Low Carbon Ferries Feasibility Study

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LOW CARBON FERRIES FEASIBILITY STUDY

Part 2 Analysis

Report to Orkney Islands Council

Issued by Aquatera Ltd

P732 – April 2016

Funded by:

Acknowledgements:

(Captain) Willie Mackay

This study was completed for:

Orkney Islands Council Marine Services Harbour Authority Building Scapa Orkney KW15 1SD

Contact: David Hibbert Technical Superintendent, Development & Infrastructure Tel: 01856 873636 Ext 3623 Email: [email protected]

This study was completed by:

Aquatera Ltd Old Academy Business Centre Stromness Orkney KW16 3AW

Contact: Ian Johnstone Tel: 01856 850 088 Email: [email protected]

Issue record The version number is indicated on the front cover.

Version Date Details

V1 16 Feb Part 1 draft 2016

V2 04 Apr 2016 Part 2 analysis draft

Members of:

Executive Summary

The scope of the report was to investigate how the current inter-island routes could be serviced by ferries powered from alternative fuels. Within the report:

 The possible fuel alternatives were to be determined;

 The routes have been assessed on their applicability to the possible fuels;

 An understanding was gained on the possible impact upon the local grid; and

 The details of what changes would be required to the current service were discussed and evaluated, in relation to alternative fuel options.

Due to the age of the current vessels operating the routes, retrofitting was not considered as a viable option and any alternatives to the current fleet would be new vessels.

The work included the compilation of case studies of vessels deriving power from alternative fuels which includes LNG, CNG, hydrogen, full-electric, liquid nitrogen, biofuels, compressed air, ammonia, nuclear, wind and wave. The report also considers hybrid propulsion systems using a mix of fuel sources. The possible scenarios of continuing to use diesel were also considered for comparative purposes. The compiled case studies have been dispersed throughout the report to provide real world examples in the discussion of possible alternatives to the current fleet.

Following the investigation into real world examples was the characterisation of the current fleet and onshore infrastructure. This was completed in order to understand the requirements that alternative fuels would need to meet in order to match service expectations. A discussion into the fuel options and the methods of utilising them in comparison with the current route services fed into the first screening process.

An initial screening process was conducted in order to remove the technologies that were not currently feasible.

The method used for the initial screening was to rate the previously mentioned fuels against five categories:

 Time to market;

 Overall cost;

 Regulatory compliance;

 Suitability of technology; and

 Availability of infrastructure.

Through this screening each of the five categories were deemed to have equal importance and thus no weighting was added to any of them. The figure below illustrates the results of this screening process; the columns in red on the left corresponding to the fuels and technologies deemed to be unsuitable for investigating

further, and the remaining green columns on the right indicating the fuel and technologies that were put forward to secondary screening.

Figure 1 Initial Screening Results

For the remaining ten propulsion methods, further screening provided a means of prioritising their implementation within the Orkney Ferries fleet. Unlike the initial screening process, weightings were agreed upon, during a workshop with OIC stakeholders, and applied in order to provide an indication of the importance of particular categories in comparison to others. The weighting ranged from one for little/no importance to five for very important. The categories in which they were ranked against, and their agreed weightings were:

Table 1 Secondary Screening Weightings Scoring Category Weighting Risk 5 Ability to deliver energy requirement for route(s) 5 Infrastructure requirements 3 Operational cost 3 Required energy input relative to propulsion output (efficiency) 2 Robustness and flexibility of the service 2 Impact on curtailed energy 1 Local content – opportunities for local business and employment 1 Impact on emissions 1

The scorings were made per route level to avoid dropping technologies which may suit short distances rather than long ones. (level 1 being short routes – Graemsay and Papa Westray, level 2 medium routes – Shapinsay, Rousay and Houton, and level 3 long routes – North Isles). Using the weights described previously for each criterion,

the results were as shown in Figure 2 („alternative fuel electric hybrids‟ correspond to all electric hybrids but diesel).

Figure 2 Weighted scores for the secondary screening per technology and route levels. The grey line indicates the minimal threshold required for the fuel system to go through analysis.

Based on the results from the second screening, the fuels taken for further analysis were the ones with a score over 15, i.e. natural gas (LNG and CNG1), electricity (Li-Ion battery), hydrogen (fuel cell and direct combustion) and electric hybrids (Li-Ion battery + diesel/LNG/CNG/hydrogen fuel cell/hydrogen direct combustion).

The analysis carried out looked at:

 the opportunity to produce the fuel locally (electricity and hydrogen) or the need to import it (natural gas and diesel);

 the different storage options; and

 the finance associated for both onshore and on-board storage systems.

Assessing the capital cost marine diesel comes out the cheapest due to the infrastructure already being in place but this has the highest carbon content. LNG would be the cheapest lower carbon option. Greener energy such as electricity and hydrogen were found to be the most expensive options, however their costs are very likely to drop in the future with improvements in these technologies and growth in their markets. The cheapest fuel per kWh is electricity, which makes its operational cost

1 LNG and CNG were looked at separately for simplification purposes, even though the most likely scenario would be to import LNG and gasify it for storage.

low; LNG2 and diesel also have low OPEX; hydrogen is the most expensive one with higher OPEX.3

An assessment of the carbon savings for each technology analysed compared to the current baseline (diesel) was also carried out and showed that the biggest reduction in carbon emissions would occur for the full electric option (Figure 3).

Figure 3 Annual amount of carbon released per technology and reduction compared to gas oil

The impact on renewable energy curtailment in Orkney was also studied. Fossil fuels do not have any effect on this as they are not produced locally. However, the electricity and hydrogen options have the potential to use significant amount of curtailed energy and even to allow for more renewable installations if the grid was to be upgraded.

The possibilities of modular energy storage have also deemed to be technologically feasible. This could reduce barriers currently limiting the use of some technologies, such as full-electric; which would suffer from high capital costs, long charging times and the need for grid upgrades. The alternative of changing the batteries during stops will significantly reduce the strain on the local grid by avoiding the requirement of rapid charging.

The weightings for the scoring of the secondary screening were decided at a workshop including Orkney Marine Services, Local Energy Scotland, Orkney Island Council‟s

2 CNG has a higher OPEX due to the high cost of import.

3 Operational costs are still unknown as the technologies are not well developed in the marine sector, but they were estimated considering a percentage of the assessed capital costs. However, by doing so, the full electric system has an overestimated OPEX (it should be the lowest) due to its high Capex.

Transport Manager and Aquatera. Depending on the priority of the council, these weightings can be changed which would result in a different overall ranking.

To demonstrate this point, increasing the weights on the priority of carbon emissions was also explored. In this analysis „Low carbon concern‟ represents the weighting of 1, „Medium carbon concern‟ describes the effect of increasing this weighting to 3 and „High carbon concern‟ gives a maximum weighting of 5. The effects of this investigation are illustrated in the graphs below for CAPEX and OPEX, across the different route levels.

Figure 4 Secondary screening for level 1 routes with varying weightings on the importance of carbon savings, and associated CAPEX and OPEX

Figure 5 Secondary screening for level 2 routes with varying weightings on the importance of carbon savings, and associated CAPEX and OPEX

Figure 6 Secondary screening for level 3 routes with varying weightings on the importance of carbon savings, and associated CAPEX and OPEX

The above figures show that the scores are highly sensitive on carbon savings. With selecting technologies with a score over 15, increasing the weight on carbon emissions would screen diesel out and bring full electric and hydrogen technologies joint first for short routes and second and third for medium routes. For medium and longer routes, the best scored technology would be alternative fuel electric hybrid, instead of LNG.

