Offshore Wind Technology Catalogue

OFFSHORE WIND TECHNOLOGY CATALOGUE

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From: BLIX Consultancy BV

Reference: Offshore wind technology catalogue

To: Elering AS and AS "Augstsprieguma Tīkls"

Authors: BLIX Consultancy: A. Alves da Silva , J. Godtschalk , T. Drummen

Enersynt: P. van Leest

Checked: I. Maassen van den Brink

Version: Final

Date: December 15th, 2021

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Contents EXECUTIVE SUMMARY 6

ACRONYM LIST 7

1 INTRODUCTION 9

2 ASSUMPTIONS 10

3 OFFSHORE SUBSTRUCTURES 11

3.1 WTG Foundations 11

3.1.1 Description 11

3.1.2 Technical Information 12

3.1.2.1 Monopile Substructures 13

3.1.2.2 Jacket Structures (3 or 4 Legged Substructures) 14

3.1.2.3 Gravity Base Structure 15

3.1.3 Costs 16

3.2 Offshore Substations Foundation 17

4 WIND TURBINES 18

4.1 Description 18

4.2 Technical Information 19

4.3 Wind Farm Power Density 21

4.4 Costs 22

4.5 Lifetime 22

4.6 Availability 23

4.7 WTG Catalogue 24

5 OFFSHORE GRID CONNECTION SYSTEMS 25

6 AC TECHNOLOGY 26

6.1 HVAC Offshore Substation 26

6.1.1 Description 26

6.1.2 Technical information 26

6.1.3 SLD 28

6.1.4 Costs 28

6.1.5 Lifetime 29

6.1.6 Availability 30

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6.1.7 Losses 30

6.2 AC cables 31

6.2.1 Description 31

6.2.2 Export cables 31

6.2.2.1 Technical information 31

6.2.2.2 Installation 34

6.2.2.3 Costs 34

6.2.2.4 Lifetime 36

6.2.2.5 Availability 36

6.2.2.6 Losses 36

6.2.3 Inter array cables 37

6.2.3.1 Technical information 37

6.2.3.2 Installation 38

6.2.3.3 Costs 38

6.2.3.4 Lifetime 39

6.2.3.5 Availability 39

6.2.3.6 Losses 40

6.3 Reactive Compensation 41

6.3.1 Technical information 41

6.3.2 Costs 42

6.3.3 Losses AC versus DC 42

6.4 Onshore HVAC Land Stations 43

7 DC TECHNOLOGY 44

7.1 Basic Components of DC Connections 44

7.1.1 SLD 46

7.2 HVDC Offshore Substation 47

7.2.1 Description 47

7.2.2 Technical information 47

7.2.3 SLD 49

7.2.4 Costs 50

7.2.5 Lifetime 51

7.2.6 Availability 51

7.2.7 Losses 52

7.2.8 DC Offshore Substation in Meshed Grids 52

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7.3 HVDC Land Station 54

7.3.1 Description 54

7.3.2 Costs 54

7.3.3 Lifetime 55

7.3.4 Availability 55

7.4 HVDC Cables 55

7.4.1 Description 55

7.4.2 Technical Information 57

7.4.3 Installation 58

7.4.4 Costs 58

7.4.6 Lifetime 59

7.4.7 Availability 59

7.4.8 Losses 59

8 DECOMMISSIONING 60

9 EXAMPLE GRID CONNECTION 61

10 ANNEXES 63

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EXECUTIVE SUMMARY BLIX Consultancy has the pleasure of presenting the Offshore Technology Catalogue. This catalogue will provide Elering/AST with the necessary information to get an insight in the current technologies that are on the market for offshore wind developments.

Overall, the outcome of compiling this catalogue is, that the nature of offshore wind technologies has evolved – and continues to evolve - at a rapid pace and that the offshore wind business has matured over the recent years. The catalogue goes into detail about the different types of foundations, wind turbine generators, substations and transmission cables. The grid connection system is the main focus of the catalogue and comparisons are made between AC and DC systems. BLIX has provided up-to-date market information on availability, reliability and – where possible - prices.

At the end a top level assessment is made of a specific connection for both technologies. In general it is stated that above 1GW and more than 100km the DC option would be preferred, as this should also consider the difference in losses during lifetime when corrected for the different power bins (wind profile) of the offshore wind farm.

Important to note in this document, is that assumptions had to be made on which the data had to be based. The assumptions are very general in nature and therefore should be considered as such. When using the catalogue, it is important that the user should always be aware of these restrictions and how they apply to the catalogue item.

Another important note to the use of this catalogue is, that during the compilation of the data, it became very clear during our research, that a lot of items and more specifically prices are site specific. This means that there are so many variables in designing, delivering or installing certain items that, without site specific detailed data, it is very difficult to obtain 100% accuracy. When compiling this catalogue, we used a lot of general available data which may lack detailed information.

Overall, we are confident that the quality of this catalogue will provide a very good, detailed, assessment of the main components for the development of an offshore wind farm in the Baltic Sea.

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ACRONYM LIST AC – Alternating current

ALU – Aluminium

BE - Belgium

BOP – balance of plant

CAPEX – Capital Expenditure

CTV – crew transfer vessel

DAS – Distributed Acoustic Sensing

DC – Direct current

DE - Germany

DK - Denmark

DOL – Depth of Burial

DTS – Distributed Temperature System

EMTP – Electro Magnetic Transient Program

EU – European union

EXC – Export cable

FAT – Factory Acceptance Test

FO - fibre optic

GB – Gravity base

GBS – Gravity base structure

HVAC – High voltage alternating current

HVDC - High Voltage Direct Current

IAC – inter array cable

IEC – International Electrotechnical Commission

LCoE – Levelised cost of energy

LFAC – Low Frequency Alternating Current

m – meter

MV - Mega Volt

MW – Megawatts

MVA – Mega Volt Ampere

NL - Netherlands

O&M – operations & maintenance

OEM – original equipment manufacturer

ONAF – Oil Natural Air Forced

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ONAN – Oil Natural Air Natural

OPEX – Operational Expenditure

OSS – offshore substation

OWF – offshore wind farm

OWF – offshore windfarm

PSCAD – Type of SW package for EMTP simulations

PQ – Power Quality

RFQ – Request for Quotations

SAT – Site acceptance test

SCADA - Supervisory Control and Data Acquisition

SE - Sweden

SOV – service operation vessel

TIV – Transport installation vessel

TP – Transition piece

TRL – Technology readiness level

TSO – Transmission system operator

UK – United Kingdom

WTG – wind turbine generator

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1 INTRODUCTION

BLIX Consultancy & partners were contracted by the Estonian and Latvian TSO’s, Elering and AST, to create an offshore wind technology catalogue. This catalogue details all the technologies used in an offshore wind farm and grid connection system. General and technical details for each technology are explained, highlighting the various factors that dictate the design, cost and lifetime of a wind farm. Important factors include but are not limited to; wind farm capacity, distance to shore, water depth, seabed conditions and onshore grid connection.

Only technologies with a TRL greater than 5 have been considered. BLIX has provided costs for all the technologies however it should be noted that these costs are best estimates of the current market based on our experience and public literature. Prices will vary depending on site and project specifics.

The report is split into individual sections for each technology. Chapter 3 covers offshore substructures for both WTG’s and platforms. It describes the various fixed bottom foundations used in water depths of up to 50m focussing on monopiles and jacket foundations.

Chapter 4 covers WTG’s, looking at; the basics design, current and future outlook for size and capacity, considerations for wind farm density and end of life. Chapters 5-7 cover the grid connection system. It splits the technologies into two categories, AC and DC. Within each category the offshore platform, onshore land station and transmission cables are discussed. These sections go into detail about the various configurations, topologies and redundancies that are used in the market and their associated losses. For AC, there is a section detailing reactive power compensation considerations that are required for longer cable distances. In the cable sections the voltage, cross section, and conductive materials used are compared.

Chapter 8 briefly describes decommissioning of an offshore wind farm and grid connection system. Discussing the cost and considerations required to ensure marine users and the environment are not severely impacted by these activities. Chapter 9 provides a qualitative comparison of both AC and DC technology. For comparison purposes an example for a specific 1GW connection, 50km from shore is assessed using both technologies.

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2 ASSUMPTIONS

Parameter Assumed for catalogue Comments

Water depth < 50 meter

Ice conditions Considered Ice conditions come in various forms. Per item it is explained what has been considered and what not.

Soil conditions Sandy soils A change in soil can have a major impact on the foundation design.

Seabed currents Very low currents Consequently, low seabed mobility (sand dunes) have been assumed.

Seabed currents is an important parameter for scour protection and/or subsea cable design.

Earthquakes Not assumed If these need to be considered, a Seismic Hazard Analysis (SHA) will need to be performed in order to

Waves Typical UK Sector North Sea conditions

Max wave heights (HMax) in the North Sea can go up to 10m (or more during a bad storm). Meaning a Significant wave height (Hs) of around 5- 6m.

Tides Small tides (<0.5m) have been assumed

Other assumptions for foundation section

1. Total windfarm size: 1000MW

2. Water depth: 30m 3. Turbine: 10MW 4. Location: North Sea –

UK Sector 5. Weight of foundation

assumed 800 ton

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3 OFFSHORE SUBSTRUCTURES

3.1 WTG Foundations

3.1.1 Description

The primary function of a foundation of any structure is to transfer applied loads to the sub- bottom. The main loads that act on an offshore structure are wind, waves, currents and the ‘self- weight’ of the structure. Examples of other loads and actions that can occur in different offshore environments around the world are ice loads, earthquakes, typhoons and ship impact.

Offshore foundation types are particularly driven by:

• Water depth; • Ground conditions; • Loads (magnitude).

In offshore wind, a discrepancy is made between floating and bottom-fixed foundations. Only bottom-fixed foundations will be discussed here, considering the shallow water depths (up to ~50 m) in the area of interest.

In the table below the word “rock” is sometimes used when discussing the foundations. It should be noted that “rock” is geological term that is used to describe a naturally occurring solid mass of minerals. Rock can occur in various degrees of hardness, from very hard (granite) to weaker types (certain types of limestone or sandstone). For foundation design, encountering rock is generally not a good thing. When being hammered, rock will either resist the piling (so that drilling is required) or will break up, making it useless for foundation design, since the soil is unable to deal with the forces on the foundation. The General soil strength can be described as follows:

Type of Soil Strength of Soil Elastic Modulus, E (Mpa) Fine sand Loose 5-10

Medium 10-25 Dense 25-50

Silt Soft <10 Stiff 10-20 Hard >20

Clay Very soft <3 Soft 2-7 Firm 5-12 Stiff 10-25 Very stiff 20-50 Hard 40-80

Table 1 - Typical elasticity modulus (ES) values for different soil types1

1 Handbook of Geotechnical Investigation and Design Tables - Burt G.Look (2007)

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The following section considers the most common bottom-fixed foundation structures in the offshore wind industry. Other foundation types such as mono buckets, tripods (currently 126 operational, but ran out of fashion for larger turbines), twisted jackets have not been applied in commercial offshore wind farms and are therefore considered to be of less importance for this exercise.

Below tables also show installation options. It is noted here however, that no limitations have been assumed. For piling operations, noise mitigation measures might be required, such as bubble screens (single of double).

3.1.2 Technical Information

Foundation size (diameters/lengths) depends mainly on ground and loading conditions on the substructure.

An important parameter to keep in mind is steel quality. Especially for icy conditions, high grade steel might be required to deal with the low temperatures. Should there be permanent ice during winter, then the foundations need to be designed as such to be able to withstand the ice loadings. According to DNV rules DNVGL-OS-C101, ice loadings are depending on multiple factors:

• geometry and nature of the ice • mechanical properties of the ice • velocity and direction of the ice • geometry and size of the ice and structure contact area • ice failure mode as a function of the structure geometry • environmental forces available to drive the ice

In order to make a proper assessment of the ice loadings, before the development stage of the project, as much as possible information should be collected on ice conditions. These conditions can be collected via a desktop study, via publicly available data bases or via meetings with knowledge institutes or other parties that have knowledge about ice and ice loadings.

Ultimately, the ice loadings can also be tested in a laboratory via simulations, for example in Hamburg (Germany)2

The ice loadings shall then be incorporated into the design of the foundation according to the applicable codes and standards.

So for the purpose of the catalogue, in these very early stages it’s very difficult to assess the exact impact of ice loadings on the substructure.

2 https://www.hsva.de/expertise/safety/safety-in-cold-regions.html

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3.1.2.1 Monopile Substructures

General The monopile foundation consists of one circular open-ended steel pile that, after installation will be partly in the ground, partly in the water column and partly above water level. A transition piece will be installed afterwards, on which the WTG tower will be mounted.

Dimensions - Diameter up to ~9 m - Length ~30 m to ~80 m - Wall thickness ~50 mm to ~120 mm - Diameter could go up to 12 m and more

Weight - ~800 t to ~1900 t (in air) - Will increase with increasing diameters - Note: the latest monopile for Arcadis Ost 1

OWF in the Baltic was 2000t at 40m water depth

Applicable water depth - < ~40 m - Could be stretched with increasing

diameters Applicable ground conditions - Soft ground conditions (clay, sand and silt

or alternations thereof) - Difficult to apply in rock

Fabrication methodology Steel plates, rolled to circular elements that are welded together

Transport and installation methodology - (Generally) transported in horizontal position on a transport installation vessel (TIV) or barge

- Up-ended and lifted at WTG location and installed with a driving hammer

- Transition piece (TP) is installed afterwards - Vibratory hammers are available, but not

common yet - (Pre-)drilling is possible in hard ground

conditions (but expensive) - TP-less monopiles are becoming more

common Pro’s - Well known and proven technology with a

market share of about 75% in Europe - ‘Simple’ fabrication, welding can be done

automatically - EU fabricators (e.g. SIF and EEW) are

specialists and can produce ~4 to ~5 monopiles/week

Con’s - Driving hammer generates a lot of noise - Lean process does not create much local

content (if applicable)

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- Decommissioning is currently considered to be difficult

Project examples: Deutsche Bucht (DE), Arcadis Ost (DE), Borssele OWF Zone (NL), Hollandse Kust Zuid (NL), about any OWF in Europe

Applicability for Estonian/Latvian projects - Very good, considering the shallow water depths

- Not so good, considering hard ground (rock) conditions at some locations(1)

(1) Based on high level general geological maps

3.1.2.2 Jacket Structures (3 or 4 Legged Substructures)

General Jackets are braced steel structures that are commonly applied in the oil & gas industry. The braced structure will be present in the water column, and above water level. The WTG tower is directly connected (integrated TP). Loads are transferred to the ground with piles or suction buckets. Piles can be installed prior or after jacket installation. For WTG support jackets typically have 3 or 4 legs.

Dimensions - Footprint at seafloor 25x25 m2 to 50x50 m2 (depending on water depth)

- Height 80 m to 120 m, but higher is possible

- Oil & gas jackets up to 500 m Weight - 600 t to 2,000 t (in air), but larger is

possible Applicable water depth - Between 60 m and 100 m, although

larger depths are possible. - Jackets might be used in shallower

water depths as well. However this might economically less viable.

Applicable ground conditions - Depends on foundation system (piles or suction buckets)

- Soft ground conditions (clay, sand and silt or alternations thereof) for piles

- Soft ground conditions (clean clay or sand) for suction buckets

- Difficult to apply in rock (impossible for suction buckets)

Fabrication methodology Tubular braces welded together in a flat position and up-ended and connected together. Fabrication of piles and suction buckets (more or less) similar to monopiles

Transport and installation methodology - (Generally) transported in vertical position on a TIV or barge

- Lifted from vessel/barge to WTG location

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- Piles installed before or after jacket installation. Piles installed with driving hammer (or with vibratory hammer)

- Suction bucket installation while lowering the jacket to the seafloor

- Large jackets can be launched Pro’s - Many (former oil & gas) construction yards

can fabricate jackets - Proven technology - Applicable for high loads and large water

depths - Labour intensive, which is favourable for

local content - Suction bucket jackets can be fully

decommissioned Con’s - Labour intensive

- Heavy structures require largest available installation vessels

- Driving hammer for piles generates a lot of noise (can be mitigated by suction buckets)

Project examples: Wikinger (DE), East Anglia (UK), Seagreen (UK) Applicability for Estonian/Latvian projects - Not so good, considering the shallow water

depths. Cost/benefit decision (1) Based on high level general geological maps

3.1.2.3 Gravity Base Structure

General Gravity base structures is a collective name for heavy foundations that transfer loads from the top structure to the sub-bottom, based on gravity. Commonly, they are concrete structures that are ballasted after set-down on the seafloor.

Dimensions - Footprint at seafloor 25 to 35 m diameter for

- Height up to 40 m, but higher is possible - Oil & gas jackets up to 350 m

Weight - 2,000 t to 5,000 t (for up to 6 MW turbine) - Note that 6MW is the maximum known

turbine size to date that is known to be installed on a gravity base.

Applicable water depth Up to 30 m, although larger depths are possible

Applicable ground conditions - Strong grounds, e.g. dense/very dense sands or rock

- Not applicable on soft soil, e.g. clay Fabrication methodology Constructed with reinforced concrete in

formwork

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Transport and installation methodology - Seabed needs to be levelized prior to GBS installation

- GBS is towed to the site and ballasted in a controlled way to lower the structure to the seabed

Pro’s - Applicable for hard ground conditions - Can be towed to site, no need for large

installation vessels - Possible to fabricate locally, since concrete

is a common material for structures and infrastructure

Con’s - Structures require a lot of space - Difficult for serial production - No track record for larger turbines - Difficult (impossible?) to decommission - Concrete is not very environmental

friendly Project examples: Thornton bank Phase 1 (BE), Avedfre Holme

(DK), Kårehamn (SE), generally small turbines < 5MW

Applicability for Estonian/Latvian projects - Potentially good, considering hard ground (rock) conditions at some locations(1)

(1) Based on high level general geological maps

3.1.3 Costs

3.1.3.1 CAPEX

Main costs are driven by steel grade and weight. The standard EU steel grade is S355, but the steel grade that needs to be used, as mentioned, depends on the actual site conditions and loads. As with all commodities, steel prices may vary heavily over time, so may prove to be difficult to provide an accurate cost estimate per foundation type that might be valid over a long period of time. Also the steel will need to be rolled, processed and shaped in the required foundation (jacket, monopile). Consequently, we provide ball park figures and our assumptions are given below:

1. Total windfarm size: 1000MW 2. Water depth: 30m 3. Soil: sandy soils 4. Turbine: 10MW 5. Location: North Sea – UK Sector 6. Weight of foundation assumed 800 ton

Turbine foundation part

Cost (in Euro/MW) Weaker soils Stiffer soils (clay)

Foundation (monopile) 335.000 Diameter increase  price increase

Diameter decrease  price decrease

Transition piece 120.000 Diameter increase  price increase

Diameter decrease -> price decrease

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Corrosion protection 24.000 Diameter increase  more protection  price increase

Diameter decrease –> price decrease

Scour protection 12.000 Higher chance of scour  price increase

Best case scour protection is not required.

Source: Catapult Offshore Renewable Energy – BVG Associates3

In addition to steel prices, the costs of foundations are also driven by transport and installation costs. Since these are large structures transport costs can be serious. However, if they are produced locally, it might be more cost effective.

Item Cost (euro/MW)

Foundation installation 100.000

Offshore transport 3.500

Source: Catapult Offshore Renewable Energy – BVG Associates

Although included already in the above foundation installation cost, it is worthwhile to mention that the day rate of a suitable installation vessel is approximately 300.000 euro a day.

For Gravity based structures, the cost estimate is very difficult to estimate. The first important factor is the levelness of the seabed. If the seabed is unsuitable to directly install a GB, there is the possibility that dredging work will need to be undertaking in order to prepare the seabed. Other factors are the same as per monopile or jacket foundations: soil, waves, ice loading, turbine size and seabed currents. Since the GB is standing “loose” on the seabed, a detailed study of the seabed currents is important. High currents potentially can lead to the seabed being “washed away” underneath the GBS, leading to instability of the WTG. Given the above, unfortunately, a price per MW is very difficult to provide.

3.1.3.2 OPEX

For all types of foundations, the OPEX are generally not very high. Making sure that the corrosion protection and the scour protection measures are still sufficient are the main OPEX drivers, together with the regular inspections of the substructures. The biggest cost driver here will be a service vessel that will need to go out and inspect foundations. Day rates for such vessels easily reach 100.000 euro per day (depending on the size & scope of the inspection). For small inspection work, cheaper vessels can be hired.

3.2 Offshore Substations Foundation

For foundations for the offshore substations, in principle the same applies as per the previous discussion of the WTG foundations. Note that for substations the monopile is not considered a viable option, since this is typically for WTG only.

3 https://guidetoanoffshorewindfarm.com/wind-farm-costs

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4 WIND TURBINES

4.1 Description

Wind turbine technology is constantly improving as OEM’s battle for the title of who has the largest turbine. The race for who has the largest turbine has led to an offshore dominance of three manufactures; Siemens Gamesa, Vestas and GE.

The wind energy industry has seen a development unlike any other in the past 40 years. It has gone from 75kW machines with a tip height of 40m in the 1980’s to recently announced turbines of 15MW that nearly rival the height of the Eiffel tower. The 15MW turbines are due for serial production by 2024 and in the future this could increase to 20MW by 2030.

Figure 1 - Wind turbine power and size evolution over time4

Figure 2 - Global offshore wind growth outlook to 20305

4 Pisanò, Federico. (2019). Input of advanced geotechnical modelling to the design of offshore wind turbine foundations

5 https://gwec.net/global-offshore-wind-report-2021/

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GWEC expects a total installed offshore wind capacity of 270 GW by 2030. It expects high compound annual growth rate of 30% towards 2025, with a slow down to 12.7 until the end of the decade. Promising outlook for offshore wind installation, because:

– Globally high ambition levels by governments

– LCoE keeps decreasing (competitive energy resource)

– Commercialisation and industrialisation of floating wind

4.2 Technical Information

Wind turbines extract energy by slowing down the wind. Albert Betz concluded that a wind turbine can only convert 59.3% of the kinetic energy from wind creating the Betz limit. For a turbine to be 100% efficient it would have to stop all the wind passing through it. In reality, this is not possible as a rotor needs the wind to pass over its blades to rotate. Modern turbines can convert 35-50% of wind energy, once you factor in mechanical and electrical losses this value reduces to 10-30% of wind power that is converted in usable electricity.

Offshore WTG consist of one tower section, nacelle, rotor and three blades. Inside the WTG there are electrical and mechanical equipment that are used to convert the wind energy. There are two types of drive train technologies that are used by all OEM’s with horizonal axis machines; direct drive and gearbox machines. Below is a basic SLD for a wind turbine that shows the gearbox, generator, DC link converter, inductance to smoothen the waveform on the AC side and transformer. Not included in the image but equally important is the switchgear that receives the energy from the transformer before it reaches the grid.

Figure 3 – Basic single line diagram of gearbox WTG showing IGBT converters

WTG’s are designed and certified to operate in specific wind conditions. These wind conditions are defined by the IEC standard and correspond to high, medium and low wind speeds. Manufacturers have also designed WTG’s that can withstand storms and typhoons for areas where this is an issue. If wind conditions are on the low end then manufacturers can increase the blade diameter and hub height to capture more energy as there will be less loads going through the turbines.

The WTG is controlled by various computers which monitor its condition and performance. They ensure that the WTG nacelle and blades are in the optimal position to capture the most wind. The SCADA system gathers and communicates the real time data so that asset owners can control and monitor the assets remotely. The power curve plots power vs wind speed which shows the cut in speed, partial and full load regions (see Figure 4). If the wind becomes too strong (typically above 25m/s) then the WTG will pitch the blades out of the wind and go into preservation mode to ensure

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that the WTG and substructures are not damaged.

Figure 4 – WTG power curve6

4.2.1 Gearbox Wind Turbine Type

The gearbox wind turbine uses a multi-stage gearbox in between the low speed rotor and the higher speed electrical generator. The purpose of the gearbox is to increase the rotor speed before it is fed into the generator. The drive train consists of a main shaft, gearbox and electrical generator before the power is converted and sent to the grid.

4.2.2 Direct Drive Wind Turbine Type7

Direct drive wind turbines remove the need for a gearbox in the drive train, by connecting the rotor directly to the synchronous generator. A direct drive wind turbine’s generator speed is equivalent to the rotor speed because they are directly connected. The power is transferred from the generator to the converter then the transformer and finally to the OSS through an inter-array cable.

Figure 5 shows the market share between OEM’s of operating wind farms up to 2020. Senvion has since gone into administration and been bought by Siemens Gamesa. The Chinese manufacturer are not widely used outside of their own market and will not be discussed further. This market share should become more equal between three manufacturers (GE, Siemens Gamesa and Vestas) as they all start to deliver 10+MW turbines in the coming years. Figure 6showsthe announced capacity expected for 2020, which for the top three manufactures is greater than the total already installed.

6 Source Wind energy conversion with a variable-ratio gearbox: Design and analysis

7 https://www.engineering.com/story/the-future-of-wind-turbines-comparing-direct-drive-and-gearbox

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Figure 5 - Offshore wind turbine manufacturer market share in operating projects

Figure 6 - Offshore wind turbine manufacturer market share for announced projects

4.3 Wind Farm Power Density

The optimal wind farm power density (MW/km2) can vary depending various factors including, location, wind farm size, rotor power density and diameter, hub height, turbine capacity and spacing. Up to a certain level, a sparsely populated wind farm will have a lower LCoE than a dense wind farm due to lower wake effects. Over the last few years, the average power density of the Dutch offshore wind farms has increased from 5MW/km2 (Borssele) to 8MW/km2 (Hollandse Kust Noord) and will further increase to 10MW/km2. This trend has a negative impact on LCoE but is advantageous from an optimal use of space. The Energy Research Centre in the Netherlands

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commissioned a report that showed the optimal wind farm power density is 4.66 MW/km2 for a 10 MW wind turbine and 5.06 MW/km2 for a 15 MW wind turbine.89

4.4 Costs

4.4.1 CAPEX

Due to the size of wind turbines towers and blades they are constructed as separate components. Normally, fabrication yards are located near shore and are easily accessible for ships, so the components can be transported to the wind farms. The CAPEX below are assumed as a base case and consist of manufacture, transport, and installation. The further away a wind farm is from the assembly port the more expensive the project will be. In the short term turbine price will increase as there is a rise in raw materials prices (steel, copper, aluminium and fibres) combines with a sharp rise in logistic costs.

1.0 – 1.2 M€/MW

4.4.2 OPEX

The price for OPEX can vary widely depending on the location, turbine type and O&M strategy. Distance to shore affects transfer time of technicians when using CTV vessels and logistics of components for replacement. Newer wind farms are moving more towards hiring SOV vessels for week shifts that provide better and safer access to the WTG.. Turbine repair costs increase with age as more parts begin to fail. This is usually factored into the O&M contract price being larger towards the end of life of a project as repairs of main components require the use of jack up vessels that are expensive.

35 – 53 k€/MW/year

4.5 Lifetime

The normal design life of a wind turbine is 20-25 years. During the development stages of a wind farm the end of life options should be considered. There are three options at the end of life;

1. Decommission – remove the wind turbines and their foundations. Costs for this activity should have been accounted for in the development stage (typically 2-3% of CAPEX).

2. Life extension – depending on environmental factors and maintenance quality there is the possibility to extend the life of the turbines. This would typically involve carrying out an assessment that would identify any parts that need to be exchanged. During the operation of a wind farm measuring the loads experienced by the turbine and foundations is important for the life extension assessment.

3. Repowering – The owner of the wind farm can look to take advantage of the existing infrastructure (foundations, cables and OSS), which tend to have longer design life, to repower the wind farm with larger wind turbines. An assessment will need to be carried out on the technical feasibility of such an option.

8 http://resolver.tudelft.nl/uuid:dfe0ce2f-04fb-4db2-80db-52bc02cfb515

9 https://blixconsultancy.com/wp- content/uploads/2021/06/20210125_RAP_Pathways_to_potential_cost_reduction_offshore_wind_energy_F03.pdf

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The end of life decision will consider the site conditions, regulatory situation, permits and leases, energy prices, subsidy schemes and compare it against the cost and value of decommissioning.

4.6 Availability

When evaluating the turbine availability (uptime) there are two methods that are used: Time based and Production based availability.

For time based availability, the O&M provider will guarantee a contractual availability between 95- 96% for each year starting after all turbines are taken over from construction. Any downtime due to non-turbine related issue are excluded from the guarantee such as weather access, BOP and Grid availability. Time based availability is calculated based on the time that the turbines are available to produce regardless of wind speeds.

Production based availability was created to prioritise the importance of having the turbine available during high wind periods which means maintenance activities are carried out in low wind periods otherwise it penalises the service provider. The so-called capacity factor gives a good indication of the wind resource available at a site by showing how well a wind turbine’s full capacity is used. Offshore windfarms have an average of 42.22% based on data available in the UK. As wind farms move further away from shore and in deeper water (floating foundations) there is scope for this to increase as seen at Hywind OWF which reached 57.1% during 2019/20.

Any form of maintenance whether schedule or unscheduled would count against the availability guarantee which incentivises an O&M provider to plan around high wind periods.

It is not possible to provide specific numbers for downtime due to regular maintenance as there is difference in types of technology and what O&M providers include in their scope of service. However looking at time based availability guarantee there are 8760 hours in a year, if the guarantee is for 96% then the wind farm would not be available for 350.4 hours (14.6 days) per year.

Seasonality affects the production, maintenance and access to site. O&M providers should concentrate maintenance during the low wind periods (spring and summer) leaving the turbines alone during high capacity seasons (autumn and winter). Non access days can affect the performance of an asset when there are failures. On average in the UK wind farms, 96 days a year access is restricted, meaning that vessels cannot access the turbines due to adverse sea and weather conditions. Use of SOV as opposed to CTV will further lower this average.10

10 https://ore.catapult.org.uk/wp-content/uploads/2021/02/SPARTA-Review-2020.pdf

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4.7 WTG Catalogue

Below is a list of the largest turbines currently in serial productions as well as the next generation prototypes that are either installed or close to being installed.

WTG supplier Largest WTG in serial production (TRL 9) Largest Planned WTG

Capacity (MW) Rotor ø (m) Capacity (MW) Rotor ø (m) Year of

prod. TRL

Siemens Gamesa (SGRE) 8.4 167 15 236 2024 7

Vestas 9.5 164 15 236 2024 6

General Electric (GE) 6 150 14 220 2024 7

Table 2 - Offshore WTG specifications

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5 OFFSHORE GRID CONNECTION SYSTEMS The first offshore wind farm was constructed in 1991 off the coast of Denmark near a town called Vindeby where it also got its name. The market took a long time to mature however now due to various factors (government policies and incentives, cost reductions, land restrictions etc) there is more deployment of offshore wind.

Electricity transmission is divided into two main grid technologies, Alternating Current (AC) and Direct Current (DC), both with their own variations as LFAC, intermediate compensation (AC), different DC technologies/setups etc. During the next sections the technical concepts for each technology will be further assessed. The main factors like wind farm size and location offshore (transmission distance) dictate the connection type that is best. Most current offshore wind farms are relatively close to shore and have been connected using AC.

The DC alternative becomes competitive for combined CAPEX and OPEX with increasing power ratings and transmission distance. Although AC substations are cheaper, DC has lower cable costs and is able to carry more MW per cross section. In general there is a tipping point of CAPEX (DC- stations versus AC, more cables versus less for same MW, transmission distance) and OPEX (losses of stations, losses of cables, maintenance costs) together which favors one of both options.

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6 AC TECHNOLOGY

6.1 HVAC Offshore Substation

6.1.1 Description

The AC offshore substation (OSS) collects the energy generated by the wind turbines and steps up the voltage to decrease the losses during transmission. This uses a radial system where the turbine are connected in strings and those strings then feed into the OSS. The design concept widely used currently is that one offshore wind farm would feed into a corresponding OSS and the power is then transported to onshore substation through an export cable (EXC) where it is connected to the grid.

This design is now being improved as countries and energy producers look to reduce costs and share energy between multiple markets. One option is to develop hub systems that can collect energy from multiple wind farms. The higher substation costs required is offset by requiring fewer EXC and increasing the wind turbine capacity factors through less curtailments. This option could be expanded to include interconnectors that connect various offshore hubs with multiple countries. A good example is the Kriegers Flak and Baltic wind farms that connect two separate markets, Denmark and Germany (although the two markets are non-synchronized leading to an additional HVDC back-to- back converter station).

At this moment AC platforms of a size larger than 1400MW are not very common, it is even considered to have multiple smaller platforms (350-450MW, for instance like the Siemens OTM which could even be regarded as a ‘standardized’ setup) as the length of the inter array cable (IAC) will increase dramatically (as the area to be built will be larger with higher power, but all need to be connected to one large OSS). Therefore the rated powers will be limited to 350, 500, 700, 1000 and 1400MW for a HVAC OSS.

Figure 7 - AC offshore grid connection layouts11

6.1.2 Technical information

When an AC-connection is considered, there are some options that impact the high-level decisions:

• length of EXC, as a longer length leads to higher capacitance / higher reactive power losses / less available MW-transmission (this can be partly reduced by symmetrical compensation and/or an intermediate compensation)

11 https://guidehouse.com/-/media/www/site/downloads/energy/2019/2019-navigant-comparison-offshore-grid-development.pdf

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• voltage of EXC, as a higher voltage leads to a higher MVA-transmission but also higher reactive power losses lowering MW-transmission

• on top of this, the redundancy should be considered - is there a need for redundancy on the OSS (maybe based on TSO requirements and

compensation schemes)? - is there a need for redundancy for the EXC

The redundancy is not further considered. It is of course clear that any OSS with at least two EXC and/or two transformers can provide partial redundancy:

• design the transformers for ONAN in normal operating conditions and use ONAF when one transformer fails

• design the EXC for normal operating conditions and use a DTS system (monitoring the complete length of the cable) when one EXC fails

• design of the system so if the compensation reactor is out-of-service the turbines can partially take over the compensation functionality

• connect to a neighboring OSS (IAC or EXC level) to have partial redundancy or only AUX power for turbines

Based on the average ampacity/capacitance of EXC with large cross sections, the following general rules can be applied for average distances (40km – 70km):

• the maximum power to be transmitted by 220kV equals to 400MW • the maximum power to be transmitted by 275kV equals to 500MW • offshore transformers larger than 500MW (550MVA) are not preferred as less standard • having the amount of EXC equal to the amount of transformers leads to an ‘optimized’

balance between the two types of equipment

These statements are very general and based on experience / calculations of different setups and of course deviations can always be found.

Based on the above the following is expected as optimal technical-economical choices:

Power [MW]

Main TR [#]

Voltage [kV]

EXC [#]

350 1 220 1 500 1 275 1 700 2 220 2

1050 2 275 2 1400 3 220 3

Table 3 - General setups for different transport powers

The exact distance from shore is no real parameter here except for the cable losses and the size of the compensation reactor. For very large distances, intermediate compensation platforms may need to be considered.

The standards / brochures that are related to OSS are in general the DVN-GL ST-0145 which refers to many other standards based on the equipment installed on the OSS.

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6.1.3 SLD

• compensation reactors are consider to be connected via a DC/ES to the EXC • an average of around 80MW/string is considered • transformers are assessed as 2 winding each winding having a MV earthing/AUX transformer

and associated bay

Figure 8 shows the resulting high level SLD (additional ES/DC are omitted) where the colors denote the amount of offshore transformers/EXC/compensation reactors (black = 1, red = 2, green = 3):

Figure 8 - High level SLD's in relation to # transformers

6.1.4 Costs

6.1.4.1 CAPEX

The CAPEX of the chosen system design is highly impacted by design choices and the prices in the OEM market for electrical components and metals. It has been observed that RFQ for main components sometimes even resulted in a spread of 100% on the received offers. For the CAPEX estimation below a range of ±20% is assumed.

The following overview is based on a minimal approach:

• amount of transformers and reactors as per previous table / SLD • reactors connected with DC/ES • if more than one EXC, a DC/ES between the both • transformers and reactors housed outside • LV and HVAC redundant • no large crane or diesel generator • unmanned

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The CAPEX can be raised considerably based on the following decisions:

• making it a manned OSS with all additional HSSE requirements • housing the transformers and reactors inside (even with HVAC, this should get an increased

capacity then) • gensets (for OSS and turbines) and IAC-compensation reactors for during grid outage • large cranes (they tend to fail at the moment you need them, better come with an equipped

vessel) • a helideck (roughly 3M€)

Power [MW]

CAPEX [M€]

€/MW [k€]

HVMV [%]

LV-AUX [%]

Structural [%]

PM, Install & Comm

[%] 350 71 204.1 22% 17% 29% 32% 500 86 171.9 23% 14% 35% 28% 700 121 173.0 23% 12% 37% 27%

1050 155 148.0 23% 11% 39% 26% 1400 179 127.6 24% 11% 40% 25%

Table 4 - Overview of CAPEX HVAC OSS for different transport powers

6.1.4.2 OPEX

OPEX is typically expressed as a percentage of CAPEX. BLIX through previous projects and confirmation from various sources finds that 1.5% is a reasonable value to apply. This is further confirmed through various research papers that arrive at similar values of 1%12 and 0.9 – 1.45%13.

The activities for preventive maintenance include:

• maintenance HVMV equipment (inspections & functional specs) • maintenance LV equipment ((inspections & functional specs) • maintenance AUX equipment ((inspections & functional specs) • coating repair • C&P: rolling testing in time of all relays by injection • cleaning: removing of guano

Corrective maintenance is expected mainly on AUX-systems and could we require 12-24 interventions/year.

6.1.5 Lifetime

The lifetime of a platform is considered to be a minimum of 25 years, where the most wear and tear can be expected from rotating components and the components that stress by continuously heating up and cooling down (transformers) and being in full power continuously (reactors). Next to having correct preventive maintenance on these components (preferably with an online gas-measuring unit

12 Brard, B. (2017). The regulation of radial grid connection systems for offshore windfarms. Delft University of Technology.

13 Ritzau, M., Macharey, U., Svoboda, P., & Wilms, J. (2017). Determination of an operating cost lump sum for offshore plants. Decision BK4-17-0002 of the Federal Network Agency

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for transformer/reactor), fans (rotating) or diesel generators (needing filtered diesel by pumps) should be avoided to increase lifetime and limit maintenance.

6.1.6 Availability

The availability is assessed in respect to preventive and corrective maintenance.

Preventive maintenance is foreseen for 24 interventions per year of 4 days without the need for production loss as all (impacting) maintenance is foreseen to be planned during low/no wind.

Corrective maintenance is difficult to assess as this is determined by the design of the system:

• each supporting system which is critical to the main functionality, should be constructed 100% redundant. Examples:

- HVAC system - LV-system

• the HV-setup determines to which level partial redundancy can be derived - when only one healthy transformer is available this can be boosted with later

attached fans

A RAMS assessment of an OSS-design will lead to the theoretical power lost availability figure which normally is higher than 99.5% (taking into account the specific power loss depending on the failure).

6.1.7 Losses

Losses can be easily derived from the losses of the main components and the own consumption of the OSS. On top of that the wind profile/powercurve should be assessed (power bins) to come to the percentage of energy produced that is considered as consumed/lost on the OSS (and include the load-losses of transformers). This is normally in the range of 0.3%-0.4%.

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6.2 AC cables

6.2.1 Description

For offshore multiple submarine cables (voltages, cross sections) are available (Prysmian catalogue):

Voltage class [kV]

Cross section [mm2]

66 240 - 2000 110 400 - 2500 132 400 - 2500 150 400 - 2500 220 630 - 2500 275 630 - 2500 345 800 - 2500 400 800 - 2500 500 1600 - 2500

Table 5 – General overview of available submarine cable cross sections per voltage class

For each OWF (Offshore Windfarm) several types of cables/accessories are needed, assuming the land station is located not too far from the coastline.

• Inter Array Cables (IAC) to connect the offshore turbines with strings towards the OSS • Export Cables (EXC) to connect the OSS to the land station. In most cases they consist of:

- a 3-core submarine cable - a transition joint (normally) on land to switch from the 3-core submarine cable to

single land-core cables - single land-core cables to connect to the land station

• Grid cables: cables to connect the land station to the TSO-grid

This chapter will concentrate on the submarine cables (IAC and EXC).

6.2.2 Export cables

6.2.2.1 Technical information

To lower the losses of the transport system, the voltage of the IAC is raised by transformers to the EXC level. At this moment the main used voltage level used is 220kV and sometimes 155kV (to connect lower power, mainly used to connect to offshore DC-stations of TenneT Germany) and 275kV.

These cables are normally made with a XLPE-insulation while having led both a radial-water-blocking element and return path for the single-phase short circuit current [7]. See below picture as a general setup:

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Figure 9 – Export cable example

The cable also contains FO (communication and temperature measurement system), armouring (protection), fillers (strength) etc.

As the cable can be considered as a large capacitance, capacitive current and hence power loss will be imminent. As the Mvar raises with the square of the voltage, this is considered having a high impact and is used in discussion what the tripping point is to move from AC-technology to DC- technology. Of course the cable is available in different cross sections (range depending on voltage level, see table) in both ALU (stranded or solid) or Cu. Milliken types are normally not used due to expenses.

Five types of information are normally available for EXC:

1. mechanical properties / cable handling 2. geometrical properties (how is the cable built up, layers, materials) 3. electrical properties 4. ampacities 5. FO-properties

Item 1 is required to have sufficient comfort that the cable handling by the installation contractor will be withing the cable handling limits. This is both for spooling of cables between different locations, installation on the seabed, burying the cable and installation of cables into the OSS until termination.

Item 2 is required if specific frequency sensitive simulations need to be executed as transient analysis or harmonics distortion calculations. Normally these parameters are translated by simulations packages as PSCAD or EMTP to frequency dependent electrical parameters which are then used in follow-up simulations.

1 Stranded wires

2 Semiconducting tapes

3 Conductor extruded screen

4 XLPE

5 Extruded screen

6 Semicon tapes for LWB

7 Lead

8 Semicon PE

9 Yarns

10 Armour (GS/HDPE)

11 Yarns

12/13 Filler / extruded filler

14 FO

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Item 5 refers to the fiber optic properties, normally the capabilities are well within the required boundaries.

For item 3 and 4 the following can be assessed as some general cable characteristics for a small and large cross section of ALU and Cu.

Table 6 – Electrical characteristics of HVAC cables

These values are available from several cable suppliers which cannot be referred to due to confidentiality. Main suppliers at this moment are:

• NKT, Germany • LS, South Korea • Prysmian, Italy • Hellenic, Greece • Nexans, Sweden • Chinese suppliers upcoming

Next to the cables several related accessories are important:

• factory joint: to be able to make long lengths in the factory, suppliers will ‘connect’ single cores with factory joints for their laying-up machine. The FJ are most times also capable of switching in cross section and sometimes even to switch in conductor material

• repair joints or offshore joints: joints to connect (or repair) offshore cables, normally consisting of 3 ‘normal’ joints in a metal casing

• transition joint: joint onshore to connect the 3-core submarine cable to single land-cable cores, normally consisting of 3 ‘normal’ joints

• terminations: mostly Pfisterer size 6 terminations which are used to connect to an inline joint or a HV-GIS

• inline joint: several types exist, but the most common is a SF6 filed system which connects to male terminations (example: Pfisterer 6 size)

The standards / brochures that are related to these type of cables are mainly IEC 62067, TB490 and TB623 (and referred standards therein). These documents refer to construction, pre-qualification

Cable characteristic Unit ALU 800m2 ALU 1600mm2 Cu 1200mm2 Cu1400mm2 Cu 2200mm2 Nominal voltage between phases UN kV 220 220 220 275 275

Maximum voltage between phases UM kV 245 245 245 325 325

Maximum electrical stress at UN @conductor surface kV/mm 8.3 7.8 10 9.7 DC-resistance conductor 20 degrees Ohm/km 0.0367 0.0186 0.0151 0.0129 0.0082 AC-resistance conductor 90 degrees @50Hz Ohm/km 0.0497 0.0287 0.026 Positive sequence impedance @50Hz Ohm/km 0.071 + 0.129j 0.047 + 0.114j 0.0272 + 0.1154j 0.024 + 107j Inductance of conductor mH/km 0.412 0.361 0.37 Capacitance per phase μF/km 0.154 0.2 0.195 0.207 0.25 Total losses @ampacity W/m 146.6 167 Conductor losses W/m 3x33.8 3x33 Dielectric losses W/m 3x0.8 3x1.0 Metallic screen losses W/m 3x5.5 3x9.2 Armour losses W/m 26.5 37.3 Maximum short circuit current conductor (1s) kA 76 151 172 Maximum short circuit current metallic screen (0.6s) kA 21.2 21.7 22

Armour material GS GS SS 50%GS/50%HDPE 50%GS/50%HDPE

Ampacity (DoB 1.5m / soil 10 degrees / soil 0.6Km/W) A 824 1073 Ampacity (DoB 1.5m / soil 15 degrees / soil 0.7Km/W) A 1180 Ampacity in HDD A 1000 1180

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tests (PQ), type tests (TT), routine tests (last test as FAT), sample tests and SAT, both for cables and their accessories.

6.2.2.2 Installation

The installation of EXC is normally executed from a cable laying vessel that contains large baskets on turntables that are filled at the quay side. Figure 10 shows the design of this equipment to be placed on a cable laying vessel:

Figure 10 – Design of turntable on a cable laying vessel14

The cable is ‘laid down’ with a special system (checking all mechanical stress parameters on the 3- core cable) on the seabed. Afterwards normally a ROV is used to bury the cable by liquifying the seabed which allows the cable to sink easily to the required depth.

At the OSS the cables are guided through a Cable Protection System (if applied, also only scour is used) and the J-tubes. Then they are stripped on the cable deck of the OSS (3-core cable will be fixated by hang-off) and the single cores are guided to the HV-GIS and terminations are installed and connected. Sometimes an inline joint is used to connect the EXC and pre-installed platform cables.

Of course, many more requirements and activities need to be fulfilled/executed during this installation process, only the high-level activities are mentioned.

