section

Fig 5.3.6 ‐ Operation for a feeder fault – H01 trips after time delay Figure 5‐9. Directional Relays used for Busbar Protection

Incomer

Incomer

BB1

H04

H08

H01

H06

H05 String

String Bus Section

Figure 5‐10. Operation for a Feeder fault – H01 trips after a time delay

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BB2

Incomer

Incomer

BB1

H04

H08

H01

BB2

H06

H05 String

String Bus Section

Figure 5‐11. Operation for a busbar fault – H04 trips after very short time delay and intertrips other CBs connected to busbar

5.3.10

Platform Transformer Protection

The transformers used on the offshore platforms may be of either two winding or three winding design. For transformers in excess of 140MVA irrespective of whether they are two or three winding design, two separate 36 kV switch panels will generally be required to accommodate the load current in excess of 2500A. The transformers will be equipped with Buchholz gas, winding and oil temperature and pressure relief protections which will operate in the same way as for any normal transformer. The transformers are equipped with HV REF which can be contained in the overall differential relay. LV REF is also used. For two winding transformers this can also be accommodated in the differential relay. For three winding transformers a separate restricted earth fault protection is required for each winding and these will normally be accommodated in a stand‐alone relay although numerical relays incorporating 3 REF elements are available. Each of the LV switch panels will be fitted with a directional overcurrent and earth fault relay. This relay is an integral part of the RIBBP busbar protection if utilized. This relay is also set to provide back up in the event of failure of the overcurrent protection on one of the strings or on a bus section or interconnector. This relay can also be set with a definite time characteristic. The back‐up protection on the HV side can be a 2 Stage IDMT Overcurrent and high set overcurrent (HSOC). Usually the Stage 2 time delay is set to zero. With three winding transformers the apparent impedance will vary significantly depending upon the different running arrangements. This can cause a large difference between the minimum and maximum LV fault levels. In order to preserve coordination at maximum fault level and minimise operation time at minimum fault levels an extra DT stage may sometimes need to be applied.

5.3.11

Export Cable Protection

The main protection for the export cables will usually be a feeder differential protection. The key factor is the communications between the relays which uses fibre optics embedded 308

in the submarine cables. For the normal operating condition the relay uses fibres in an adjacent cable (assuming at least two export cables are used). If the normal channel is not available then the back‐up channel using fibres in the protected cable is activated. This latter situation would be the normal case for a wind power plant with a single export cable. Alternatively a distance scheme could be utilised if an alternative fibre connection is not available. This could be a default operating mode provided by the differential protection following a loss of communications. The back‐up protection is provided by overcurrent and earth fault. Only one relay is applied per cable – located at the on shore end. This is due to the general approach of grading protections back from machines to the Grid. Back‐up earth fault does not need to discriminate with any other devices as the earth fault reach is limited by the star/delta transformer connections. This enables short clearance times to be achieved which minimises the fault duration on cable sheaths. The back‐up overcurrent must grade with the transformer HV back‐up. An IDMT characteristic may be applied. To minimise operation time a curve graded at HVBU Characteristic transition from IDMT to HSOC should be used.

5.3.12

Breaker Fail Protection

The circuit breaker fail function is normally provided as an integral function of the numerical busbar protection scheme, which saves on space in the relay panels. Circuit breaker fail protection will cater for the possibility of a single circuit breaker failing to clear fault current when commanded to do so by protection elements that are either internal or external to the main protection relay, due to a breaker or trip relay failure. The breaker fail protection relay should initiate rapid back‐tripping and intertripping of other circuit breakers, as necessary, and within the required EHV back‐up fault clearance time. Breaker Fail protection tends to be applied to all circuit breakers from those in the 36 kV switchgear offshore right up to the onshore CBs. The operation of the CB Fail protection is basically the same as applied on any transmission system. For failure of the last CB within the wind power plant system intertripping of the Transmission Operators CB will occur to clear the fault.

5.3.13

Tripping Philosophy

As the WTGs cannot generate if they are not connected to a grid supply then the loss of the grid supply will require re‐instating the system. Consequently if a fault occurs on some upstream (HV) equipment the tripping normally takes out all downstream (LV) plant to avoid this being left in the closed position when the voltage is restored at the HV end This downstream tripping may be effected from onshore to offshore using the intertripping facility built into the feeder differential protection relays

5.3.14

Interface with Operational Intertrip Schemes

In some countries the connection agreements for some wind power plants may require the inclusion of operational intertripping schemes to trip the output of the wind power plant for certain grid system outage conditions. Although the simplest way to remove the output would be to trip the CB at the point of common coupling in many cases it may be beneficial to trip the output at the offshore 36 kV busbars. This has two main advantages in that it does not require re‐energisation of the large offshore transformers with associated voltage dip on the network and it will leave any onshore compensation plant connected to the

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network to assist with voltage control. The intertripping can again be achieved using the facility in the differential relay. An alternative approach is to provide fast curtailment of generation by interfacing directly to the WTG SCADA. This technique avoids the need for the tripping of CB’s.

5.4

Control and Supervisory Control and Data Acquisition (SCADA) System Requirements

5.4.1

Introduction

As the cost of keeping people in an offshore location is so high the wind power plant will normally be designed for unmanned operation. This obviously puts large demands on the control and data acquisition system in order to perform this requirement. The substation naturally acts as a hub for the primary circuits, potentially owned by a number of different entities, it naturally follows that the substation acts as a hub for communications, SCADA and other data services such as asset management data. Traditionally, the manufacturers of wind turbine generators (WTG) have developed their own SCADA systems which have been totally dedicated to the needs of controlling the WTGs. These needs will involve the control of the blade angles etc. to control the real power which can be extracted from the wind to achieve the target generation at the 36 kV busbars, as well as the status indications and alarms from all of the different items associated with the many WTGs involved in the wind power plant. This has led to there normally being at least two SCADA systems associated with offshore wind power plants, one to control the WTGs and the other to control the electrical system used to collect the energy and transmit it to the onshore grid connection point, this is referred to as the HV SCADA system. The dependency of the plant operation on these SCADA facilities increases their importance and may have commercial implications. It is therefore clear that the substation must play a part in the control of the entire offshore wind power plant, even if that part may be as simple as providing a communication route for the control systems of those other parts. However, in the complex world of privatised companies, depending on the commercial arrangements and ownership structure of the “wind power plant complex” there may be further separate operating organizations requiring communication with and operational data from various elements of the “wind power plant complex”. Typically there may be: ‐ wind turbine operator(s) ‐ collection system operator(s) ‐ offshore transmission system operator (OFTO) In the simplest case there may be a willingness and commercial structure which allows the use of common systems with shared data, procedures and communications controlled by password access, whilst in the most difficult circumstances each of the stakeholders in the “wind power plant complex” may require fully independent data, communications and procedures leading to the need for the HV SCADA system to be designed in two sections to allow the wind power plant SCADA and the OFTO SCADA systems to be separated, allowing them to be operated by different owners. It is important to ensure that these commercial and ownership issues are addressed very early in the substation design process to avoid any rework at a later date. Clearly, if one operator is unable to control his equipment because of the failure of a SCADA system owned and operated by a third party then this could lead to some difficult legal and commercial consequences. Therefore the SCADA system needs to be designed so that the operation, maintenance and any potential updates / 310

modifications can be done independently without any undue effects in the availability and information in the other system. For each of the above mentioned systems, secure SCADA systems with high availability are required for all of the reasons discussed earlier, but as it is the communication and SCADA system which enables the remote management and operation of the wind power plant complex, the need for high availability here is paramount. Often the SCADA system will have duplicated servers, communications, power supplies and will have I/O segregated and/or duplicated so that the loss of any I/O card has a minimal effect on the wind power plant operability or availability. The required level of information about the various systems offshore is an order of magnitude higher than that for onshore installations where even the most remote installations are usually accessible within a few hours by any number of different transport systems; allowing maintenance staff to go and take a look at the installation. In offshore applications the ability to “take a look” may be very restricted and much more emphasis is needed on the remote collection of data to take operational decisions, identify failures, decide on repair strategies and select replacement components to be taken by the correct repair team, when access can be arranged. These factors will have a major impact on the architecture and complexity of the communications and SCADA equipment installed on offshore platforms, which in turn impacts on the power and accommodation required for the systems.

5.4.2

Structure of the SCADA Systems

In this section, attention is concentrated on the SCADA system for the offshore substation itself rather than for other systems like the WTG SCADA or the collector system SCADA. The SCADA system for the offshore substation will usually be part of a common SCADA system with the onshore substation and the servers will be located at the onshore substation. As space is at a premium on the offshore substations use should be made of the facilities provided in modern digital relays to provide the input/output for the SCADA system rather than providing lots of additional remote terminal units. This should still be possible even if the SCADA and protection are coming from different suppliers(refer to Figure 5‐12), either by hardwiring using volt free contacts to connect the two systems together, or these days the protocol used by the protection relays may be one which is also supported by the SCADA system. By using the protection relays in this way it should be possible to gather approximately 80‐90% of the total data required and only the 10‐20% remaining will require to be picked up by separate RTUs which can be of the small terminal rail mounted type. The intelligent electronic devices (IED) such as the protection relays and the RTUs can be arranged to run independently of the SCADA system such that in the event of a SCADA failure or communications failure they will continue to function locally. The communications will be designed as a redundant LAN topology to minimize the risk of path breakdowns. This will allow the SCADA servers located onshore to access the RTU/IEDs located offshore. Typically the protocols used for the SCADA systems will be IEC61850, IEC 60570‐5‐104, DNP3, Modbus TCP, OPC etc. A typical SCADA configuration for an offshore wind power plant with two offshore substations is indicated in Figure 5‐13 below. This example incorporates the information from the WTG switchgear into the substation SCADA. A ring topology is used and redundant servers at the onshore substation. External access to the SCADA can be provided to enable: ‐ Remote monitoring of the plant by the Offshore transmission operator 311

‐

Remote diagnosis of fault conditions by the maintenance staff to enable a more rapid and accurate response to site problems. Different levels of redundancy can be selected and some typical possibilities are illustrated in Figures 5‐15 to 5‐17. The key features of any SCADA system communication system for an offshore wind power plant can be summarised as follows:‐ ‐ A single local Area Network (LAN) will be established across the wind power plant ‐ The Offshore to Onshore communications will be provided by single mode fibre optic cables embedded in the export power cable. ‐ If required, the offshore platform to wind turbines can be connected with either single mode or multi mode fibres embedded in the inter array power cables. ‐ Usually there will be sufficient fibres embedded in the cables to enable different networks to be established for different equipment e.g. CCTV can have an independent network from the SCADA system. ‐ The multiple networks can also co‐exist on a single physical LAN infrastructure with the use of Virtual Local Area Networks (VLANs) ‐ The use of fibre cables avoids the need for wireless or radio systems which ensures that the links are less prone to failure or losses in poor environmental/weather conditions. ‐ It also allows the use of higher speed networks ‐ The use of embedded fibres also has the advantage that it can be used to provide distributed temperature sensing (DTS) monitoring equipment which is particularly advantageous to minimize the capital expenditure on the cable system and take advantage of the fluctuating power availability of the wind by not putting fixed ratings on the cables without the risk of causing damage to the cable due to excessive temperatures. ‐ The SCADA systems can be accessed by broadband connections from remote control centres, mobile work places or from the operator’s home. Alarm signals can even be addressed to an operator’s mobile phone.