From the cost analysis, diesel appears to be the cheapest option. However, from the carbon analysis, it has the biggest impact. On the opposite, technologies using energies which can be produced locally (hydrogen and electricity) are the most expensive but the most environmental friendly. Electric hybrids may be a compromise between these two criteria.

Figure 7 shows the ratio between the amount of CO2 released and the capital expenditure for each technology.

Figure 7 Amount of CO2 released per £ of Capex

Through the process of screening possible propulsion technologies and prioritising the remaining viable methods, it became clear it was not possible to support one particular technology for the Orkney routes. But instead the report highlights how differing technologies fit differing needs and priorities, and the consequences of these choices.

However, one conclusion across all alternatives is that deviating from the marine diesel will be the need to accept impact of cost. Moving towards cleaner technologies will have cost implications which will depend on the priorities of the decision makers.

The second key component coming from the report is the fact that these are relatively new technologies within the Marine sector and therefore are still expensive. They are steadily dropping in price as they become a commercial reality with for example battery costs dropping by 50% within the last year. The cost model will need to be continually monitored with new costs added as technology pricing changes.

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Contents

EXECUTIVE SUMMARY ...... I CONTENTS ...... I LIST OF FIGURES ...... IV LIST OF TABLES ...... VI 1 INTRODUCTION ...... 10 2 CURRENT SHIPPING CONDITIONS...... 11 2.1 ORKNEY FLEET ...... 11 2.1.1 Ro-Ro Vessels ...... 12 2.1.2 Small Passenger Vessels ...... 13 2.2 ROUTE CHARACTERISTICS ...... 13 2.3 BASELINE ORKNEY FERRIES ENERGY USAGE ...... 17 2.4 RECOMMENDATIONS FOR VESSEL UPGRADES ...... 17 2.4.1 Vessel Size ...... 18 2.4.2 Catamarans ...... 18 2.4.3 Propulsion Systems ...... 18 2.4.4 Classification ...... 19 2.4.5 Training ...... 19 2.4.6 Ballast Movement...... 19 2.5 HARBOURS DESCRIPTIONS ...... 20 2.5.1 Kirkwall Pier ...... 20 2.5.2 Kirkwall – Hard Ramp ...... 21 2.5.3 Shapinsay – Balfour Pier ...... 21 2.5.4 North Ronaldsay – Nouster Pier ...... 22 2.5.5 Eday – Backaland Pier ...... 23 2.5.6 Sanday – Loth Pier ...... 24 2.5.7 Stronsay - Whitehall ...... 25 2.5.8 Westray – Rapness ...... 26 2.5.9 Westray – Pierowall ...... 27 2.5.10 Papa Westray – Moclett Pier ...... 28 2.5.11 Tingwall Pier ...... 29 2.5.12 Rousay – Trumland ...... 30 2.5.13 Egilsay ...... 31 2.5.14 Wyre ...... 32 2.5.15 Stromness – South Pier ...... 33 2.5.16 Graemsay ...... 34 2.5.17 Hoy - Moaness ...... 35 2.5.18 Houton (Orphir) ...... 36

2.5.19 Flotta – Gibraltar Pier ...... 37 2.5.20 Hoy – Lyness ...... 38 2.5.21 Hoy - Longhope...... 39 3 FUTURE VESSELS AND FUEL TYPES OPTIONS ...... 40 3.1 NATURAL GAS ...... 40 3.1.1 Fuel Properties ...... 40 3.1.2 Direct Burning Propulsion ...... 47 3.1.3 Natural Gas Hybrid Propulsion ...... 52 3.2 BIOFUELED SYSTEMS ...... 56 3.2.1 Fuel Properties ...... 56 3.3 ELECTRICAL DRIVEN SYSTEMS ...... 67 3.3.1 Fuel Properties ...... 67 3.3.2 Electrical Battery Driven Systems ...... 67 3.3.3 Flow Cell Systems ...... 74 3.3.4 Diesel Electric Driven Systems ...... 77 3.3.5 Electric Hybrid Driven Systems ...... 79 3.4 HYDROGEN FUELS SYSTEMS ...... 83 3.4.1 Fuel Properties ...... 83 3.4.2 Hydrogen Co-Burning ...... 94 3.4.3 Direct Combustion Systems ...... 95 3.4.4 Fuel Cell Enhanced Systems ...... 96 3.5 OTHER NOVEL POWER/FUEL SYSTEMS ...... 98 3.5.1 Wind Driven Propulsion ...... 98 3.5.2 Compressed Air and Liquid Nitrogen ...... 101 3.5.3 Anhydrous Ammonia ...... 102 3.5.4 Solar Photovoltaics and Hybrid Systems ...... 103 3.5.5 Wave Energy ...... 104 3.5.6 Nuclear ...... 104 4 REGIONAL AND NATION INTEGRATION ...... 105 4.1 LEGISLATION AND PLANNING IMPLICATIONS ...... 105 4.1.1 National Legislation and Advice ...... 105 5 SCREENING METHODOLOGY: ABSOLUTE ASSESSMENT. 107 5.1 PRELIMINARY SCREENING PROCESS ...... 108 5.1.1 Assessment Factors ...... 108 5.1.2 Results from the Preliminary Screening ...... 108 5.2 SECONDARY SCREENING PROCESS ...... 110 5.2.1 Assessment Factors ...... 110 5.2.2 Results from the Secondary Screening ...... 111 6 FUEL SCENARIOS COMPARISON ...... 115

7 VESSEL DESIGN CHARACTERISTICS ...... 131 7.1 INTRODUCTION ...... 131 7.2 NATURAL GAS ...... 131 7.2.1 Production/Fuel demand ...... 131 7.2.2 Storage ...... 134 7.2.3 Refuelling ...... 137 7.2.4 Impact on Vessels ...... 137 7.2.5 Impact on Shore ...... 138 7.2.6 Conclusion ...... 139 7.3 FULL ELECTRIC ...... 140 7.3.1 Production ...... 140 7.3.2 Storage ...... 141 7.3.3 Refuelling ...... 142 7.3.4 Impact on Vessels ...... 143 7.3.5 Impact on-shore ...... 149 7.3.6 Conclusion ...... 152 7.4 HYDROGEN ...... 152 7.4.1 Production ...... 153 7.4.2 Storage ...... 159 7.4.3 Refuelling ...... 162 7.4.4 Impact on Vessels ...... 163 7.4.5 Impact on-shore ...... 164 7.4.6 Conclusion ...... 164 7.5 ELECTRIC HYBRIDS ...... 166 7.5.1 Production ...... 166 7.5.2 Storage ...... 167 7.5.3 Refuelling ...... 173 7.5.4 Impact on Vessels ...... 173 7.5.5 Impact on Shore ...... 178 7.5.6 Conclusion ...... 178 8 CONCLUSION ...... 180 8.1 CARBON SAVINGS ...... 180 8.2 INFRASTRUCTURE COSTS ...... 181 8.2.1 CAPEX ...... 182 8.2.2 OPEX ...... 184 8.3 CURTAILED ENERGY ...... 189 8.4 MODULAR STORAGE ...... 191 9 APPENDICES ...... 192