6.2.2.3 Costs

6.2.2.3.1 CAPEX

The following table shows some costs that can be expected for different types of EXC. When this information is used, the next points should be considered carefully which requires to use the prices with a large margin:

• it should be noted that the cable prices have been very volatile in 2020/2021 due to COVID and the price of metal

• the tender prices that have been used are the variable prices per meter • the tender prices are also highly depending highly on the cable-volume of the project (LOW

< 50km, MEDIUM, HIGH: > 150km)

14 Enersea presentation of activities. www.enersea.nl

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• suppliers tend to also assess the risk of a project in their price, this is not further detailed • based on the above a margin of at least 25% should be applied

Voltage class [kV]

Cross section [mm2]

Conductor material [ALU/Cu]

Armour material

[GS/SS/HDPE]

Volume Costs [€/m]

220 630 ALU GS LOW 480 220 800 ALU GS HIGH 410 220 800 ALU SS HIGH 480 220 1000 ALU GS HIGH 430 220 1000 ALU SS HIGH 510 220 1000 Cu SS/HDPE HIGH 750 220 1200 ALU GS HIGH 450 220 1200 ALU SS HIGH 505 220 1200 ALU SS/HDPE HIGH 530 220 1600 ALU SS MEDIUM 770 275 1400 Cu GS/HDPE MEDIUM 1200 275 2000 Cu SS MEDIUM 1500

Table 7 – Cost per meter of several HVAC cables

The above prices do not include:

• engineering and if needed additional type test or PQ tests • fixed (starting) costs for supply • installation of offshore joints / transition joints (high costs due to vessel availability) • termination and testing (T&T)

- termination is normally not the highest portion of costs but does pose a risk (check: availability)

- testing can be quite expensive if a resonance test (from onshore) is conducted

In recent projects calculations for EXC are done based on dynamic rating (per IEC 60853-2) instead of continuous rating (per IEC 60287) as it has been shown that the cables are over-dimensioned and never reach their maximum temperature. This lowering of cross sections of course does add to higher losses during normal operation and less margin during n-1 situations.

The installation costs of all cables are roughly the same (if the cable is larger/heavier the vessel needs to make more trips / more offshore joints are needed) and can be assessed for €200/m for the variable part with a margin of 20%. The mobilization and demobilization costs should be added including weather delay provisions which are very project specific.

6.2.2.3.2 OPEX

OPEX is very depending on the project specific situation (how is it buried, rocks, sand, mattresses (for crossings), clay, ..) leading to a wide spectrum of inspection techniques and cannot easily be given.

The OPEX can be ‘minimized’ by use of DTS (Distributed Temperature Systems) and/or DAS (Distributed Acoustic Sensing) which monitors the temperature (and if installed correctly, the DoL (Depth of Laying)) next to free hangs or other mechanical stress adding activities.

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In a ‘normal’ situation the following activities are covered as preventive maintenance:

1. a 1-5 yearly survey is needed to check the exact laying configuration of the cable (based on the magnetization of the armour during load-out)

2. a Remote Operated Vehicle (ROV) with camera’s to inspect CPS (Cable Protection Systems) entering the J-tubes and crossings done with mattresses

3. re-execution of LIRA/TDR tests to assess impact on insulation

6.2.2.4 Lifetime

Lifetime of type tested cables (all cables are assumed to be a dry design) are considered to be 25-40 year. Formally the IEC-standards do not mention this and the first installed submarine cables have barely reached this lifetime

6.2.2.5 Availability

The availability of EXC is depending on 4 major items:

1. The electrical quality of the cable: normally if this is correctly tested (PQ, routine, FAT, SAT) there is a low expectation on failure

2. The mechanical quality of the cable: normally if this is correctly tested (PQ, SAT) and the installation conditions have been monitored and kept all beneath the allowed limits, there is a low expectation on failure

3. Man-made additions as repair joints and terminations: this can be a source of failure 4. Mechanical damages due to free-hanging (stress), anchors, fishing nets etc.: this is a major

source of failures and is heavily depending on the offshore location

Item 3 is partly covered by the SAT (Site Acceptance Test) which stresses the cable according to IEC 62067 including the accessories. This is normally a resonance test until 1.7U0 per phase in the range of 20Hz - 300Hz (or a bit lower as per table 10 of IEC 62067). If a choice is made for a 24hr soaktest, this is not applicable and not ‘tested’. The failure rate of the EXC is normally expressed as an electrical failure rate per km (λ) and added on top that the failure rate per joint/termination (which usually derived from land-based failure rates).

Item 4 is a practical assessment which needs to be made by the OWF and differs all over the world. A value derived from available sources shows an average of 0.003 failures/km/year15.

6.2.2.6 Losses

It should be clear that for losses calculations 3 options can be used:

• W/m as given for the 220kV cable (see overview) • metallic screen losses can also be referred to as λ1 being the ratio between conductor losses

and metallic screen losses and armour losses can be referred to as λ2 being the ratio between conductor losses and the armour losses

• use of positive sequence resistance which incorporates all these 3 losses (but missing the dielectric losses which are considered small)

As stated before, the losses and Mvar of the cable do impact the tripping point where an AC connection is becoming less attractive. A qualitative approach is shown in the compensation chapter.

15 Failure Rates of Offshore Wind Transmission Systems. energies-12-02682

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To lower/eliminate the armour losses, suppliers can replace the galvanised steel wires by stainless steel wires or HDPE (if the impact amount of pulling force is allowed) or a mix of these types.

6.2.3 Inter array cables

6.2.3.1 Technical information

To connect the turbines to the OSS, the inter array cables (IAC) are used. They will operate on the voltage level of the turbines on the HV-side of the transformer. Until a few years ago this voltage level for offshore was 33kV, this has been changed now to 66kV, amongst others by projects initiated by the Carbon Trust. Further the next step, also initiated by the Carbon Trust, is to increase this level to 132kV, however cable characteristics are still unknown. This level is ‘agreed’ between cable suppliers and turbine suppliers will follow. This also has to do with the amount of power each turbine is able to produce which has raised very fast from 4MW (Gemini, 2010), 9.5MW (Blauwwind, 2018) to 15MW (expected in 2024/25). Further the higher voltage will give reduced losses, longer distances and a more acceptable voltage profile along the string.

These cables are normally made with a XLPE-insulation or EPR-insulation (Prysmian), the last one having more flexibility then XLPE-cables (and also claimed better ampacity). The radial water blocking functionality can be present (overlapping, glued foils or ALU welded sheath) or constructed as a (semi)wet design which allows the cores (screen wires, outside semicon) to come in contact with the seawater. See below picture as a general setup for a dry design:

Figure 11 – Inter array cable example

The cable also contains FO (communication and temperature measurement system), armoring (protection), fillers (strength) etc. The information types of IAC are identical as for EXC.

1 Stranded wires

2 Semiconducting tapes

3 Conductor extruded screen

4 XLPE

5 Extruded screen

6 Semicon tapes for LWB

7 Copper wires

8 Semiconducting tapes

9 RWB tapes

10 HDPE sheath

11 Extruded fillers

12/14 Yarns

13 Armour GS

15 FO

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Table 8 – Electrical characteristics of IAC AC cables

These values are available from several cable suppliers which cannot be referred to due to confidentiality. Main suppliers at this moment are (known for 66kV):

• NKT, Germany • LS, South Korea • Prysmian, Italy • Hellenic, Greece • JDR, UK • TKF, Netherlands • Chinese suppliers upcoming

Next to the cables several related accessories are important which are sort of identical to EXC. The use of FJ is normally not needed and allowed (by clients) as the single lengths of cables are, with an exception, not so long that this is needed.

The standards / brochures that are related to these type of cables are mainly IEC 63026, TB623 and TB722 (and referred standards therein). These documents refer to construction, pre-qualification tests (PQ, only if a certain stress-level is passed), type tests (TT), routine tests (last test as FAT), sample tests and SAT, both for cables and their accessories.

6.2.3.2 Installation

The installation of IAC can be assessed as like the EXC except for lighter, smaller cables, shorter lengths and more pull-ins, stripping and terminations.

The installation on the OSS is nowadays more often with an inline joint already pre-installed at the cable deck.

6.2.3.3 Costs

6.2.3.3.1 CAPEX

The following table shows some costs that can be expected for different types of IAC. It should be mentioned that many 33kV-producing factories have reacted to 66kV as a small additional step (and therefore small price increase) which showed to be incorrect at the end. Therefore prices have, next

Cable characteristic Unit ALU 800m2 ALU 1200mm2 Nominal voltage betwen phases UN kV 66 66 Maximum voltage between phases UM kV 72.5 72.5 Maximum electrical stress at UN @conductor surface kV/mm 6.5 6.3 DC-resistance conductor 20 degrees Ohm/km 0.0367 0.0247 AC-resistance conductor 90 degrees @50Hz Ohm/km 0.0508 0.0371 Positive sequence impedance @50Hz Ohm/km 0.061 + 0.096j 0.048 + 0.092j Inductance of conductor mH/km 0.305 0.292 Capacitance per phase μF/km 0.384 0.4621 Total losses @ampacity W/m 108.1 115.3 Conductor losses W/m 3x29.2 3x28.8 Dielectric losses W/m 3x0.1 3x0.1 Metallic screen losses W/m 3x2.0 3x3.0 Armour losses W/m 14.3 19.6 Maximum short circuit current conductor (1s) kA 75.6 113.5 Maximum short circuit current metallic screen (1s) kA 3.4 3.9 Ampacity (DoB 2m / soil 15 degrees / soil 0.7Km/W) A 757 881

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to market prices, relatively grown. When this information is used, a large margin should be used for the same reasons as for the EXC (25%).

Prices for 132kV cables are not readably available as not in use at the moment. An estimate has been added based on prices for 66kV and 220kV cables. This should be confirmed later once it becomes more widely used as the product matures.

Voltage class [kV]

Cross section [mm2]

Conductor material [ALU/Cu]

Armour material [GS/SS/HDPE]

Volume Costs [€/m]

66 300 ALU GS MEDIUM 150 66 400 ALU GS HIGH 140 66 800 ALU GS HIGH 190 66 800 Cu GS HIGH 420 66 1200 Cu GS LOW 710

132 800 ALU GS MEDIUM 310 132 1200 Cu GS MEDIUM 750

Table 9 – Cost per meter of several IAC cables

The above prices do not include:

• engineering and if needed additional typetest or PQ_tests • termination and testing (T&T)

- termination can be quite a portion of all costs and do pose a risk (check: availability)

- testing can be quite expensive if a resonance test offshore is conducted

The installation costs of all cables are roughly the same (if the cable is larger/heavier the vessel needs to make more trips) and can be assessed for €200/m for the variable part with a margin of 20%. The mobilization and demobilization costs should be added including weather delay provisions which are very project specific. Further the Installation of IAC on the turbines/OSS require relatively an additional high additional CAPEX part compared to the EXC as the lengths of section are quite small (1.5km – 2.5km), on the other hand in general offshore joints are not considered for IAC.

6.2.3.3.2 OPEX

Reference is made to EXC.

6.2.3.4 Lifetime

Lifetime of type tested cables (especially the dry design) are considered to be 25-40 year. Formally the IEC-standards do not mention this and the first installed submarine cables have barely reached this lifetime.

6.2.3.5 Availability

The availability of IAC is depending on these same 4 major items as the EXC except one item is much more prominent: as the IAC normally have a 2 terminations per 2km (distance between 2 turbines), the EXC have a joint/termination per 40km. This makes the sensitivity for man-made terminations per km cable much higher.

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This is partly covered by the SAT (Site Acceptance Test) which stresses the cable according to IEC 63026 including the accessories. This is formally a resonance test until 3U0 per phase in the range of 10Hz - 500Hz, but this test, which is standard onshore, has only recently been developed. Oher options are VLF (Very Low Frequency) tests, normally on 0.1Hz, sinusoidal, square waved or a damped AC test. The reader should be awarethat the VLF and AC-damped tests do not conform to standards. Another test is the 24hr soak test, although this is not assessed as ‘tested’. A practical solution could be to agree with a supplier a VLF or damped AC test and use the soak test as the formal contractual milestone.

The above is not valid for the 132kV version of the IAC as the IEC 63026 ‘ends’ at 72.5kV. For that voltage level the IEC 60840 needs to be used. This would mean a resonance test between 20-300Hz of UN per phase or a soak test.

In reference 16 a value derived from there shows an average of 0.0045 failures/km/year.

6.2.3.6 Losses

Reference is made to EXC.

16 Failure Rates of Offshore Wind Transmission Systems. energies-12-02682

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6.3 Reactive Compensation

6.3.1 Technical information

The main aspect of the EXC (and the discussion of DC) is related to the reactive power that is induced by the power frequency with long cables.

Compensation of the reactive current can be applied in 3 ways, each resulting in a different reactive current profile (with an assumed EXC capacitance):

Figure 12 - Capacitive current AC EXC versus distance

• with one-sided compensation, at the onshore station, the Mvar current is high when reaching the beach (sometimes via a HDD). The effective current is the highest, resulting in the highest losses

• with symmetrical compensation it can be observed the Mvar current has been lowered to 50% on both ends

• with intermediate compensation this can even be further reduced

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A practical calculation can show the difference:

Table 10 - Example of available ampacity ([A] versus compensation)

The project Gemini in the Netherlands was built with a 110km long export cable on 220kV and a 2- sided symmetrical compensation. Of course, long AC-connections will also give other PQ-challenges to check / mitigate.

In practice the EXC can have smaller cross sections on locations where the overall current is the lowest. Which in return also lowers the capacitance hence the reactive current.

6.3.2 Costs

The CAPEX for reactors is assumed as follows (margin 20%):

Table 11 - CAPEX of compensation reactors

These values are based on a 50km EXC. The differences are based on the EXC voltage and the assumed capacitance per kilometer for the cable.

Of course intermediate compensation requires a complete additional offshore platform.

6.3.3 Losses AC versus DC

First it should be assessed that based on the required power, both the AC and DC options are technically feasible. When comparing the two options, the following items should be compared:

• the CAPEX of the AC and DC solution should be made available including the cables • the OPEX should be made available of both solutions • the losses during lifetime should be calculated and made actual by means of a NPV

calculation. This means the wind profile (and resulting EXC currents) should be made available, the interest rate and the future electricity price (or even lower subsidies)

It is not difficult to assess that the CAPEX and OPEX of the DC-option is normally substantially higher. So the gain will come from less losses.

Voltage 220 kV Capacitance 0.2 μF/km Ampacity cable 1000 A

Length [km]

1-sided [A]

2-sided [A]

Intermed. [A]

Capacitive current 50 399 200 100 Available MW current 50 917 980 995 Capacitive current 100 798 399 200 Available MW current 100 603 917 980 Capacitive current 200 1596 798 399 Available MW current 200 NA 603 917

Voltage class [kV]

Reactive power [Mvar]

Costs [k€]

220 76 1500 275 137 2500

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6.4 Onshore HVAC Land Stations

The AC-landstations function as the intermediate for the EXC arriving and the connection to the onshore TSO-grid. On this connection point the grid code of the TSO will apply. The function of this landstation is therefore:

• bring the voltage to the required grid voltage - a transformer could even be considered as to be able to cope with voltage variations

leading to higher losses in the EXC • connect compensation reactors (compensation of EXC) • have equipment installed to show grid compliance in respect to reactive power:

- add a reactor with OLTC - add reactor and capacitor banks to be switched - add a STATCOM in case fast voltage support is needed which cannot be supplied by

the turbines • have equipment installed to show grid compliance in respect to PQ (power quality):

- add a filter to limit the harmonic distortion to the allowed limits - add a filter to take care of TOV in case of energization or load rejections o take care of stable operation of the wind turbines, which is highly impacted by the

minimum short-circuit-ratio (MW-OWF/MVA-grid). It is considered this value should at least be 3 to be able to have a stable operational connection without the probable need for this additional equipment

The design of such a station is very depending on all functions that are required but a ball park figure for a 1000MW AC station including the above amounts up to 80M€ - 90M€. Depending on the size, the STATCOM (including transformer, bays, C&P) represents 30% of this CAPEX figure.

OPEX activities in general are the same as for OSS except the coating repairs. Be aware of the preventive cleaning of insulators in (marine) environments if the land station is located nearby the coast.

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7 DC TECHNOLOGY

7.1 Basic Components of DC Connections

The DC-technology is conceived as the next generation of connectors for longer distances / higher powers of OWF. A DC-link has already been in operation since 1954 by means of Line Commutated Converters (LCC-HVDC). As such this is a very mature technology used to transmit high power over long distances using grids overhead lines, submarine cables, back-to-back). Some specifics are:

• based on thyristor technology (thyristors only conduct current in one direction after gate signal, the current is transferred from one phase to another between thyristor valves). Thyristors can now even conduct 5000A as 8kV devices

• need for strong network connections (SCR > 3) or supporting systems • need to filter both on the AC and DC-side • absorption of reactive power (both as rectifier or inverter) • direction of power flow not easily changed and if so, the polarity of the cable conductor

changes • large footprint due to filters • losses: 0.6% - 0.8% per converter

Short Circuit Ratio (SCR) is here considered to be the MVA (LCC inverter) / MVA (Grid).

To have a smaller footprint (OSS platform) and to be able to connect to weak grids (OWF with wind turbines) the converter type used for the connection of OWF is the MM-VSC (Modular Multilevel Voltage Source Converters or MMC, Modular Multilevel Converters). Key specifics are::

• based on IGBT technology (based on modules, half bridge or full bridge that are put in series and can already include some ‘redundancy’)

• able to connect to weak grids (self-commutating) • the need for a filter to have the correct power quality to feed the grid will be minimal • able to control reactive power on each side of the connection • power flow easily changed (other direction current) • smaller footprint (30% - 50% reduction compared to LCC) • higher losses than LCC-HVDC: 1.0% per converter station

The key element of VSC is the use of power capacitors integrated with the converter modules. They function as an intermediate storage which realizes the balance between constant DC power flow and oscillating AC power flow. Values that are common are 3.3kV IGBT’s with 10mF capacitors. To arrive at for instance 320kV this would lead to more than 400 modules if 5 - 10% redundancy is included. Nowadays IGBT’s (ABB types, Mitsubishi types) conduct to around 2200A.

Examples of such a module is shown below where the half bridge is only capable of providing half the output voltage compared to the full bridge.

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Figure 13 – Output voltage levels depending on type of bridge

Figure 14 - Siemens HVDC Plus module

The overall system should be made robust for faults such as:

• internal faults as submodule faults, modulation & control faults and phase reactor fault • external faults as AC network faults at PCC, AC faults inside the converter station and DC-

faults, pole-to-pole and pole-to-ground.

The components and systems to mitigate these faults are rapidly developing and are considered differently by each of the 3 main suppliers:

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• discharging cable system • onshore DC choppers/dynamic breakers • inrush current limiting resistors • series pole reactor to limit peak/rise of currents and smoothen ripple/harmonics • phase reactor to suppress circulating currents due to imbalances in the converters and ability

to control active and reactive power flow • DC-breakers

Special attention should be given to the DC-breakers. There are available in the market and to a certain theoretical extent work (in all kind of hybrid solutions) but the missing current-zero moment (as with AC) hinders an easy extinguishing of the arc-flash. Also several suppliers as ABB and Mitsubishi are (further) developing the hybrid solution which uses mechanical switches, full electronic bridges and artificial current-zero moments by injection.

Until now the faults of a point-to-point DC-connection with VSC is cleared by opening AC-breakers. To have selective fault detection and clearing for meshed DC-grids, there is no real proven affordable solution yet available which hinders the meshed grid development.

7.1.1 SLD

Figure 15 - Simple HVDC single line diagram

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7.2 HVDC Offshore Substation

7.2.1 Description

The first large group of VSC OWF-connections has been pursued by Germany after the decisions to close all nuclear power plants. These connections, consisting of 8 platforms in total have power ranges of 576MW to 900MW, link voltages of 250kV – 320kV and have been provided by the 3 large suppliers (ABB, Siemens and GE/Alstom). It has been experienced that the commissioning and reliability of these ‘new’ technologies in the harsh marine environment including a constant ‘vibration’ as standing on a jacket is/was very challenging.

Figure 16 - DC offshore grid connection layouts17

The 3 main different setups can be derived from the figure:

1. Connection of an OSS platform (or more) to the DC-platform. This is the standard way of connections of the German OWF by TenneT Germany

2. Connection of the IAC directly to the DC-platform, of 1 OWF or more. This is making the OSS of the OWF superfluous. This is the new way of TenneT Holland to connect to IJmuiden Ver

3. Connection of IAC of more OWF to an offshore hub, which can be connected to multiple countries/markets

7.2.2 Technical information

The 5 main topologies that are used/proposed to build DC-connections with VSC are (also applicable to land connections):

1. Symmetrical monopole (figure a), this one is used in the TenneT Germany DC-platforms 2. Asymmetrical monopole: only 1 pole with a high voltage (positive or negative) with a metallic

return (figure b) 3. Asymmetrical monopole: only 1 pole with a high voltage (positive or negative) with no

metallic return (figure c) so making use of the ground electrode return, normally not allowed by the permit

17 https://guidehouse.com/-/media/www/site/downloads/energy/2019/2019-navigant-comparison-offshore-grid-development.pdf

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Figure 17 – Different topologies for monopoles

4. bipolar with a metallic return, this one will be chosen by TenneT Holland for 2GW 5. rigid bipole: no metallic return or ground electrode return, mostly not allowed by permit but

the current should be minimal if balanced poles

Figure 18 – Different topologies for bipoles

As alternatives also homopolar schemes are possible (so twice a negative or positive voltage).

In addition it can be reported there has been 1 project executed which has connected a LCC- converter station with a VSC-converter station.

The choices of which system would be the most appropriate is depending on the following:

• what is the amount of power that needs to be transported • what is the good balance between voltage (investment in converters) and cables (investment

in metal and insulation material) • what is the required availability: in case a bipolar system is chosen, the failure of 1 converter

will only lead to 50% power reduction (in case of a not allowed ground return, the cable of the faulty converter can be re-arranged as the metallic return)

• how are the losses calculated (power curve, wind-data) and evaluated (NPV, future electricity prices, interest rate etc.)

A general overview based on some high level calculations:

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Power [MW]

Topology [#]

Voltage [kV]

Current [A]

Cable Cu [mm2]

700 2 320 2188 2000 1000 1 320 1563 1000 1400 1 400 1750 1500 1750 4 400 2188 2000 2000 4 525 1905 1500 2100 4 525 2000 2000

Table 12 – Practical relation between power, voltage and cable type

It should be noted that this overview can change due to:

• other cable cross sections needed due to unfavorable installation circumstances • overall loss calculation shows the voltage level should be raised (lowering current and usage

of other type of DC-cable) as stated before

7.2.3 SLD

The SLD which is used by the German project is shown below.

As stated, the next generation to be constructed by TenneT NL is including the OWF platform functionality on the converter station platform.

Main thing will be that the transformation of IAC voltage to converter voltage is done in 1 step. Of course the requirements to these transformers, as being stressed both by AC as DC voltages, is more stringent than for the OWF main transformer.

Figure 19 – Standard setup for DC-connection for OWF

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7.2.4 Costs

7.2.4.1 CAPEX

Based on several sources (publicly available reports, project data) the following overview can be derived. It should be noted that these kind of prices are depending heavily on the pipeline (amount of projects) of the main HVDC suppliers, HV suppliers and the metal prices (OSS and jacket). It should be mentioned the HVDC market is a sellers market due to a limited amount of suppliers. Further the suppliers / buyers of the several existing projects are not open to disclose information in respect of costs.

The first table shows the estimates (±25%) for a DC-platform (as per TenneT Germany) with separate OWF-platforms and the second table shows the estimation if the functionality is combined (as per TenneT NL). In both table the HV-related components are priced separately.

Power [MW]

HV Offshore

[M€]

ACDC Platform

[M€]

Total [M€]

k€/MW

700 70 450 520 743 1000 150 490 640 640 1400 200 570 770 550 1750 250 650 900 514 2000 300 730 1030 515 2100 315 750 1065 507

Table 13 - CAPEX of HVDC OSS

Where the data was not available, intelligent extrapolation has been made between the different power sections. A bipole HVDC equipment is considered 35% more expensive than a monopole (700MW). As the system grows in power, the related platform size grows as the weight and amount of steel.

7.2.4.2 OPEX

The OPEX of DC-stations is considered to be roughly based on a percentage of the CAPEX.

Power [MW]

Total ACDC [M€]

OPEX [%]

Total [M€]

k€/MW/ year

700 520 1.5 7.8 11.1 1000 640 1.5 9.6 9.6 1400 770 1.5 11.6 8.3 1750 900 1.5 13.5 7.7 2000 1030 1.5 15.5 7.7 2100 1065 1.5 16.0 7.6

Table 14 - OPEX of DC-platforms

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Activities are based as for the AC-substations and include:

• maintenance HVMV equipment (inspections & functional specs) • maintenance LV equipment ((inspections & functional specs) • maintenance AUX equipment ((inspections & functional specs) • coating repair • C&P: rolling testing in time of all relays by injection • cleaning: removing of guano

Corrective maintenance is expected on AUX-systems (more complex than AC OSS, for instance water cooled systems) but also on converter systems (IGBT’s, although they have some built-in redundancy) and could we require 24-36 interventions/year.

7.2.5 Lifetime

The expected lifetime of the system is 25 years and it should be capable of ‘surviving’ the OWF/turbines that are connected to the OSS. This can vary depending on each countries regulatory and legal frameworks as well as the wind farm lease lengths. However an extension to wind farm operating life can be requested as long as proper/expensive preventive maintenance and lifetime extension analysis is carried out. TenneT is designing platforms with an expected life of 30 years. HVDC offshore platforms have only been installed recently (since 2015) so there is much to learn about the reliability of the technology in harsh marine conditions.

7.2.6 Availability

As already stated before, the availability of the system can be improved in several ways:

• have a metallic return for a bipole such that if one pole is malfunctioning / in maintenance there is still 50% power flow possible

• add a certain percentage additional modules in the converters arms. The system is setup such, that if one fails, a short circuit is made and the other available IGBT-modules can take over

• have spare IGBT-modules available, in case of failure they can be replaced in 2-4hrs (depending on access on the topside).

Numbers are not yet available based on a large database, CIGRE TB713 did a simulation based on a fictitious grid and came up with a forced outage of 2.2% for a bipole converter (including 200km cable).

The input consisted of:

• symmetrical monopole: λ = 0.0153 failures / year MTTR: 1664h • bipoles: λ = 0.0153 failures / year /pole MTTR: 1664h

MTTF (Mean Time To Failure) = 8760/ λ

Which results in a technical availability of A = MTTF / (MTTF + MTTR)

• symmetrical monopole: MTTF = 572549 A = 99.71% • bipoles (per pole): MTTF = 572549 A = 99.71%

Downtime due to preventive maintenance should be minimal for bipoles if this can be done in low wind periods (as then the system can be operated for 50% of transport power. Loss of availability due to monopole maintenance is not available.

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7.2.7 Losses

Losses are derived from the general data which should be evaluated for different currents.

Let us assume:

• 1000MW bipolar system • ±320kV • 100km 1400mm2 ALU cable (Rdc20 = 0.0129Ohm/km, Rdc70 = 0.0154Ohm/km): • no-load losses passive components and IGBT (switching losses): 0.05% * Pnmon • load losses IGBT (conducting losses, related to I^2): 0.62% * Pnmon • average losses passive components: 0.33 * Pnmon

Power [MW]

Current [A]

Rdc [Ohm]

Losses 2xHVDC

[kW]

Losses Cable [kW]

Total Losses [kW]

Total Losses

[%] 0 0 1.29 7600 0 7600 0.8%

250 391 1.34 8375 409 8784 0.9% 500 781 1.39 10700 1697 12397 1.2% 750 1172 1.48 14575 4065 18640 1.9%

1000 1563 1.54 20000 7520 27520 2.8%

Table 15 - Losses of 1000MW DC system

7.2.8 DC Offshore Substation in Meshed Grids

As already stated in 7.1 the meshed grids, more specific the multi-terminal DC (MTDC), are seen as the way forward but are not executed on a large scale yet, partly due to the absence of proper protection schemes to have more selective mitigations.

The simplest version if the parallel set-up, where all HVDC converters are connected to the same DC- cables and ‘do their thing’, either consuming or generating power. The most complex is the meshed grid where units are set in series (so adding up in voltage) and set in parallel (same voltage).

Special grid control strategies as LF-control, master voltage control, current-voltage control, voltage- power control etc. should be derived to operate in combination with sophisticated fault detections.

In theory the values as given for DC OSS are applicable but need to be increased with:

• double connection of DC cables • installation of DC-breakers • more complex control of power, voltage and current • fault detection and protection measures

The fault detection will consist of direct measurements (as distance, differential and over current) and signal processing methods (travelling wave, voltage derivative, frequency based) which will activate the needed fault-mitigation.

ABB has provided a general overview of protection systems for their HVDC-Light:

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Figure 20 – Different protection systems as proposed by ABB for HVDC-Light

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7.3 HVDC Land Station

7.3.1 Description

The DC-land station in principle mirrors the OSS HVDC setup (only from DC to AC) except the connection to the onshore grid should be done at the correct local voltage level and quality.

The AC-switch yard is considered to be a standard setup (AIS, GIS) and filters are considered to be minimal with VSC due to the multi-level system.

The type of grid transformers should be assessed based on the power. For large powers (>1500MW) single phase units are considered more realistic.

7.3.2 Costs

7.3.2.1 CAPEX

The CAPEX is based on the HVMV component prices of the offshore substations but a bit lower for due to easier access and building freedom. Added to that are the civil works that include also all other supporting systems (LV, HVAC, building-systems etc.). Margin is expected to be 20%.

Power [MW]

ACDC Onshore

[M€]

Civil [M€]

Total [M€]

k€/MW

700 50 20 70 100 1000 120 30 150 150 1400 160 35 195 139 1750 205 40 245 140 2000 250 45 295 148 2100 262.5 45 308 146

Table 16 - CAPEX of HVDC land station

7.3.2.2 OPEX

Power [MW]

Total ACDC [M€]

OPEX [%]

Total [M€]

k€/MW/ year

700 70 1.5 1.1 1.5 1000 150 1.5 2.3 2.3 1400 195 1.5 2.9 2.1 1750 245 1.5 3.7 2.1 2000 295 1.5 4.4 2.2 2100 307.5 1.5 4.6 2.2

Table 17 - OPEX of HVDC land station

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7.3.3 Lifetime

Reference is made to offshore although the land conditions shall be favorable in relation to the marine conditions so preservation shall be longer.

7.3.4 Availability

Reference is made to offshore.

OPEX activities in general are the same as for OSS except the coating repairs. Be aware of the preventive cleaning of insulators in (marine) environments if the land station is located nearby the coast.

7.4 HVDC Cables

7.4.1 Description

To connect DC-stations, DC cables are required. In general there are 2 types:

7.4.1.1 Mass impregnated cables (MI)

Mass impregnated insulation consists of layers of Kraft paper which are heated, subjected to vacuum and impregnated with high viscosity oil over several weeks. The technology is very mature and has been employed since the 1950s for HVDC applications. A survey conducted by Cigré Working group B1.21 revealed over 15,000km of HVDC Mass Impregnated cable cumulatively installed amongst its respondents prior to 2005. Mass impregnated paper is not used for HVAC applications due to problems with partial discharge. This is not an issue for HVDC cables due to the lack of rapid polarity reversal.

7.4.1.2 Extruded XLPE cable (XLPE)

The first real utility scale HVDC cable to be installed using extruded XLPE as an insulation medium was the Cross Sound Cable installed in 2002 between Connecticut and Long Island in the northeast USA, operating at ±150kV and capable of transporting 330MW.

XLPE cables have several advantages over Mass Impregnated which is the reason why they are dominating the market now for VSC types of converters. In the case of land applications, XLPE cables are lighter which allows longer transportation lengths and therewith longer distances between joints. XLPE land cables are also quicker to manufacture. In essence they are like HVAC cables (see other chapter on build-up of these cables) with the following other process steps:

• higher XLPE base material cleanliness • a longer degassing period on less high temperatures

For long distance submarine cable, factory joints are necessary. Here the distance between joints would be longer than for Mass Impregnated cables. XLPE is generally more mechanically robust and they may operate at higher temperatures (70⁰) than Mass Impregnated cables allowing them to carry more current for a given conductor cross section. For this last reason XLPE cables are often used with aluminium conductors to reduce the weight and cost of the cables (although copper conductor is still common for submarine applications). For land applications, pre-moulded joints are available, reducing the time required for cable jointing, making this technology attractive.

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XLPE cables cannot presently be used with current source converters (CSC); the reason for this is outlined below. XLPE cables suffer from a space charge phenomenon (which can be triggered also with higher temperatures, hence a HVDC-XLPE conductor may rise to 70⁰ as opposed to HVAC-XLPE to 90⁰). After being subjected to a constant electric field for a protracted period of time, as in HVDC applications, the insulation becomes polarized and this can lead to breakdown and failure should the polarity of the field be reversed. This renders currently available XLPE cables unsuitable for use in current source HVDC installations where in order to reverse the direction of power flow the polarity must be reversed. Hence XLPE cables can presently only be used in voltage source installations (or ‘oversized’ cables can be used on a lower voltage).

Figure 21 – Typical setup HVDC cables18

Figure 21 shows the drawing of an XLPE submarine HVDC cable and a deep sea HVDC cable. The last one having 2 armor layers.

On HVDC cables a next generation is being developed, namely the cable based on Polypropylene (PP). This cable type does not require cross-linking like XLPE hence referred to as much more environment friendly (as it can be recycled and used for other applications), although on XLPE recycling is mentioned through pyrolyse (TKF).

Prysmian claims to be able to supply an improved solution (P-Laser type) of this High Performance Thermoplastic Elastomer (HPTE) which is allowing the conductor to heat until 90⁰ and allows voltage reversal. It can also make used of the existing XLPE-accessories and does not need degassing. In essence they have further improved the PP-base material (by very fine filtration just before the extrusion heads) to avoid by-products.

18 As per most HVDC cable suppliers

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Figure 22 - Prysmian overview of PP cable capabilities versus XLPE

7.4.2 Technical Information

The XLPE HVDC cables can be found/made in all voltage classes, from 150kV until nowadays 525kV.

As per the positive aspects of the XLPE cable as described before (see 7.4.1) this cable type is expected to support whichever future HVDC application levels are required. As such all information is only considering XLPE-extruded cable types.

As DC-systems are missing the capacitive current and the skin effect, the ampacity of transported energy is much higher than with long HVAC cables.

General data for a Cu 2500mm2 cable as reference:

• Rconductor = 0.0073Ohm/km, this can be used for losses calculations (conductor temperature is allowed to rise until 70⁰)

• Rsheath = 0.23Ohm/km, Rjacket = 0.1Ohm/km - these values are important for the 1 phase short circuit - the cable needs to be grounded every 5km - 10km (sheath and jacket connected) as

to limit the voltage on the sheath - submarine cables will have an interconnection between armour and sheath each

5km made in the factory

Further technical cable data:

Table 18 - Electrical specifications of some HVDC cables

Main suppliers at this moment are:

• NKT, Germany • LS, South Korea • Prysmian, Italy • Hellenic, Greece

Cable characteristic Unit ALU 800m2 ALU 1400mm2 ALU 1200m2 ALU 2500mm2 Cu 2500mm2 Nominal voltage kV ±200 ±200 ±320 ±320 ±400 DC-resistance conductor 20 degrees Ohm/km 0.0221 0.0129 0.0151 0.0073 DC-resistance conductor 70 degrees Ohm/km 0.0264 0.0154 0.0181 0.0087 0.0073 Maximum short circuit current conductor (1s) kA 92 161 138 287 Maximum short circuit current metallic screen (1s) kA 16.6 22 29.9 40 Ampacity (DoB 2m / soil 15 degrees / soil 0.7Km/W) A 1105 1505 1336 2030

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• Nexans, Sweden • Chinese suppliers upcoming (ZZT)

7.4.3 Installation

The installation of HVDC cables can be done in several ways if the known topology has been chosen.

Table 19 - Installation configurations of HVDC cables

Some considerations:

• to have the two current conducting paths bundled, will give the lowest ecological footprint (spatial, magnetic field) but is impacting negatively the ampacity as the cables heat up (each other)

• bundles of 2 cables is not ‘round’ and less easy to process, so adding the (single) metallic return is beneficial

• split laying of 2 HVDC cores (including a metallic return path per core) is giving the highest availability and possibility to repair when the second circuit is still functioning

Further reference is made to the installation of HVAC cables.

7.4.4 Costs

7.4.4.1 CAPEX

As the market is reluctant to supply information (except for projects), the data available is minimal. Table 19 shows the variable price per meter with a very large margin (-10% - +30%):

Voltage class [kV]

Cross section [mm2]

Conductor material [ALU/Cu]

Armour Volume Costs [€/m]

320 1800 Cu GS/Single MEDIUM 395 400 1600 Cu GS/Single MEDIUM 375 400 2500 Cu GS/Single MEDIUM 615

Table 20 - Costs for several HVDC cables

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The prices in Table 19 do not include:

• engineering and if needed additional type test or PQ tests • fixed (starting) costs for supply • installation of offshore joints / transition joints (high costs due to vessel availability) • termination and testing (T&T)

Further reference is made to HVAC EXC.

7.4.4.2 OPEX

Reference is made to EXC.

7.4.5 Lifetime

Just as HVAC cables, the PQ-testing of HVDC cables according to the TB852 (and included references) should be the guarantee for a long lifetime of XLPE HVDC cables. The fault conditions and heating cycles should reflect a lifetime of 30 years.

7.4.6 Availability

Numbers are not yet available based on a large database, CIGRE TB713 did a simulation based on a fictitious grid and came up with a forced outage of 2.2% for a bipole converter (including 200km cable).

The input consisted of:

• cable ±200kV or ±400kV: λ = 0.0007 failures / year / km MTTR: 1440h

MTTF (Mean Time To Failure) = 8760/ λ

Which results in a technical availability of A = MTTF / (MTTF + MTTR)

• cable ±200kV or ±400kV: MTTF = 62571 A = 97.75%

7.4.7 Losses

Losses of cables is easy to derive from the DC-resistance calculation. One could assume different DC- resistances with different power flows (between 20⁰ and 70⁰). Be aware that 2 cables are carrying current. See further 7.2.7.

On top of this additional losses can be expected caused by the ripple current (resulting in induced current in the sheath) and ripple voltage (resulting in a charging current from core to sheath). This will require a correct sheath bonding scheme as per 7.4.2 to be minimised.

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8 DECOMMISSIONING During the project development stage of an offshore wind farm the plan for how to decommission a wind farm is usually required as part of the permit application. Depending on the technology used there are various options and marine users, environment, pollution, and costs should all be considered. Most of the structures that are not buried can be easily removed by dismantling or cutting just below the seabed mudline. Once removed they are transported to shore and can be processed and recycled accordingly. The parts of the foundations that are below the seabed cannot be removed without disturbing the seabed and surrounding environment. This process can become expensive and risky depending on how far below the mudline you want to go. If it does not pose an environmental or pollution risk, it is usually left.

Cables will be partially or fully removed but this depends whether the cable is buried on not. Buried cables do not pose a risk to marine users and have limited environmental or pollution impacts although this can depend on the cable technology adopted. The complete removal is considered to cause substantial damage and disruption to the seabed given the extensive length of the cables. There would be need for excavation to pull them out of the trench, and then cutting, which involve high costs. Leaving the cables in situ and well buried is therefore the best option suggested till date.19

19 https://www.researchgate.net/publication/309654822_Sustainable_Decommissioning_of_an_Offshore_Wind_Farm

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9 EXAMPLE GRID CONNECTION In this section we compare each high voltage technology to get a better understanding of their strengths and weaknesses. For comparison purposes a specific connection will be assessed for both technologies. This will be a top-level comparison using the information already discussed as well as making some assumptions.

To have an overview of both presented technologies (AC and DC), Table 20 shows a list of the high- level pro’s and con’s.

AC-technology DC-technology (VSC)

Pro’s - many vendors of equipment / many engineering firms - very mature technology (lifetime phase: lowering costs) - experience on onshore grids available with TSO’s - intermediate compensation can extend distances - all phenomena and their mitigations are known - high robustness / availability

- low(er) losses above a certain transport level and distance - high level of grid supporting reactive power - availability can be improved by redundant IGBT set-up or chosen topology - very modular so transport power can increase with same technology

Con’s - over long distances less available ampacity / high losses due to capacitive currents - skin effect having low gain in higher cross sections of cables

- only 3 major vendors of equipment - in general high(er) costs/MW (CAPEX) - technology still improving (lifetime phase: higher robustness/ improving components) - due to sensitive devices (IGBT) lower robustness / lower availability (higher OPEX)

Table 21 – Pro’s and Con’s of AC and DC

For comparison purposes a specific connection will be assessed for both technologies.

General information:

• transport power: 1000MW (PMAX) • distance from onshore land station: 50km • seabed temperature: 10⁰C • depth of burial (DoB) of EXC: 2m • frequency: 50Hz • IAC not considered as equal for both • Mvar requirement: cos phi = 0.95 (Q = 0.33pu Pmax), can be supplied by onshore

components or turbines (not considered in losses or ampacity calculations)

AC:

• 220kV • 1000MW leading to 2624A • symmetrical compensation (assuming cable capacitance is 0.2μF/km): 400A/cable and

152Mvar (76Mvar reactor on each side) • total 962A leading to 3 HVAC cables of 1200ALU SS (50%) and 1200 ALU GS (50%) • 3 separate small OSS with one transformer per OSS (no redundancy) • land station without STATCOM

DC

• bipole arrangement • ±320kV • 1000MW / 320kV / 2 = 1562A, leading to 2 HVDC 1400mm2 Cu XLPE cables

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• for comparison the AC collection system is included in the OSS

Below a comparison of the two options where it must be noted the losses are quite high and include cables and both onshore and offshore substations:

OSS [M€]

EXC proc. [M€]

EXC inst. [M€]

ONSS [M€]

Total [M€]

OPEX/y [k€]

Losses 100% P [%]

AC 214 71.6 35 60 381 2744 3.1 DC 640 39.5 25 150 855 7900 2.8

Table 22 – Comparison of several parameters for AC and DC of 1000MW

In general it is stated that above 1GW and more than 100km the DC option would be preferred, as this should also consider the difference in losses during lifetime when corrected for the different power bins (wind profile) of the OWF. This business case can although be challenged with intermediate compensation platforms and hence a project specific assessment should always be carried out each time.

Table 22 shows the TRL’s for the HV technology described in this report. AC technology up to now has been widely adopted in the offshore wind market and is therefore a mature technology scoring nine in all cases. DC technology for offshore wind farms exists but it is still a maturing market. As more wind farms are built further away from shore and interconnectors become more common, so will the technology mature and price decrease.

Equipment Solution TRL

Offshore substation

HVAC 9

DC – VSC (all poles) 8

Meshed DC – VSC (all poles) 6

Land station HVAC 9

DC – LCC 9

DC – VSC (all poles) 8

Export cables

AC - XLPE 9

DC – Mass impregnated 9

DC – XLPE 9

DC – PP 6

Table 23 - Different TRL of related solutions

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10 ANNEXES

10.1 Technology Readiness Level

Table 23 describes the technology readiness level scale. This catalogue has focussed on technology with a level of 5 or greater.

Table 24 - Different Technology Readiness Levels20

10.2 Raw Material Costs

In this section we will briefly state the main raw materials that are used in the construction of an offshore wind farm. Prices for these material can heavily influence the final price of certain products. Typically suppliers will include clauses in the procurement contract that allow the final price to be subjective to current raw material prices.

Steel

The substation, foundations, WTG tower section and cables all use steel as a primary material. Steel prices have seen a sharp increase over the last year, seeing 5 year highs in May and close again in October 2021. As an example the Hollandse Kust Noord (759MW) platform jacket foundation weighs 2100 tonnes. On a platform a 400MW transformer can weigh 92 tonnes (tank, radiator & pipes). These examples give a good indication of the amount of steel that is required during an offshore wind project.

Copper

All electrical components will use copper due to its conductive properties. The WTG generator especially direct drive types, platform transformers (42t for 400MW) and inter array and export cables all rely heavily on the material. Export cable lengths can go from near shore 5km up to hundreds of km’s in distance for interconnectors between different platforms and countries. Copper saw the same sharp increases as steel and continues high.

20 HORIZON 2020 – WORK PROGRAMME 2014-2015

Project no.: 2021_0067

Employer: AS Augstsprieguma tikls

Elering AS

Consultant Skepast&Puhkim OÜ

Laki põik 2, 12915 Tallinn

Telefon: +372 664 5808; e-post: [email protected]

Registrikood: 11255795;

Date 17.12.2021

RIGHT-OF-WAY STUDIES ON THE

MAIN LAND ROUTE CORRIDORS

Final report

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Version 3

Date 17.12.2021

Authors: Anni Konsap, Kati Kraavi, Sander Lõuk, Raivo Damkevics

Photo credits: Sven Zacek

Project no. 2021_0067

SKEPAST&PUHKIM OÜ

Laki põik 2

12915 Tallinn

Registrikood 11255795

tel +372 664 5808

e-mail [email protected]

www.skpk.ee

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Contents

Introduction ..................................................................................................................... 4

1. Description of the methodology .................................................................................... 5

2. Route description ......................................................................................................... 7

2.1. Criteria for route description ........................................................................................... 7

2.2. Route descriptions ........................................................................................................ 8

2.2.1. Possible routes from Lihula substation .......................................................................... 8

2.2.2. Possible routes from Sindi substation .......................................................................... 10

2.2.3. Possible routes from Kilingi-Nõmme substation ............................................................ 11

2.2.4. Possible routes from Aloja substation .......................................................................... 12

2.2.5. Possible routes from Tume substation ......................................................................... 13

2.2.6. Possible routes from Dundaga substation .................................................................... 14

2.2.7. Possible routes from Ventspils substation .................................................................... 16

2.2.8. Possible routes from Uzava substation ........................................................................ 17

3. Criteria for route comparison ..................................................................................... 19

4. Comparison of alternatives for route corridors ........................................................... 22

4.1. Presentation of results ................................................................................................. 22

5. Comparison of alternatives for mainland route corridors ............................................ 23

5.1. Corridor alternatives from Aloja substation ..................................................................... 23

5.1.1. Technical criteria ...................................................................................................... 24

5.1.2. Environmental criteria ............................................................................................... 25

5.1.3. Socioeconomic criteria .............................................................................................. 27

5.1.4. Preferred corridor alternative for Aloja substation ......................................................... 27

5.2. Corridor alternatives from Dundaga substation ............................................................... 28

5.2.1. Technical criteria ...................................................................................................... 28

5.2.2. Environmental criteria ............................................................................................... 29

5.2.3. Socioeconomic criteria .............................................................................................. 30

5.2.4. Preferred corridor alternative for Dundaga substation ................................................... 31

5.3. Corridor alternatives from Tume substation .................................................................... 32

5.3.1. Technical criteria ...................................................................................................... 32

5.3.2. Environmental criteria ............................................................................................... 33

5.3.3. Socioeconomic criteria .............................................................................................. 34

5.3.4. Preferred corridor alternative for Tume substation ........................................................ 34

5.4. Corridor alternatives from Uzava substation ................................................................... 35

5.4.1. Technical criteria ...................................................................................................... 37

5.4.2. Environmental criteria ............................................................................................... 38

5.4.3. Socioeconomic criteria .............................................................................................. 39

5.4.4. Preferred corridor alternative for Uzava substation ....................................................... 40

5.5. Corridor alternatives from Ventspils substation ............................................................... 41

5.5.1. Technical criteria ...................................................................................................... 41

5.5.2. Environmental criteria ............................................................................................... 43

5.5.3. Socioeconomic criteria .............................................................................................. 43

5.5.4. Preferred corridor alternative for Ventspils substation ................................................... 43

5.6. Corridor alternatives from Lihula substation ................................................................... 45

5.6.1. Technical criteria ...................................................................................................... 45

5.6.2. Environmental criteria ............................................................................................... 45

5.6.3. Socioeconomic criteria .............................................................................................. 45

5.6.4. Preferred corridor alternative for Lihula substation ....................................................... 45

5.7. Corridor alternatives from Sindi substation ..................................................................... 45

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5.7.1. Technical criteria ...................................................................................................... 45

5.7.2. Environmental criteria ............................................................................................... 45

5.7.3. Socioeconomic criteria .............................................................................................. 45

5.7.4. Preferred corridor alternative for Sindi substation ......................................................... 45

5.8. Corridor alternatives from Kilingi-Nõmme substation ....................................................... 45

5.8.1. Technical criteria ...................................................................................................... 45

5.8.2. Environmental criteria ............................................................................................... 45

5.8.3. Socioeconomic criteria .............................................................................................. 45

5.8.4. Preferred corridor alternative for Kilingi-Nõmme substation ........................................... 45

6. Analyses of the most suitable spatial planning and impact assessment procedure for

planning the route .......................................................................................................... 46

6.1. Latvia ........................................................................................................................ 46

6.2. Estonia ...................................................................................................................... 47

Annexes

Annex 1. Online application with spatial data:

https://gis.skpk.ee/portal/apps/MapSeries/index.html?appid=e55f17b56ac74c38a68702

31f9238bd4 (version dated 17.12.2021)

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Introduction

This report gives an overview of the work to be done to determine the main land route corridors of

the electricity transmission grid from Lihula, Sindi and Kilingi-Nõmme substations in Estonia and from

Ventspils, Dundaga, Tume, Užava and Aloja substations in Latvia toward the Baltic Sea and an

overview of the initial corridor descriptions. This report is the final report for right-of-way studies on

the main land route corridors and presents designing of alternatives for corridors based on the

methodology, analysis to identify the most appropriate route corridors based on data available from

public sources, presents options for preferred corridors based on comparative criteria and gives

recommendations for future processes.