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Communication protocol based interface e.g. IEC 61850 over fibre

Remote control centre

SCADA Protection signals hardwired via volt free contacts or using a communication protocol

Controller

Local control points

Protection scope

SCADA scope

Figure 5‐12. Example of Protection and SCADA supplied by different parties 313

Figure 5‐13. Typical SCADA Configuration Diagram 314

Figure 5‐14. Example of combined control and protection solution for a transition piece 315

Figure 5‐15. Redundant All in One System 316

Figure 5‐16. Partially Redundant Server System 317

Figure 5‐17. Redundant and Distributed Server System Server System

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5.4.3

Functionality of Each System

5.4.3.1 Wind Turbine SCADA The wind turbine SCADA system is not the subject of this document; however this SCADA usually covers all aspects of the control of all of the wind turbines within the wind power plant. This will cover the control of the real power and reactive power as well as the status indications and alarms from all of the WTGs. If it is possible to interface the HV SCADA system to the WTG SCADA system information such as voltage control and plant status signals should be provided. 5.4.3.2 Collection System SCADA If this system is separated from the Offshore System Operator SCADA system for reasons of ownership then this system would control, provide status indications, alarms and analogues for all of the electrical equipment within the ownership of the Generator with the exception of the wind turbines themselves. Typically this would consist of any switchgear located at each WTG together with any 36 kV or other equipment on the offshore substation platform, including protection equipment, monitoring of power flows and voltages, of cable temperatures if using embedded optical fibres included for this purpose, of any battery / UPS systems including any on the WTG’s and any security systems which are in the ownership of the Generator. The features of this SCADA system would basically be the same as are described in the next section 5.4.3.3 Offshore Transmission System Operator SCADA This SCADA system will be the one which controls most of the plant on the offshore substation. It will provide control, status indications, alarms and analogue information for the following items:‐ ‐ HV switchgear ‐ Transformers (including tap change control and indication) ‐ 36 kV switchgear ‐ LVAC system ‐ DC system and batteries ‐ Diesel generator ‐ Protection systems ‐ export cable temperatures (if using embedded optical fibres included for this purpose) ‐ Fire fighting systems ‐ Platform building services functions such as air conditioning, crane position and status and tank, sump and bund level monitoring, Security and CCTV systems alarms, etc ‐ Navigation systems In order to ensure that the best available data is presented to the operator a process of source value selection can be integrated into the SCADA. The process accesses the data including manual operator updates for all of the measurements. It will receive and detect spontaneous value changes and where necessary handle blocking and manual substitution of data values. In addition to the basic control functions certain interlock features can be built into the SCADA system to avoid maloperation of the plant. Examples of this kind of interlock are:‐ ‐ prevention of operating more than one device at any time 319

‐ transformer is already at maximum or minimum tap ‐ network must be isolated before it can be earthed ‐ device is in local control mode ‐ disconnectors cannot be operated on load Many other interlock conditions may be built in if it is felt to be effective. The SCADA system should also be designed to allow operation locally and remotely. Remote could be at the onshore substation adjacent to the onshore server or remotely at the customer’s operating centre or even from other locations by broadband access. Each of these accesses can be controlled to limit who has authority to effect control. Other functions which may be built into the SCADA are:‐ Data processing examples being ‐ Status data such as normal/abnormal states and sequence of events ‐ Analogue data processing such as limit checks, threshold adaptation, max/min/average values ‐ Counting such as operating hours or number of operations ‐ Data calculation ‐ Disturbance data processing such as snapshot, triggers and disturbance analysis Event and Alarm Processing examples being ‐ Event/Alarm administration allocating alarms to alarm classes by technological area, responsibility, local/remote state ‐ Event/alarm presentation acoustical annunciation and visual annunciation ‐ Event/alarm handling and control, single and/or multiple acknowledgement or suppression ‐ Alarm forwarding to remote locations or specific operators An example of these features is shown in Figure 5‐18. Use of SCADA for Maintenance Information The designer of the SCADA system should also make allowance for how the SCADA system may be most effectively used as part of the maintenance regime of the wind power plant. The SCADA system will effectively provide a means for continuous remote condition monitoring. It can also provide the vehicle for remote fault analysis and error correction. The data collected by the SCADA system can give the maintenance team information on sequence of events, analogue fault record charts, trend graphs etc to enable the maintenance team either to intervene remotely or to ensure that they have the personnel with the required skills and tools dispatched to the substation to deal with the problem. The SCADA system can have the capability to support predictive maintenance, preventive maintenance and corrective maintenance.

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Figure 5‐18. Alarm Processing Example

5.4.4

Interoperability of the Systems

Although the different SCADA systems may be owned and operated by different entities there will be a need to communicate some information between the different systems. Usually this information will be communicated between the main servers for the different systems which are usually located at the onshore substation. The communication may be by means of a protocol convertor or in the worst case by hard wired connections between the two systems. However the control of the different systems will normally be completely independent.

5.4.5

High Speed Signalling

The SCADA system usually cannot be used for communications which are required in very fast times such as intertrip functions or certain control signals used for the dynamic response of the equipment in order to comply with Grid Code requirements. In such cases the communications will either be by direct hardwiring or by dedicated fibres specifically for that purpose.

5.4.6

Operation with Degraded Communications

The SCADA system is clearly vital to the successful operation and maintenance of the offshore substation. It is therefore important that the communications system is designed such that the failure of a single communication route does not cause the SCADA system to fail or become severely depleted. The communication routes from the shore to the platform should be duplicated and run in separate export cables such that loss of one route does not cause any interruption in the operation of the SCADA system. With regard to communications to the WTGs or their associated switchgear ring systems will still be used but these may be run in the same cable. If the strings are tied to other strings at the end of their runs then a complete SCADA ring system via different cables can be established. Clearly any alarm indicating the failure of a communication route must be investigated swiftly to avoid the risk of a second failure losing the functionality of the system, as the

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occurrence of such a loss of control may have severe financial and commercial consequences.

5.5

CCTV and Security Systems

5.5.1

Statement of Requirements

In order to allow remote monitoring of the substation and personnel for safety and security reasons the use of CCTV and an associated security system is sometimes required to provide support to other systems of detection. The design of the system to provide safety monitoring will need to comply with legislation enacted by the appropriate statutory authority responsible for offshore installations. CCTV systems can be equipped with time‐ lapse video recording allowing images to be recorded at appropriate intervals. The time period that is saved before being over written needs to be defined. The system needs to have facilities to copy images onto removable media for long term retention. The system may also be configured to monitor the approach and docking of vessels to the platform and be arranged to provide warning of the close approach of vessels to the substation platform. The location of the substation and the sometimes difficult access conditions are such that a remote accessible surveillance and detection system for all facilities offers operational advantages. In the design & construction of the surveillance system, the reliability and availability should be carefully considered as under certain climatic conditions the monitoring of activities may be totally dependent on the system. In case of a substation equipment failure the surveillance and monitoring system, may be able to aid fault tracing and damage assessment prior to repair teams being dispatched.

5.5.2

Alarm System

An alarm system capable of alerting all personnel in any accessible location is required to ensure awareness of abnormal conditions existing in the substation which may present danger to personnel and plant. The system is required to provide audible and where appropriate (noisy location) visible annunciators and should also provide for two way voice communications so that additional information or instructions can be given to persons affected by the alarm situation. The system should be designed for both automatic and manual activation as required by the particular situation and system conditions in the substation. As a minimum the alarm system should warn of smoke and gas detection activation, fire protection systems operated, major plant failures and general situations such as the need to muster staff. The system should have discrete, discernable alarm signals which allow the personnel to identify the alarm type being annunciated but limited to a small number of discrete signals to avoid confusion.

5.5.3

CCTV System

The CCTV system provides three distinct functions: 5.5.3.1 Personnel Surveillance The strategic location of CCTV surveillance cameras in work areas allows the monitoring of staff working offshore by control centre staff so that their safety and wellbeing is monitored

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allowing early intervention by alerting other staff in other areas of the substation or by initiating emergency procedures. 5.5.3.2 Security Surveillance The strategic location of CCTV surveillance cameras around the perimeter of the platform allows monitoring of vessels approaching the platform by both substation and remote control centre staff to determine if the approach is: „ planned, „ unplanned and acceptable „ a possible threat to the substation For planned and unplanned acceptable approaches, the situation may be monitored and for possible threat situations the appropriate services may be informed and may monitor the situation and react accordingly. 5.5.3.3 Plant Surveillance The strategic location of CCTV surveillance cameras in work areas allows the monitoring of equipment by control centre staff so that abnormal plant behaviour can be identified allowing early intervention by gathering detailed information from remote engineering systems, changing the operational configuration, switching out equipment at risk, alerting staff in other areas of the substation and initiating investigation and repair. The cameras should be capable of remote control to cover defined areas of the plant, have sufficient zoom capability to provide detailed views and operate in the visible light spectrum and infra red spectrum (for thermal imaging of the equipment).

5.6

Navigation Aids

5.6.1

Statement of Requirements

In order to comply with statutory regulations, the substation needs to be identified and equipped with the necessary navigation aids to minimize the risks of collisions with any airborne or seaborne traffic. As the substation is intrinsically linked with a number of other offshore structures such as WTGs and possible accommodation platforms, the navigation aids arrangements should be coordinated for the complete installation. The substations navigation aids and markings should comply with all relevant standards including; „ IMO Regulation “Convention on the International Regulations for Preventing Collisions at Sea”, 1972 (COLREG) „ IALA (International Association of Marine Aids to Navigation and Lighthouse Authorities) Recommendation O‐139; “The Marking of Man‐Made Offshore Structures” December 2008 Local regulations may make further prescriptions for design and operation of navigation aids.

5.6.2

Navigation Aid Power Supplies

The effectiveness of navigation aids is partly dependent on the security of their power supplies, hence to maximise availability all navigation aids systems are required to have two independent supplies of power. So far as practicable, the physical arrangement of the 323

supplies should be such that a fire, a fault or mechanical damage at any one point will not render both systems inoperative. The supply system is to include automatic switch‐over between these two supplies in case of failure of one of them and any fault on any of the power supplies is required to initiate an alarm on the supervisory control system. To monitor the system and demonstrate that the required availability is provided, the supervisory control system is required to record the duration of any supply malfunctions.

5.6.3

Lamps

The construction and installation of the navigation lights used in the system should be suitable for the application taking into account the required availability and the limited maintenance opportunities and should comply with the appropriate legislation. All lamps should be individually supplied by a discrete circuit from a dedicated navigation lighting panel designed to provide secure supplies and lighting circuit monitoring / alarms. Main and standby lamps of identical type (usage) may be supplied via a single cable with two independent circuits provided that individual lamp isolation is provided. The location and mounting of lamps must be carefully considered to ensure that blinding of personal working on the platform is avoided and that safe maintenance access is possible. The selection of the type of lamp, its operating duty and installation design should minimise the maintenance required. Lights panel The navigation lights are to be controlled and supervised from a dedicated navigation lights panel and no other systems may take supplies from the panel. For every lamp the panel is to be fitted with a device which indicates or signals the extinction of a lamp. Where the indicating device is connected in series with the lamp, it must be ensured that a failure of the indicating device does not cause the navigation light to be extinguished. Provision should be made for testing the function of the panel supplied from either of the two power sources. All alarms originating at the navigation lights panel monitoring systems are to be repeated to the supervisory control system and recorded.

5.6.4

Foghorn

When required by the local authorities an audible warning device “foghorn” is to be provided for the substation platform complying with appropriate legislation. The warning system is required to have fully duplicated supplies with automatic changeover to the second supply and fault monitoring / alarm facilities giving local and supervisory alarms.

5.7

Communications

5.7.1

Statement of Requirements

The remote location and dependency of many systems on the correct operation of the communications system places a very high performance requirement both in terms of capacity and availability. There are two main communications systems which may be considered suitable to provide the required bandwidth IP/ SDH fibre optic communications and IP/SDH satellite communications. Depending on the overall structure of the power supply system it may be that a fully redundant fibre system or a combination of fibre, microwave radio and satellite is used. For example for an offshore substation with two power cable installations to shore, each with an associated fibre cable, the fully fibre based solution is the most attractive. For a single 324

power cable solution, the use of one fibre cable in the power cable plus a separately installed fibre cable may be used with microwave radio or satellite used to provide the second channel. Microwave radio is limited by range i.e. line of site required for reasonable data rates. Satellite communication has large latency delays and therefore cannot support polled data exchanges e.g. IEC 60870‐5 protocols or multiple TCP/IP socket connections required by SCADA systems. In the single power cable case it will be necessary to assess the probability of the optical communication cable being completely lost without the loss of the power connection. If such a situation is considered unlikely, then the bandwidth required from the satellite system will be relatively small, limited to providing restricted data and voice communications; real time operational data from the substation may not be required. If the loss of the fibre optic cable in the power cable without loss of the power cable is considered a real possibility the second separate fibre cable will be required. In addition to substation to shore communications, the substation will require radio communication for use with supply boats, helicopters and rescue services which are fully compliant with the statutory requirements for the jurisdiction in which the substation platform is located.

5.7.2

Communication Routes and Usage

The communications system provided is required to support the following routes and functions: 5.7.2.1 Routes ‐ Substation to shore – for voice and data communications into on shore corporate and public networks ‐ Substation to shore – for connection to onshore protection systems ‐ Substation to wind turbines – for voice and data communications into the substation systems for use at the substation or onward transmission to shore ‐ Internal within the substation – between locations on the platform for operation ‐ General “public address” broadcast system covering the entire substation ‐ Substation to supply or maintenance vessels for coordination ‐ Substation to emergency services and rescue teams – secure system 5.7.2.2 Voice Communication ‐ Normal communications from operation and maintenance staff to shore for switching instructions, administrative procedures, and technical discussions in those situations where the platform is manned. ‐ Communications during installation for coordination of commissioning activities for example when testing substation to shore systems. It follows that one of the first substation to shore systems to be tested will be the communications which may require temporary satellite communication until the permanent facility is in reliable service. ‐ Communications to supply boats for the coordination of platform approach, access and off loading of staff and materials.

