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SPatial Deployment of offshore WINDEIE/07/759/S12.499460
Energy in Europe (WINDSPEED)
Horizontal Key Actions
Grid Implications: Optimal design of a subsea power grid in the North Sea
WP6 Final Report D6.3
June 2011
Supported by:
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Grid Implications: Optimal design of a subsea power grid in the North Sea Daniel Huertas Hernando Magnus Korpås Silke van Dyken SINTEF Energy Research Sem Sælands vei 11 N-7465 Trondheim, Norway
Tlf: +47 735 97462 [email protected] June 2011
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The sole responsibility for the content of this report lies with the authors. It does not necessarily reflect the opinion of the European Communities. The European Commission is not responsible for any use that may be made of the information contained therein.
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Table of contents
Table of contents 6
Tables 7
Figures 8
Executive summary 11
1. Introduction 17
2. Grid Scenario Analysis 19
2.1. The Net-Op tool 19 2.2. Scenarios for offshore wind development 21 2.3. Basic data 23 2.4. Results Scenario In the Deep 34 2.5. Results Scenario Grand Design 43
3. Discussion of grid connection results 56
3.1. Optimal timing and coordination of offshore grid investments 56 3.2. Consequences for onshore grid 60 3.3. Connection to oil and gas platforms 63
4. Summary and Conclusions 66
Appendix A: Generation Capacity In the Deep 70
Appendix B: Generation capacity Grand Design 73
Appendix C: Offshore wind cluster 76
Appendix D: Technical solutions 77
Appendix E: Offshore grid integration: State-of-the-art 90
Appendix F: Power market and System operation 96
5. References 98
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Tables
Table 2-1 Subsea cables expected in 2020 ............................................................................................ 24
Table 2-2 Cost data ................................................................................................................................ 25
Table 2-3 Generation Cost 2030 (€/MWh) ............................................................................................ 27
Table 2-4 Gas Generation Cost 2030 (€/MWh) ..................................................................................... 27
Table 2-5 Energy Demand 2030 (TWh) ................................................................................................. 29
Table 2-6 Realized capacity for planned permitted areas in 2030 (In the Deep) .................................. 32
Table 2-7 Realized capacity for planned permitted areas in 2030 (Grand Design) ............................... 32
Table 2-8 Production and full load hours of offshore wind clusters for “In the Deep 20%” ................ 37
Table 2-9 Production and full load hours of offshore wind clusters for “In the Deep 0%” .................. 37
Table 2-10 Production and full load hours of offshore wind clusters for “Grand Design V05” ............ 47
Table 2-11 Production and full load hours of offshore wind clusters for “Grand Design V06” ............ 47
Table 3-1 Total Costs and Benefit. ......................................................................................................... 58
Table 3-2 Onshore Grid connection capacity ........................................................................................ 60
Table 4-1 Non-Renewable Generation capacity [MW] in 2030 (PRIMES) ............................................. 70
Table 4-2 Renewable Generation capacity [MW] in 2030 (RESolve-E) ................................................. 71
Table 4-3 Maximum allowed conventional production (GWh) in 2030 (PRIMES) ................................ 72
Table 4-4 Maximum allowed renewable production (GWh) in 2030 from RESolve-E .......................... 72
Table 4-5 Non-Renewable Generation capacity [MW] in 2030 (PRIMES) ............................................. 73
Table 4-6 Renewable Generation capacity [MW] in 2030 (RESolve-E) ................................................. 74
Table 4-7 Maximum allowed conventional production (GWh) in 2030 (PRIMES) ................................ 75
Table 4-8 Maximum allowed renewable production (GWh) in 2030 from RESolve-E .......................... 75
Table 4-9 Offshore Wind cluster In the Deep ........................................................................................ 76
Table 4-10 Offshore Wind cluster “Grand Design ................................................................................. 77
Table 4-11 Strengths (+) and weaknesses (-), of AC and DC transmission systems .............................. 79
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Figures
Figure 1-1 Offshore grid configurations for the In the Deep (left) and Grand Design (right) scenarios. ............................................................................................................................. 12
Figure 1-2 Production per country per generation type. ...................................................................... 13
Figure 2-1 Illustration of the four WINDSPEED scenarios from Task 6.1 [12]. ...................................... 22
Figure 2-2 Exchange capacity and HVDC links expected in 2020 .......................................................... 25
Figure 2-3 Onshore and Offshore cost .................................................................................................. 26
Figure 2-4 Example of onshore connection points in the Net-Op Model ............................................. 28
Figure 2-5 Hourly load patterns (UK) .................................................................................................... 29
Figure 2-6 Variable renewable production in the UK ............................................................................ 30
Figure 2-7 Offshore Wind Permitted Areas. .......................................................................................... 31
Figure 2-8 Potential offshore wind capacity maps and labelling of different clusters ......................... 33
Figure 2-9 In the Deep 70m Optimized Offshore Grid. ......................................................................... 34
Figure 2-10 In the Deep 70m Pmin=20% Optimized Offshore Grid (MW) ............................................ 35
Figure 2-11 In the Deep 70m Pmin=0% Optimized Offshore Grid (MW) .............................................. 36
Figure 2-12 Power Flows in cable connections In the Deep ................................................................. 38
Figure 2-13 Duration diagrams (cable connections) In the Deep ......................................................... 39
Figure 2-14 Power Flows for HVDC connections of the meshed offshore grid In the Deep ................. 40
Figure 2-15 Duration diagram for HVDC connections of the meshed offshore grid In the Deep ......... 41
Figure 2-16 Production by country and per generation mix for In the Deep in TWh ........................... 42
Figure 2-17 Grand Design 70m Optimized Offshore Grid. .................................................................... 43
Figure 2-18 Grand Design 70m Optimized Offshore Grid. .................................................................... 44
Figure 2-19 Grand Design 70m V05 Optimized Offshore Grid (MW) .................................................... 45
Figure 2-20 Grand Design 70m V06 Optimized Offshore Grid (MW) .................................................... 46
Figure 2-21 Power Flows in cable connection Grand Design ................................................................ 48
Figure 2-22 Duration diagrams (cable connections) Grand Design ...................................................... 49
Figure 2-23 Power Flows for HVDC connections of the meshed offshore grid ..................................... 49
Figure 2-24 Duration diagram for HVDC connections of the meshed offshore grid ............................. 50
Figure 2-25 Flow diagram (Left) and duration diagram (Right) for HVDC connection .......................... 51
Figure 2-26 Production by country and per generation mix for Grand Design in TWh. ....................... 52
Figure 2-27 Production vs Demand per country per scenario. Values are given in TWh ..................... 53
Figure 2-28 Production per country per generation type. .................................................................... 54
Figure 2-29 Main trans-national exchanges flow corridors. ................................................................. 55
Figure 3-1 Source: Deliverable D6.1, WINSPEED project [12]. .............................................................. 58
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Figure 3-2 Long-term investments around the North Sea area as reported by ENTSO-E TYNDP [25]. ......................................................................................................................... 62
Figure 3-3 Conceptual drawing of a possible Norway-Germany connection [28]. ............................... 64
Figure 3-4 Electrification of oil and gas by offshore wind turbines. Right panel from[27] ................... 65
Figure 4-1 Non-renewable generation capacity (GW) in all WINDSPEED countries in 2030 ................ 70
Figure 4-2 Renewable generation capacity (GW) in all WINDSPEED countries in 2030 ....................... 71
Figure 4-3 Non-renewable generation capacity (GW) in all WINDSPEED countries in 2030 ................ 73
Figure 4-4 Renewable generation capacity (GW) in all WINDSPEED countries in 2030 ....................... 74
Figure 4-5 Alternatives for transmission of offshore wind power ([30] and [31]). ............................... 78
Figure 4-6 Single line diagram for Horns Rev 1 [34]. ............................................................................. 80
Figure 4-7 HVDC with current source converters [37]. ......................................................................... 81
Figure 4-8 Simplified single line diagram for NorNed. (Source: ABB) ................................................... 82
Figure 4-9 HVDC with voltage source converter (PWM type) [37]. ...................................................... 83
Figure 4-10 HVDC Light [37]. ................................................................................................................. 84
Figure 4-11 HVDC Plus [37]. .................................................................................................................. 84
Figure 4-12 Example of T-junction. Source: SINTEF Energy Research. .................................................. 85
Figure 4-13 Sketch of a HVDC multi-terminal system. (Source ABB) .................................................... 85
Figure 4-14 Example of a possible offshore MTDC [46] ........................................................................ 86
Figure 4-15 Power cables with extruded polymer insulation [48]. ....................................................... 87
Figure 4-16 Power cables with oil/paper insulation [48]. ..................................................................... 87
Figure 4-17 Losses for HVAC and HVDC (LCC and VSC) [51] .................................................................. 88
Figure 4-18 Outline of the E.ON1 HVDC connection of offshore wind farms [54] ................................ 90
Figure 4-19 Airtricity’s Supergrid proposal [57] .................................................................................... 92
Figure 4-20 Imera’s EuropaGrid proposal [58] ...................................................................................... 92
Figure 4-21 Statnett’s North Sea Offshore Grid [1]) ............................................................................. 92
Figure 4-22 Offshore grid: medium wind scenario, 2030 [28] .............................................................. 93
Figure 4-23 Radial grid: medium wind scenario, 2030 [28] .................................................................. 93
Figure 4-24 Statnett’s potential future Norwegian offshore grid (Statnett)[14] .................................. 94
Figure 4-25 Possible offshore grid for the North Sea and Baltic sea [13] ............................................. 95
Figure 4-26 EWEA Offshore Network Development Master Plan [6] ................................................... 95
Figure 4-27 Net Load = Load – Wind. See [63] for details. .................................................................... 96
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Executive summary The WINDSPEED project assesses the potential for further development of offshore wind energy (OWE) in the Central and Southern North Sea. The overall objective of the project, which is funded under the Intelligent Energy for Europe (IEE) programme, is to develop a 2020-2030 roadmap for the deployment of OWE in this region of the North Sea as bounded by Belgium, Denmark, Germany, the Netherlands, Norway and the United Kingdom. This report presents the results from task 6.3 of the WINDSPEED project. Task 6.3 aims to develop scenarios for grid connection and grid development to support the overall scenarios obtained in the analysis carried out in task 6.1 of Work Package 6 by considering technical solutions, grid topologies and costs involved. It also aims to discuss the impact that the obtained grid scenarios will have on the power system and market operation, the need for onshore grid reinforcements and possible environmental benefits due to reduction of CO2 emissions. Special focus is devoted to the optimal timing and coordination of grid investments. The grid connection and development scenario analysis (task 6.3) provides input for the final roadmap (task 6.4). SINTEF’s offshore grid optimization tool, Net-Op, has been used in the analysis presented. Net-Op is a transmission expansion planning tool for power systems with large shares of renewable energy sources like e.g. wind. The tool explicitly considers the benefit of transmission capacity between differently priced areas and the value of connecting offshore wind power to the grid versus the investment cost of power cables and auxiliary equipment. It finds a solution for the least-cost offshore grid structure and cable dimensioning, taking into account variable power generation (solar and wind power), variable power demand, total renewable and non-renewable/conventional generation capacity and cost of generation per country, investment costs and possible connection points to the onshore power system. The scenarios for offshore wind development in task 6.1 have been defined using the Decision Support System (DSS) tool for spatial development of offshore wind and the techno-economic renewable electricity market simulator (Resolve-E). From such spatial-techno-economic analysis, expected potentials for renewable (Biomass, Hydro power, PV, Geothermal, Wave and Onshore and Offshore wind) and non-renewable/conventional sources (Fossil Fuels and Nuclear power) are obtained. Moreover, from the DSS maps defined for each scenario, spatial positions of potential offshore wind farm clusters, their relevant onshore grid connection points and total (economically constrained) installed capacities are found. Only the two scenarios in task 6.1 considering large scale deployment of offshore wind far from shore have been analyzed by Net-Op. These scenarios are referred as In the Deep and Grand Design. They both assume fast technological development/ low cost of technology. Potential for large scale deployment of offshore wind power, of which a significant share comes from areas far from shore, is found in these two scenarios. Possibilities for building a trans-national meshed offshore grid are therefore investigated during the period 2020-2030. The offshore meshed grid configurations found by the Net-Op analysis for the 2030 In the Deep and Grand Design scenarios are shown in Figure 1-1.
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Figure 1-1 Offshore grid configurations for the In the Deep (left) and Grand Design (right) scenarios. Detailed discussion of the exchange power flows, production per country, total cost and total economical benefits for the offshore meshed grids found is presented in this report. Figure 1-2 presents the production per country per generation type for the grid scenarios analyzed. A major shift in production from fossil fuels to carbon-free renewable sources is found in the scenario Grand Design (Figure 1-2).
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Grand Design V05 [TWh]
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In the Deep Pmin = 20% [TWh]
Figure 1-2 Production per country per generation type. Our main conclusions are: Regarding timing of electrical infrastructure investments:
1. The offshore grid design found for the Grand Design scenario (Figure 2-17) shares some
similarities with the EWEA’s master plan offshore grid of Figure 5-25, considering that EWEA master plan was developed by a bottom-up approach whereas the WINDSPEED analysis is a top-down one. Moreover, the WINDSPEED grid scenarios include mixed solutions combining LCC classical point-to-point links, VSC T-links and multiterminal VSC links. Also two new offshore clusters in Norway and Denmark are suggested in the WINDSPEED project analysis with respect to the EWEA’s master plan.
2. Regarding development of wind farms and electrical infrastructure, a total time of 8-10 years (application phase, investment decision and construction) can be assumed per project. Many of the projects making up the grid infrastructure scenarios presented, must be planned and development simultaneously. A coordinated development of all these projects is needed to allow for flexible and harmonized technical standards regarding technology and technical choices.
3. For 2030 as target year, pro-offshore wind regulatory and commercial frameworks should be established in the period 2015-2020 such that large scale investment decisions are being
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made around the beginning of 2020. Under these assumptions, large scale construction of an offshore grid can slowly emerge from national development to international coordination between 2020 and 2030, with a minimum total construction time of 10 years.
4. Possibilities of T-connections between wind farms and the planned/existing bilateral links are suggested in our analysis. Planning and investment decision of T-connections should be coordinated between the link developers (typically TSOs) and wind farm developers. New market rules that allow trading of power from the link and from the wind farm in the same market are needed to support investment decisions regarding T-connections. T-connections could be the first steps to allow moving away from nationally driven radial connection strategies and towards a transnational fully meshed offshore grid solution.
5. Transnational clustering is suggested between offshore parks nearby the border of UK and NL exclusive economic zones (EEZ), the border between DE-EEZ and NL-EEZ as well as nearby the border of DE-EEZ and DK-EEZ.
6. Planning to allow for transnational clustering should be done in a coordinated manner at an early stage of the development of the wind farms in the different countries, so the connection to the transnational offshore cluster hub allows for flexible and harmonized technical standards regarding technology and technical choices. Lessons learned from the Kriegers Flag[1] project should be used when development transnational clusters.
7. Flexibility on the connection choice and technological solution must be considered. For most of the clusters large portions of the found capacity of the connections between wind farms and the shore can be assumed to be mostly unidirectional 2-terminal VSC connections. Only a fraction of the capacity found needs to be based of fully bidirectional multi-terminal VSC connection technology.
8. There are a number of connections which are found in both the In the Deep and Grand Design grid scenarios. These common connections should be planned first as they represent the more robust choices regarding uncertainties in offshore wind development.
9. Planning and development of symmetrical multi-terminal VSC connection, allowing fully meshed offshore grids, will be driven by improved flexibility and security of supply of the offshore grid in addition to possibilities for trans-national power exchanges. These connections are likely to be built once the development of unidirectional 2-terminal VSC radial connections and T-connections is well established from a technical and economical point of view.
Regarding operational and investment costs, coordination and savings, we conclude from our analysis
1. Substantial reduction in operational costs is found in Grand Design with respect to In the Deep. This benefit is a consequence of the higher installed capacity of offshore wind. This leads to more grid investments and more meshed offshore grid configuration, allowing the transfer of (remote) wind power to load centers in a flexible and efficient manner.
2. A total benefit of ~ 120 M€ is found when comparing the total costs of Grand Design with In the Deep, despite of larger installed capacity and larger investment costs of electrical
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infrastructure in the Grand Design scenario, due to the higher penetration of offshore wind in Grand Design.
3. From our assessment of onshore grid reinforcements, new grid infrastructure onshore (update and new lines) will be needed between 2020 and 2030 to accommodate ~ 145 GW offshore wind proposed in the Grand Design scenario, of which ~130GW is expected to be developed in the North Sea. Further detail analysis is needed to determine the particular transmission capacity, distance of the transmission lines and use AC or DC technology onshore, for each of the WINDSPEED countries. The estimation of a total 3600 km of additional lines into the German grid between the year 2015 and 2020, according to the dena II study [2], is a good example of the type of study needed for this type of assessment.
Regarding the potential of meshed grids to allow replacement of conventional generation sources by renewable sources in the supply of electricity and for reduction of CO2: 1. A major shift in production from fossil fuels to carbon-free renewable sources is found in the
scenario Grand Design (Figure 1-2). 2. Renewable generation in countries with surplus (mainly NO and DE) is transferred to countries
with large demand needs (UK and DE) through both bilateral HVDC links and the meshed offshore grid.