The final alternatives of the route corridors and their suitability must be specified during public

procedure within an inclusive (planning) process and a preparation of a detailed impact assessment.

During this, data used (eg areas with building design conditions, land use, etc.) during the initial

analyses must be updated so that the final conclusions drawn are appropriate and applicable.

An integral part of this analysis is an online application with spatial data and the results of the

analyses.

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1. Description of the methodology

The following methodology gives an overview of the work to be done to determine the main land

route corridors of the electricity transmission grid in Estonia from Lihula, Sindi, Kilingi-Nõmme and

in Latvia from Ventspils, Dundaga, Tume, Užava and Aloja substations toward the Baltic Sea. The

aim of the transmission grid is to create necessary preconditions for an offshore wind park to be

planned in close cooperation of Estonia and Latvia.

Figure 1. Substations of Latvia and Estonia and area of interest for possible route

corridors.

In the course of the work, it is necessary to describe possible alternatives for the route corridors (see

paragraph 2), assess their initial suitability and create a preference for the most suitable route

corridor. Among other things, the transition points of the underground cable to the overhead cable

(coming from sea to land) must be defined.

The width of the corridor to be sketched and analysed is 120 meters. The width consists of the

protection zone of the high voltage line, which is 40 meters on both sides of the route axis (see

Figure 2) and a buffer zone of 20 meters on both sides of the protection zone, giving the necessary

room for adjusting the corridor in the next steps of the planning process.

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Figure 2. Description of route corridor with protection and buffer zones.

Exclusion method is used to describe possible route corridors - exclusion of unsuitable areas based

on agreed criteria (see Chapter 1.1.). This results in areas where potential corridors could be located.

Within these areas, route corridors are outlined, which then are compared based on qualitative and

quantitative criteria (see Chapter 1.2.).

As a result of the comparison of route corridors, preferences regarding route corridors are formed.

As a result of the work, the preference for the most suitable route corridor location is presented from

each substation, which needs to be supplemented and specified in the subsequent planning and

impact assessment process.

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2. Route description

2.1. Criteria for route description

The following selection criteria were used as the exclusion method for sketching the corridors:

• No residential or public buildings within the corridor and 100 meters from the edge of the

corridor.

• No auxiliary and industrial buildings within the corridor.

• The route corridor must not pass through a densely populated area.

The criteria may be specified as a result of further drafting of the corridors. If no other

alternatives can be outlined or the densely populated area proves to be the most appropriate,

the possibility of constructing an underground cable through the densely populated area should

be considered.

• The route corridor must not pass through mining allocations.

• The route corridor must not pass through cemeteries.

• The route corridor must not pass through milieu areas.

The criteria may be specified as a result of further drafting of the corridors. If no other

alternatives can be outlined or the milieu area proves to be the most appropriate, the possibility

of constructing an underground cable through the milieu area should be considered.

• No cultural monuments and their protection zones within the corridor.

• No churches and shrines within the corridor.

• The corridor must not overlap with habitats of species in protection categories I and II.

In Natura bird areas and at a distance of 100 meters from them, the underground cable corridor is

considered as a route corridor. The route corridors shown in this work, which pass through (incl. as

an underground cable) or are adjacent to Natura sites, must be assessed in the next stages of the

impact assessment of the route corridor. Based on this, it may be necessary to shift the route

corridors, relocate or take other necessary measures.

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2.2. Route descriptions

2.2.1. Possible routes from Lihula substation

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Name Description

Lihula-L3-1 Line can be placed inside existing 110 kv line corridor in the Lihula part of the corridor but the existing corridor is not wide enough for 330 kv corridor and it is situated in the protection zone of residential buildings

Lihula-L3-2 Ca 2 km of the line corridor can be placed inside the existing 110 kV line corridor. Corner posts can be placed nead existing roads and on state owned/municipal land.

L3-Pivarootsi Line corridor is very close to and runs parallel to Natura 2000 bird area.

Cable-Pivarootsi Transmission can be built near existing road, 250m from coastline and from Natura 2000 area

L3-Nõmme Corner posts can be built near existing road.

Cable-Nõmme Transmission can be built near the existing road.

Lihula-Kulli 65 km can be placed inside existing 330 kV overhead line corridor. Corridor is situated between 2 Natura 2000 bird areas

Cable-Kulli 1 One of the ways to go underground in the Kulli control point

Cable-Kulli 2 One of the ways to go underground in the Kulli control point

Cable-Kulli 3 One of the ways to go underground in the Kulli control point

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2.2.2. Possible routes from Sindi substation

Name Description

Pärnu-P1.1 Line corridor is as straight as possible but crosses existing 100 kV line corridor and 5 km of the corridor will be placed within an active mining area.

Pärnu-P1.2 One of the alternatives for crossing a mining area. Line crosses existing 110 kV electrical line many times. Line corridor avoids residential building protection zones, but the impact to the airport landing zone must be evaluated.

P1-P2 This part of a line corridor is avoiding residential building protection zones as much as possible, line corridor is crossing existing 110 kV electrical line

P2-Lao Line is crossing an active mining area. Corner posts can be placed near existing road on a state-owned land

P2-P3-Lao Corner posts can be placed near an existing road. Corridor is not crossing any protected areas. Corridor is between two Natura 2000 areas and an alternative to crossing mining areas.

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P2-P3-Kavaru Corner posts can be placed near an existing road. Corridor is not crossing any protected areas.

Cable-Lao Transmission area can be built on non-private land, near existing road.

Cable-Kavaru Transmission area can be built on non-private land, near existing road.

Pärnu-Reiu Approx 46 km of existing 330 kV overhead line corridor can be used. Many corner posts can be placed near the existing road on a land that is state-owned.

Cable-Reiu Cable must be built under high density residential area

2.2.3. Possible routes from Kilingi-Nõmme substation

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Name Description

Kilingi-Nõmme- Võiste

33,4 km of existing 330 kV overhead line corridor can be used. Many corner posts can be placed near the existing road on a land that is state-owned.

Cable-VõisteCable must be built under high density residential area

Kilingi-Nõmme- Häädemeeste

Approx 3,3 km can be placed inside existing 330 kV line corridor. Corridor is near Natura 2000 protection zone. Transition point can be built near existing road. Many corner posts are near existing road.

Cable- Häädemeeste

Cable must be built under high density residential area

Cable-Kabli 600 m from coastline, transmission can be placed near an existing road

2.2.4. Possible routes from Aloja substation

Name Description

Aloja-Salacgriva 1

Mostly parallel to existing 110 kV electricity line. Overhead to cable transmission point is outside high density residential area.

Aloja-Salacgriva 2

Approx 56 km of the 330 kV line corridor can be placed parallel to and existing 110 kV corridor. Corner posts are near an existing road. Transmission to underground cable is near the location shown in Latvian MSP and is not in conflict with Natura 2000 areas and is away from existing high density residental areas.

Aloja- Salacgriva(MSP5)

Corridor alternative as planned in Latvian MSP. Mostly parallel to an existing 110 kV line corridor.

Cable-Svetciems 1,2 km from coastline, transmission can be placed near an existing road

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Cable- Salacgriva(MSP5)

Corridor alternative as planned in Latvian MSP. The corridor passes through a high density residental area.

2.2.5. Possible routes from Tume substation

Name Description

Tume-Apsuciems 1

Approx 8,5 km can be placed inside an existing 330 kV Line corridor. Corner posts are near an existing road.

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Tume-Apsuciems 2

Corridor is crossing an existing 110 kv line corridor, the effect of an airport must be assessed, many corner posts can be placed near an existing road.

Cable - Apsuciems

290 m from coastline, corner posts remain near existing road.

2.2.6. Possible routes from Dundaga substation

Name Description

Dundaga- MSP4original

Corridor alternative as planned in Latvian MSP. On the coast, the corridor follows an existing road. Near the Dundaga station the corridor is drawn straight through a high-density residential area.

Dundaga-MSP4 The corridor is specified according to protection zones of buildings, so the corridor can be as straight as possible. Electrical line near Dundaga can mostly be placed

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inside the existing 330 kV overhead line corridor. Natura 2000 area is 9 km from the coast; therefore the underground part is relatively long.

Dundaga- Jaunciems

Electrical line near Dundaga can mostly be placed inside the existing 330 kV overhead line corridor. Natura 2000 area is 5 km from the coast, therefore the underground part is relatively long.

Dundaga- Purciems

Electrical line near Dundaga can mostly be placed inside the existing 330 kV overhead line corridor.

Dundaga- Mazirbe

Electrical line near Dundaga can mostly be placed inside the existing 330 kV overhead line corridor. Natura 2000 area is 6 km from the coast, therefore the underground part is relatively long.

Cable-Purciems Touches Natura 2000 areas on sea.

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2.2.7. Possible routes from Ventspils substation

Name Description

Ventspils-MSP3- 1

Line follows existing 110 kv corridor, which must be widened. The extension might not be possible because of the protection zones of buildings.

Ventspils-MSP3- 2

1,7 km from the Ventspils station, can be placed inside existing 330 kV electrical corridor. New corner posts can be placed near the existing roads, no Natura 2000 area on the coastline. Corridor is crossing an existing 110 kV corridor, to describe it as straight as possible.

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2.2.8. Possible routes from Uzava substation

Name Description

Cable-Uzava Corridor is close to a corridor planned in the Latvian MSP corridor, but does not cross a protection zone of buildings. 1,5 km passes through a Natura 2000 area.

Cable-Vendzavas Ca 1 km from coastline, corner posts near existing road

Cable-Osvalki 230 m from coastline, corner posts near existing road

Cable-Uzava (MSP2)

Original line from Latvian MSP, 1,8 km is inside Natura 2000 area.

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Uzava-Uzava (MSP2)1

Corridor alternative as planned in Latvian MSP. This corridor needs to be specified due to the station location and building protection zones.

Uzava-Uzava (MSP2)2

Line corridor is very close to Natura 2000 area, corner posts can be placed near the existing road. The transmission on the coastline is as planned in Latvian MSP

Uzava- Vendzavas

Line corridor is very close to Natura 2000 area, corner posts can be placed near the existing road.

Uzava-Osvalki 4 km of existing 330 kV overhead cable corridor can be used. The rest of the corridor goes around Natura 2000 area.

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3. Criteria for route comparison

The results of the comparison of route alternatives described in paragraph 2 are compared and

presented by groups of comparison criteria:

• Socio-economic criteria

o Residential land plots with residential buildings (ha)

Takes into account the extent (ha) to which the route corridor passes through the residential

land. The less residential land passed the better.

o Residental land plots without residental buildings (ha)

Takes into account the extent (ha) to which the route corridor passes through residential land.

The choice of the route corridor is based on the principle that any passage of residential land

is worse than passing land with other intended land use.

o Residential or public buildings

The location of the route corridor closer than 100 m from residential buildings is excluded.

When comparing, the number of dwellings up to 250 m from the axis of the corridor shall be

assessed. An alternative is preferred in which there are fewer dwellings in the vicinity of the

corridor or they are located further away from dwellings in the vicinity of other alternatives.

o Valuable landscapes, places with beautiful views and road sections

Takes into account the extent to which (length, m) the route corridor passes through areas of

valuable landscapes determined by county and general plans. It is also assessed that in many

cases the route corridor may interfere with the visibility of places with a beautiful view marked

in the county and general plan.

o Passage of recreational areas (m)

Takes into account the extent to which (m) the alternative route corridor passes through the

recreation areas determined by the general plans or other public information. An alternative

that does not pass through recreation areas or passes through them to a lesser extent is

preferred over other alternatives.

o Deforestation of private forests (ha)

Takes into account the area of private forests to be deforested (ha). It is based on the principle

that a private forest in the protection zone must be compensated to the owner. The longer the

route corridor passes through a private forest, the less suitable the alternative is.

o Deforestation of state forests (ha)

Takes into account the area of deforested state forest (ha). When calculating the forest area,

it has been taken into account whether the route corridor is located on the route of the existing

line (smaller clearable area) or in a new route corridor (larger clearable area). It is based on

the principle that the state forest remaining in the protection zone must be compensated to

the state. Passing through a state forest is preferable to passing through a private forest, as

it is estimated that it is easier and cheaper to reach agreements.

o Passage of mineral deposits (m)

Takes into account the extent to which (length, m) the alternative route corridor passes

through mineral deposits. The excavation of mineral resources must not be hindered in the

area of the deposit, therefore the mineral resources must be mined in advance upon

construction there. Mining is a separate process that increases the cost of time and money.

o Agricultural land use (ha)

The location of the route on agricultural land is preferred over forest land.

o Land plots with established detailed plans

A route alternative that does not pass through areas with a detailed plan is preferred.

o Land plots with building design specifications

A route alternative that does not pass through areas with issued design conditions is preferred.

o Privately owned cadastral units (ha)

Smaller area of privately owned land impacted by the corridor is preferred.

o Publicly owned cadastral units (ha)

Publicly owned land is preferred.

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Additional criteria which are initially exclusive, but which must be considered in the absence of other

viable alternatives:

o Densely populated areas

Takes into account the extent to which (length, m) the route corridor passes through densely

populated areas determined by the general plans. When densely populated areas cannot be

avoided, an underground cable must be considered.

• Environmental criteria

o Impact on protected areas (Natura 2000 sites, protected areas, conservation

areas)

Impact on national parks, nature and landscape protection areas has been assessed if the

route corridor passes through it or passes close to it. A precondition for the selection of

alternatives is the compliance of the proposed activity with the protection rules and the

management plan. The less the alternative relates to the protection objective pursued, the

more prefered it is.

o Species in protection category III

The impact on the habitats in the protection category III will been assessed. The less the

alternative is exposed to habitats in category III, the more preferred the alternative.

o Other protected environmental objects

Impacts on protected environmental objects (excluding protected areas) have been

assessed, such as valuable habitats, individual objects without protection categories, etc.

The less the alternative comes into contact with the object under protection, the more

preferred the alternative is.

o Fragmentation of green network

The impact on the green network areas due to the deforestation of the route corridor will be

assessed. The less the alternative reduces green corridors, the more preferred it is.

o Projected protected species and protected areas

The impact on projected protected species and protected areas will be assessed. The less the

alternative is in contact with the habitat or protected area, the more preferred it is.

• Cultural criteria

o Cultural heritage (cultural heritage sites, rural heritage, military heritage, etc.)

A route corridor with as few cultural heritage sites as possible is preferred.

o Areas and objects based on local protection

A route corridor with as few local protection sites and areas as possible is preferred.

Additional criteria which are initially exclusive, but which must be considered in the absence of other

viable alternatives:

o Milieu areas

Takes into account the extent (length, m) of the route corridor passing through the areas of

milieu areas determined by the general plans. Passage through milieu areas is generally

excluded. If there are no other alternatives, an underground cable in milieu areas must be

considered.

• Technical criteria

o Length of the corridor (km)

The route corridor that is the shortest is preferred.

o Cost of the corridor (eur)

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The cost of the corridor is directly related to the length of the corridor and the length of the

underground cable and overhead line in the corridor. The cost of building a 1 km overhead

line is estimated at 425,000 euros, and the cost of an underground cable is 1.2 times higher.

o Complexity of construction and maintenance

The need to build anchor masts is considered. It is estimated that an anchor mast must be

located every 5 kilometers and an access road must be provided.

o Use of existing corridors (m)

A route corridor that uses the existing route corridor for as long as possible is preferred.

o Intersections with existing infrastructure elements

The route corridor with the smallest number of intersections with existing infrastructure

elements is preferred.

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4. Comparison of alternatives for route corridors

The corridors will be compared on a scale of "strong preference", "weak preference" and "non-

preference" within each criterion. The same scale is used to give an overall grade to a group of

criteria. Preferences are marked as follows:

STRONG PREFERENCE Best route corridor in terms of comparable criteria.

WEAK PREFERENCE There are disadvantages compared to the strongly preferred route

corridor, but it is still recommended.

NON-PREFERENECE Non-prefered route corridor in terms of comparable criteria.

NO PREFERENCE There are no significant differences between corridors in terms of

criteria and no preference is created.

Both quantitative and qualitative (based on expert opinion) methods will be used to form the

preference. In case of quantitative criteria (eg number of dwellings in the corridor), the preference

is based on numerical indicators - eg a smaller number is better. In the case of qualitative criteria,

the basis for the formation of preference is an expert assessment (if the assessment is possible

considering the level of accuracy of given work). For all criteria, preference is formed through

comparing route alternatives to each other.

The following principles will be considered when forming the final preference:

• If all corridors are equal according to the criterion, no preference will be given to any of the

corridors.

• The technical preference has been developed in cooperation with the Customers.

• The construction cost is approximate and is presented according to the level of detail of

current study.

• In case of environmental criteria, a strong preference means a situation where, due to

significant effects in one or more of the criteria, the implementation of the alternative has

more negative effects.

• For natural environment criteria, low preference means a situation where both options are

acceptable, but one option is preferred due to either smaller negative effects or larger

positive effects.

• The final preference is formed through summing and weighing the preferences of different

criteria.

4.1. Presentation of results

The outputs of the work are:

• A written report explaining the corridor description criteria, the comparison results, the

preferred corridor and proposals for upcoming planning and impact assessment process.

• Map layers with alternative route corridors and data collected during the study that are not

available in public databases.

• Schematic maps in .pdf format, for example described route corridors, extracts from the

vicinity of densely populated areas, etc.

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5. Comparison of alternatives for mainland route

corridors

The following alternative comparisons are presented without data and information on cadastral units.

The results of route comparisons are updated, after data is received from Latvian State Land Service

(expected 7th January 2022).

5.1. Corridor alternatives from Aloja substation

There are three corridor alternatives compared from Aloja substation:

• Aloja – Salacgriva MSP corridor sketched in Latvian MSP.

• Aloja – Salacgriva 1 sketched in this report.

• Aloja – Salacgriva 2 sketched in this report.

Figure 3. Corridor alternatives compared from Aloja substation

From Salacgriva, two possible cable directions to the sea are possible – to Svetciems or to Salacgriva.

The latter is also drawn in Latvian MSP. The final direction depends on the corridor alternative chosen.

Independently, the endpoint for the corridor (and starting point for the cable) in Svetciems is

preferred, because it is away from densely populated areas and Natura 2000.

Figure 4. Cable directions from Salacgriva to the sea.

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5.1.1. Technical criteria

According to the technical criteria the most preferred corridor is the one drawn in Latvian MSP – Aloja

– Salacgriva MSP alternative combined with Aloja – Salacgriva 1 corridor for cable transmission.

Criteria Aloja-Salacgriva 1 Aloja-Salacgriva 2 Aloja-Salacgriva

(MSP5)

Length of the corridor 33,41 32,53 32,72

The number of possible turns in

the corridor 15 6 22

The need to build anchor masts 1 5 0

The cost of the corridor (eur)1 14200249 13827258 13906426

Length of excisting 110 and 330

kV corridors used 27,6 5,4 29,8

Number of crossings with

other engineering structures 24 28 27

Number of crossings with local

roads 21 26 24

Number of crossings with state

roads 3 2 3

Number of crossings with existing

electricity lines 0 0 0

The main conclusions from route comparison are following:

• Aloja – Salacgriva MSP corridor is shortest and therefore has the lowest building cost.

• Aloja – Salacgriva MSP corridor follows the existing 110 kV corridor approx. 30 km (overall

length of the corridor approx. 32 km). Although the existing corridor is stongly preferred, the

corridor runs through residential areas, where proximity of houses to the corridor becomes

very narrow (see Figure 3).

1 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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Figure 5. Narrow conditions between residential buildings for Aloja-Salacgriva

alternatives in existing 110 kV corridor

• Aloja-Salacgriva MSP corridor has more turns than Aloja-Salacgriva corridors 1 and 2,

increasing its building cost.

• In terms of crossings with existing engineering structures, the corridor alternatives are quite

similar. Aloja-Salacgriva 1 gets a small advantage for number of crossings with roads.

Even though the Aloja-Salacgriva MSP alternative has more turns than other alternatives, and

therefore might be more expensive, the landscape and the visual impact for these locations is already

impaired by the existing overhead line, making it supposedly more acceptable for local residents to

build a parallel overhead line to an existing corridor, rather than clearing forests or other land

elsewhere.

In future planning and building, the Aloja - Salacgriva MSP corridor together with Aloja – Salacgriva

1 corridor should be explored. The Aloja – Salacgriva 1 corridor follows also the existing 110 kV

corridor but ends in Svetciems instead of Salacgriva. In Svetciems the transmition to cable is more

preferred as it is away from densely populated areas (Salacgriva).

5.1.2. Environmental criteria

For environmental criteria, preference is given to Aloja-Salacgriva 2 corridor alternative.

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Criteria Aloja-Salacgriva 1 Aloja-Salacgriva 2 Aloja-Salacgriva

(MSP5)

Conflicts with Natura 2000 area

Crosses Natura 2000

area. New possible corridor is near

existing 110 line

corridor, which is

inside Natura 2000 area.

no

Crosses Natura 2000

area. New possible corridor is near

existing 110 line

corridor, which is

inside Natura 2000 area.

Conflicts with protected areas Completely inside

protected site

Completely inside

protected site

Completely inside

protected site

Number of habitat sites in conflict

with the corridor 39 45 45

Trees under protection in the

corridor 2 0 2

Number of cultural monuments in

the corridor 2 2 3

The main conclusions from route comparison are following:

• Aloja – Salacgriva MSP alternative and Aloja – Salacgriva 1 alternative, following the existing

110 kV corridor towards Salacgriva and the sea, extend into Natura 2000 areas. Even though

it is an existing corridor, building a new overhead line in Natura 2000 area might not be in

accordance with the protection goals of the Natura site. In future building and planning

processes, should these alternatives be chosen as preferred corridors, impacts on Natura

2000 must be assessed and if necessary, the corridor be moved north from the Natura 2000

site (see Figure 6). Aloja – Salacgriva 2 alternative has no conflicts with Natura 2000 areas.

Figure 6. Possible conflicts with Niedraju-Pilkas Natura 2000 site (light blue polygon) for

Aloja - Salacgriva MSP and Aloja - Salacgriva 1 alternatives in existing 110 kV corridor

(yellow line).

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• For other compared criteria, the differences between corridor alternatives are minor and can

be mitigated through necessary measures in the next steps of the planning and design

process.

5.1.3. Socioeconomic criteria

For socioeconomic criteria, preference is given to Aloja-Salacgriva MSP corridor alternative.

Criteria Aloja-Salacgriva 1 Aloja-Salacgriva 2 Aloja-Salacgriva

(MSP5)

Deforestation of forests

(total) 703655,56 2263549,77 606189,5

Deforestation of private forests 373491,44 258020,39 272596,33

Deforestation of State-owned

forest (LVM) 330164,12 2005529,38 333593,17

Passage of mineral deposits (m2) 0 0 0

The main conclusions from route comparison are following:

• Overall need for deforestation for Aloja – Salacgriva 2 corridor alternative in comparison to

Aloja – Salacgriva 1 and MSP alternatives are so extensive that the interplay between state-

owned and privately held forests does not play a role in the comparison results. More than

1,5 mil m2 of deforestation needs make Aloja – Salacgriva 2 alternative strongly not preferred

compared to other alternatives.

• For passage of mineral deposits, all corridors are the same.

5.1.4. Preferred corridor alternative for Aloja substation

For Aloja substation, the most preferred corridor is the one drawn in Latvian MSP – Aloja – Salacgriva

MSP alternative combined with Aloja – Salacgriva 1 corridor for cable transmission in Svetciems.

Figure 7. Preferred coridor alternative for Aloja substation

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The corridor follows the existing 110 kV line and causes narrow conditions in few places between

residential buildings and touches Natura 2000 site in the middle part of the corridor but can be

repaired through more detail planning and impact assessment procedures.

5.2. Corridor alternatives from Dundaga substation

There are five corridor alternatives compared from Dundaga substation:

• Dundaga MSP (original) corridor sketched in Latvian MSP.

• Dundaga MSP corridor sketched in Latvian MSP and specified in this report.

• Dundaga – Jaunciems sketched in this report.

• Dundaga – Mazirbe sketched in this report.

• Dundaga – Purciems sketched in this report.

Cable corridors are foreseen from Purciems, Mazirbe and Januciems because of Natura 2000 areas

on shore.

Figure 8. Corridor alternatives compared from Dundaga substation

5.2.1. Technical criteria

According to the technical criteria the most preferred corridor is Dundaga – Jaunciems.

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Criteria Dundaga- Jaunciems

Dundaga- Mazirbe

Dundaga MSP

(specified)

Dundaga MSP

(original)

Dundaga-

Purciems

Length of the corridor 15,46 17,33 35,88 32,9 19,15

The number of possible

turns in the corridor 4 3 9

Original MSP corridor on

coast is

unclear. 39

turns is not realistic.

4

The need to build

anchor masts 1 2 3 2

The cost of the corridor

(eur)2 6570500 7365250 15249000 13982500 8138750

Length of excisting 110

and 330 kV corridors

used

2,8 2,8 1,4 no 1,4

Number of crossings

with other

engineering

structures

10 9 13 17 9

Number of crossings

with local roads 10 8 12 15 8

Number of crossings

with state roads 0 1 1 2 1

Number of crossings

with existing electricity lines

no no no no no

The main conclusions from route comparison are following:

• Dundaga – Jaunciems alternative is most preferred in almost every comparison criteria – it

is the shortest possible corridor (even with the cable corridor from Jaunciems to sea),

therefore with the lowest cost, it is one of the straightest line with crossings with local roads

– no state roads or existing electricity lines.

• Dundaga – Jaunciems enables the use of existing 330 kV overhead cable corridor for approx.

3 km for the beginning of the corridor. The same applies for Dundaga – Mazirbe corridor.

• Dundaga – Mazirbe is the straightest line from Dundaga substation to the shore with 3 turns

for the corridor.

• The corridors drawn in Latvian MSP and specified with this report are both widely unpreferred

corridors – they are the longest, need most turns and have the highest number of crossings

with other engineering structures.

5.2.2. Environmental criteria

For environmental criteria, preference is given to Dundaga – Purciems corridor alternative.

2 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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Criteria Dundaga- Jaunciems

Dundaga- Mazirbe

Dundaga MSP

(specified)

Dundaga MSP

(original)

Dundaga- Purciems

Conflicts with

Natura 2000 area

174 m to the nearest

Natura 2000

area.

Line ends on

the border of Natura 2000

area and is

transformed

into cable.

33 098,97 m2 crossing

Natura 2000

area.

31 910,98 m2 crossing

Natura 2000

area

no

Conflicts with

protected areas <Null> <Null>

1

microreservati

on area,

Northern part inside

protected site.

1

microreservati

on area,

Northern part inside

protected site.

2

microreservati on area

Number of habitat

sites in conflict with

the corridor 41 23 212 179 30

Trees under

protection in the

corridor 0 0 2 5 1

Number of cultural monuments in the

corridor

<Null> <Null> 3 8 1

The main conclusions from route comparison are following:

• Dundaga – Purziems corridor alternative is the only corridor that does not have a conflict

with Natura 2000 areas, as Natura 2000 does not reach inland as widely as it does for corridor

alternatives in west.

• Dundaga – Jaunciems and Dundaga – Mazirbe corridors do not have direct conflict with

Natura 2000 areas, but transmission areas near Natura 2000 areas might result in negative

effects for Natura areas. These locations must be assessed in future planning and design

phases and if necessary, found mitigation measures for negative impacts.

• Corridors drawn in Latvian MSP go directly through Natura 2000 areas, which means they

are not preferred as corridors.

• In other criteria, Dundaga – Jaunciems and Dundaga – Mazirbe, get clear advantages as

conflicts with habitats and nature protection objects and areas are smallest. Latvian MSP

corridors (both original and specified) have high conflicts with habitats.

5.2.3. Socioeconomic criteria

For socioeconomic criteria, preference is given to Dundaga - Mazirbe corridor alternative.

Criteria Dundaga-

Jaunciems

Dundaga-

Mazirbe

Dundaga

MSP

(specified)

Dundaga

MSP

(original)

Dundaga-

Purciems

Deforestation of

forests (total m2) 2017665,2 1729009,49 2339403,79 2675132,28 2589987

Deforestation of private

forests 611265,85 346453,65 489425,12 582157,77 481752,9

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Deforestation of State-

owned forest (LVM) 1406399,36 1382555,85 1849978,66 2092974,51 2108233,867

Passage of mineral deposits (m2)

0 0 182 684,33 0 0

The main conclusions from route comparison are following:

• Overall need for deforestation for Dundaga - Mazirbe corridor alternative in comparison to

other alternatives are so extensive that the interplay between state-owned and privately held

forests does not play a role in the comparison results.

• For passage of mineral deposits, all corridors, except the specified Latvian MSP corridors, are

the same. The specified MSP corridor follows through a mineral deposit, making it a non-

preferred corridor based on socioeconomic criteria.

5.2.4. Preferred corridor alternative for Dundaga substation

For Dundaga substation, the most preferred corridor is Dundaga – Mazirbe corridor combined with

cable transmission in Mazirbe.

Figure 9. Preferred coridor alternative for Dundaga substation

The corridor follows the existing 330 kV line at the beginning of the corridor. The overhead line

transmits to a cable on the boarder of the Slitere National Park on the shore. Detail impact

assessment must be carried out at the next phases of planning and designing to fix the transmission

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place from overhead line to cable and minimize or exclude negative impacts to Slitere National Park.

This also includes assessment of visual impacts.

5.3. Corridor alternatives from Tume substation

There are two corridor alternatives compared from Tume substation:

• Tume-Apsuciems 1 sketched in this report (western corridor).

• Tume-Apsuciems 2 sketched in this report (eastern corridor).

Cable corridor is foreseen from Apsuciems to sea due to Natura 2000 area on shore.

Figure 10. Corridor alternatives compared from Tume substation

5.3.1. Technical criteria

According to the technical criteria the most preferred corridor is Tume-Apsuciems 1 alternative.

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Criteria Tume-Apsuciems 1 Tume-Apsuciems 2

Length of the corridor 15,46 17,33

The number of possible turns in the

corridor 17 10

The need to build anchor masts 0 0

The cost of the corridor (eur)3 6571403,4 7364499,3

Length of excisting 110 and 330 kV corridors used

8,4 no

Number of crossings with other

engineering structures 30 30

Number of crossings with local roads 27 27

Number of crossings with state roads 3 3

Number of crossings with existing

electricity lines no

Crossing with 110 kv -

2 places and 330 kv -

1 place

The main conclusions from route comparison are following:

• Tume - Apsuciems 1 alternative gets high preference mainly due to the possibility to use an

existing overhead line corridor for half the corridor alternative length – 8,4 km.

• Tume-Apsuciems 1 alternative is also shorter and does not cross with existing electricity

lines. Tume-Apsuciems 2 alternative crosses with 110 kV line twice and 330 kV line once.

• Tume-Apsuciems 1 alternative has more turns, but this is probably compensated by the

already impaired landscape, making it supposedly more acceptable for local residents to build

a parallel overhead line to an existing corridor, rather than clearing forests or other land

elsewhere.

5.3.2. Environmental criteria

For environmental criteria, slight preference is given to Tume-Apsuciems 1 corridor alternative,

mainly due to longer distance from the transmission area from Natura 2000 area.

Criteria Tume-Apsuciems 1 Tume-Apsuciems 2

Conflicts with Natura 2000 area 409 m to the nearest

Natura 2000 area.

61 m to the nearest

Natura 2000 area.

3 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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Conflicts with protected areas <Null> <Null>

Number of habitat sites in conflict with

the corridor 33 22

Trees under protection in the corridor 0 0

Number of cultural monuments in the corridor

1 monument site is partly in the corridor

<Null>

The main conclusions from route comparison are following:

• Tume-Apsuciems 2 corridor gets slight preference for conflicts with habitats and for not

having cultural monuments within the corridor.

• Natura 2000 is the biggest conflict for overhead lines, so the further the transmission area

from overhead line to cable, the higher the preference for the corridor. As no conflict with

Natura 2000 areas can be good, alternatives can not get high preference in environmental

criteria.

5.3.3. Socioeconomic criteria

For socioeconomic criteria, preference is given to Tume-Apsuciems 2 corridor alternative.

Criteria Tume-Apsuciems 1 Tume-Apsuciems 2

Deforestation of forests (total m2) 1439543 1031531

Deforestation of private forests 25077,71 120752,24

Deforestation of State-owned forest

(LVM) 1414465,6 910778,26

Passage of mineral deposits (m2) 0 0

The main conclusions from route comparison are following:

• Overall need for deforestation for Tume-Apsuciems 2 corridor alternative is more extensive

The interplay between state-owned and privately held forests does not play a role in the

comparison results.

• For passage of mineral deposits, all corridors are the same.

5.3.4. Preferred corridor alternative for Tume substation

For Tume substation, the most preferred corridor is Tume-Apsuciems 1 corridor combined with cable

corridor to sea.

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Figure 11. Preferred coridor alternative for Tume substation

Even though the alternative is not preferred for environmental and social criteria, the technical

criteria give definite preference to the corridor, mainly because of possibility to use existing overhead

line corridor in the existing environment. Detail impact assessment must be carried out at the next

phases of planning and designing to fix the transmission place from overhead line to cable.

5.4. Corridor alternatives from Uzava substation

There are four corridor alternatives compared from Uzava substation:

• Uzava – Uzava MSP original corridor alternative sketched in Latvian MSP.

• Uzava – Uzava MSP specified corridor alternative sketched in Latvian MSP.

• Uzava – Osvalki corridor alternative sketched in this report.

• Uzava – Vendzavas corridor alternative sketched in this report.

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Figure 12. Corridor alternatives compared from Uzava substation

Overhead line transmission areas to cables are possible in Osvalki, Vendzavas and Uzava. The latter

is also drawn in Latvian MSP. The final direction depends on the corridor alternative chosen.

Independently, the endpoint for the corridor (and starting point for the cable) in Uzava is not

preferred, because it follows through Natura 2000 area. In future building and planning processes,

should the overhead line alternatives ending in Uzava be chosen as preferred corridors, impacts on

Natura 2000 must be assessed.

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Figure 13. Cable directions from Uzava to the sea.

5.4.1. Technical criteria

According to the technical criteria the most preferred corridor is the one drawn in Latvian MSP and

also the one specified based on Latvian MSP.

Criteria Uzava-

Osvalki

Uzava-Uzava

MSP original

Uzava-Uzava MSP

specified

Uzava-

Vendzavas

Length of the corridor 14 9,11 9,27 10,6

The number of possible turns in

the corridor 3 1 3 3

The need to build anchor masts 1 1 0 <Null>

The cost of the corridor (eur)4 5950000 3871750 3939750 4505000

4 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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Length of excisting 110 and 330

kV corridors used

4,4 km of

existing line

corridor can be

used.

no no no

Number of crossings with

other engineering structures 7 11 10 12

Number of crossings with local

roads 6 10 9 11

Number of crossings with state

roads 1 1 1 1

Number of crossings with existing electricity lines

no no no no

The main conclusions from route comparison are following:

• Both corridor alternatives stemming from Latvian MSP are the shortest, so the cheapest

overall.

• The original MSP corridor alternative has the smallest number of turns, affecting the cost of

the corridor.

• Uzava – Osvalski corridor gets high preference due to the possibility to use existing line

corridor in the middle part of the corridor for approx. 4,4 km. As the corridor itself is much

longer than the alternatives stemming from Latvian MSP, the preference coming from

possible use of existing overhead line corridor, is questionable.

• Uzava – Vendzavas corridor is not strongly preferred in any criteria. The overall length of the

corridor is close to the MSP alternatives, but other criteria – such as turns of the corridor and

number of crossings – make it less preferable.

5.4.2. Environmental criteria

For environmental criteria, preference is given to original Latvian MSP corridor alternative.

Criteria Uzava-

Osvalki

Uzava-Uzava

MSP original

Uzava-Uzava

MSP

specified

Uzava-

Vendzavas

Conflicts with Natura 2000 area

Conflict with

Natura area.

Line goes

inside existing corridor.

71 m to the

nearest Natura

2000 area.

7 m to the

nearest Natura

2000 area.

41 m to the

nearest Natura

2000 area.

Conflicts with protected areas

1

microreserve,

7414 m2 conflict with

Natura 2000

area

<Null> 0 0

Number of habitat sites in conflict

with the corridor 6 5 6 13

Trees under protection in the

corridor 0 0 0 0

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Number of cultural monuments in

the corridor 0 0 0 0

The main conclusions from route comparison are following:

• Uzava-Osvalki corridor alternative, following the existing overhead line corridor towards the

sea, extend into Natura 2000 areas. Even though it is an existing corridor, building a new

overhead line in Natura 2000 area might not be in accordance with the protection goals of

the Natura site. In future building and planning processes, should these alternatives be

chosen as preferred corridors, impacts on Natura 2000 must be assessed and if necessary,

the corridor be moved north from the Natura 2000 site (see Figure 14). Other corridors do

not have clear conflicts with Natura areas.

Figure 14. Possible conflicts with Natura 2000 site (light blue polygon) for Uzava-Osvalki

alternative in existing 110 kV corridor (yellow line).

• For other compared criteria, the differences between corridor alternatives are minor and can

be mitigated through necessary measures in the next steps of the planning and design

process.

5.4.3. Socioeconomic criteria

For socioeconomic criteria, preference is given to Aloja-Salacgriva MSP corridor alternative.

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Criteria Uzava- Osvalki

Uzava-Uzava MSP original

Uzava-Uzava MSP

specified

Uzava- Vendzavas

Deforestation of forests

(total) 767459,23 0 0 219516,3

Deforestation of private forests 18664,46 0 0 5043,1

Deforestation of State-owned

forest (LVM) 748794,77 0 0 214473,2

Passage of mineral deposits (m2) 0 0 0 0

The main conclusions from route comparison are following:

• Overall need for deforestation is absent for MSP alternatives so they have a clear preference

compared to other corridors.

• For passage of mineral deposits, all corridors are the same.

5.4.4. Preferred corridor alternative for Uzava substation

For Uzava substation, the most preferred corridor is the original corridor drawn in Latvian MSP

combined with cable corridor also drawn in MSP. The starting point for the cable in Uzava is not

preferred, because it follows through Natura 2000 area. In future building and planning processes,

should the overhead line alternatives ending in Uzava be chosen as preferred corridors, impacts on

Natura 2000 must be assessed.

Figure 15. Preferred coridor alternative for Uzava substation

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5.5. Corridor alternatives from Ventspils substation

There are three corridor alternatives compared from Ventspils substation:

• Original MSP corridor sketched in Latvian MSP.

• MSP corridor 1 alternative specified in this report.

• MSP corridor 2 alternative specified in this report.

Figure 16. Corridor alternatives compared from Ventspils substation

In current report, Latvian MSP corridor alternative is taken as a bases for corridor direction and

specified it mainly due to location of residential building. The area is very densely populated.

Overhead line is a possibility around residential areas. Should the straightest line be preferred, a

cable must be considered (approx. 4 km straight to the shore).

5.5.1. Technical criteria

According to the technical criteria the most preferred corridor is the specified MSP corridor alternative

2.

Criteria Ventspils-MSP3-1 Ventspils-MSP3-2 Ventspils-MSP3-3

Length of the corridor 10,339 5,286819261 6,900052657

The number of possible turns in

the corridor 5 6 8

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The need to build anchor masts 0 0 <Null>

The cost of the corridor (eur)5 4394075 2246898,186 2932522,379

Length of excisting 110 and 330

kV corridors used

6,6 km (100 % inside

110 kv existing line corridor)

1,7 km 2,9 km

Number of crossings with

other engineering structures 13 12 12

Number of crossings with local

roads 9 7 10

Number of crossings with state

roads 4 5 2

Number of crossings with existing

electricity lines

There might be

crossings near the

Ventspils substation

depending on the design solution.

There might be

crossings near the

Ventspils substation

depending on the design solution.

1 crossing with 110 and 330 kv corridor.

There might be

crossings near the

Ventspils substation depending on the

design solution.

The main conclusions from route comparison are following:

• The modified MSP corridor 2 is the shortest corridor from Ventspils substation to sea

compared to other alternatives in this section. This also results in lower building costs.

• Although the original MSP corridor has lower number of turns, the specified MSP corridor 2

is similar in terms of turns in the corridor. These corridors are therefore quite similar. As the

original MSP corridor is twice the length of MSP alternative 2 corridor.

• The original MSP corridor follows existing 110 kV corridor, which must be extended. The

extension might not be possible because of the protection zones of existing buildings.

Figure 17. Narrow conditions between residential buildings for Ventspils original MSP

alternative in existing 110 kV corridor

5 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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• In terms of crossings with existing engineering structures, the corridor alternatives are quite

similar.

5.5.2. Environmental criteria

For environmental criteria, no corridor alternative gets preference.

Criteria Ventspils-MSP3-1 Ventspils-MSP3-2 Ventspils-MSP3-3

Conflicts with Natura 2000 area no no no

Conflicts with protected areas 0 0 0

Number of habitat sites in conflict

with the corridor 0 0 0

Trees under protection in the

corridor 0 0 0

Number of cultural monuments in

the corridor <Null> <Null> <Null>

5.5.3. Socioeconomic criteria

For socioeconomic criteria, preference is given to original MSP corridor (Ventspils-MSP3-1)

alternative.

Criteria Ventspils-MSP3-1 Ventspils-MSP3-2 Ventspils-MSP3-3

Deforestation of forests

(total) 102519,29 147156,78 148458,19

Deforestation of private forests 0 0 0

Deforestation of State-owned

forest (LVM) 102519,29 147156,78 148458,19

Passage of mineral deposits (m2) 0 0 0

The main conclusions from route comparison are following:

• Overall need for deforestation is least for original MSP corridor.

• For passage of mineral deposits, all corridors are the same.

5.5.4. Preferred corridor alternative for Ventspils substation

For Ventspils substation, the most preferred corridor is the specified MSP alternative 2 as it is shorter

than the original MSP corridor and has less areas of conflicts with existing buildings.

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Figure 18. Preferred coridor alternative for Ventspils substation

The corridor follows the existing 110 kV line and causes narrow conditions in few places between

residential buildings. As the original MSP corridor follows the existing overhead line between

residential building and areas, fitting into narrow conditions without disturbing further residential

areas or conflicting with them, the specified MSP alternative 2 is preferred.

5.6. Corridor alternatives from Lihula substation

There are three corridor alternatives compared from Lihula substation:

• Lihula – Kulli corridor alternative sketched in this report.

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• Lihula – Nõmme corridor alternative sketched in this report (includes divisions between

Lihula and L3 control points Lihula–L3-1 and Lihula-L3-2).

• Lihula – Pivarootsi corridor alternative sketched in this report (includes divisions between

Lihula and L3 control points Lihula–L3-1 and Lihula-L3-2).

Figure 19. Corridor alternatives compared from Lihula substation

From Kulli, Nõmme and Pivarootsi, cable corridors to the sea are possible. The final direction depends

on the corridor alternative chosen. Kulli corridor is in most densely populated area, which requires

thorough assessment for the right passage of the corridor causing minimum impact on residential

areas. Environmental restrictions are high for every cable corridor. Natura 2000 areas cover the

coast, requiring environmental impact assessment in next steps of corridor planning to find the best

possible locations for cables with minimum impacts on the environment.

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Figure 20. Cable directions from Kulli to the sea.

Figure 21. Cable directions from Nõmme to the sea.

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Figure 22. Cable directions from Pivarootsi to the sea.

5.6.1. Technical criteria

According to the technical criteria the most preferred corridor is Lihula – Pivarootsi corridor combined

with L3-1 route division.

Criteria Lihula – L3-1 –

Pivarootsi

Lihula – L3-1 -

Nõmme Lihula – Kulli

Length of the corridor 20,43 25,32 47,74

The cost of the corridor (eur)6 8680873,29 15736715,82 20291375,92

The number of possible turns in

the corridor 13,00 11,00 18,00

The need to build anchor masts 1,00 0,00 4,00

Length of excisting 110 and 330

kV corridors used 4 4 19

6 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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Number of crossings with existing

electricity lines <Null> <Null> 23,00

Number of crossings with roads 18 19,00 80,00

The main conclusions from route comparison are following:

• Lihula - Pivarootsi corridor is shortest and therefore has the lowest building cost.

• Lihula - Pivarootsi corridor is also the straightest, bringing the overall building cost of the

alternative down even more compared with other corridors between Lihula and the sea.

• Lihula - Kulli gets high preference for following existing cable corridor for 19 kilometres. As

the existing corridor touches Natura 2000 areas in Tuhu küla, future planning and design

projects must address this possible conflict.

• For all route corridors, close cooperation with Lääneranna municipality is recommended, to

analyse necessities of their plans with ongoing renewable energy projects.