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‐

Communications to emergency services and rescue teams capable of providing independent channels in the event that systems integrated into the platform system are compromised.

5.7.2.3 Data Communications ‐ Electronic communications ‐ e‐mail, remote document access, internet / intranet browsing etc. to provide general data collection and access to engineering documentation, specialist information and assistance ‐ Measurement and metering data – depending on the commercial arrangements and structure of the control system, multiple discrete communications circuits may be needed to support the segregation required. With the systems identified high levels of data segregation can be achieved with the use of proprietary interface equipment, virtual private networks, separate fibres etc. The bandwidth required is largely dependent on the volume of data generated by the SCADA system(s) ‐ Video surveillance for plant monitoring and personnel security – visible spectrum and infra‐red video surveillance of equipment as a back up to conventional monitoring systems. Surveillance of work teams for safety and to provide images for discussion with technical experts. ‐ Engineering tools – for accessing engineering data for remote analysis e.g. fault records and remote adjustments to platform sub‐systems e.g. protection settings 5.7.2.4 High Speed Communications Protection signalling – the protection relays used particularly for the substation ‐ shore connection may require several communications facilities. Typically these would be; ‐ Differential current data – measured values of current at a remote location for comparison with local measured values ‐ Intertripping – to provide a direct tripping instruction to the remote circuit breaker ‐ Blocking – to prevent operation of a device or system using remote instructions The differential current data would normally have a dedicated fibre connection to the relay whilst the intertripping and blocking signals may be direct fibre or multiplexed with other data provided high speed transfer is maintained.

5.7.3

Interfaces

The communication system will be required to interface to a number of equipments ‐ Direct optical connection for protection relays, typically to IEEE C37.94 TM ‐ (IEEE C37.94 is an optical standard for interfacing to PDH/SDH equipment. This would only be required if the protection relay data was multiplexed with other data on the same fibre) ‐ ITU – T G821 V.35, G703, X21 ‐ IEC 60870‐5‐10x ‐ DNP 3.0

326

5.7.4 Communications Technology

5.7.4.1 SDH Communications using Optical Fibre Links Main connection ‐ multiple fibre optical cable installed with each of the main connections to the MITS cables, normally incorporated into the power cable and terminated into an Optical Fibre terminal box on the platform. Breakout of the fibre cable from the main cable is arranged as part of the trifurcation installation for three core cables. The optical cable characteristics will have to be coordinated with the optical terminal equipment to ensure the required data transfer performance is achieved. Terminal equipment ‐ optical termination equipment providing an interface to electrical or optical inputs from devices on the platform is required. This equipment should be suitably “hardened” for operation in a harsh electromagnetic environment and protected against adverse climatic conditions. The equipment output should be coordinated with the transmission distances required to avoid the use of intermediate repeaters. Multiplexing ‐ the architecture of the communications system and the mix of direct fibre connections and multiplexed connections will need to be designed to support the required performance and availability of the systems which utilise the communications links. Platform distribution ‐ may be using optical cables or copper connections to individual subsystems. Ideally the direct connection using optical cables will minimise the risk of degraded performance due to interference but may not be justified for low bandwidth connections. The system is capable of providing the highest availability both inherently and by the use of redundancy within the system. The performance is generally unaffected by environmental or atmospheric conditions as all system components are protected.

5.7.4.2

SDH Communications using Leased Satellite Links

Satellite system characteristics – uses third party communication leased from a satellite system provider. The provision of high bandwidth dedicated communications is possible but at a high cost. The use of satellite links for voice communications and limited monitoring requiring low bandwidth is a viable option for back‐up functions ‐ The service is rented from specialist supplier and may be specified to meet the performance required. ‐ The communication bandwidth available even using the dedicated point to point service is lower than that which is possible with SDH operating on optical fibres ‐ Multiplexing into the satellite communications system is possible but the use of the link for protection signalling functions is not advisable ‐ Platform distribution ‐ may be using optical cables or copper connections to individual subsystems. Ideally the direct connection using optical cables will minimise the risk of degraded performance due to interference but may not be justified for low bandwidth connections. ‐ The system is capable of providing the high availability both inherently and by the use of redundancy within the system. However, the performance is affected by environmental and atmospheric conditions as the main transmission medium is 327

exposed to all atmospheric conditions most noticeably heavy rain and high winds. The availability is also determined by the operating mode selected which may be “point to point” or “shared”. The “point to point” option provides allocated bandwidth to a single user whereas the shared mode uses multiplexing techniques to share bandwidth, possibly resulting in reduced availability due to third party interactions. 5.7.4.3 SDH Communications using Point to Point Microwave Links Microwave radio system characteristics – uses direct point to point communication and can provide high band width comparable to optical fibre based systems. The radio system is suitable for use where line of sight connections are possible between the substation platform and an on‐shore radio installation or between two offshore substation platforms where each has onshore fibre connections capable of being used to provide back‐up. ‐ Multiple routes – fully duplicated radio transceivers are required to provide secure communications operating in hot standby mode. For multi‐substation installations this system may be convenient for platform to platform communications. ‐ The communication system is dedicated to the substation and requires no ongoing expenditure for line capacity or equipment. The equipment is “hardened” for use in demanding electrical environments. ‐ Platform distribution ‐ may be using optical cables or copper connections to individual subsystems. Ideally the direct connection using optical cables will minimise the risk of degraded performance due to interference but may not be justified for low bandwidth connections. ‐ The system is capable of providing the high availability both inherently and by the use of redundancy within the system. However, the performance is affected by environmental and atmospheric conditions as the main transmission medium is exposed to all atmospheric conditions most noticeably heavy rain and high winds. ‐ The impact of local shipping channels and their impact on the point‐to‐point link performance must be investigated. It is possible for line of sight links to be lost for periods of minutes whilst large vessels cross the link path. 5.7.4.4 Radio Systems for Voice Communications Radio system characteristics – VHF band radio independent from the platform system other than for the recharging of portable devices. The system should be in place and proven in advance of positioning the platform so that emergency services are contactable and vessel coordination is practicable before leaving shore. The radio system should be suitable for communications: ‐ Between personnel located on the substation platform ‐ Between personnel located on the substation platform and others engaged in activities relating to the substation platform ‐ With vessels serving the platform for the transfer of equipment and personnel ‐ With helicopters serving the platform for the transfer of equipment and personnel 5.7.4.5

Back-up Satellite Phone or Mobile Phone Systems for Voice Communications Back‐up system characteristics – to provide communications during the platform installation and commissioning stages, in the period before full broadband communications are 328

established a satellite telephone system or mobile phone system may be used. The choice will be largely influenced by the availability of mobile network coverage at the platform location.

5.7.5

Communications System Monitoring and Maintenance

It has been established that communications systems play a major role in the protection, operation and safety of plant and personnel on an offshore substation. As for all other equipment, access for maintenance and repair is limited by distance and transport constraints. It is therefore essential that the monitoring, remote diagnostic systems and remote repair facilities are designed to minimise site access requirements. For any substation equipment it is essential that the harsh electro‐magnetic environment is considered but for offshore installations the physical environment, location of equipment, enclosure design and protective finishes are major factors in determining the service availability and life of communications equipment. It should be noted that the time to obsolescence of the equipment (typically 10‐15years) may limit the service life more than durability of the equipment in the offshore environment.

329

Figure 5‐19. Typical communications two fibre routes 330

FO cable termination

FO cable termination

FO terminal equipment and multiplexer

FO terminal equipment and multiplexer

331

FO terminal equipment and multiplexer

FO cable termination

Satellite communication interface

FO terminal equipment and multiplexer

Figure 5‐20. Typical communications one fibre route, one satellite route

Figure 5‐21. Communications configurations, two fibres routes associated with power cables

Figure 5‐22. Communications configurations, two fibres routes one independent 332

Figure 5‐23. Communications configurations, one fibre route to each sub, with microwave interconnection

Figure 5‐24. Communications configurations, one fibre route to each sub, with microwave interconnection to shore 333

5.8

Equipment Accommodation and Environmental Management

5.8.1

Statement of Requirements

Unless special requirements are specified, secondary systems are designed to operate over a well defined but limited range of environmental conditions. If standard equipment, without special design or protective treatments, is to be used the installation environment will need to be managed to provide the conditions required. The locations in which the majority of secondary systems are to be installed will be required to provide a managed environment which ensures that the equipment operates only within its design parameters. This controlled environment must be incorporated with the structural design of the substation platform so that adequate protection from the following is provided „ Extremes of temperature and humidity „ Corrosive atmospheres and deposits „ Exposure to water ingress

5.8.2

Constructional Requirements and Equipment Accommodation

The secondary systems for offshore installations are required to operate reliably in a hostile external environment. Even though the substation construction is designed to provide a secure and protected location for the equipment it is prudent to provide additional protection at the equipment level wherever practicable. The constructional design of the system considering location, housing, main components and connections needs to recognize the particular environmental conditions in all circumstances, including normal operation, testing, maintenance and replacement. This ensures that deterioration of the system is minimized and does not result in premature failure. To achieve the required reliability the overall construction system will need to be considered including: - The accommodation room - Position of the room - Access doors - Construction of the room - Heating and ventilation systems - Position for replacement equipment and or spares - Cubicles and kiosks housing system components - Physical construction - Sealing - Lighting, Heating and ventilation - Protection function segregation - Minimising access requirements - Major components - Additional anti corrosion measures - Selection of high specification long life components - Wiring, cabling and other connection systems 334

-

Corrosion resistant connectors and terminals Tracking resistant terminal blocks Cable glanding and sealing of gland plates

5.9

Maintenance Management

The objective is to minimize the time taken to carry out planned maintenance and restore operation of the substation to rated operational levels after unplanned maintenance or repair. By designing and selecting equipment for low maintenance and making provision for simple testing the number of personnel visits required and thus the time spent by staff at the substation is kept to a minimum. Staff used for maintenance of offshore installations do not only need to be competent technically in their particular field but also have to be qualified to work in offshore locations. This is likely to limit the availability of, and increase the cost of such staff. The number of different personnel required providing the specialist skill sets necessary may be directly related to the number of equipment types used within a substation; standardization of products will help in this respect. Incorporating standardization and redundancy in the design of secondary systems:‐ Minimises the number of visits Allows visits to be deferred until safe conditions for travel exist Reduces diagnostic and repair times Facilitates correct selection of spare parts to be taken to the substation Minimises the number of special tools, equipment and spares to be held at the substation

5.10

Metering

The wind power plant generation networks are connected through the offshore substation to supply power to the main transmission system. To measure the power delivered to the system it is necessary to install tariff metering. The exact location for the metering will be dependent upon the location of the ownership boundary. In many countries an Offshore Transmission System Operator has been established and consequently this has led to the installation of tariff metering at the offshore substation. The exact location for this metering may vary from one system to another. The common locations are at 36 kV on each array cable, at 36 kV on the LV side of the step up transformers to the transmission voltage or at the HV side of the step up transformers. If the metering is installed on the array cables then this requires a large number of meters and current transformers to be installed. However the current and voltage transformer performance requirements tend to be less onerous. Tariff metering normally requires two sets of metering known as main and check. Typically at load levels less than 100 MW the main and check meters can be connected to the same high accuracy CT core and the same high accuracy VT winding. If the metering is connected to the LV or HV side of the step up transformer then this will require fewer meters than for the arrays but the current and voltage transformer performance requirements are more onerous. At higher load levels the main metering must be connected to a dedicated high accuracy CT core and VT winding. The check metering can be connected to a second high accuracy CT core and VT winding but in this case other loads can be connected to these windings.

335

It should be noted however that if the metering is connected on the LV side of the step up transformer and two circuit breakers are connected in parallel to achieve the rating then each circuit breaker will need to be equipped with its own set of tariff meters as the summation of the CT signals will not be acceptable to meet the high accuracy requirements.

336

6.