3. The lowest CO2 emissions are expected to occur in the Grand Design scenario. No detailed estimates of CO2 reduction have been done in our analysis. Savings in conventional generation found in Figure 1-2 will have to be translated into fuel savings (mainly coal, gas, oil) and therefore into CO2 emissions.
4. Further reduction in CO2 emissions can be obtained by supplying wind power to oil and gas rigs. The large potential for offshore wind development found in the Grand Design indicates that wind turbines could be installed near oil and gas rigs and operated in parallel with gas turbines that supply power to the platforms. This can save fuel and CO2 emissions about proportional to the energy output of the wind turbines.
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1. Introduction There are two main motivating factors for considering new sources for energy supply in Europe. Firstly, the current dependence on fossil fuels brings with it, greenhouse gas emissions that are leading to global climate change. Secondly, Europe’s dependence on fossil fuels implies a dependence on oil and gas imports. A global peak in conventional oil production before 2030 appears likely and there is a significant risk of a peak before 2020, according to the UK Energy Research Council [3]. The EU currently covers 50 % of its energy needs through imports and, if no action is taken, this may increase to 70 % by 2020 or 2030 [4, 5]. This makes the energy system vulnerable to increasing fuel costs and potential disruptions in fuel supply. On the other hand, exploitation of the abundant offshore wind energy resources, together with onshore wind and other indigenous renewable energy sources will reduce Europe’s dependence on fossil fuels, thereby reducing CO2 emissions and improving the security of energy supply at the same time. At present, onshore wind is considered commercially viable at sites with good wind conditions and grid access. Offshore wind largely is in a pre-commercial development phase, although currently under rapid technological progress. The advantages of offshore wind compared to onshore wind include i) higher wind speeds, yielding as much as 50 % higher output, ii) less land conflicts and environmental constraints and lower visual impact. Presently, offshore wind is considerably more expensive, but cost improvements are expected from continuous technological developments. The expected number of offshore wind farms is likely to increase substantially between 2020 and 2030. Large portions of this offshore wind power will have to be generated at sites located at long distances from shore ( > 70 km) and at deeper seas (> 30 m). The ambitious targets found in the WINDSPEED analysis, which are in line with targets e.g. from the European Wind Energy Association (EWEA) [5, 6] imply wide impacts related to transmission technology and planning and system operation that need to be addressed. There are also key challenges related to how the future power markets should be developed to ensure that official targets for wind energy can be achieved. In response to these challenges, the transmission system operators (TSOs) have developed grid codes that specify new requirements on wind farm controllability and ability to provide system (ancillary) services. Significant R&D work is being performed with a focus on technology development and wind farm modelling for power system studies [7]. There are still remaining challenges related to implementation and verification of models and control solutions, as well as on how to enforce and interpret the grid codes to ensure a socio-economic cost effective integration of wind farms. Large scale integration of wind power, as a variable and less controllable source of energy, will have an impact on the overall power system operation, ranging from network management to market solutions. When the basic technical problems related to network capacity, controllability and stability of wind farms are solved, the challenge remains on how to effectively deal with operation planning, reliable forecasting, balancing control and reserve management in order to maintain acceptable power system security. The degree of variations in offshore wind power depends on time-scale and geographical distribution. In the long term, offshore wind farms may be developed to constitute a significant part of the total power system generation capacity. Definition of realistic but ambitious target(s) for offshore wind deployment in the North Sea basin for the year 2030 is in the main focus of the WINDSPEED project.
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The WINDSPEED project is funded under the Intelligent Energy for Europe (IEE) programme, and addresses the potential for offshore wind deployment in the Central and Southern North Sea in light of competing non-wind sea use functions as well as techno-economic and grid integration issues. The final deliverable of the WINDSPEED project will be a roadmap to the deployment of offshore wind energy in the above-mentioned sea basin up to 2030. The roadmap will identify realistic but ambitious target(s) for offshore wind deployment in this sea basin, and policy recommendations. Scenarios for ambitious but realistic deployment of offshore wind energy have been defined in task 6.1, by using the GIS-based Decision Support System tool (DSS-tool). Once the location and potential capacity of offshore wind energy has been indentified in the North Sea, it is necessary to address the grid consequences of connecting this power to (remote) demand areas. Task 6.3 aims to develop scenarios for grid connection and grid development to support the overall scenarios obtained in the analysis carried out in task 6.1 of Work Package 6 by considering technical solutions, grid topologies and costs involved. It also aims to discuss the impact that the obtained grid scenarios will have on the power system and market operation, the need for onshore grid reinforcements and possible environmental benefits due to reduction of CO2 emissions. Special focus is devoted to the optimal timing and coordination of grid investments. The task deliverable D6.3 together with deliverables D6.1 and D6.2 constitute the key input documents to the roadmap deliverable D6.4. The report is organized as follows:
Chapter 1 presents the main objective and focus of the work presented in this report in the context of the WINDSPEED project. Chapter 2 describes the methodology applied for the grid assessment of the scenarios defined in task 6.1 and presents the analysis of the scenarios for grid development and grid connection. Chapter 3 presents the discussion of the grid connection results with special focus on the optimal timing and coordination of offshore grid investements, consequences for the onshore grid and possibilities for reduction in CO2 emissions.
Chapter 4 includes a summary and final conclusions. Details on the input data required for the simulations are presented in Appendices A-C. A general description of the “state-of-the-art” regarding technical solutions and grid connection strategies for offshore wind farms is presented in appendices D and E respectively. Appendix F discusses the impact that future large scale deployment of offshore wind energy will have on the power market and system operation. Chapter 5 contains the list of References.
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2. Grid Scenario Analysis The task in this work package is to investigate how offshore wind farms can be connected to the onshore main grid. Both the location and the power rating of the cables are determined. Interconnections between countries may be required in addition to the cables connecting the offshore wind farms. The objective is to maximize the socio-economic benefit. Exogenous variables used in the optimisation are the capacity and the location of offshore wind farms (cluster), potential onshore connection points (substations), statistical descriptions of wind, solar power generation and power demand, the onshore grid equivalent, cost scenarios for grid infrastructure and marginal cost of generation. The problem is defined as a mixed integer problem which can be solved applying a branch and bound algorithm.
2.1. The Net-Op tool The optimisation model used is Net-Op has been developed in MATLAB by SINTEF Energy Research. A detailed description of the tool and the algorithms are to be found in [8] and in the user manual [9]. The area analysed is the Central and Southern North Sea with all neighbouring countries (Norway, Denmark, Germany, Netherlands, Belgium and United Kingdom). Net-Op has a nodal structure. The offshore clusters, the substations and the generation in each country (conventional and renewable generation) are represented by different nodes. The following text in this sub-chapter describes the methodology used in the optimal offshore grid expansions tool Net-Op, and is mainly taken from references [8-11]. The method extends the standard mixed-integer LP approach to the solution of the transmission expansion planning problem to account for fluctuations in wind power generation and load. This makes the method especially suited to identify optimal transnational offshore HVDC grid structures for the integration of large amounts of offshore wind power. New grid capacity can be built both to ensure a more stable and secure power system, to reduce bottlenecks in the network and to connect new customers. Socio-economic benefits arise from fewer outages, less losses and improved trade opportunities enabling reduced operational costs. Long term benefits of improved trade arise mainly because more power can be generated in areas with surplus capacity and low marginal generation costs. Thus a capacity expansion model needs to include a model of the power market to capture the improved operation of the power system due to more transmission capacity between areas. The problem of finding the optimal capacity expansion of the grid is therefore of dual nature; one must find the power market equilibrium (i.e. the optimal generator dispatch) as well as the optimal combination of new interconnectors to build. In principle, investments in transmission lines and generator dispatch should be co-optimized with investment in new generation capacity. Net-Op tool aims to optimize the investments in the grid for the locations and installed capacities of wind power plants as given by the scenarios from task 6.1. The focus of the expansion planning problem is to optimize the offshore grid layout for a given scenario for installed generation and given demand in the system. In the following we shall discuss the assumptions underlying the power market model and describe the theory and implementation of the expansion planning algorithm.
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A model of the power market needs to cover supply and demand of electricity as well as the transmission constraints imposed on the market due to the underlying power grid. Commonly, one considers electricity to be supplied by generation units with a maximum generation capacity and an associated marginal cost function while demand usually is considered completely inelastic. We also adopt this view and restrict the marginal cost function to be constant, i.e. independent on production level, to stay within the mixed integer linear problem (MILP) conventions. If desirable, it is possible to use piecewise linear cost functions to model more complex generator costs and still have a linear program. The constraints due to the physics of the power grid are normally modelled in one of two ways: either with the linearized power flow (PF) equations or as a ``transportation model''. The main difference between the two is that power flow in an alternating current (AC) network is better described with the PF equations than with a transportation model. In a transportation model, power can be transferred through the grid wherever there is free capacity, whereas in a PF the flow on each line is inversely proportional to the impedance on the line. For instance no loop flows are modelled in a transportation model. The path with the lowest losses is always utilized without affecting other parts of the system. Even though a transport model is a very simplified description of a power network, for transfer capacities between aggregate systems -- like whole countries or price areas within countries -- and for controllable HVDC-links -- it is a sufficiently good description. Since the intended use of this model is to provide a simplified description of the onshore power system with the inclusion of offshore HVDC grids, a transport model is considered to be the most appropriate. A natural extension of the here presented methodology is to include the linearized power flow equations as constraints for those parts of the network that are AC and keep the transportation description for the controllable HVDC-links. In short, the following assumptions describe the model of the power market and the underlying power system:
• Power output of each generator is limited by its minimum capacity and maximum capacity in MW
• Each generator offers its entire generation capacity at the marginal generation cost which is constant.
• Demand is either completely inelastic or modelled as a generator with negative production. • Flow on an interconnector is no larger than the rating of the interconnector in MW • Sum of generation and imports must equal sum of load and exports at each node • Losses are linearly dependent on the flow on an interconnector • Temporal constraints like ramp-rates and minimum up/down times of generators and hydro
reservoir limits are neglected • No reduction in generation efficiency at part-load is modelled
To achieve a good representation of the power market it is necessary to combine many power flow situations into the modelling scenario. Usually, historical data is available pertaining to load and generation. Previous models for transmission expansion planning tend to use a single load flow state (usually the peak load or expected load in the planning horizon) as the basis for planning. This is a valid assumption for thermal systems where power flows from central generating units to consumers in a predictable pattern. For a system with high wind power penetration distributed over a large area this is an invalid assumption and will lead to suboptimal results. Instead we solve the capacity expansion planning problem with regard to several states that together give a good statistical description of the wind and solar power and load fluctuations. The model includes a description of the power market with HVDC connections of given capacities. To allow expansion of the grid, new interconnectors will have to be added to the model or existing
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interconnectors will have to be upgraded. The associated costs of these variables are reflected in the objective function as the unit cost of new interconnector capacity. Building a new interconnector is associated with large fixed costs that are independent of the capacity of the interconnector. These costs can be the trench and laying costs, the cost of switchgear and circuit breakers, the transportation, installation and planning costs etc.. The other part of the cost of a new interconnector is dependent on the capacity. To some extent cables can be manufactured with custom capacity, i.e. differing cross-sectional area and voltage which translates to a MW capacity limit, and one can regard the capacity as a continuous variable with an upper limit. The upper limit represents the highest rated cable that can be built; if more capacity is needed it is necessary to build a second cable which entails the full fixed costs again (e.g. new trench, transport, switchgear etc). Thus the cost of interconnector capacity is a stair-step function with sloped steps. Depending on the application it may be possible to build only one type of cable in which case the entire cost is a fixed charge per cable and the cost function becomes a stair-step function with flat steps. To take fixed costs into account it is necessary to add integer variables to the model that indicate how many cables are built for a particular interconnector project. These integer variables have fixed costs associated with them in the objective function of the optimization model. In this way the cost of new interconnector capacity can have both a fixed part and a part that is linearly dependent on rating. Since the investment cost of new equipment is a one time capital expenditure at year 0 and the generation cost is calculated on an hourly basis (or other time base) and applies through the whole lifetime of the grid, they cannot be compared directly. This is solved by assuming a discount rate and lifetime of the equipment and calculating the present value of the generation costs over the economic lifetime of the grid. The a parameter is the present value of a series of unit payments at the end of each year for n years. A discount rate r and an economical lifetime n-years of the equipment gives a=[1-(1 + r)-n]/r. The expansion problem is solved for one year of operating the power system. It is thus assumed that all n years give the same generation costs. An important part in transmission expansion planning is the handling of contingencies. The power system must be able to operate during outages of lines, generators or other equipment. This issue has been disregarded in the described framework because of the aggregate level of modelling, e.g. using net transfer capacities instead of modelling each transmission line independently and having all onshore generation at one node instead of modelling each power plant by itself. Also, offshore wind farms and bilateral interconnectors are today usually built without redundancy or only partial redundancy (in the form of sea return in case of HVDC single pole failure). Instead such connections are usually designed such that the onshore system can tackle an outage, albeit with the loss of generation or exchange capacity. If the onshore power grid becomes more reliant on an offshore grid, planning with security constraints will become more important.
2.2. Scenarios for offshore wind development
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Figure 2-1 Illustration of the four WINDSPEED scenarios from Task 6.1 [12].
Four scenarios for offshore wind development in 2030, denoted as Little Will-Little Wind, Going Solo, In the Deep and Grand Design have are defined in the WINDSPEED project task 6.1, as shown in Figure 2-1. The two main indicators used to separate the different scenarios are the prioritisation of deployment of offshore wind power and the level of technological development/cost of technology. The two scenarios Little Will-Little Wind, Going Solo, assume high cost for the development of offshore wind energy, which translate into offshore wind only being developed as close as possible from the shore and basically only at national level without trans-national coordination. For the other two scenarios In the Deep and Grand Design fast technological development/ low cost of technology is assumed. These two scenarios therefore imply a large scale deployment of offshore wind power, of which a significant share will come from areas far from shore. Possibilities for building a trans-national meshed offshore grid are investigated for these two In the Deep and Grand Design scenarios by using the Net-Op tool. The location and capacity of the offshore wind farms defined in these scenarios is found applying the DSS tool. The four scenarios show incremental growth of the offshore wind development in the wind clusters with the Baseline 2020 scenario as a starting point. For more details on the scenario analysis of task 6.1 see [12]. The scenarios considered in this report assume a maximum depth constraint of 70 m, therefore often denoted as In the Deep_70m and Grand Design_70m. If not explicitly specified, In the Deep and Grand Design refer to these In the Deep_70m and Grand Design_70m scenarios. The 70 m depth constraint excludes the use of floating wind turbines for offshore wind development. Our simulations are therefore conservative regarding the use of floating technology. Larger potentials for far-from-shore offshore wind development are expected if floating turbines are considered as economically viable, as shown in depth unconstrained In the Deep and Grand Design scenarios investigated in WP6 as part of sensitive analysis of the scenario analysis of task 6.1. Two different case studies have been considered in the In the Deep scenario in year 2030:
1. IntheDeep 20 %: This case assumes a finite minimum production constraint for non-renewable/conventional generation units: oil, gas, nuclear as well as for biomass (Pmin = 20 % Pmax). This is the most constrained scenario for the deployment of offshore wind considered in task6.3.
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2. IntheDeep 0 %: This case assumes the same input as the 20 % case but considers a zero
minimum production constraint for non-renewable/conventional units: oil, gas, nuclear as well as for biomass (Pmin = 0 % Pmax ). This scenario shows a higher utilization of the offshore wind farms located at the clusters far from shore, showing a higher share of wind penetration.
The different assumption for the In the Deep 0 % scenario compared with the In the Deep 20 % rely on the existence of support mechanisms, adjusted legal frameworks and market measures that ensure/favor a smooth replacement of generation from carbon emitting traditional sources (e.g. oil, gas and coal) by renewable generation. As a first step for such transition, traditional units are expected to run at partial load efficiency and even shut down during off-peak load hours and/or hours with high wind production. The possibility of zero “minimum” production for generation sources like e.g. oil, gas and coal sources in the In the Deep 0 % allows for the possibility of large scale “phasing-out” of these carbon-emitting generation sources. The Grand Design scenario is the most pro-offshore wind scenario considered in this project. In this scenario it is assumed that high level trans-national coordination for the development of an offshore grid is possible. In addition, the possibility of zero “minimum” production for generation sources like oil, gas and coal is permitted. The phasing-out of these carbon-emitting generation sources by large scale deployment of offshore wind energy is therefore investigated in this scenario. Complete phase-out of nuclear power is assumed. Two different case studies have been considered in the Grand Design scenario in year 2030:
1. GrandDesign_70m_V05: In this case, the maximum possible potential (~88 GW) for the installed capacity at the offshore clusters is assumed as being obtained from the DSS +Resolve-E analysis.
2. GrandDesign_70m_V06: In this case, a reduced potential of ~81 GW for the installed capacity at the offshore clusters is considered.
The 7 GW reduction in installed capacity in case V06 compared to case V05 reflects both the competition with other sea uses as well as the high grid investments needed for the development of all available economic potential found in the DSS + Resolve-E analysis. The phasing-out of nuclear power assumed in our simulations implies a significant reduction of the available generation capacity for the UK. The 6 GW of nuclear power assumed in the In the Deep scenario are not longer available in the Grand Design scenario. In order to obtain a balance between the available capacity and the demand in the UK, some extra assumptions regarding the installed capacity of coal power in the UK were needed. For the V05 scenario, 4.9 GW of installed coal power in the UK were assumed. This amount had to be increased to 9.7 GW for the V06 case. It was found that the 5 GW higher installed capacity for coal in the UK in the V06 scenario was closely related to the 7 GW reduction of installed capacity for offshore wind power in order to guarantee that the (variable) demand was met by the available (and partially variable) generation at each hour of the simulated year.