5.6.2. Environmental criteria

For environmental criteria, preference is given to Lihula - Nõmme corridor alternative.

Criteria Lihula – L3-1 –

Pivarootsi

Lihula – L3-1 -

Nõmme Lihula – Kulli

Conflicts with Natura 2000 area

Conflict with 2 Natura

areas - space between

areas is not wide enough to pass.

30m distance Natura

area on coast, other

nearest Natura areas are 176 m and 200 m

from the corridor.

Corridor is ca 120 m from Natura area, In

mid part, Natura is 200

m and 300 m from the

corridor. In northern part, corridor is

between 2 Natura

areas.

Conflict with I and II category

protected species no no

Conflict with II category protected

plant region ca 5500

m2.

Conflict with III category

protected species 8 species, 60448 m2

land affected

14 species, 253624

m2 land affected

44 species, 314551m2

land affected

Conflicts with other protected

areas <Null> <Null> <Null>

The main conclusions from route comparison are following:

• For Natura 2000 advantage is given to Lihula – Nõmme corridor, although the preferences is

small. Every corridor has some conflict with Natura 2000 areas – mainly on coast, but also

near existing line corridors. For Lihula – Pivarootsi corridor, the line must go through a narrow

space between areas of Väinamere bird area. In future developments impacts on Natura

2000 must be assessed thoroughly and if necessary, transmitted the overhead line to cable

further from coast.

• Lihula – Pivarootsi and Lihula - Nõmme corridors do not have conflicts with I and II category

protected species.

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• For III category protected species, clear preference is given to Lihula - Pivarootsi corridor.

Even though the negative impacts on these species can be mitigated through impact

assessment results in next stages, the differences between Kilingi-Nõmme – Häädemeeste

corridor and Kilingi-Nõmme – Võiste corridor are undisputable.

Figure 23. Lihula - Pivarootsi corridor conflict with Natura 2000 areas.

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Figure 24. Lihula - Kulli corridor conflicts between and on the border of Natura 2000

areas

5.6.3. Socioeconomic criteria

For socioeconomic criteria, preference is also given to Kilingi-Nõmme - Häädemeeste corridor

alternative.

Criteria Lihula – L3-1 –

Pivarootsi Lihula – L3-1 -

Nõmme Lihula – Kulli

Cadastral unit with residential

land use 336,59 362,51 9028,39

Cadastral unit with residential

land use and existing buildings <Null> <Null> <Null>

Residential buildings within 250 m 33,00 34,00 40,00

Non-residential buildings within

250 m 75,00 79,00 85,00

Forest in corridor (ha) 160,52 219,98 457,71

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Mining area in corridor (ha) 0,00 0 4,80

Mining allotment in corridor (ha) 0,00 0 4,78

Cultivated land (ha) 198,27 212,94 378,54

Cadastral units with detailed

plans <Null> <Null> <Null>

Cultural monuments 3 <Null> <Null>

Cemeteries and churches <Null> <Null> <Null>

Privately held land plots 1 970 113,4 m2 3 023 332,64 m2 7 612 997,78 m2

The main conclusions from route comparison are following:

• For impacts with residential functions and land use, Lihula - Pivarootsi corridor gets clear

preference. For future planning and design processes, it must be kept in mind that the end

point of the overhead line in Pivarootsi has clear conflicts with Natura 2000 areas.

• For cultural monuments, all corridors are the same. Avoidance of churches and cemeteries

is a base criterion, and these areas are excluded in the first stage, when drawing the

corridors.

5.6.4. Preferred corridor alternative for Lihula substation

For Lihula substation, the most preferred corridor is Lihula – Nõmme corridor alternative. Even

though it does not get high preference for any criteria category, it does not have intensive conflicts

with the most important components – Natura 2000, residential areas. For technical criteria, it comes

out as average. So, the preference in Lihula substation is not formed based on criteria categories,

rather than specific criteria itself.

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Figure 25. Preferred corridor alternative for Lihula substation

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5.7. Corridor alternatives from Sindi substation

There are three corridor alternatives compared from Sindi substation:

• Sindi – Reiu corridor alternative sketched in this report.

• Sindi – Kavaru corridor alternative sketched in this report (includes divisions between Sindi

and Audru (Sindi – P1.1 and Sindi P1.2)).

• Sindi – Lao corridor alternative sketched in this report (includes divisions between Sindi –

P1.1 and Sindi P1.2 and P2 – Lao and P2-P3-Lao).

Figure 26. Corridor alternatives compared from Sindi substation

From Lao, Kavaru and Reiu, cable corridors to the sea are possible. The final direction depends on

the corridor alternative chosen. Reiu corridor is in densely populated areas, which requires thorough

assessment for the right passage of the corridor causing minimum impact on residential areas.

Environmental restrictions are smaller in Reiu and Lao. For Kavaru, Natura 2000 areas cover the

coast, requiring environmental impact assessment in next steps of corridor planning to find the best

possible locations for cables with minimum impacts on the environment.

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Figure 27. Cable directions from Lao to the sea.

Figure 28. Cable directions from Kavaru to the sea.

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Figure 29. Cable directions from Reiu to the sea.

5.7.1. Technical criteria

According to the technical criteria the most preferred corridor is Pärnu – Reiu corridor alternative.

Criteria Pärnu - Reiu Pärnu – P2 –

Lao

Pärnu – P3 -

Lao

Pärnu -

Kavaru

Length of the corridor 20,62 43,77422552 58,96 35,62

The cost of the corridor (eur)7 8764463,40 28150006,9 25057808,76 24686195,49

The number of possible turns in

the corridor 11,00 15 20,00 13

The need to build anchor masts 1,00 2 3,00 0

Length of excisting 110 and 330 kV corridors used

5 0 0 0

Number of crossings with existing

electricity lines 1 1 1 1

7 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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Number of crossings with roads 10 24 31 29

The main conclusions from route comparison are following:

• Pärnu – Reiu corridor alternative is the shortest, therefore its building costs are lowest.

• Pärnu – Reiu corridor enables the use of existing line corridor for 5 km, which is not much

overall, but still more than other corridors.

• Crossing Rail Baltic railway must be considered in the next steps for Pärnu – Reiu corridor.

5.7.2. Environmental criteria

For environmental criteria, preference is given to Pärnu – P3 – Lao corridor alternative.

Criteria Pärnu - Reiu Pärnu – P2 –

Lao

Pärnu – P3 -

Lao

Pärnu -

Kavaru

Conflicts with Natura 2000 area

Crossing over

Natura 2000 area. Closest

Natura 2000

area is ca

350m.

Has a conflict with Natura

2000 area, ca

400 m along

the corridor.

Nearest Natura

2000 area is in

136 m on one side and on

250 m on the

other side.

Line is situated between two

Natura areas.

Ca 3 800 m2 is

in conflict with

Natura 2000

area. Other parts of the

same Natura

2000 area are

close to the corridor (ca

30m).

Conflict with I and II category

protected species

18 440 m2

conflict with II cat species

Small conflict

with 1 species of II category

Small conflict

with 1 species of I cat species

no

Conflict with III category

protected species

10 species,

27 119 m2 land affected

26 species,

66705 m2 land affected

4 species,

32 006 m2 land affected

4 species,

39347 m2 land affected

Conflicts with other protected

areas 0 0 0 0

The main conclusions from route comparison are following:

• Pärnu – P2 – Lao corridor alternative gets preference for Natura 2000. Although the area is

also in conflict with Natura 2000, the conflicts for other corridors are more intense.

• For other compared criteria, the differences between corridor alternatives are minor and can

be mitigated through necessary measures in the next steps of the planning and design

process.

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Figure 30. Pärnu - P2 - Lao corridor possible conflict with environmental restrictions

5.7.3. Socioeconomic criteria

For socioeconomic criteria, preference is given to Pärnu – Kavaru corridor alternative. Close

preference is given to Pärnu – P2 – Lao corridor alternative.

Criteria Pärnu - Reiu Pärnu – P2 – Lao Pärnu – P3 - Lao Pärnu - Kavaru

Cadastral unit

with

residential

land use

54831,61 0 18644,91 0

Cadastral unit

with

residential

land use and existing

buildings

1 unit near the

existing line

corridor

0 0,00 0

Residential

buildings

within 250 m 12,00 12 14,00 13

Non-

residential

buildings

within 250 m

85,00 40 39,00 34

Forest in

corridor (ha) 178,30 464 606,91 323,71

Mining area in

corridor (ha) 32,41 106,48 159,61 106,36

Mining allotment in

corridor (ha) 0,00 104,13 102,39 102,39

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Cultivated

land (ha) 127,67 215,58 325,13 193

Cadastral

units with

detailed plans <Null>

1 unit with building

design

specifications

1 unit with building

design

specifications

<Null>

Cultural

monuments 0 0 0 0

Cemeteries

and churches 0 0 0 0

Privately held

land plots 1825456 m2 3548371 m2 6613516 m2 4520938 m2

The main conclusions from route comparison are following:

• The main preference for Pärnu – Kavaru corridor is given through land units with residential

use – no such units are placed in Pärnu – Kavaru corridor.

• In addition, Pärnu – Kavaru corridor does not have land units with building design

specifications (ehitusõigus) in its corridor. Pärnu – Reiu is also missing this, but as Pärnu –

Reiu follows through several residential land units near Pärnu and near Reiu, preference to

this corridor can not be given.

• For cultural monuments, all corridors are similar. As this was a precondition for corridors, it

has been met.

5.7.4. Preferred corridor alternative for Sindi substation

For Sindi substation, two corridors are given preference to: Pärnu – Reiu for technical preferences,

Pärnu – Kavaru for socioeconomic preferences.

Figure 31. Preferred corridor alternatives for Sindi substation

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5.8. Corridor alternatives from Kilingi-Nõmme substation

There are three corridor alternatives compared from Kilingi-Nõmme substation:

• Kilingi-Nõmme – Võiste corridor alternative sketched in this report.

• Kilingi-Nõmme – Häädemeeste corridor alternative sketched in this report.

• Kilingi-Nõmme – Kabli corridor alternative sketched in this report.

Figure 32. Corridor alternatives compared from Kilingi-Nõmme substation

From Kabli, Häädemeeste and Võiste, cable corridors to the sea are possible. The final direction

depends on the corridor alternative chosen. All cable corridors are in densely populated areas, which

requires thorough assessment for the right passage of the corridor causing minimum impact on

residential areas. Environmental restrictions are smaller in Kabli. For Häädemeeste and Võiste,

Natura 2000 areas cover the coast, requiring environmental impact assessment in next steps of

corridor planning to find the best possible locations for cables with minimum impacts on the

environment.

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Figure 33. Cable directions from Kabli to the sea.

Figure 34. Cable directions from Häädemeeste to the sea.

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Figure 35. Cable directions from Võiste to the sea.

5.8.1. Technical criteria

According to the technical criteria the most preferred corridor is the one drawn in Kilingi-Nõmme –

Häädemeeste alternative combined with Häädemeeste cable corridor for cable transmission.

Criteria Kilingi-Nõmme –

Võiste

Kilingi-Nõmme –

Häädemeeste

Kilingi-Nõmme -

Kabli

Length of the corridor 42,50 35,33 49,81

The cost of the corridor (eur)8 18062049,59 15013916,63 21169464,18

The number of possible turns in

the corridor 17,00 16,00 19,00

The need to build anchor masts 2,00 1,00 2,00

Length of excisting 110 and 330

kV corridors used 33,4 3,3 2

Number of crossings with existing

electricity lines 8 lines 5 lines 5 lines

8 The cost of building a 1 km overhead line is estimated at 425,000 euros, and the cost of an underground cable

is 1.2 times higher

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Number of crossings with roads 76 48 85

The main conclusions from route comparison are following:

• Kilingi-Nõmme - Häädemeeste corridor is shortest and therefore has the lowest building cost.

• Kilingi-Nõmme - Häädemeeste corridor is also the straightest, bringing the overall building

cost of the alternative down even more compared with other corridors between Kilingi-

Nõmme and the sea.

• Kilingi-Nõmme – Võiste gets high preference for following existing cable corridor for 33

kilometres. As the existing corridor goes through Natura 2000 areas, this preference is

quickly turned into a disadvantage as building new lines inside existing corridors is in conflict

with Natura 2000 goals.

• For all route corridors, technical solution for crossing with the planned Rail Baltic railway

corridor, must be considered in future planning and design stages.

From Häädemeeste to the sea, the cable corridor must be developed in an densely populated area

and Natura 2000 areas on the shore. This requires thorough assessment for the right passage of the

corridor causing minimum impact on residential areas. Natura 2000 areas cover the coast, requiring

environmental impact assessment in next steps of corridor planning to find the best possible locations

for cables with minimum impacts on the environment.

5.8.2. Environmental criteria

For environmental criteria, preference is given to Kilingi-Nõmme - Häädemeeste corridor alternative.

Criteria Kilingi-Nõmme –

Võiste

Kilingi-Nõmme –

Häädemeeste

Kilingi-Nõmme -

Kabli

Conflicts with Natura 2000 area

Passing in between

Natura 2000 areas.

Crossing over Natura 2000 area (river) and

has a conflict near the

existing line corridor.

Crossing over Natura 2000 area (river)

Crossing over Natura 2000 area (river)

Conflict with I and II category

protected species 1 II cat bird near the

existing line corridor no

1 I cat and 1 II cat protected species

(small conflict with

area)

Conflict with III category

protected species 98 species, 828307 m2

land affected

10 species, 18754

m2 land affected

18 species, 272219 m2

land affected

Conflicts with other protected

areas 2 plots with permanent

habitat small conflict with permanent habitat

<Null>

The main conclusions from route comparison are following:

• For Natura 2000 small advantage is given to Kilingi-Nõmme – Häädemeeste and Kilingi-

Nõmme – Kabli corridor alternatives. Kilingi-Nõmme – Võiste corridor has two specific

conflicts with Natura 2000 areas – when following the existing line through Kikepera bird

area and near Võiste – a new line following through Uulu-Võiste and Luitemaa areas. The

alternative can be considered if now other option is available.

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• Kilingi-Nõmme – Häädemeeste corridor does not have conflicts with I and II category

protected species.

• For III category protected species, clear preference is also given to Kilingi-Nõmme –

Häädemeeste corridor. Even though the negative impacts on these species can be mitigated

through impact assessment results in next stages, the differences between Kilingi-Nõmme –

Häädemeeste corridor and Kilingi-Nõmme – Võiste corridor are undisputable.

Figure 36. Kilingi-Nõmme - Võiste corridor conflict with Natura 2000 areas inside

existing overhead corridor

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Figure 37. Kilingi-Nõmme - Võiste corridor conflict between Natura 2000 areas

• For other compared criteria, the differences between corridor alternatives are minor and can

be mitigated through necessary measures in the next steps of the planning and design

process.

5.8.3. Socioeconomic criteria

For socioeconomic criteria, preference is also given to Kilingi-Nõmme - Häädemeeste corridor

alternative.

Criteria Kilingi-Nõmme –

Võiste Kilingi-Nõmme –

Häädemeeste Kilingi-Nõmme -

Kabli

Cadastral unit with residential

land use 46439,10 9103,18 22850,06

Cadastral unit with residential

land use and existing buildings 1 unit near the existing

line corridor <Null> <Null>

Residential buildings within 250 m 35,00 23,00 30,00

Non-residential buildings within

250 m 65,00 54,00 62,00

Forest in corridor (ha) 472,53 424,32 663,25

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Mining area in corridor (ha) 4,05 <Null> <Null>

Mining allotment in corridor (ha) 3,64 0,00 0,00

Cultivated land (ha) 151,75 189,47 219,95

Cadastral units with detailed

plans <Null> <Null> <Null>

Cultural monuments <Null> <Null> <Null>

Cemeteries and churches <Null> <Null> <Null>

Privately held land plots 155 plots and 3 641

143,66 m2

155 plots and 4 481

413,15 m2

189 plots and 5 001

966,60 m2

The main conclusions from route comparison are following:

• For impacts with residential functions and land use, Kilingi-Nõmme – Häädemeeste corridor

gets clear preference. For future planning and design processes, it must be kept in mind that

the end point of the overhead line must be before Häädemeeste, a densely populated area.

If also cable corridors are considered, Häädemeeste with its population density, might not

be preferred. Cable mitigates the conflict from overhead line.

• For cultural monuments, all corridors are the same. Avoidance of churches and cemeteries

is a base criterion, and these areas are excluded in the first stage, when drawing the

corridors.

5.8.4. Preferred corridor alternative for Kilingi-Nõmme substation

For Kilingi-Nõmme substation, the most preferred corridor is Kilingi-Nõmme – Häädemeeste

alternative combined with cable corridor for Häädemeeste.

Figure 38. Preferred corridor alternative for Kilingi-Nõmme substation

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6. Recommendations for suitable spatial planning and

impact assessment procedure for planning the route

6.1. Future planning process for Latvia

In Latvia, the precondition for developing the lines is for the corridors to be added to municipality

territorial plans. This can either be done voluntarily by the municipalities or through Cabinet of

Ministers if the project is of national importance. The precondition for the corridor to be added to

territorial plans, is going through the process of EIA.

The requirement of EIA is set by the Law on Environmental Impact Assessment9 of Latvia. In its annex – Objects Requiring Impact Assessment - par 26 state high-voltage electric lines the length of which is more than 15 kilometres and the voltage of which is 110 kilovolts or more as an object requiring impact assessment. Therefore, impact assessment must be carried out for the lines, if it meets the requirements set in law. For the EIA process to be carried out properly and fast, it is essential to know technical parameters, proposed solutions and alternatives. The corridors mainly affect protected territories on coast.

After EIA procedure and detailed planning is done, designing the structure can begin.

6.2. Future planning process for Estonia

In Estonia, the options for planning the line and/or cable corridor and assessing its environmental,

social and economic impacts can be done through three possible procedures – national designated

spatial plan, local municipality comprehensive plan with building design specifications and a local

municipality detailed plan with environmental impact assessment.

6.2.1. National designated spatial plan

The compilation of a national designated spatial plan is divided into two stages - the pre-selection

stage for the corridor(s) and the subsequent stage of compiling a detailed solution. During the pre-

selection phase, the most suitable alternative for establishing a line corridor is found. For that,

possible location alternatives for the corridors are outlined, they are compared based on quantitative

and qualitative indicators, and the location alternative that is most favourable for establishing a line

corridor is decided. Sector studies and impact assessment (environmental, social, economic) provide

important input for the choice of the preferred route alternative, especially in the context of

environmental restrictions – Natura 2000 and other restricted areas. By the end of the site pre-

selection phase, a decision is made to proceed with the best possible line corridor or corridors to

which a detailed plan is prepared, which determines the building rights of the envisaged construction

work.

In the second stage of the plan - compiling a detailed solution - the construction right is determined

for the most suitable line corridor alternative selected in the pre-selection stage and other tasks

provided in the Planning Act are solved, including traffic management conditions, landscaping

requirements, easements, etc. Thus, in the second stage, a plan is prepared in the level of a detailed

plan, which is the basis for the preparation of the construction project. In parallel with the preparation

of the detailed solution, a design project will be prepared for the most suitable alternative to the line

9 https://likumi.lv/ta/en/en/id/51522-on-environmental-impact-assessment

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and an impact assessment will be carried out. The purpose of the impact assessment here is to

assess the effects of a specific technical solution and to develop mitigation measures.

National designated spatial plan is prepared by Ministry of Finance. The planning area of a national

designated spatial plan is not limited to a territory of a single municipality but allows for a wider look

for line corridor alternatives – for example the areas around all substations or multiple municipalities.

Havin Ministry of Finance in charge of the planning process, means not having to conduct several

procedures with different municipalities. This results in reduced time spent on the planning and SEA

procedures.

National designated spatial plan, if conducted too general, might leave local municipalities and

residents uninvolved in the process. At the same time, they are the most impacted by the line itself.

Therefore, should national designated spatial plan be chosen as the appropriate planning procedure

for future planning of the overhead line, much emphasis must be put to involvement of local

municipalities and residents, even though it is not thoroughly required by Planning Act.

6.2.2. Municipality comprehensive plan and building design specifications

Possible line corridors analysed in this report are located on the territories of municipalities in the

middle of their comprehensive planning processes. Comprehensive plan of a municipality enables to

carry out an integrated planning process for line corridor planning that considers not only the

necessities of the line itself, but also other spatial requirements stemming from other tasks of the

municipality – residential areas, recreation need, business environment etc. Most of the municipality

comprehensive plans are in development and currently in different stages, so if comprehensive plan

will be chosen as the most appropriate planning level for the line corridors, thorough cooperation

must be made with municipalities for joining the procedures.

For comprehensive plans, strategic environmental assessment is compulsory. For line corridors,

impacts on Natura 2000 must be assessed to finalise the right solution for overhead lines and

transmission areas. This complicates the comprehensive planning and its SEA process, as a new topic

will be brought on the table. For the line corridor to be assessed and planned in the comprehensive

planning process, specific needs of the line corridor must be presented to the municipality.

Comprehensive planning is done by municipalities. Municipality governments adopt the plans, which

means that for the plan to become legally binding, municipalities have the final say. If there are

disputes or arguments between parties, municipalities can stall the adoption process to turn the

result in their favour. At the same time, municipalities are known in their communities and if

municipalities lead the process, the result might be more acceptable by residents.

There are four municipalities affected by the line corridors. Different municipalities work in different

pace and have different approaches and needs for spatial development. Therefore, it is necessary to

manage four different comprehensive planning procedures for line comparison and selection.

Comprehensive plan is not bases for construction project. After comprehensive plan is adopted by

the municipality, building design specifications must be applied for from the municipality and/or

Consumer Protection and Technical Regulatory Authority. During this, public consultations will also

be carried out, to talk over the details that were left unclear during the comprehensive planning

process.

If comprehensive planning procedures go well and municipalities are keen on taking on planning and

assessment of corridors, comprehensive planning and building design specifications are the fastest

way for corridor planning.

It must be kept in mind that municipalities have contracts with planning consultants and

environmental experts to carry out the comprehensive planning process. Assessment of preferred

corridors and their impacts on Natura 2000 area are usually not foreseen in the consultancy

contracts.

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6.2.3. Municipality detailed plan and environmental impact assessment

Detailed plan is done for a certain area of municipality’s territory needed to build the line and other

necessary structures for it to work. For line corridors on the coast of Pärnumaa, an impact assessment

is also necessary, due to proximity of Natura 2000 areas. If the line is longer than 15 kilometres,

impact assessment is also required by law10.

Detailed planning is also done by municipalities. Municipality governments adopt the plans, which

means that for the plan to become legally binding, municipalities have the final say. If there are

disputes or arguments between parties, municipalities can stall the adoption process to turn the

result in their favour. At the same time, municipalities are known in their communities and if

municipalities lead the process, the result might be more acceptable by residents.

Detailed plan is bases for construction project. After the plan is adopted by the municipality, building

right is granted and designing the corridor can start.

The complication for detailed planning procedures come from the fact that overhead lines cross

municipality borders which again means different legal procedures in four different municipalities,

for an object that must be handled as one for it to function properly. If one municipality stalls the

process, the whole development at risk.

As the line corridors are planned for cross border activities, the need for cross border SEA and/or

EIA will arise and might be necessary in the building and planning procedures of the line corridors.

10 Par 6 of the Environmental Impact Assessment and Environmental Management System Act defines

construction of an overhead electrical power line with a voltage of 220 kV or more and a length of more than 15

km as an activity with significant environmental impact.

Töö number: 2021_0069

Tellija Elering AS

Konsultant Skepast&Puhkim OÜ

Laki põik 2, 12915 Tallinn

Telefon: +372 664 5808; e-post: [email protected]

Registrikood: 11255795

Kuupäev 17.12.2021

Kõrgepingeliini asukohavalik

Saaremaal

Trassikoridoride visandamise ja võrdlemise aruanne

Kõrgepingeliini asukohavalik Saaremaal

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Versioon 3

Kuupäev 17.12.2021

Koostanud: Anni Konsap, Kati Kraavi, Sander Lõuk

Kooskõlastanud:

Projekti nr 2021_0069

SKEPAST&PUHKIM OÜ

Laki põik 2

12915 Tallinn

Registrikood 11255795

tel +372 664 5808

e-mail [email protected]

www.skpk.ee

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Sisukord

Sissejuhatus ..................................................................................................................... 3

1. Metoodika kirjeldus ...................................................................................................... 4

1.1. Trassikoridoride visandamine.......................................................................................... 5

1.2. Trassikoridoride võrdlemise kriteeriumid .......................................................................... 7

1.3. Eelistuse kujunemine................................................................................................... 10

1.4. Lõpptulemuste vormistamine ........................................................................................ 10

2. Trassikoridoride visandamine ..................................................................................... 12

3. Trassikoridoride võrdlemine ....................................................................................... 40

3.1. Eelistatud trassikoridor lõigus A-H ................................................................................. 40

3.1.1. Võrdlustulemused piirkonnas A-B ............................................................................... 41

3.1.2. Võrdlustulemused piirkonnas B-C ............................................................................... 44

3.1.3. Võrdlustulemused piirkonnas C-D ............................................................................... 48

3.1.4. Võrdlustulemused piirkonnas D-E ............................................................................... 52

3.1.5. Võrdlustulemused piirkonnas E-F................................................................................ 55

3.1.6. Võrdlustulemused piirkonnas F-G ............................................................................... 59

3.1.7. Võrdlustulemused piirkonnas G-H ............................................................................... 62

3.2. Eelistatud trassikoridor lõigus A-B-I............................................................................... 63

3.2.1. Võrdlustulemused piirkonnas A-B-I ............................................................................. 64

3.3. Eelistatud trassikoridor lõigus A-I-M .............................................................................. 66

3.3.1. Võrdlustulemused piirkonnas L1-L2 ............................................................................ 68

4. Soovitused edasise protsessi ülesehitamiseks ............................................................ 71

Lisad

Lisa 1. Kaardirakendus alusandmetega:

https://gis.skpk.ee/portal/apps/MapSeries/index.html?appid=e55f17b56ac74c38a6870

231f9238bd4

Lisa 2. Võrdlustulemuste maatriks

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Sissejuhatus

Käesoleva töö eesmärk on analüüsida meretuuleparkide ühendamiseks vajalike kõrgepingeliinide

võimalikke trassikoridoride asukohavalikut Saaremaal. Töö tulemusena on lähtuvalt lähteülesandest

erinevate asukohavaliku kriteeriumide rakendamisel tuvastatud võimalikud trassikoridorid

Saaremaal, esitatud trassikoridoride võrdlus eelistatud koridori väljaselgitamiseks ning antud

soovitused edasise planeerimis- ja mõjude hindamise protsessi ülesehitamiseks.

Analüüs toob välja avalikest allikatest kättesaadavate andmete pinnalt sobivaimad trassikoridorid

ning esitab objektiivsetele kriteeriumidele tuginevad eelistused koridoride võrdluses. Trassikoridoride

alternatiivid ning nende sobivus tuleb täpsustada avalikus menetluses läbiviidava ning kaasava

(planeerimis)protsessi ning detailse mõjude hindamise koostamise käigus. Kõrgepingeliini lõpliku

asukohavaliku protsessi käigus tuleb kasutatud alusandmeid (nt projekteerimistingimustega alasid,

üldplaneeringu lahendust, katastriandmeid jmt ajas muutuvat informatsiooni) värskendada, et

tehtavad järeldused oleksid kõige aja- ja asjakohasemad.

Käesoleva analüüsi lahutamatu osa on andmeanalüüsi tulemusel koostatud kaardirakendus ning selle

aluseks olevad kaardikihid.

Käesolev aruanne on töö lõpparuanne, mis koosneb töö metoodika kirjeldamisest, trassikoridoride

visandamise tulemustest ning trassikoridoride võrdlemise tulemusel eelistatud trassikoridori

kujunemisest. Täiendavalt on lõpparuandes antud soovitused edasise protsessi, sh mõjude

hindamise ülesehitamiseks.

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1. Metoodika kirjeldus

Käesoleva töö ülesandeks on leida trassikoridorid võimaliku kõrgepingeliini kavandamiseks

Saaremaal. Joonis 1 kujutab analüüsitavat territooriumi.

Joonis 1. Võimaliku kõrgepingeliini maale tuleku (rohelisega) ning merre suubumise

asukohad (lillaga) Saaremaal. Sinise viirutusega on esitatud võimalikud tuuleparkide

asukohad merealal.

Töö käigus tuleb visandada võimalikud trassikoridori alternatiivid, hinnata nende esialgset sobivust

ning luua eelistus sobivaima trassikoridori osas. Muuhulgas tuleb töö käigus määratleda maakaabli

üleminekukohad õhukaabliks (merelt maismaale tulles) ning vastupidi (maismaalt merre minnes).

Visandatava ja analüüsitava trassikoridori laiuseks on 100 meetrit ja 200 meetrit. 100-meetrine

trassikoridor tähendab ühe 330 kV õhuliini ning selle kaitsevööndi ulatust, millele on lisatud kokku

20 meetrit puhvervööndit, mis annab trassi edasisel kavandamisel asukoha täpsustamiseks

nihutamistuumi. 200-meetrine trassikoridor tähendab kahte 330 kV õhuliini ja selle kaitsevööndi

ulatust, millele on lisatud kokku 20 meetrit puhvervööndit. 200-meetrine trassikoridor võib osutuda

vajalikuks mitme liini rajamise korral, mille vajadus omakorda on tingitud suuremate

ülekandvõimsuste vajadusest. Paralleelselt kulgevate kõrgepingeliinide koridorid on kavandatud

asukohtades, kus see on ruumiliselt võimalik – näiteks on elamute vahel selleks piisavalt ruumi või

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seda võimaldavad looduskeskkonna tingimused. Laius tuleneb kõrgepingeliini kaitsevööndist1,

milleks on 40 meetrit mõlemale poole trassi teljest (vt Joonis 2).

Joonis 2. Kõrgepinge õhuliini kaitsevööndi ulatus. Allikas: AS Elering

Võimalike trassikoridoride visandamiseks kasutatakse välistusmeetodit – kokkulepitud kriteeriumide

alusel (vt ptk 1.1.) sobimatute alade välistamist. Selle tulemusel tekivad alad, kus võimalikud

trassikoridorid asuda võiksid. Nende alade sees visandatakse trassikoridorid, mida järgmises etapis

võrreldakse omavahel kvalitatiivsete ja kvantitatiivsete kriteeriumide (vt ptk 1.2.) alusel.

Trassikoridoride võrdlemise tulemusel kujundatakse eelistused trassikoridoride osas. Töö tulemusena

esitatakse sobivaima trassikoridori asukoha eelistus, mida tuleb täiendada ja täpsustada järgnevas

planeerimis- ja mõjude hindamise protsessis.

1.1. Trassikoridoride visandamine

Trassikoridoride visandamiseks kasutati välistusmeetodina järgmisi valikukriteeriume:

• Trassikoridori ning 100 meetri kaugusele trassikoridori servast ei tohi jääda ühtki elu- või

ühiskondliku hoonet.

• Trassikoridori ei tohi jääda ühtki kõrval- või tootmishoonet.

• Trassikoridor ei tohi läbida tiheasustusala.

• Trassikoridor ei tohi läbida mäeeraldisi.

• Trassikoridor ei tohi läbida kalmistuid.

• Trassikoridori ei tohi jääda kultuurimälestisi ja nende kaitsevööndeid.

• Trassikoridori ei tohi jääda kirikuid ja pühakodasid.

• Trassikoridor ei tohi kattuda I ja II kaitsekategooria elupaikadega.

1 Käesoleva töö koostamise ajal (detsember 2021) kehtiva majandus- ja taristuministri 25.06.2015 määruse nr

73 „Ehitise kaitsevööndi ulatus, kaitsevööndis tegutsemise kord ja kaitsevööndi tähistusele esitatavad nõuded“ §

10 lg 1 punkti 5 kohaselt on õhuliini kaitsevööndi ulatus on mõlemal pool liini telge 220 kV kuni 330 kV

nimipingega liinide korral 40 meetrit.

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Käesoleva töö esimeses etapis toodi välistava kriteeriumina välja ka tingimus, et trassikoridor ei tohi

läbida miljööväärtuslikke alasid. Trassikoridoride visandamise käigus ilmnes, et eeltingimuse –

võimalikult sirge ja lühike – rakendamisel ei ole võimalik miljööväärtuslikke alasid täielikult välistada.

Liinide edasisel kavandamisel tuleb koostöös omavalitsusega2 hinnata miljööväärtuslikel aladel

kaitstavaid väärtusi ning kavandada vajadusel leevendavad meetmed (nt asukoha täpsustamine)

miljööväärtuslike aladele avalduvate negatiivsete mõjude hüvitamiseks.

Trassikoridori jaoks sobivate alade valikul ilmnes, et Saaremaa läänerannikul merelt maismaale

tulekuks asukohti, kus merekaabel saaks kohe õhuliiniks üle minna, ei ole. Alal asuvad mitmed

Natura linnualad (Karala-Pilguse linnuala, Riksu ranniku linnuala), Karala miljööväärtuslik ala jmt

kitsendavad piirkonnad. 330 kV õhuliin Natura linnualal on konfliktne ja ebasoodsaid mõjusid

linnualale ei saa käesolevas töös välistada3. Samuti on keeruline olukord, kus õhuliin jookseb kahe

lähestikku paikneva linnuala vahelt.

Seetõttu on sobivate trassikoridoride visandamisel trassikoridoride valikuks rakendatud veel

järgnevaid põhimõtteid:

• Natura linnualadel ning sellest 100 meetri kaugusel on trassikoridorina silmas peetud

maakaabli koridori. Käesolevas töös näidatud trassikoridore, mis läbivad (sh maakaabel),

mööduvad Natura aladest või külgnevad nendega, tuleb järgmistes etappides hinnata

trassikoridori kavandamisega kaasnevat mõju Natura aladele. Sellest lähtuvalt võib osutuda

vajalikuks trassikoridoride nihutamine, ümberpaigutamine vmt vajalik meede.

Joonis 3. Natura alade paiknemine Saaremaa läänerannikul (roosa viirutus).

• Välistatud on alad, kus elu- või ühiskondlike hoonete ning nende 100 meetrise puhvervööndi

paiknemine välistab 200-meetrise trassikoridoriga hoonete vahelt läbitulemise. Kriteeriumi

rakendamise eesmärgiks on välistada visuaalne mõju eluhoonetele ning minimeerida

kitsendusi eraomandile.

2 Käesoleva töö koostamise ajal (detsember 2021) on koostamisel Saaremaa valla uue üldplaneeringu

koostamine, mille käigus on muuhulgas võimalik täpsustada miljööväärtuslike alade ulatust ja/või

kasutustingimusi või kavandada liinikoridor sellele vastavalt. 3 Mõjude hindamine, ebasoodsate mõjude esinemise võimalikkus ning nende võimalike leevendusmeetmete

hindamine toimub

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Joonis 4. Näide alast, kus elu- või ühiskondlike hoonete tihedus ei võimalda liini

trassikoridori visandada. Lilla polügoonina on esitatud üldplaneeringuga kavandatud

miljööalad.

1.2. Trassikoridoride võrdlemise kriteeriumid

Trassialternatiivide võrdlustulemused esitatakse võrdluskriteeriumide gruppide kaupa:

• Sotsiaalmajanduslikud kriteeriumid

o Elamuga elamumaa sihtotstarbega kinnistu läbimine (ha)

Arvestab, kui suures ulatuses (ha) läbib alternatiivne trassikoridor elamuga hoonestatud

elamumaa sihtotstarbega kinnistuid.

o Elamuta elamumaa sihtotstarbega kinnistu läbimine (ha)

Arvestab, kui suures ulatuses (ha) läbib alternatiivne trassikoridor elamuta elamumaa

sihtotstarbega kinnistuid. Trassikoridori valikul on lähtutud põhimõttest, et igasugune

elamumaa sihtotstarbega maa läbimine on halvem, kui muu sihtotstarbega maa läbimine.

o Elu- või ühiskondlikud hooned

Lähemale kui 100 m kaugusele eluhoonetest on trassikoridori paiknemine välistatud.

Kaalutlemisel hinnatakse, kui suur on trassikoridori teljest kuni 250 m kaugusele jäävate

elamute arv. Eelistatud on alternatiiv, mille korral jääb trassikoridori lähedusse vähem

elamuid või need asuvad võrreldes teiste alternatiivide lähedusse jäävate elamutega

kaugemal.

o Väärtuslikud maasikud, ilusa vaatega kohad ja teelõigud

Arvestab, millises ulatuses (pikkus, m) läbib alternatiivne trassikoridor maakonna- ja

üldplaneeringutega määratud väärtusliku maastiku alasid. Samuti hinnatakse, mitmel juhul

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võib trassikoridor häirida maakonna- ja üldplaneeringuga tähistatud ilusa vaatega kohtade

vaadeldavust.

o Puhkealade läbimine (m)

Arvestab, millises ulatuses (m) läbib alternatiivne trassikoridor üldplaneeringutega määratud

puhkealasid, RMK puhketaristut. Eelistatumaks on alternatiiv, mis ei läbi puhkealasid või

läbib neid vähimas ulatuses, teiste alternatiividega võrreldes.

o Raadatava erametsa pind (ha)

Arvestab, kui suur on raadatava erametsa pinda (ha). Lähtutud on põhimõttest, et

kaitsevööndisse jääv eramets tuleb omanikule kompenseerida. Mida pikemalt läbib

trassikoridor erametsa, seda vähem sobilik on vastav alternatiiv.

o Raadatava riigimetsa pind (ha)

Arvestab raadatava riigimetsa pinda (ha). Metsamaa pinna arvutamisel on arvestatud, kas

trassikoridor asub olemasoleva liini trassil (väiksem raadatav pind) või uues trassikoridoris

(suurem raadatav pind). Lähtutud on põhimõttest, et kaitsevööndisse jääv riigimets tuleb

RMK-le kompenseerida. Riigimetsa läbimine on eelistatum, kui erametsa läbimine, kuna

kokkulepete saavutamine on hinnanguliselt kergem ja odavam.

o Maardlad (m)

Arvestab, millises ulatuses (pikkus, m) läbib alternatiivne trassikoridor maardla ala. Maardla

alal ei tohi takistada maavara väljakaevamist, seetõttu tuleb sinna rajamisel maavara

eelnevalt ära kaevandada. Väljakaevandamine on eraldiseisev, aja- ja rahakulu suurendav

protsess.

o Põllumajanduslik maakasutus (ha)

Trassi paiknemine põllumajandusmaal on eelistatud võrreldes metsamaaga.

o Kehtestatud detailplaneeringutega alad

Eelistatud on trassialternatiiv, mis ei läbi detailplaneeringuga alasid.

o Väljastatud projekteerimistingimustega katastriüksused

Eelistatud on trassialternatiiv, mis ei läbi väljastatud projekteerimistingimustega alasid.

o Eraomandis olevad katastriüksused (ha)

Eelistatud on trassi võimalikult vähene paiknemine eraomandis oleval maal

o Avalikus omandis olevad katastriüksused (ha)

Eelistatud on trassi paiknemine avalikus omandis oleval maal

Täiendavad kriteeriumid, mis on esmalt välistavad, kuid mida tuleb kaaluda teiste reaalsete

alternatiivide puudumisel:

o Tiheasustusalade paiknemine

Arvestab, millises ulatuses (pikkus, m) läbib trassikoridor üldplaneeringutega määratud

tiheasustusala. Tiheasustusala läbimine on välistatud. Kui muid alternatiive pole, siis kaaluda

maakaablit.

• Looduskeskkonna kriteeriumid

o Mõju kaitsealadele (Natura 2000 alad, kaitsealad, hoiualad)

Hinnatud on mõju rahvuspargile, loodus- ja maastikukaitsealadele, kui alternatiivne

trassikoridor seda läbib või möödub lähedalt4. Alternatiivide valiku eeltingimuseks on

kavandatava tegevuse vastavus kaitse-eeskirjaga ja kaitsekorralduskavaga. Mida vähem

alternatiiv puutub kokku seatud kaitse-eesmärgiga, seda eelistatum see on.

o III kaitsekategooria liigid

Hinnatud on mõju III kaitsekategooria liigi elupaikadele. Mida vähem alternatiiv puutub

kokku III kaitsekategooria elupaigaga, seda eelistatum alternatiiv on.

4 „Lähedalt“ on käesoleva töö raames hinnatud ca 200-250 meetrist vahemaad võimaliku liini telje ning Natura

ala piiri vahel. Mõju konkreetsele alale, tuleb välja selgitada liini edasise kavandamise korral.

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o Mõju muule kaitstavale loodusobjektile va kaitsealad (vääriselupaigad,

kaitsekategooriata üksikobjektid)

Hinnatud on mõju kaitstavatele loodusobjektidele (va kaitsealad), näiteks vääriselupaigad,

kaitsekategooriata üksikobjektid, jne. Mida vähem alternatiiv puutub kokku kaitstava

objektiga, seda eelistatum alternatiiv on.

o Rohevõrgustiku vähendamine ja killustamine

Hinnatud on alternatiivses trassikoridorikoridoris raadatava metsamaa tõttu tekkivat mõju

rohevõrgustiku aladele. Mida vähem alternatiiv vähendab tugiala või lõikab läbi rohekoridori,

seda eelistatum see on.

o Kavandatavad kaitsealused liigid ja kaitsealad

Hinnatud on mõju kavandatavatele kaitsealustele liikidele ja kaitsealadele.

Mida vähem puutub alternatiiv kokku elupaigaga või kaitsealaga, seda eelistatum see on.

• Kultuurilised kriteeriumid

o Kultuuripärand (pärandkultuuriobjektid, XX sajandi arhitektuuripärand,

maaehituspärand, militaarpärand jmt)

Eelistatud on trassikoridor, millesse jääb võimalikult vähe kultuuripärandi objekte.

o Kohaliku kaitse alused alad ja objektid

Eelistatud on trassikoridor, millesse jääb võimalikult vähe kohaliku kaitse aluseid objekte ja

alasid.

Käesoleva töö esimeses etapis toodi välistava kriteeriumina välja ka tingimus, et trassikoridor ei tohi

läbida miljööväärtuslikke alasid. Trassikoridoride visandamise käigus ilmnes, et eeltingimuse –

võimalikult sirge ja lühike – rakendamisel ei ole võimalik miljööväärtuslikke alasid täielikult välistada.

Liinide edasisel kavandamisel tuleb koostöös omavalitsusega5 hinnata miljööväärtuslikel aladel

kaitstavaid väärtusi ning kavandada vajadusel leevendavad meetmed (nt asukoha täpsustamine)

miljööväärtuslike aladele avalduvate negatiivsete mõjude hüvitamiseks. Seetõttu on

miljööväärtuslike alade läbimist käsitletud võrdluskriteeriumina – eelistatud on trassikoridor, mis ei

läbi või läbib võimalikult vähe miljööväärtuslikke alasid.

• Tehniline teostatavus

o Trassikoridori pikkus (km)

Eelistatud on trassikoridor, mis on kõige lühem.

o Trassikoridori pöörete arv

Eelistatud on trassikoridor, mis on võimalikult sirge ehk kus võimalike pöörete arv ning

seeläbi nurgapostide rajamise vajadus on kõige väiksem.

o Trassikoridori maksumus (eur)

Trassikoridori maksumus on otseses seoses trassikoridori pikkuse ning maakaabli ja õhuliini

pikkusega trassikoridoris. Arvestuslikult on 1 km õhuliini rajamise maksumus 425 000 eurot,

maakaabli maksumus 1,2 korda kõrgem6.

o Rajamise ja hooldamise keerukus

Arvestatakse ankrumastide rajamise vajadust. Arvestuslikult peab ankrumast asuma iga 5

kilomeetri tagant ning sellele peab olema tagatud juurdepääsutee.

o Olemasolevate koridoride kasutamine (m)

Eelistatud on trassikoridor, mis kasutab võimalikult pikalt olemasolevat trassikoridori.

5 Käesoleva töö koostamise ajal (detsember 2021) on koostamisel Saaremaa valla uue üldplaneeringu

koostamine, mille käigus on muuhulgas võimalik täpsustada miljööväärtuslike alade ulatust ja/või

kasutustingimusi või kavandada liinikoridor sellele vastavalt. 6 Info Elering AS-ilt seisuga september 2021.

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o Ristumised olemasolevate taristuelementidega

Eelistatud on trassikoridor, millel on väikseim arv ristumisi olemasolevate

taristuelementidega7.

1.3. Eelistuse kujunemine

Kriteeriumigrupid on eristatud kriteeriumide kaupa, mille osas on trassikoridore omavahel võrreldud

skaalal „tugev eelistus“, „nõrk eelistus“ ning „mitte-eelistatud“. Kriteeriumigrupi lõikes koondhinde

andmisel on kasutusel sama skaala. Eelistused on markeeritud järgmiselt:

TUGEV EELISTUS Kõige parem trassikoridor võrreldava kriteeriumi lõikes.

NÕRK EELISTUS Esineb miinuseid võrreldes tugeva eelistuse saanud trassikoridoriga,

kuid on siiski soovitatav.

MITTE-EELISTATUD Kõige halvem trassikoridor võrreldava kriteeriumi lõikes.

EELISTUS PUUDUB Kriteeriumi lõikes olulised erinevused trassikoridoride vahel puuduvad

ja eelistust ei teki.

Eelistuse kujundamisel on kasutatud nii kvantitatiivseid kui ka kvalitatiivseid (eksperthinnangule

tuginevaid) meetodeid. Kvantitatiivsete kriteeriumide korral (nt elamute arv trassikoridoris) on

eelistus kujundatud numbriliste näitajate põhjal – nt väiksem arv on parem. Kvalitatiivsete

kriteeriumide korral on eelistuse kujunemise aluseks eksperthinnang (kui selle andmine kuulub antud

töö täpsusastmesse) selle kohta, milline trassikoridor avaldab vähim mõju hinnatavale kriteeriumile

või suudab kaasa tuua enim positiivseid muutusi. Kõikide kriteeriumide lõikes on eelistus kujundatud

trassialternatiivide omavahelisel võrdlemisel.

Eelistuse kujundamisel on arvestatud järgmisi põhimõtteid:

• Kui hinnatava kriteeriumi lõikes on kõik koridorid võrdsed, ei anta ühelegi trassikoridorile

eelistust. Sellisel juhul on jäetud lahtrid värvimata.

• Tehniline eelistus on kujundatud koostöös Tellijaga.

• Ehitusmaksumus on ligikaudne ning käesolevas etapis esitatud eelkõige koridoride

omavaheliseks võrdlemiseks.

• Looduskeskkonna kriteeriumite puhul tähendab tugev eelistus olukorda, kus ühes või mitmes

kriteeriumis ilmnenud oluliste mõjude tõttu on alternatiivse variandi elluviimine

negatiivsemate mõjudega.