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List of Figures

Figure 2.1 Map of the different Orkney Ferries routes and the level associated ...... 16 Figure 2.2 Kirkwall Harbour ...... 20 Figure 2.3 Current Kirkwall Power Infrastructure ...... 20 Figure 2.4 Shapinsay Balfour Pier ...... 21 Figure 2.5 Current Shapinsay Power Infrastructure ...... 21 Figure 2.6 North Ronaldsay Nouster Pier ...... 22 Figure 2.7 Current North Ronaldsay Power Infrastructure ...... 22 Figure 2.8 Eday Backaland Pier ...... 23 Figure 2.9 Current Eday Power Infrastructure ...... 23 Figure 2.10 Sanday Loth Pier...... 24 Figure 2.11 Current Sanday Power Infrastructure ...... 24 Figure 2.12 Stronsay Whitehall Pier ...... 25 Figure 2.13 Current Power Infrastructure at Stronsay Harbour ...... 25 Figure 2.14 Rapness Pier in Westray ...... 26 Figure 2.15 Current Power Infrastructure at Rapness ...... 26 Figure 2.16 Pierowall Pier in Westray ...... 27 Figure 2.17 Papa Westray - Moclett Pier ...... 28 Figure 2.18 Current Papa Westray Power Infrastructure ...... 28 Figure 2.19 Tingwall Pier...... 29 Figure 2.20 Rousay Trumland Pier ...... 30 Figure 2.21 Egilsay Pier ...... 31 Figure 2.22 Wyre Pier ...... 32 Figure 2.23 Stromness Harbour ...... 33 Figure 2.24 Graemsay Pier ...... 34 Figure 2.25 Moaness Pier on Hoy ...... 35 Figure 2.26 Houton Pier (Orphir) ...... 36 Figure 2.27 Flotta Gibraltar Pier ...... 37 Figure 2.28 Lyness Pier (Hoy)...... 38 Figure 2.29 Longhope Pier (Hoy) ...... 39 Figure 3.1 Natural Gas Market Price ...... 41 Figure 3.2 Global Commons fuel price forecasts (HFO: Heavy Fuel Oil, MDO: Marine Diesel Oil, LSHFO: Low Sulphur Heavy Fuel Oil, LNG: Liquefied Natural Gas) 41 Figure 3.3 LNG Refuelling of Glutra ...... 44 Figure 3.4 Natural Gas Bunkering Solutions ...... 44 Figure 3.5 Accolade II ...... 46 Figure 3.6 Francisco ...... 47 Figure 3.7 MF Glutra ...... 48

Figure 3.8 Bergen Viking ...... 48 Figure 3.9 M.V. Queen of Capilano ...... 50 Figure 3.10 Texelstroom ...... 52 Figure 3.11 Viking Lady ...... 53 Figure 3.12 MF Fannefjord ...... 54 Figure 3.13 Seaspan LNG Hybrid Ferries ...... 55 Figure 3.14 First and second generation biofuels production processes in comparison with fossil fuels ...... 59 Figure 3.15 Potential outputs of biofuels per hectare per annum ...... 61 Figure 3.16 Stena Germanica ...... 64 Figure 3.17 MF Ampere ...... 68 Figure 3.18 Global Utility Scale Battery Storage Capacity and Revenue Forecast ..... 73 Figure 3.19 Flow Cell ...... 74 Figure 3.20 Frisia 111 ...... 78 Figure 3.21 MF Prinsesse Benedikte ...... 80 Figure 3.22 Electrolyser basic configuration ...... 83 Figure 3.23 Proton exchange membrane ...... 84 Figure 3.24 Alkaline electrolyser ...... 85 Figure 3.25 Solid oxide electrolyte ...... 86 Figure 3.26 Hydrogen Production Costs through Electrolysis ...... 89 Figure 3.27 Global Commons fuel price forecasts. (HFO: Heavy Fuel Oil, MDO: Marine Diesel Oil, LSHFO: Low Sulphur Heavy Fuel Oil, LNG: Liquefied Natural Gas) 89 Figure 3.28 Hydrogen Co-Burning Efficiency...... 90 Figure 3.29 Sensitivity analysis on the uptake of hydrogen between 2010 - 2050 ... 94 Figure 3.30 Direct Combustion Propulsion Efficiency ...... 95 Figure 3.31 Fuel Cell Propulsion Efficiency ...... 97 Figure 3.32 Greenheart's soft-sail freighter (left) and B9 Shipping‟s 3,000dwt bulker (right) 99 Figure 3.33 Example of Oceanfoil's fuel-assist aerofoil wingsail technology (Source: Oceanfoil.com) ...... 99 Figure 3.34 Ships using rotor sails (Magnus effect) Alcyone (left) and E-Ship 1 (right)100 Figure 3.35 OCIUS technology's solar sailor design utilising fixed sails with PV panels (see also Section Wingsails or Rigid Sails) ...... 103 Figure 5.1 Primary screening results ...... 109 Figure 5.2 Results from the secondary screening for route level 1...... 112 Figure 5.3 Results from the secondary screening for route level 2...... 112 Figure 5.4 Results from the secondary screening for route level 3...... 113 Figure 5.5 Overall results of the secondary screening process: fuel suitability to each route level...... 114

Figure 6.1 Orkney‟s DNO Zones for ANM ...... 118 Figure 7.1 LNG carrier ship ...... 133 Figure 7.2 LNG tank containers, an alternative to LNG carrier ships , ...... 133 Figure 7.3 Ship CNG carrier concept...... 133 Figure 7.4 Example of above ground horizontal LNG storage tanks...... 134 Figure 7.5 Horizontal above ground CNG storage in pressurised trailer tubes ...... 134 Figure 7.6 Pressurised spherical tanks for onshore CNG storage ...... 135 Figure 7.7 Shore side recharging infrastructure. (A) Vacuum berthing mounts (B) Charging tower with buffer battery and plug on a pulley system ...... 143 Figure 7.8 Line diagram of MF Ampere propulsion system ...... 145 Figure 7.9 Surf 'n' Turf...... 158 Figure 8.1 Annual amount of carbon released per technology and reduction compared to gas oil...... 180 Figure 8.2 Amount of carbon released per £ invested for each technology and carbon saving compared to gas oil...... 181 Figure 8.3 Capital expenditures (per route level and total) for (a) non-hybrid technologies and (b) hybrid technologies...... 183 Figure 8.4 Comparison between current and future capital expenditures per route level and total for hybrid technologies, considering a 50% reduction of battery costs in five years...... 184 Figure 8.5 Operational expenditures (per route level and total) for (a)non-hybrid technologies and (b) hybrid technologies...... 185 Figure 8.6 Comparison between current and future operational expenditures per route level and total for hybrid technologies, considering a 50% reduction of battery costs in five years...... 186 Figure 8.7 Secondary screening for level 1 routes with varying weightings on the importance of carbon savings, and associated CAPEX (a) and OPEX (b).187 Figure 8.8 Secondary screening for level 2 routes with varying weightings on the importance of carbon savings, and associated CAPEX (a) and OPEX (b).188 Figure 8.9 Secondary screening for level 3 routes with varying weightings on the importance of carbon savings, and associated CAPEX (a) and OPEX (b).189 Figure 9.1 Non-weighted score per technology and per assessment factor Figure 9.2 Weighted score per technology 193

List of Tables

Table 1 Secondary Screening Weightings ...... ii Table 2.1 List of the ro-ro ferries operated by Orkney Ferries and their characteristics ...... 12 Table 2.2 List of the small passenger ferries operated by Orkney Ferries and their characteristics ...... 13 Table 2.3 Orkney Ferries routes and their characteristics ...... 13