2.3. Basic data The main assumptions and input data used in the Net-Op tool for both scenarios are described in the following subchapters.
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Exchange capacity and HVDC links
When planning for the optimal design of a subsea power grid in the North Sea it is important to distinguish between two different strategies for the development of the grid connection of offshore wind farms namely:
Radial Grid: This strategy considers (radial) connection between each offshore wind farm and the main grid onshore and point–to–point HVDC connections between countries across the North Sea. This strategy assumes the use of classical LCC technology and 2-terminal VSC technology. Offshore Meshed Grid: A strategy based on the use of offshore nodes-hubs to build a meshed HVDC offshore grid. The offshore nodes or hubs are also known as offshore clusters as they constitute the offshore connection point for offshore wind farms located in an area around it. This strategy assumes the use of multi-terminal VSC technology.
The construction of an offshore cluster node starts being economically beneficial for distances from shore of about ~70 km or higher. High enough density MW/km2 of installed capacity is also a determining factor for offshore clusters to be beneficial. Largest available rating for HVDC technology ~ 1-2GW in an area of radius up to 40 km has been reported as economically beneficial criteria in the OffshoreGrid project [13]. Table 2-1 list the planned HVDC point-to-point cables expected to be in operation in 2020 or before 2030. The first five HVDC cables of Table 2-1 are assumed to be based on classical LCC in the Net-Op simulations presented. The last two connections shown are assumed to be part of the optimization and both LCC & T-connection and VSC & hub connection possibilities are considered, since Norwegian-German and Norwegian-British TSOs are respectively considering both options at present[14]. Table 2-1 Subsea cables expected in 2020
Name Country [MW] Technology Status Expected year
BritNed GB-NL 1290 HVDC LCC Construction 2011
Skagerrak 4 NO-DK 1750 HVDC LCC Design & permitting 2014
Cobra Cable DK-NL 700 HVDC LCC Design & permitting 2016
Nemo Cable GB-BE 1000 HVDC LCC Planned 2016
NorNed2 NO-NL 1400 HVDC LCC Consideration 2017
NorGer NO-DE 1400 HVDC LCC/VSC Consideration 2016
Brit-Nor NO-GB 1600 HVDC LCC/VSC Consideration after 2020 Also, Net Transfer Capacities (NTC) between Belgium and The Netherlands, The Netherlands and Germany and Germany and West-Denmark as published by ENTSO-E are considered [15] in the simulations. An overview of these connections as implemented in Net-Op is shown in Figure 2-2.
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Figure 2-2 Exchange capacity and HVDC links expected in 2020 Component and generation costs The Net-Op tool explicitly considers the value of connecting offshore wind power to the main land grid versus the investment cost of power cables and auxiliary equipment. Assumptions on cost data for cables, converter stations, switchgear and offshore platforms are used as provided in the WINDSPEED Deliverable D2.2 “Inventory of location specific wind energy cost” and listed in Table 2-2. Table 2-2 Cost data
Component Cost Unit
Trench/laying cost 0.76 M€/km
Cable cost, fixed charge 5.0 M€
AC/DC converter station onshore 136.1 M€
AC/DC converter station and platform offshore 167.2 M€
DC breaker and switching gear onshore, per cable 136.1/β M€
DC breaker and switching gear offshore, per cable 167.2/β M€
Both cables and converter stations are built in whole units. The block capacity implemented in the Net-Op simulation is 600 MW. Multiple blocks can be built. In this case, each new block incurs the full fixed cost defined in Table 2-2. Offshore nodes (offshore clusters, offshore hubs) are always assumed to be part of a meshed multi-terminal offshore grid in the Net-Op simulations whereas onshore
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nodes (onshore connection points, main land onshore connection points) can be connected by cables both using classical LCC and/or VSC technology depending on whether the connection is point-to-point or between offshore and onshore/offshore node respectively. There is a high uncertainty on the DC breaker and switching gear costs for the VSC technology as those components are under development and not yet fully commercially available per today. For this purpose the sensitivity parameter β is introduced as indicated in Figure 2-3, which schematically shows the offshore and onshore connections and costs. The cost for DC breaker and switching gear onshore (offshore) is assumed to be a 1/ β fraction of the cost for AC/DC converter station (and platform offshore) onshore. A sensitivity analysis has been performed with the Net-Op tool before running the final scenarios presented here.
Figure 2-3 Onshore and Offshore cost From these sensitivity analysis it has been found that the value of the parameter β equal to 3 (β = 3) corresponds to a situation where both LCC and VSC solutions can appear simultaneously, allowing for a mixed solution between Radial and Meshed Grid strategies. In Net-Op, a certain “cluster” area with certain installed capacity has a potential of producing certain TWh. Its production is determined first by the time series of wind production, i.e. wind power fluctuates hour by hour between values 100 % and 0 % installed MW due to wind speed variability. For each hour the output of each wind cluster is compared with the rest of generation capacity available in the system and the demand needed. The optimization finds the optimal solution such that the demand is covered by the cheapest possible mode of production. The comparison between investment costs of offshore wind electrical infrastructure and the operational costs of generation for the other generation sources in the system determines the production output of the offshore wind clusters. Therefore, marginal cost of generation for all different generation sources has been
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considered (Table 2-3). The generation cost data originates from ref. [13]. The generation costs for different technologies are identical for all countries except the gas generation costs as shown in Table 2-4. Table 2-3 Generation Cost 2030 (€/MWh)
Technology Cost (€/MWh)
Hard coal 62.04
Hydro 25.00
Lignite 58.26
Mixed oil / gas 168.93
Non-attributable 176.93
Nuclear 11.00
Oil 162.59
Renewable non wind 50.56
Wind power 0.50
Table 2-4 Gas Generation Cost 2030 (€/MWh)
Country Gas Cost (€/MWh)
NO 69.05
DK 61.03
DE 74.74
NL 69.05
BE 64.74
GB 73.92
Onshore connection points
Potential onshore connection points have been investigated in the WINDSPEED Deliverable D2.4. “Inventory of current grid infrastructure and future plans”. Based on the findings from D2.4 potential substations in the respective countries are selected and implemented with their geographical position (latitude and longitude pairs). The onshore connection points are marked by a black square in Figure 2-4 which shows an example of typical Net-Op starting point configuration.
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Figure 2-4 Example of onshore connection points in the Net-Op Model Country nodes are marked by a pink dot. A blue triangle indicates the offshore wind clusters and the red lines show the existing interconnections. The dotted green lines show all potential connections between country nodes, offshore nodes and onshore connection points. Net-Op determines the number of green connections which is optimal to use and at which rating capacity, such as the total demand is met at each hour of the year by all available generation, with the minimum global total investment plus operational costs for the system. Generation capacity and energy demand Regarding the generation capacity, the Net-Op tool uses the results obtained from the Resolve-E model as input data (see D6.1). The RESolve-E model is a techno-economic simulation model that uses the principles of demand and supply to model a market for renewable electricity. Renewable Electricity (RES-E) supply curves are matched with policy-based demand curves. The potential that is available in supply curves is constrained by growth limitations and by a project succeed factor. Besides that not the whole potential can be available at all time, the realization is also limited by the demand for RES-E. The model can be used to give projection of future RES-E capacities for each EU country for the time horizon 2005 – 2030. Important inputs of the model are RES-E policies. Within WINDSPEED the main purpose of using the RESolve-E model is in giving projections for the OWE developments in each of the six WINDSPEED countries, considering RES-E policies and growth limitations. Including RES-E policies and expected developments, the growth path resulting from the model has been calibrated to mimic the official National REnewable Actions Plans (NREAP) developments in 2020 as closely as possible. Further, potentials for RES-E production are predicted
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for the target year 2030. Generation capacity and production for Non-RES sources are taken from the PRIMES data base [16] (see D6.1 for details). The potentials for the In the Deep scenario are shown in Appendix A, the ones for the Grand Design scenario in Appendix B. The assumed total energy demand in the six WINDSPEED countries in 2030 is shown in Table 2-5. The value for Norway is taken from EURPROG [17]. The other five demand values are taken from PRIMES [16] models. Table 2-5 Energy Demand 2030 (TWh)
Energy demand [TWh] BE DK DE NL NO UK
2030 120.23 43.50 664.31 141.28 152.6 452.24
Hourly time series for demand in each country, calibrated to the total values in Table 2-5, have been used from [30]. Figure 2-5 shows snapshots (hours 2000-3000 of the year 2030) for hourly load profiles for the UK.
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Figure 2-5 Hourly load patterns (UK) Corresponding to the load patterns, wind patterns with hourly values are implemented to model the fluctuating generation of onshore and offshore wind as well as solar production [30]. They are scaled according to the capacity defined for the offshore clusters and the onshore capacity. The wind and solar patterns are based on an interpolated reanalysis data [30]. An example of the variable production used in the Net-Op simulations is shown in Figure 2-6. The variable production includes generation from onshore wind, wind close from shore (d < 70 km) and PV in the UK for 2030. Snapshots (hours 2000-3000 of the year 2030 shown) of the hourly time series are presented. Individual hourly time series are used for onshore wind (magenta), wind close from shore (black) and PV (green) adding up to the total variable generation “inland” (blue).
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Figure 2-6 Variable renewable production in the UK Capacity and location of offshore wind clusters In order to define the location and capacity of the offshore wind clusters, which make the nodes of the offshore meshed grid, a two step procedure has been considered. First, offshore wind permitted areas for 2030 have been considered, as shown in Figure 2-7.
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Figure 2-7 Offshore Wind Permitted Areas. Different permitted areas (red lines in Figure 2-7) are further divided into A-G areas by the DSS tool. The different sub-areas A, B, etc.., are divided based on different values of Levelized Production Cost LPC [€/MWh] calculated from the Resolve-E model and implemented in the DSS tool. As a second step, the DSS tool searches for additional incremental offshore wind capacity potentially available such as the total Resolve-E targets for offshore wind generation (Appendix A and Appendix B) are met. Table 2-6 shows the realized capacity of the planned permitted parks in 2030 from RESolve-E for the In the Deep scenario. The capacities for the Grand Design scenario are shown in Table 2-7.
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Table 2-6 Realized capacity for planned permitted areas in 2030 (In the Deep)
Capacity planned/ permitted [MW]
Realized Capacity in 2030 [MW]
% realized in 2030
A 4 777 4 387 91.8 B 14 250 9 625 67.5 Germany C 2 600 1 756 67.5 D 1 510 1 510 100.0 E 4 310 2 265 52.5
A 3 600 3 236 89.9 B 3 600 3 207 89.1 C 2 000 1 402 70.1 D 2 000 803 40.2 UK E 2 000 1 606 80.3 F 7 000 5 864 83.3 G 3 500 0 0.0 H 3 800 0 0.0
NL I 1 045 1 045 100 Table 2-7 Realized capacity for planned permitted areas in 2030 (Grand Design)
Capacity planned/ permitted [MW]
Realized Capacity in 2030 [MW]
% realized in 2030
A 4 777 4 385 91.8 B 14 250 10 411 73.1 Germany C 2 600 1 900 73.1 D 1 510 1 510 100.0 E 4 310 2 612 60.6
A 3 280 3 280 91.1 B 3 271 3 271 90.9 C 514 514 25.7 D 0 0 0.0 UK E 1 033 1 033 51.6 F 4 937 4 937 70.5 G 0 0 0.0 H 0 0 0.0 NL I 1 045 1045 100 Applying the DSS tool additional incremental offshore wind potential is identified. This results in the offshore wind potential capacity maps shown in Figure 2-8.
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In the Deep 70 m
Grand Design “V05”
Labelling of offshore clusters Grand Design “V06” Figure 2-8 Potential offshore wind capacity maps and labelling of different clusters The blue triangles indicate the location of the offshore wind clusters considered for the Net-Op optimization. Details on the allocation of the total capacities from the two step procedure are shown in Table 4-9 for the In the Deep scenario and in Table 4-10 for the Grand Design scenario (Appendix C). In the left-bottom panel in Figure 2-8 the labelling of the different clusters used throughout the rest of the report is indicated. The labelling is the same for both In the Deep and
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Grand Design grid scenarios but the capacities allocated to each cluster varies between the different grid scenarios.
2.4. Results Scenario In the Deep E Borkum (B area in Figure 2-7) , UK Hornsea (C& D area in Figure 2-7) and UK DoggerBank (E&F area in Figure 2-7) are the areas where the development of offshore wind is expected to occur first, according to the ambitious national plans of both UK and Germany. Under such nationally-driven planning it is reasonable to assume that all the power produced in these offshore wind farm areas will be sent in the onshore grid of the corresponding country. Therefore for clusters (3)-DE Borkum, (6)-UK Hornsea and (7)-UK DoggerBank an existing connection of 9GW, 5GW and 6.6GW is assumed before the Net-Op grid optimization is performed. This is indicated by the red lines in Figure 2-10 below. Offshore grid design
Figure 2-9 In the Deep 70m Optimized Offshore Grid. The optimized grid found by Net-Op for the In the Deep scenario is shown schematically in Figure 2-9. This map shows the connections found in both In the Deep 20 % and 0 % scenarios. Detailed maps for both In the Deep 20 % and In the Deep 0 % cases showing the nominated rating capacities in MW for each line are shown in Figure 2-10 and Figure 2-11.
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Figure 2-11 In the Deep 70m Pmin=0% Optimized Offshore Grid (MW) Utilization hours The production and utilization hours (also known as full load hours) for the offshore clusters in the In the Deep 20 % and the In the Deep 0 % are shown in Table 2-8 and Table 2-9 respectively. For the same installed capacity (53.2 GW), the production in the In the Deep 0 % scenario is 20.8 TWh higher than in the In the Deep 20 % scenario. Also the full load hours are significantly higher in the In the Deep 0 % scenario compared to In the Deep 20 %. These results indicate the need of pro-active support mechanisms, legal frameworks and market measures in order to achieve optimal performance of the offshore wind projects to be developed far from shore as part of an offshore grid to avoid that the high costs of infrastructure involved in these projects do not end up as stranded investments.
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Table 2-8 Production and full load hours of offshore wind clusters for “In the Deep 20%”
Pmin = 20 % Installed [MW] Offshore grid - clustered OWE (TWh) Full load hours
CLUSTER (1) 11 562 43.09 3 727.01 CLUSTER (2) 10 650 29.89 2 807.01 CLUSTER (3) 10 265 32.52 3 168.37 CLUSTER (4) 2 560 7.92 3 093.82 CLUSTER (5) 5 102 18.17 3 561.36 CLUSTER (6) 5 650 19.37 3 428.49 CLUSTER (7) 7 470 25.93 3 472.34
Total 53 259 176.90 Table 2-9 Production and full load hours of offshore wind clusters for “In the Deep 0%”
Pmin = 0 % Installed [MW] Offshore grid - clustered OWE (TWh) Full load hours
CLUSTER (1) 11 562 43.7787 3 786.42 CLUSTER (2) 10 650 38.0789 3 575.48 CLUSTER (3) 10 265 37.1536 3 619.44 CLUSTER (4) 2560 9.2962 3 631.32
CLUSTER (5) 5102 19.4287 3 808.05 CLUSTER (6) 5650 21.539 3 812.21 CLUSTER (7) 7470 28.4839 3 813.10
Total 53 259 197.759 Power Flows Models for transmission expansion planning tend to use a single load flow case, usually the peak load situation. For systems with high wind power penetration, this is an invalid assumption which will lead to sub-optimal results. The expansion planning problem solved by Net-Op considers an ensemble of several load flow cases in such a way that a good statistical description of the fluctuations of both (renewable) variable generation and demand is taken into account [8]. In Figure 2-12, Figure 2-13, Figure 2-14 and Figure 2-15, the power flows and duration diagrams for selected connections of the In the Deep offshore grid design presented in Figure 2-9 are shown. Figure 2-12 and Figure 2-14 show the power flow through some selected cables for 100 randomly chosen hours of one year (8760 hours). The alternating patterns for the flows shown in Figure 2-12 and Figure 2-14 are a direct consequence of the variable generation and hourly load profiles that the considered power system will experience throughout a typical year (in this case 2030)1
. The patterns illustrate the complexity
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of solving the transmission expansion problem for systems with high shares of variable generation and demand. Both the capacity rating (maximum MW supported by the connection) and the utilization (average MW flow over the year/ maximum MW capacity) of the cables determine the optimal grid configuration which minimizes the total costs over the whole year. In order to get a better picture of how the average flow patterns develop over the year, duration diagrams for the selected connection are shown in Figure 2-13 and Figure 2-152
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Figure 2-12 Power Flows in cable connections In the Deep The results in Figure 2-13 indicate:
1. A shift into the positive direction is observed in all the HVDC connections shown in Figure 2-13 for the 0 % scenario with respect to the 20 % scenario. This means a higher flow in the direction NO DK for the Skagerrak cable, in the direction NO NL for the NorNed cable, in the direction DK NL for the Cobra cable, in the direction BE UK for the Nemo cable,
1 For Skagerrak: positive flow means flow NO DK, NorNed: positive flow means flow NO NL, Cobra: positive flow means flow DK NL,for Nemo: positive flow means flow BE UK, for BritNed: positive flow means flow NL UK for and NorGer: positive flow means flow NO DE. For NTC between NL-BE : positive flow means flow NL BE, NTC DK-DE: positive flow means flow DK DE and NTC: DE-NL positive flow means flow DE NL. Only 100 hours of the year are shown for illustration. Blue = “0 %” and Red = “20%” scenario. 2 HVDC connections between offshore clusters (i) and (j) O:(i)-(j) [positive flow means flow O:(i) (j)] and radial connection of selected cluster O(i) to onshore land connection point [positive flow means flow O(i) country]. Only 100 hours of the year are shown for illustration. Blue (Light Blue) = “0 %” and Red (Green) = “20 %” scenario.