• Looduskeskkonna kriteeriumite puhultähendab nõrk eelistus olukorda, kus mõlemad

variandid on aktsepteeritavad, kuid üks variant on, kas väiksemate negatiivsete mõjude või

suuremate positiivsete mõjude tõttu eelistatud.

• Kokkuvõtlik eelistus on kujundatud erinevate valdkondade eelistuste summeerimise ning

kaalumise tulemusel.

1.4. Lõpptulemuste vormistamine

Töö väljunditeks on:

7 Ristumiste korral tuleb tagada ankrumastide paiknemine mõlemal pool taristuelementi, mida õhuliin ületab.

Ristumine peab toimuma mitte teravama kui 60 kraadise nurga all.

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• Kirjalik aruanne, mis selgitab ala valikukriteeriume, võrdlustulemusi, eelistatud koridori ning

ettepanekuid edasise protsessi läbiviimiseks.

• Kaardikihid trassikoridoridega ning töö käigus kogutud andmetega, mis ei ole kättesaadavad

avalikes andmebaasides.

• Ülevaatlikud skeemkaardid .pdf formaadis näiteks visandatud trassikoridoride osas,

väljavõtetena tiheasustatud alade lähedusest vmt.

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2. Trassikoridoride visandamine

Saaremaa rannikul on leitud üks asukoht (joonisel 6, punkt A), kus merekaabli saab üle viia elektri

õhuliiniks (tulenevalt eelkõige Natura 2000 alade paiknemisest) ning kolm asukohta (joonisel 6

punktid H, M ja I), kus elektri õhuliin on võimalik viia merekaabliks.

Kogu võimalike liinikoridoride alal on tähistatud kontrollpunktidega A-H ning A-B-I (olemasoleva

liinikoridori võimaliku laiendamise analüüsimiseks) ning lisaks koridor I-M. Punktid A, H, I ja M on

kohad, kus merekaabli saab üle viia elektri õhuliiniks või vastupidi.

Joonis 5. Ülevaateskeem liinikoridoride asukohtadest.

Trassikoridoride kirjeldamiseks moodustati piirkonnad (joonis 6), mille sees on antud kontrollpunkte

ühendavate trassikoridoride alternatiive kirjeldatud.

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Joonis 6. Trassialternatiivide kirjeldamise piirkonnad.

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Alljärgnevas tabelis on toodud trassikoridoride kirjeldused koos võimaliku liinikoridori tähise (nr), pindala ja trassikoridori lõigu pikkusega. Koridoride

visandamisel on tegu õhuliinidega. Kaablina käsitletakse koridori alates merelt kuni õhuliini üleminekukohani (punktis A) ning õhuliini üleminekust kuni

mereni (punktides H, I või M). Liinikoridoride täpsemad asukohad on märgitud ja leitavad rakenduses.

Lõik Nr Pindala (m2)

Nurgapunkte Pikkus (m)

Liini kirjeldus Asukoha ülevaade

Punkti A

1_Kaabel 8860 1 0 Merekaabli üleminek õhuliiniks. Merepiirist ca 190 m kaugusel, kaitsealuse looma elupaigast rannikul 119 m kaugusel. Üleminekukohas on teede ristmik ja veidi lagedam ala.

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Punkti H

2_Kaabel 73387 2 0 Õhuliini üleminek merekaabliks. Üleminekukoht on merepiirist ca 970 m kaugusel lagedal põllualal.

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Punkti I

3_Kaabel 46685 1 0 Õhuliini üleminek merekaabliks asub rannikust 1260 m kaugusel ja Natura alast 950 m kaugusel (kõrvaloleval fotol roosa viirutusega).

A-B AB-1 1349381 3 6757 Möödub elamualadest põhjapoolt. Ei ole puutumust Natura alaga. Kaks liini mahub ühte koridori.

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AB-2 1344739 4 6729 Möödub elamualadest põhjapoolt. Ei ole puutumust Natura alaga. Kaks liini mahub ühte koridori. On sirgem juhul kui valida lõigu B-C lõunapoolne suund.

AB-3 1422202 5 9793 Nurgapunkt asub riigimaal. Lõigu esimeses osas mahub kaks liini koridori. Pärast hargnemist asub põhjapoolne koridor suures osas haritaval maal, nurgapost on riigimaal.

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AB-4 1154936 3 5775 Kõige lühem liinikoridor A-B lõigus. Nurgaposti saab paigutada olemasoleva tee kõrvale. Liinikoridor on lähedal Natura alale ( kõrvaloleval fotol roosa viirutusega).

AB-5 1154795 4 5774 Kui valida B-C lõigu lõunapoolne koridor, on tegemist kõige lühema A-B lõiguga. Möödub Natura alast lähedalt ( kõrvaloleval fotol roosa viirutusega). Nurgapost võimalik paigutada olemasoleva tee kõrvale

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B-C BC-1 2925692 7 14640 Koridor läbib II kategooria kaitsealuse liigi leiukohta ( kõrvaloleval fotol kuvatud roosa polügoonina). Koridor on sirge. Mõned nurgapostid on võimalik paigutada olemasoleva tee lähedale. Põhjapoolses osas pole puutumust elamuhoonete kaitsetsooniga.

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BC-2 2941970 6 14719 Liini läänepoolne osa on suhteliselt sirge, aga läbib II kategooria kaitsealuse taime leiukohta ( kõrvaloleval fotol esitatud roosa polügoonina). Mõned postid on võimalik paigutada olemasoleva tee kõrvale. Põhjapoolsemas osas pole puutumust elamute kaitsetsooniga.

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BC-3 2802932 12 16832 Liin läänepoolne osa on üsna sirge, aga läbib II kategooria kaitsealuse taime leiukohta. Möödub kõikidest kaitsetsoonidest väga lähedalt ( kõrvaloleval fotol kollasega esitatud 250 m puhvertsoon elamutest).

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BC-4 3015884 10 15094 Väldib kõiki kaitsevööndeid, kuid möödub Natura alast ja kaitsealustest liikidest väga lähedalt ( kõrvaloleval fotol kujutatud roosa viirutusega, oranžide ja punaste polügoonidena). Mitmeid tugiposte on võimalik paigutada olemasoleva tee äärde riigimaale.

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BC-5 3031594 7 6158 Väldib kõiki kaitsevööndeid, aga möödub Natura alast ja kaitsealustest liikidest väga lähedalt ( kõrvaloleval fotol kujutatud roosa viirutusega, oranžide ja punaste polügoonidena). Mitmeid tugiposte on võimalik paigutada olemasoleva tee äärde riigimaale.

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BC-6 2892701 14 17286 Möödub Natura aladest ja kaitsealadest väga lähedalt ( kõrvaloleval fotol kujutatud roosa viirutusega, oranžide ja punaste polügoonidena) ning jääb osaliselt elumajade kaitsetsooni. Mitmed nurgapostid on võimalik paigutada riigimaale.

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BC-7 3669262 8 13927 Liin möödub Natura alasti lähedalt ( kõrvaloleval fotol roosa viirutusega), kuid puutumus Natura alaga ja teiste kaitsevöönditega puudub. Liin on alternatiiviks samas lõigus põhjapool asuvatele liinikoridoridele, mis läbivad kaitsealasi.

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BC-8 3647932 7 18252 Liin möödub Natura ala lähedalt ( kõrvaloleval fotol kujutatud roosaga), kuid otsene puutumus Natura ala ja teiste kaitsevöönditega puudub. Koridor on alternatiiviks samas lõigus põhjapool asuvatele koridoridele, mis läbivad kaitsevööndeid. Liinikoridor sobib AB-2 ja AB-5 koridoride jätkamiseks.

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C-D CD-1 937947 2 4694 Liinikoridor riivab miljööväärtuslikku ala ( kõrvaloleval fotol lilla polügoon) ning möödub Natura ala lähedalt ( kõrvaloleval fotol roosa viirutus). Elamualade kaitsevööndise liinikoridor ei jää. Kõik tugipostid on võimalik paigutada riigimaale.

CD-2 802261 0 4011 Liinikoridor on kõige sirgem tee punktide C ja D vahel, kuid läbib miljööväärtusliku ala ( kõrvaloleval fotol lilla polügoonina) ning II kat kaitsealuse taime elupaika ( kõrvaloleval fotol roosa polügoonina). Selle liinikoridori puhul pole

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nurgaposte vaja rajada.

D-E DE-1 1303498 4 6520 Liinikoridor riivab elamualade kaitsetsoone (kõrvaloleval fotol punasega), möödub väga lähedalt Natura linnualast (kõrvaloleval fotol roosa viirutus) ning läbib miljööala. Koridori mahub 2 liini.

DE-2 1513461 6 10423 Koridor möödub Natura aladest väga lähedalt, läänepoolses osas on kaitsetsoonid ning hoonete vaheline ala kitsas, seetõttu hargnevad liinid kahte trassikoridori. DE- 2 trassikoridor

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riivab eluhoonete kaitsevööndit, kuid vähem kui alternatiivne DE-1 koridor.

E-F EF-1 1272026 4 6368 Liinikoridori idapoolses osas on trassikoridor märgitud olemasolevas liinikoridoris, kuid olemasolevat koridori on vaja laiendada. Koridori laiendus ulatub hoonete kaitsetsooni.

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EF-2 1271789 3 6366 Koridor on alternatiiviks idapoolses osas olemasoleva trassikoridori laiendamisele, kuid läbib hoonete kaitsetsooni. Selle liinikoridori saab jätkata sirgjooneliselt F punktist üle minnes.

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F-G FG-1 1527076 4 7637 Koridor on kõige sirgem tee punktist F punkti G, vältides maksimaalselt kaitsealasid.

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FG-2 1839043 3 9203 Koridori põhjapoolne osa kulgeb mööda olemasolevat trassikoridori, mille laiendamise tulemusel ulatub uus liinikoridor elamute kaitsetsooni. Seda liini saab jätkata sirgjooneliselt, G punktist üle minnes

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GH 2225058 4 11126 Koridor kulgeb võimalikult sirgelt, vältides hoonete ja kaitsealuste loodusobjektide kaitsetsoone. Üks nurgapost on võimalik paigutada riigimaale.

A-I AI-1 3011608 7 14905 Koridor ei puutu kaitsealasid ega kaitsetsoone, möödub Natura alast lähedalt. Kulgeb suures osas riigimaal ( kõrvaloleval fotol rohelisega). Mitmed tugipostid saab paigutada olemasoleva tee äärde.

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AI-2 3009297 6 14890 Koridor ei puutu kaitsealasid ega kaitsetsoone, möödub Natura alast lähedalt. Kulgeb suures osas riigimaal. Mitmed tugipostid saab paigutada olemasoleva tee äärde.

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I-M I-L1 1406319 4 7036 Liin ristub olemasolevate elektriliinidega. Koridor ei puuduta kaitsevööndeid. Olemasolev liinikoridor on elamute ja kaitsealade vahel ning koridori laiendamine toimuks elamute kaitsetsoonis. Seetõttu on planeeritav koridor viidud kaitsealadest eemale. Üks tugipost on võimalik paigutada riigimaale, üks tugipostidest on võimalik paigutada olemasoleva tee lähedusse, olemasoleva liini koridori.

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L1-L2a 817104 6 7358 L1-L2 kontrollpunktide piirkonda jääb I kategooria kaitsealune taim ( kõrvaloleval fotol roosa polügoonina). Ainus võimalus kõiki välistavaid kriteeriume vältida on viia 60+60 m läbimõõduga liinikoridorid mõlemalt poolt kaitsealuse liigi elupaika. Kahe trassi vahele jääb I kaitsekategooria – merikotka – elupaik ( kõrvaloleval fotol punase polügoonina). L1 nurgapunkt on võimalik paigutada riigi maale, olemasoleva tee kõrvale.

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L1-L2b 683726 5 3419 100+100 läbimõõduga koridor ei mahu kaitsealade vahele selliselt, et puutumust ei oleks. Olemasolevat liinikoridori tuleks laiendada, kuid laiendamine toimuks kas kaitsealuse liigi (kõrvaloleval fotol roosa polügoon) elupaiga või elamute kaitsetsooni arvelt (kõrvaloleval fotol punane ring). Koridor möödub I kaitsekategooria liigi – merikotkas – elupaiga lähedalt.

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L2-M 4006702 7 20037 Liin kulgeb võimalikult sirgjooneliselt, vältides elamualade ja kaitsealuste liikide kaitsetsoone. Olemasolevat liinikoridori pole võimalik kasutada, kuna see asub elamualade vahel ning läbib Kura kurgu loodusala

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M_Kaabel 1 Õhuliini üleminekukoht kaabliks asub ca 600 m kaugusel rannikul olevast Natura 2000 alast. Üleminekukoht on võimalik rajada olemasoleva tee lähedusse.

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3. Trassikoridoride võrdlemine

Järgnevalt on esitatud erinevate trassikoridori alternatiivide võrdlustulemused kontrollpunktide A-H,

A-I ning A-M vahel. Kontrollpunkt A tähistab merekaabli üleminekukohta õhuliiniks, kontrollpunktid

H, I ning M tähistavad õhuliinilt merekaabliks üleminekukohta. Eelistused on kujundatud piirkondade

kaupa (vt selgitusi ptk 2).

Detailsed võrdlustulemused on maatriksina lisatud käesolevale aruandele (Lisa 2).

Joonis 7. Trassikoridoride võrdlemise piirkonnad

3.1. Eelistatud trassikoridor lõigus A-H

Eelistatud trassikoridori kujundamise aluseks on valdavalt elamute ja elamualade paiknemine,

Natura 2000 ja teiste looduskaitseliste piirangute olemasolu ning tehnilised kriteeriumid – ennekõike

võimalikult lühike ja sirge trassikoridor, kui see on muid kriteeriumide valdkondi silmas pidades

võimalik.

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Joonis 8. Eelistatud trassikoridori skeem lõigus A-H. Joonisel kuvatud eelistatud

trassikoridori kulgemine Natura 2000 alade (roosa viirutus) ning elamute (punasega)

taustal.

3.1.1. Võrdlustulemused piirkonnas A-B

Joonis 9. Võrreldud trassikoridorid piirkonnas A-B

Summaarne eelistus

Kokkuvõtvalt saab piirkonnas A-B eelistuse trassikoridor AB-4, kuna see vastab enim tehnilistele

kriteeriumidele – kõige lühem ja sirgem võimalik koridor, mistõttu on tegemist ka kõige odavama

koridoriga antud lõigus. Ka sotsiaalmajanduslike kriteeriumide (nt kaugus elamutest) lõikes on tegu

kõige soodsama koridoriga. Kuna looduskriteeriumide vaates – nt Natura 2000 alade lähedus,

puutumus I ja II kaitsekategooria liikidega – ei ole antud lõigus väga tugevat eelistust ühelgi koridoril,

tuleb eelistuse kujundamisel lähtuda tehnilistest kriteeriumidest, kui trassikoridori visandamise

baaskriteeriumist.

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Joonis 10. Eelistatud trassikoridor piirkonnas A-B

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes saab tugeva eelistuse trassilõik AB-4, kuna trassikoridori

puhveralasse (250 meetrit) jääb kõige vähem elamuid, trassikoridor eeldab kõige väiksema hulga

erametsa raadamist ning eraomandis olevate maade hulk trassikoridoris on kõige väiksem.

KOOND AB-1 AB-2 AB-3 AB-4 AB-5

Elamuga elamumaa sihtotstarbega

kinnistu läbimine

Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud hooned

Kõrval- või tootmishooned

Väärtuslikud maastikud, ilusa vaatega

kohad ja teelõigud

Tiheasustusalade paiknemine

Puhkealade läbimine

Raadatava erametsa pind

Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik maakasutus

Kehtestatud detailplaneeringutega alad

Väljastatud projekteerimistingimustega

katastriüksused

Eraomandis olevad katastriüksused

Avalikus omandis olevad

katastriüksused

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Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide lõikes on trassikoridorid suhteliselt võrreldavad. Mitte-eelistuse (kuigi

mitte tugeva) saab trassilõik AB-3, kuna sellesse trassikoridori jääb 1 kultuuripärandi objekt.

Võrdlustulemustes on ülejäänud trassikoridorid loetud võrdseteks.

KOOND AB-1 AB-2 AB-3 AB-4 AB-5

Kultuurimälestis (vastavalt

muinsuskaitseseadusele)

Kalmistud

Kirikud ja pühakojad

Kultuuripärand (PKO, XX saj

arhitektuuripärand, maaehituspärand,

militaarpärand, matmispaigad)

Kohaliku kaitse alused alad ja objektid

Miljööväärtuslikud alad

Looduskeskkonna kriteeriumid

Looduskeskkonna kriteeriumide lõikes saab eelistuse trassikoridor AB-2, kuna see on eelistatud

(kuigi nõrgalt) Natura 2000 puutumuse kontekstis ning ta lõikab III kaitsekategooria liikide elupaiku

vähem. Looduskeskkonna kriteeriumide lõikes on üldjuhul kõik koridorid mitte-eelistatud, kuna

omavad kõik puutumust Natura 2000 võrgustiku aladega (mööduvad alade lähedalt) ning koridoride

vahetus läheduses (kuni 200 m koridori välisservast) asuvad I kaitsekategooria liigid.

KOOND AB-1 AB-2 AB-3 AB-4 AB-5

Mõju kaitsealadele (Natura 2000 alad,

kaitsealad, hoiualad)

I ja II kaitsekategooria

liigid

III kaitsekategooria

liigid

Mõju muule kaitstavale

loodusobjektile va kaitsealad (vääriselupaigad, kaitsekategooriata

üksikobjektid)

Maakonnaplaneeringuga kavandatud

rohevõrgustiku vähendamine ja

killustamine

Kavandatavad kaitsealused liigid ja

kaitsealad

Tehnilised kriteeriumid

Tehniliste kriteeriumide lõikes saab eelistuse trassikorid AB-4, mis on kõige lühem (5,78 km),

mistõttu summaarselt ka odavaim. Ka trassikoridoride pöörete (nurgapostide arv) on antud trassil

kõige lühem, mis annab samuti tugeva eelistuse teiste koridoride ees. Näiteks mitte-eelistatud AB-3

on eelistatud koridorist AB-4 ligi kaks korda pikem.

KOOND AB-1 AB-2 AB-3 AB-4 AB-5

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Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise keerukus

Ristumised olemasolevate

taristuelementidega

Olemasolevate trassikoridoride

kasutamine

3.1.2. Võrdlustulemused piirkonnas B-C

Joonis 11. Võrreldud trassikoridorid piirkonnas B-C

Summaarne eelistus

Kokkuvõtvalt saab piirkonnas B-C eelistuse trassikoridor BC-2, kuna see vastab enim tehnilistele

kriteeriumidele – kõige lühem võimalik koridor, mistõttu on tegemist ka kõige odavama koridoriga

antud lõigus. Ka sotsiaalmajanduslike kriteeriumide (nt kaugus elamutest) lõikes on tegu kõige

soodsama koridoriga. Kuna looduskriteeriumide vaates – nt Natura 2000 alade lähedus, puutumus I

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ja II kaitsekategooria liikidega – ei ole antud lõigus väga tugevat eelistust ühelgi koridoril, tuleb

eelistuse kujundamisel lähtuda tehnilistest kriteeriumidest, kui trassikoridori visandamise

baaskriteeriumist.

Joonis 12. Eelistatud trassikoridor lõigus B-C

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes saab piirkonnas B-C eelistuse koridorid BC-1, BC-2, BC-7

ning BC-8. Tegemist on koridoridega, millel kõigil on mingi kriteeriumi lõikes tugev eelistus:

• Koridorid BC-1 ja BC-2 domineerivad trassikoridorist 250 meetri kaugusele jäävate elamute

vähesusega (9), kui mitte-eelistatud koridorides on see näitaja 14.

• Koridorid BC-1 ja BC-2 saavad eelistuse BC-7 ja BC-8 ees raadamist vajava erametsa pindala

osas. Samas raadamist vajava riigimetsa pindalade osas on suurusjärgud sarnased.

• Koridorid BC-7 ja BC-8 saavad eelise trassikoridori jäävate avalikus omandis olevate

katastriüksuste pindala osas.

Kuigi summaarselt on BC-7 ja BC-8 osas tugevaid eelistusi enam, tuleb baaskriteeriumi „elu- või

ühiskondlikud hooned“ tugeva eelistuse tõttu lugeda samaväärseks ka koridorid BC-1 ja BC-2.

KOOND BC-1 BC-2 BC-3 BC-4 BC-5 BC-6 BC-7 BC-8

Elamuga elamumaa

sihtotstarbega kinnistu

läbimine

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Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud

hooned

Kõrval- või tootmishooned

Väärtuslikud maastikud,

ilusa vaatega kohad ja

teelõigud

Tiheasustusalade

paiknemine

Puhkealade läbimine

Raadatava erametsa pind

Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik

maakasutus

Kehtestatud

detailplaneeringutega alad

Väljastatud

projekteerimistingimustega

katastriüksused

Eraomandis olevad

katastriüksused

Avalikus omandis olevad

katastriüksused

Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide osas on ainsaks eelistuse kujunemise aluseks kultuuripärandi objektide

arv trassikoridoris. Selle tõttu saavad eelistuse BC-6 ja BC-8, mille mõlemasse koridori jääb 5

kultuuripärandi objekti. Antud objektide hulk trassikoridoris võib valla üldplaneeringu koostamise

käigus muutuda, kuna tegu ei ole muinsuskaitseseaduse kaitse all olevate objektidega.

Teiste kultuuriliste kriteeriumide lõikes on trassikoridorid võrdsed.

KOOND BC-1 BC-2 BC-3 BC-4 BC-5 BC-6 BC-7 BC-8

Kultuurimälestis (vastavalt

muinsuskaitseseadusele)

Kalmistud

Kirikud ja pühakojad

Kultuuripärand (PKO, XX saj

arhitektuuripärand,

maaehituspärand,

militaarpärand,

matmispaigad)

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Kohaliku kaitse alused alad

ja objektid

Miljööväärtuslikud alad

Looduskeskkonna kriteeriumid

Looduskeskkonna kriteeriumide lõikes saab tugeva eelistuse koridor BC-3, kuna koridori puutumus

Natura 2000 aladega kui looduskeskkonna vaates suurima konfliktala osas, on antud koridoril

väikseim. Kuigi koridor saab mitte-eelistuse I ja II kaitsekategooria puutumuse osas, on see suuresti

võrdne või sarnane teiste koridoridega, mis ei vähenda koridori tugevat eelistust.

Looduskeskkonna kriteeriumide lõikes on üldjuhul kõik (õhuliini) koridorid mitte-eelistatud, kuna

omavad kõik puutumust Natura 2000 võrgustiku aladega (mööduvad alade lähedalt) ning koridoride

vahetus läheduses (kuni 200 m koridori välisservast) asuvad I kaitsekategooria liigid.

KOOND BC-1 BC-2 BC-3 BC-4 BC-5 BC-6 BC-7 BC-8

Mõju kaitsealadele (Natura 2000 alad, kaitsealad,

hoiualad)

I ja II kaitsekategooria

liigid

III kaitsekategooria

liigid

Mõju muule kaitstavale

loodusobjektile va kaitsealad (vääriselupaigad,

kaitsekategooriata

üksikobjektid)

Maakonnaplaneeringuga kavandatud rohevõrgustiku

vähendamine ja killustamine

Kavandatavad kaitsealused

liigid ja kaitsealad

Tehnilised kriteeriumid

Tehniliste kriteeriumide lõikes saavad tugeva eelistuse BC-1 ja BC-2, kuna tegu on kõige lühemate

koridoridega, mis omakorda tähendab kõige soodsama maksumusega koridore. Tugev eelistus on

kujunenud ka olemasolevate koridoridega ristumise osas. Pöörete arvu ehk nurgapostide vajaduse

osas tõuseb esile, kuigi mitte suure eduga, koridor BC-2 (6 versus 7 nurgaposti). Kokkuvõtvalt on

koridorid BC-1 ja BC-2 tehniliste kriteeriumide lõikes praktiliselt võrdsed ning eelistuse kujunemise

aluseks kokkuvõtvalt on teised kriteeriumide valdkonnad ning nendes kujunenud trassikoridori

eelistused.

KOOND BC-1 BC-2 BC-3 BC-4 BC-5 BC-6 BC-7 BC-8

Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise

keerukus

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Ristumised olemasolevate

taristuelementidega

Olemasolevate

trassikoridoride kasutamine

3.1.3. Võrdlustulemused piirkonnas C-D

Summaarne eelistus

Kokkuvõtvalt saab piirkonnas C-D eelistuse trassikoridor CD-1, kuna see vastab enim looduslikele

kriteeriumidele ning saab eelise miljööala läbimise ulatuse osas. Kuigi tehniliselt on tegemist veidi

pikema (ca 700 m ning üks nurgapost) trassiga, kui samas piirkonnas võrreldav koridor CD-2, on

looduslikud ja kultuurilised kriteeriumid piisavalt kaalukad, et anda koridorile CD-1 tugev eelis.

Joonis 13. Eelistatud trassikoridor lõigus C-D

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes saab piirkonnas C-D eelistuse koridor CD-2. Kuigi eelistus

ei ole tugev ning selle valdavaks mõjutajaks on põllumajandusliku maakasutuse suurem hulk koridori

CD-1 ees, on eelistuse kujundajaks ka eraomandis oleva maa väiksem hulk võrreldes CD-1-ga (CD-

2 vastav näitaja 54 ha, CD-1 puhul 70 ha). Kuna CD-1 saab näiteks raadatava erametsa osas ning

üldiselt eramaa hulga osas mitte-eelistused, kui CD-2-l on mitte-eelistusi üks – raadatava riigimetsa

pindala hulk.

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KOOND CD-1 CD-2

Elamuga elamumaa

sihtotstarbega kinnistu läbimine

Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud hooned

Kõrval- või tootmishooned

Väärtuslikud maastikud, ilusa

vaatega kohad ja teelõigud

Tiheasustusalade paiknemine

Puhkealade läbimine

Raadatava erametsa pind

Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik maakasutus

Kehtestatud

detailplaneeringutega alad

Väljastatud

projekteerimistingimustega

katastriüksused

Eraomandis olevad

katastriüksused

Avalikus omandis olevad

katastriüksused

Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide osas on ainsaks eelistuse kujunemise aluseks miljööväärtuslike alade

läbimine. Kuigi pindalalt (hektarites) läbivad mõlemad võrreldavad trassikoridorid valla

üldplaneeringuga kavandatud Karida miljööväärtuslikku ala praktiliselt võrdselt – 2,47 ha vs 2,78 ha

– läbib CD-1 miljööala selle servalt, samas kui CD-2 kulgeb läbi miljööala selle keskosast. Sellest

tulenevalt saab kultuuriliste kriteeriumide lõikes eelise (mitte tugeva) CD-1.

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Joonis 14. Trassikoridoride CD-1 ja CD-2 paiknemine miljööväärtusliku ala suhtes (vt

joonisel lilla polügoonina).

Teiste kultuuriliste kriteeriumide lõikes on trassikoridorid võrdsed.

KOOND CD-1 CD-2

Kultuurimälestis (vastavalt

muinsuskaitseseadusele)

Kalmistud

Kirikud ja pühakojad

Kultuuripärand (PKO, XX saj

arhitektuuripärand, maaehituspärand,

militaarpärand, matmispaigad)

Kohaliku kaitse alused alad ja objektid

Miljööväärtuslikud alad

Looduskeskkonna kriteeriumid

Looduskeskkonna kriteeriumide lõikes saab tugeva eelistuse koridor CD-1, kuna koridoril puudub

puutumus I, II ja III kaitsekategooria liikidega. Koridori CD-2 puhul läbib koridor II kaitsekategooria

taimeliigi kasvukohta ning nelja III kaitsekategooria liigi elupaika. CD-2 läbib ka suuremas mahus

maakonnaplaneeringuga kavandatud rohevõrgustikku8.

8 Rohevõrgustiku paiknemine täpsustatakse Saaremaa valla üldplaneeringu koostamisel. Üldplaneeringu

koostamisel on muuhulgas võimalik täpsustada rohevõrgustiku paiknemist või kavandada rohevõrgustiku

toimimiseks leevendavad meetmed.

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KOOND CD-1 CD-2

Mõju kaitsealadele (Natura 2000 alad, kaitsealad,

hoiualad)

I ja II kaitsekategooria

liigid

III kaitsekategooria

liigid

Mõju muule kaitstavale

loodusobjektile va kaitsealad (vääriselupaigad,

kaitsekategooriata

üksikobjektid)

Maakonnaplaneeringuga kavandatud rohevõrgustiku

vähendamine ja killustamine

Kavandatavad kaitsealused

liigid ja kaitsealad

Tehnilised kriteeriumid

Tehniliste kriteeriumide lõikes saab tugeva eelistuse CD-2, kuna tegu on kõige lühema ja võimalikult

sirge koridoriga, mis omakorda tähendab kõige soodsamat maksumust. CD-1 on võrreldes CD-2-ga

veidi pikem, mistõttu kokkuvõttes kallim, kuid vahe ei ole tugevat mitte-eelistust tekitav.

KOOND CD-1 CD-2

Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise

keerukus

Ristumised olemasolevate

taristuelementidega

Olemasolevate

trassikoridoride kasutamine

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3.1.4. Võrdlustulemused piirkonnas D-E

Joonis 15. Piirkonnas D-E võrreldavad trassikoridori alternatiivid.

Summaarne eelistus

Kokkuvõtvalt saab piirkonnas D-E eelistuse trassikoridor DE-1, kuna see on kõigi hinnatavate

kriteeriumide valdkondade lõikes eelsitatud või tugevalt eelistatud. Kuigi looduslike ning kultuuriliste

kriteeriumide lõikes ei kujune eelistus väga ülekaalukalt, mängib tugeva eelistuse kujunemisel rolli

märgatav trasside pikkuse erinevus – 6,5 km DE-1 puhul versus 10,42 km DE-2 puhul – tehes DE-1

eelistuse seeläbi baaskriteeriumi ehk trassi odavuse osas tugevalt eelistatud koridoriks.

Trassikoridori alternatiivi DE-1 mahub vajadusel kaks paralleelset liini. Koridori DE-2 puhul peab kahe

liini rajamiseks toimuma koridori hargnemine (vt joonis 15).

Joonis 16. Eelistatud trassikoridor lõigus D-E

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes saab piirkonnas D-E eelistuse koridor DE-1. Kuigi koridoril

DE-1 ei ole antud kriteeriumide lõikes ühtki tugevat eelistust, annavad seitse nõrka eelistust ning

mitte ühtegi mitte-eelistust piisava eelise selle trassikoridori esile toomiseks DE-2 ees (üks tugev

eelistus ja 6 mitte-eelistust). Peamiselt on eelistus kujunenud trassikoridori jäävate elamumaade,

eramaade ning raadamist vajava metsamaa pinnalt – DE-1 saab nende kriteeriumide lõikes nõrga

eelistuse DE-2 ees. Ka olulise baaskriteeriumi – elamute arv 250 meetrises puhveralas – saab DE-1

nõrga eelise DE-2.

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KOOND DE-1 DE-2

Elamuga elamumaa sihtotstarbega kinnistu

läbimine

Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud

hooned

Kõrval- või tootmishooned

Väärtuslikud maastikud,

ilusa vaatega kohad ja

teelõigud

Tiheasustusalade

paiknemine

Puhkealade läbimine

Raadatava erametsa pind

Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik

maakasutus

Kehtestatud

detailplaneeringutega alad

Väljastatud

projekteerimistingimustega

katastriüksused

Eraomandis olevad

katastriüksused

Avalikus omandis olevad

katastriüksused

Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide osas on ainsaks eelistuse kujunemise aluseks kultuuripärandi objektide

arv trassikoridoris. DE-1 puhul on trassikoridoris 5 kultuuripärandi objekti. DE-2 puhul on sama

näitaja 6. Teiste kultuuriliste kriteeriumide lõikes on trassikoridorid võrdsed.

KOOND DE-1 DE-2

Kultuurimälestis (vastavalt

muinsuskaitseseadusele)

Kalmistud

Kirikud ja pühakojad

Kultuuripärand (PKO, XX saj arhitektuuripärand, maaehituspärand,

militaarpärand, matmispaigad)

Kohaliku kaitse alused alad ja objektid

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Miljööväärtuslikud alad

Looduskeskkonna kriteeriumid

Looduskeskkonna kriteeriumide lõikes saab tugeva eelistuse koridor DE-1, kuna koridori puutumus

Natura aladega on väiksem ning väiksem (mitte oluliselt – ca 8 ha osas) on ka konflikt

maakonnaplaneeringuga kavandatud rohevõrgustiku aladega. Seega ei saa DE-1 olulist eelist

looduskriteeriumide lõikes DE-2 ees.

KOOND DE-1 DE-2

Mõju kaitsealadele (Natura

2000 alad, kaitsealad,

hoiualad)

I ja II kaitsekategooria

liigid

III kaitsekategooria

liigid

Mõju muule kaitstavale

loodusobjektile va

kaitsealad (vääriselupaigad,

kaitsekategooriata

üksikobjektid)

Maakonnaplaneeringuga

kavandatud rohevõrgustiku

vähendamine ja killustamine

Kavandatavad kaitsealused

liigid ja kaitsealad

Tehnilised kriteeriumid

Tehniliste kriteeriumide lõikes saab tugeva eelistuse DE-1, kuna tegu on oluliselt (ca 4 km) lühema

ja võimalikult sirge koridoriga, mis omakorda tähendab kõige soodsamat maksumust. DE-1 vajalike

nurgapostide arv on samuti väiksem, võrreldes DE-2-ga. DE-2 kulgeb ca 800 meetrit pikemalt

paralleelselt olemasoleva liinikoridoriga. Eelistus on võrreldes DE-1 kogupikkusega mitteoluline.

KOOND DE-1 DE-2

Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise

keerukus

Ristumised olemasolevate

taristuelementidega

Olemasolevate

trassikoridoride kasutamine

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3.1.5. Võrdlustulemused piirkonnas E-F

Joonis 17. Piirkonnas E-F võrreldavad trassikoridori alternatiivid.

Summaarne eelistus

Kuna piirkonnas E-F kulgevad koridorid valdavas osas samal trajektooril, saavad koridorid EF-1 ja

EF-2 kokkuvõtvalt võrdsed võrdluspunktid. Kuna koridorid on kriteeriumide gruppide lõikes võrdsed,

tuleb summaarne eelistus kujundada üksiktingimuse alusel. Baaskriteeriumi – elu- ja ühiskondlike

hoonete arv 250 meetri kaugusel trassikoridorist – osas saab eelistuse koridor EF-1, mistõttu on

piirkonnas E-F ka eelistatud trassikoridoriks EF-1. Eelistus võib muutuda liinikoridori edasisel

kavandamisel ja projekteerimisel, mh ka keskkonna jmt tingimuste täpsustamisel.

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Joonis 18. Eelistatud trassikoridor lõigus E-F

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes saab piirkonnas E-F eelistuse koridor EF-2. Peamine eelis

tuleneb elamumaa sihtotstarbega katastriüksuste läbimisest. Eelistatud koridor EF-2 elamumaid ei

läbi. Võrreldav koridor EF-1 läbib elamumaid ca 1,2 hektaril. Samas saab EF-1 eelise elu- ja

ühiskondlike hoonete hulga osas, mis jäävad 250 meetri kaugusele trassikoridorist. Kui EF-1 puhul

on neid hooneid 11, siis EF-2 puhul pea kaks korda rohkem – 20. Kokkuvõtvalt saab EF-2 eelistuse

sotsiaalmajanduslike kriteeriumide lõikes, kuid see ei ole ülekaalukas eelistus.

KOOND EF-1 EF-2

Elamuga elamumaa

sihtotstarbega kinnistu

läbimine

Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud

hooned

Kõrval- või tootmishooned

Väärtuslikud maastikud, ilusa vaatega kohad ja

teelõigud

Tiheasustusalade

paiknemine

Puhkealade läbimine

Raadatava erametsa pind

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Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik

maakasutus

Kehtestatud

detailplaneeringutega alad

Väljastatud

projekteerimistingimustega

katastriüksused

Eraomandis olevad

katastriüksused

Avalikus omandis olevad

katastriüksused

Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide osas on ainsaks eelistuse kujunemise aluseks kultuuripärandi objektide

arv trassikoridoris. EF-1 puhul ei ole trassikoridoris ühtki kultuuripärandi objekti. DE-2 puhul on sama

näitaja 1. Teiste kultuuriliste kriteeriumide lõikes on trassikoridorid võrdsed.

KOOND EF-1 EF-2

Kultuurimälestis (vastavalt

muinsuskaitseseadusele)

Kalmistud

Kirikud ja pühakojad

Kultuuripärand (PKO, XX saj

arhitektuuripärand, maaehituspärand,

militaarpärand, matmispaigad)

Kohaliku kaitse alused alad ja objektid

Miljööväärtuslikud alad

Looduskeskkonna kriteeriumid

Looduskeskkonna kriteeriumide lõikes saab nõrga eelistuse koridor EF-2, kuna koridori puutumus

maakonnaplaneeringuga kavandatud rohevõrgustiku aladega9 on ca 20 hektarit väiksem, kui koridori

EF-1 puhul. Muude looduskriteeriumide lõikes on trassikoridorid võrdsed.

KOOND EF-1 EF-2

Mõju kaitsealadele (Natura

2000 alad, kaitsealad,

hoiualad)

I ja II kaitsekategooria

liigid

9 Rohevõrgustiku paiknemine täpsustatakse Saaremaa valla üldplaneeringu koostamisel. Üldplaneeringu

koostamisel on muuhulgas võimalik täpsustada rohevõrgustiku paiknemist või kavandada rohevõrgustiku

toimimiseks leevendavad meetmed.

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III kaitsekategooria

liigid

Mõju muule kaitstavale

loodusobjektile va

kaitsealad (vääriselupaigad,

kaitsekategooriata

üksikobjektid)

Maakonnaplaneeringuga

kavandatud rohevõrgustiku

vähendamine ja killustamine

Kavandatavad kaitsealused

liigid ja kaitsealad

Tehnilised kriteeriumid

Tehniliste kriteeriumide lõikes saab nõrga eelistuse EF-1, kuna trassikoridori alternatiiv lõikub vähem

olemasolevate taristuelementidega (teed). Kui EF-1 lõikub 22 teega, siis EF-2 puhul on see näitaja

27. Arvestades, et trassikoridorid jooksevad valdavas enamuses samas koridoris, on muus osas

trassikoridori alternatiivid ka tehniliste kriteeriumide lõikes võrdsed.

KOOND DE-1 DE-2

Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise

keerukus

Ristumised olemasolevate

taristuelementidega

Olemasolevate

trassikoridoride kasutamine

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3.1.6. Võrdlustulemused piirkonnas F-G

Joonis 19. Piirkonnas F-G võrreldavad trassikoridori alternatiivid.

Summaarne eelistus

Piirkonnas F-G on trassikoridori eelistuse kujunemise ainsaks asjaoluks tehnilised kriteeriumid, kus

tugeva eelistuse saab trassikoridor FG-1 tulenevalt sellest, et see koridor on ca 2 km lühem koridorist

FG-2; see ristub 12 teega, samas kui FG-2 koridoril on ristumisi 30. Ülejäänud kriteeriumide

valdkondade lõikes on antud piirkonnas võrreldud trassikoridorid võrdsed.

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Joonis 20. Eelistatud trassikoridor lõigus E-F

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes on trassikoridorid FG-1 ja FG-2 võrdsed. Trassikoridor FG-

1 saab teatava eelise elu- või ühiskondlike hoonete paiknemise osas (6 hoonet trassikoridoris versus

12 hoonet FG-2 puhul). Olulisemate erinevustena saab antud kriteeriumide puhul välja tuua ka veel

asjaolud, et FG-2 ei ole puutumust maardlate ja mäeeraldistega (FG-1 sama näitaja ca 20 hektarit)

ning FG-2 kulgeb valdavalt põllumajanduslikul maal (puudub vajadus metsa ulatuslikuks

raadamiseks). Vastavad näitajad 29 hektarit versus 53 hektarit.

KOOND FG-1 FG-2

Elamuga elamumaa sihtotstarbega

kinnistu läbimine

Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud hooned

Kõrval- või tootmishooned

Väärtuslikud maastikud, ilusa vaatega

kohad ja teelõigud

Tiheasustusalade paiknemine

Puhkealade läbimine

Raadatava erametsa pind

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Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik maakasutus

Kehtestatud detailplaneeringutega alad

Väljastatud projekteerimistingimustega

katastriüksused

Eraomandis olevad katastriüksused

Avalikus omandis olevad

katastriüksused

Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide osas on võrreldud trassikoridorid võrdsed.

KOOND FG-1 FG-2

Kultuurimälestis (vastavalt

muinsuskaitseseadusele)

Kalmistud

Kirikud ja pühakojad

Kultuuripärand (PKO, XX saj

arhitektuuripärand, maaehituspärand,

militaarpärand, matmispaigad)

Kohaliku kaitse alused alad ja objektid

Miljööväärtuslikud alad

Looduskeskkonna kriteeriumid

Looduskriteeriumide osas on võrreldud trassikoridorid võrdsed. Erinevused on III kaitsekategooria

elupaikade puutumuses (FG-1 ei läbi elupaiku, FG-2 läbib ühte elupaika) ning

maakonnaplaneeringuga kavandatud rohevõrgustiku läbimise ulatuses (81 hektarit versus 43

hektarit). Kuna tegemist on looduskeskkonna kriteeriumide vaates käesoleva töö täpsusastmes mitte

baaskriteeriumidega, ei ole trassikoridorides kokkuvõttes erinevusi.

KOOND FG-1 FG-2

Mõju kaitsealadele

(Natura 2000 alad,

kaitsealad, hoiualad)

I ja II

kaitsekategooria

liigid

III kaitsekategooria

liigid

Mõju muule kaitstavale

loodusobjektile va kaitsealad

(vääriselupaigad,

kaitsekategooriata

üksikobjektid)

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Maakonnaplaneeringuga

kavandatud rohevõrgustiku

vähendamine ja

killustamine

Kavandatavad kaitsealused liigid ja

kaitsealad

Tehnilised kriteeriumid

Käesolevas lõigus on tehnilised kriteeriumid trassikoridori eelistuse kujunemisel määrava tähtsusega.

Kuna trassikoridor FG-1 on lühem ja seetõttu ka odavam, saab koridor tehniliste kriteeriumide lõikes

eelistuse. Kuigi FG-2 kulgeb ca 3 km ulatuses paralleelselt olemasoleva liinikoridoriga, on see ca 2

km pikem kui FG-1, mistõttu muutub FG-2 maksumus siiski oluliselt kõrgemaks.

KOOND FG-1 FG-2

Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise

keerukus

Ristumised olemasolevate

taristuelementidega

Olemasolevate

trassikoridoride kasutamine

3.1.7. Võrdlustulemused piirkonnas G-H

Piirkonnas G-H visandati üks trassikoridor, mis kulgeb võimalikult sirgelt, vältides hoonete ja

kaitsealuste loodusobjektide kaitsetsoone. Alternatiivseid koridore, mis oleksid võrreldavad, ei ole

antud piirkonnas tuvastatud.

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Joonis 21. Eelistatud trassikoridor piirkonnas G-H

Kontrollpunktis H läheb õhuliin üle merekaabliks ning suubub siit merre. Alal tuleb hinnata võimalikku

konflikti Natura 2000 alaga elektriühenduse edasisel kavandamisel.

3.2. Eelistatud trassikoridor lõigus A-B-I

Eelistatud trassikoridori kujundamise aluseks on valdavalt elamute ja elamualade paiknemine,

Natura 2000 ja teiste looduskaitseliste piirangute olemasolu ning tehnilised kriteeriumid – ennekõike

võimalikult lühike ja sirge trassikoridor, kui see on muid kriteeriumide valdkondi silmas pidades

võimalik.

Joonis 22. Eelistatud trassikoridori skeem lõigus A-B-I. Joonisel kuvatud eelistatud

trassikoridori kulgemine Natura 2000 alade (roosa viirutus) ning elamute (punasega)

taustal.

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3.2.1. Võrdlustulemused piirkonnas A-B-I

Joonis 23. Piirkonnas A-B-I võrreldavad trassikoridori alternatiivid.

Summaarne eelistus

Piirkonnas A-B-I on võrreldavad trassikoridorid praktiliselt võrdsed. Kui AI-1 saab nõrga eelistuse

sotsiaalsete ja tehniliste kriteeriumide lõikes, siis AI-2 saab eelistuse looduslike ja kultuuriliste

kriteeriumide lõikes. Seega on eelistatud trassikoridor kujundatud üksikkriteeriumide lõikes –

koridori AI-1 jääb vähem elu- ja ühiskondlikke hooneid, see mõjutab vähem eraomandis olevaid

maid ning ristub vähem olemas

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes saab nõrga eelistuse trassikoridor AI-1 ning seda

ennekõike elu- ja ühiskondlike hoonete arvu osas 250 meetri kaugusel trassikoridorist (6 versus 7)

ning eramaade osakaalu osas trassikoridoris – lõigus AI-1 on eraomandis olevaid katastriüksuseid

30 ha võrra vähem kui lõigus AI-2.

KOOND AI-1 AI-2

Elamuga elamumaa sihtotstarbega

kinnistu läbimine

Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud hooned

Kõrval- või tootmishooned

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Väärtuslikud maastikud, ilusa vaatega

kohad ja teelõigud

Tiheasustusalade paiknemine

Puhkealade läbimine

Raadatava erametsa pind

Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik maakasutus

Kehtestatud detailplaneeringutega alad

Väljastatud projekteerimistingimustega

katastriüksused

Eraomandis olevad katastriüksused

Avalikus omandis olevad

katastriüksused

Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide osas on võrreldud trassikoridorid praktiliselt võrdsed. Selgelt eristuvad

koridorid kultuuripärandi osas – AI-2 koridoris on vaid 1 kultuuripärandi objekt, koridoris AI-1 on

neid 5. Seetõttu saab kultuuriliste kriteeriumide osas lõigus A-B-I eelistuse koridor AI-2.

KOOND AI-1 AI-2

Kultuurimälestis (vastavalt

muinsuskaitseseadusele)

Kalmistud

Kirikud ja pühakojad

Kultuuripärand (PKO, XX saj arhitektuuripärand, maaehituspärand,

militaarpärand, matmispaigad)

Kohaliku kaitse alused alad ja objektid

Miljööväärtuslikud alad

Looduskeskkonna kriteeriumid

Looduskriteeriumide osas erinevad antud lõigus trassikoridorid üksnes III kaitsekategooria

elupaikade läbimise osas ning maakonnaplaneeringuga kavandatud rohevõrgustiku läbimise osas. III

kaitsekategooria elupaiku läbib AI-2 5 võrra vähem (18 versus 13) ning rohevõrgustiku läbib AI-2 ca

50 ha võrra vähem kui AI-1 (189 versus 131 hektarit). Looduskeskkonna kriteeriumide osas saab

seetõttu eelistuse trassikoridor AI-2.