Areas for Further Consideration

This Working Group intentionally limited its scope to AC connected wind power plants. Naturally, the majority of the work of this working group will also be applicable for AC substations to be used as collector substations for HVDC connected wind power plants but there are a number of factors to be considered which are quite different. This section will try to set out what these fundamental differences are that need to be considered such that Terms of Reference for a follow on working group can be derived. Many countries are currently looking at connections using HVDC but at present the detail of how these connections will be made is far from clear other than very high level thinking and the majority of the thought is being focussed on the HVDC part and we are not aware of any real thought being given to the AC collector systems. Some of the issues that will need to be considered are :‐ What frequency should the offshore network operate at? As the HVDC link provides a distinct separation from the onshore network serious consideration should be given to advantages of using an optimum frequency. What voltage should the collector AC network operate at? Again it does not need to be related to the onshore voltage. How is fault ride through of the WTGs achieved compared to an AC connected system? As the HVDC system basically decouples the AC offshore from the AC onshore they cannot inject maximum reactive current but they must return to at least 90% of the active power available before the fault within 500ms of the fault being cleared. How many collector stations should be used? How many cable radials can be accommodated on one platform? Will AC and HVDC be combined on one platform? What ratio of AC stations to HVDC offshore substations? What are the reactive compensation requirements on this offshore AC network and how will they be met? What is the most suitable control strategy at the offshore AC network, and its interaction with the HVDC converter? Wind turbines can contribute to the reactive power control strategy of the AC offshore network (e.g. Voltage control, power factor control, Q control), which is the most appropriate control option for the AC offshore networks. For the AC transformers on the AC offshore substations how to optimise the impedance required? For AC connection the impedance choice was heavily dominated by controlling the fault level as the major fault infeed came from the AC system onshore. With a HVDC link high fault current is not a problem but low fault current may be. The protection on AC connected wind power plants has been heavily focussed on current operated protections and grading. With a fault infeed from the HVDC converters of about 1.2pu load current maximum the protection philosophy of the substation will need to be totally reconsidered. Particularly for the protection of the array cables. How will the communications systems work. What interconnection will be needed using AC either between collector substations or between HVDC hubs? Auxiliary power during island operation. During commissioning stages and HVDC outage, auxiliary power has to be provided to the wind turbines and platform. 337

Diesel generators have to be correctly sized, in case of a DC connection, since for AC connections to shore it is generally assumed that one export cable will always be available to supply auxiliary power for WTGs/platform. A set of Terms of Reference needs to be created to define the task of the designer of these AC collector systems such that these issues can be clearly identified and set the scene for tackling these issues in a controlled and disciplined manner within a new Working Group. In preparing this Technical Brochure some other areas requiring further investigation were identified as follows:‐ • Insulation Co‐ordination At present the IEC standard does not identify switching impulse levels for equipment at voltages below 245 kV. For offshore wind power plants it is the switching impulse conditions which are most critical, perhaps specifying switching impulse withstand levels for equipment at lower voltage levels would be appropriate. Furthermore, the waveforms experienced within an offshore wind power plant can be significantly different to the test waveforms specified by the IEC. This raises the question as to whether the standard waveforms are appropriate. CIGRE WG C54‐142 “Electrical Environment for Transformers” is currently looking at this issue and will be including recommendations on standards for waveforms. The work of CIGRE WG A2/C4‐ 309 “Electrical Transient Interaction between Transformers and the Power System” may also be relevant. It is very difficult, if not impossible, to obtain models of wind turbines from manufacturers for transient studies. It has been suggested to form a new CIGRE working group with the aim to produce a ‘benchmark’ transient model for DFIG and full converter wind turbines. • Vibration It is recognised that some standards for switchgear (e.g. IEC) do not include any dedicated provisions for specification or type testing to demonstrate insensitivity to prospective mechanical impacts to be seen by electrical apparatus on offshore platforms, such as wind gusts or wave loads. Requirements published in IEC switchgear standards tend to be limited to localised impact tests, and are applicable only when specifically agreed between the purchaser and the manufacturer. They only refer to points of suspected weakness in the structure of the switchgear (e.g. ref. IEC 60694 and 62271‐1). These requirements are not adequate for the case in question when vibrations to the entire switchgear structure could be expected on a long term basis. With the planned pan‐European growth in offshore generation and transmission, it is suggested that the vibration topic should be an area for more thorough investigation. Consideration should be made for the feasibility and merit of defining a series of dedicated type test criteria. This could be similar to the rigorous "marine classification" regime for other offshore air‐insulated switchgears for mobile offshore units and vessels.

338

• Supply Chain The present offshore platforms are generally driven by existing and proven onshore equipment ranges and types with minor modifications or enhancements to be installed offshore. However to fully evolve the offshore substation and wind power plants consideration may need to be given to developing special ranges of equipment adapted to deal with the conditions experienced on offshore substations.

339

7.

Concluding Remarks

This brochure provides a set of guidelines to assist Utilities, Developers and Contractors who are involved in designing and constructing offshore AC substations associated with wind power plants. The document, which is not intended to be design standards, has identified the key issues which have been encountered to date within the industry and are likely to be faced, in conjunction with others, in the future. As there is no unique solution which will be appropriate to all offshore wind power plants, it presents some of the possible solutions to be considered to assist in developing the correct solution for any particular offshore substation. The document has divided the subject matter up into major headings to enable an organised approach to the design to be achieved. As every aspect of an offshore substation requires different thinking to what power engineers are used to when designing onshore substations, the brochure commences with the fundamental considerations of risk management (including deriving the correct redundancy policy), maintenance aspects and certification. When the fundamental policy decisions in this area are established the task of defining the single line diagram and establishing the key plant parameters can be started. For virtually all offshore wind power plants this will involve a comprehensive set of system studies. These system aspects are covered in the next main chapter. When considering the primary plant for the substation most people are aware of the considerations associated with the harsh environment, however there are many other aspects which impact upon the choice of the correct primary plant to be included in the substation and these are covered in Chapter 3. Chapter 4 deals with the physical aspects of combining all of this plant, establishing a workable layout which can then be built onto a suitable platform which can be constructed, transported and installed onto a foundation some kilometres out at sea, This platform must also take account of the cabling requirements and the ongoing lifetime aspects of maintenance and replacement and the required access requirements to achieve all of this. This introduces power engineers to a whole new area of expertise not encountered onshore such as designing steel structures with weights of some 2‐3 thousand tonnes including heli‐ decks, boat landings etc. Chapter 5 then looks at the secondary equipment requirements and how they differ from what we are all familiar with in onshore substations. This includes how the normal aspects such as protection, control and metering are addressed as well as those new items such as CCTV , navigation aids, aeronautical aids which are not normally associated with onshore substations. The final Chapter briefly summarises the work which is now required, from a new Working Group, to address the aspects associated with AC collector substations for wind power plants which will be connected by HVDC links which was expressly excluded from the content of this brochure. It also identifies some other areas worthy of further investigation. It is sincerely hoped by the whole team involved in the preparation of this brochure that this document will assist all Utilities, Developers and Contractors to achieve satisfactory solutions for the offshore substations required for their wind power plants.

340

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[20]

S. Johansson et al, ‘AC Cable solutions for Offshore Wind Energy’. Copenhagen Offshore Wind, 2005 [21] Anna Guldbrand, ‘Earth faults in Extensive Cable Networks’, Licentiate Thesis, Lund University, Sweden 2009 [22] Lars Liljestrand, A.S. (2007), ‘Transients in collection grids of large offshore wind parks’, Wind Energy, Volume 11, Issue 1, 45‐61 [23] Reza, M. and Breder, H., (2009), ‘Cable System Transient Study, Vindforsk V‐110. Experiments with switching transients and their mitigation in a windpower collection grid scale model’, Elforsk report 09:05. Available from: http://www.vindenergi.org/Vindforskrapporter/09_05_rapport.pdf [24] IEEE PES Wind Plant Collector System Design Working Group, (2009), ‘Wind Power Plant Grounding, Overvoltage Protection, and Insulation Coordination’, IEEE Power & Energy Society General Meeting, Calgary [25] Turner, R.A. and Smith, K.S. (2008), ‘Resonance Excited by Transformer Inrush Current in Inter‐Connected Offshore Power Systems’, in Industry Applications Society Annual Meeting, IAS '08, IEEE [26] Akhmatov, V. (2006), ‘Excessive Overvoltage in Long Cables of Large Offshore Wind power plants’, Wind Engineering, Vol. 30, No. 5 , 375‐383 [27] W. Wiechowski, P. B. (2008), ‘Selected Studies on Offshore Wind Power plant Cable Connections ‐ Challenges and Experience of the Danish TSO’, Power and Energy Society General Meeting ‐ Conversion and Delivery of Electrical Energy in the 21st Century (pp. 1‐8), Pittsburgh, PA: IEEE [28] Larsson, A. (May 2008), ‘Practical Experiences gained at Lillgrund Offshore Wind Power plant’, Wind Integration Workshop. Madrid: Energynautics [29] CIGRE Technical Brochure 430 “SF6 Tightness Guide”, 2010 [30] CIGRE Technical Brochure 276 “Guide for the preparation of customised practical SF6 handling instructions”, 2005 [31] CIGRE Technical Brochure 234 “SF6 recycling guide”, 2003 [32] CIGRE Brochure No.462 Obtaining Value from On‐Line Substation Condition Monitoring [33] Andersen, N., Marcussen, J.H., Jacobsen, E., and Nielsen, S.B., Experience Gained by a major Transformer Failure at the Offshore Platform of the Nysted Offshore Wind power plant, in 7th International Workshop on Large‐Scale Integration of Wind Power into Power Systems as well as on Transmission Networks for Offshore Wind power plants. 26 ‐ 28th May 2008, Energynautics: Madrid, Spain. [34] N.G. Boyd, Taylor Woodrow: “Topsides Weight Reduction Design Techniques For Offshore Platforms”, Paper Number 5257‐MS, Offshore Technology Conference, 5‐8 May 1986, Houston, Texas [35] IEC 60076‐1 Power transformers, Part 1: General [36] IEC 60695‐1‐40 “Fire hazard testing: guidance for assessing the fire hazard of electrotechnical products ‐ insulating liquids” [37] American National Electrical Safety Code (NEC) [38] Equivalence study for transformer fire protection using “ester‐based” insulating fluid” Swiss Institute for the Promotion of Safety and Security, Zurich, Switzerland, June 2011

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Appendix 1

Example of the Use of Weibull Distribution

The assessment of the duration of generation at different levels over a year, can best be done by estimating the probability of the wind speed using the 2‐parameter Weibull distribution where k>0 is the shape parameter and λ > 0 is the scale parameter.

kx fWeibull (x ; k , λ ) =   λλ

k −1

e

x −  k λ

Weilbull Characteristics: ‐ Mean wind speed at Hub height: 9.4 m/s Weibull scale factor λ: 10.61 * Weilbull shape factor k: 2.26 * Wind speed x (m/s) * These values were taken from a particular wind power plant and are used here as being typical for the purpose of this example. Table 1 shows the power park curve (PPC), number of hours per year with respect to the wind speed x (m/s) using the probability function of Weibull distribution. Number of hours per year with respect to the wind speed = number of hours per year x the estimated probability value from the Weibull Distribution. = 8760 hrs x Probability (x) Having known the number of hours per year associated with varying wind speed, the annual electrical generation can be calculated. Table 2 presents the annual electrical generation and also presents losses for a particular 800mm2 submarine cable. whereas Table 3 presents the losses for a 1000mm2 submarine cable. Due to smaller conductor size, the cost of the losses in the 800mm2 cable is (€722,495.13 ‐ €654,471.28) = €68023.85 higher than the 1000mm2 cable.