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in the direction NL UK for the BritNed cable and in the direction NO DE for the NorGer cable. Higher flows occur towards UK and DE in the 0 % scenario compared to the 20 %one.
2. Large percentage of the time with zero flow for Nemo and BritNed cable is found in the 20 % scenario. Finite flow towards UK in the 0 % case is seen for these cables
3. For the Net Transfer Capacities (NTC) we observe an increase of the flow from DK DE and from DE NL and reduction of the flow from NL BE in the 0 % scenario with respect to the 20 %
4. These results indicate a higher trans-national exchange of power in the 0 % scenario with respect to the 20 % through the existing bilateral links.
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Figure 2-13 Duration diagrams (cable connections) In the Deep
40
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O: (1) - (7)
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O: (2) - (4)
0 20 40 60 80 1000
2000
4000
6000
8000
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O(7)-->UK
Figure 2-14 Power Flows for HVDC connections of the meshed offshore grid In the Deep The results in Figure 2-15 indicate:
1. The amount of total flow (MW rating) from the Norwegian Cluster (1) into the Danish (1) (2), German (1) (3) and British cluster (1) (7) is reduced in the 0 % case with respect to the 20 %. This shows that more power is produced “locally” or close from shore, e.g. in DE and UK, so less power is demanded trans-nationally from Norwegian offshore wind. However no substantial shift is observed in the duration curves between both cases.
2. The flow (5) (6) is shifted to the right in the 0 % compared to the 20 % indicating an increased flow in the direction NL UK.
3. The amount of total flow (MW rating) from the Danish cluster (2) into the German cluster (4) (2) (4) increases in the 0 % case compared to the 20 %. A replacement of some non-renewable generation in the German system by Danish offshore wind seems beneficial. See Figure 2-16 for further detailed discussion.
4. The connection (5) (7) disappears in the 0 % case. 5. The duration diagram for the flow from cluster (3) into the German system (3) DE
connection does not shown any significant change between 20 % and 0 % cases 6. Both the amount of total flow (MW rating) and the direction of the flow from cluster (4) into
the German system (4) DE connection increases in the 0 % case compared to the 20 % case. This indicates a higher penetration of offshore wind power into the German system.
7. The duration diagram for the flow from cluster (7) into the British system (7) UK connection shows a slight increase in total flow (MW) from the 20 % to the “0 %” cases.
8. For the flow from cluster (6) into the British system (6) UK connection, a clear shift in the direction towards UK is observed, indicating a higher penetration of offshore wind power into the UK system in the 0 % case.
41
0 20 40 60 80 100
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O: (1) - (7)
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(3)-20%(3)-0%(4)-20%(4)-0%
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O: (2) - (4)
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Percent of Time
O(7)-->UK
Figure 2-15 Duration diagram for HVDC connections of the meshed offshore grid In the Deep
Production by Generation Mix In addition to the offshore wind power production and flow results presented so far, production figures by country for different types of generation are presented in Figure 2-16 below. Renewable generation in countries with surplus (mainly NO and DE) is transferred to countries with large demand needs (UK and DE) through both bilateral HVDC links and the meshed offshore grid. Reduction of Fossil Fuels generation and increasing Renewable generation is found in the 0 % case (blue bars in Figure 2-16) compared to the 20 %(red bars in Figure 2-16) case. Substantial reduction in Fossil Fuel generation between the 20 % and the 0 % case is found for UK and DE (UK reduction = 23.9 TWh, DE reduction = 18.5 TWh).
42
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Figure 2-16 Production by country and per generation mix for In the Deep in TWh3
3 Blue bars = ”0 %”, Red bars = ”20 %”. Wind in “Wind+PV” denotes onshore plus close from shore (d < 70 km) wind power.
43
2.5. Results Scenario Grand Design Offshore grid design
Figure 2-17 Grand Design 70m Optimized Offshore Grid. The optimized grid found by Net-Op for the Grand Design scenario is shown schematically in Figure 2-17. Red areas indicate planned offshore wind parks. Figure 2-18 shows the same optimized offshore grid as Figure 2-17, but in this case additional areas for offshore wind potential development as found by the DSS tool are highlighted. Green areas, found by the DSS tool, indicate additional areas for offshore wind potential development. These maps show the connections found in both scenarios (V05 and V06). Detailed maps for both cases showing the nominated rated capacities for each line in MW, are shown in Figure 2-19 and Figure 2-20.
44
Figure 2-18 Grand Design 70m Optimized Offshore Grid.
45
3oW 0o 3oE 6oE 9oE 50oN
52oN
54oN
56oN
58oN
60oN
1640
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Figure 2-19 Grand Design 70m V05 Optimized Offshore Grid (MW)
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3oW 0o 3oE 6oE 9oE 50oN
52oN
54oN
56oN
58oN
60oN
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Figure 2-20 Grand Design 70m V06 Optimized Offshore Grid (MW) Utilization hours The comparison of the production and utilization hours (also known as full load hours) between the offshore clusters in Grand Design V05 and Grand Design V06 is shown in Table 2-10 and Table 2-11. Note that the installed capacity in the clusters is 88.12 GW in Grand Design V05 and 81.12 GW in Grand Design V06. Despite this difference, the total average production over the year in V05 (299.8 TWh) is only 9.8 TWh larger than the total production in V06 (~290 TWh). Moreover, the utilization hours for the clusters in V05 are typically lower than in V06. Considering the variable nature of wind power production, the potential total average production for the clusters is 334.8 TWh in V05 and 308.12 TWh in V06 – as long as no wind power production restrictions occur due to grid restrictions. However the actual grid constrained total production values in Table 2-10 and Table 2-11 reflect that the total production in both cases is similar and seems to be bound around 300 TWh.
47
To understand these results, is important to note that the Net-Op optimization takes certain installed MW in the clusters as an input and then considers both the impact of variable generation and the competition between investment costs of offshore grid infrastructure against the marginal cost of operation of expensive traditional generation sources. In this way, the value of the offshore grid electrical infrastructure investments is measured against the reduction in operational costs that the system will experience during the lifetime of the grid due to large scale penetration of offshore wind energy. In case V05 for instance, the remaining 35 TWh = (334.8 – 299.8 TWh), which the clusters are potentially able to produce, would require more cables than found in Figure 2-19. The investment costs associated with such an additional offshore grid expansion are much higher than the marginal cost of generation of these extra 35TWh by conventional generation onshore. Table 2-10 Production and full load hours of offshore wind clusters for “Grand Design V05”
“V05” Installed [MW] Offshore grid - clustered OWE (TWh) Full load hours
CLUSTER (1) 14 250 48.02 3 370.10 CLUSTER (2) 11 000 33.76 3 069.51 CLUSTER (3) 20 362 65.88 3 235.62 CLUSTER (4) 9 760 31.40 3 217.92 CLUSTER (5) 12 366 45.46 3 676.59 CLUSTER (6) 7 164 27.03 3 774.32 CLUSTER (7) 11 720 43.75 3 733.55 CLUSTER (8) 1 500 4.46 2 979
Total 88 122 299.80 Table 2-11 Production and full load hours of offshore wind clusters for “Grand Design V06”
“V06” Installed [MW] Offshore grid - clustered OWE (TWh) Full load hours
CLUSTER (1) 13 250 47.83 3 610.08 CLUSTER (2) 10 000 33.39 3 339.52 CLUSTER (3) 19 362 65.90 3 403.63
CLUSTER (4) 8 760 29.37 3 353.04
CLUSTER (5) 11 366 43.22 3 803.14 CLUSTER (6) 6 164 23.54 3 819.58 CLUSTER (7) 10 720 41.91 3 910.19
CLUSTER (8) 1 500 4.81 3 208.13
Total 81 122 290.00 Power Flows In Figure 2-21, Figure 2-22, Figure 2-23 and Figure 2-24, the power flows and duration diagrams for selected connections of the Grand Design offshore grid design presented in Figure 2-17 are shown.
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Figures Figure 2-21 and Figure 2-22 show the power flow through some selected cables for 100 randomly chosen hours of one year (8760 hours)4
.
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Figure 2-21 Power Flows in cable connection Grand Design The results in Figure 2-21 and Figure 2-22 indicate:
1. The average flow is the direction NO DK for the Skagerrak cable, in the direction NO NL for the NorNed cable, in the direction DK NL for the Cobra cable, in the direction BE UK for the Nemo cable, in the direction NL UK for the BritNed cable and in the direction NO DE for the NorGer cable. No large differences are found in the flows of the Skagerrak, NorNed, Cobra, Nemo, BritNed cables between cases V05 and V06. The rating capacity of the NorGer cable is 700 MW higher in V05 (2800 MW) than in V06 (2100 MW).
2. For the Net Transfer Capacities (NTC) it can be observed that the average flow almost exclusively occurs in the direction DK DE. For V05 this is the case in almost 100 % of the time and for V06 the flow is in the direction DK DE about 80 % of the time.
3. For DE and NL the average flow is mainly NL DE 60 % of the time and zero 40 % of the time. For NL and BE, the flow is 20-40 % of the time NL BE and zero 40 % of the time. 20 % of the time there is some flow towards NL, but not at full capacity. No large differences are found between V05 and V06.
4 For Skagerrak: positive flow means flow NO DK, NorNed: positive flow means flow NO NL, Cobra: positive flow means flow DK NL,for Nemo: positive flow means flow BE UK, for BritNed: positive flow means flow NL UK for and NorGer: positive flow means flow NO DE. For NTC between NL-BE : positive flow means flow NL BE, NTC DK-DE: positive flow means flow DK DE and NTC: DE-NL positive flow means flow DE NL. Only 100 hours of the year are shown for illustration. Blue = “V05” and Red = “V06” scenario.
49
0 20 40 60 80 100
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V06V05
Figure 2-22 Duration diagrams (cable connections) Grand Design
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O(7)-->UK
Figure 2-23 Power Flows for HVDC connections of the meshed offshore grid
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The results in Figure 2-23 and Figure 2-24 indicate5
:
1. The amount of total flow (MW rating) at the connections (1) (7), (1) (2) is higher in V05 than V06 as expected due to the higher installed capacity. However, the utilization diagrams show higher utilization and lower periods with zero flow in V06 than in V05 for these connections.
2. Connection (2) (4) shows both a higher total flow and utilization towards cluster (4) in V06 than V05. Moreover, the 600 MW connection (2) (3) present in V05 disappears in V06. These results indicate high power flow congestion and wind power curtailment for cluster (2) in the V05 case.
3. Connection (5) (6), (6) (UK), (7) (UK) and (9) (UK), indicate a high utilization factor for penetration of offshore wind from the offshore grid into the UK system.
4. German (3) DE and (4) DE connection indicates a moderate utilization factor for penetration of offshore wind from the offshore grid into the DE system. The utilization factor from cluster (3) is practically the same between V05 and V06 despite the lower installed capacity. The utilization factor from cluster (4) is slightly higher in case V06 than V05 despite the lower installed capacity. This indicates higher power flow congestion and wind power curtailment in V05.
0 50 100
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(3)-V06(3)-V05(4)-V06(4)-V05
Figure 2-24 Duration diagram for HVDC connections of the meshed offshore grid An interesting connection appears in Figure 2-25 between the clusters (3) and (7). The flow and duration diagram for this East-West connection of the offshore grid is compared to the North-South connection (1) (7). The flow for connection (3) - (7) for both cases shows an oscillatory pattern
5 HVDC connections between offshore clusters (i) and (j) O:(i)-(j) [positive flow means flow O:(i) (j)] and radial connection of selected cluster O(i) to onshore land connection point [positive flow means flow O(i) country]. Only 100 hours of the year are shown for illustration. Blue (Light Blue) = “V05” and Red (Green) = “V06” scenario.
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between positive and negative full rated capacity (+/-600 MW) (top, middle panels in Figure 2-256
). This translates into a “step-like” profile in the duration diagram with a substantial amount of hours with zero flow, since the flow oscillates continuously between positive and negative values between hours. These flow and duration diagram profiles are quite different from the ones for the North-South (1) - (7) connection in which the average flow is directed from NO towards UK (1) (7). Due the distribution of the offshore clusters and the demand scenario, the average flows follow a North-South pattern across the North Sea. On the other hand, the East-West (3)-(7) connection shows a distinctly different flow pattern where no net export or import pattern appears throughout the year. Such connections show the added flexibility of a meshed grid regarding variations of wind power production across the North Sea as well as improved security of supply.
0 20 40 60 80 100
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Figure 2-25 Flow diagram (Left) and duration diagram (Right) for HVDC connection Production by Generation Mix In Figure 2-26 the average total production over the year for the different countries across the North Sea and per generation type available is shown for the Grand Design scenario cases V05 and V067
Figure 2-16
. A major shift from fossil fuels to carbon-free renewable generation is observed in the Grand Design results, compared e.g. to the In the Deep results in . The main conclusions from Figure 2-26 are:
6 Connection (3)-(7) (V06-Top, V05-Middle) and (1)-(7) (V05-Bottom). Only 200 hours of the year are shown in the flow diagram panels (Left) for illustration. Positive flow means flow O:(i) (j). 7 Blue bars = ”V05”, Red bars = ”V06”. Wind in “Wind+PV” denotes onshore plus close from shore (d <70 km) wind power.
52
1. Generation by wind onshore, wind close from shore and solar energy is larger than generation by fossil fuels in DK, DE and the UK. Renewable generation from wind onshore, wind close from shore and solar energy is ~227 TWh in DE and ~143 TWh in the UK.
2. Generation from the offshore wind clusters is above 50 TWh in all countries with installed clustered wind power capacity. The UK shows the highest production from its offshore wind clusters (~72 TWh).
3. Offshore wind generation from the clusters is comparable to renewable production from wind onshore, wind close from shore and solar energy in DK and NL (~50 TWh), indicating a high utilization of these clusters in the Grand Design scenario.
4. Biomass and offshore wind generation from the clusters is comparable for DE (~61 TWh), indicating a high utilization of its clusters in the Grand Design scenario.
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Figure 2-26 Production by country and per generation mix for Grand Design in TWh.
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Energy Balance Figure 2-27 shows total production versus total demand per country and per scenario. Norway and Denmark produce more than their national demand need. This is mainly due to the large installed capacities in clusters (1) and (2). Accordingly, a reduction of the production is observed in DE and the UK between the Grand Design and the In the Deep scenarios. In the Grand Design scenario, the Netherlands produce more than their national demand need.
Figure 2-27 Production vs Demand per country per scenario. Values are given in TWh In Figure 2-28 the total production figures in Figure 2-27 are specified per generation type within each country. Figure 2-28 basically includes the data shown in both Figure 2-16 and Figure 2-26 in one graph. The surplus production in the Netherlands for the Grand Design case is due to a higher production from Renewable generation types. The large increase in offshore wind production from the clusters reflects the high installed capacity and high utilization of the Dutch part of transnational cluster (5).
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Grand Design V05 [TWh]
Grand Design V06 [TWh]
In the Deep Pmin = 0% [TWh]
In the Deep Pmin = 20% [TWh]
Figure 2-28 Production per country per generation type. Figure 2-29 schematically shows the main corridors where trans-national exchanges occur from NO and DK to the UK and DE in both the In the Deep and the Grand Design scenario. The arrow side schematically denotes the size of the average flows. See Figure 2-12 - Figure 2-15 and Figure 2-21 - Figure 2-24 for details on the flows.
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Figure 2-29 Main trans-national exchanges flow corridors. Left panel: In the Deep; Right panel: Grand Design. Arrow side schematically denotes the size of the average flows
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3. Discussion of grid connection results
3.1. Optimal timing and coordination of offshore grid investments
Regarding the timing of the offshore grid investment, we conclude based on our numerical results that:
• Cluster (4) is a transnational cluster consisting of both nationally clustered wind farms in the German area around the DanTysk planned area (DE-D and DE-DSS in appendix C) as well as potential viable wind farms areas found by the DSS-tool at the Danish side of the DE-DK EEZ. Similarly, Cluster (5) is a transnational cluster involving both nationally clustered wind farms in the NL area around the Ijmuiden planned park (NL-I and NL-DSS in appendix C) and the outermost clustered wind farms of the EastAnglia planned area (UK-B in appendix C). In the Grand Design scenario, Cluster (3) is a transnational cluster consisting of both nationally clustered wind farms in the German area around the Borkum-Gaia planned area (DE-B,E and DE-DSS in appendix C) as well as potential viable wind farms areas found by the DSS-tool (NL-DSS in appendix C) at the Dutch side of the DE-NL territorial sea border. These transnational clusters imply that national planning and development of the nationally located wind farms should be done in a coordinated manner at early stages of the development in either one or both countries such that connection to the transnational offshore cluster hub (blue triangle in Figure 2-8 for clusters 3, 4 and 5) is trans-nationally optimal. The development of the transnational clusters 3, 4 and 5 could profit from the lessons learn/to be learnt in the existing Kriegers Flag development project [1].