Table 2.4 Total marine fuel use by Orkney Marine Services ...... 17 Table 2.5 Annual consumption of Orkney Ferries of marine gas oil and equivalent energy since 2004 ...... 17 Table 3.1 CNG Storage Tank Comparison ...... 43 Table 3.2 Examples of LNG Projects in the UK ...... 46 Table 3.3 Biofuels characteristics ...... 58 Table 3.4 Biofuel applications in shipping (International Renewable Energy Agency; IRENA 2015) ...... 63 Table 3.5 Estimated biofuel costs (from IEA 2007) ...... 65 Table 3.6 Battery technology comparison ...... 69 Table 3.7 Specifications of a 1MWh reference battery based on different technologies ...... 71 Table 3.8 Current and projected capital cost for utility scale battery technologies (per kWh) ...... 72 Table 3.9 Flow Cell Technology Comparison ...... 75 Table 3.10 Electrolysers technology overview ...... 86 Table 3.11 Overview of hydrogen storage options...... 93 Table 5.1 Summary of the methodology for the screening process ...... 107 Table 5.2 Details of the expanded assessment factors for the preliminary screening process 108 Table 5.3 Details of the expanded assessment criteria ...... 110 Table 6.1 Orkney harbours electricity consumption 2013/2014 (Source: OIC) ... 119 Table 6.2 Orkney's Biofuel Potential ...... 120 Table 6.3 Bio waste resource potential ...... 120 Table 6.4 Food processing waste resource potential ...... 121 Table 6.5 Fuel per unit energy densities and system efficiencies ...... 122 Table 6.6 Current fuel consumption per vessel per year and equivalents for other fuels 123 Table 6.7 Potential curtailed energy absorption through ferries...... 126 Table 6.8 Full Hydrogen Scenario and Grid Implications ...... 127 Table 7.1 Comparative transport costs of LNG ...... 131 Table 7.2 Average current annual fuel usage per route and potential LNG and CNG equivalent yearly and weekly demand (does not take MV Thorsvoe into account) 132 Table 7.3 Onshore LNG storage sizing and cost per route. (see also Table 7.7) .. 136 Table 7.4 Onshore CNG storage sizing and cost per route...... 136 Table 7.5 Size, weight and costs for on-board LNG storage and infrastructure for each route...... 137 Table 7.6 Size, weight and costs for on-board CNG storage and infrastructure for each route...... 138

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Table 7.7 Total area requirement for onshore LNG storage installation, considering all vessels run on LNG. (Tank area: 15m x 5m; Safety zone buffer: 30m)139 Table 7.8 Total area requirement for onshore CNG storage installation, considering all vessels run on CNG (Tank area: 15m x 5m; Safety zone buffer: 30m)139 Table 7.9 Total capital and operational expenditures (include both onshore and vessel infrastructures) for LNG and CNG technologies (comparison with gas oil). 140 Table 7.10 Required Energy Consumption and Wind Generation ...... 141 Table 7.11 Required batteries capacity for longest trips and backup system ...... 144 Table 7.12 Required batteries capacity for full return trip and backup scenario .... 147 Table 7.13 Electric Motor Costs...... 149 Table 7.14 On-shore Battery Capacity Cost ...... 149 Table 7.15 On-shore Energy Storage Capacity ...... 150 Table 7.16 Power Requirement per Destination over Time ...... 151 Table 7.17 CAPEX (£) ...... 152 Table 7.18 Daily Hydrogen Consumption ...... 153 Table 7.19 Total On-Board Storage ...... 155 Table 7.20 Generation Power ...... 155 Table 7.21 Electrolyser Cost ...... 156 Table 7.22 Required Wind Turbine Generation ...... 158 Table 7.23 On-Board Storage Solution Weight and Cost for Fuel Cell ...... 161 Table 7.24 On-Board Storage Solution Weight and Cost for Direct Combustion .... 161 Table 7.25 On-shore Storage ...... 162 Table 7.26 SmartFuel hydrogen tube trailer ...... 163 Table 7.27 Breakdown Costs of Fuel Cell Propulsion ...... 163 Table 7.28 Breakdown Costs of Direct Combustion Propulsion ...... 164 Table 7.29 Direct Combustion Propulsion Total System Costs ...... 166 Table 7.30 Fuel Cell Propulsion Total Systems Costs...... 166 Table 7.31 Type of on-shore infrastructure per fuel and refuelling frequency...... 167 Table 7.32 On-shore storage infrastructure and costs for 30% electric hybrid vessels. 168 Table 7.33 Total on-shore storage infrastructure and costs for 30% electric hybrid vessels 172 Table 7.34 Type of storage infrastructure on-board vessels per fuel and refuelling frequency...... 173 Table 7.35 On-board storage infrastructure and costs for 30% electric hybrid vessels. 174 Table 7.36 Total on-board storage infrastructure and costs for 30% electric hybrid vessels 177 Table 7.37 Extra costs and savings considering hybrids over non-hybrids...... 178

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Table 7.38 Total capital and operational expenditures (include both onshore and vessel infrastructures) for the hybrid technologies considered...... 179 Table 8.1 Required Energy Consumption and Wind Generation ...... 190

ix LOW CARBON FERRIES – FEASIBILITY STUDY

1 INTRODUCTION

The Orkney Islands inter-islands ferries provide a lifeline service for the users either passenger or freight. It is vital to the individual islands and the overall Orkney economy that these services are maintained and where possible improved. Within the framework of overall sustainability a number of key drivers can be recognised. These include: capital and operational costs, user costs, carbon emissions, safety, carrying capacity, scheduling, flexibility, reliability and performance. It is against this multi-faceted backdrop that this study has been undertaken.

This report provides a description of the baseline conditions that exist in Orkney for the ferry system. This includes consideration of:

 Vessels and their fuel usage;  Route characteristics; and  Harbours characteristics including the electrical infrastructure.

The report also describes in detail a large range of low carbon fuelling options that could be used in Orkney, listing their positive aspects and limitations.

The fuel options are then taken through a first stage screening process where they are compared against each other using the parameters time to market, cost, regulatory issues and suitability for the route. This reduced the number of fuels down so that the analysts along with members of Orkney Islands Council (OIC) could decide which of the options merited further investigation.

This report also looks at Orkney‟s infrastructure with particular reference to energy resources and options to feed into the alternative fuel option analysis.

Those fuel options that were not screened out but the first stage screening process were carried further for a more analysis. In addition, an interactive modelling tool was developed that could be used to match different parameters such as fuel price and availability, storage costs and capital requirements of the alternative fuels.

10 OIC LOW CARBON FERRIES – FEASIBILITY STUDY

2 CURRENT SHIPPING CONDITIONS

2.1 ORKNEY FLEET

The Orkney fleet is composed of nine vessels operating as passenger ferries within Orkney waters. Seven of them are roll on - roll off (ro-ro) vessels (can carry road vehicles) and two are small passenger ferries.

Passenger-carrying ships are classified primarily by the Maritime and Coastguard Agency (MCA) on whether they operate inshore or on short or long international voyages.

The classes of passenger ships are as follows1:

 Class I - ships engaged on voyages any of which are long international voyages;  Class II - ships engaged only on voyages any of which are short international voyages;  Class II(A) - ships engaged on voyages of any kind other than international voyages, which are not ships of Classes III to VI(A);  Class III - ships engaged only on voyages in the course of which they are at no time more than 70 miles by sea from their point of departure and not more than 18 miles from the coast of the UK and which are at sea only in favourable weather and during restricted periods;  Class VI - ships engaged only on voyages with not more than 250 passengers on board. In favourable weather and during restricted periods, in the course of which the ships are at no time more than 15 miles from their point of departure, nor more than three miles from land; and  Class VI (A) - ships carrying not more than 50 passengers for a distance of not more than six miles. Voyages to or from isolated communities on the islands or coast of the UK and which do not proceed for a distance of more than three miles from land - this is subject to any conditions which the Secretary of State may impose.