344

Wind speed (m/s) Probability No. of hours / year Park Output m/s

MW

0.5

0.00

40

0.0

1.5

0.02

157

0.0

2.5

0.03

291

0.0

3.5

0.05

425

3.7

4.5

0.06

548

11.3

5.5

0.07

650

21.8

6.5

0.08

723

37.1

7.5

0.09

763

57.8

8.5

0.09

770

84.6

9.5

0.09

745

114.8

10.5

0.08

693

143.1

11.5

0.07

622

169.8

12.5

0.06

539

195.5

13.5

0.05

451

208.7

14.5

0.04

365

212.4

15.5

0.03

285

212.4

16.5

0.02

216

212.4

17.5

0.02

158

212.4

18.5

0.01

112

212.4

19.5

0.01

77

212.4

20.5

0.01

51

212.4

21.5

0.00

33

212.4

22.5

0.00

20

212.4

23.5

0.00

12

212.4

24.5

0.00

7

212.4

Table A1‐1. Probability estimate of wind speed and number of hours in operation using Weibull distribution

345

Hours Hrs 40 157 291 425 548 650 723 763 770 745 693 622 539 451 365 285 216 158 112 77 51 33 20 12 7

Wind speed m/s 0.5 1.5 2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 14.5 15.5 16.5 17.5 18.5 19.5 20.5 21.5 22.5 23.5 24.5

Park Output MW 0.00 0.00 0.00 3.70 11.30 21.80 37.10 57.80 84.60 114.80 143.10 169.80 195.50 208.70 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40

% full output Loss MW 0.00 0.0000 0.00 0.0000 0.00 0.0000 1.74 0.0806 5.32 0.0905 10.26 0.1227 17.47 0.2056 27.21 0.3854 39.83 0.7309 54.05 1.3195 67.37 1.9614 79.94 2.7386 92.04 3.5440 98.26 3.9983 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305 100.00 4.1305

Loss kW 0.00 0.00 0.00 80.62 90.46 122.71 205.64 385.38 730.86 1,319.48 1,961.41 2,738.62 3,544.02 3,998.31 4,130.48 4,130.48 4,130.48 4,130.48 4,130.48 4,130.48 4,130.48 4,130.48 4,130.48 4,130.48 4,130.48

Loss kWh 0.00 0.00 0.00 34,281.60 49,602.92 79,772.21 148,720.63 294,220.44 562,703.32 982,910.82 1,360,121.14 1,704,115.02 1,910,071.20 1,803,188.20 1,506,849.72 1,178,831.63 892,130.47 653,235.40 462,817.42 317,288.77 210,469.88 135,077.90 83,867.52 50,369.15 29,257.35 TOTAL

Table A1‐2. Calculation of Electrical Generation and Annual Losses for 3c x 800mm2 Submarine Cable 346

Cost of Losses Euros € 0.00 € 0.00 € 0.00 € 1,714.08 € 2,480.15 € 3,988.61 € 7,436.03 € 14,711.02 € 28,135.17 € 49,145.54 € 68,006.06 € 85,205.75 € 95,503.56 € 90,159.41 € 75,342.49 € 58,941.58 € 44,606.52 € 32,661.77 € 23,140.87 € 15,864.44 € 10,523.49 € 6,753.89 € 4,193.38 € 2,518.46 € 1,462.87 € 722,495.13

Hours Hrs 40 157 291 425 548 650 723 763 770 745 693 622 539 451 365 285 216 158 112 77 51 33 20 12 7

Wind speed m/s 0.5 1.5 2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5 13.5 14.5 15.5 16.5 17.5 18.5 19.5 20.5 21.5 22.5 23.5 24.5

Park Output MW 0.00 0.00 0.00 3.70 11.30 21.80 37.10 57.80 84.60 114.80 143.10 169.80 195.50 208.70 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40 212.40

full output %age 0.00 0.00 0.00 1.74 5.32 10.26 17.47 27.21 39.83 54.05 67.37 79.94 92.04 98.26 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00 100.00

Loss MW 0.0000 0.0000 0.0000 0.0647 0.0741 0.1028 0.1775 0.3394 0.6508 1.1977 1.7769 2.4946 3.2220 3.6326 3.7520 3.7520 3.7520 3.7520 3.7520 3.7520 3.7520 3.7520 3.7520 3.7520 3.7520

Loss kW 0.00 0.00 0.00 64.73 74.13 102.79 177.51 339.45 650.76 1,197.72 1,776.89 2,494.63 3,222.05 3,632.63 3,752.01 3,752.01 3,752.01 3,752.01 3,752.01 3,752.01 3,752.01 3,752.01 3,752.01 3,752.01 3,752.01

Loss kWh 0.00 0.00 0.00 27,525.46 40,648.61 66,823.02 128,378.35 259,152.46 501,033.83 892,208.18 1,232,168.23 1,552,287.93 1,736,544.42 1,638,271.29 1,368,778.21 1,070,816.17 810,385.22 593,379.93 420,409.80 288,215.83 191,184.68 122,700.81 76,182.80 45,753.86 26,576.52 TOTAL

Cost of Losses Euros € 0.00 € 0.00 € 0.00 € 1,376.27 € 2,032.43 € 3,341.15 € 6,418.92 € 12,957.62 € 25,051.69 € 44,610.41 € 61,608.41 € 77,614.40 € 86,827.22 € 81,913.56 € 68,438.91 € 53,540.81 € 40,519.26 € 29,669.00 € 21,020.49 € 14,410.79 € 9,559.23 € 6,135.04 € 3,809.14 € 2,287.69 € 1,328.83 € 654,471.28

Table A1‐3. Calculation of Electrical Generation and Annual Losses for 3c x 1000mm2 Submarine Cable

347

If the lifecycle costs of the cables are of particular interest then this can be calculated using the total Net Present Value (NPV) of the cable as follows:

N

Ct + C0 t t =1 (1 + r )

NPV = ∑

With: C0 Ct R T N

: Investment costs [€] : Yearly costs due to electrical losses cabling [€] : Discount rate [7%] : Year [‐] : Period over which return has to be achieved in years [15 years in this example]

Table A1‐4 shows the NPV calculation for 3c x 800mm2 submarine cable throughout the 15 years subsidy period of the project. The total value of the losses part of the NPV is €6,580,423.56. The capital cost value has not been added in this example. NPV Calculation for 3c x 800mm2 Submarine Cable YEAR NPV w/o C0 Invest. Costs, C0 NPV/Yr 1 € 675,229.10 € 0.00 € 675,229.10 2 € 631,055.23 € 0.00 € 631,055.23 3 € 589,771.24 € 0.00 € 589,771.24 4 € 551,188.08 € 0.00 € 551,188.08 5 € 515,129.05 € 0.00 € 515,129.05 6 € 481,429.01 € 0.00 € 481,429.01 7 € 449,933.66 € 0.00 € 449,933.66 8 € 420,498.75 € 0.00 € 420,498.75 9 € 392,989.48 € 0.00 € 392,989.48 10 € 367,279.89 € 0.00 € 367,279.89 11 € 343,252.23 € 0.00 € 343,252.23 12 € 320,796.48 € 0.00 € 320,796.48 13 € 299,809.79 € 0.00 € 299,809.79 14 € 280,196.07 € 0.00 € 280,196.07 15 € 261,865.49 € 0.00 € 261,865.49 TOTAL € 6,580,423.56 € 0.00 € 6,580,423.56 Table A1‐4. NPV Calculation for 3c x 800mm2 Submarine Cable

348

Table A1‐5 shows the NPV calculation for 3c x 1000mm2 submarine cable throughout the 15 years subsidy period of the project. The total value of the losses part of the NPV is €5,960,868.14. The capital cost value has not been added in this example.

NPV Calculation for 3c x 1000mm2 Submarine Cable YEAR NPV w/o C0 Invest. Costs,C0 NPV/Yr 1 € 611,655.40 € 0.00 € 611,655.40 2 € 571,640.56 € 0.00 € 571,640.56 3 € 534,243.52 € 0.00 € 534,243.52 4 € 499,293.01 € 0.00 € 499,293.01 5 € 466,628.98 € 0.00 € 466,628.98 6 € 436,101.85 € 0.00 € 436,101.85 7 € 407,571.82 € 0.00 € 407,571.82 8 € 380,908.24 € 0.00 € 380,908.24 9 € 355,989.01 € 0.00 € 355,989.01 10 € 332,700.01 € 0.00 € 332,700.01 11 € 310,934.59 € 0.00 € 310,934.59 12 € 290,593.08 € 0.00 € 290,593.08 13 € 271,582.31 € 0.00 € 271,582.31 14 € 253,815.25 € 0.00 € 253,815.25 15 € 237,210.51 € 0.00 € 237,210.51 TOTAL € 5,960,868.14 € 0.00 € 5,960,868.14 Table A1‐5. NPV Calculation for 3c x 1000mm2 Submarine Cable

349

Appendix 2 Failure Modes, Effects and Criticality Analysis (FMECA) 1.

Introduction

Failure modes effects and criticality analysis (FMECA) (also called failure modes and effects analysis (FMEA)), is one of the most widely used and most effective design reliability analysis methods. The principle of FMECA is to consider each mode of failure of every component of a system and to ascertain the effects on system operation of each failure mode in turn. Failure effects may be considered at more than one level, for example at subsystem and at overall system level. Failure modes are classified in relation to the severity of their effects. FMECA may be based on a hardware or a functional approach. In the hardware approach actual hardware failure modes are considered (e.g. resistor short‐circuited, valve seized, etc.). The functional approach is used when hardware items cannot be uniquely identified or in early design stages when hardware is not fully defined. In this approach function failures are considered (e.g. no voltage output, memory wiped, etc.). FMECA can also be performed using a combination of hardware and functional approaches.

Table A2‐1. A simple FMEA analysis FMEA is a non‐quantitative method, which serves to highlight failure modes whose effects would be considered important in relation to severity, detectability, maintainability or safety. Table A2‐1 shows a part of a simple example (in this case hardware based) which includes the rating of the severity of each failure mode for prioritisation of work. FMECA includes all of the elements of a FMEA as well as consideration of failure rate or probability, failure mode ratio and a quantitative assessment of criticality, in order to provide a quantitative criticality rating for the component or function.

350

2.

Performing a FMECA Study

FMECA is not a trivial task, and can involve many hours or weeks of work. An effective FMECA can be performed only by an engineer or team of engineers that have a thorough knowledge of the system's design and application. The first step therefore is to obtain all the information available on the design. This includes specifications, drawings, computer‐aided design data, stress analysis, test results, etc., to the extent they are available at the time. For a criticality analysis, the reliability prediction information must also be available or it might be generated simultaneously. A system functional block diagram and reliability block diagram should be prepared as these are the basis for preparing the FMECA and for understanding the completed analysis. If the system operates in more than one phase in which different functional relationships or item operating modes exist, these must be considered separately in the analysis. The effects of redundancy must also be considered by evaluating the effects of failure modes assuming that the redundant subsystem is or is not available. A FMECA can be performed from different perspectives, such as safety, availability, repair costs, etc. It is necessary to decide, and to state, the perspective or perspectives being considered in the analysis. For example, a safety‐related FMECA might give a low criticality number to an item whose reliability seriously affects availability, but which is not safety critical. The FMECA is then prepared, using the appropriate worksheet, and working to the item or sub‐assembly level considered appropriate, bearing in mind the design data available and the objectives of the analysis. For a new design, particularly when the effects of failures are serious (high warranty costs, reliability reputation, safety, etc.) the analysis should take account of all failure modes of all components. However, it might be appropriate to consider functional failure modes of subassemblies when these are based upon existing designs, e.g. modular power supplies in electronic systems, particularly if the design details are not known. The FMECA should be started as soon as initial design information is available. It should be performed iteratively as the design evolves, so that the analysis can be used to influence the design and to provide documentation of the eventually completed design. Design options should be separately analysed, so that reliability implications can be considered in deciding on which option to choose. Test results should be used to update the analysis. It is important to coordinate the design activities, so that the most effective use can be made of the FMECAs in all of them, and to ensure that FMECAs are available at the right time and to the right people. It can be difficult to trace the effects of low‐level failures correctly through complex systems. If the system has been designed or modelled using engineering design software, this can be used to assist in the analysis where it supports such functionality, thus aiding the task of working out the effects of component‐level failures on the operation of complex systems. Even with aids such as these, FMECA can be an inappropriate method for some designs, such as digital electronic systems in which low level failures (e.g. of transistors within integrated circuits) are very, but uniformly, unlikely, and the effects are dynamic in the sense that they could differ widely depending up on the state of the system. FMECA has been, and continues to be, widely used in many industries, particularly in those for which failures can have serious consequences, such as military, aerospace, automotive, medical equipment, etc. Some industries have established standardized approaches (the US Military Standard is MIL‐Handbook‐1629, and the US automotive companies have also 351

produced a guidance document). However, these are valid approaches for their respective technologies, but often are inappropriate for other technology types.

3.

Component Failure Rates

Since FMECAs are performed primarily to identify critical failure modes and to evaluate design options, failure rate or reliability values which could be considered as realistic worst cases should be used. Standard methods sometimes stipulate the reliability prediction methods to be used, e.g. MIL‐HDBK‐217 for electronics. However, it is very important to appreciate the large amount of uncertainty inherent in reliability prediction, particularly at the level of individual failure events. Therefore, worst‐case or pessimistic reliability values should always be used as input assumptions for failure modes which are identified as critical, or which might be critical if the pessimistic assumption proved to be realistic. Alternatively, and preferably unless credible quantitative data is available, a value scale such as 0‐1 should be used, with prearranged assignment (e.g. 1 = will definitely occur, 0.5 = will occur occasionally, 0.1 = will rarely occur, 0 = will never occur). Generally, the more critical the failure mode the more pessimistic should be the worst‐case reliability assumptions.

4.