• Several large connections between Norway and Germany appear in our grid scenarios. Our results suggest that first a point-to-point link of around 2.1 GW can be constructed, which corresponds to a 600MW upgrade of the planned 1.400 GW NorGer link[18]. Then further increase in exchange capacity should be planned considering different combinations of meshed solutions, possibly T-connections between wind farms and the existing bilateral NorGer link first (a 600MW update is suggested) and finally meshed multiterminal connections.
• When planning connection of far offshore wind farms, flexibility on the connection choice and technological solution must be considered. For most of the clusters large portions of the found rated capacity of the connection between wind farms and the shore can be assumed to be mostly unidirectional 2-terminal VSC connections. Only a fraction of the connections found need to be based of fully bidirectional multiterminal VSC connection technology. As an example, cluster (4)-DanTysk area in Grand Design V06 case could be connected by 2-terminal VSC connections up to 6.6GW and by mutiterminal VSC technology up to 5.4GW to cluster (2). Similarly cluster (7)-DoggerBank area in Grand Design V06 could be connected by 2-terminal VSC connections up to 8.4GW and by mutiterminal VSC technology up to 4.2GW to cluster (1).
• There are a number of connections which are always found in the four grid scenario considered (In the Deep 20% & 0% and Grand Design V05&V06). These connections should be planned as first. The capacities reported in our analysis for these common connections can be thought as the minimum (in Figure 2-10,Figure 2-11) and maximum rating (Figure 2-19,Figure 2-20) respectively which are required for these connections.
• The additional connections found in our analysis, especially in the Grand Design grid scenarios should be planned in a second stage of the development of the offshore grid.
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These connections can be planned in coordination with the capacity upgrade of the previously mentioned common connections from In the Deep to Grand Design found ratings.
• The 600MWconnection found between clusters (3) and (7) for the Grand Design analysis shown a symmetrical bidirectional flow pattern. The link supports flow at maximum capacity in both directions for approximately the same number of hours throughout the year. No net import or export situation is found for this link over the whole year of operation. Such flow pattern is different that the flow pattern found for most of the other interconnections, which is more of unidirectional type. For most of the links the power flow occurs predominantly in one direction over the year, showing a clear power exchange pattern (see Figure 2-25). The planning and development of such symmetrical connections will be motivated by added flexibility to the offshore grid rather than net profitability, so they are might appear in the as part of te development of offshore grids, after radial 2-terminal VSC and T-connections are established as proven connection solutions both from technical and economical point of view.
• The planning of the BritNor–NSN link between NO and UK cable should consider flexibility on the choice of connection type and technological solution, since T-connection & multiterminal VSC solutions are found instead of point-to-point connection in our final grid scenarios. However for this particular connection, sensitivity analysis on the results show that a reduction of roughly 20TWh on the available renewable production in land for UK (onshore & close to shore wind and PV) causes the BritNor–NSN link to appear as a bilateral point-to-point link of roughly 800-1000MW size. The production of the cluster (7)-DoggerBank area is ~25TWh out of 30TWh maximum possible for all cases found, which indicates the utilization of this cluster is high. The appearance of the bilateral BritNor-NSN link shows that it is costs efficient to supply the missing 20TWh of production in UK by hydro power from Norway despite the apparently large investment costs of such a long cable.
• The offshore grid design analysis found for the Grand Design scenario (Figure 2-17) shares some similarities with the EWEA’s master plan offshore grid of Figure 5-25 of appendix E. The main differences between the EWEA’s master plan and our Grand Design grid scenario are that: i) The WINDSPEED scenario actually includes elements that resemble both radial and offshore grid strategies indicating that it a mixed solution combining LCC classical point-to-point links, VSC T-links and multiterminal VSC links might occur in reality. ii) The clusters (1) and (2) found in the WINDSPEED project analysis, are new compared to defined offshore clusters in the EWEA’s master plan offshore grid. The clusters/offshore hubs in EWEA’s master plan seem equivalent to our clusters (3-8), although the location of cluster (8) in the WINDSPEED analysis is more to the north in comparison to the EWEA’s offshore hub nearby the Norwegian shore.
Table 3-1 shows investment, operational and total costs as well the associated relative benefit for the In the Deep 20%-0% and Grand Design V05-V06 grid scenario cases analyzed. Total cost is defined in Net-Op as Total = Operational Cost × Lifetime Factor + Investment Cost. The operational costs of generation are determined by the production output of all different generation sources both in generation type and in location. Therefore marginal cost of generation €/MWh for all different generation sources is considered. The investment costs consider the cost of electrical infrastructure needed to connect the far-from-shore offshore wind power clusters to shore or to other clusters. The optimization selects the configuration which the lowest total operational and investment cost for the whole system at each hour of operation considered. The Life Time Factor for a lifetime of 30 years and 5 % discount rate is Σ =1..30 1/ (1 + 0.05)n = 15.3725 and it allows a comparison of the operational savings accumulated throughout the lifetime of a grid project with the investment costs needed to build the grid. Benefit in Table 3-1 is defined as the difference between the total operational and
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investment costs of the In the Deep 20 % case with respect to the total costs of the other 3 scenarios In the Deep 0 %, Grand Design 05 and Grand Design 06. Table 3-1 Total Costs and Benefit.
Million € In the Deep 20 % In the Deep 0 % Grand Design V05 Grand Design V06
Investment Cost 36 290 38 687 60 519 56 562 Operational Cost8 786 280 708 580 637 170 637 950
Total 822 570 747 260 697 690 694 510
Benefit 0 75 310 124 880 128 060 Table 3-1 shows a substantial reduction on system costs between Grand Design and In the Deep in spite of larger installed capacity and more cables being installed in the Grand Design scenario. This benefit indicates the value of a meshed offshore grid in enabling the transfer of wind power to (remote) load centres allowing for lower total operational costs. Note that the higher utilization of offshore wind in V06 compared to V05 translates in similar operational costs for lower investment costs. The investment costs reported in Table 3-1 have been used by the Resolve-E model to calculate final Levelised Production Costs (LPC) for the Grand Design and In the Deep scenario[12]. The results of the LPC calculations are shown in Figure 3-1 below (see [12] for details).
Figure 3-1 Source: Deliverable D6.1, WINSPEED project [12]. Figure 3-1 shows the value of “pro-OWE” scenarios were assumptions on fast technology and reduced cost development are made. The following assumptions are used to obtain the values in Figure 3-1:
1. Investments costs calculated by Net-Op are used in the In the Deep and Grand Design calculation of Figure 3-1. Note that all LPCs are expressed in €2010.
2. Learning effects in the development of technology are considered by Resolve-E. A certain progress ratio “d” for the development of OWE means that with each doubling of the total installed capacity, costs decrease by “100-d” percent. Varying progress ratios are used in the
8 Operational Cost = Operational Cost for 1 year operation × Lifetime Factor
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different WINDSPEED scenarios to reflect the changed assumptions on technology and cost development. Both In the Deep and Grand Design scenarios assume a future with substantial technology development (i.e. fast learning)[12].
3. The LPC of the necessary offshore grid investment is presented with (red) and without (blue) learning effects considered. The benefits of increased scale of deployment, i.e. fast learning, translate into lower LPC in those scenarios that had the highest estimated installed capacities in 2030.
In such pro-OWE scenarios, it is indirectly assumed that the necessary policy measures exist such as there is sufficient stability and predictability in the renewable power sector to allow for market growth and financial support measures. This is a very long and complex process so timing of the necessary steps regarding pro-OWE regulatory frameworks that will permit subsequent grid investment is very important. As an example, EWEA has indicated the need of a new regulatory framework for the renewable sector post-2020 [19]. According to EWEA, the EU commission needs to have such framework in place by the end of 2014 to ensure continued growth and financial stability[19]. When it comes to grid investments, regulatory frameworks for interconnectors and offshore transmission must be unified. As per today, these are very different between different countries. It is e.g. not clear how offshore wind farms could be connected to several different countries to allow for trans-national power exchanges. This leads to uncertainty and high risk of stranded investments due to the high costs of infrastructure as well as unclear financial support and/or necessary market growth perspectives. Regarding timing for construction of the offshore grid electrical infrastructure, we take as examples the existing NorNed [20] and BritNed [21] links, the future NorGer HVDC link, [18], the existing offshore wind farm BARD Offshore 1 [22] and the future offshore wind farm Dogger Bank [23]. The total period of time for the completion of these projects seems to be approximately between 8-10 years, of which the application process, approval and investment decision typically takes 5-7 years and construction phase 3-5 years. For 2030 as target year, it seems reasonable to assume that new pro-OWE regulatory and commercial frameworks should be established in the period 2015-2020 such that large scale investment decisions are being made latest before the beginning of 2020. Under these assumptions, large scale construction of an offshore grid can slowly emerge from national development to international coordination between 2020 and 2030, with a minimum total construction time of 10 years.
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3.2. Consequences for onshore grid Grid development onshore will be needed in order to allow for integration of large scale offshore wind development into the power system. The need for onshore grid expansion is determined by the presence of transmission bottlenecks in the transmission grid, preventing wind production to be fully transmitted from its location of generation to the demand area where is needed. On one hand, since wind production is non-dispatchable, transmission grid expansion demands are driven by the perspective of allowing all potentially available wind generation to be utilized/consumed. On the other hand, transmission grid expansion projects involving both the construction of new grids and technological upgrade of the existing grids, are usually constrained by security of supply and operational guidelines on one hand, and public acceptance and environmental limitations on the other hand. In this report we will only discuss the technical consequences regarding transmission grid expansion needs in order to guarantee a sufficient penetration of offshore wind into the power system. This technical discussion will be fed into the much broader discussion of the roadmap document of the WINDSPEED project which will also include economic, political, social and environmental considerations[24]. Moreover, since the focus of the WINDSPEED project is the deployment of offshore wind energy in the area around the North Sea basin, the Net-Op grid expansion optimization tool uses a simplified description of the onshore power system. From the results of the Net-Op simulations, we are able to quantify the onshore connection capacity needed for each country in order to accommodate the offshore wind power feeding into the respective transmission grid. Table 3-2 shows the onshore connection capacity (MW) needed for each country in the In the Deep and Grand Design scenarios. The total onshore connection capacity needed per country to accommodate the offshore wind potential found in each scenario of the WINDSPEED analysis is therefore the sum of the “Offshore Grid”( distance to shore d > 70 km) and “Close to Shore” (distance to shore d < 70 km) numbers reported in Table 3-2. Table 3-2 Onshore Grid connection capacity
OFFSHORE -> ONSHORE : OFFSHORE GRID
BE DE DK NL NO UK
MW MW MW MW MW MW
In the Deep 20 % 1 200 21 300 3 600 1 200 13 500 11 400
In the Deep 0 % 1 200 23 100 4 800 1 200 14 100 12 600
Grand Design V05 9 600 26 800 3 000 9 600 15 400 21 000
Grand Design V06 8 300 25 500 3 600 8 300 14 700 20 400
OFFSHORE -> ONSHORE : CLOSE TO SHORE
BE DE DK NL NO UK
MW MW MW MW MW MW
In the Deep 20 % 2 032 13 878 9 728 6 662 0 19 927
In the Deep 0 % 2 032 13 878 9 728 6 662 0 19 927
Grand Design V05 2 242 22 195 9 657 9 459 506 17 785
Grand Design V06 2 242 22 363 9 728 9 459 506 20 497
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Detailed investigations on which lines of the internal transmission grid in each country should be expanded to account for the onshore grid connection capacity shown in Table 3-2 is needed. However, this task is beyond the scope of the WINDSPEED project. Detailed technical investigations regarding non-transmittable power and grid extensions require detailed grid studies e.g. using Power Transfer Distribution Factors (PTDF). One example of such study for the German grid has been recently presented in the dena Grid Study II [2]. We present some figures from the dena Grid Study II [2] as an illustration of the consequences that future scenarios for electricity generation from renewable energy will have on the onshore transmission grid. In the scenarios considered in [2], the addition of new lines into the German grid amounts to total 3600 km of additional lines between the year 2015 and 2020. Different transmission tasks (i.e. transmission capacity needed vs. Distance of the transmission line needed) were used in [2] to decide which portion of these additional 3600 km transmission will use AC or DC technology. Different combinations of transmission capacity (1 GW and 4 GW) as well as distances (100 km and 400km), have been considered [2]. For low transmission (1GW) and short distance (100km), conventional 380 kV AC overhead lines provided the best result. For capacities between 1-4 GW and for the same distance of 100 km, different combinations of solutions including both AC and DC transmission technologies were found to be best, depending on the situation considered. For line lengths of 400 km and capacities of 4 GW or even higher, overhead HVDC solutions start being preferred. The installed wind capacity considered in the dena II study is 37 GW onshore and 14 GW offshore in 2020 and 34 GW onshore and 7 GW offshore in 2015. This is a 3 GW increase onshore and a 7 GW increase offshore between 2015 and 2020. We note that for the 2030 Grand Design scenario analyzed here, the assumed installed capacity is ~35 GW onshore and 41 GW offshore. This is a ~27 GW increase in offshore installed capacity between 2020 in the dena II study [2] and the Grand Design 2030 WINDSPEED scenario. In the Grand Design scenario some remote offshore wind power installed in other countries EEZ across the North Sea penetrates the German system through the meshed offshore grid also affecting the need for onshore grid reinforcements. Assessment of both offshore and onshore grid reinforcements by using a detailed grid model are subject of investigation e.g. in the OffshoreGrid project [13].
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Figure 3-2 Long-term investments around the North Sea area as reported by ENTSO-E TYNDP [25]. Beyond the technical assessments, transmission expansion projects are very complex and typically involve considerations about investments, energy policy, security of supply, renewable integration, expected demand, market design and social acceptance both at national and European level. The first steps towards the future development of the transmission network have been addressed by ENTSO-E in its Ten Year Network Development Plan 2010-2020 TYNDP [25]. Figure 3-2 illustrates the complexity of such investigations already up to the year 2020. Further investigations for the period 2020-2030 will follow based on existing regional, multilateral or bilateral cooperation between TSOs with support from the European Commission, European Regulators Group for Electricity and Gas (ERGEG), and many other key stakeholders. In Figure 2-9 an orange connection between cluster (3), located around the border of the German-Dutch exclusive economic zone (EEZ), and cluster (5) located around the Dutch-British EEZ is shown. This connection has been added into the recommended offshore grid for 2030 and has not been found by the Net-Op optimization. The reasons for including this connection in our final suggested grid are:
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1. In the In the Deep 0 % scenario, a 600 MW connection from DK to NL is found. This connection could be joined to the connection to cluster (3) in a T-connection type, making a DK – DE – NL link.
2. The orange line together with other connections found in the analysis provides the full-meshed alternative to the previous DK – DE – NL link as DK – (2) – (3) – (5) – NL. Such DC subsea connection between the Eemshaven and Ijmuiden offshore areas has been recommended in [26] to allow offshore wind production around the Eemshaven area – cluster (3) to penetrate the Dutch power system at the onshore connection point of the Ijmuiden parks, since this is an area with high power demand. This solution will therefore bypass the Dutch internal grid bottlenecks that prevent wind power produced in the Eemshaven area from being transmitted to the high demand area around the Ijmuiden-onshore area.
3. The reason why the Net-Op simulation does not find such connection is twofold: a. In the study of [26], 5 GW are installed at the Ijmuiden clusters (V and VI) and
9.4 GW at the Eemshaven cluster. A connection between these two points is recommended to allow for the surplus at Eemshaven to penetrate the Dutch system through the onshore connection point of Ijmuiden. In Net-Op, the cluster (5), corresponding to the Ijmuiden area, has 11.3 GW installed capacity. This is a quite different situation than the one investigated in [26]. This means that the Ijmuiden cluster (5) can provide more power to the Dutch area nearby, therefore reducing the need for the recommended connection in [26]. On the other hand, this assumes a more substantial development of offshore wind in the Dutch EEZ far from shore in the Grand Design scenario compared to the scenario in [26].
b. In addition, the connection recommended in [26] is based on the assumption that internal grid bottlenecks in the Dutch grid North-South will prevent power feeding from Eemshaven into land to reach the higher demand area nearby Ijmuiden. Due to the focus of the WINDSPEED project, the Net-Op simulations presented here focus on trans-national power exchanges and do not consider the role of internal grid constrains in details. Therefore this connection was not found by the Net-Op tool.
3.3. Connection to oil and gas platforms Development of offshore deep sea wind power is interesting for supplying power to oil and gas rigs. Traditionally, the electric loads at oil and gas rigs are powered by gas turbines typically ranging about 10-20 MW. The wind turbines can be located near the oil rig and operated in parallel with the gas turbines that supply power to the platforms. This can save fuel and CO2 emissions about proportional to the energy output of the wind turbines. Petroleum installations in the North Sea could also be part of an offshore grid. The installations will then be offshore load points, which could be connected to an offshore node nearby a wind farm, as shown in the example in Figure 3-3. The connection includes an offshore hub with links to a wind farm and a petroleum installation. Traditional electrification of petroleum installations may become very costly due to the long transmission distances needed for grid connection. Estimates for CO2-abatement costs is in the range of 190 €/tonnes for the best areas [27]. With the possibility of connecting to a nearby offshore hub, the connection costs, and thus the electrification costs, may be significantly reduced. This can also make electrification of oil and gas platforms to be a more attractive measure for reducing CO2-emissions, especially in the Norwegian sector. Additional
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benefits of connecting wind farms to oil and gas rigs (or include oil and gas rigs as demand nodes in an offshore grid) is to create a local demand for wind power (thus reducing transmission costs) and to share grid connection to shore (thus increasing the utilization of capital-intensive cable investment).