Additional EU classifications for domestic seagoing passenger ships are:

 Class A - passenger ships engaged on domestic voyages other than voyages covered by Classes B, C and D;  Class B - a passenger ship engaged on domestic voyages in the course of which it is at no time more than 20 miles from the line of the coast;

 Class C - a passenger ship engaged on domestic voyages in sea areas where the probability of exceeding 2.5 metres significant wave height is less than 10% over a one-year period for all-year round operation; or operating over a specific restricted period (eg summer) in the course of which it is at no time more than 15 miles from a place of refuge, nor more than five miles from the line of the coast; and  Class D - a passenger ship engaged on domestic voyages in sea areas where the probability of exceeding 1.5 metres significant wave height is less than 10% over a one-year period for all-year round operation; or operating over a specific restricted period (eg summer) in the course of which it is at no time more than 15 miles from a place of refuge, nor more than five miles from the line of the coast.

11 OIC LOW CARBON FERRIES – FEASIBILITY STUDY

2.1.1 Ro-Ro Vessels

Table 2.1 List of the ro-ro ferries operated by Orkney Ferries and their characteristics2

Vessel (date of Route Class Engine Fuel usage Number of Other construction) in 2015 hours run characteristics (Litres) in 2015

M.V. Earl Sigurd Outer North Isles MCA 2 Mirrlees, 664,640 2,968 Tonnage: 771 (1989) Service (incl. Class 743kW each Speed: 12 knots Eday, Stronsay, IIA/III Length: 45.0m Sanday, Westray, North Ronaldsay) Beam: 11.0m Draft: 3.155m

M.V. Earl Outer North Isles MCA 2 Mirrlees, 715,360 3,032 Tonnage: 771 Thorfinn (1989) Service (incl. Class 743kW each Speed: 12 knots Eday, Stronsay, IIA/III Length: 50.0m Sanday, Westray, North Ronaldsay) Beam: 11.0m Draft: 3.006m

M.V. Varagan Outer North Isles MCA 2 Caterpillars, 657,985 3,011 Tonnage: 928 (1988) Service (incl. Class 790kW each Speed: 15 knots Eday, Stronsay, IIA/III Length: 45.0m Sanday, Westray, North Ronaldsay) Beam: 11.0m Draft: 3.155m

M.V. Shapinsay Shapinsay- MCA 2 Volvo 151,506 2,823 Tonnage: 219 (1988) Kirkwall Class IV Penta, 331kW Speed: 10 knots each Length: 35.0m Beam: 9.0m Draft: 1.45m

M.V. Eynhallow Tingwall – Rousay MCA 2 Volvos, 156,400 3,232 Tonnage: 104 (1987) – Egilsay - Wyre Class 220.5kW each Speed: 11 knots VIA/VI Length: 29.0m Beam: 7.0m Draft: 1.5m

M.V. Hoy Head South Isles MCA 2 Volvos, 345,454 3,176 Tonnage: 482 (1994) Service (incl. Class IV 478kW each Speed: 11 knots Houton, Flotta, Length: 53.3m Lyness) Beam: 10.0m Draft: 2.5m

M.V. Thorsvoe Relief vessel MCA 2 Volvos, 120,022 1,641 Tonnage: 385 (1991) Class IV 346kW each Speed: 11 knots Length: 35.0m Beam: 10.0m Draft: 1.8m

12 OIC LOW CARBON FERRIES – FEASIBILITY STUDY

2.1.2 Small Passenger Vessels

Table 2.2 List of the small passenger ferries operated by Orkney Ferries and their characteristics

Vessel (date of Route Class Engine Fuel usage Number of Other construction) in 2015 hours run characteristics (Litres) in 2015

M.V. Golden Westray - Papa MCA 1 Gardner, 22,470 1,162 Tonnage: 33 Mariana (1973) Westray Class 97kW Speed: 10 knots VIA/VI Length: 15.2m Beam: 4.9m Draft: 1.676m

M.V. Graemsay Stromness – MCA 2 Volvo Penta, 77,410 1,498 Tonnage: 58 (1996) Graemsay - North Class 261kW each Speed: 10 knots of Hoy IV/VI/VIA Length: 21.3m Beam: 6.0m Draft: 1.95m

2.2 ROUTE CHARACTERISTICS

Orkney Ferries operate on several routes which are often divided into a number of sections; a section of route being the journey between two harbours while the route is the whole journey until the vessel comes back to the first harbour. Table 2.3 gathers the characteristics for each of them (Note: the number of trips includes the direct return when there is one).

Table 2.3 Orkney Ferries routes and their characteristics

Route Route section Distance Number of Max Crossing Turn over Max per trip trips/week trips/day time time tide (km) (summer/ (minutes) (minutes) (knots) winter)

Outer North Kirkwall – Eday 26.1 09/07 3 75 10 to 15 3.5 Isles Eday – Sanday 5.5 09/06 2 20 10 to 15

Sanday – 9.1 00/01 2 35 10 to 15 Stronsay

Stronsay – 34.0 09/07 3 95 10 4 Kirkwall

Eday-Stronsay 11.7 10/08 2 35 10 to 15

Kirkwall - 29.9 10/10 4 85 10 to 65 Sanday

Kirkwall – 30.7 16/15 6 85 15 - 235 3 Westray (1)*

Westray (1) – 11.9 01/01 2 40 15 Papa Westray

Kirkwall - Papa 41.5 01/01 2 110 25 3

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Route Route section Distance Number of Max Crossing Turn over Max per trip trips/week trips/day time time tide (km) (summer/ (minutes) (minutes) (knots) winter) Westray

Kirkwall – North 54.9 02/01 2 160 3 Ronaldsay

Papa Westray (2)* – Westray Papa Westray 4.9 10/05 4 25 5 to 10

Rousay – Tingwall – 6.6 34/30 11 25 10 to 15 Wyre - Rousay

Egilsay Rousay – 4.3 31/28 5 15 Egilsay

Egilsay – Wyre 4.3 31/28 5 15

Wyre – Rousay 1.0 49/45 8 10

Wyre – 6.8 07/06 1 25 Tingwall

Shapinsay Kirkwall – 7.0 41/37 12 25 20 3.5 Shapinsay

Houton Houton – 9.5 28/20 9 35 15 0.5 Lyness

Lyness – Flotta 3.7 35/32 7 20 5 0.5

Flotta – Houton 9.7 10/10 4 35 15 0.5

Flotta - 6.2 06/06 2 20 5 1.5 Longhope

Longhope - 5.4 01/00 1 20 5 1.5 Lyness

Graemsay Stromness – 8.5 09/09 6 25 5 to 10 5 Moaness

Moaness – 4.1 16/16 6 13 3 Graemsay

Graemsay – 4.2 12/12 6 13 10 - 195 5 Stromness

*Westray (1): Rapness Pier; Westray (2): Pierowall harbour

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According to the energy use of each vessel, the size of the vessel, and the distance of the longest route section, these routes have been divided into three levels (see Figure 2.1):

 Level 1 (red): characterised by a small vessel (<60t, <100,000L of fuel/year) and a short route distance (<5 nautical miles)  Level 2 (orange): characterised by a medium size vessel (between 100 and 500t, between 100,000 and 500,000L of fuel/year) and short to medium route (up to 10 nautical miles)

 Level 3 (white): characterised by a large vessel (>500t, >500,000L of fuel/year) and long route distance (>10 nautical miles).

It is noted that the Rousay and Shapinsay routes both suit level 1 as far as distance is concerned but are in level 2 because of the vessel characteristics. Further analysis on route suitability to fuel system will be undertaken in the second phase of the report.