Computerized FMECA

Computer programs have been developed for performance of FMECA. Using a computer program instead of FMECA worksheets allows FMECAs to be produced more quickly and accurately, and greatly increases the ease of editing and updating to take account of design changes, design options, different viewpoints, and different input assumptions. Like any other computer‐aided design technique, computerized FMECA frees engineers to concentrate on engineering, rather than on tedious compilation, so that for the same total effort designs can be more thoroughly investigated or less effort can be expended for the same depth of analysis. Also, by eliminating the more tedious and time‐consuming aspects of the work, engineers' motivation and effectiveness is increased. Computerized FMECA enables more perceptive analysis to be performed. Failure effects can be ranked in criticality order, at different system levels, in different phases of system operation and from different viewpoints. Report preparation can be partly automated and sensitivity analyses quickly performed. It is also possible, and effective, to use a spreadsheet to create a FMECA. This method has the advantage that the format and type of analysis can be designed to suit the particular design and methods of analysis. Modern integrated software also allows a wide range of graphic presentations to be created, databases to be used for reliability information, and for the analysis to be incorporated into word processors for report preparation. Computer‐aided engineering (CAE) software, when used to create and analyse designs, can be used to perform FMECAs. Use of CAE permits very detailed, objective analyses to be made, covering transient and dynamic conditions, which can be very difficult to analyse manually. For example, some electronic design software can be used to determine the effects on circuit operation of component failure modes, by running the simulation with parameter values set at the failure conditions. Mechanical design CAE software can be similarly used in some cases, for example finite element analysis (FEA) software can be used to analyse the effects of mechanical or thermal stress. The SABER™ (Avanti Corp.) program enables FMECAs of mixed‐technology designs to be created and for the FMECA to be automated using a database of component failure modes. 352

5.

Benefits of a FMECA study

FMECA can be used very effectively for several purposes, in addition to the prime one of identifying safety or reliability critical failure modes and effects. These include: 1. Identifying features to be included in the test programme. 2. Preparation of diagnostic routines such as flowcharts or fault‐finding tables. FMECA provides a convenient listing of the failure modes which produce particular failure effects or symptoms, and the relative likelihoods of occurrence. 3. Preparation of preventive maintenance requirements. The effects and likelihood of failures can be considered in relation to the need for scheduled inspection, servicing or replacement. For example, if a failure mode has an insignificant effect on safety or operating success, the item could be replaced only on failure rather than at scheduled intervals, to reduce the probability of failure. 4. Formal records of the safety and reliability analysis, to be used as evidence if required in reports to customers or in litigation.

353

APPENDIX 3 Cables

Power Transmission with Long A.C. Submarine

1.

Definitions

1.1.

Signs of Variables and Definition of Voltages

Directions of currents and powers are according Figure A3‐1. At the sending end have powers positive sign when fed into the line. At the receiving end have powers positive sign when taken out of the line. Index 1 means variables at the sending end and index 2 means variables at the receiving end. Sending end U1 I1 P1 Q1

d km

Receiving end U2 I2 P2 Q2

Figure A3‐1. Definition of voltages is according to IEC 60183. Rated voltage U = the rated r.m.s. power frequency voltage between any two conductors for which cables and accessories are designed. Maximum voltage Um = the maximum r.m.s. power frequency voltage between any two conductors for which cables and accessories are designed. It is the highest voltage that can be sustained under normal operating conditions at any time and at any point in the system. It excludes temporary voltage variations due to fault conditions and the sudden disconnection of large loads. Size of voltage The voltage at the sending U1 end is kept constant and defined as the normal voltage at which the network is operated.

1.2.

Ferranti Effect

There is a voltage rise at the receiving end on open‐circuit due to the line charging current. The voltage rise on open‐circuit is referred to as the Ferranti effect. The voltage rise depends on the length of the line. The voltage rise must not be so high that maximum voltage of the network is overridden.

1.3.

Uncompensated Line

An uncompensated line reaches maximum length when receiving end is open and maximum voltage at receiving end is reached.

1.4.

Compensated Line

A compensated line has shunt reactors at the ends to keep voltage rise at the ends below maximum voltage of the network. The shunt reactors are assumed to compensate the charging power of the cable at respective end. This means that the power Q1 has negative sign. 354

1.5.

Maximum Length of Cable

The maximum continuous current IN of a cable is limited by the maximum temperature of the conductor. The maximum current IN is the rated current of the cable and calculated at the conductor temperature 90 °C. The maximum length of the cable is defined according: 1. The powers P2 and Q2 are adjusted to give absolute values of the currents at cable ends below or equal to the rated current of the cable: I1 = I 2 ≤ I N

Shunt reactors at both ends are designed to compensate for Q1 and Q2. 2. When the load P2 at receiving end is disconnected must not any of the currents |I1| or |I2| be greater than the rated current IN. The shunt reactors are still connected to the cable. 2. Selection of cable design Maximum transmission capacities are calculated for 150 kV and 220 kV 3‐core cables buried in sea bed and used for transmission of power over long distances. The design and transmission capacity of a buried cable depends on: 1. Conductor cross‐section 2. Conductor material 3. Burial depth in ground 4. Ambient temperature at burial depth 5. Thermal resistivity of ground 6. Maximum voltage drop compensated cable 7. Maximum voltage rise no load
2.1.

Ambient Conditions

Typical values of temperature and thermal resistivity for Europe are chosen: θ = 15 °C at burial depth ρ = 1,0 K×m/W thermal resistivity of ground Drying out of backfill close to the cable is not considered.

2.2.

Burial Conditions

Common burial conditions are chosen: H = 1,0 m burial depth to centre of cables

3.

Cable Design

Cable designs with voltages 110 kV, 132 kV, 150 kV and 220 kV and equal conductor cross‐ section copper 630 mm2 are analyzed.

355

4.

Electrical Data Cables U kV 110 132 150 220

U Um Ac λ1 λ2 R1 L1 C1 In

Um kV 123 145 170 245

Ac mm2 630 630 630 630

λ2 p.u. 0,4632 0,4687 0,4719 0,4685

R1 ohm/km 0,064 0,065 0,066 0,068

L1 mH/km 0,366 0,377 0,389 0,427

C1 µF/km 0,239 0,215 0,196 0,161

In A 738 738 736 731

= Rated voltage between two conductors = Maximum voltage between two conductors = Cross‐section conductor = Ratio of losses in lead sheath and losses in conductor = Ratio of losses in armour and losses in conductor = Positive sequence resistance at 70 °C conductor temperature = Positive sequence impedance = Positive sequence capacitance = Rated current at 90 °C conductor temperature

5.

110 kV Cable

5.1.

Absolute Values

d km 20 40 60 80 100 120 140 160 180

λ1 p.u. 0,1096 0,2083 0,2302 0,3064

U1 kV 110 | | | | | | | |

I1 A 739 739 739 739 736 733 730 725 719

P1 MW 140,6 140,1 139,2 137,8 136,0 133,7 130,8 127,1 122,1

Q1 MVAr ‐7,1 ‐14,0 ‐20,7 ‐27,3 ‐33,8 ‐40,4 ‐47,2 ‐54,1 ‐61,6

∆P MW 2,1 4,2 6,2 8,2 10,0 11,6 13,1 14,3 15,3

∆U % 1,5 3,0 4,4 5,9 7,3 8,7 10,0 11,2 12,3

1) Losses in percent of P2 Voltage drop limits length of cable

356

U2 kV 108,4 106,7 105,1 103,5 102,0 100,5 99,0 97,7 96,5

I2 A 739 | | | | | | | |

P2 MW 138,5 135,9 133,0 129,7 126,1 122,1 117,7 112,7 107,2

∆P1) % 1,5 3,0 4,4 5,9 7,3 8,7 10,0 11,2 12,3

Q2 MVAr 7,0 13,9 20,6 27,2 33,8 40,3 47,1 54,1 61,5

5.2.

Normalised Values

Ub = 110 kV Ib = 739 A Sb = 141 MVA d km 20 40 60 80 100 120 140 160 180

I1 A 1,000 1,000 1,000 1,000 0,996 0,992 0,988 0,981 0,973

P1 MW 0,997 0,994 0,987 0,977 0,965 0,948 0,928 0,901 0,866

Q1 MVAr ‐0,050 ‐0,099 ‐0,147 ‐0,194 ‐0,240 ‐0,287 ‐0,335 ‐0,384 ‐0,437

∆P MW 0,015 0,030 0,044 0,058 0,071 0,082 0,093 0,101 0,109

∆U % 0,015 0,030 0,044 0,059 0,073 0,087 0,100 0,112 0,123

357

U2 kV 0,985 0,970 0,955 0,941 0,927 0,914 0,900 0,888 0,877

P2 MW 0,982 0,964 0,943 0,920 0,894 0,866 0,835 0,799 0,760

∆P1) % 0,011 0,021 0,031 0,042 0,052 0,062 0,071 0,079 0,087

Q2 MVAr 0,050 0,099 0,146 0,193 0,240 0,286 0,334 0,384 0,436

6.

Export Cable

6.1.

Absolute Values

d U1 I1 P1 Q1 ∆P ∆U km kV A MW MVAr MW % 20 132 739 168,7 ‐9,7 2,1 1,3 40 | 739 167,9 ‐19,2 4,3 2,5 60 | 739 166,4 ‐28,5 6,3 3,7 80 | 738 164,4 ‐37,7 8,2 4,9 100 | 736 161,6 ‐46,9 10,0 6,1 120 | 733 157,9 ‐56,3 11,6 7,2 140 | 730 153,4 ‐65,9 13,0 8,2 160 | 726 147,6 ‐75,9 14,0 9,1 180 | 720 140,2 ‐86,4 14,7 9,8 200 | 714 130,7 ‐98,0 15,0 10,3 220 | 708 118,1 ‐110,8 14,7 10,3 240 | 704 100,3 ‐125,8 13,7 9,6 260 | 706 71,2 ‐145,0 11,9 7,3 1) Losses in percent of P2 Reactive power generation limits length of cable.

6.2.

U2 kV 130,3 128,7 127,1 125,5 123,9 122,5 121,1 120,0 119,0 118,4 118,4 119,3 122,3

I2 A 739 | | | | | | | | | | | |

P2 MW 166,5 163,6 160,1 156,1 151,5 146,3 140,4 133,5 125,4 115,7 103,4 86,6 59,3

∆P1) % 1,3 2,6 3,9 5,3 6,6 7,9 9,3 10,5 11,7 13,0 14,2 15,8 20,1

Q2 MVAr 9,6 19,1 28,4 37,6 46,9 56,2 65,8 75,8 86,4 97,9 110,7 125,7 144,9

Normalised Values

Ub = 132 kV Ib = 739 A Sb = 169 MVA d I1 km A 20 1,000 40 1,000 60 1,000 80 0,999 100 0,996 120 0,992 140 0,988 160 0,982 180 0,974 200 0,966 220 0,958 240 0,953 260 0,955

P1 MW 0,998 0,993 0,985 0,973 0,956 0,934 0,908 0,873 0,830 0,773 0,699 0,593 0,421

Q1 MVAr ‐0,057 ‐0,114 ‐0,169 ‐0,223 ‐0,278 ‐0,333 ‐0,390 ‐0,449 ‐0,511 ‐0,580 ‐0,656 ‐0,744 ‐0,858

∆P MW 0,012 0,025 0,037 0,049 0,059 0,069 0,077 0,083 0,087 0,089 0,087 0,081 0,070

∆U % 0,013 0,025 0,037 0,049 0,061 0,072 0,082 0,091 0,098 0,103 0,103 0,096 0,073

358

U2 kV 0,987 0,975 0,963 0,951 0,939 0,928 0,917 0,909 0,902 0,897 0,897 0,904 0,927

P2 MW 0,985 0,968 0,947 0,924 0,896 0,866 0,831 0,790 0,742 0,685 0,612 0,512 0,351

∆P1) % 0,008 0,015 0,023 0,031 0,039 0,047 0,055 0,062 0,069 0,077 0,084 0,093 0,119

Q2 MVAr 0,057 0,113 0,168 0,222 0,278 0,333 0,389 0,449 0,511 0,579 0,655 0,744 0,857

359

7.

150 kV Cable

7.1.

Absolute Values

d U1 I1 P1 Q1 ∆P ∆U km kV A MW MVAr MW % 20 150 737 191,1 ‐11,7 2,2 1,1 40 | 737 190,1 ‐23,2 4,3 2,2 60 | 737 188,2 ‐34,6 6,4 3,3 80 | 736 185,5 ‐45,8 8,3 4,4 100 | 734 182,0 ‐57,1 10,1 5,4 120 | 732 177,3 ‐68,6 11,6 6,4 140 | 729 171,4 ‐80,4 12,9 7,2 160 | 725 163,9 ‐92,7 13,9 7,9 180 | 720 154,3 ‐105,7 14,4 8,5 200 | 715 141,8 ‐119,8 14,5 8,7 220 | 710 124,9 ‐135,5 14,0 8,5 240 | 708 100,3 ‐154,1 12,8 7,5 260 | 718 52,3 ‐179,1 10,6 4,0 1) Losses in percent of P2 Reactive power generation limits length of cable.

7.2.