NO
DE
~
~
Wind farm
Off shore load (Ekofisk)
~
AC link, 750MW, 120 km
DC link, 1000MW
Figure 3-3 Conceptual drawing of a possible Norway-Germany connection [28]. Based on the information from [27], the Mid and Southern North Sea areas of Norway could represent an electricity load of about 200 MW. Assuming 3500 full load hours for offshore wind farms, the demand could in average be covered by a 500 MW wind farm. The large potential for offshore wind development found in the Grand Design (green areas in Figure 3-4) nearby areas with high concentration of oil and gas platforms (light blue circles in Figure 3-4) indicates high potential for electrification of oil and gas platforms in the Norwegian sea. Note that the Grand Design potential map in Figure 3-4 excludes the possibility of floating turbines due to the 70 depth constrain used in our analysis. Scenarios without any depth constrains haven been analyzed in the WINDSPEED project showing an even higher potential for offshore wind development around the indicated areas with high concentration of oil and gas platforms.
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NorthernNorth Sea
MidNorth Sea
SouthernNorth Sea
(Ula, Gyda, Ekofisk, Eldfisk)142 MW (60 Hz)
(Ringhorne, Grane, Sleipner)64 MW (50 Hz and 60 Hz)
(Visund, Kvitebjørn, Oseberg, Troll and more)405 MW (50 Hz and 60 Hz)
280 km
200 km
160 km
80 km
NorthernNorth Sea
MidNorth Sea
SouthernNorth Sea
(Ula, Gyda, Ekofisk, Eldfisk)142 MW (60 Hz)
(Ringhorne, Grane, Sleipner)64 MW (50 Hz and 60 Hz)
(Visund, Kvitebjørn, Oseberg, Troll and more)405 MW (50 Hz and 60 Hz)
280 km
200 km
160 km
80 km
Figure 3-4 Electrification of oil and gas by offshore wind turbines. Right panel from[27]
The indicated capacity in cluster (1) - 14.2GW and (8) - 1.5GW, assumed in our Net-Op analysis is not expected to be reduced by possibilities for electrification of oil and gas platforms around these areas, due to the large potential found for offshore wind development in the southern Norwegian Sea (around cluster (1) and (8)) and possibilities for even higher potential considering floating turbine technology. Electrification of oil and gas platforms will not cause any significant alteration of the offshore grid designs obtained in our analysis. For the other countries around the North Sea with petroleum activity (The Netherlands, UK and Denmark), an assessment for the potential for connection to offshore grids has been done in [13]. It was concluded that connecting oil and gas platforms in these countries to offshore grids is not relevant, due to the low energy demand, fast decline of fields and high uncertainty about future developments.
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4. Summary and Conclusions In this report, a technical-economical assessment of grid connection/development has been done for the In the Deep and Grand Design offshore wind development scenarios defined in task D6.1[12] of the WINDSPEED project. A major shift in production from fossil fuels to carbon-free renewable sources is found in the pro-Offshore Wind Energy (pro-OWE) scenario Grand Design with respect to the In the Deep scenario. Regarding the timing of the offshore grid investment, we conclude based on our numerical analysis and on the assessment of the results obtained that:
1. The offshore grid design found for the Grand Design scenario (Figure 2-17) shares some
similarities with the EWEA’s master plan offshore grid of Figure 5-25, considering that EWEA master plan was developed by a bottom-up approach whereas the WINDSPEED analysis is a top-down one. The WINDSPEED grid scenario includes a mixed solution combining LCC classical point-to-point links, VSC radial connections of wind farms to shore, T-links and multiterminal VSC links. Two new offshore clusters in Norway and Denmark are suggested in the WINDSPEED project analysis with respect to the EWEA’s master plan.
2. For 2030 as target year, pro offshore wind regulatory and commercial frameworks should be established in the period 2015-2020 such that large scale investment decisions are being made around the beginning of 2020. Under these assumptions, large scale construction of an offshore grid can slowly emerge from national development to international coordination between 2020 and 2030, with an approximate total construction time of 10 years.
3. Planning of T-connections should be coordinated between the link developers (typically TSOs) and wind farm developers. Investment decisions should consider the profitability of the T-junction as a whole instead of considering the profitability of the link and of the wind farm independently. Coordination at early stages of the development of both projects between link developers and wind farms developers and new market rules that allow trading of power from the link and from the wind farm in the same market, are needed.
4. Some important T-connections suggested in our analysis are: i) between the planned NSN link and the clusters (8) (only in Grand Design); ii) Between a possible southern version of the UK-NO NSN link and cluster (1) and cluster(5)-DoggerBank (two independent T-connections); iii) A ~2100MW bilateral link between NO-DE is suggested from our analysis, which is ~700MW upgrade to the planned 1400MW NorGer link[18]. Upgrades in exchange capacity between NO-DE above 2100MW involve T-connections through offshore cluster (4).
5. Note that for options ii) and iii) mentioned in point 4, clusters (1,4,5) are connected in a multiterminal fashion to others clusters according to our analysis, so the suggested T-connections mentioned above are suggested as first steps towards the fully multiterminal meshed solution found.
6. Transnational clustering, i.e. the connection of wind farms located in different EEZ areas into a common offshore hub or node, is suggested between the UK-Hornsea and the NL-Ijmuiden area (cluster (5)), the DE-DanTysk and the DK-nearby area (cluster (4)) and between the NL- Eemshaven and DE- Borkum&Gaia area (cluster (3) but only in Grand Design).
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7. Planning for transnational clustering should be done in a coordinated manner at an early stage of the development of the wind farms in the different countries, so the connection to the transnational offshore cluster hub allows for flexible and harmonized technical standards regarding technology and technical choices. Lessons learned from the Kriegers Flag[1] project should be used when development transnational clusters.
8. Flexibility on the connection choice and technological solution must be considered. For most of the clusters large portions of the found capacity of the connections between wind farms and the shore in Net-Op can be assumed to be mostly unidirectional 2-terminal VSC connections. Only a fraction of the capacity found needs to be based of fully bidirectional multi-terminal VSC connection technology.
9. There are a number of connections which are found in both the In the Deep and Grand Design grid scenarios. These common connections should be planned first as they represent the more robust choices regarding uncertainties in offshore wind development between a 2030 In the Deep-like future or a 2030 Grand Design-like future. The capacities reported in the In the Deep and Grand Design solutions provide respectively the minimum and maximum capacity needed for these connections.
10. The flow in some connections in a meshed offshore grid configuration, like e.g. the 600MW link between clusters (3) and (7) in the Grand Design, is such that no net import or export situation is found for such link over the whole year of operation. Such flow patterns demonstrate the added flexibility of the offshore grid. Planning and development of such symmetrical connections will be motivated by improved flexibility and security of supply of the offshore grid rather than on possibilities for trans-national power exchanges. Because of this, these connections may be built once the development of unidirectional 2-terminal VSC radial connections and T-connections is well established from a technical and economical point of view.
Regarding operational and investment costs, coordination and savings we conclude from our analysis:
1. Substantial reduction in operational costs is found in Grand Design with respect to In the Deep. This benefit is a consequence of the higher installed capacity of offshore wind. This leads to more grid investments and more meshed offshore grid configuration, allowing the transfer of (remote) wind power to load centers in a flexible and efficient manner.
2. A total benefit of ~ 120 M€ is found when comparing the total costs of Grand Design with In the Deep, despite of larger installed capacity and larger investment costs of electrical infrastructure in the Grand Design scenario, due to the higher penetration of offshore wind in Grand Design.
3. Higher utilization of offshore wind in Grand Design V06 compared to Grand Design V05 (see Table Table 2-10 and Table 2-11) translates in similar operational costs for lower investment costs.
4. Regarding need for onshore grid reinforcements and assuming a total project time of minimum 8-10 years (application phase, investment decision and construction), development of pro-OWE scenarios In the Deep and Grand Design requires that regulatory and commercial frameworks should be established in the period 2015-2020 such that large scale investment
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decisions regarding offshore wind farm development and electrical infrastructure connection are made before or up to the beginning of 2020.
5. From our assessment of onshore grid reinforcements, new grid infrastructure onshore (update and new lines) will be needed between 2020 and 2030 to accommodate ~ 145 GW offshore wind proposed in the Grand Design scenario, of which ~130GW is expected to be developed in the North Sea. Further detail analysis is needed to determine the particular transmission capacity, distance of the transmission line and use AC or DC technology onshore in each of the WINDSPEED countries. The estimation of a total 3600 km of additional lines into the German grid between the year 2015 and 2020, according to the dena II study, is a good example of the type of study needed [2].
Regarding the potential of meshed grids to allow replacement of conventional generation sources by renewable sources in the supply of electricity and for reduction of CO2 we conclude:
1. Renewable generation in countries with surplus (mainly NO and DE) is transferred to countries with large demand needs (UK and DE) through both bilateral HVDC links and the meshed offshore grid.
2. Substantial reduction of Fossil Fuels generation and increasing renewable generation is found in the Grand Design scenario. Specifically our analysis shows:
a) Generation by wind onshore, wind close from shore and solar energy is larger than generation by fossil fuels in DK, DE and the UK. Renewable generation from wind onshore, wind close from shore and solar energy is ~227 TWh in DE and ~143 TWh in the UK.
b) Generation from the offshore wind clusters is above 50 TWh in all countries with installed clustered wind power capacity. The UK shows the highest production from its offshore wind clusters (~72 TWh).
c) Offshore wind generation from the clusters is comparable to renewable production from wind onshore, wind close from shore and solar energy in DK and NL (~50 TWh), indicating a high utilization of these clusters in the Grand Design scenario.
d) Biomass and offshore wind generation from the clusters is comparable for DE (~61 TWh), indicating a high utilization of its clusters in the Grand Design scenario.
3. The lowest CO2 emissions are expected to occur in the Grand Design scenario. No
detail estimates of CO2 reduction has been done in our analysis though. Savings in conventional generation found in Figure 2-26 will have to be translated into fuel savings (mainly coal, gas, oil) and therefore into CO2 emissions.
4. Further reduction in CO2 emissions can be obtained by supplying wind power to oil and gas rigs. The large potential for offshore wind development found in the Grand Design indicates that wind turbines could be installed near oil and gas rigs and operated in parallel with gas turbines that supply power to the platforms. This can save fuel and CO2 emissions about proportional to the energy output of the wind turbines
Some general conclusions regarding the development of offshore grids can be also mentioned:
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1. Investment cost of electrical infrastructure, distance to shore, installed capacity of offshore wind and volume of generation and demand per country and prices of (conventional) generation on land, are the main factors that determine the ”optimal” design of an offshore grid structure.
2. High costs of electrical infrastructure, compared with the price of generation for conventional
generation on land and short distance to shore (d < 70 km) for offshore wind deployment typically mean that radial and bilateral interconnectors are preferred.
3. Comparable costs of electrical infrastructure with respect to the price of generation for
conventional generation on land and long distances to shore (d > 70 km) for offshore wind deployment translates into a meshed offshore grid being economically feasible.
4. Meshed grids improve the reliability of grid connections for wind farms and enable the transfer
of wind power to (remote) load centres. 5. Hydropower (from South of Norway and the Alps region) and other storage technologies, as well
as Combined Cycle Gas Turbines (CCGT) will play an important role as balancing sources to compensate for the variable nature of wind generation, specially as wind penetration levels increase. The meshed nature of an offshore grid also helps to balance wind variations across the North Sea OW clusters.
6. Need for trans-national coordination regarding technical, commercial and regulatory issues is
needed for cost efficient and reliable development of offshore wind technology. 7. Under these assumptions, large scale construction of an offshore grid can slowly emerge from
national development to international coordination during 2020 - 2030.
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Appendix A: Generation Capacity In the Deep Non Renewable generation capacity Table 4-1 Non-Renewable Generation capacity [MW] in 2030 (PRIMES)
Generation capacity [MW] BE DK DE NL NO UK
Nuclear energy 0 0 0 589 0 6 012
19 386 Thermal power 7 505 96 488 23 470 2 622 61 693
Solids fired 4 387 3 104 35 620 6 279 0 9 799
Oil fired 1 172 118 8 114 770 0 1 299
Gas fired 11 047 2 524 42 538 11 709 2 622 43 108
Natural gas 10 581 2 524 40 088 10 979 2 622 42 420
Derived gasses 466 0 2 450 730 0 688
Figure 4-1 Non-renewable generation capacity (GW) in all WINDSPEED countries in 2030
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Renewable Generation capacity Table 4-2 Renewable Generation capacity [MW] in 2030 (RESolve-E)
Generation capacity [MW] BE DK DE NL NO UK
Biomass 3 066 1 612 9 036 2 559 40 4 921
Hydro power 171 12 3 946 133 36 754 2 060
PV 5 797 397 67 306 5 790 0 13 962
Geothermal 0 0 384 0 0 5
Wave 0 188 0 0 0 6 163
5 085 Wind total 25 991 61 836 13 053 20 617 59 926
Wind onshore 3 053 4 863 35 883 4 496 9 055 23 672
Wind offshore 2 032 21 128 25 953 8 557 11 562 36 254
Figure 4-2 Renewable generation capacity (GW) in all WINDSPEED countries in 2030
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Maximum conventional and renewable production Table 4-3 Maximum allowed conventional production (GWh) in 2030 (PRIMES)
Total production [GWh] BE DK DE NL NO UK
0 Nuclear energy 0 0 5 096 0 48 031
83 526 Fossil fuels 15 615 353 656 90 480 0 178 660
Coal and lignite 31 244 8 140 224 747 26 567 0 80 767
Petroleum products 3 363 141 5 221 1 685 0 1 108
Natural gas 38 360 7 334 110 597 51 243 15 500 96 374
Derived gasses 2 748 0 13 091 1 445 0 411 Table 4-4 Maximum allowed renewable production (GWh) in 2030 from RESolve-E
Total production [GWh] BE DK DE NL NO UK
Biomass 17 959 12 107 59 784 18 183 283 33 188
Hydro power 539 29 22 152 422 152 417 6 480
PV 5 434 369 61 804 4 793 0 11 701
Geothermal 0 0 2 521 0 0 33
Wave 0 453 0 0 0 14 847
14 315 Wind total 100 519 185 789 44 830 74 615 203 503
Wind onshore 5 965 11 733 81 835 10 818 23 955 63 137
Wind offshore 8 350 88 787 103 955 34 012 50 661 140 366
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Appendix B: Generation capacity Grand Design Non-Renewable generation capacity Table 4-5 Non-Renewable Generation capacity [MW] in 2030 (PRIMES)
Generation capacity[MW] BE DK DE NL NO UK
Nuclear energy 0 0 0 0 0 0
14 961 Thermal power 2 642 78 895 16 165 2 622 49 307
Solids fired 2 742 0 28 243 3 686 0 4900(9979)9
Oil fired
1 172 118 8 114 770 0 1 299
Gas fired 11 047 2 524 42 538 11 709 2 622 43 108
Natural gas 10 581 2 524 40 088 10 979 2 622 42 420
Derived gasses 466 0 2 450 730 0 688
Figure 4-3 Non-renewable generation capacity (GW) in all WINDSPEED countries in 2030
9 4.9 GW in “V05” and 9.979 in “V06”
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Renewable generation capacity Table 4-6 Renewable Generation capacity [MW] in 2030 (RESolve-E)
Generation capacity [MW] BE DK DE NL NO UK
Biomass 3 073 1 612 9 036 2 559 40 4 915
Hydro power 171 12 3 946 133 36 754 2 060
PV 5 797 397 67 306 5 790 0 13 938
Geothermal 0 0 384 0 0 5
Wave 0 188 0 0 0 6 163
5 295 Wind total 31 091 77 318 26 950 25 311 62 605
Wind onshore 3 053 4 863 35 883 4 496 9 055 23 853
Wind offshore 2 242 26 228 41 435 22 454 16 256 38 752
Figure 4-4 Renewable generation capacity (GW) in all WINDSPEED countries in 2030
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Maximum conventional and renewable production Table 4-7 Maximum allowed conventional production (GWh) in 2030 (PRIMES)
Total production [GWh] BE DK DE NL NO UK
0 Nuclear energy 0 0 0 0 0
63 999 Fossil fuels 7 475 307 108 69 969 15 500 168 660
Coal and lignite 19 527 0 178 199 15 596 0 7076710
Petroleum products
3 363 141 5 221 1 685 0 1 108
Natural gas 38 360 7 334 110 597 51 243 15 500 96 374
Derived gasses 2 748 0 13 091 1 445 0 411
Table 4-8 Maximum allowed renewable production (GWh) in 2030 from RESolve-E
Total production [GWh] BE DK DE NL NO UK
Biomass 17 995 12 107 59 784 18 183 283 33 149
Hydro power 538 29 22 152 422 152 417 6 480
PV 5 434 369 61 804 4 793 0 11 671
Geothermal 0 0 2 521 0 0 33
Wave 0 453 0 0 0 14 847
15 169 Wind total 121 951 248 772 100 339 96 957 210 052
Wind onshore 5 965 11 733 81 835 10 818 23 955 63 137
Wind offshore 9 203 110 218 166 937 89 521 73 002 146 916
10 50.767 TWh in “V05” and 70.767 TWh in “V06”
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Appendix C: Offshore wind cluster Table 4-9 Offshore Wind cluster In the Deep
Cluster Region Region MW Sum MW
(1) NO-DSS 7 200 11 562 NO-DSS 1 712 NO-DSS 2 650
(2) DK-DSS 8 000 10 650 DK-DSS 2 650
(3) DE-DSS 350 10 265 DE-DSS 1 000 DE-B11 6 650 DE-E 2 265
(4) DK-DSS 750 2 560 DE-DSS 300 DE-D 1 510
(5) NL-DSS 250 5 102 NL-DSS 600 NL-I 1 045 UK-B 3 207
(6) UK-DSS 2 100 5 650 UK-DSS 900 UK-DSS 650 UK-C&D 2 000
(7) UK-E 1 606 7 470 UK-F 5 864
11 The allocated capacity for clustering for the permitted area DE-B is 6.65 GW, following the detailed assessment done in [41] regarding installed capacity density MW/km2 for clustering. The remaining capacity 9.625 – 6.65 = 2.975 GW is assumed to be radially connected to the German shore.