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Figure 2.1 Map of the different Orkney Ferries routes and the level associated

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2.3 BASELINE ORKNEY FERRIES ENERGY USAGE

Marine fuel is currently the only energy supply for sea vessels in Orkney. The fuel comes in by sea via tanker and is discharged at Scapa Pier, for Highland Fuels; and Kirkwall Pier, for Scottish Fuels. This is re-distribution by road tanker to where it is required. Most of the marine fuel is used by the Orkney Islands Council (OIC) Marine Services on harbour craft and tugs as well as several of the main fuel suppliers. The table below shows the distribution of the different marine fuels currently used on the island.

Table 2.4 Total marine fuel use by Orkney Marine Services 3

Unit Estimated annual fuel use 2009 - present (GWh)

Marine Gas Oil 44.60

Marine Diesel Oil 16.91

Heavy Fuel Oil 165.79

Total 227.3

Orkney Ferries, a section of Marine Services, operates nine dedicated inter-island ferries between Orkney‟s mainland and thirteen island destinations. Table 2.5 shows the trend of annual consumption of marine gas oil by Orkney Ferries in litres of fuel and equivalent Gigawatt hours (GWh) of equivalent energy for the last decade.4

Table 2.5 Annual consumption of Orkney Ferries of marine gas oil and equivalent energy since 20045

Year Orkney Ferries fuel (Litres) Orkney Ferries energy usage (GWh)

2004 - 05 2,708,915 29.08

2005 - 06 2,668,670 28.65

2006 - 07 2,708,642 29.08

2007 - 08 2,653,982 28.49

2008 - 09 2,849,191 30.59

2009 - 10 2,775,956 29.8

2010 - 11 2,986,693 32.07

2011 - 12 2,893,130 31.06

2012 - 13 2,850,614 30.61

2013 - 14 2,792,629 29.98

2.4 RECOMMENDATIONS FOR VESSEL UPGRADES

This section considers some of the issues around the choice of vessel and how they are affected by the type of fuel they use. The current fleet has been described as it stands today as well as key statistics on energy requirements by fuel types, but there are also some practical issues that need to be considered. These practical issues will be further assessed against the options that are favoured within the analysis section.

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2.4.1 Vessel Size

During discussions with OIC and industry experts it is thought that on the outer isles routes the size of the next generation ferries would increase to around 60 – 65 metres. This would need some pier infrastructure changes to ensure safe berthing (particularly overnight) but could be accommodated in the ports that are currently used.

For the inner isles routes (Hoy, Shapinsay and Rousay) the sizes of the vessels are considered adequate especially since the Hoy Head has been lengthened which has increased her capacity. There may be some need to increase carrying capacity at peak times so any redesign would need to take account of this. The port facilities at Houton are quite restrictive for the vessel which again would need some thought if the ferry is to be redesigned, in particular extra draft would cause issues. The port at Egilsay also has some severe restrictions and could not cope with any vessel bigger than the MV Shapinsay.

The two short routes with smaller ferries (Graemsay and Papa Westray) have some port restrictions in particular lengths and draft at the Moaness (Hoy) pier is limited without some pier redevelopments.

2.4.2 Catamarans

Catamarans have been thought of as an alternative to conventionally shaped vessels due to their higher speed and weight displacement characteristics. We suggest that due to the more extreme weather conditions faced on the north isles routes that care would need to be taken on the construction methods and materials. They would offer a large cargo surface but with the increased beam could have some serious issues at some ports in berthing.

They also present some difficulties when considering engine type and choice. The favoured option of electric drives with three options for power source would be more problematic in a twin hull design. It would therefore be worth considering two engines with four power sources, two in each hull. This may well add to cost for relatively small vessels although this is a similar configuration to that used by Pentland Ferries MV Pentalina (though a two propeller solution preferable over that opting for four). Space requirements and balance would need to be carefully thought through if a catamaran was a favoured option.

The traditional linkspans would probably need some substantial redesign for this type of vessel, especially for the larger lorries that are used on the routes. The majority of the Outer North Isles linkspans are in relatively good condition so the costs involved in this redesign could be substantial and very specific to the individual ferry. There is however currently weight bearing restrictions on all but Kirkwall linkspans that restrict what can be carried on the ferries. These present significant problems with the likes of large cranes and the larger wind turbine installations but it is recognised that dealing with this would add considerable infrastructure cost.

2.4.3 Propulsion Systems

The propulsion system that will be used will be subject to a detailed technical assessment but it is suggested that there are some options that would support low carbon options by giving greater flexibility. The main option that is thought to provide this flexibility would be electric propulsion units driven by a power source that is yet to be defined. This system has been proven and improved a lot over the last 10 – 15 years in diesel-electric form and to a certain extent divorces the power source from the propulsion unit.

It must however be noted that there would be additional installation cost that would likely be outweighed by benefits in service reliability and possibly offer future cost-effective changes. It must be noted from recent experience on more modern vessels, including hybrid designs now operating that there may be a certain dependence on good communication access to a limited number of very experienced electronic technicians from companies such as Kongsberg, Siemens or other approved electronic control gear supplier.

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The propulsion unit whether it be azimuth or driving a fixed pitch (cheaper and more easily repaired or replaced in the event of blade damage) or Controllable Pitch (CP) propeller can then be supplied from different power sources such as diesel/LNG (Liquid Natural Gas) and batteries or hydrogen and batteries. The power source could be modular; this will be discussed later in the report. The generator units should themselves be arranged to be easily removed and replacement set in place without long downtime and service impact issues.

The drive system could be one of three types:

 Traditional propeller gives options driven by three power units giving redundancy and safety back up. Most vessels, other than the smallest, would still require some tunnel thrusters at the other end of the vessel to allow for more manoeuvrability;

 Omni directional azimuth drive units are drives which can turn around 360 degrees allowing a good degree of manoeuvrability and although more expensive initially there may not be a need for thrusters in this system. There could be an option of longitudinally disposed drives that would not require thrusters. This option is not used often. The systems are more complex and therefore maintenance may be more expensive. It must also be noted that it would be desirable for a vessel fitted with two of these electrically driven units to have three generators whether they be diesel, LNG, hydrogen fuel cell or other driving the two units ( this would be true for other propulsion systems as well);  The Voith Schneider propulsion system is relatively common on ferries, longitudinally disposed. They have a similar capability to azimuth drives but are generally more capital expensive and can create a larger draft on the vessel by comparison or  Jet drive system can give good speed characteristics but have problems for larger vessel in shallow water with intakes and possibly some issues manoeuvring in confined berths. They can also be costly to operate.

Each of the power generators require to have two separate fuel sources so that if one tank/filter system gets a blockage or has a system fault there is an alternative fuel system that can be used to ensure the ferry has some power.

2.4.4 Classification

There are some conditions of classification particularly for the outer isles vessels that will have some impacts on the vessel design. One key design point will be having an enclosed bow section to protect the cargo in the rougher open- water seas that these vessels will encounter.

2.4.5 Training

New systems will require an investment in training staff and the supply chain to cope with new fuels. This could have a substantial impact on recruiting as initially there may be very limited numbers of suitably experienced certificated mariners that could apply for positions. There could also be an opportunity as there will an increased demand for this type of training and as with the Community Energy Scotland Surf „n‟ Turf program Orkney could become a centre for the training on these different systems.

2.4.6 Ballast Movement

Ships traditionally have to move ballast around to ensure that as a vessel is loaded it is trimmed correctly. This involves moving water ballast around tanks. The requirement to do this is relatively small with the ferries we have now but if in the future large weights of batteries etc. are added to the vessel this may need to be considered in the vessel design.

