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
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Disclaimer notice
“CIGRE gives no warranty or assurance about the contents of this publication, nor does it accept any
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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
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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
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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
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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
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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
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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
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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
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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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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
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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
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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
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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
12
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.
18
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.
20
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.
21
0. Introduction
6000
600
5000
500
4000
400
3000
300
2000
200
1000
100
0
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
Wind Farm Capacity (MW)
Cumulative Capacity (MW)
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.
24
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
25
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
27
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
28
- 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
29
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:
30
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.
31
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
33
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
34
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
35
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
36
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
39
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.
40
Demand for power transmission
Percentage of installed power
120%
100%
80%
60%
40%
20%
0%
Hours per year
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
Low risk
Impact
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.
41
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
42
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).
43
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
44
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).
8750
8400
8050
7700
7350
7000
6650
6300
5950
5600
5250
4900
4550
4200
3850
3500
3150
2800
2450
2100
1750
700
1400
1050
0
8750
8400
8050
7700
7350
7000
6650
6300
5950
5600
5250
4900
4550
4200
3850
3500
0
3150
50
0
2800
100
50
2450
150
100
2100
200
150
1750
250
200
1400
300
250
1050
350
300
0
400
350
700
400
350
450
350
Failure of export cable OWF 1
450
Figure 2‐9. Transmitted (blue and green
areas) and lost (red area) energy.
45
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‐
46
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.
47
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
48
(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.
49
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.
50
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
51
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.
52
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
53
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.
54
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.
55
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
56
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.
57
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
58
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
59
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
60
•
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.
61
•
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
62
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.
63
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
64
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.
66
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.
67
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.
68
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
69
•
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
70
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
71
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
72
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
73
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.
74
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
75
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
77
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.
78
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).
79
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
80
•
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.
81
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).
82
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.
83
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.
84
M
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
85
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
86
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).
87
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.
88
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
89
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
90
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].
91
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
92
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.
M
Figure 2‐41. Cable discharged through earth switch.
93
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.
94
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.
95
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.
96
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.
97
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.
98
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.
99
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
100
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.
101
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.
102
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)
103
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
104
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.
105
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.
106
•
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.
108
•
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.
109
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
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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
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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.
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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.
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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,
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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
130
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
132
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
133
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
134
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.
135
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.
137
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.
139
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).
140
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
142
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
IEC 60076‐1 Power transformers, Part 1: General
144
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.
146
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.
149
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).
151
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)
152
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.
Compact and highly
preserved feature under
the severe environmental
condition The area of the
equipment is small.
Heat exchanger cannot
be changed easily. The
area of the equipment is
large.
System
is
slightly
redundant
and
complicated. Initial cost is
high.
It is necessary to remove
marine debris/obstacles,
it is more complicated
with high redundancy.
Running cost is high.
Disadvantage
Advantage
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.
153
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
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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
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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
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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.
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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:‐
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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.
164
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
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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
166
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
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- 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”
169
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”
170
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
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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
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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
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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
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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
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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
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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
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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,
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•
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
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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
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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.
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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.
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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
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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”
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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
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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
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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:‐
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▪ 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
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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
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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
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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
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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
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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.
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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
208
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.
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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
and
DNV‐OS‐J201
Offshore substations
wind power plants
for
Structural design
ISO 19900
ISO 19902
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
214
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)
216
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.
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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
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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
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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
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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.
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(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
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(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.
228
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
230
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
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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
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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)
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▪ 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.
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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
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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.
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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
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▪ 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
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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
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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
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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
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▪ 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
254
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.
256
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.
257
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.
259
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.
260
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.
262
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.
265
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.
266
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.
268
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..
270
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
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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
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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
274
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.
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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
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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:
‐
„
„
„
„
„
282
‐
‐
‐
‐
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
‐
„
„
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.
287
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
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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
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‐
‐
‐
„
‐
‐
‐
„
‐
‐
‐
„
‐
‐
‐
‐
‐
„
„
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.
296
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
298
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
299
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.
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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
BB1
Incomer
Incomer
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
BB1
Incomer
Incomer
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
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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 /
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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
318
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
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‐ 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
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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
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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
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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
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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
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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.
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Figure 5‐19. Typical communications two fibre routes
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FO cable termination
FO cable termination
FO terminal equipment and multiplexer
FO terminal equipment and multiplexer
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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
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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
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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
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-
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.
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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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343
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
: Investment costs [€]
Ct
: Yearly costs due to electrical losses cabling [€]
R
: Discount rate [7%]
T
: Year [‐]
N
: 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 <Um
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
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
= 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
|
|
|
|
|
|
|
|
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