KOOND AI-1 AI-2

Mõju kaitsealadele (Natura 2000 alad,

kaitsealad, hoiualad)

I ja II kaitsekategooria

liigid

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III kaitsekategooria

liigid

Mõju muule kaitstavale

loodusobjektile va kaitsealad

(vääriselupaigad, kaitsekategooriata

üksikobjektid)

Maakonnaplaneeringuga kavandatud

rohevõrgustiku vähendamine ja

killustamine

Kavandatavad kaitsealused liigid ja

kaitsealad

Tehnilised kriteeriumid

Käesolevas lõigus kujuneb tehniliste kriteeriumide lõikes eelistus AI-1 kasuks lähtuvalt ristumiste

arvust olemasolevate taristuelementidega – AI-1 puhul on ristumisi olemasolevate teedega 33, kui

AI-2 trassikoridori puhul on neid 43. Trassikoridoride pöörete arvu osas on trassikoridorid praktiliselt

võrdsed – AI-1 puhul on eeldatav nurgapostide vajadus 7 ning AI-2 puhul on see 6. Seetõttu saab

tehniliste kriteeriumide lõikes antud lõigus nõrga eelistuse trassikoridor AI-1.

KOOND AI-1 AI-2

Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise keerukus

Ristumised olemasolevate

taristuelementidega

Olemasolevate trassikoridoride

kasutamine

3.3. Eelistatud trassikoridor lõigus A-I-M

Eelistatud trassikoridori kujundamise aluseks on valdavalt elamute ja elamualade paiknemine,

Natura 2000 ja teiste looduskaitseliste piirangute olemasolu ning tehnilised kriteeriumid – ennekõike

võimalikult lühike ja sirge trassikoridor, olemasoleva liinikoridori kasutamine, kui see on muid

kriteeriumide valdkondi silmas pidades võimalik.

Trassikoridori eelistuse kujunemine lõigus A-B-I on esitatud peatükis 3.2.1.

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Joonis 24. Eelistatud trassikoridori alternatiiv lõigus A-I-M. Joonisel kuvatud eelistatud

trassikoridori kulgemine Natura 2000 alade (roosa viirutus) ning elamute (punasega)

taustal.

Alternatiivsed trassikoridorid on visandatud lõigus L1-L2. Teistes lõikudes alternatiivseid koridore ei

visandatud, kuna see ei olnud erinevate objektide kaitsevööndite tõttu võimalik.

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3.3.1. Võrdlustulemused piirkonnas L1-L2

Joonis 25. Piirkonnas L1-L2 võrreldavad trassikoridori alternatiivid

Summaarne eelistus

Piirkonnas L1-L2 on võrreldavad trassikoridorid (L1-L2a ja L1-L2b) praktiliselt võrdsed. Koridoride

suurim erinevus tuleneb nende laiusest – kui L1-L2a mahutab ühe liinikoridori, siis L1-L2b koridori

puhul on arvestatud kahe paralleelse liinikoridoriga. Liinikoridor L1-L2b kulgeb enamjaolt

olemasolevas õhuliini koridoris ning on eelistatud kõikide kriteeriumide valdkondade lõikes.

Tugevaim eelistus on kujunenud tehniliste kriteeriumide lõikes, kuna koridor on oluliselt lühem (3,4

km vs 7,3 km) kui L1-L2a ning seetõttu oluliselt madalama rajamismaksumusega.

Sotsiaalmajanduslikud kriteeriumid

Sotsiaalmajanduslike kriteeriumide lõikes saab eelistuse L1-L2b ennekõike kahe kriteeriumi tõttu –

elu- ja ühiskondlike hoonete paiknemine trassikoridorist 250 m kaugusel (6 versus 2) ning ligikaudu

20 hektari väiksema eramaade hulga tõttu trassikoridoris. Kuigi eelistus ei ole tugev, on see siiski

ilmne ja soositud ka muuhulgas olemasoleva liinikoridori ärakasutamise tõttu.

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KOOND L1-L2a L1-L2b

Elamuga elamumaa sihtotstarbega

kinnistu läbimine

Elamuta elamumaa

sihtotstarbega kinnistu

läbimine

Elu- või ühiskondlikud hooned

Kõrval- või tootmishooned

Väärtuslikud maastikud, ilusa vaatega

kohad ja teelõigud

Tiheasustusalade paiknemine

Puhkealade läbimine

Raadatava erametsa pind

Raadatava riigimetsa pind

Maardlad ja mäeeraldised

Põllumajanduslik maakasutus

Kehtestatud detailplaneeringutega alad

Väljastatud projekteerimistingimustega

katastriüksused

Eraomandis olevad katastriüksused

Avalikus omandis olevad

katastriüksused

Kultuurilised kriteeriumid

Kultuuriliste kriteeriumide osas on võrreldud trassikoridorid praktiliselt võrdsed. Selgelt eristuvad

koridorid kultuuripärandi osas – L1-L2b koridoris on vaid 1 kultuuripärandi objekt, koridoris L1-L2a

on neid 4. Seetõttu saab kultuuriliste kriteeriumide osas lõigus eelistuse koridor L1-L2b.

KOOND L1-L2a L1-L2b

Kultuurimälestis (vastavalt

muinsuskaitseseadusele) 00

Kalmistud 00

Kirikud ja pühakojad00

Kultuuripärand (PKO, XX saj

arhitektuuripärand, maaehituspärand,

militaarpärand, matmispaigad)

41

Kohaliku kaitse alused alad ja objektid0 0

Miljööväärtuslikud alad00

Looduskeskkonna kriteeriumid

Looduskriteeriumide osas erinevad antud lõigus trassikoridorid peamiselt üksnes

maakonnaplaneeringuga kavandatud rohevõrgustiku läbimise osas. Rohevõrgustiku läbib L1-L2b ca

Kõrgepingeliini asukohavalik Saaremaal

Trassikoridoride visandamise ja võrdlemise aruanne

70 / 71

30 ha võrra vähem kui L1-L2a (58 versus 28 hektarit). Looduskeskkonna kriteeriumide osas saab

seetõttu eelistuse trassikoridor L1-L2b.

KOOND L1-L2a L1-L2b

Mõju kaitsealadele (Natura 2000 alad,

kaitsealad, hoiualad)

I ja II kaitsekategooria

liigid

III kaitsekategooria

liigid

Mõju muule kaitstavale loodusobjektile va kaitsealad

(vääriselupaigad, kaitsekategooriata

üksikobjektid)

Maakonnaplaneeringuga kavandatud rohevõrgustiku vähendamine ja

killustamine

Kavandatavad kaitsealused liigid ja

kaitsealad

Tehnilised kriteeriumid

Käesolevas lõigus kujuneb tehniliste kriteeriumide lõikes tugev eelistus L1-L2b kasuks ennekõike

trassi pikkusest ning seeläbi rajamise maksumusest tulenevalt. Lõigus L1-L2b on ka ristumiste arv

olemasolevate teedega mõnevõrra väiksem – 4 teed lõigus L1-L2b versus 10 teed lõigus L1-L2a.

KOOND L1-L2a L1-L2b

Trassikoridori pikkus

Trassikoridori pöörete arv

Trassikoridori maksumus

Rajamise ja hooldamise keerukus

Ristumised olemasolevate

taristuelementidega

Olemasolevate trassikoridoride

kasutamine

Kõrgepingeliini asukohavalik Saaremaal

Trassikoridoride visandamise ja võrdlemise aruanne

71 / 71

4. Soovitused edasise protsessi ülesehitamiseks

Käesolevas töös on avalikest andmebaasidest kättesaadavate andmeallikate põhjal analüüsitud

võimalikke õhuliini koridoride asukohti Saaremaal. Töö tulemused on kasutatavad edasise õhuliini

rajamise protsessi kavandamiseks, mille käigus tuleb arvestada:

• Aruandes tuvastatud konfliktid Natura 2000 alade, I-III kaitsekategooria liikide ning teiste

looduskaitseliste objektide ja aladega lähtuvad ruumiandmetest. Õhuliini kavandamisega

kaasnevaid keskkonnamõjusid tuleb hinnata edasise planeerimise ja projekteerimise käigus.

• Töö koostamise ajal (september – detsember 2021) on koostamisel kogu Saaremaa valda

hõlmava üldplaneeringu koostamine. Käesolevas töös kasutatud andmed näiteks

tiheasustusalade või miljööväärtuslike hoonestusalade kohta lähtuvad Saaremaa valla

territooriumil kehtivatest üldplaneeringutest. Uue üldplaneeringu koostamise käigus võivad

viidatud alad muutuda või täpsustuda nende kasutustingimused.

• Saare maakonnaplaneeringuga kavandatud rohevõrgustik, mis on käesoleva töö aluseks,

täpsustatakse ja täiendatakse uue Saaremaa valla üldplaneeringu koostamisel. Juhul kui

õhuliini koridori valik viiakse läbi üldplaneeringu koostamise käigus, tuleb kavandada

rohevõrgustik tulenevalt õhuliini paiknemisest või näha ette leevendavad meetmed

rohevõrgustiku konfliktaladel.

• Õhuliini rajamiseks sobivaid menetlusi on planeerimisseaduses mitu – detailplaneeringu

koostamine, üldplaneeringu koostamine ning riigi eriplaneeringu koostamine. Tervikliku ning

läbimõeldud ruumilahenduse leidmiseks on mõistlik õhuliini koridor kavandada

üldplaneeringuga või riigi eriplaneeringuga.

• Üldplaneeringu kui sobiva menetlusliigi valikul tuleb silmas pidada, et õhuliini koridori valik

on vaid üks paljudest üldplaneeringus käsitletavatest teemadest. Seetõttu võib realiseerida

risk, et õhuliini kavandamiseks sobivaima koridori kehtestamine jääb teiste üldplaneeringu

teemade lahendamise või vaidluste tõttu viibima. Samuti oleneb õhuliini koridori

lahendamine üldplaneeringu koostamise käigus omavalitsuse tahtest uusi teemasid protsessi

käigus lahendada.

• Riigi eriplaneeringu kui sobiva menetlusliigi valikul tuleb silmas pidada, et asukoha eelvaliku

teostamise käigus kaasataks põhjalikult valiku teostamisse ka kohalik omavalitsus ning

kohalikud elanikud kui asjast enim puudutatud osapooled.

Tallinna 10, Kuressaare 93819 / registrikood 77000306 / 452 5000 / [email protected] / www.saaremaavald.ee

Kuressaares 18.06.2021 Lugupeetud Kaia Sarnet, Triin Lepland, Eleri Kautlenbach ja teised Eesti mereala planeeringu koostajad Edastame Saaremaa valla, Muhu valla, Ruhnu valla, Saare Arenduskeskus SA, Saaremaa Ettevõtjate Liit MTÜ, Meretööstuse Liit MTÜ ja Energiaühistu TÜ poolt ühispöördumise täiendusteks/parandusteks kõnealuses Eesti mereala teemaplaneeringus. Valitsus on seadnud ambitsioonikad eesmärgid tuuleenergia mahu järsuks kasvuks. Üldise praktika kohaselt saavutatakse planeerimis- ja keskkonnamõju hindamise lahendused kompromissina kogukondadega. Hetkel on arendajad jäetud tuuleparkide vastastega üksi vaidlema. Valitsus võiks anda sõnumi: nõustudes tuugenitega meres, saate põhivõrgu rajamise kaudu korraliku varustuskindluse ja liitumisvõimalused. See on saarte majandusarengu eelduseks. Olemas on Ida-Viru ja Kagu-Eesti ettevõtlusprogrammid, ent saartel puudub isegi liitumisvõimalustega riigi 330 kV põhielektrivõrk, olles strateegilisele tuule- ja päikeseressursile kõige lähemal. Meretuuleparkide arendamine Eestis on rohepöörde kontekstis sisuliselt vältimatult vajalik. Ilma meretuuleparke rajamata ei ole Eestis elektritootmine kasvõi omatarbe rahuldamiseks järgmistel aastakümnetel realistlik ning Eesti muutuks elektrit importivaks riigiks (nagu viimastel aastatel on juhtunud) koos sellega kaasnevate negatiivsete mõjudega majanduses, elu-olus ja julgeolekus. Meretuuleparkide arendamine toob kaasa Eesti põhivõrgu põhimõttelise ümberkujundamise – ajalooline elektritootmise raskuspunkt nihkub Kirde-Eestist Lääne-Eestisse ning selle toimimiseks peab muutuma ka ülekandesüsteem. Eesti vetes peaks EL Läänemere kavade kohaselt loodama 7GW tuuleenergia võimsust (Eesti riiklik energia ja kliimakava aastani 2030). Vajadus suurendada taastuvenergia tootmist meretuuleparkide abil annab võimaluse, et võrguühendus rahvusvahelise merevõrguni tehakse avamere tuuleenergiaks planeeritud sihtpiirkonnale üle Hiiu- ja Saaremaa. Eesti valmiva merealade planeeringu ja investorite huvi kohaselt on suurim tuuleenergia potentsiaal ümber saarte, ent Elering tutvustab mereparkide liitumispunktidena Harku, Lihula ja Kilingi-Nõmme alajaamu. Oleksime tuuleenergia investorite suhtes paremas konkurentsipositsioonis, kui annaksime liitumisvõimalused Saare- ja Hiiumaa 330 kV rannikualajaamadesse. Need järgiksid geograafiliselt Klaipeda – Ventspilsi telge ja annaksid võimalusi investeeringute kaasamiseks muuhulgas päikeseelektrijaamade, vesinikrakenduste, serverparkide, vesiviljeluskomplekside, biotehnoloogia rakenduste, energiamahukate tööstuste jms. rajamisel. Vastasel juhul pole investoritel kallimate liitumistingimuste tõttu põhjust valida miljardite investeerimiseks Eestit. Taanis ja Saksamaal ei jäeta liitumiskulusid vaid arendaja kanda. Lisaks peaks merealade planeering hõlmama ka maismaa-rannikul soovitavaid arenguid. Merealade tuleviku planeerimisel tuleb ette näha kõiki võimalusi Eesti meremajanduse pikaajalise rahvusvahelise konkurentsivõime tagamiseks. Mereriigi tõrgeteta toimimiseks peaks olema läbi mõeldud merealadel asuvate arenduste teenindamiseks vajalikud taristulahendused – sadamad, veeteed, maismaaligipääsud, samuti tuuleparkide, vesiviljelusrajatiste ja teiste valdkondlike arenduste teenindus- ja logistiline võrk, mis pakuks merealale asjakohast ja kvaliteetset kaldateenust.

Tallinna 10, Kuressaare 93819 / registrikood 77000306 / 452 5000 / [email protected] / www.saaremaavald.ee

PÖÖRDUMISE ALLKIRJASTANUD ORGANISATSIOONIDE ETTEPANEKUTE KOOND:

1. Meretuuleparkide loomisega liigub elektritootmine Kirde-Eestist Lääne-Eestisse, kuid selle toimimiseks puudub saartel ülekandesüsteem. Selmet kanda üksnes „talumiskohustust“, tuleb saartel välja arendada planeeritavate meretuuleparkide/taastuvenergiaüksuste liitumispunktide ja 330kv võrguühendused, et tagada saarte energiavarustuskindlus ning majanduse ja elu-olu arenguvõimalusi avardavad tingimused.

Meie hinnangul on üheks väga atraktiivseks meretuulepargi Eesti põhivõrguga ühendamise variandiks uue võimsa (330 kV) ülekandesüsteemi rajamine maismaal läbi Saaremaa. Atraktiivsus ei seisneks ainuüksi mõistlikkuses meretuuleparkide jaoks, vaid see avaks mitmeid uusi võimalusi ka paljudele teistele ettevõtetele Saaremaal – nii olemasolevatele tegutsejatele kui ka täiesti uutele valdkondadele ja tegevustele. Sisuliselt tekiks Saaremaale väga suure võimsusega elektri ülekandesüsteem, mis avab võimalused ka väga suure tarbimismahuga liitujatele ja avaks võimalused täiendavateks investeeringuteks. Meretuuleparkide elektriühendused rajatakse väga töökindlatena, mistõttu oleks ka tarbimissuunal tagatud väga hea varustuskindlus. Üldkontseptsioonina pakume ühe võimaliku lahendusena välja alljärgneva ülekandesüsteemi võimaluse:

 Olemasoleva Lihula – Virtsu õhuliini ja alajaamade rekonstrueerimine/arendamine.

 Uus merekaabel trassil Virtsu – Kagu-Saaremaa. Kagu-Saaremaa all peame silmas Laimjala piirkonna rannikut, kus merekaabel suunduks Saaremaa maismaale.

 330 kV õhuliin Laimjala piirkond – Lääne-Saaremaa (Karala-Üüdibe rannikulõik). 330 kV õhuliin võiks võimalikult palju kulgeda samas trassis ja olla maksimaalselt integreeritud olemasoleva 110 kV õhuliiniga.

 330 kV alajaam Lääne-Saaremaal, kust lähtuvad merekaablid meretuuleparki.

Eelnev kontseptsioon on väga esialgne ja üks võimalikest lahendustest ning arvukad detailid vajavad täpsustamist. Konkreetsed liinide asukohad, alajaamade asukohad, integreerimine olemasoleva Saaremaal asuva elektrisüsteemiga (sh. seotus alajaamades) jms. on veel detailselt lahendamata.

2. Nõustume ja toetame, et tuuleenergeetika peab merel olema prioriteet, kuid sama

olulisena ja samas ajaraamis tuleks seal ette näha, et seda võivad merel arendada ka kogukonnad ise.

Palume täiendada planeeringu punkti 5.6.1 selliselt, et kogukondlik energiatootmine oleks samuti lähiaja prioriteetseks suunaks ja võimaluseks. Tunnustame, et planeering kajastab põgusalt ka hajaenergeetikat ning märgib, et pikemas perspektiivis võib hajaenergeetika olla oluliseks arengusuunaks, mis võimaldab näiteks rannikukogukondadel arendada oma vajadusi katvaid energialahendusi. Ka Euroopa Liidu direktiividega nähakse ette kodanike energiaühenduste (uuenenud elektrituru direktiivis) ja taastuvenergiakogukondade (uuenenud taastuvenergia direktiivis) soodustamist. Kogukondlik energiatootmine on oluline viis suurendada taastuvenergia tootmist, aga veelgi olulisemaks võib pidada asjaolu, et see aitab suurendada ühiskonna aktsepteeritust taastuvenergiale ja seega ka rohepöördele. Kogukonnaenergeetika mudel on rakendatav juba täna, mistõttu peame oluliseks, et planeering kajastaks hajaenergeetikat aktuaalsemana kui kaugemas tulevikus

Tallinna 10, Kuressaare 93819 / registrikood 77000306 / 452 5000 / [email protected] / www.saaremaavald.ee

potentsiaali omava suunana. Hetkel on punktis 5.6.1 toodud taastuvenergia tootmise suunistes lähiaja prioriteediks eelkõige tuuleenergeetika, pikemas perspektiivis laiemad taastuvenergia tootmisvõimalused (näiteks päikese- ja laineenergia) ning alles seejärel nimetatud kaugema tulevikuvisioonina hajaenergeetika arendamist merealal, mis võimaldab näiteks rannikukogukondadel arendada oma vajadusi katvaid energialahendusi.

3. Soovime, et merealade planeering oleks terviklik, sisaldades kõiki vajalikke mõjuanalüüse ja hinnanguid, langetamaks põhjendatud otsus energeetikavõrgustiku rajamiseks. Kaasnevaid mõjuanalüüse/hinnanguid ei saa edasi lükata hoonestusloa protsessi, ega seada kohustuseks kohalikele omavalitsustele, vaid need tuleb ära teha merealade planeeringu käigus, kuivõrd muidu ei täida planeering oma peamist ülesannet, milleks on energeetikavõrgustiku rajamiseks sobivate alade määratlemine.

Mereplaneeringu algatanud Vabariigi Valitsuse korralduses on kirjas, et planeeringuga määratakse kindlaks, kus ja mis tingimustel mingeid tegevusi ellu viiakse. Mereala planeeringu lähteseisukohtade ja mõjude hindamise välja töötamise kavatsuses (KSH VTK) on kirjas, et mereala ruumilisel planeerimisel tuleb arvestada rannikukogukondade pikaajaliste ruumiliste vajaduste ja väärtustega, mis mõjutavad rannikuala kasutust ja elukeskkonna atraktiivsust ning erinevate tegevuste elluviimist merealal. Täna pole selgelt välja toodud olulisemad kavandatavad muudatused võrreldes olemasoleva olukorraga. Näiteks nähakse küll ette meretuuleparkide tulekut, millele on seatud niiöelda sotsiaalne puhver (11,1 km rannajoonest), kuid selle puhvri mõju ja visualiseeringuid pole hinnatud.

Viidates planeeringule, selgub vaba vaatevälja jätmise võimalikkus ja asukoht visuaalsete mõjude hindamisel hoonestusloa menetluse käigus, millele eelnevalt tuleb teha maastike inventuur. Viidates planeeringu KSH-le aga ei tohiks hoonestusloa etapis arendaja maastikke inventeerida, vaid seda tuleks teha mingil üldisemal tasandil, näiteks valla üldplaneeringu raames. Et kohalikud omavalitsused ei saa oma planeeringutes merd planeerida, nende üldplaneeringute lähteülesanded on juba ammu lukus või suisa planeeringud valmis ning tuulepargi arendajad ei saa ilma maastiku hindamiseta edasi liikuda, siis on tegemist absurde konstruktsiooniga, mille tulemusel pole võimalik planeeringut rakendada. Ometigi peaks planeeringu ülesandeks olema konkreetse suunise andmine, kuhu saab meretuulikuid püstitada.

4. Soovime, et merealade planeering ei seaks ohtu laeva- ja lennuühendust mandri ja saarte vahel.

Transport saartele sõltub paljuski ilmastikust. Vähendamaks transporti veelgi keerulisemaks tegevaid faktoreid, tuleb arvestada lennu-ja laevakoridoridega ning võimalusel neid mitte muuta, vaid valida arendamisel prioriteetseks alad, mis ei jää saarte põhiliste transpordikoridoride ette.

Tallinna 10, Kuressaare 93819 / registrikood 77000306 / 452 5000 / [email protected] / www.saaremaavald.ee

5. Merealade ekspluateerimisega tekkiva täiendava potentsiaali parimaks rakendamiseks tuleb planeerida ja kavandada ka merealadel asuvate arenduste teenindamiseks vajalikud taristulahendused – sadamad, veeteed, maismaaligipääsud sadamatele jms. Merealade planeering peab hõlmama ka maismaa-rannikul soovitavaid arenguid. Merealade tuleviku planeerimisel tuleb ette näha kõiki meretööstuses tekkivaid võimalusi Eesti meremajanduse pikaajalise rahvusvahelise konkurentsivõime tagamiseks. Eelkõige on oluline, et Eestisse jääb ka merele ehitatavate tuuleparkide, vesiviljelusrajatiste ja teiste valdkondlike arenduste teenindus- ja logistiline võrk. See nõuab täiendavaid planeeringuid rannikualade, teede- ja elektrivõrkude ning tuleviku tööjõuvajadusi arvestavate õppekavade arendamiseks, millele seni on vähe tähelepanu pööratud. Mereriigi tõrgeteta toimimise tagatiseks on läbi mõeldud, kaasaegne ja aastaringselt kasutatav sadamate ja veeteede võrk, mis pakub lisaks meresõiduohutuse tagamisele ka asjakohast ja kvaliteetset kaldateenust. Täna on Eesti sadamate potentsiaal rakendamata, muuhulgas ka meri-meri tegevusvaldkondades, kus kogu logistikaahel on seotud meritsi toodud ja meritsi viidavatele materjalidele/toormele/toodetele lisandväärtuse andmisega piirkonnas asuvate ettevõtete poolt.

6. Meretuulepargi olemasolu võib põhjustada kitsendusi muule majandustegevusele konkreetses piirkonnas ja see tuleb kompenseerida, saavutamaks laiem kogukondlik kokkulepe soovitud arengute käivitumiseks. Palume planeering siduda Majandus- ja Kommunikatsiooniministeeriumi poolt ette valmistatava seaduseelnõuga seoses meretuuleparkide talumistasuga kohalikele elanikele ja omavalitsustele.

On mõistetav, et meretuulepargi olemasolu võib põhjustada kitsendusi muule majandustegevusele konkreetses piirkonnas, näiteks traalpüügile. Sellisel juhul tuleks mõjutatud ettevõtjatele ette näha põhjendatud määral kompensatsioon, mille jaoks on võimalik kasutada osa tuuleparkide hoonestustasust. Seejuures on oluline arvesse võtta, et tuulepargi olemasolu võib sadama operaatori, aluste omanike jt. jaoks majandustegevuse mitmekesistumise tõttu tõenäoliselt kujuneda märkimisväärseks täiendavaks tuluallikaks.

7. Palume planeeringusse jätta sisse võimalus arvestada ka uute perspektiivikate tehnoloogiate rakendamisega taastuvenergia ja kliimaeesmärkide täitmisel.

Planeering ei tohiks olla seotud ainult ühte liiki tehnoloogiatega ja täna üldtuntud võimalustega, mistõttu palume planeeringu konteksti käsitleda laiemalt taastuvenergeetika vaatest ja mitte eelistada üht lahendust teisele. Palume meretuuleparkideks sobivaks markeeritud alade juures käsitleda võimalusi ka teistsugusteks energiatootmisviisideks ja muuhulgas käsitleda neid alasid ka kui erinevateks vesiviljeluslahendusteks sobivaid.

Muu maailma eeskujul saaks näiteks vesiviljelusüksusi/kalakasvatusi meretuuleparkides otse varustada energiaga, kalakasvatussumpasid kinnitada tuugenite jalamitele ja ühendada tuuleparkide kui ka vesiviljelusüksuste hooldus/teenindus. Selliselt saaks energia tootmiseks planeeritud alasid topelt kasutada ja on võimalik mujal merel koormust vähendada.

Tallinna 10, Kuressaare 93819 / registrikood 77000306 / 452 5000 / [email protected] / www.saaremaavald.ee

8. Soovime, et meretuuleparkide kontekstis määratletaks ära ka tuulepargi amortisatsioonijärgsed tegevused ja muu hoolduse ning käitlusega seonduv.

Leiame, et planeering peaks käsitlema ka tuuleparkide tulevase võimaliku sulgemise ehk töö lõpetamise teemat. Erinevate mõjuuuringute kontekstis tuleks arvesse võtta ka tuuleparkide nn. sulgemise mõjud ja kaasnevad tegevused, muuhulgas lammutamise/demonteerimise/teisaldamise kohustus. Lugupidamisega

Mikk Tuisk Saaremaa vallavanem Jaanus Tamkivi Saaremaa vallavolikogu esimees Raido Liitmäe Muhu vallavanem Ain Saaremäel Muhu vallavolikogu esimees Andre Nõu Ruhnu vallavanem Heiki Kukk Ruhnu vallavolikogu esimees Rainer Paenurk Saare Arenduskeskus SA juhatuse liige Robert Pajussaar Saaremaa Ettevõtjate Liit MTÜ juhatuse liige Peeter Sääsk Eesti Meretööstuse Liit MTÜ juhatuse liige Märt Helmja Energiaühistu TÜ juhatuse liige /allkirjastatud digitaalselt/

Elering AS | Registrikood/Reg. code 11022625 | Kadaka tee 42, 12915 Tallinn, Estonia + 372 715 1222 | + 372 715 1200 | www.elering.ee | Ametlik e-post/Official e-mail: [email protected]

Sulev Vikat Teie: 09.08.2026

[email protected] Meie: 08.09.2026 nr 11-4/2026/768-4

Vastus teabenõudele

Lugupeetud härra Vikat

Esitasite Majandus- ja Kommunikatsiooniministeeriumile ning Elering AS-le (edaspidi Elering) teabenõude seoses Eesti–Läti neljanda elektriühenduse riigi eriplaneeringu ning Saaremaa– Kuramaa lahenduse valiku aluseks olnud analüüside ja arvutuste väljastamisega. Elering pikendas 14.08.2026 kirjaga nr 11-4/2026/768-2 teabenõudele vastamise tähtaega AvTS (avaliku teabe seaduse) § 19 alusel kuni 15 tööpäeva võrra. Selgitasime, et avaliku teabe seaduse (AvTS) § 3 lg 1 järgi on avalik teave mis tahes viisil ja mis tahes teabekandjale jäädvustatud ja dokumenteeritud teave, mis on saadud või loodud seaduses või selle alusel antud õigusaktides sätestatud avalikke ülesandeid täites. AvTS § 5 lg 1 p 3 kohaselt on eraõiguslik juriidiline isik teabevaldajaks üksnes AvTS § 5 lg-s 2 sätestatud tingimustel. AvTS § 5 lg 2 kohaselt laienevad eraõiguslikule juriidilisele isikule teabevaldaja kohustused, kui isik täidab seaduse, haldusakti või lepingu alusel avalikke ülesandeid, sh osutab haridus-, tervishoiu-, sotsiaal- või muid avalikke teenuseid, – teabe osas, mis puudutab nende ülesannete täitmist. Avalikke ülesandeid on kohtupraktikas sisustatud kui ülesandeid, mis on ette nähtud vahetult seadusega või seaduse alusel või õigusnormist tõlgendamise teel tuletatud (Riigikohtu 20.11.2019 otsus nr 3-17-2718, p-d 13 ja 14). Seega ei ole Elering AS kohustatud avaldama igasugust teavet oma majandustegevuse kohta, vaid üksnes seda teavet, mis on seotud avaliku ülesande täitmisega ning teabenõudes taotletud teave peab puudutama selle avaliku ülesande täitmist.

Elering on eraõiguslik juriidiline isik, kellele laienevad AvTS § 5 lg 2 kohaselt teabevaldaja kohustused teabe osas, mis puudutab talle seaduse või selle alusel antud õigusaktiga pandud avalike ülesannete täitmist. Tallinna halduskohus on haldusasjas nr 3-24-3120/41 selgitanud, et elektrivarustuse puhul saab avalikuks ülesandeks lugeda elektriga varustamist kui elutähtsa teenuse osutamist, mis on Kliimaministeeriumi ja seega riigi otsene ülesanne. Ettevõtjate määratlus, kes nimetatud elutähtsat teenust peavad aitama tagada, on toodud ELTS §-s 21¹, kuhu alla kuulub Elektrilevi OÜ. Elering põhivõrguettevõtjana on ELTS § 16 lg 3 p 1 ja 21¹ alusel elutähtsa teenuse osutaja (elektri varustuskindluse tagaja), põhivõrgu arendaja, süsteemihaldur. AvTS § 3 lg 1 kohaselt on avalikuks teabeks teave, mis on saadud või loodud seaduses või selle alusel antud õigusaktides sätestatud avalikke ülesandeid täites.

Oleme Eleringi valduses olevad teabenõude esemega seotud dokumendid üle vaadanud. Väljastame teabe ulatuses, milles sellele ei kehti seadusest tulenevat juurdepääsupiirangut.

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Juurdepääsupiiranguga teabe väljastamisest keeldume AvTS § 23 lg 1 p 1 alusel koostoimes AvTS § 35 lg 1 p-dega 10 ja 17.

Olete palunud väljastada elektrooniliselt järgmised dokumendid ja andmed:

1) Kõik Elering AS 12.10.2023 taotluses viidatud „senised analüüsid“, mille alusel jõuti järeldusele, et Saaremaalt Kuramaa piirkonda kulgev ühendus on kõige otstarbekam lahendus ja võimaldab vajaliku ülekandevõimsuse rajada kõige väiksema rahalise kuluga.

Elering on viinud läbi mitmeid analüüse, mis on olnud aluseks järeldama, et üle Saaremaa rajatav Eesti-Läti neljanda ühenduse rajamine on otstarbekaim viis täiendava ühenduse rajamiseks Lätiga. Otstarbekaima lahenduse valiku aluseks on muuhulgas olnud järgmised dokumendid, mis on lisatud käesolevale vastusele:

 Meres rajatava taristu maksumuse analüüs (kaablid) - 20211119_BLIX_Offshore Wind Technology Catalogue_F (lisa 1)

 Uuring kuidas jõuda rannikult olemasoleva võrguni eri asukohtadest - 2021_0067_ASTER_report_final_dets2021 (lisa 2)

 Saaremaad ületava trassi asukohavaliku analüüs - 2021_0069_Elering_aruanne_ver3 (lisa 3)

 Saaremaa vallavalitsuse edastatud ühispöördumine - 2021-06-17_MSP_arvamus_Saarte energiapöördumine (lisa 4)

Ülejäänud Eleringi valduses olevad dokumendid sisaldavad detailseid tehnilisi võrgu parameetreid ning võrgu investeeringu- ja kuluprognoose. Nende andmete avalikuks tulek võimaldaks teha järeldusi võrgu tehniliste parameetrite kohta, mis võivad anda turueelise või ohustada võrgu julgeolekut ning kahjustada Eleringi majanduslikke huve ning ärisaladust. Seetõttu kehtib kirjeldatud teabele juurdepääsupiirang AvTS § 35 lg 1 p-de 10 ja 17 alusel.

2) Nimetatud analüüside juurde kuuluvad tehnilised ja majanduslikud arvutused, tabelid, mudelid, alternatiivide võrdlused, maksumushinnangud, memod, aruanded, esitlused ja muud olemasolevad dokumendid, millele nimetatud järeldus tugines.

Võrgu tehnilised ja majanduslikud arvutused ei kuulu avalikustamisele, sest võrgu detailsetes arvutustes on võimalik teha kindlaks ülekandevõrgu tehnilised parameetrid, mis võivad anda turueelise või ohustada võrgu julgeolekut või sisaldavad äriliselt tundlikke kulueelduseid. Selles osas keeldub Elering teabe väljastamisest AvTS § 23 lg 1 p 1 alusel koostoimes AvTS § 35 lg 1 p- dega 10 ja 17.

Täiendavalt märgime, et praegune parim avalik info seoses taristu hindadega on kättesaadav Euroopa Liidu energeetikaregulaatorite koostööameti ACER ühikhindade statistikast1, kuhu on koondatud kõigi põhivõrguoperaatorite taristu ehitusmaksumused.

3) Dokumendid, milles võrreldi Saaremaa–Kuramaa lahendust teiste võimalike Eesti–Läti neljanda elektriühenduse trassi- või tehnoloogiliste alternatiividega.

Tehnoloogiliste alternatiivide täpsustamiseks viis Elering koos Läti põhivõrguoperaatoriga AS Augstsprieguma tikls läbi hanke “Offshore grid technology catalogue” (RHR viitenumber 236573), mille alusel hangiti tehnoloogiakataloog meres paiknevate ülekandevõrgu seadmete

1 https://www.acer.europa.eu/sites/default/files/documents/Publications/ACER-2026-Unit-Investment-Cost- Indicators.pdf

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kohta. Hanke tulemusel valmis tehnoloogiakataloog koos teoreetiliste trassianalüüside, eskiisprojekti mahu kirjelduse ning teoreetilise ajakavaga. Dokument edastatakse lisana 1.

Uuringu eesmärk oli anda põhivõrguettevõtjatele ülevaade tehnoloogilistest piirangutest ja võimekustest ning seadmete võimalikest maksumustest, kuid mitte teostada kindlaid trassianalüüse. Uuringu tulemustele põhinedes on Elering näidanud Eesti elektrivarustuskindluse aruande 2022 versioonis2 trasse kulgemas teabepäringus viidatud alternatiividel. Trassialternatiivide võrdlus edastatakse lisana 2.

4) Kui analüüsides käsitleti Eesti mandrilt otse Läti suunas kulgevat merekaabelühendust, palun väljastada selle alternatiivi kohta koostatud tehnilised ja majanduslikud arvutused ning dokumendid, millest nähtub selle võrdlus Saaremaa kaudu kulgeva lahendusega.

Nagu juba ülal mainitud, ei kuulu tehnilised ja majanduslikud arvutused avalikustamisele (AvTS § 35 lg 1 p 10 ja p 17).

5) Kui võrreldi vahelduvvoolu (HVAC) ja kõrgepinge alalisvoolu (HVDC) tehnoloogiaid, palun väljastada vastavad olemasolevad analüüsid ja arvutused, sealhulgas kasutatud eeldused ühenduse pikkuse, võimsuse, kaablite, konverter- või kompensatsiooniseadmete, elektriliste kadude ning investeerimis- ja käidukulude kohta.

Tehnoloogiliste lahenduste võrdlusi ei väljastata osas, milles need sisaldavad AvTS § 35 lg 1 p- de 10 ja 17 alusel piiratud juurdepääsuga teavet.

6) Palun väljastada olemasolevad dokumendid ja arvutused, mille põhjal otsustati enne riigi eriplaneeringu algatamist, et Eesti–Läti neljanda elektriühenduse Eestis paiknev osa tuleb kavandada suunal Paide–Lihula–Saaremaa ning et ühenduse jätkumine Läti suunas toimub Saaremaa läänerannikult.

Selle otsustuse aluseks olnud Eleringi valduses olevad avalikud dokumendid ja analüüsid on käsitletud vastuse punktides 1–5 ning edastatakse lisadena 1-4. Täiendavad detailseid võrguarendusvariante, tehnilisi parameetreid ja kuluprognoose sisaldavad materjalid on piiratud juurdepääsuga vastuse punktides 1 ja 2 kirjeldatud ulatuses ning alustel.

7) Palun väljastada olemasolevad analüüsid, milles on hinnatud, milline osa Saaremaale kavandatavast 330 kV elektrivõrgust ja sellega seotud alajaamadest on vajalik Eesti–Läti neljanda elektriühenduse jaoks ning milline osa oleks vajalik Saaremaa elektrivarustuse, taastuvenergia tootmise või meretuuleparkide võrku ühendamise eesmärgil sõltumata Eesti–Läti neljanda ühenduse trassist.

Selgitame, et sellist analüüsi ei eksisteeri, kuna elektrisüsteemi olemus on, et kõik ühendatud tootjate ja tarbijate elekter saab liikuda vabalt kõigis elektrisüsteemi punktides. Eristatakse ülekandevõrgu osasid liitumislahtrite näol, mis on loodud konkreetsete liitujate tarbimis- või tootmissuunaliseks liitumiseks.

Kavandatav Eesti-Läti neljas elektriühendus tugevdab tervikuna Lääne-Eesti ja saarte elektrivarustust, kuna sellega nähakse ette olemasoleva 110 kV võrgu ühendamine uue Lääne- Saaremaale kavandatud alajaamaga. Kui arvestada, et uus elektriühendus loob Saaremaal olemasoleva elektrivõrguga kaks eri asukohast alguse saavat täiendavat ühendust, suurendatakse saarte võrgu vastupanuvõimet riketele oluliselt. Samal ajal kõnealust elektrivõrgu tugevnemist ei

2https://elering.ee/sites/default/files/public/Elektriturg/Energiasüsteem/Varustuskindluse%20analüüsid/ elering_vka_2022.pdf

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toimu, kui ei rajata Eesti-Läti neljandat elektriühendust tervikuna. Seega ei saa eristada, missugune osa loodavast võrgust on mingiks konkreetseks otstarbeks kavandatud.

Lugupidamisega

(allkirjastatud digitaalselt)

Reigo Kebja Juhatuse liige

Lisad:  Lisa 1: 20211119_BLIX_Offshore Wind Technology Catalogue_F  Lisa 2: 2021_0067_ASTER_report_final_dets2021  Lisa 3: 2021_0069_Elering_aruanne_ver3  Lisa 4: 2021-06-17_MSP_arvamus_Saarte energiapöördumine

Teadmiseks: Majandus- ja Kommunikatsiooniministeerium

Priit Heinla 53 428 273, [email protected]

Kerti Kokk 508 4143, [email protected]

Offshore Wind Technology Catalogue

OFFSHORE WIND TECHNOLOGY CATALOGUE

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From: BLIX Consultancy BV

Reference: Offshore wind technology catalogue

To: Elering AS and AS "Augstsprieguma Tīkls"

Authors: BLIX Consultancy: A. Alves da Silva , J. Godtschalk , T. Drummen

Enersynt: P. van Leest

Checked: I. Maassen van den Brink

Version: Final

Date: December 15th, 2021

OFFSHORE WIND TECHNOLOGY CATALOGUE

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Contents EXECUTIVE SUMMARY 6

ACRONYM LIST 7

1 INTRODUCTION 9

2 ASSUMPTIONS 10

3 OFFSHORE SUBSTRUCTURES 11

3.1 WTG Foundations 11

3.1.1 Description 11

3.1.2 Technical Information 12

3.1.2.1 Monopile Substructures 13

3.1.2.2 Jacket Structures (3 or 4 Legged Substructures) 14

3.1.2.3 Gravity Base Structure 15

3.1.3 Costs 16

3.2 Offshore Substations Foundation 17

4 WIND TURBINES 18

4.1 Description 18

4.2 Technical Information 19

4.3 Wind Farm Power Density 21

4.4 Costs 22

4.5 Lifetime 22

4.6 Availability 23

4.7 WTG Catalogue 24

5 OFFSHORE GRID CONNECTION SYSTEMS 25

6 AC TECHNOLOGY 26

6.1 HVAC Offshore Substation 26

6.1.1 Description 26

6.1.2 Technical information 26

6.1.3 SLD 28

6.1.4 Costs 28

6.1.5 Lifetime 29

6.1.6 Availability 30

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6.1.7 Losses 30

6.2 AC cables 31

6.2.1 Description 31

6.2.2 Export cables 31

6.2.2.1 Technical information 31

6.2.2.2 Installation 34

6.2.2.3 Costs 34

6.2.2.4 Lifetime 36

6.2.2.5 Availability 36

6.2.2.6 Losses 36

6.2.3 Inter array cables 37

6.2.3.1 Technical information 37

6.2.3.2 Installation 38

6.2.3.3 Costs 38

6.2.3.4 Lifetime 39

6.2.3.5 Availability 39

6.2.3.6 Losses 40

6.3 Reactive Compensation 41

6.3.1 Technical information 41

6.3.2 Costs 42

6.3.3 Losses AC versus DC 42

6.4 Onshore HVAC Land Stations 43

7 DC TECHNOLOGY 44

7.1 Basic Components of DC Connections 44

7.1.1 SLD 46

7.2 HVDC Offshore Substation 47

7.2.1 Description 47

7.2.2 Technical information 47

7.2.3 SLD 49

7.2.4 Costs 50

7.2.5 Lifetime 51

7.2.6 Availability 51

7.2.7 Losses 52

7.2.8 DC Offshore Substation in Meshed Grids 52

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7.3 HVDC Land Station 54

7.3.1 Description 54

7.3.2 Costs 54

7.3.3 Lifetime 55

7.3.4 Availability 55

7.4 HVDC Cables 55

7.4.1 Description 55

7.4.2 Technical Information 57

7.4.3 Installation 58

7.4.4 Costs 58

7.4.6 Lifetime 59

7.4.7 Availability 59

7.4.8 Losses 59

8 DECOMMISSIONING 60

9 EXAMPLE GRID CONNECTION 61

10 ANNEXES 63

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EXECUTIVE SUMMARY BLIX Consultancy has the pleasure of presenting the Offshore Technology Catalogue. This catalogue will provide Elering/AST with the necessary information to get an insight in the current technologies that are on the market for offshore wind developments.

Overall, the outcome of compiling this catalogue is, that the nature of offshore wind technologies has evolved – and continues to evolve - at a rapid pace and that the offshore wind business has matured over the recent years. The catalogue goes into detail about the different types of foundations, wind turbine generators, substations and transmission cables. The grid connection system is the main focus of the catalogue and comparisons are made between AC and DC systems. BLIX has provided up-to-date market information on availability, reliability and – where possible - prices.

At the end a top level assessment is made of a specific connection for both technologies. In general it is stated that above 1GW and more than 100km the DC option would be preferred, as this should also consider the difference in losses during lifetime when corrected for the different power bins (wind profile) of the offshore wind farm.

Important to note in this document, is that assumptions had to be made on which the data had to be based. The assumptions are very general in nature and therefore should be considered as such. When using the catalogue, it is important that the user should always be aware of these restrictions and how they apply to the catalogue item.

Another important note to the use of this catalogue is, that during the compilation of the data, it became very clear during our research, that a lot of items and more specifically prices are site specific. This means that there are so many variables in designing, delivering or installing certain items that, without site specific detailed data, it is very difficult to obtain 100% accuracy. When compiling this catalogue, we used a lot of general available data which may lack detailed information.

Overall, we are confident that the quality of this catalogue will provide a very good, detailed, assessment of the main components for the development of an offshore wind farm in the Baltic Sea.

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ACRONYM LIST AC – Alternating current

ALU – Aluminium

BE - Belgium

BOP – balance of plant

CAPEX – Capital Expenditure

CTV – crew transfer vessel

DAS – Distributed Acoustic Sensing

DC – Direct current

DE - Germany

DK - Denmark

DOL – Depth of Burial

DTS – Distributed Temperature System

EMTP – Electro Magnetic Transient Program

EU – European union

EXC – Export cable

FAT – Factory Acceptance Test

FO - fibre optic

GB – Gravity base

GBS – Gravity base structure

HVAC – High voltage alternating current

HVDC - High Voltage Direct Current

IAC – inter array cable

IEC – International Electrotechnical Commission

LCoE – Levelised cost of energy

LFAC – Low Frequency Alternating Current

m – meter

MV - Mega Volt

MW – Megawatts

MVA – Mega Volt Ampere

NL - Netherlands

O&M – operations & maintenance

OEM – original equipment manufacturer

ONAF – Oil Natural Air Forced

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ONAN – Oil Natural Air Natural

OPEX – Operational Expenditure

OSS – offshore substation

OWF – offshore wind farm

OWF – offshore windfarm

PSCAD – Type of SW package for EMTP simulations

PQ – Power Quality

RFQ – Request for Quotations

SAT – Site acceptance test

SCADA - Supervisory Control and Data Acquisition

SE - Sweden

SOV – service operation vessel

TIV – Transport installation vessel

TP – Transition piece

TRL – Technology readiness level

TSO – Transmission system operator

UK – United Kingdom

WTG – wind turbine generator

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1 INTRODUCTION

BLIX Consultancy & partners were contracted by the Estonian and Latvian TSO’s, Elering and AST, to create an offshore wind technology catalogue. This catalogue details all the technologies used in an offshore wind farm and grid connection system. General and technical details for each technology are explained, highlighting the various factors that dictate the design, cost and lifetime of a wind farm. Important factors include but are not limited to; wind farm capacity, distance to shore, water depth, seabed conditions and onshore grid connection.

Only technologies with a TRL greater than 5 have been considered. BLIX has provided costs for all the technologies however it should be noted that these costs are best estimates of the current market based on our experience and public literature. Prices will vary depending on site and project specifics.

The report is split into individual sections for each technology. Chapter 3 covers offshore substructures for both WTG’s and platforms. It describes the various fixed bottom foundations used in water depths of up to 50m focussing on monopiles and jacket foundations.