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2.5 HARBOURS DESCRIPTIONS

The descriptions in this section are taken from Orkney Harbours‟ port handbook6.

2.5.1 Kirkwall Pier

Terminal overview

Kirkwall Pier is located on the northern coast and in the main town of the mainland of Orkney, at the head of Bay of Kirkwall. The terminal provides Orkney Ferry ro-ro services to Eday, Westray (Rapness), Sanday and Stronsay. Ferries also visit non-ro-ro berths at North Ronaldsay and Papa Westray as part of the Outer North Isles ro-ro ferry service.

The main linkspan is shorter and wider than others on the Outer North Isles ferry service.

Structures and condition

Bulk loading and a LoLo (Lift on-Lift off) contingency is available at Kirkwall Pier, which also has a fuel gantry. It has about 750m of berthing quay excluding the camber with a maximum available berthing length of 119m. The water depth (below Chart datum, CD) is 1 - 5.5m with a tidal range of 4m. Gas oil is available from road tankers. No local supply of fuel oil is available.

Figure 2.2 Kirkwall Harbour Figure 2.3 Current Kirkwall Power Infrastructure

The Kirkwall harbour is connected to the core zone of the Active Network Management (ANM) system which experiences little curtailment. It is well served with an 11kV connection available at the harbour and a substation connecting to an underground 33kV connection which is located within 500m from the harbour.

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2.5.2 Kirkwall – Hard Ramp

Terminal overview

Kirkwall‟s hard ramp is to the east of the harbour and provides Orkney Ferry services to Shapinsay.

Structures and condition

The ramp is in good condition with a solid quay alongside. There is limited car parking and road access.

2.5.3 Shapinsay – Balfour Pier

Terminal overview

Balfour Pier is located to the south-west of the island of Shapinsay. The terminal provides Orkney Ferry services to Kirkwall. The location of the terminal is reasonably protected with vessels able to berth overnight here. The pier to the south could be extended to give more protection in extreme weather.

Structures and condition

The ramp has a piled jetty alongside. Vessels can berth on the northern outer side of the quay when not loading. The maximum berthing length available is 33m and the water depth (below CD) is 2 - 4m. There is a parking area at the end of the quay.

Figure 2.4 Shapinsay Balfour Pier Figure 2.5 Current Shapinsay Power Infrastructure

The Shapinsay harbour is within a 300m radius of the 33kV power grid; where it comes ashore from the mainland to the pier where a charging point can be used to charge the vessel overnight. There is also an opportunity to link into the 11kV system by adding a three phase transformer at the shore side.

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2.5.4 North Ronaldsay – Nouster Pier

Terminal overview

Nouster Pier is located to the south-west of the island of North Ronaldsay. The terminal provides Orkney Ferry services with Kirkwall as part of the North Isles ferry route. The location of the terminal is exposed and swell can be a problem especially from the west and potentially from the east.

Structures and condition

The quay is old but very solid. Vessels overhang the structure when berthed, so an extension of the structure would be a benefit but would be difficult and expensive to build. Local inhabitants would like a ro-ro facility but appreciate that this would be challenging to construct.

Passengers embark and disembark via a gangplank. Cargo is lifted on and off the ferry using a crane mounted on the vessel.

The maximum available berthing length is 50m and the water depth (below CD) is 1 - 3m.

Figure 2.6 North Ronaldsay Nouster Pier Figure 2.7 Current North Ronaldsay Power Infrastructure

The North Ronaldsay harbour is serviced by an 11kV overhead line that links to the mainland through an 11kV subsea cable. This connection will be sufficient for connecting to low carbon ferries infrastructure owing to the small size of vessels that will be plying this route.

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2.5.5 Eday – Backaland Pier

Terminal overview

Backaland Pier is located to the south-east of the island of Eday. The terminal provides services to Kirkwall (mainland), Sanday and Stronsay as part of the Outer North Isles ferry service. The berth provides reasonable shelter but is not suitable for overnight ferry berthing. The berth can be shallow at low water.

Structures and condition

Vessels berth against the quay that extends 60m from the end of the linkspan. The quay wall is formed of straight sheet piled wall with timber piles faced with plastic rubbing strips. Significant amount of corrosion can be seen.

The terminal has a maximum available berthing length of 50m, a water depth (below CD) of 5 - 7m and a tidal range of 4m.

Figure 2.8 Eday Backaland Pier Figure 2.9 Current Eday Power Infrastructure

The Eday harbour consists of an 11kV connection within the harbour as shown on Figure 2.9. There is a 33kV overhead line approximately 5km from the port. The requirements for the charging stations or hydrogen electrolysers have the option of linking to the existing 11kV connection and installation of a new transformer at the harbour.

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2.5.6 Sanday – Loth Pier

Terminal Overview

The Loth Pier is located to the south of the island of Sanday. The terminal provides Orkney Ferry services to Kirkwall, Stronsay and Eday as part of the Outer North Isles ro-ro ferry service. The pier extends about 200m west-northwest and then 130m north from the shore in a small inlet.

The berth is well protected and can be used for overnight berthing in the summer months, depending on the ferry schedule.

Structures and condition

Vessels berth against the quay that extends 70m from the end of the linkspan. The quay wall is formed of a cylindrical flat pan sheet pile structure with timber piles faced with plastic rubbing strips.

The maximum available berthing length is 50m with a water depth (below CD) of 3 - 7m and a tidal range of 4m. During berthing, vessels turn in the lee of the quay 90% of the time. However, sometimes this manoeuvre can be depth restricted, although there is enough depth at berth.

A significant amount of corrosion can be seen on the pier.

Fuel is available for members of the Orkney Marine Fuel Co. from a bunded tank located on the pier.

Figure 2.10 Sanday Loth Pier Figure 2.11 Current Sanday Power Infrastructure

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2.5.7 Stronsay - Whitehall

Terminal Overview

The Whitehall terminal is located to the north-east of the island of Stronsay and provides Orkney Ferry services to Kirkwall and Eday as part of the Outer North Isles ro-ro ferry service. The extended quay provides a berth protected from the east, albeit with some exposure to the north. Ferries can safely overnight in summer months if needed, to suit their schedule.

Structures and condition

Vessels can berth against the quay that extends 60m from the end of the linkspan. The quay wall is formed of a straight sheet piled wall with timber fender piles faced with plastic rubbing strings. It has a maximum available berthing length of 50m with a water depth (below CD) of 1 - 4m and a tidal range of 4m.

A significant amount of corrosion can be seen on the quay.

Because the berth and its approach can be shallow at low water, dredging is carried out as needed. The approach channel is marked with buoys that have to be moved from time to time. There is a draught restriction of 3.5m.

There are no formal lanes for parking although there is about 150m available for a single lane on the quay leading up to the berth.

Fuel is available for members of the Orkney Marine Fuel Co. from a bunded tank located on West Pier, 0.22 miles to the north-west.

Figure 2.12 Stronsay Whitehall Pier Figure 2.13 Current Power Infrastructure at Stronsay Harbour

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2.5.8 Westray – Rapness

Terminal overview

Rapness is located to the south of the island of Westray. The terminal provides Orkney Ferry services with Kirkwall as part as the Outer North Isles ro-ro service.

Structures and condition

Both ro-ro and conventional cargo handling is available at the terminal. It has a maximum available berthing length of 50m, a water depth (below CD) of 2 - 5m and a tidal range of 2m.