U2 kV 148,3 146,6 145,0 143,4 141,9 140,5 139,2 138,1 137,3 136,9 137,2 138,8 143,9

I2 A 737 | | | | | | | | | | | |

P2 MW 188,9 185,7 181,9 177,2 171,9 165,7 158,4 150,0 139,9 127,3 111,0 87,6 41,5

∆P1) % 1,2 2,3 3,5 4,7 5,9 7,0 8,1 9,3 10,3 11,4 12,6 14,6 25,5

Q2 MVAr 11,7 23,2 34,5 45,8 57,1 68,5 80,3 92,6 105,6 119,7 135,5 154,0 179,0

Normalised Values

Ub = 150 kV Ib = 737 A Sb = 192 MVA d I1 km A 20 1,000 40 1,000 60 1,000 80 0,999 100 0,996 120 0,993 140 0,989 160 0,984 180 0,977 200 0,970 220 0,963 240 0,961 260 0,974

P1 MW 1,001 0,995 0,985 0,971 0,953 0,928 0,897 0,858 0,808 0,742 0,654 0,525 0,274

Q1 MVAr ‐0,061 ‐0,121 ‐0,181 ‐0,240 ‐0,299 ‐0,359 ‐0,421 ‐0,485 ‐0,553 ‐0,627 ‐0,709 ‐0,807 ‐0,938

∆P MW 0,012 0,023 0,034 0,043 0,053 0,061 0,068 0,073 0,075 0,076 0,073 0,067 0,055

∆U % 0,011 0,022 0,033 0,044 0,054 0,064 0,072 0,079 0,085 0,087 0,085 0,075 0,040

360

U2 kV 0,989 0,977 0,967 0,956 0,946 0,937 0,928 0,921 0,915 0,913 0,915 0,925 0,959

P2 MW 0,989 0,972 0,952 0,928 0,900 0,868 0,829 0,785 0,732 0,666 0,581 0,459 0,217

∆P1) % 0,006 0,012 0,018 0,025 0,031 0,037 0,042 0,049 0,054 0,060 0,066 0,076 0,134

Q2 MVAr 0,061 0,121 0,181 0,240 0,299 0,359 0,420 0,485 0,553 0,627 0,709 0,806 0,937

361

8.

220 kV Cable

8.1.

Absolute Values

d U1 I1 P1 Q1 ∆P ∆U km kV A MW MVAr MW % 20 220 732 278,0 ‐22,2 2,2 0,8 40 | 732 275,4 ‐44,1 4,4 1,6 60 | 732 270,9 ‐65,9 6,4 2,3 80 | 731 264,3 ‐87,7 8,3 3,0 100 | 729 255,2 ‐109,8 9,9 3,6 120 | 727 243,4 ‐132,4 11,1 4,2 140 | 724 227,9 ‐155,7 11,9 4,6 160 | 721 207,4 ‐180,2 12,3 4,8 180 | 718 209,7 ‐206,5 12,0 4,7 200 | 717 138,0 235,7 10,9 4,0 220 | 726 46,8 ‐272,5 8,9 1,4 1) Losses in percent of P2 Reactive power generation limits length of cable.

8.2.

U2 kV 218,3 216,6 215,5 213,4 212,0 210,8 209,9 209,5 209,7 211,2 216,9

I2 A 732 | | | | | | | | | |

P2 MW 275,8 271,0 264,5 256,0 245,4 232,3 215,9 195,1 165,7 127,1 37,9

∆P1) % 0,8 1,6 2,4 3,2 3,9 4,8 5,5 6,3 7,2 8,6 23,5

Q2 MVAr 22,2 44,1 65,8 87,6 109,7 132,3 155,7 180,2 206,5 235,7 272,4

Normalised Values

Ub = 220 kV Ib = 732 A Sb = 279 MVA d km 20 40 60 80 100 120 140 160 180 200 220

I1 A 1,000 1,000 1,000 0,999 0,996 0,993 0,989 0,985 0,981 0,980 0,992

P1 MW 0,996 0,987 0,971 0,947 0,915 0,872 0,817 0,743 0,752 0,495 0,168

Q1 MVAr ‐0,080 ‐0,158 ‐0,236 ‐0,314 ‐0,394 ‐0,475 ‐0,558 ‐0,646 ‐0,740 0,845 ‐0,977

∆P MW 0,008 0,016 0,023 0,030 0,035 0,040 0,043 0,044 0,043 0,039 0,032

∆U % 0,008 0,016 0,023 0,030 0,036 0,042 0,046 0,048 0,047 0,040 0,014

362

U2 kV 0,992 0,985 0,980 0,970 0,964 0,958 0,954 0,952 0,953 0,960 0,986

P2 MW 0,989 0,971 0,948 0,918 0,880 0,833 0,774 0,699 0,594 0,456 0,136

∆P1) % 0,003 0,006 0,009 0,011 0,014 0,017 0,020 0,023 0,026 0,031 0,084

Q2 MVAr 0,080 0,158 0,236 0,314 0,393 0,474 0,558 0,646 0,740 0,845 0,976

Comments to Figures The figures show that the voltage drop is the limiting factor at low rated voltages and that the influence of the reactive power generation limits the transmitted power at higher voltages. It is also obvious according the transmission line equations where per unit voltage and current are introduced: I ( x)  ∂u ( x)  ∂x = − Z ⋅ U  b  i ( x ) U ( x) ∂  = − jω C ⋅  ∂x Ib

Ub and Ib are base values for expression of per unit values. The first equations shows decreased relative voltage drop at increased voltage. The second equations shows increased generated capacitive current at increased voltage. In second equation are the conductive losses neglected.

363

APPENDIX 4

Codes and Standards per Discipline

HV Transformer • •

CENELEC HD 398.3 CENELEC HD 398.5

•

DEFU R2

•

DEFU R20

•

DEFU KR94

• • • • •

EN 12079 IEC 60044 IEC 60038 IEC 60076 IEC 60076‐14

• • •

IEC 60137 IEC 60214 IEC 60296

•

IEC 60354

• •

IEC 60529 IEC 60599

•

IEC 60721‐2‐6

•

IEC 60815

• • •

IEC 61000 IEC 61892 IEC 62271

Power Transformers Insulation Level and Dielectric Tests Power Transformers, Part 5: Ability to Withstand Short‐ Circuit Technical terms and conditions of transformers for 132‐ 150 kV/50‐60 Hz system voltage and with a rated power of 63‐200 MVA Tekniske bestemmelser for apparater til 132‐150 kV udendørs stationsanlæg Håndtering af SF6 og dets reaktionsprodukter i elforsyningsanlæg Offshore containers and associated lifting sets Instrument transformers IEC standard voltages Power transformers Design and application of liquid‐immersed power transformers using high‐temperature insulation materials Insulated bushings for alternating voltages above 1000 V Tap‐changers Fluids for electrotechnical applications – Unused mineral insulating oils for transformers and switchgear Loading guide for oil‐immersed power transformers (Overload capacity) Degrees of protection provided by enclosures (IP Code) Mineral oil‐impregnated electrical equipment in service – Guide to the interpretation of dissolved and free gases analysis Classification of environmental conditions, Environmental conditions appearing in nature – Earthquake vibration and shock Guide for the selection of insulators in respect of polluted conditions Electromagnetic compatibility (EMC) Mobile and fixed offshore units – Electrical installations High‐voltage switchgear and controlgear

HV & MV Switchgear •

DEFU KR94

•

EN 12079

Håndtering af SF6 og dets reaktionsprodukter i elforsyningsanlæg Offshore containers and associated lifting sets

364

•

EN 50181

•

EN 50052

•

EN 60694

• •

IEC 60044‐1 IEC 60044‐2

•

IEC 60071‐1

• •

IEC 60071‐2 IEC 60099‐4

• •

IEC 60137 IEC 60270

•

IEC 60376

• •

IEC 60417 IEC 60439‐1

•

IEC 60480

• •

IEC 60529 IEC 60694

•

IEC 61000‐5‐1

•

IEC 61000‐5‐1

•

IEC 61634

•

IEC 62271‐100

•

IEC 62271‐102

•

IEC 62271‐200

Plug‐in type bushings above 1 up to 36 kV and from 250 A to 1,25 kA for equipment other than liquid filled transformers Cast aluminium alloy enclosures for gas‐filled high‐ voltage switchgear and controlgear Common specifications for high‐voltage switchgear and controlgear standards (Amendment A1 & A2 to IEC 60694) Instrument transformers – Current transformers Instrument transformers – Inductive voltage transformers Insulation co‐ordination – Definitions, principles and rules Insulation co‐ordination – Application guide Surge arresters – Metal‐oxide surge arresters without gaps for a.c. systems Insulated bushings for alternating voltages above 1000 V High‐voltage test techniques – Partial discharge measurements Specification of technical grade sulphur hexafluoride (SF6) for use in electrical equipment Graphical symbols for use on equipment Low‐voltage switchgear and controlgear assemblies – Type‐tested and partially type‐tested assemblies Guideline for the checking and treatment of sulphur hexafluoride (SF6) taken from electrical equipment and specification for its re‐use Degrees of protection provided by enclosure (IP Code) Common specifications for high‐voltage switchgear and controlgear standards (phased out, but remains reference to IEC 62271‐200 and IEC 62271‐203) Electromagnetic compatibility (EMC) – Installation and mitigation guidelines – General considerations Electromagnetic compatibility (EMC) – Installation and mitigation guidelines – Earthing and cabling High‐voltage switchgear and controlgear – Use and handling of sulphur hexafluoride (SF6) in high‐voltage switchgear and controlgear High‐voltage switchgear and controlgear – High‐voltage alternating‐current circuit‐breakers High‐voltage switchgear and controlgear – High‐voltage alternating‐current disconnectors andearthing switches High‐voltage switchgear and controlgear – AC metal‐ enclosed switchgear and controlgear for rated voltages above 1kV and up to and including 52 kV

365

•

IEC 62271‐203

•

IEC 62271‐209

High‐voltage switchgear and controlgear – Gas‐insulated metal‐enclosed switchgear for rated voltages above 52 kV High‐voltage switchgear and controlgear – Cable connections for gas‐insulated metal‐enclosed switchgear for rated voltages above 52 kV – Fluid‐filled and extruded insulation cables‐ Fluid‐filled and dry‐type cable‐ terminations

HV, MV, LV and Signal Cables and Cable Routing • •

ANSI/TIA 568B EN 50167

• • • • • • • • • • •

EN 50173 IEC 11801 IEC 60038 IEC 60092 IEC 60183 IEC 60287 IEC 60228 IEC 60331 IEC 60332 IEC 60364 IEC 60502

•

IEC 60724

• • • •

IEC 60754 IEC 60793 IEC 60794 IEC 60840

• • •

IEC 60863 IEC 60885 IEC 60949

•

IEC 60986

• •

IEC 61034 IEC 61034

•

IEC 61443

•

IEC 61892

Communications cabling standard Sectional specification for horizontal floor wiring cables with a common overall screen for use in digital communication Information technology – Generic cabling systems Information technology – Generic cabling for customer premises IEC standard voltages Electrical installations in ships Guide to the selection of high‐voltage cables Electric cables – Calculating of the current rating Conductors of insulated cables Tests for electrical cables under fire conditions Tests on electric and optical fibre cables under fire conditions Low‐voltage electrical installations Power cables with extruded insulation and their accessories for rated voltages 1 kV ‐ 30 kV. Short‐circuit temperature limits of electric cables with rated voltages from of 1 (Um=1,2 kV) and up to 3 (Um=3,6 kV) Test on gasses evolved during combustion of electric cables Optical fibres Optical fibre cables Power cables with extruded insulation and their accessories for rated voltages above 30 (Um= 36 kV) up to 150 kV (Um=170 kV) – Test methods and requirements Cyclic rating Electrical test methods for electrical cables Calculation of thermally permissible short‐circuit currents, taking into account non‐adiabatic heating effects Short‐circuit temperature limits of electric cables with rated voltages from of 6 kV (Um=7,2 kV) and up to 30 kV (Um=36 kV) Measurement of smoke density of cables burning under Measurement of smoke density of cables burning under defined conditions Short‐circuit temperature limits of electric cables with rated voltages above 30 kV (Um=36 kV) Mobile and fixed offshore units – Electrical installations 366

•

IEC 62067

•

IEC/TR 62095

Power cables with extruded insulation and their accessories for rated voltages above 150 kV Electric cables – Calculation for current ratings – Finite element method

Earthing, bonding and Lightning Protection • • •

DS/EN 50164 IEC 60092 IEC 60364

• • • • •

IEC 61000 IEC 61892 IEC 62305 DEFU Recom‐

Lightning Protection Components Electrical installations in ships Low voltage electrical installations ‐ Protection for safety and protection against electric shock Electromagnetic compatibility (EMC) Mobile and fixed offshore units – Electrical installations Protection against lightning Lightning protection of wind turbines mendations Nr. 25