Chapter 4 covers WTG’s, looking at; the basics design, current and future outlook for size and capacity, considerations for wind farm density and end of life. Chapters 5-7 cover the grid connection system. It splits the technologies into two categories, AC and DC. Within each category the offshore platform, onshore land station and transmission cables are discussed. These sections go into detail about the various configurations, topologies and redundancies that are used in the market and their associated losses. For AC, there is a section detailing reactive power compensation considerations that are required for longer cable distances. In the cable sections the voltage, cross section, and conductive materials used are compared.

Chapter 8 briefly describes decommissioning of an offshore wind farm and grid connection system. Discussing the cost and considerations required to ensure marine users and the environment are not severely impacted by these activities. Chapter 9 provides a qualitative comparison of both AC and DC technology. For comparison purposes an example for a specific 1GW connection, 50km from shore is assessed using both technologies.

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2 ASSUMPTIONS

Parameter Assumed for catalogue Comments

Water depth < 50 meter

Ice conditions Considered Ice conditions come in various forms. Per item it is explained what has been considered and what not.

Soil conditions Sandy soils A change in soil can have a major impact on the foundation design.

Seabed currents Very low currents Consequently, low seabed mobility (sand dunes) have been assumed.

Seabed currents is an important parameter for scour protection and/or subsea cable design.

Earthquakes Not assumed If these need to be considered, a Seismic Hazard Analysis (SHA) will need to be performed in order to

Waves Typical UK Sector North Sea conditions

Max wave heights (HMax) in the North Sea can go up to 10m (or more during a bad storm). Meaning a Significant wave height (Hs) of around 5- 6m.

Tides Small tides (<0.5m) have been assumed

Other assumptions for foundation section

1. Total windfarm size: 1000MW

2. Water depth: 30m 3. Turbine: 10MW 4. Location: North Sea –

UK Sector 5. Weight of foundation

assumed 800 ton

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3 OFFSHORE SUBSTRUCTURES

3.1 WTG Foundations

3.1.1 Description

The primary function of a foundation of any structure is to transfer applied loads to the sub- bottom. The main loads that act on an offshore structure are wind, waves, currents and the ‘self- weight’ of the structure. Examples of other loads and actions that can occur in different offshore environments around the world are ice loads, earthquakes, typhoons and ship impact.

Offshore foundation types are particularly driven by:

• Water depth; • Ground conditions; • Loads (magnitude).

In offshore wind, a discrepancy is made between floating and bottom-fixed foundations. Only bottom-fixed foundations will be discussed here, considering the shallow water depths (up to ~50 m) in the area of interest.

In the table below the word “rock” is sometimes used when discussing the foundations. It should be noted that “rock” is geological term that is used to describe a naturally occurring solid mass of minerals. Rock can occur in various degrees of hardness, from very hard (granite) to weaker types (certain types of limestone or sandstone). For foundation design, encountering rock is generally not a good thing. When being hammered, rock will either resist the piling (so that drilling is required) or will break up, making it useless for foundation design, since the soil is unable to deal with the forces on the foundation. The General soil strength can be described as follows:

Type of Soil Strength of Soil Elastic Modulus, E (Mpa) Fine sand Loose 5-10

Medium 10-25 Dense 25-50

Silt Soft <10 Stiff 10-20 Hard >20

Clay Very soft <3 Soft 2-7 Firm 5-12 Stiff 10-25 Very stiff 20-50 Hard 40-80

Table 1 - Typical elasticity modulus (ES) values for different soil types1

1 Handbook of Geotechnical Investigation and Design Tables - Burt G.Look (2007)

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The following section considers the most common bottom-fixed foundation structures in the offshore wind industry. Other foundation types such as mono buckets, tripods (currently 126 operational, but ran out of fashion for larger turbines), twisted jackets have not been applied in commercial offshore wind farms and are therefore considered to be of less importance for this exercise.

Below tables also show installation options. It is noted here however, that no limitations have been assumed. For piling operations, noise mitigation measures might be required, such as bubble screens (single of double).

3.1.2 Technical Information

Foundation size (diameters/lengths) depends mainly on ground and loading conditions on the substructure.

An important parameter to keep in mind is steel quality. Especially for icy conditions, high grade steel might be required to deal with the low temperatures. Should there be permanent ice during winter, then the foundations need to be designed as such to be able to withstand the ice loadings. According to DNV rules DNVGL-OS-C101, ice loadings are depending on multiple factors:

• geometry and nature of the ice • mechanical properties of the ice • velocity and direction of the ice • geometry and size of the ice and structure contact area • ice failure mode as a function of the structure geometry • environmental forces available to drive the ice

In order to make a proper assessment of the ice loadings, before the development stage of the project, as much as possible information should be collected on ice conditions. These conditions can be collected via a desktop study, via publicly available data bases or via meetings with knowledge institutes or other parties that have knowledge about ice and ice loadings.

Ultimately, the ice loadings can also be tested in a laboratory via simulations, for example in Hamburg (Germany)2

The ice loadings shall then be incorporated into the design of the foundation according to the applicable codes and standards.

So for the purpose of the catalogue, in these very early stages it’s very difficult to assess the exact impact of ice loadings on the substructure.

2 https://www.hsva.de/expertise/safety/safety-in-cold-regions.html

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3.1.2.1 Monopile Substructures

General The monopile foundation consists of one circular open-ended steel pile that, after installation will be partly in the ground, partly in the water column and partly above water level. A transition piece will be installed afterwards, on which the WTG tower will be mounted.

Dimensions - Diameter up to ~9 m - Length ~30 m to ~80 m - Wall thickness ~50 mm to ~120 mm - Diameter could go up to 12 m and more

Weight - ~800 t to ~1900 t (in air) - Will increase with increasing diameters - Note: the latest monopile for Arcadis Ost 1

OWF in the Baltic was 2000t at 40m water depth

Applicable water depth - < ~40 m - Could be stretched with increasing

diameters Applicable ground conditions - Soft ground conditions (clay, sand and silt

or alternations thereof) - Difficult to apply in rock

Fabrication methodology Steel plates, rolled to circular elements that are welded together

Transport and installation methodology - (Generally) transported in horizontal position on a transport installation vessel (TIV) or barge

- Up-ended and lifted at WTG location and installed with a driving hammer

- Transition piece (TP) is installed afterwards - Vibratory hammers are available, but not

common yet - (Pre-)drilling is possible in hard ground

conditions (but expensive) - TP-less monopiles are becoming more

common Pro’s - Well known and proven technology with a

market share of about 75% in Europe - ‘Simple’ fabrication, welding can be done

automatically - EU fabricators (e.g. SIF and EEW) are

specialists and can produce ~4 to ~5 monopiles/week

Con’s - Driving hammer generates a lot of noise - Lean process does not create much local

content (if applicable)

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- Decommissioning is currently considered to be difficult

Project examples: Deutsche Bucht (DE), Arcadis Ost (DE), Borssele OWF Zone (NL), Hollandse Kust Zuid (NL), about any OWF in Europe

Applicability for Estonian/Latvian projects - Very good, considering the shallow water depths

- Not so good, considering hard ground (rock) conditions at some locations(1)

(1) Based on high level general geological maps

3.1.2.2 Jacket Structures (3 or 4 Legged Substructures)

General Jackets are braced steel structures that are commonly applied in the oil & gas industry. The braced structure will be present in the water column, and above water level. The WTG tower is directly connected (integrated TP). Loads are transferred to the ground with piles or suction buckets. Piles can be installed prior or after jacket installation. For WTG support jackets typically have 3 or 4 legs.

Dimensions - Footprint at seafloor 25x25 m2 to 50x50 m2 (depending on water depth)

- Height 80 m to 120 m, but higher is possible

- Oil & gas jackets up to 500 m Weight - 600 t to 2,000 t (in air), but larger is

possible Applicable water depth - Between 60 m and 100 m, although

larger depths are possible. - Jackets might be used in shallower

water depths as well. However this might economically less viable.

Applicable ground conditions - Depends on foundation system (piles or suction buckets)

- Soft ground conditions (clay, sand and silt or alternations thereof) for piles

- Soft ground conditions (clean clay or sand) for suction buckets

- Difficult to apply in rock (impossible for suction buckets)

Fabrication methodology Tubular braces welded together in a flat position and up-ended and connected together. Fabrication of piles and suction buckets (more or less) similar to monopiles

Transport and installation methodology - (Generally) transported in vertical position on a TIV or barge

- Lifted from vessel/barge to WTG location

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- Piles installed before or after jacket installation. Piles installed with driving hammer (or with vibratory hammer)

- Suction bucket installation while lowering the jacket to the seafloor

- Large jackets can be launched Pro’s - Many (former oil & gas) construction yards

can fabricate jackets - Proven technology - Applicable for high loads and large water

depths - Labour intensive, which is favourable for

local content - Suction bucket jackets can be fully

decommissioned Con’s - Labour intensive

- Heavy structures require largest available installation vessels

- Driving hammer for piles generates a lot of noise (can be mitigated by suction buckets)

Project examples: Wikinger (DE), East Anglia (UK), Seagreen (UK) Applicability for Estonian/Latvian projects - Not so good, considering the shallow water

depths. Cost/benefit decision (1) Based on high level general geological maps

3.1.2.3 Gravity Base Structure

General Gravity base structures is a collective name for heavy foundations that transfer loads from the top structure to the sub-bottom, based on gravity. Commonly, they are concrete structures that are ballasted after set-down on the seafloor.

Dimensions - Footprint at seafloor 25 to 35 m diameter for

- Height up to 40 m, but higher is possible - Oil & gas jackets up to 350 m

Weight - 2,000 t to 5,000 t (for up to 6 MW turbine) - Note that 6MW is the maximum known

turbine size to date that is known to be installed on a gravity base.

Applicable water depth Up to 30 m, although larger depths are possible

Applicable ground conditions - Strong grounds, e.g. dense/very dense sands or rock

- Not applicable on soft soil, e.g. clay Fabrication methodology Constructed with reinforced concrete in

formwork

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Transport and installation methodology - Seabed needs to be levelized prior to GBS installation

- GBS is towed to the site and ballasted in a controlled way to lower the structure to the seabed

Pro’s - Applicable for hard ground conditions - Can be towed to site, no need for large

installation vessels - Possible to fabricate locally, since concrete

is a common material for structures and infrastructure

Con’s - Structures require a lot of space - Difficult for serial production - No track record for larger turbines - Difficult (impossible?) to decommission - Concrete is not very environmental

friendly Project examples: Thornton bank Phase 1 (BE), Avedfre Holme

(DK), Kårehamn (SE), generally small turbines < 5MW

Applicability for Estonian/Latvian projects - Potentially good, considering hard ground (rock) conditions at some locations(1)

(1) Based on high level general geological maps

3.1.3 Costs

3.1.3.1 CAPEX

Main costs are driven by steel grade and weight. The standard EU steel grade is S355, but the steel grade that needs to be used, as mentioned, depends on the actual site conditions and loads. As with all commodities, steel prices may vary heavily over time, so may prove to be difficult to provide an accurate cost estimate per foundation type that might be valid over a long period of time. Also the steel will need to be rolled, processed and shaped in the required foundation (jacket, monopile). Consequently, we provide ball park figures and our assumptions are given below:

1. Total windfarm size: 1000MW 2. Water depth: 30m 3. Soil: sandy soils 4. Turbine: 10MW 5. Location: North Sea – UK Sector 6. Weight of foundation assumed 800 ton

Turbine foundation part

Cost (in Euro/MW) Weaker soils Stiffer soils (clay)

Foundation (monopile) 335.000 Diameter increase  price increase

Diameter decrease  price decrease

Transition piece 120.000 Diameter increase  price increase

Diameter decrease -> price decrease

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Corrosion protection 24.000 Diameter increase  more protection  price increase

Diameter decrease –> price decrease

Scour protection 12.000 Higher chance of scour  price increase

Best case scour protection is not required.

Source: Catapult Offshore Renewable Energy – BVG Associates3

In addition to steel prices, the costs of foundations are also driven by transport and installation costs. Since these are large structures transport costs can be serious. However, if they are produced locally, it might be more cost effective.

Item Cost (euro/MW)

Foundation installation 100.000

Offshore transport 3.500

Source: Catapult Offshore Renewable Energy – BVG Associates

Although included already in the above foundation installation cost, it is worthwhile to mention that the day rate of a suitable installation vessel is approximately 300.000 euro a day.

For Gravity based structures, the cost estimate is very difficult to estimate. The first important factor is the levelness of the seabed. If the seabed is unsuitable to directly install a GB, there is the possibility that dredging work will need to be undertaking in order to prepare the seabed. Other factors are the same as per monopile or jacket foundations: soil, waves, ice loading, turbine size and seabed currents. Since the GB is standing “loose” on the seabed, a detailed study of the seabed currents is important. High currents potentially can lead to the seabed being “washed away” underneath the GBS, leading to instability of the WTG. Given the above, unfortunately, a price per MW is very difficult to provide.

3.1.3.2 OPEX

For all types of foundations, the OPEX are generally not very high. Making sure that the corrosion protection and the scour protection measures are still sufficient are the main OPEX drivers, together with the regular inspections of the substructures. The biggest cost driver here will be a service vessel that will need to go out and inspect foundations. Day rates for such vessels easily reach 100.000 euro per day (depending on the size & scope of the inspection). For small inspection work, cheaper vessels can be hired.

3.2 Offshore Substations Foundation

For foundations for the offshore substations, in principle the same applies as per the previous discussion of the WTG foundations. Note that for substations the monopile is not considered a viable option, since this is typically for WTG only.

3 https://guidetoanoffshorewindfarm.com/wind-farm-costs

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4 WIND TURBINES

4.1 Description

Wind turbine technology is constantly improving as OEM’s battle for the title of who has the largest turbine. The race for who has the largest turbine has led to an offshore dominance of three manufactures; Siemens Gamesa, Vestas and GE.

The wind energy industry has seen a development unlike any other in the past 40 years. It has gone from 75kW machines with a tip height of 40m in the 1980’s to recently announced turbines of 15MW that nearly rival the height of the Eiffel tower. The 15MW turbines are due for serial production by 2024 and in the future this could increase to 20MW by 2030.

Figure 1 - Wind turbine power and size evolution over time4

Figure 2 - Global offshore wind growth outlook to 20305

4 Pisanò, Federico. (2019). Input of advanced geotechnical modelling to the design of offshore wind turbine foundations

5 https://gwec.net/global-offshore-wind-report-2021/

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GWEC expects a total installed offshore wind capacity of 270 GW by 2030. It expects high compound annual growth rate of 30% towards 2025, with a slow down to 12.7 until the end of the decade. Promising outlook for offshore wind installation, because:

– Globally high ambition levels by governments

– LCoE keeps decreasing (competitive energy resource)

– Commercialisation and industrialisation of floating wind

4.2 Technical Information

Wind turbines extract energy by slowing down the wind. Albert Betz concluded that a wind turbine can only convert 59.3% of the kinetic energy from wind creating the Betz limit. For a turbine to be 100% efficient it would have to stop all the wind passing through it. In reality, this is not possible as a rotor needs the wind to pass over its blades to rotate. Modern turbines can convert 35-50% of wind energy, once you factor in mechanical and electrical losses this value reduces to 10-30% of wind power that is converted in usable electricity.

Offshore WTG consist of one tower section, nacelle, rotor and three blades. Inside the WTG there are electrical and mechanical equipment that are used to convert the wind energy. There are two types of drive train technologies that are used by all OEM’s with horizonal axis machines; direct drive and gearbox machines. Below is a basic SLD for a wind turbine that shows the gearbox, generator, DC link converter, inductance to smoothen the waveform on the AC side and transformer. Not included in the image but equally important is the switchgear that receives the energy from the transformer before it reaches the grid.

Figure 3 – Basic single line diagram of gearbox WTG showing IGBT converters

WTG’s are designed and certified to operate in specific wind conditions. These wind conditions are defined by the IEC standard and correspond to high, medium and low wind speeds. Manufacturers have also designed WTG’s that can withstand storms and typhoons for areas where this is an issue. If wind conditions are on the low end then manufacturers can increase the blade diameter and hub height to capture more energy as there will be less loads going through the turbines.

The WTG is controlled by various computers which monitor its condition and performance. They ensure that the WTG nacelle and blades are in the optimal position to capture the most wind. The SCADA system gathers and communicates the real time data so that asset owners can control and monitor the assets remotely. The power curve plots power vs wind speed which shows the cut in speed, partial and full load regions (see Figure 4). If the wind becomes too strong (typically above 25m/s) then the WTG will pitch the blades out of the wind and go into preservation mode to ensure

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that the WTG and substructures are not damaged.

Figure 4 – WTG power curve6

4.2.1 Gearbox Wind Turbine Type

The gearbox wind turbine uses a multi-stage gearbox in between the low speed rotor and the higher speed electrical generator. The purpose of the gearbox is to increase the rotor speed before it is fed into the generator. The drive train consists of a main shaft, gearbox and electrical generator before the power is converted and sent to the grid.

4.2.2 Direct Drive Wind Turbine Type7

Direct drive wind turbines remove the need for a gearbox in the drive train, by connecting the rotor directly to the synchronous generator. A direct drive wind turbine’s generator speed is equivalent to the rotor speed because they are directly connected. The power is transferred from the generator to the converter then the transformer and finally to the OSS through an inter-array cable.

Figure 5 shows the market share between OEM’s of operating wind farms up to 2020. Senvion has since gone into administration and been bought by Siemens Gamesa. The Chinese manufacturer are not widely used outside of their own market and will not be discussed further. This market share should become more equal between three manufacturers (GE, Siemens Gamesa and Vestas) as they all start to deliver 10+MW turbines in the coming years. Figure 6showsthe announced capacity expected for 2020, which for the top three manufactures is greater than the total already installed.

6 Source Wind energy conversion with a variable-ratio gearbox: Design and analysis

7 https://www.engineering.com/story/the-future-of-wind-turbines-comparing-direct-drive-and-gearbox

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Figure 5 - Offshore wind turbine manufacturer market share in operating projects

Figure 6 - Offshore wind turbine manufacturer market share for announced projects

4.3 Wind Farm Power Density

The optimal wind farm power density (MW/km2) can vary depending various factors including, location, wind farm size, rotor power density and diameter, hub height, turbine capacity and spacing. Up to a certain level, a sparsely populated wind farm will have a lower LCoE than a dense wind farm due to lower wake effects. Over the last few years, the average power density of the Dutch offshore wind farms has increased from 5MW/km2 (Borssele) to 8MW/km2 (Hollandse Kust Noord) and will further increase to 10MW/km2. This trend has a negative impact on LCoE but is advantageous from an optimal use of space. The Energy Research Centre in the Netherlands

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commissioned a report that showed the optimal wind farm power density is 4.66 MW/km2 for a 10 MW wind turbine and 5.06 MW/km2 for a 15 MW wind turbine.89

4.4 Costs

4.4.1 CAPEX

Due to the size of wind turbines towers and blades they are constructed as separate components. Normally, fabrication yards are located near shore and are easily accessible for ships, so the components can be transported to the wind farms. The CAPEX below are assumed as a base case and consist of manufacture, transport, and installation. The further away a wind farm is from the assembly port the more expensive the project will be. In the short term turbine price will increase as there is a rise in raw materials prices (steel, copper, aluminium and fibres) combines with a sharp rise in logistic costs.

1.0 – 1.2 M€/MW

4.4.2 OPEX

The price for OPEX can vary widely depending on the location, turbine type and O&M strategy. Distance to shore affects transfer time of technicians when using CTV vessels and logistics of components for replacement. Newer wind farms are moving more towards hiring SOV vessels for week shifts that provide better and safer access to the WTG.. Turbine repair costs increase with age as more parts begin to fail. This is usually factored into the O&M contract price being larger towards the end of life of a project as repairs of main components require the use of jack up vessels that are expensive.

35 – 53 k€/MW/year

4.5 Lifetime

The normal design life of a wind turbine is 20-25 years. During the development stages of a wind farm the end of life options should be considered. There are three options at the end of life;

1. Decommission – remove the wind turbines and their foundations. Costs for this activity should have been accounted for in the development stage (typically 2-3% of CAPEX).

2. Life extension – depending on environmental factors and maintenance quality there is the possibility to extend the life of the turbines. This would typically involve carrying out an assessment that would identify any parts that need to be exchanged. During the operation of a wind farm measuring the loads experienced by the turbine and foundations is important for the life extension assessment.

3. Repowering – The owner of the wind farm can look to take advantage of the existing infrastructure (foundations, cables and OSS), which tend to have longer design life, to repower the wind farm with larger wind turbines. An assessment will need to be carried out on the technical feasibility of such an option.

8 http://resolver.tudelft.nl/uuid:dfe0ce2f-04fb-4db2-80db-52bc02cfb515

9 https://blixconsultancy.com/wp- content/uploads/2021/06/20210125_RAP_Pathways_to_potential_cost_reduction_offshore_wind_energy_F03.pdf

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The end of life decision will consider the site conditions, regulatory situation, permits and leases, energy prices, subsidy schemes and compare it against the cost and value of decommissioning.

4.6 Availability

When evaluating the turbine availability (uptime) there are two methods that are used: Time based and Production based availability.

For time based availability, the O&M provider will guarantee a contractual availability between 95- 96% for each year starting after all turbines are taken over from construction. Any downtime due to non-turbine related issue are excluded from the guarantee such as weather access, BOP and Grid availability. Time based availability is calculated based on the time that the turbines are available to produce regardless of wind speeds.

Production based availability was created to prioritise the importance of having the turbine available during high wind periods which means maintenance activities are carried out in low wind periods otherwise it penalises the service provider. The so-called capacity factor gives a good indication of the wind resource available at a site by showing how well a wind turbine’s full capacity is used. Offshore windfarms have an average of 42.22% based on data available in the UK. As wind farms move further away from shore and in deeper water (floating foundations) there is scope for this to increase as seen at Hywind OWF which reached 57.1% during 2019/20.

Any form of maintenance whether schedule or unscheduled would count against the availability guarantee which incentivises an O&M provider to plan around high wind periods.

It is not possible to provide specific numbers for downtime due to regular maintenance as there is difference in types of technology and what O&M providers include in their scope of service. However looking at time based availability guarantee there are 8760 hours in a year, if the guarantee is for 96% then the wind farm would not be available for 350.4 hours (14.6 days) per year.

Seasonality affects the production, maintenance and access to site. O&M providers should concentrate maintenance during the low wind periods (spring and summer) leaving the turbines alone during high capacity seasons (autumn and winter). Non access days can affect the performance of an asset when there are failures. On average in the UK wind farms, 96 days a year access is restricted, meaning that vessels cannot access the turbines due to adverse sea and weather conditions. Use of SOV as opposed to CTV will further lower this average.10

10 https://ore.catapult.org.uk/wp-content/uploads/2021/02/SPARTA-Review-2020.pdf

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4.7 WTG Catalogue

Below is a list of the largest turbines currently in serial productions as well as the next generation prototypes that are either installed or close to being installed.

WTG supplier Largest WTG in serial production (TRL 9) Largest Planned WTG

Capacity (MW) Rotor ø (m) Capacity (MW) Rotor ø (m) Year of

prod. TRL

Siemens Gamesa (SGRE) 8.4 167 15 236 2024 7

Vestas 9.5 164 15 236 2024 6

General Electric (GE) 6 150 14 220 2024 7

Table 2 - Offshore WTG specifications

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5 OFFSHORE GRID CONNECTION SYSTEMS The first offshore wind farm was constructed in 1991 off the coast of Denmark near a town called Vindeby where it also got its name. The market took a long time to mature however now due to various factors (government policies and incentives, cost reductions, land restrictions etc) there is more deployment of offshore wind.

Electricity transmission is divided into two main grid technologies, Alternating Current (AC) and Direct Current (DC), both with their own variations as LFAC, intermediate compensation (AC), different DC technologies/setups etc. During the next sections the technical concepts for each technology will be further assessed. The main factors like wind farm size and location offshore (transmission distance) dictate the connection type that is best. Most current offshore wind farms are relatively close to shore and have been connected using AC.

The DC alternative becomes competitive for combined CAPEX and OPEX with increasing power ratings and transmission distance. Although AC substations are cheaper, DC has lower cable costs and is able to carry more MW per cross section. In general there is a tipping point of CAPEX (DC- stations versus AC, more cables versus less for same MW, transmission distance) and OPEX (losses of stations, losses of cables, maintenance costs) together which favors one of both options.

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6 AC TECHNOLOGY

6.1 HVAC Offshore Substation

6.1.1 Description

The AC offshore substation (OSS) collects the energy generated by the wind turbines and steps up the voltage to decrease the losses during transmission. This uses a radial system where the turbine are connected in strings and those strings then feed into the OSS. The design concept widely used currently is that one offshore wind farm would feed into a corresponding OSS and the power is then transported to onshore substation through an export cable (EXC) where it is connected to the grid.

This design is now being improved as countries and energy producers look to reduce costs and share energy between multiple markets. One option is to develop hub systems that can collect energy from multiple wind farms. The higher substation costs required is offset by requiring fewer EXC and increasing the wind turbine capacity factors through less curtailments. This option could be expanded to include interconnectors that connect various offshore hubs with multiple countries. A good example is the Kriegers Flak and Baltic wind farms that connect two separate markets, Denmark and Germany (although the two markets are non-synchronized leading to an additional HVDC back-to- back converter station).

At this moment AC platforms of a size larger than 1400MW are not very common, it is even considered to have multiple smaller platforms (350-450MW, for instance like the Siemens OTM which could even be regarded as a ‘standardized’ setup) as the length of the inter array cable (IAC) will increase dramatically (as the area to be built will be larger with higher power, but all need to be connected to one large OSS). Therefore the rated powers will be limited to 350, 500, 700, 1000 and 1400MW for a HVAC OSS.

Figure 7 - AC offshore grid connection layouts11

6.1.2 Technical information

When an AC-connection is considered, there are some options that impact the high-level decisions:

• length of EXC, as a longer length leads to higher capacitance / higher reactive power losses / less available MW-transmission (this can be partly reduced by symmetrical compensation and/or an intermediate compensation)

11 https://guidehouse.com/-/media/www/site/downloads/energy/2019/2019-navigant-comparison-offshore-grid-development.pdf

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• voltage of EXC, as a higher voltage leads to a higher MVA-transmission but also higher reactive power losses lowering MW-transmission

• on top of this, the redundancy should be considered - is there a need for redundancy on the OSS (maybe based on TSO requirements and

compensation schemes)? - is there a need for redundancy for the EXC

The redundancy is not further considered. It is of course clear that any OSS with at least two EXC and/or two transformers can provide partial redundancy:

• design the transformers for ONAN in normal operating conditions and use ONAF when one transformer fails

• design the EXC for normal operating conditions and use a DTS system (monitoring the complete length of the cable) when one EXC fails

• design of the system so if the compensation reactor is out-of-service the turbines can partially take over the compensation functionality

• connect to a neighboring OSS (IAC or EXC level) to have partial redundancy or only AUX power for turbines

Based on the average ampacity/capacitance of EXC with large cross sections, the following general rules can be applied for average distances (40km – 70km):

• the maximum power to be transmitted by 220kV equals to 400MW • the maximum power to be transmitted by 275kV equals to 500MW • offshore transformers larger than 500MW (550MVA) are not preferred as less standard • having the amount of EXC equal to the amount of transformers leads to an ‘optimized’

balance between the two types of equipment

These statements are very general and based on experience / calculations of different setups and of course deviations can always be found.

Based on the above the following is expected as optimal technical-economical choices:

Power [MW]

Main TR [#]

Voltage [kV]

EXC [#]

350 1 220 1 500 1 275 1 700 2 220 2

1050 2 275 2 1400 3 220 3

Table 3 - General setups for different transport powers

The exact distance from shore is no real parameter here except for the cable losses and the size of the compensation reactor. For very large distances, intermediate compensation platforms may need to be considered.

The standards / brochures that are related to OSS are in general the DVN-GL ST-0145 which refers to many other standards based on the equipment installed on the OSS.

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6.1.3 SLD

• compensation reactors are consider to be connected via a DC/ES to the EXC • an average of around 80MW/string is considered • transformers are assessed as 2 winding each winding having a MV earthing/AUX transformer

and associated bay

Figure 8 shows the resulting high level SLD (additional ES/DC are omitted) where the colors denote the amount of offshore transformers/EXC/compensation reactors (black = 1, red = 2, green = 3):

Figure 8 - High level SLD's in relation to # transformers

6.1.4 Costs

6.1.4.1 CAPEX

The CAPEX of the chosen system design is highly impacted by design choices and the prices in the OEM market for electrical components and metals. It has been observed that RFQ for main components sometimes even resulted in a spread of 100% on the received offers. For the CAPEX estimation below a range of ±20% is assumed.

The following overview is based on a minimal approach:

• amount of transformers and reactors as per previous table / SLD • reactors connected with DC/ES • if more than one EXC, a DC/ES between the both • transformers and reactors housed outside • LV and HVAC redundant • no large crane or diesel generator • unmanned

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The CAPEX can be raised considerably based on the following decisions:

• making it a manned OSS with all additional HSSE requirements • housing the transformers and reactors inside (even with HVAC, this should get an increased

capacity then) • gensets (for OSS and turbines) and IAC-compensation reactors for during grid outage • large cranes (they tend to fail at the moment you need them, better come with an equipped

vessel) • a helideck (roughly 3M€)

Power [MW]

CAPEX [M€]

€/MW [k€]

HVMV [%]

LV-AUX [%]

Structural [%]

PM, Install & Comm

[%] 350 71 204.1 22% 17% 29% 32% 500 86 171.9 23% 14% 35% 28% 700 121 173.0 23% 12% 37% 27%

1050 155 148.0 23% 11% 39% 26% 1400 179 127.6 24% 11% 40% 25%

Table 4 - Overview of CAPEX HVAC OSS for different transport powers

6.1.4.2 OPEX

OPEX is typically expressed as a percentage of CAPEX. BLIX through previous projects and confirmation from various sources finds that 1.5% is a reasonable value to apply. This is further confirmed through various research papers that arrive at similar values of 1%12 and 0.9 – 1.45%13.

The activities for preventive maintenance include:

• maintenance HVMV equipment (inspections & functional specs) • maintenance LV equipment ((inspections & functional specs) • maintenance AUX equipment ((inspections & functional specs) • coating repair • C&P: rolling testing in time of all relays by injection • cleaning: removing of guano

Corrective maintenance is expected mainly on AUX-systems and could we require 12-24 interventions/year.

6.1.5 Lifetime

The lifetime of a platform is considered to be a minimum of 25 years, where the most wear and tear can be expected from rotating components and the components that stress by continuously heating up and cooling down (transformers) and being in full power continuously (reactors). Next to having correct preventive maintenance on these components (preferably with an online gas-measuring unit

12 Brard, B. (2017). The regulation of radial grid connection systems for offshore windfarms. Delft University of Technology.

13 Ritzau, M., Macharey, U., Svoboda, P., & Wilms, J. (2017). Determination of an operating cost lump sum for offshore plants. Decision BK4-17-0002 of the Federal Network Agency

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for transformer/reactor), fans (rotating) or diesel generators (needing filtered diesel by pumps) should be avoided to increase lifetime and limit maintenance.

6.1.6 Availability

The availability is assessed in respect to preventive and corrective maintenance.

Preventive maintenance is foreseen for 24 interventions per year of 4 days without the need for production loss as all (impacting) maintenance is foreseen to be planned during low/no wind.

Corrective maintenance is difficult to assess as this is determined by the design of the system:

• each supporting system which is critical to the main functionality, should be constructed 100% redundant. Examples:

- HVAC system - LV-system

• the HV-setup determines to which level partial redundancy can be derived - when only one healthy transformer is available this can be boosted with later

attached fans

A RAMS assessment of an OSS-design will lead to the theoretical power lost availability figure which normally is higher than 99.5% (taking into account the specific power loss depending on the failure).

6.1.7 Losses

Losses can be easily derived from the losses of the main components and the own consumption of the OSS. On top of that the wind profile/powercurve should be assessed (power bins) to come to the percentage of energy produced that is considered as consumed/lost on the OSS (and include the load-losses of transformers). This is normally in the range of 0.3%-0.4%.

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6.2 AC cables

6.2.1 Description

For offshore multiple submarine cables (voltages, cross sections) are available (Prysmian catalogue):

Voltage class [kV]

Cross section [mm2]

66 240 - 2000 110 400 - 2500 132 400 - 2500 150 400 - 2500 220 630 - 2500 275 630 - 2500 345 800 - 2500 400 800 - 2500 500 1600 - 2500

Table 5 – General overview of available submarine cable cross sections per voltage class

For each OWF (Offshore Windfarm) several types of cables/accessories are needed, assuming the land station is located not too far from the coastline.

• Inter Array Cables (IAC) to connect the offshore turbines with strings towards the OSS • Export Cables (EXC) to connect the OSS to the land station. In most cases they consist of:

- a 3-core submarine cable - a transition joint (normally) on land to switch from the 3-core submarine cable to

single land-core cables - single land-core cables to connect to the land station

• Grid cables: cables to connect the land station to the TSO-grid

This chapter will concentrate on the submarine cables (IAC and EXC).

6.2.2 Export cables

6.2.2.1 Technical information

To lower the losses of the transport system, the voltage of the IAC is raised by transformers to the EXC level. At this moment the main used voltage level used is 220kV and sometimes 155kV (to connect lower power, mainly used to connect to offshore DC-stations of TenneT Germany) and 275kV.

These cables are normally made with a XLPE-insulation while having led both a radial-water-blocking element and return path for the single-phase short circuit current [7]. See below picture as a general setup:

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Figure 9 – Export cable example

The cable also contains FO (communication and temperature measurement system), armouring (protection), fillers (strength) etc.

As the cable can be considered as a large capacitance, capacitive current and hence power loss will be imminent. As the Mvar raises with the square of the voltage, this is considered having a high impact and is used in discussion what the tripping point is to move from AC-technology to DC- technology. Of course the cable is available in different cross sections (range depending on voltage level, see table) in both ALU (stranded or solid) or Cu. Milliken types are normally not used due to expenses.

Five types of information are normally available for EXC:

1. mechanical properties / cable handling 2. geometrical properties (how is the cable built up, layers, materials) 3. electrical properties 4. ampacities 5. FO-properties

Item 1 is required to have sufficient comfort that the cable handling by the installation contractor will be withing the cable handling limits. This is both for spooling of cables between different locations, installation on the seabed, burying the cable and installation of cables into the OSS until termination.

Item 2 is required if specific frequency sensitive simulations need to be executed as transient analysis or harmonics distortion calculations. Normally these parameters are translated by simulations packages as PSCAD or EMTP to frequency dependent electrical parameters which are then used in follow-up simulations.

1 Stranded wires

2 Semiconducting tapes

3 Conductor extruded screen

4 XLPE

5 Extruded screen

6 Semicon tapes for LWB

7 Lead

8 Semicon PE

9 Yarns

10 Armour (GS/HDPE)

11 Yarns

12/13 Filler / extruded filler

14 FO

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Item 5 refers to the fiber optic properties, normally the capabilities are well within the required boundaries.

For item 3 and 4 the following can be assessed as some general cable characteristics for a small and large cross section of ALU and Cu.

Table 6 – Electrical characteristics of HVAC cables

These values are available from several cable suppliers which cannot be referred to due to confidentiality. Main suppliers at this moment are:

• NKT, Germany • LS, South Korea • Prysmian, Italy • Hellenic, Greece • Nexans, Sweden • Chinese suppliers upcoming

Next to the cables several related accessories are important:

• factory joint: to be able to make long lengths in the factory, suppliers will ‘connect’ single cores with factory joints for their laying-up machine. The FJ are most times also capable of switching in cross section and sometimes even to switch in conductor material

• repair joints or offshore joints: joints to connect (or repair) offshore cables, normally consisting of 3 ‘normal’ joints in a metal casing

• transition joint: joint onshore to connect the 3-core submarine cable to single land-cable cores, normally consisting of 3 ‘normal’ joints

• terminations: mostly Pfisterer size 6 terminations which are used to connect to an inline joint or a HV-GIS

• inline joint: several types exist, but the most common is a SF6 filed system which connects to male terminations (example: Pfisterer 6 size)

The standards / brochures that are related to these type of cables are mainly IEC 62067, TB490 and TB623 (and referred standards therein). These documents refer to construction, pre-qualification

Cable characteristic Unit ALU 800m2 ALU 1600mm2 Cu 1200mm2 Cu1400mm2 Cu 2200mm2 Nominal voltage between phases UN kV 220 220 220 275 275

Maximum voltage between phases UM kV 245 245 245 325 325

Maximum electrical stress at UN @conductor surface kV/mm 8.3 7.8 10 9.7 DC-resistance conductor 20 degrees Ohm/km 0.0367 0.0186 0.0151 0.0129 0.0082 AC-resistance conductor 90 degrees @50Hz Ohm/km 0.0497 0.0287 0.026 Positive sequence impedance @50Hz Ohm/km 0.071 + 0.129j 0.047 + 0.114j 0.0272 + 0.1154j 0.024 + 107j Inductance of conductor mH/km 0.412 0.361 0.37 Capacitance per phase μF/km 0.154 0.2 0.195 0.207 0.25 Total losses @ampacity W/m 146.6 167 Conductor losses W/m 3x33.8 3x33 Dielectric losses W/m 3x0.8 3x1.0 Metallic screen losses W/m 3x5.5 3x9.2 Armour losses W/m 26.5 37.3 Maximum short circuit current conductor (1s) kA 76 151 172 Maximum short circuit current metallic screen (0.6s) kA 21.2 21.7 22

Armour material GS GS SS 50%GS/50%HDPE 50%GS/50%HDPE

Ampacity (DoB 1.5m / soil 10 degrees / soil 0.6Km/W) A 824 1073 Ampacity (DoB 1.5m / soil 15 degrees / soil 0.7Km/W) A 1180 Ampacity in HDD A 1000 1180

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tests (PQ), type tests (TT), routine tests (last test as FAT), sample tests and SAT, both for cables and their accessories.

6.2.2.2 Installation

The installation of EXC is normally executed from a cable laying vessel that contains large baskets on turntables that are filled at the quay side. Figure 10 shows the design of this equipment to be placed on a cable laying vessel:

Figure 10 – Design of turntable on a cable laying vessel14

The cable is ‘laid down’ with a special system (checking all mechanical stress parameters on the 3- core cable) on the seabed. Afterwards normally a ROV is used to bury the cable by liquifying the seabed which allows the cable to sink easily to the required depth.

At the OSS the cables are guided through a Cable Protection System (if applied, also only scour is used) and the J-tubes. Then they are stripped on the cable deck of the OSS (3-core cable will be fixated by hang-off) and the single cores are guided to the HV-GIS and terminations are installed and connected. Sometimes an inline joint is used to connect the EXC and pre-installed platform cables.

Of course, many more requirements and activities need to be fulfilled/executed during this installation process, only the high-level activities are mentioned.

6.2.2.3 Costs

6.2.2.3.1 CAPEX

The following table shows some costs that can be expected for different types of EXC. When this information is used, the next points should be considered carefully which requires to use the prices with a large margin:

• it should be noted that the cable prices have been very volatile in 2020/2021 due to COVID and the price of metal

• the tender prices that have been used are the variable prices per meter • the tender prices are also highly depending highly on the cable-volume of the project (LOW

< 50km, MEDIUM, HIGH: > 150km)

14 Enersea presentation of activities. www.enersea.nl

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• suppliers tend to also assess the risk of a project in their price, this is not further detailed • based on the above a margin of at least 25% should be applied

Voltage class [kV]

Cross section [mm2]

Conductor material [ALU/Cu]

Armour material

[GS/SS/HDPE]

Volume Costs [€/m]

220 630 ALU GS LOW 480 220 800 ALU GS HIGH 410 220 800 ALU SS HIGH 480 220 1000 ALU GS HIGH 430 220 1000 ALU SS HIGH 510 220 1000 Cu SS/HDPE HIGH 750 220 1200 ALU GS HIGH 450 220 1200 ALU SS HIGH 505 220 1200 ALU SS/HDPE HIGH 530 220 1600 ALU SS MEDIUM 770 275 1400 Cu GS/HDPE MEDIUM 1200 275 2000 Cu SS MEDIUM 1500

Table 7 – Cost per meter of several HVAC cables

The above prices do not include:

• engineering and if needed additional type test or PQ tests • fixed (starting) costs for supply • installation of offshore joints / transition joints (high costs due to vessel availability) • termination and testing (T&T)

- termination is normally not the highest portion of costs but does pose a risk (check: availability)

- testing can be quite expensive if a resonance test (from onshore) is conducted

In recent projects calculations for EXC are done based on dynamic rating (per IEC 60853-2) instead of continuous rating (per IEC 60287) as it has been shown that the cables are over-dimensioned and never reach their maximum temperature. This lowering of cross sections of course does add to higher losses during normal operation and less margin during n-1 situations.

The installation costs of all cables are roughly the same (if the cable is larger/heavier the vessel needs to make more trips / more offshore joints are needed) and can be assessed for €200/m for the variable part with a margin of 20%. The mobilization and demobilization costs should be added including weather delay provisions which are very project specific.

6.2.2.3.2 OPEX

OPEX is very depending on the project specific situation (how is it buried, rocks, sand, mattresses (for crossings), clay, ..) leading to a wide spectrum of inspection techniques and cannot easily be given.

The OPEX can be ‘minimized’ by use of DTS (Distributed Temperature Systems) and/or DAS (Distributed Acoustic Sensing) which monitors the temperature (and if installed correctly, the DoL (Depth of Laying)) next to free hangs or other mechanical stress adding activities.

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In a ‘normal’ situation the following activities are covered as preventive maintenance:

1. a 1-5 yearly survey is needed to check the exact laying configuration of the cable (based on the magnetization of the armour during load-out)

2. a Remote Operated Vehicle (ROV) with camera’s to inspect CPS (Cable Protection Systems) entering the J-tubes and crossings done with mattresses

3. re-execution of LIRA/TDR tests to assess impact on insulation

6.2.2.4 Lifetime

Lifetime of type tested cables (all cables are assumed to be a dry design) are considered to be 25-40 year. Formally the IEC-standards do not mention this and the first installed submarine cables have barely reached this lifetime

6.2.2.5 Availability

The availability of EXC is depending on 4 major items:

1. The electrical quality of the cable: normally if this is correctly tested (PQ, routine, FAT, SAT) there is a low expectation on failure

2. The mechanical quality of the cable: normally if this is correctly tested (PQ, SAT) and the installation conditions have been monitored and kept all beneath the allowed limits, there is a low expectation on failure

3. Man-made additions as repair joints and terminations: this can be a source of failure 4. Mechanical damages due to free-hanging (stress), anchors, fishing nets etc.: this is a major

source of failures and is heavily depending on the offshore location

Item 3 is partly covered by the SAT (Site Acceptance Test) which stresses the cable according to IEC 62067 including the accessories. This is normally a resonance test until 1.7U0 per phase in the range of 20Hz - 300Hz (or a bit lower as per table 10 of IEC 62067). If a choice is made for a 24hr soaktest, this is not applicable and not ‘tested’. The failure rate of the EXC is normally expressed as an electrical failure rate per km (λ) and added on top that the failure rate per joint/termination (which usually derived from land-based failure rates).

Item 4 is a practical assessment which needs to be made by the OWF and differs all over the world. A value derived from available sources shows an average of 0.003 failures/km/year15.

6.2.2.6 Losses

It should be clear that for losses calculations 3 options can be used:

• W/m as given for the 220kV cable (see overview) • metallic screen losses can also be referred to as λ1 being the ratio between conductor losses

and metallic screen losses and armour losses can be referred to as λ2 being the ratio between conductor losses and the armour losses

• use of positive sequence resistance which incorporates all these 3 losses (but missing the dielectric losses which are considered small)

As stated before, the losses and Mvar of the cable do impact the tripping point where an AC connection is becoming less attractive. A qualitative approach is shown in the compensation chapter.

15 Failure Rates of Offshore Wind Transmission Systems. energies-12-02682

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To lower/eliminate the armour losses, suppliers can replace the galvanised steel wires by stainless steel wires or HDPE (if the impact amount of pulling force is allowed) or a mix of these types.

6.2.3 Inter array cables

6.2.3.1 Technical information

To connect the turbines to the OSS, the inter array cables (IAC) are used. They will operate on the voltage level of the turbines on the HV-side of the transformer. Until a few years ago this voltage level for offshore was 33kV, this has been changed now to 66kV, amongst others by projects initiated by the Carbon Trust. Further the next step, also initiated by the Carbon Trust, is to increase this level to 132kV, however cable characteristics are still unknown. This level is ‘agreed’ between cable suppliers and turbine suppliers will follow. This also has to do with the amount of power each turbine is able to produce which has raised very fast from 4MW (Gemini, 2010), 9.5MW (Blauwwind, 2018) to 15MW (expected in 2024/25). Further the higher voltage will give reduced losses, longer distances and a more acceptable voltage profile along the string.

These cables are normally made with a XLPE-insulation or EPR-insulation (Prysmian), the last one having more flexibility then XLPE-cables (and also claimed better ampacity). The radial water blocking functionality can be present (overlapping, glued foils or ALU welded sheath) or constructed as a (semi)wet design which allows the cores (screen wires, outside semicon) to come in contact with the seawater. See below picture as a general setup for a dry design:

Figure 11 – Inter array cable example

The cable also contains FO (communication and temperature measurement system), armoring (protection), fillers (strength) etc. The information types of IAC are identical as for EXC.

1 Stranded wires

2 Semiconducting tapes

3 Conductor extruded screen

4 XLPE

5 Extruded screen

6 Semicon tapes for LWB

7 Copper wires

8 Semiconducting tapes

9 RWB tapes

10 HDPE sheath

11 Extruded fillers

12/14 Yarns

13 Armour GS

15 FO

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Table 8 – Electrical characteristics of IAC AC cables

These values are available from several cable suppliers which cannot be referred to due to confidentiality. Main suppliers at this moment are (known for 66kV):

• NKT, Germany • LS, South Korea • Prysmian, Italy • Hellenic, Greece • JDR, UK • TKF, Netherlands • Chinese suppliers upcoming

Next to the cables several related accessories are important which are sort of identical to EXC. The use of FJ is normally not needed and allowed (by clients) as the single lengths of cables are, with an exception, not so long that this is needed.

The standards / brochures that are related to these type of cables are mainly IEC 63026, TB623 and TB722 (and referred standards therein). These documents refer to construction, pre-qualification tests (PQ, only if a certain stress-level is passed), type tests (TT), routine tests (last test as FAT), sample tests and SAT, both for cables and their accessories.

6.2.3.2 Installation

The installation of IAC can be assessed as like the EXC except for lighter, smaller cables, shorter lengths and more pull-ins, stripping and terminations.