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Table 4-10 Offshore Wind cluster “Grand Design
---- V05 ---- ---- V06 ---- Cluster Region Region MW Sum MW Region MW Sum MW
(1) NO-DSS 2 750 14 250 2 750 13 250 NO-DSS 11 500 10 500
(2) DK-DSS 11 000 11 000 10 000 10 000 (3) NL-DSS 5 311 20 362 5 050 19 362
DE-DSS 5 311 5 050 DE-B12 6 993 6 650 DE-E 2 747 2 612
(4) DK-DSS 5 571 9 760 5 000 8 760 DE-DSS 2 507 2 250 DE-D 1 682 1 510
(5) NL-DSS 7 670 12 366 7 050 11 366 NL-I 1 137 1 045 UK-B 3 559 3 271
(6) UK-DSS 6 650 7 164 5 650 6 164 UK-C&D 514 514
(7) UK-E 1 129 11 720 1 033 10 720 UK-F 5 398 4 937 UK-DSS 3 717 3 400 NL-DSS 1 476 1 350
(9) NO-DSS 1 500 1 500 1 500 1 500
Appendix D: Technical solutions The text in this appendix in mainly taken from [29]. Offshore power transmission The purpose of the offshore transmission system (in connection with a wind farm) is to transfer power from the wind farm to the power network onshore, or to any offshore consumers. Several technical solutions can be possible: 50 or 60 Hz HVAC transmission, low frequency HVAC transmission or HVDC transmission. Possible layouts for the different technologies, including two types of HVDC transmission, are shown in Figure 4-5. The different types of HVDC transmission will be further explained below.
12 The allocated capacity for clustering for the permitted area DE-B is 6.993 GW in “V05” and 6.65 GW in “V06”, following the detailed assessment done in [46] regarding installed capacity density MW/km2 for clustering. The remaining capacity 10.411 – 6.993 = 3.418 GW in “V05” and 10.411 – 6.65 = 3.761 GW in “V06” is assumed to be radially connected to the German shore.
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~= ~
=
Filtre
Statcom/Diesel gen
FilterStrong grid
~= ~
=
Strong orweak grid
LCC LCC
600 MWwind farm
~= ~
=HVDC
VSC VSC600 MWwind farm
SVCSVC
Strong grid
600 MWwind farm
HVDC
HVAC
a)
b)
c)
Figure 4-5 Alternatives for transmission of offshore wind power ([30] and [31]). a) HVAC with SVC (Static Var Compensator) b) LCC HVDC c) VSC HVDC. The choice of transmission solution will be governed by economic and technical matters. The most important technical factor for the choice of transmission technology is the combination of distance from the wind farm to shore/consumer and the amount of power that will be transmitted. HVAC transmission will normally be used for low to moderate lengths (~70km from shore) while HVDC technology will be used when the distance as well as the amount of power increases (distance to shore > 70km). The reason for the limited transmission capacity of long AC cables is the large cable capacitance that leads to high reactive currents (charging currents) which in turn reduce the cable’s ability to carry active current. The use of reactors or similar to avoid this problem, makes it viable to transmit power on AC over longer distances. All offshore wind farms installed till early 2009 use AC cable transmission. Gas insulated transmission lines (GIL), which consist of tubular aluminium conductors encased in a metallic tube filled with a mixture of Sulphur Hexafluoride and Nitrogen gases, can theoretically be an alternative to cables for HVAC transmission [32]. GIL has low capacitance and is considered to be an alternative for lengths up to 100 km without any reactive compensation. Some installations with relatively high capacity (1000-3800 MVA) exist on shore (underground) [32], but no installations offshore exist yet. HVDC transmission systems do not have length limitation issues due to reactive power, but do on the other hand need large and costly converter stations. The converter stations themselves will
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represent losses in the system. The wind farm cluster Borkum 2 [22, 33] in the German sector is connected to shore via a 200 km HVDC link utilising the VSC technology. A comparison of strengths and weaknesses of AC and DC transmission systems is given in Table 4-11. Table 4-11 Strengths (+) and weaknesses (-), of AC and DC transmission systems
+/- HVAC technology +/- HVDC technology + Main network today is AC, easy
connection + Relatively low losses, long distances
possible + Transformation between voltage levels + Connection of asynchronous grids + Available circuit breakers and switches (for
onshore/indoors use), fault handling
+ Long operational experience - Large and heavy converter stations necessary
+ Costs of installation - Lack of components for breaking, fault handling
+ Limited amount of space required on board offshore platform
- No experience, nor ready technology for DC grid
- Relatively high losses in cable, especially for long distances
- Costs of installation
- Need for reactive compensation - Converter station losses - Connection of asynchronous networks
Technical details: HVAC technology 50/60 Hz technology Figure 4-5 a) shows an outline of a typical AC transmission system for an offshore wind farm and Figure 4-6 shows the actual single line diagram for Horns Rev 1 wind farm as an example. Some data for Horns Rev 1 is also given in Figure 4-6. The vital components of the AC transmission system are the transformer platform/offshore substation including components for reactive compensation, the transmission cables, the cable transition station, the land cable and the transformer station on shore. Horns Rev 2 is situated about 23 km northwest of Horns Rev 1. Connecting the 91 wind turbines of Horns Rev 2 offshore wind farm off the west coast of Jutland required the following installations:
• A transformer platform, which collects the power from the wind turbines and increases the voltage level from 33 kV to 150 kV. The platform is 37 m from the seabed to the helipad.
• A 42 km 150 kV submarine cable from the platform to the shore where it is connected to a cable substation.
• A 150 kV land cable to Endrup substation where the voltage level is increased to 400 kV. • The grid connection, which was budgeted at EUR 110 million, was completed in May 2009.
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Figure 4-6 Single line diagram for Horns Rev 1 [34]. The onshore substation is mature technology which can be found with large capacities and with voltage levels up to 765 kV [35]. This part of the system will not represent a limit to what can be achieved with HVAC transmission systems for connection of offshore wind farms. Technical details: HVDC technology High Voltage Direct Current (HVDC) transmission is the alternative to HVAC transmission for long distances and high powers. There are two different technologies: Line Commutated Converters (LCC) and Voltage Source Converters (VSC). Today there are more than 100 HVDC transmission links around the world. Nearly all of these are of the LCC type. The two technologies are further described below. LCC HVDC technology The LCC HVDC technology is a mature technology, though still developing. The first installation came out in 1950 in USSR (Kashira-Moscow) [36] followed by the Gotland installation in Sweden in 1954. A list of the different LCC installations showing capacity in MW and voltage can be found in [36]. The current state of the art for LCC HVDC transmission is 6300 MW at a DC voltage of ±600 kV (Itaipu, Brazil) and the first commercial application of ±800 kV, 6400 MW will be the Shanghai-Xiangjiaba connection, scheduled to be in operation this year [37]. The Itaipu transmission is done with overhead lines and the transmission length is 807 km. The longest LCC HVDC transmission link is the Inga-Shaba link in Democratic Republic of Kongo. The longest LCC HVDC transmission on a submarine cable is the NorNed link from Norway to the Netherlands. The cable is 580 km long. The converters in a LCC transmission system utilize line commutated thyristor valves, normally connected in a 12 pulse bridge. These valves can be switched on by a control signal, and the current is extinguished by the AC system to which the converter is connected. The converters are also called Current Source Converters (CSC) since they operate with a controlled DC current and thus behave dynamically as a current source in the AC grid. Figure 4-5b) shows how an LCC scheme could be used for connection of an offshore wind power to the grid.
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Due to the line controlled commutation, the LCC is difficult to operate in a weak AC network. A synchronous voltage source is required for the commutation. The ratio between the short circuit power of the connection point and the power transferred on the HVDC link should be larger than 2 to avoid commutation failure [36]. This feature makes it difficult to use LCC for connection of wind power to the onshore grid. The LCC converter consumes reactive power, and hence a source of reactive power is necessary to operate the converter. In steady state operation the consumption of reactive power is about 60 % of the active power transferred on the DC link [36]. Converter operation generates harmonic current and voltages on the AC and DC side respectively, and hence harmonic filters are necessary. Normally the harmonic filters will also provide all reactive power needed. These filters are relatively large. A DC reactor contributes to smoothing the DC current. The transformer used for a 12 pulse bridge is normally a three winding “star-star-delta” configuration. Since the harmonic filters are placed in front of the transformer, a special transformer able to deal with both DC stress and harmonics must be used. The LCC converter operates with a DC current that does not change direction. In order to change the direction of the power flow of the system, the polarity of the voltage is reversed. The presence of space charges in XLPE insulation is problematic in relation to this necessary reversing of the polarity, causing that XLPE cables can not be used in LCC systems. Instead, mass impregnated cables must be used. Further details on cables can be found in section 0. An outline of a LCC converter station is shown in Figure 4-7.
Figure 4-7 HVDC with current source converters [37]. An outline of the NorNed link is shown in Figure 4-8.
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Figure 4-8 Simplified single line diagram for NorNed. (Source: ABB) The necessary filters, transformers and sources of reactive power to operate the LCC HVDC transmission make the size of the converter stations large. The size and weight in combination with the possible commutation problems makes LCC technology unsuited for connection of offshore wind power to the onshore grid. The technology will, however, be developed and used for large onshore transmissions of bulk power from remote areas to load centres and for connection of asynchronous AC networks. For these types of applications the technology provides efficient, reliable and cost effective power transmission [36]. VSC HVDC technology As opposed to the LCC technology, VSC HVDC is a relatively new technology, introduced in the late 1990s. Self-commutated converters have been known since motor control came into existence, but only in the 1990s the switching elements had sufficient rating to economically build high voltage valves. The first test installation for a VSC HVDC transmission was the 10 km long, 3 MW, ± 10 kV Hellsjön transmission in Sweden that was commissioned in March 1997 [38]. Up to date, a total of 5 HVDC links based on VSC technology are in operation. Estlink with a DC voltage of 150 kV and a capacity of 350 MW is seen as state-of-the-art, but the development is fast. The Caprivi link in Namibia, commissioned in 2009, will set a new record for the DC voltage with 350 kV [39]. All these installations are delivered by ABB. The 400 MW Trans Bay Cable project, in operation since 2010, is the first application of a VSC HVDC delivered by Siemens [37]. In addition to the direct links between different AC systems, mentioned above, there are also VSC HVDC installations to supply power to offshore petroleum installations. The 70 km long power supply system to Troll A, commissioned in 2005 was the first of these [40]. The voltage of the HVDC supply system is ± 60 kV, and the capacity is 84 MW. A power supply system for the Valhall field will be commissioned in 2010 [41]. The length of this supply system is 292 km, the DC voltage is 150 kV, and the capacity is 78 MW. In 2010 the first offshore wind farm, the Borkum 2 wind farm cluster, was put into operation[22, 33]. This is a 400 MW transmission with a DC voltage of ± 150 kV. The transmission distance is 200 km, where 125 km is at sea and 75 km onshore. The basis for the development of VSC HVDC was the introduction of the IGBT (integrated gate-commutated thyristor), a valve that can be switched both on and off by a control signal. The converters operate by controlling both the amplitude and phase angle of the voltages and thus behaving as voltage sources in the AC grid (hence the name voltage source converter). Figure 4-5c) shows how a VSC scheme can be used for connecting an offshore wind farm to the onshore grid. VSC converters do not consume reactive power and do not require a synchronous voltage source to operate, so can thus feed in to passive networks. The VSC converter can control the reactive power
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flow in addition to the active power and thus operate in all four quadrants. Control of active and reactive power can be done independently. Voltage stability in the grid is enhanced because of the reactive power control [37]. In the much more controllable VSC system, the reversal of power direction is done by reversing the current and not as in LCC systems, by reversing the voltage polarity. This feature allows for faster control of active power. It also allows for the use of XLPE cables rather than mass impregnated cables. A drawback of the VSC technology, compared to the LCC technology, is that the losses in the converter stations are larger, mainly due to higher switching frequency. The higher switching frequency on the other hand contributes to less harmonic distortion than for an LCC converter, and consequently the need for harmonic filters is reduced. The harmonic filters in a VSC system are connected between the transformer and the valves, shielding the transformer from the harmonic currents and DC voltages. Ordinary transformers can be used. Due to less auxiliary equipment like filters and shunt capacitors/statcom, the footprint of a VSC converter station is considerably smaller than that of a LCC converter station. This together with the other favourable properties makes VSC HVDC transmission suitable for connection of offshore wind farms to the onshore grid. A general outline of a VSC converter station is shown in Figure 4-9,
Figure 4-9 HVDC with voltage source converter (PWM type) [37]. There are (at least) two different types of VSC HVDC systems, supplied by ABB and Siemens respectively. The HVDC Light concept supplied by ABB uses high frequency pulse-width modulation (PWM) as a switching technique to control the magnitude and phase of the voltage. Deciding the switching frequency is a trade off between converter losses and filter requirements. A switching frequency between 1 and 2 kHz is used. The HVDC Light concept is illustrated in Figure 4-10.
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Figure 4-10 HVDC Light [37]. The HVDC Plus system supplied by Siemens uses a concept called modular multi level (MMC), which does not use PWM to produce a waveform, but builds the waveforms by discrete voltage steps. Switching losses and harmonics are expected to be lower [37]. The HVDC Plus concept is illustrated in Figure 4-11.
Figure 4-11 HVDC Plus [37]. T-connections Use of VSC HVDC technology when planning and development point-to-point bilateral cables can be consider when: i) the AC grid at both ends of the links is weak so LCC HVDC is not an option; ii) If a wind farms is to be developed nearby a bilateral cable line. The second case offers a very interesting connection solution in terms of so-called a T-connection, in which the wind-farm is connected to the cable in a 3-terminal configuration together with the bilateral link (see Figure 4-12 for an example). Such connections could provide the fist steps from a purely radial connection strategy towards a fully meshed offshore grid solution. A T-connection has two main advantages, namely: a) Savings in investment cost, since no extra cable for connection the wind farm to shore is needed, only a shorter cable between the wind farm and the link connection point (green square in Figure 4-12); b) Wind farm utilization is higher since the wind farm has two connections instead of only one if is connected only to shore. In the example of Figure 4-12, the wind power can be exported both to UK or/and to NO. Higher penetration of wind power in the power system will reduce total operational costs.
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Figure 4-12 Example of T-junction. Source: SINTEF Energy Research. As per today, bilateral cables are planned and developed, aiming to maximize the operation profit, e.g., an almost 100% utilization. This means that the flow is at maximum capacity in either one or other direction at all times. T-connection solution will reduce the utilization of the link compared to its utilization alone, due to the variable nature of wind production. However a T-junction will provide investment and operational savings with respect to the independent development of the link and the wind farm. Planning of T-connections should therefore involve coordination between link developers (typically TSO’s) and wind farm developers such us not only profitability of the link but profitability of the whole T-junction/link+wind farm is considered. New market designs will be needed to ensure that trading of power through the link and from the wind farm are bidden in the same market. Multi terminal HVDC The VSC HVDC technology looks promising in terms of possibilities for establishing multi-terminal solutions, but no such solution is in operation today. There are only two multi-terminal HVDC systems in operation today, both using the LCC technology. These are the Quebeck-New England transmission [42] and the Italy-Corsica-Sardinia transmission [43].
Figure 4-13 Sketch of a HVDC multi-terminal system. (Source ABB) A multi-terminal HVDC transmission is an HVDC system with more than two converter stations, (see Figure 4-13). Multi-terminal HVDC (MTDC) transmission is therefore more complex than ordinary point-to-point transmission. In particular, the control and protection solutions become more elaborate, as there is a need for coordinated control system that maintain security and stability of operation in a similar way as in interconnected AC grids. This may also require more telecommunication between the stations to ensure reliability both in steady-state as well as during dynamic performance.
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The VSC scheme is superior to the conventional thyristor-based LCC technology in terms of independent reactive power control, no need for external voltage source and fast system control (see also [44, 45]). Moreover for LCC, huge space demands are needed for the converter stations, while much smaller spaces are needed for installation of VSC converter offshore platforms. These aspects indicate that VSC based HVDC technology is better suited than LCC technology for remote offshore wind farm connections. DC systems based on point-to-point connection for integration of wind farms have been extensively studied. Also multi-terminal VSC based HVDC systems consisting of only one grid side have been studied recently (see [46, 47] and References therein). However, a general MTDC system would involve several VSC grid points, so control, operation and management of such multi-input system are significantly more complex. Control and protection methods have to be addressed carefully when going from the single “point-to-point” HVDC, into truly multi-terminal HVDC configurations like the one shown in Figure 4-14. A detailed discussion of development of control and protection for multi-terminal HVDC can be found in [44-46].