Scada and Communication • •

IEC 60092 IEC 60364

• • • • •

IEC 60529 IEC 60870 IEC 61000 IEC 61892 IEC 61850

Electrical installations in ships Low voltage electrical installations ‐ Protection for safety and protection against electric shock. Degrees of protection provided by enclosures (IP Code) Tele control equipment and systems Electromagnetic compatibility (EMC) Mobile and fixed offshore units – Electrical installations Communication, networks and systems in substations

Electrical Equipment and Installation of lightning, small Power and Navigation Aids • •

IEC 60092 IEC 60364

• • • •

IEC 60529 IEC 61000 IEC 61892 DS 700

•

EN 1838

Electrical installations in ships Low voltage electrical installations ‐ Protection for safety and protection against electric shock. Degrees of protection provided by enclosures (IP Code) Electromagnetic compatibility (EMC) Mobile and fixed offshore units – Electrical installations “kunstig belysning I arbejdslokaler” (Directions for artificial lighting in work rooms). Lighting Applications – Emergency Lighting

Platform Power Supply • • • •

IEC 60034 IEC 60038 IEC 60076 IEC 60092

Rotating electrical machines IEC standard voltages Power transformers Electrical installations in ships 367

• • •

IEC 60354 IEC 60439 IEC 60909‐0

• • • •

IEC 60529

• •

IEC 61000 IEC 61660‐1

• • •

IEC 61892 ISO 8528

• •

NFPA 20 NFPA 25

•

NFPA 70

IEC 60947 IEC 61363‐1

Loading guide for oil‐immersed power transformers Low‐voltage switchgear and controlgear assemblies Short‐circuit currents in three‐phase a.c. systems, Part 0: Calculations of currents Degrees of protection provided by enclosures (IP Code) Low‐voltage switchgear and controlgear Electrical installations in ships and mobile and fixed offshore units, Part 1: Procedures for calculating short‐circuit currents in three‐phase a.c. Electromagnetic compatibility (EMC) Short‐circuit currents in d.c. auxiliary installations in power plants and substations. Part 1: Calculation of short‐circuit currents Mobile and fixed offshore units – Electrical installations Reciprocating internal combustion engine driven alternating current generating sets Installation of Stationary Pumps for Fire Protection Standard for the Inspection, Testing and Maintenance of Water‐ Based Fire Protection Systems National Electrical Code

Fire Protection of Electrical Systems and Hazardous Materials • • •

NORSOK S‐001 DS/EN 54 series DS/CEN/TS 54‐14

• •

NFPA 72 NFPA 2001

“Technical safety” – Edition 4, February 2008 Fire detection and fire alarm systems Fire detection and fire alarm systems: Guidelines for planning, design, installation, commissioning, use and maintenance National Fire Alarm Code Clean agent fire extinguishing systems

Ventilation System DS/EN ISO 15138

Petroleum and Natural gas Industries – Offshore production installations – Heating, ventilation and air‐ conditioning.

DS 447

Code of Practice installations

DS 452

Code of practice for thermal insulation of technical service and supply systems in buildings

for

368

mechanical

ventilation

DS 474

Code for Indoor Thermal Climate

Eurovent 2/2

Air leakage rate in sheet metal air distribution systems

SBI – 102

Danish Building Research Institute (SBI) – Specification 102. Measurements in ventilating systems.

2006/42/EC

Machinery Directive (DK version = 2006/42/EF)

Materials and Fabrication of Topside Structures. API 2B

Specification for fabricated structural steel pipe

API 5L

Specification for line pipe

ASME, Section V

Article 7, Magnetic Particle Examination

ASME, Section V

Article 9, Visual Examination

ASME, Section IX

Qualification standard for welding and brazing procedures, welders, brazers and welding and brazing operators

AWS D1.1

Structural welding code ‐ steel

BS 7448

Part 1, Specification for fracture mechanics toughness test

DNV‐OS‐C101 (DNV standard)

Design of offshore steel structures (LRFD method)

DNV‐OS‐C401 (DNV standard)

Fabrication and testing of offshore structures

DNV‐OS‐E401 (DNV standard)

Offshore standard, Helicopter Decks

EN 287‐1

Approval Testing of Welders for Fusion Welding.

EN 473

Qualification and certification of NDT personnel. General principles.

EN 970

Welding – Visual Examination of Fusion Welded Joints.

EN 1011

Recommendations for Arc Welding of Ferritic steels.

369

EN 1418

Welding personnel – Approval testing of welding personnel for fully mechanized and automatic welding of metallic materials

EN 10002‐1

Metallic Materials ‐ Tensile Testing ‐ Part 1. Method of Test.

EN 10025

Hot Rolled Products of Non‐Alloy Structural Steels. Technical Delivery Conditions.

EN 10225YAC

Weldable structural steels for fixed offshore structures – Technical delivery conditions

EN 10045

Metallic Materials ‐ Charpy Impact Test.

EN 10163‐1 to 3

Delivery Requirements for Surface Conditions of Hot Rolled Steel Plates, Wide Flats and Section.

EN 10164

Steel Flat Products with Specified Through Thickness Properties. Technical Conditions for Delivery.

EN 10204

Metallic Products ‐ Types of Inspection Documents.

EN 10210

Hot Finished Structural Hollow Sections of Non‐Alloy and Fine Grain Structural Steels.

EN 45004

General Criteria for the Operation of Various Types of Bodies Performing Inspection.

EN ISO 5817

Welding‐Fusion‐welded joints in steel, nickel, titanium and their alloys

EN ISO 13920

Welding – General tolerances for welded constructions – dimensions for lengths and angles – Shape and position

EN ISO 17025

General Requirements for the Competence of Testing and Calibration Laboratories

ISO 898

Part 1‐6, Mechanical properties of fasteners made of carbon steel and alloy steel

ISO 1459

Protection against corrosion by hot dip galvanizing

ISO 1461

Hot dip galvanized coatings on fabricated iron and steel articles – Specifications and test methods

370

ISO 3690

Welding and allied processes. Determination of hydrogen content in ferritic arc weld metal

ISO 7090

Plain washers, chamfered. Normal series. Project grade A

ISO 8501

Part 1‐2, Preparation of steel substrates before application of paints and related products. Visual assessment of surface cleanliness.

ISO 1106

Recommended practice for radiographic Examination of Fusion Welded Joints.

ISO 2553

Welds ‐ Symbolic Representation on Drawings.

ISO 3452

NDT ‐ penetrant inspection ‐ general principles.

ISO 9606‐2

Qualification test of welders – Fusion welding of aluminium and its alloys

ISO 15614

Specification and qualification of welding procedures for metallic materials

BL 3‐5

Statens Luftfartsvæsen, Bestemmelser om helikopterdæk på havanlæg

Materials and Fabrication of Sub‐Structures API 2B

Specification for fabricated structural steel pipe

API 5L

Specification for line pipe

ASME, Section V

Article 7, Magnetic Particle Examination

ASME, Section V

Article 9, Visual Examination

ASME, Section IX

Qualification standard for welding and brazing procedures, welders, brazers and welding and brazing operators

AWS D1.1

Structural welding code ‐ steel

BS 7448

Part 1, Specification for fracture mechanics toughness test

371

DNV‐OS‐C101 (DNV standard)

Design of offshore steel structures (LRFD method)

DNV‐OS‐C401 (DNV standard)

Fabrication and testing of offshore structures

EN 287

Approval Testing of Welders for Fusion Welding.

EN 473

Qualification and certification of NDT personnel. General principles.

EN 970

Welding – Visual Examination of Fusion Welded Joints.

EN 1011

Recommendations for Arc Welding of Ferritic steels.

EN 1418

Welding personnel – Approval testing of welding personnel for fully mechanized and automatic welding of metallic materials

EN 10002‐1

Metallic Materials ‐ Tensile Testing ‐ Part 1. Method of Test.

EN 10025

Hot Rolled Products of Non‐Alloy Structural Steels. Technical Delivery Conditions.

EN 10225YAC

Weldable structural steels for fixed offshore structures – Technical delivery conditions

EN 10045

Metallic Materials ‐ Charpy Impact Test.

EN 10163‐1 to 3

Delivery Requirements for Surface Conditions of Hot Rolled Steel Plates, Wide Flats and Section.

EN 10164

Steel Flat Products with Specified Through Thickness Properties. Technical Conditions for Delivery.

EN 10204

Metallic Products ‐ Types of Inspection Documents.

EN 10210

Hot Finished Structural Hollow Sections of Non‐Alloy and Fine Grain Structural Steels.

EN 45004

General Criteria for the Operation of Various Types of Bodies Performing Inspection.

EN ISO 5817

Welding‐Fusion‐welded joints in steel, nickel, titanium and

372

their alloys EN ISO 13920

Welding – General tolerances for welded constructions – dimensions for lengths and angles – Shape and position

EN ISO 17025

General Requirements for the Competence of Testing and Calibration Laboratories

ISO 898

Part 1‐6, Mechanical properties of fasteners made of carbon steel and alloy steel

ISO 1459

Protection against corrosion by hot dip galvanizing

ISO 1461

Hot dip galvanized coatings on fabricated iron and steel articles – Specifications and test methods

ISO 3690

Welding and allied processes. Determination of hydrogen content in ferritic arc weld metal

ISO 7090

Plain washers, chamfered. Normal series. Project grade A

ISO 8501

Part 1‐2, Preparation of steel substrates before application of paints and related products. Visual assessment of surface cleanliness.

ISO 1106

Recommended practice for radiographic Examination of Fusion Welded Joints.

ISO 2553

Welds ‐ Symbolic Representation on Drawings.

ISO 3452

NDT ‐ penetrant inspection ‐ general principles.

ISO 9606‐2

Qualification test of welders – Fusion welding of aluminium and its alloys

ISO 15614

Specification and qualification of welding procedures for metallic materials

Cathodic Protection of Sub‐Structures. EN10204 EN 10204 Metallic Products – Types of Inspection Documents NORSOK 501

M‐ Standard for Surface Preparation and Protective Coating

373

DNV‐RP‐B401

DNV Recommended Practice, Cathodic Protection Design

ISO 3506

Mechanical Properties of Corrosion‐Resistant Stainless Steel Fasteners

ISO 8044

Corrosion of Metals and Alloys; Basic Terms and Definitions

ISO 8501‐1

Preparation of Steel Substrates for Application of Paint and Related Products – Visual Assessment of Surface Cleanliness. Part 1: Rust Grades and Preparation Grades of Uncoated Steel Substrates.

ISO 10005

Quality Management‐ Guidelines for Quality Plans

ISO 10474

Steel and Steel Products – Inspection Documents

NACE RP0176

Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production

NACE RP0387

Metallurgical and Inspection Requirements for Cast Sacrificial Anodes for Offshore Applications

Weight Monitoring and Weighing DS/EN ISO 19901‐5 Petroleum and natural gas industries – Specific requirements for offshore structures – Part 5: Weight control during engineering and construction. 1 Edition, 2003.11.20

Protective Coating of Steel ISO 1461 Metallic Coatings – Hot dip galvanised coating on fabricated ferrous products. NORSOK M‐501

Surface preparation and protective coating

ISO 8501‐1

Preparation of steel substrates before application of paints and related products – Visual assessment of surface cleanliness – Part 1: Rust grades and preparation grades of uncoated steel substrates and of steel substrates after overall removal of previous coatings. Informative supplement to part 1: Representative photographic examples of the change of appearance imparted to steel when blast‐cleaned with different abrasives (ISO 8501‐1:1988/Suppl: 1994). 374

ISO 8503

Preparation of steel substrates before application of paints and related products ‐ Surface roughness characteristics of blast cleaned substrates.

EN1395

Thermal spraying – Acceptance Inspection of Thermal Spraying Equipment.

ISO 12944‐8

Paints and varnishes – Corrosion protection of steel structures by protective paint systems – Part 8: Development of specification for new work and maintenance.

SSPC/SSPM Volume 2

Systems and Specifications. SSPC Painting Manual, Volume 2

WEA D.2.1

Guideline Vejledning om sandblæsning med tør fristråle i kabine og hal (Danish version only)

WEA Executive Executive Order on Work with Substances and Order No. 292 Materials (chemical agents). DNV‐OS‐J101

Design of offshore wind turbine structures, October 2007

Piping Design, Materials and Fabrication. EN 13480 EN 15614‐1 EN 287‐1 EN 1418 EN 1011 EN 13920 EN ISO 14731 ISO 3834‐2

Metallic industrial piping Specification and qualification of welding procedures for metallic materials Qualification test of welders Welding personnel Welding. Recommendations for welding of metallic materials Aluminium and aluminium alloys Welding coordination – tasks and responsibilities

ASME B31.3

Quality requirements for fusion welding of metallic materials Process piping

NORSOK M‐001

Material selection

Force Report 94

Force Technology

375