The installation on the OSS is nowadays more often with an inline joint already pre-installed at the cable deck.

6.2.3.3 Costs

6.2.3.3.1 CAPEX

The following table shows some costs that can be expected for different types of IAC. It should be mentioned that many 33kV-producing factories have reacted to 66kV as a small additional step (and therefore small price increase) which showed to be incorrect at the end. Therefore prices have, next

Cable characteristic Unit ALU 800m2 ALU 1200mm2 Nominal voltage betwen phases UN kV 66 66 Maximum voltage between phases UM kV 72.5 72.5 Maximum electrical stress at UN @conductor surface kV/mm 6.5 6.3 DC-resistance conductor 20 degrees Ohm/km 0.0367 0.0247 AC-resistance conductor 90 degrees @50Hz Ohm/km 0.0508 0.0371 Positive sequence impedance @50Hz Ohm/km 0.061 + 0.096j 0.048 + 0.092j Inductance of conductor mH/km 0.305 0.292 Capacitance per phase μF/km 0.384 0.4621 Total losses @ampacity W/m 108.1 115.3 Conductor losses W/m 3x29.2 3x28.8 Dielectric losses W/m 3x0.1 3x0.1 Metallic screen losses W/m 3x2.0 3x3.0 Armour losses W/m 14.3 19.6 Maximum short circuit current conductor (1s) kA 75.6 113.5 Maximum short circuit current metallic screen (1s) kA 3.4 3.9 Ampacity (DoB 2m / soil 15 degrees / soil 0.7Km/W) A 757 881

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to market prices, relatively grown. When this information is used, a large margin should be used for the same reasons as for the EXC (25%).

Prices for 132kV cables are not readably available as not in use at the moment. An estimate has been added based on prices for 66kV and 220kV cables. This should be confirmed later once it becomes more widely used as the product matures.

Voltage class [kV]

Cross section [mm2]

Conductor material [ALU/Cu]

Armour material [GS/SS/HDPE]

Volume Costs [€/m]

66 300 ALU GS MEDIUM 150 66 400 ALU GS HIGH 140 66 800 ALU GS HIGH 190 66 800 Cu GS HIGH 420 66 1200 Cu GS LOW 710

132 800 ALU GS MEDIUM 310 132 1200 Cu GS MEDIUM 750

Table 9 – Cost per meter of several IAC cables

The above prices do not include:

• engineering and if needed additional typetest or PQ_tests • termination and testing (T&T)

- termination can be quite a portion of all costs and do pose a risk (check: availability)

- testing can be quite expensive if a resonance test offshore is conducted

The installation costs of all cables are roughly the same (if the cable is larger/heavier the vessel needs to make more trips) and can be assessed for €200/m for the variable part with a margin of 20%. The mobilization and demobilization costs should be added including weather delay provisions which are very project specific. Further the Installation of IAC on the turbines/OSS require relatively an additional high additional CAPEX part compared to the EXC as the lengths of section are quite small (1.5km – 2.5km), on the other hand in general offshore joints are not considered for IAC.

6.2.3.3.2 OPEX

Reference is made to EXC.

6.2.3.4 Lifetime

Lifetime of type tested cables (especially the dry design) are considered to be 25-40 year. Formally the IEC-standards do not mention this and the first installed submarine cables have barely reached this lifetime.

6.2.3.5 Availability

The availability of IAC is depending on these same 4 major items as the EXC except one item is much more prominent: as the IAC normally have a 2 terminations per 2km (distance between 2 turbines), the EXC have a joint/termination per 40km. This makes the sensitivity for man-made terminations per km cable much higher.

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This is partly covered by the SAT (Site Acceptance Test) which stresses the cable according to IEC 63026 including the accessories. This is formally a resonance test until 3U0 per phase in the range of 10Hz - 500Hz, but this test, which is standard onshore, has only recently been developed. Oher options are VLF (Very Low Frequency) tests, normally on 0.1Hz, sinusoidal, square waved or a damped AC test. The reader should be awarethat the VLF and AC-damped tests do not conform to standards. Another test is the 24hr soak test, although this is not assessed as ‘tested’. A practical solution could be to agree with a supplier a VLF or damped AC test and use the soak test as the formal contractual milestone.

The above is not valid for the 132kV version of the IAC as the IEC 63026 ‘ends’ at 72.5kV. For that voltage level the IEC 60840 needs to be used. This would mean a resonance test between 20-300Hz of UN per phase or a soak test.

In reference 16 a value derived from there shows an average of 0.0045 failures/km/year.

6.2.3.6 Losses

Reference is made to EXC.

16 Failure Rates of Offshore Wind Transmission Systems. energies-12-02682

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6.3 Reactive Compensation

6.3.1 Technical information

The main aspect of the EXC (and the discussion of DC) is related to the reactive power that is induced by the power frequency with long cables.

Compensation of the reactive current can be applied in 3 ways, each resulting in a different reactive current profile (with an assumed EXC capacitance):

Figure 12 - Capacitive current AC EXC versus distance

• with one-sided compensation, at the onshore station, the Mvar current is high when reaching the beach (sometimes via a HDD). The effective current is the highest, resulting in the highest losses

• with symmetrical compensation it can be observed the Mvar current has been lowered to 50% on both ends

• with intermediate compensation this can even be further reduced

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A practical calculation can show the difference:

Table 10 - Example of available ampacity ([A] versus compensation)

The project Gemini in the Netherlands was built with a 110km long export cable on 220kV and a 2- sided symmetrical compensation. Of course, long AC-connections will also give other PQ-challenges to check / mitigate.

In practice the EXC can have smaller cross sections on locations where the overall current is the lowest. Which in return also lowers the capacitance hence the reactive current.

6.3.2 Costs

The CAPEX for reactors is assumed as follows (margin 20%):

Table 11 - CAPEX of compensation reactors

These values are based on a 50km EXC. The differences are based on the EXC voltage and the assumed capacitance per kilometer for the cable.

Of course intermediate compensation requires a complete additional offshore platform.

6.3.3 Losses AC versus DC

First it should be assessed that based on the required power, both the AC and DC options are technically feasible. When comparing the two options, the following items should be compared:

• the CAPEX of the AC and DC solution should be made available including the cables • the OPEX should be made available of both solutions • the losses during lifetime should be calculated and made actual by means of a NPV

calculation. This means the wind profile (and resulting EXC currents) should be made available, the interest rate and the future electricity price (or even lower subsidies)

It is not difficult to assess that the CAPEX and OPEX of the DC-option is normally substantially higher. So the gain will come from less losses.

Voltage 220 kV Capacitance 0.2 μF/km Ampacity cable 1000 A

Length [km]

1-sided [A]

2-sided [A]

Intermed. [A]

Capacitive current 50 399 200 100 Available MW current 50 917 980 995 Capacitive current 100 798 399 200 Available MW current 100 603 917 980 Capacitive current 200 1596 798 399 Available MW current 200 NA 603 917

Voltage class [kV]

Reactive power [Mvar]

Costs [k€]

220 76 1500 275 137 2500

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6.4 Onshore HVAC Land Stations

The AC-landstations function as the intermediate for the EXC arriving and the connection to the onshore TSO-grid. On this connection point the grid code of the TSO will apply. The function of this landstation is therefore:

• bring the voltage to the required grid voltage - a transformer could even be considered as to be able to cope with voltage variations

leading to higher losses in the EXC • connect compensation reactors (compensation of EXC) • have equipment installed to show grid compliance in respect to reactive power:

- add a reactor with OLTC - add reactor and capacitor banks to be switched - add a STATCOM in case fast voltage support is needed which cannot be supplied by

the turbines • have equipment installed to show grid compliance in respect to PQ (power quality):

- add a filter to limit the harmonic distortion to the allowed limits - add a filter to take care of TOV in case of energization or load rejections o take care of stable operation of the wind turbines, which is highly impacted by the

minimum short-circuit-ratio (MW-OWF/MVA-grid). It is considered this value should at least be 3 to be able to have a stable operational connection without the probable need for this additional equipment

The design of such a station is very depending on all functions that are required but a ball park figure for a 1000MW AC station including the above amounts up to 80M€ - 90M€. Depending on the size, the STATCOM (including transformer, bays, C&P) represents 30% of this CAPEX figure.

OPEX activities in general are the same as for OSS except the coating repairs. Be aware of the preventive cleaning of insulators in (marine) environments if the land station is located nearby the coast.

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7 DC TECHNOLOGY

7.1 Basic Components of DC Connections

The DC-technology is conceived as the next generation of connectors for longer distances / higher powers of OWF. A DC-link has already been in operation since 1954 by means of Line Commutated Converters (LCC-HVDC). As such this is a very mature technology used to transmit high power over long distances using grids overhead lines, submarine cables, back-to-back). Some specifics are:

• based on thyristor technology (thyristors only conduct current in one direction after gate signal, the current is transferred from one phase to another between thyristor valves). Thyristors can now even conduct 5000A as 8kV devices

• need for strong network connections (SCR > 3) or supporting systems • need to filter both on the AC and DC-side • absorption of reactive power (both as rectifier or inverter) • direction of power flow not easily changed and if so, the polarity of the cable conductor

changes • large footprint due to filters • losses: 0.6% - 0.8% per converter

Short Circuit Ratio (SCR) is here considered to be the MVA (LCC inverter) / MVA (Grid).

To have a smaller footprint (OSS platform) and to be able to connect to weak grids (OWF with wind turbines) the converter type used for the connection of OWF is the MM-VSC (Modular Multilevel Voltage Source Converters or MMC, Modular Multilevel Converters). Key specifics are::

• based on IGBT technology (based on modules, half bridge or full bridge that are put in series and can already include some ‘redundancy’)

• able to connect to weak grids (self-commutating) • the need for a filter to have the correct power quality to feed the grid will be minimal • able to control reactive power on each side of the connection • power flow easily changed (other direction current) • smaller footprint (30% - 50% reduction compared to LCC) • higher losses than LCC-HVDC: 1.0% per converter station

The key element of VSC is the use of power capacitors integrated with the converter modules. They function as an intermediate storage which realizes the balance between constant DC power flow and oscillating AC power flow. Values that are common are 3.3kV IGBT’s with 10mF capacitors. To arrive at for instance 320kV this would lead to more than 400 modules if 5 - 10% redundancy is included. Nowadays IGBT’s (ABB types, Mitsubishi types) conduct to around 2200A.

Examples of such a module is shown below where the half bridge is only capable of providing half the output voltage compared to the full bridge.

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Figure 13 – Output voltage levels depending on type of bridge

Figure 14 - Siemens HVDC Plus module

The overall system should be made robust for faults such as:

• internal faults as submodule faults, modulation & control faults and phase reactor fault • external faults as AC network faults at PCC, AC faults inside the converter station and DC-

faults, pole-to-pole and pole-to-ground.

The components and systems to mitigate these faults are rapidly developing and are considered differently by each of the 3 main suppliers:

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• discharging cable system • onshore DC choppers/dynamic breakers • inrush current limiting resistors • series pole reactor to limit peak/rise of currents and smoothen ripple/harmonics • phase reactor to suppress circulating currents due to imbalances in the converters and ability

to control active and reactive power flow • DC-breakers

Special attention should be given to the DC-breakers. There are available in the market and to a certain theoretical extent work (in all kind of hybrid solutions) but the missing current-zero moment (as with AC) hinders an easy extinguishing of the arc-flash. Also several suppliers as ABB and Mitsubishi are (further) developing the hybrid solution which uses mechanical switches, full electronic bridges and artificial current-zero moments by injection.

Until now the faults of a point-to-point DC-connection with VSC is cleared by opening AC-breakers. To have selective fault detection and clearing for meshed DC-grids, there is no real proven affordable solution yet available which hinders the meshed grid development.

7.1.1 SLD

Figure 15 - Simple HVDC single line diagram

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7.2 HVDC Offshore Substation

7.2.1 Description

The first large group of VSC OWF-connections has been pursued by Germany after the decisions to close all nuclear power plants. These connections, consisting of 8 platforms in total have power ranges of 576MW to 900MW, link voltages of 250kV – 320kV and have been provided by the 3 large suppliers (ABB, Siemens and GE/Alstom). It has been experienced that the commissioning and reliability of these ‘new’ technologies in the harsh marine environment including a constant ‘vibration’ as standing on a jacket is/was very challenging.

Figure 16 - DC offshore grid connection layouts17

The 3 main different setups can be derived from the figure:

1. Connection of an OSS platform (or more) to the DC-platform. This is the standard way of connections of the German OWF by TenneT Germany

2. Connection of the IAC directly to the DC-platform, of 1 OWF or more. This is making the OSS of the OWF superfluous. This is the new way of TenneT Holland to connect to IJmuiden Ver

3. Connection of IAC of more OWF to an offshore hub, which can be connected to multiple countries/markets

7.2.2 Technical information

The 5 main topologies that are used/proposed to build DC-connections with VSC are (also applicable to land connections):

1. Symmetrical monopole (figure a), this one is used in the TenneT Germany DC-platforms 2. Asymmetrical monopole: only 1 pole with a high voltage (positive or negative) with a metallic

return (figure b) 3. Asymmetrical monopole: only 1 pole with a high voltage (positive or negative) with no

metallic return (figure c) so making use of the ground electrode return, normally not allowed by the permit

17 https://guidehouse.com/-/media/www/site/downloads/energy/2019/2019-navigant-comparison-offshore-grid-development.pdf

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Figure 17 – Different topologies for monopoles

4. bipolar with a metallic return, this one will be chosen by TenneT Holland for 2GW 5. rigid bipole: no metallic return or ground electrode return, mostly not allowed by permit but

the current should be minimal if balanced poles

Figure 18 – Different topologies for bipoles

As alternatives also homopolar schemes are possible (so twice a negative or positive voltage).

In addition it can be reported there has been 1 project executed which has connected a LCC- converter station with a VSC-converter station.

The choices of which system would be the most appropriate is depending on the following:

• what is the amount of power that needs to be transported • what is the good balance between voltage (investment in converters) and cables (investment

in metal and insulation material) • what is the required availability: in case a bipolar system is chosen, the failure of 1 converter

will only lead to 50% power reduction (in case of a not allowed ground return, the cable of the faulty converter can be re-arranged as the metallic return)

• how are the losses calculated (power curve, wind-data) and evaluated (NPV, future electricity prices, interest rate etc.)

A general overview based on some high level calculations:

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Power [MW]

Topology [#]

Voltage [kV]

Current [A]

Cable Cu [mm2]

700 2 320 2188 2000 1000 1 320 1563 1000 1400 1 400 1750 1500 1750 4 400 2188 2000 2000 4 525 1905 1500 2100 4 525 2000 2000

Table 12 – Practical relation between power, voltage and cable type

It should be noted that this overview can change due to:

• other cable cross sections needed due to unfavorable installation circumstances • overall loss calculation shows the voltage level should be raised (lowering current and usage

of other type of DC-cable) as stated before

7.2.3 SLD

The SLD which is used by the German project is shown below.

As stated, the next generation to be constructed by TenneT NL is including the OWF platform functionality on the converter station platform.

Main thing will be that the transformation of IAC voltage to converter voltage is done in 1 step. Of course the requirements to these transformers, as being stressed both by AC as DC voltages, is more stringent than for the OWF main transformer.

Figure 19 – Standard setup for DC-connection for OWF

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7.2.4 Costs

7.2.4.1 CAPEX

Based on several sources (publicly available reports, project data) the following overview can be derived. It should be noted that these kind of prices are depending heavily on the pipeline (amount of projects) of the main HVDC suppliers, HV suppliers and the metal prices (OSS and jacket). It should be mentioned the HVDC market is a sellers market due to a limited amount of suppliers. Further the suppliers / buyers of the several existing projects are not open to disclose information in respect of costs.

The first table shows the estimates (±25%) for a DC-platform (as per TenneT Germany) with separate OWF-platforms and the second table shows the estimation if the functionality is combined (as per TenneT NL). In both table the HV-related components are priced separately.

Power [MW]

HV Offshore

[M€]

ACDC Platform

[M€]

Total [M€]

k€/MW

700 70 450 520 743 1000 150 490 640 640 1400 200 570 770 550 1750 250 650 900 514 2000 300 730 1030 515 2100 315 750 1065 507

Table 13 - CAPEX of HVDC OSS

Where the data was not available, intelligent extrapolation has been made between the different power sections. A bipole HVDC equipment is considered 35% more expensive than a monopole (700MW). As the system grows in power, the related platform size grows as the weight and amount of steel.

7.2.4.2 OPEX

The OPEX of DC-stations is considered to be roughly based on a percentage of the CAPEX.

Power [MW]

Total ACDC [M€]

OPEX [%]

Total [M€]

k€/MW/ year

700 520 1.5 7.8 11.1 1000 640 1.5 9.6 9.6 1400 770 1.5 11.6 8.3 1750 900 1.5 13.5 7.7 2000 1030 1.5 15.5 7.7 2100 1065 1.5 16.0 7.6

Table 14 - OPEX of DC-platforms

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Activities are based as for the AC-substations and include:

• maintenance HVMV equipment (inspections & functional specs) • maintenance LV equipment ((inspections & functional specs) • maintenance AUX equipment ((inspections & functional specs) • coating repair • C&P: rolling testing in time of all relays by injection • cleaning: removing of guano

Corrective maintenance is expected on AUX-systems (more complex than AC OSS, for instance water cooled systems) but also on converter systems (IGBT’s, although they have some built-in redundancy) and could we require 24-36 interventions/year.

7.2.5 Lifetime

The expected lifetime of the system is 25 years and it should be capable of ‘surviving’ the OWF/turbines that are connected to the OSS. This can vary depending on each countries regulatory and legal frameworks as well as the wind farm lease lengths. However an extension to wind farm operating life can be requested as long as proper/expensive preventive maintenance and lifetime extension analysis is carried out. TenneT is designing platforms with an expected life of 30 years. HVDC offshore platforms have only been installed recently (since 2015) so there is much to learn about the reliability of the technology in harsh marine conditions.

7.2.6 Availability

As already stated before, the availability of the system can be improved in several ways:

• have a metallic return for a bipole such that if one pole is malfunctioning / in maintenance there is still 50% power flow possible

• add a certain percentage additional modules in the converters arms. The system is setup such, that if one fails, a short circuit is made and the other available IGBT-modules can take over

• have spare IGBT-modules available, in case of failure they can be replaced in 2-4hrs (depending on access on the topside).

Numbers are not yet available based on a large database, CIGRE TB713 did a simulation based on a fictitious grid and came up with a forced outage of 2.2% for a bipole converter (including 200km cable).

The input consisted of:

• symmetrical monopole: λ = 0.0153 failures / year MTTR: 1664h • bipoles: λ = 0.0153 failures / year /pole MTTR: 1664h

MTTF (Mean Time To Failure) = 8760/ λ

Which results in a technical availability of A = MTTF / (MTTF + MTTR)

• symmetrical monopole: MTTF = 572549 A = 99.71% • bipoles (per pole): MTTF = 572549 A = 99.71%

Downtime due to preventive maintenance should be minimal for bipoles if this can be done in low wind periods (as then the system can be operated for 50% of transport power. Loss of availability due to monopole maintenance is not available.

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7.2.7 Losses

Losses are derived from the general data which should be evaluated for different currents.

Let us assume:

• 1000MW bipolar system • ±320kV • 100km 1400mm2 ALU cable (Rdc20 = 0.0129Ohm/km, Rdc70 = 0.0154Ohm/km): • no-load losses passive components and IGBT (switching losses): 0.05% * Pnmon • load losses IGBT (conducting losses, related to I^2): 0.62% * Pnmon • average losses passive components: 0.33 * Pnmon

Power [MW]

Current [A]

Rdc [Ohm]

Losses 2xHVDC

[kW]

Losses Cable [kW]

Total Losses [kW]

Total Losses

[%] 0 0 1.29 7600 0 7600 0.8%

250 391 1.34 8375 409 8784 0.9% 500 781 1.39 10700 1697 12397 1.2% 750 1172 1.48 14575 4065 18640 1.9%

1000 1563 1.54 20000 7520 27520 2.8%

Table 15 - Losses of 1000MW DC system

7.2.8 DC Offshore Substation in Meshed Grids

As already stated in 7.1 the meshed grids, more specific the multi-terminal DC (MTDC), are seen as the way forward but are not executed on a large scale yet, partly due to the absence of proper protection schemes to have more selective mitigations.

The simplest version if the parallel set-up, where all HVDC converters are connected to the same DC- cables and ‘do their thing’, either consuming or generating power. The most complex is the meshed grid where units are set in series (so adding up in voltage) and set in parallel (same voltage).

Special grid control strategies as LF-control, master voltage control, current-voltage control, voltage- power control etc. should be derived to operate in combination with sophisticated fault detections.

In theory the values as given for DC OSS are applicable but need to be increased with:

• double connection of DC cables • installation of DC-breakers • more complex control of power, voltage and current • fault detection and protection measures

The fault detection will consist of direct measurements (as distance, differential and over current) and signal processing methods (travelling wave, voltage derivative, frequency based) which will activate the needed fault-mitigation.

ABB has provided a general overview of protection systems for their HVDC-Light:

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Figure 20 – Different protection systems as proposed by ABB for HVDC-Light

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7.3 HVDC Land Station

7.3.1 Description

The DC-land station in principle mirrors the OSS HVDC setup (only from DC to AC) except the connection to the onshore grid should be done at the correct local voltage level and quality.

The AC-switch yard is considered to be a standard setup (AIS, GIS) and filters are considered to be minimal with VSC due to the multi-level system.

The type of grid transformers should be assessed based on the power. For large powers (>1500MW) single phase units are considered more realistic.

7.3.2 Costs

7.3.2.1 CAPEX

The CAPEX is based on the HVMV component prices of the offshore substations but a bit lower for due to easier access and building freedom. Added to that are the civil works that include also all other supporting systems (LV, HVAC, building-systems etc.). Margin is expected to be 20%.

Power [MW]

ACDC Onshore

[M€]

Civil [M€]

Total [M€]

k€/MW

700 50 20 70 100 1000 120 30 150 150 1400 160 35 195 139 1750 205 40 245 140 2000 250 45 295 148 2100 262.5 45 308 146

Table 16 - CAPEX of HVDC land station

7.3.2.2 OPEX

Power [MW]

Total ACDC [M€]

OPEX [%]

Total [M€]

k€/MW/ year

700 70 1.5 1.1 1.5 1000 150 1.5 2.3 2.3 1400 195 1.5 2.9 2.1 1750 245 1.5 3.7 2.1 2000 295 1.5 4.4 2.2 2100 307.5 1.5 4.6 2.2

Table 17 - OPEX of HVDC land station

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7.3.3 Lifetime

Reference is made to offshore although the land conditions shall be favorable in relation to the marine conditions so preservation shall be longer.

7.3.4 Availability

Reference is made to offshore.

OPEX activities in general are the same as for OSS except the coating repairs. Be aware of the preventive cleaning of insulators in (marine) environments if the land station is located nearby the coast.

7.4 HVDC Cables

7.4.1 Description

To connect DC-stations, DC cables are required. In general there are 2 types:

7.4.1.1 Mass impregnated cables (MI)

Mass impregnated insulation consists of layers of Kraft paper which are heated, subjected to vacuum and impregnated with high viscosity oil over several weeks. The technology is very mature and has been employed since the 1950s for HVDC applications. A survey conducted by Cigré Working group B1.21 revealed over 15,000km of HVDC Mass Impregnated cable cumulatively installed amongst its respondents prior to 2005. Mass impregnated paper is not used for HVAC applications due to problems with partial discharge. This is not an issue for HVDC cables due to the lack of rapid polarity reversal.

7.4.1.2 Extruded XLPE cable (XLPE)

The first real utility scale HVDC cable to be installed using extruded XLPE as an insulation medium was the Cross Sound Cable installed in 2002 between Connecticut and Long Island in the northeast USA, operating at ±150kV and capable of transporting 330MW.

XLPE cables have several advantages over Mass Impregnated which is the reason why they are dominating the market now for VSC types of converters. In the case of land applications, XLPE cables are lighter which allows longer transportation lengths and therewith longer distances between joints. XLPE land cables are also quicker to manufacture. In essence they are like HVAC cables (see other chapter on build-up of these cables) with the following other process steps:

• higher XLPE base material cleanliness • a longer degassing period on less high temperatures

For long distance submarine cable, factory joints are necessary. Here the distance between joints would be longer than for Mass Impregnated cables. XLPE is generally more mechanically robust and they may operate at higher temperatures (70⁰) than Mass Impregnated cables allowing them to carry more current for a given conductor cross section. For this last reason XLPE cables are often used with aluminium conductors to reduce the weight and cost of the cables (although copper conductor is still common for submarine applications). For land applications, pre-moulded joints are available, reducing the time required for cable jointing, making this technology attractive.

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XLPE cables cannot presently be used with current source converters (CSC); the reason for this is outlined below. XLPE cables suffer from a space charge phenomenon (which can be triggered also with higher temperatures, hence a HVDC-XLPE conductor may rise to 70⁰ as opposed to HVAC-XLPE to 90⁰). After being subjected to a constant electric field for a protracted period of time, as in HVDC applications, the insulation becomes polarized and this can lead to breakdown and failure should the polarity of the field be reversed. This renders currently available XLPE cables unsuitable for use in current source HVDC installations where in order to reverse the direction of power flow the polarity must be reversed. Hence XLPE cables can presently only be used in voltage source installations (or ‘oversized’ cables can be used on a lower voltage).

Figure 21 – Typical setup HVDC cables18

Figure 21 shows the drawing of an XLPE submarine HVDC cable and a deep sea HVDC cable. The last one having 2 armor layers.

On HVDC cables a next generation is being developed, namely the cable based on Polypropylene (PP). This cable type does not require cross-linking like XLPE hence referred to as much more environment friendly (as it can be recycled and used for other applications), although on XLPE recycling is mentioned through pyrolyse (TKF).

Prysmian claims to be able to supply an improved solution (P-Laser type) of this High Performance Thermoplastic Elastomer (HPTE) which is allowing the conductor to heat until 90⁰ and allows voltage reversal. It can also make used of the existing XLPE-accessories and does not need degassing. In essence they have further improved the PP-base material (by very fine filtration just before the extrusion heads) to avoid by-products.

18 As per most HVDC cable suppliers

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Figure 22 - Prysmian overview of PP cable capabilities versus XLPE

7.4.2 Technical Information

The XLPE HVDC cables can be found/made in all voltage classes, from 150kV until nowadays 525kV.

As per the positive aspects of the XLPE cable as described before (see 7.4.1) this cable type is expected to support whichever future HVDC application levels are required. As such all information is only considering XLPE-extruded cable types.

As DC-systems are missing the capacitive current and the skin effect, the ampacity of transported energy is much higher than with long HVAC cables.

General data for a Cu 2500mm2 cable as reference:

• Rconductor = 0.0073Ohm/km, this can be used for losses calculations (conductor temperature is allowed to rise until 70⁰)

• Rsheath = 0.23Ohm/km, Rjacket = 0.1Ohm/km - these values are important for the 1 phase short circuit - the cable needs to be grounded every 5km - 10km (sheath and jacket connected) as

to limit the voltage on the sheath - submarine cables will have an interconnection between armour and sheath each

5km made in the factory

Further technical cable data:

Table 18 - Electrical specifications of some HVDC cables

Main suppliers at this moment are:

• NKT, Germany • LS, South Korea • Prysmian, Italy • Hellenic, Greece

Cable characteristic Unit ALU 800m2 ALU 1400mm2 ALU 1200m2 ALU 2500mm2 Cu 2500mm2 Nominal voltage kV ±200 ±200 ±320 ±320 ±400 DC-resistance conductor 20 degrees Ohm/km 0.0221 0.0129 0.0151 0.0073 DC-resistance conductor 70 degrees Ohm/km 0.0264 0.0154 0.0181 0.0087 0.0073 Maximum short circuit current conductor (1s) kA 92 161 138 287 Maximum short circuit current metallic screen (1s) kA 16.6 22 29.9 40 Ampacity (DoB 2m / soil 15 degrees / soil 0.7Km/W) A 1105 1505 1336 2030

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• Nexans, Sweden • Chinese suppliers upcoming (ZZT)

7.4.3 Installation

The installation of HVDC cables can be done in several ways if the known topology has been chosen.

Table 19 - Installation configurations of HVDC cables

Some considerations:

• to have the two current conducting paths bundled, will give the lowest ecological footprint (spatial, magnetic field) but is impacting negatively the ampacity as the cables heat up (each other)

• bundles of 2 cables is not ‘round’ and less easy to process, so adding the (single) metallic return is beneficial

• split laying of 2 HVDC cores (including a metallic return path per core) is giving the highest availability and possibility to repair when the second circuit is still functioning

Further reference is made to the installation of HVAC cables.

7.4.4 Costs

7.4.4.1 CAPEX

As the market is reluctant to supply information (except for projects), the data available is minimal. Table 19 shows the variable price per meter with a very large margin (-10% - +30%):

Voltage class [kV]

Cross section [mm2]

Conductor material [ALU/Cu]

Armour Volume Costs [€/m]

320 1800 Cu GS/Single MEDIUM 395 400 1600 Cu GS/Single MEDIUM 375 400 2500 Cu GS/Single MEDIUM 615

Table 20 - Costs for several HVDC cables

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The prices in Table 19 do not include:

• engineering and if needed additional type test or PQ tests • fixed (starting) costs for supply • installation of offshore joints / transition joints (high costs due to vessel availability) • termination and testing (T&T)

Further reference is made to HVAC EXC.

7.4.4.2 OPEX

Reference is made to EXC.

7.4.5 Lifetime

Just as HVAC cables, the PQ-testing of HVDC cables according to the TB852 (and included references) should be the guarantee for a long lifetime of XLPE HVDC cables. The fault conditions and heating cycles should reflect a lifetime of 30 years.

7.4.6 Availability

Numbers are not yet available based on a large database, CIGRE TB713 did a simulation based on a fictitious grid and came up with a forced outage of 2.2% for a bipole converter (including 200km cable).

The input consisted of:

• cable ±200kV or ±400kV: λ = 0.0007 failures / year / km MTTR: 1440h

MTTF (Mean Time To Failure) = 8760/ λ

Which results in a technical availability of A = MTTF / (MTTF + MTTR)

• cable ±200kV or ±400kV: MTTF = 62571 A = 97.75%

7.4.7 Losses

Losses of cables is easy to derive from the DC-resistance calculation. One could assume different DC- resistances with different power flows (between 20⁰ and 70⁰). Be aware that 2 cables are carrying current. See further 7.2.7.

On top of this additional losses can be expected caused by the ripple current (resulting in induced current in the sheath) and ripple voltage (resulting in a charging current from core to sheath). This will require a correct sheath bonding scheme as per 7.4.2 to be minimised.

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8 DECOMMISSIONING During the project development stage of an offshore wind farm the plan for how to decommission a wind farm is usually required as part of the permit application. Depending on the technology used there are various options and marine users, environment, pollution, and costs should all be considered. Most of the structures that are not buried can be easily removed by dismantling or cutting just below the seabed mudline. Once removed they are transported to shore and can be processed and recycled accordingly. The parts of the foundations that are below the seabed cannot be removed without disturbing the seabed and surrounding environment. This process can become expensive and risky depending on how far below the mudline you want to go. If it does not pose an environmental or pollution risk, it is usually left.

Cables will be partially or fully removed but this depends whether the cable is buried on not. Buried cables do not pose a risk to marine users and have limited environmental or pollution impacts although this can depend on the cable technology adopted. The complete removal is considered to cause substantial damage and disruption to the seabed given the extensive length of the cables. There would be need for excavation to pull them out of the trench, and then cutting, which involve high costs. Leaving the cables in situ and well buried is therefore the best option suggested till date.19

19 https://www.researchgate.net/publication/309654822_Sustainable_Decommissioning_of_an_Offshore_Wind_Farm

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9 EXAMPLE GRID CONNECTION In this section we compare each high voltage technology to get a better understanding of their strengths and weaknesses. For comparison purposes a specific connection will be assessed for both technologies. This will be a top-level comparison using the information already discussed as well as making some assumptions.

To have an overview of both presented technologies (AC and DC), Table 20 shows a list of the high- level pro’s and con’s.

AC-technology DC-technology (VSC)

Pro’s - many vendors of equipment / many engineering firms - very mature technology (lifetime phase: lowering costs) - experience on onshore grids available with TSO’s - intermediate compensation can extend distances - all phenomena and their mitigations are known - high robustness / availability

- low(er) losses above a certain transport level and distance - high level of grid supporting reactive power - availability can be improved by redundant IGBT set-up or chosen topology - very modular so transport power can increase with same technology

Con’s - over long distances less available ampacity / high losses due to capacitive currents - skin effect having low gain in higher cross sections of cables

- only 3 major vendors of equipment - in general high(er) costs/MW (CAPEX) - technology still improving (lifetime phase: higher robustness/ improving components) - due to sensitive devices (IGBT) lower robustness / lower availability (higher OPEX)

Table 21 – Pro’s and Con’s of AC and DC

For comparison purposes a specific connection will be assessed for both technologies.

General information:

• transport power: 1000MW (PMAX) • distance from onshore land station: 50km • seabed temperature: 10⁰C • depth of burial (DoB) of EXC: 2m • frequency: 50Hz • IAC not considered as equal for both • Mvar requirement: cos phi = 0.95 (Q = 0.33pu Pmax), can be supplied by onshore

components or turbines (not considered in losses or ampacity calculations)

AC:

• 220kV • 1000MW leading to 2624A • symmetrical compensation (assuming cable capacitance is 0.2μF/km): 400A/cable and

152Mvar (76Mvar reactor on each side) • total 962A leading to 3 HVAC cables of 1200ALU SS (50%) and 1200 ALU GS (50%) • 3 separate small OSS with one transformer per OSS (no redundancy) • land station without STATCOM

DC

• bipole arrangement • ±320kV • 1000MW / 320kV / 2 = 1562A, leading to 2 HVDC 1400mm2 Cu XLPE cables

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• for comparison the AC collection system is included in the OSS

Below a comparison of the two options where it must be noted the losses are quite high and include cables and both onshore and offshore substations:

OSS [M€]

EXC proc. [M€]

EXC inst. [M€]

ONSS [M€]

Total [M€]

OPEX/y [k€]

Losses 100% P [%]

AC 214 71.6 35 60 381 2744 3.1 DC 640 39.5 25 150 855 7900 2.8

Table 22 – Comparison of several parameters for AC and DC of 1000MW

In general it is stated that above 1GW and more than 100km the DC option would be preferred, as this should also consider the difference in losses during lifetime when corrected for the different power bins (wind profile) of the OWF. This business case can although be challenged with intermediate compensation platforms and hence a project specific assessment should always be carried out each time.

Table 22 shows the TRL’s for the HV technology described in this report. AC technology up to now has been widely adopted in the offshore wind market and is therefore a mature technology scoring nine in all cases. DC technology for offshore wind farms exists but it is still a maturing market. As more wind farms are built further away from shore and interconnectors become more common, so will the technology mature and price decrease.

Equipment Solution TRL

Offshore substation

HVAC 9

DC – VSC (all poles) 8

Meshed DC – VSC (all poles) 6

Land station HVAC 9

DC – LCC 9

DC – VSC (all poles) 8

Export cables

AC - XLPE 9

DC – Mass impregnated 9

DC – XLPE 9

DC – PP 6

Table 23 - Different TRL of related solutions

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10 ANNEXES

10.1 Technology Readiness Level

Table 23 describes the technology readiness level scale. This catalogue has focussed on technology with a level of 5 or greater.

Table 24 - Different Technology Readiness Levels20

10.2 Raw Material Costs

In this section we will briefly state the main raw materials that are used in the construction of an offshore wind farm. Prices for these material can heavily influence the final price of certain products. Typically suppliers will include clauses in the procurement contract that allow the final price to be subjective to current raw material prices.

Steel

The substation, foundations, WTG tower section and cables all use steel as a primary material. Steel prices have seen a sharp increase over the last year, seeing 5 year highs in May and close again in October 2021. As an example the Hollandse Kust Noord (759MW) platform jacket foundation weighs 2100 tonnes. On a platform a 400MW transformer can weigh 92 tonnes (tank, radiator & pipes). These examples give a good indication of the amount of steel that is required during an offshore wind project.

Copper

All electrical components will use copper due to its conductive properties. The WTG generator especially direct drive types, platform transformers (42t for 400MW) and inter array and export cables all rely heavily on the material. Export cable lengths can go from near shore 5km up to hundreds of km’s in distance for interconnectors between different platforms and countries. Copper saw the same sharp increases as steel and continues high.

20 HORIZON 2020 – WORK PROGRAMME 2014-2015

Project no.: 2021_0067

Employer: AS Augstsprieguma tikls

Elering AS

Consultant Skepast&Puhkim OÜ

Laki põik 2, 12915 Tallinn

Telefon: +372 664 5808; e-post: [email protected]

Registrikood: 11255795;

Date 17.12.2021

RIGHT-OF-WAY STUDIES ON THE

MAIN LAND ROUTE CORRIDORS

Final report

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Version 3

Date 17.12.2021

Authors: Anni Konsap, Kati Kraavi, Sander Lõuk, Raivo Damkevics

Photo credits: Sven Zacek

Project no. 2021_0067

SKEPAST&PUHKIM OÜ

Laki põik 2

12915 Tallinn

Registrikood 11255795

tel +372 664 5808

e-mail [email protected]

www.skpk.ee

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Contents

Introduction ..................................................................................................................... 4

1. Description of the methodology .................................................................................... 5

2. Route description ......................................................................................................... 7

2.1. Criteria for route description ........................................................................................... 7

2.2. Route descriptions ........................................................................................................ 8

2.2.1. Possible routes from Lihula substation .......................................................................... 8

2.2.2. Possible routes from Sindi substation .......................................................................... 10

2.2.3. Possible routes from Kilingi-Nõmme substation ............................................................ 11

2.2.4. Possible routes from Aloja substation .......................................................................... 12

2.2.5. Possible routes from Tume substation ......................................................................... 13

2.2.6. Possible routes from Dundaga substation .................................................................... 14

2.2.7. Possible routes from Ventspils substation .................................................................... 16

2.2.8. Possible routes from Uzava substation ........................................................................ 17

3. Criteria for route comparison ..................................................................................... 19

4. Comparison of alternatives for route corridors ........................................................... 22

4.1. Presentation of results ................................................................................................. 22

5. Comparison of alternatives for mainland route corridors ............................................ 23

5.1. Corridor alternatives from Aloja substation ..................................................................... 23

5.1.1. Technical criteria ...................................................................................................... 24

5.1.2. Environmental criteria ............................................................................................... 25

5.1.3. Socioeconomic criteria .............................................................................................. 27

5.1.4. Preferred corridor alternative for Aloja substation ......................................................... 27

5.2. Corridor alternatives from Dundaga substation ............................................................... 28

5.2.1. Technical criteria ...................................................................................................... 28

5.2.2. Environmental criteria ............................................................................................... 29

5.2.3. Socioeconomic criteria .............................................................................................. 30

5.2.4. Preferred corridor alternative for Dundaga substation ................................................... 31

5.3. Corridor alternatives from Tume substation .................................................................... 32

5.3.1. Technical criteria ...................................................................................................... 32

5.3.2. Environmental criteria ............................................................................................... 33

5.3.3. Socioeconomic criteria .............................................................................................. 34

5.3.4. Preferred corridor alternative for Tume substation ........................................................ 34

5.4. Corridor alternatives from Uzava substation ................................................................... 35

5.4.1. Technical criteria ...................................................................................................... 37

5.4.2. Environmental criteria ............................................................................................... 38

5.4.3. Socioeconomic criteria .............................................................................................. 39

5.4.4. Preferred corridor alternative for Uzava substation ....................................................... 40

5.5. Corridor alternatives from Ventspils substation ............................................................... 41

5.5.1. Technical criteria ...................................................................................................... 41

5.5.2. Environmental criteria ............................................................................................... 43

5.5.3. Socioeconomic criteria .............................................................................................. 43

5.5.4. Preferred corridor alternative for Ventspils substation ................................................... 43

5.6. Corridor alternatives from Lihula substation ................................................................... 45

5.6.1. Technical criteria ...................................................................................................... 45

5.6.2. Environmental criteria ............................................................................................... 45

5.6.3. Socioeconomic criteria .............................................................................................. 45

5.6.4. Preferred corridor alternative for Lihula substation ....................................................... 45

5.7. Corridor alternatives from Sindi substation ..................................................................... 45

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5.7.1. Technical criteria ...................................................................................................... 45

5.7.2. Environmental criteria ............................................................................................... 45

5.7.3. Socioeconomic criteria .............................................................................................. 45

5.7.4. Preferred corridor alternative for Sindi substation ......................................................... 45

5.8. Corridor alternatives from Kilingi-Nõmme substation ....................................................... 45

5.8.1. Technical criteria ...................................................................................................... 45

5.8.2. Environmental criteria ............................................................................................... 45

5.8.3. Socioeconomic criteria .............................................................................................. 45

5.8.4. Preferred corridor alternative for Kilingi-Nõmme substation ........................................... 45

6. Analyses of the most suitable spatial planning and impact assessment procedure for

planning the route .......................................................................................................... 46

6.1. Latvia ........................................................................................................................ 46

6.2. Estonia ...................................................................................................................... 47

Annexes

Annex 1. Online application with spatial data:

https://gis.skpk.ee/portal/apps/MapSeries/index.html?appid=e55f17b56ac74c38a68702

31f9238bd4 (version dated 17.12.2021)

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Introduction

This report gives an overview of the work to be done to determine the main land route corridors of

the electricity transmission grid from Lihula, Sindi and Kilingi-Nõmme substations in Estonia and from

Ventspils, Dundaga, Tume, Užava and Aloja substations in Latvia toward the Baltic Sea and an

overview of the initial corridor descriptions. This report is the final report for right-of-way studies on

the main land route corridors and presents designing of alternatives for corridors based on the

methodology, analysis to identify the most appropriate route corridors based on data available from

public sources, presents options for preferred corridors based on comparative criteria and gives

recommendations for future processes.

The final alternatives of the route corridors and their suitability must be specified during public

procedure within an inclusive (planning) process and a preparation of a detailed impact assessment.

During this, data used (eg areas with building design conditions, land use, etc.) during the initial

analyses must be updated so that the final conclusions drawn are appropriate and applicable.

An integral part of this analysis is an online application with spatial data and the results of the

analyses.

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1. Description of the methodology

The following methodology gives an overview of the work to be done to determine the main land

route corridors of the electricity transmission grid in Estonia from Lihula, Sindi, Kilingi-Nõmme and

in Latvia from Ventspils, Dundaga, Tume, Užava and Aloja substations toward the Baltic Sea. The

aim of the transmission grid is to create necessary preconditions for an offshore wind park to be

planned in close cooperation of Estonia and Latvia.

Figure 1. Substations of Latvia and Estonia and area of interest for possible route

corridors.

In the course of the work, it is necessary to describe possible alternatives for the route corridors (see

paragraph 2), assess their initial suitability and create a preference for the most suitable route

corridor. Among other things, the transition points of the underground cable to the overhead cable

(coming from sea to land) must be defined.

The width of the corridor to be sketched and analysed is 120 meters. The width consists of the

protection zone of the high voltage line, which is 40 meters on both sides of the route axis (see

Figure 2) and a buffer zone of 20 meters on both sides of the protection zone, giving the necessary

room for adjusting the corridor in the next steps of the planning process.

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Figure 2. Description of route corridor with protection and buffer zones.

Exclusion method is used to describe possible route corridors - exclusion of unsuitable areas based

on agreed criteria (see Chapter 1.1.). This results in areas where potential corridors could be located.

Within these areas, route corridors are outlined, which then are compared based on qualitative and

quantitative criteria (see Chapter 1.2.).

As a result of the comparison of route corridors, preferences regarding route corridors are formed.

As a result of the work, the preference for the most suitable route corridor location is presented from

each substation, which needs to be supplemented and specified in the subsequent planning and

impact assessment process.

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2. Route description

2.1. Criteria for route description

The following selection criteria were used as the exclusion method for sketching the corridors:

• No residential or public buildings within the corridor and 100 meters from the edge of the

corridor.

• No auxiliary and industrial buildings within the corridor.

• The route corridor must not pass through a densely populated area.

The criteria may be specified as a result of further drafting of the corridors. If no other

alternatives can be outlined or the densely populated area proves to be the most appropriate,

the possibility of constructing an underground cable through the densely populated area should

be considered.

• The route corridor must not pass through mining allocations.

• The route corridor must not pass through cemeteries.

• The route corridor must not pass through milieu areas.

The criteria may be specified as a result of further drafting of the corridors. If no other

alternatives can be outlined or the milieu area proves to be the most appropriate, the possibility

of constructing an underground cable through the milieu area should be considered.

• No cultural monuments and their protection zones within the corridor.

• No churches and shrines within the corridor.

• The corridor must not overlap with habitats of species in protection categories I and II.

In Natura bird areas and at a distance of 100 meters from them, the underground cable corridor is

considered as a route corridor. The route corridors shown in this work, which pass through (incl. as

an underground cable) or are adjacent to Natura sites, must be assessed in the next stages of the

impact assessment of the route corridor. Based on this, it may be necessary to shift the route

corridors, relocate or take other necessary measures.

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2.2. Route descriptions

2.2.1. Possible routes from Lihula substation

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Name Description

Lihula-L3-1 Line can be placed inside existing 110 kv line corridor in the Lihula part of the corridor but the existing corridor is not wide enough for 330 kv corridor and it is situated in the protection zone of residential buildings

Lihula-L3-2 Ca 2 km of the line corridor can be placed inside the existing 110 kV line corridor. Corner posts can be placed nead existing roads and on state owned/municipal land.

L3-Pivarootsi Line corridor is very close to and runs parallel to Natura 2000 bird area.

Cable-Pivarootsi Transmission can be built near existing road, 250m from coastline and from Natura 2000 area

L3-Nõmme Corner posts can be built near existing road.

Cable-Nõmme Transmission can be built near the existing road.

Lihula-Kulli 65 km can be placed inside existing 330 kV overhead line corridor. Corridor is situated between 2 Natura 2000 bird areas

Cable-Kulli 1 One of the ways to go underground in the Kulli control point

Cable-Kulli 2 One of the ways to go underground in the Kulli control point

Cable-Kulli 3 One of the ways to go underground in the Kulli control point

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2.2.2. Possible routes from Sindi substation

Name Description

Pärnu-P1.1 Line corridor is as straight as possible but crosses existing 100 kV line corridor and 5 km of the corridor will be placed within an active mining area.

Pärnu-P1.2 One of the alternatives for crossing a mining area. Line crosses existing 110 kV electrical line many times. Line corridor avoids residential building protection zones, but the impact to the airport landing zone must be evaluated.

P1-P2 This part of a line corridor is avoiding residential building protection zones as much as possible, line corridor is crossing existing 110 kV electrical line