Figure 4-14 Example of a possible offshore MTDC [46] Cables The transmission of power from offshore wind farms to the onshore grid will be done by means of subsea cables whether the transmission is done by AC or by DC. There are different types of insulation systems for cables, each having their own characteristics and each being used for different types of transmission schemes. The main distinction in insulation system is between extruded polymer insulation (crosslinked polyethylene (XLPE) or ethylene propylene rubber (EPR)) and oil/paper insulation (mass impregnated cable (MIC) or self contained fluid filled cable (SCFF)). Figure 4-15 and Figure 4-16 illustrate the different types of insulation systems.
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Figure 4-15 Power cables with extruded polymer insulation [48].
a) Mass impregnated cable b) Self contained fluid filled cable Figure 4-16 Power cables with oil/paper insulation [48]. High voltage power cables with oil/paper insulation, already appeared in the beginning of the 1900’s, while cables with extruded polymer insulation were introduced in the 1970’s. Today the general picture is that extruded polymer insulation is preferred wherever it can be used, due to lower dielectric losses, lower weight, easier handling and jointing, and no environmental concerns due to leakage of oil. Most power cables with extruded insulation uses XLPE. In terms of electrical properties, XLPE is better than EPR, but EPR is sometimes chosen due to other favourable properties, for instance its good water resistance [48, 49]. In polymer insulation, space charges build up when used for DC transmission. This is problematic for LCC schemes, which use reversed polarity to change direction of the power flow. Therefore XLPE cables can not be used in LCC schemes. Mass impregnated cables are used for the large HVDC links, like NorNed. For VSC HVDC where the direction of the power flow is reversed by means of current reversal, XLPE cables can be used (see e.g. ABB HVDC Light cables [50]). There are three major suppliers of subsea cables: ABB, Nexans and Prysmian. Cables for AC transmission Cables for high voltage AC transmission are normally extruded XLPE cables, and they can be delivered either as three core cables or single core cables. In three core cables, the three cores, each having its separate insulation, are bundled together in one cable, while when using single core cables, three separate cables must be installed. Installation wise, it is easier to install one cable only and the three
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core design is favoured when possible. For the highest voltages, only single core cables are available. Single core and three core cables are illustrated in Figure 4-15. There is also a possibility to use oil/paper insulated cables for AC transmission. The conductor cross section in combination with its thermal limit set the maximum amount of power that can be transmitted through each power cable. A solution to this limitation will be to install more than one cable in parallel. Such an installation will be more expensive, but will give reliability gains because one cable can be operated during a fault of the other. Cables for DC transmission Oil/paper insulated cables are the only viable cables for LCC HVDC transmission, and usually mass impregnated cables are used. A mass impregnated cable is illustrated in Figure 4-16 a). These systems are used for interconnections between two power systems and for transport of bulk power over long distances. For VSC HVDC transmission the normal choice is extruded polymer insulated cables. The VSC scheme is used both for links between different power systems and for connection of wind farms. In 2010, the first wind farm connected to shore via HVDC transmission, Borkum 2 in northern Germany, will be commissioned. Losses for HVAC, LCC HVDC and VSC HVDC Offshore wind farms will become larger with time (i.e. increased installed capacity and voltage rates) and most likely be located further away from shore, where the best wind conditions occur. Evaluation of the corresponding increase in transmission losses is critical. In Ref. [51], detailed evaluation of HVAC and HVDC transmission losses for large offshore wind farms was done. Some of the results of [51] are shown in Figure 4-17 (grey areas show the solution giving lower losses for each case):
Figure 4-17 Losses for HVAC and HVDC (LCC and VSC) [51]
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In general, HVAC solution is found to give the lowest losses for distances up to 55-70 km from shore. For larger distances (> 70 km), HVDC LCC was found to give lower losses than VSC HVDC. Although LCC seems better than VSC from a “losses-point-of-view”, many other aspects are likely to influence the final choice of design, such as number of cables, reliability, lifetime costs and grid integration potential [51]. Offshore Transformers / Conversion stations Offshore wind farms can be built with or without an offshore transformer station/substation. The wind farms that are built without an offshore transformer station are typically situated less than 10 km from shore and have a limited power, typically less than 200 MW. The largest existing offshore wind farm with export cables on the same level as the collection cables is Lynn & Inner Dowsing (UK) with a maximum power of 194 MW. This wind farm is situated only 5.5 km from shore [52]. For larger distances and powers, an offshore transformer station containing a step up transformer is used. For the longest distances and powers, HVDC is considered, as e.g. in the Borkum 2 wind farm cluster [53]. The main electrical components present are a medium voltage (MV) switchgear, the main transformer, disconnectors for the high voltage (HV) side and equipment for reactive compensation. The equipment that is used in offshore transformer stations is not particularly special and rather standard electrical components are used. However, the conditions under which the equipment is used gives rise to layout and maintenance challenges for the transformer station as a whole. To date, all offshore transformer stations have only one transformer although there have been discussions about reliability when all the energy from a wind farm passes through one single component. For AC solutions, the role of the AC transformer station is to step up the voltage from the collection voltage to a suitable transmission voltage in order to reduce losses in transmission. The transformer station is a separate platform, which in itself is a quite complex construction. It can also fulfil other roles than just the electrical step up of voltage, like staff and service facilities, e.g. accommodate people in a living quarter, storage for spare parts for the wind turbines etc. In addition to the main electrical system, there will be need for auxiliary power to supply the transformer station itself and the facilities it hosts. For security, an emergency generator is situated on the platform. This emergency generator can also supply power to control systems and other functions that need power during a possible fault that will result in disconnection of the wind farm/transformer station. The only DC existing solution planned for collection of power from offshore wind farms and connection to shore is the E.ON1/Borkum 2 system commissioned in 2010. An outline of the system is shown in Figure 4-18.
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Figure 4-18 Outline of the E.ON1 HVDC connection of offshore wind farms [54] In this system, the AC step up transformer station for each wind farm is of the same type as the offshore transformer station used for direct AC transmission to shore. The HVAC transmission is used to reach a separate AC/DC converter platform from which the power is connected to shore through a DC link. The converter platform hosts the AC to DC converter with necessary equipment.
Appendix E: Offshore grid integration: State-of-the-art The text in this appendix in mainly taken from [29]. There are key challenges related to how the future power markets should be developed to ensure that official targets for wind energy can be achieved. In response to these challenges, the transmission system operators (TSOs) have developed grid codes that specify new requirements on wind farm controllability and ability to provide system (ancillary) services. Significant R&D work is being performed with a focus on technology development and wind farm modelling for power system studies [7]. There are still remaining challenges related to implementation and verification of models and control solutions, as well as on how to enforce and interpret the grid codes to ensure a socio-economic cost effective integration of wind farms. Simulation tools that correctly combine both market details about production, demand and power exchange transactions as well as power system details regarding grid capabilities and power flow bottlenecks are essential when investigating the impact of integrating wind power in the power system. The market determines the power exchanges that match demand and production but the flow of power ultimately occurs through the lines and cables of the physical grid. Interplay between market and grid dynamics is especially important for high penetration levels of wind power, as wind power has zero “fuel” cost but at the same time brings more variability and uncertainty into the power system operation. In the European R&D project TradeWind [55], a model of the European power system was established and hour-by-hour simulations were run for scenarios until year 2030,
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in order to investigate how large amounts of wind power may affect the power system operation. Emphasis was on market design and need for new transmission [55]. Offshore Wind Scenarios Concerning the integration of offshore wind energy into the power system, the approaches can be classified according to two different strategies:
• Point-to-point connection between the offshore wind farm and the onshore grid (radial grid) • Connection of wind farms into an offshore meshed grid (offshore grid)
In short, the radial grid strategy is motivated by a case-by-case cost-saving approach, while the offshore grid strategy is motivated from system-wide cost and security point of view. A meshed grid adds flexibility and can serve multiple purposes. In addition to bringing power from the offshore wind farms to shore, it can also be used as an inter-area connection to support power system balancing or inter-area trade. These possibilities are relevant e.g. for the proposed Kriegers Flag wind farm cluster. Trans-national offshore grid Different concepts for linking offshore wind farms and subsea interconnectors to form an offshore grid have been proposed in several studies and projects, see e.g. OffshoreGrid [56], Airtricity [57], EuropaGrid [58], Greenpeace [59], Statnett [60, 61]. One example of a trans-national sub-sea connection scheme for offshore wind farms in Europe has been proposed by the renewable energy company Airtricity (see Figure 4-19). The proposed concept is called Supergrid and is intended to stretch from the Baltic Sea to the Bay of Biscay and on to the Mediterranean Sea, giving a considerable smoothing effect from wind power fluctuations. The grid is planned to be made up of both high voltage AC and DC cables (both sub-sea and land) as well as onshore and offshore voltage source HVDC converter stations [57]. An advantage of a common offshore grid is that the utilisation of the grid capacity can be increased considerably compared to single (radial) wind farm connections to shore (an increase from 40 % to 70 % utilisation is indicated). Another vision of an offshore grid is Imera’s EuropaGrid proposal shown in Figure 4-20.
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Figure 4-19 Airtricity’s Supergrid proposal [57] Figure 4-20 Imera’s EuropaGrid proposal [58] Statnett’s proposal for an offshore grid in the North Sea is shown in Figure 4-21.
Figure 4-21 Statnett’s North Sea Offshore Grid [1]) Based on the 2030 scenarios from TradeWind [55], a recent analysis of offshore grid alternatives for North Sea offshore wind farms has been conducted by SINTEF Energy Research [28]. In this study, a
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comparison of the total investment and operational costs between the offshore grid and the radial grid shown in Figure 4-22 and Figure 4-23 respectively has been carried out. The red nodes and lines represent the AC grid and the white lines HVDC cables. For a year 2030 medium wind scenario of the TradeWind European grid model (302 GW wind power, both onshore and offshore), the socio-economic benefit of the offshore grid was found to be about 2.6 Billion € higher than for the radial grid. Although the simulation case study indicated significant added value of the offshore grid structure with respect to the total power system cost and performance, further studies in this direction are needed in order to establish sound strategies for (step-wise) development of offshore grids.
Figure 4-22 Offshore grid: medium wind scenario, 2030 [28]
Figure 4-23 Radial grid: medium wind scenario, 2030 [28] Very large investments are needed for both offshore and radial grid expansion strategies shown in the above examples, so it is important to evaluate which strategy is the best both from a socio-economical and security-of-supply points of view. On the other hand, grid expansion will occur in steps rather than at once, so it seems reasonable that the actual development will be a combination of both strategies. Point-to-point connections could be first developed with one or more offshore
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nodes. Those can then be used for connecting other cables e.g. from wind farms developed at later stages, gradually making up a meshed offshore grid. According to Statnett’s 2009 assessment of a future offshore grid outside Norway [61], a development based on VSC HVDC technology will be technically possible in the southern North Sea with the same voltage levels for the various TSOs. The development is likely to be made in steps, potentially starting with a submarine power cable link between Norway and the UK. A sketch of the offshore grid envisaged by Statnett is shown in Figure 4-24.
HVDCAC
Oljeinstallasjon
Vindkraftpark
(a) (b)
Figure 4-24 Statnett’s potential future Norwegian offshore grid (Statnett)[14] A recent study from the EU-IEE project OffshoreGrid finds that radial connections make sense up to 50 km distance from their connection onshore. For larger distances, 50-150 km, the density of wind farms largely determines the benefits of clustering and for distances larger than 150 km, offshore grid nodes-hubs making up the meshed grid are considered as typical solutions. Figure 4-25 shows a possible grid concept for the North Sea and the Baltic Sea. Existing lines (red), planned lines (green), commissioned lines (pink) and additional transmission lines (blue) are shown according to the EU-IEE Offshore Grid project study [13].
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Figure 4-25 Possible offshore grid for the North Sea and Baltic sea [13] EWEA has recently published its Offshore Network Development Master Plan[6] (see Figure 4-26).
Figure 4-26 EWEA Offshore Network Development Master Plan [6]
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Appendix F: Power market and System operation The text in this appendix in mainly taken from [62]. Variations in load and wind power differ in period (time) and amplitude (MW), as shown in Figure 4-27. The power system grid of the area where wind production and demand are given as shown in Figure 4-27, will see an aggregate net imbalance resulting from both load and wind power variations. All other generating units, except the wind generators (and other non-flexible generators such as PV and run-of-river hydro), will be subjected to a positive load from the real demand and to a “negative”, but strongly varying load from the wind power generation.
a) b)
Figure 4-27 Net Load = Load – Wind. See [63] for details. Scheduling and dispatch of power plants is usually done according to the load forecast, one day-ahead. Operational reserves are used to balance the load forecast errors caused by the variable and uncertain nature of the load/demand profile. Wind power increased variability and uncertainty (Figure 4-27) therefore increase the forecast errors, as not only demand, but also some part of generation, is now variable and difficult to predict beforehand. Wind power variations and uncertainty must be incorporated to load variations and uncertainty when it comes to allocation and activation of operational reserves. The relevant load-following scheme for increased wind power presence in the power system should be based on the concept of Net – Load = Load – Wind. The need for additional reserve requirements depend heavily on the planning horizon (day-ahead or intra-day trading) and wind power penetration level. As an example, for 10 min – 1 hour ahead forecasts (intra-day forecast), the additional reserve capacity needed is only a few percent (1 – 3 %) of the installed wind capacity, depending on wind penetration level whereas for 12– 36 hours ahead forecasts (day-ahead forecast), the additional reserve capacity needed on average is roughly 10 % of the installed wind capacity [63]. Wind power production is characterised by variations on all times scales, so allocation of reserves to balance wind necessarily becomes a dynamical operational process. Reliable methods for reducing wind forecast uncertainty became essential for system operation when balancing wind power. A “state-of-the-art” example of dynamical reserve allocation is the so-called “Day-ahead technical constraint management” method, used by one of the TSOs of ENTSO-E [64]. Probabilistic wind forecast with different confidence intervals are used in order to estimate the amounts of additional reserves needed. Design of future balancing power markets should take into account dynamic allocation of flexible amounts of reserve capacity, depending on installed wind and wind penetration
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level and intra-day trading possibilities which will reduce the size of the additional reserve capacity needed. Flexible generation is very important when dealing with dynamic allocation of reserve capacity. As per today, flexible Combined Cycle Gas Turbines (CCGT) and hydro power, e.g. from Norway and the Alps, seem the best candidates for large scale balancing of variable wind generation in Northern Continental Europe, the North Sea and UK. The use of hydro power from the Nordic region as balancing power for continental Europe and the UK implies e.g. the increase in the number of interconnectors between the Nordic region and both Continental Europe and the UK. These prospects raise many questions. Some examples are grid investments, increased pumped storage capacity, new market design, reservation of capacity on HVDC links for spot market trade or trade of balancing power, dedicated usage of hydro units beyond the standard scheduling and dispatch in the market today, quality of frequency, improved control strategies, etc… [65]. Under storm conditions, each turbine in a wind power plant will suddenly stop when it experiences wind speeds that exceed their storm control shut down threshold (~25 m/s) and as a result the wind farm gradually stops its production. As wind penetration levels are expected to increase in the future, the power system will be exposed to higher levels of variable and unpredictable generation. An interesting question is whether the existing balancing capabilities and market designs available at present will be able to account for the large imbalance expected if a big storm passes across the North Sea when offshore wind power on the order of 100 GW is installed. Improved storm control and storm forecasting might be needed in a power system with large shares of wind power [66] . Grid codes Grid codes basically contain the rules for connecting generators to the grid. They are typically developed by the Transmission System Operator (TSO) to facilitate rules fitted to system needs; hence they may vary in items covered, level of detail and requirements to generator technology. Detailed requirements to wind power technology are a fairly new addition to grid codes, reflecting that wind farms until the end of the nineties were generally relatively small and had little impact on the system operation. The large wind farms being built and operated today may however have a significant impact, thus it is increasingly important to include requirements for these types of large farms in the grid codes. National grid codes vary from country to country, although EWEA has launched a working group aiming for harmonization of European grid codes for wind farms [67]. At the moment, the discussion focuses on establishing the concept of “structural harmonization”. The basic idea behind the structural harmonization is to establish a generic code format where the structure, designations, figures, method of specification, definitions and units are fixed and agreed upon. No harmonization of the numerical values of the various parameters is intended. Instead, the different national parameter-requirements are expected to fit naturally into the generic code. A more technical discussion on how to fulfil such harmonization is expected to follow gradually once the concept of harmonization has been established. EWEA’s recommendations are not specific for offshore wind farms but rather general for any type of wind farm. However, these recommendations are based on the technological situation at present, which in practice means, on- or offshore wind farms connected to an AC grid. Different sets of grid code requirements may be relevant for offshore wind farms connected to an HVDC grid, hence R&D
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work is required to address this topic. It is not obvious that the same requirements shall apply for on- and offshore wind farms connected to a HVAC grid and offshore wind farms connected to a HVDC grid. It is also important to distinguish grid code requirements and system operation. For example, grid codes might state that wind farms shall be able to operate at a limited power output. This is however not the same as saying that the wind farm will have to actually operate in this way at all times. Offshore grids are technically feasible but very demanding. They are a rather complex in structure with many countries involved. In this sense and offshore TSO must be nominated, such as offshore grid codes could be developed in a high level, coordinated fashion.
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