Figure 2.14 Rapness Pier in Westray Figure 2.15 Current Power Infrastructure at Rapness

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2.5.9 Westray – Pierowall

Terminal overview

Pierowall is located to the north-east of the island of Westray. The terminal provides Orkney Ferry services to Papa Westray as part of the North Isles ferry service.

Structures and condition

There are no linkspan facilities available and cargo is handled the conventional way.

The maximum available berthing length is 50m and the water depth (below CD) is 2 - 5m.

Fuel is available for members of the Orkney Marine Fuel Co. from a bunded tank located on the pier.

Figure 2.16 Pierowall Pier in Westray

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2.5.10 Papa Westray – Moclett Pier

Terminal overview

Moclett Pier is located to the south of the island of Papa Westray. The terminal provides passenger service to Pierowall (Westray) and ro-ro service as part of the Outer North Isles ferry service to Kirkwall.

Structures and condition

No ro-ro facility is available. Cargo is lifted on and off the ferry using a crane mounted on the vessel.

The maximum available berthing length is 75m and the water depth (below CD) is 1 - 3m.

Figure 2.17 Papa Westray - Moclett Pier Figure 2.18 Current Papa Westray Power Infrastructure

Papa Westray harbour is also served by an 11kV overhead connection. This option is likely to require a step down transformer to supply appropriate voltages to the potential options.

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2.5.11 Tingwall Pier

Terminal overview

Tingwall Pier is located to the north of the mainland of Orkney. The terminal provides Orkney Ferry services to Rousay and Wyre.

Structures and condition

The pier is of sheet pile and concrete construction with limited fendering available. The hard ramp is used by ro-ro ferries and has a solid quay wall alongside.

The maximum available berthing length is 28m and the water depth is 1.5 - 3.5m.

Fuel is available for members of the Orkney Marine Fuel Co. from a bunded tank located on the pier.

Figure 2.19 Tingwall Pier

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2.5.12 Rousay – Trumland

Terminal overview

Trumland Pier is located to the south of the island of Rousay. The terminal provides Orkney Ferry services to Tingwall, Egilsay and Wyre. The berth is sheltered so vessels can berth overnight. In a south-westerly storm, vessels can gain further shelter by berthing on the eastern side of the quay. Quays can become submerged at very high tides, which delays the service.

Structures and condition

The ramp has a solid quay wall alongside. The maximum available berthing length is 28m and the water depth (below CD) is 1 - 4m.

Figure 2.20 Rousay Trumland Pier

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2.5.13 Egilsay

Terminal overview

Egilsay Pier is located to the north-west of the island of Egilsay and provides the terminal for Orkney Ferry services to Tingwall, Rousay and Wyre.

There are two break-waters and the sea can be choppy between them at times. The water depth is adequate for landing craft but might not be for larger vessels.

Structures and condition

Vessels berth against a hard ramp which has a solid quay wall alongside on both sides.

The maximum available berthing length is 28m with a water depth (below CD) of 1 - 2m.

Figure 2.21 Egilsay Pier

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2.5.14 Wyre

Terminal overview

Wyre Pier is located to the north of the island of Wyre. The terminal provides Orkney Ferry services to Tingwall, Rousay and Egilsay.

Structures and condition

The terminal is well constructed but has limited shore facilities. Vessels berth against a hard ramp.

The maximum available berthing length is 28m and the water depth (below CD) is 1 - 3m.

Figure 2.22 Wyre Pier

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2.5.15 Stromness – South Pier

Terminal overview

Stromness Pier is located to the south-west of the mainland of Orkney. The terminal provides Orkney Ferry passenger services with Graemsay and Moaness (Hoy).

The berth lies in a sheltered position within the harbour.

Structures and condition

Vessels are accessed by steps and there is limited space on the quayside which is cluttered. A pontoon would improve access to the vessel.

The maximum available berthing length is 135m and the water depth (below CD) is 3 - 6m.

Cranes are available and there is a garbage disposal option. Gas oil is available from road tankers, there is no local supply of fuel oil.

Figure 2.23 Stromness Harbour

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2.5.16 Graemsay

Terminal overview

Graemsay Pier is located on the east coast of the island of Graemsay and provides Orkney Ferry services to Stromness and Moaness (Hoy).

The quay berth is solid and lies on the sheltered northern side of the harbour.

Structures and condition

Graemsay Pier is of sheet pile and concrete construction with diagonal rubber fendering. Passenger access is by steps and cargo is handled by LoLo. Passenger/Cargo segregation could be improved and there are very limited shore facilities.

The maximum available berthing length is 20m and the water depth (below CD) is 2 - 5m.

Figure 2.24 Graemsay Pier

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2.5.17 Hoy - Moaness

Terminal overview

Moaness Pier is located to the north-west of the island of Hoy. The terminal provides Orkney Ferry services to Graemsay and Stromness.

The terminal can be exposed to north-western and eastern gales, which means that berthing is unavailable approximately five or six times annually.

Structures and condition

The quay is curved in plan and of solid construction with the berth located on the northern side, and has limited fendering. The maximum available berthing length is 20m and the water depth (below CD) is 1 - 2m. The vessels‟ belting gets above deck at highest tides and there is not enough water depth at lowest tides. An extension of 12m and an additional height of 1.5m have been suggested to remedy this.

There are limited parking and shore side facilities.

Figure 2.25 Moaness Pier on Hoy

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2.5.18 Houton (Orphir)

Terminal overview

Houton terminal is located on the south coast of the mainland of Orkney and provides Orkney Ferry services to Flotta and Lyness terminals.

The location provides reasonable shelter. It can receive swell from the west on occasion but this does not cause a problem on berth. The berthing depth can be restrictive at very low waters.

Structures and condition

Vessels berth against the quay that extends 45m from the end of the linkspan. The quay wall is formed of a cylindrical flat pan sheet pile structure with timber piles faced with plastic rubbing strips.

The maximum available berthing length is 53m, with a water depth (below CD) of 1 - 3m and a tidal range of 4m.

The pier is of sheet pile construction with limited fendering and is fitted with a ro-ro linkspan facility. The current vessel enters the berth either bow or stern in, depending on the size of loaded vehicles and the draught and linkspan trimming requirements. The height of the linkspan means that the berth can be unusable at extreme high tides. Because the current vessel was extended and floats higher in the water, it may need ballasting. Significant amounts of corrosion can be seen.

Figure 2.26 Houton Pier (Orphir)

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2.5.19 Flotta – Gibraltar Pier

Terminal overview

Gibraltar Pier is located to the north-west of the island of Flotta and provides the terminal for Orkney Ferry services to Houton, Lyness and Longhope.

The approach to the pier is reasonable but can become more difficult if there is swell from the north-west.

Structures and condition

A linkspan is located on the south side of the pier. There have been some recent modifications to the quay adjacent to the linkspan which may have been done to provide access for small craft.

The maximum available berthing length is 53m, the water depth (below CD) is 2 - 3m and the tidal range is 4m.

Significant amounts of corrosion can be seen.

Figure 2.27 Flotta Gibraltar Pier

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2.5.20 Hoy – Lyness

Terminal overview

Lyness Pier is located to the south-east of Hoy. It provides Orkney Ferry services to Flotta, Longhope and Houton terminals.

The location is well protected although it can be affected by swell from the south-east. It is not used for overnight berthing (the ferry is taken to Longhope for overnighting, where there is no ro-ro facility).

Structures and condition

The linkspan berth was added to the conventional berth which is of large concrete block construction. There is a considerable amount of disused infrastructure in the port.

The maximum available berthing length is 170m, the water depth (below CD) is 4 - 8m and the tidal range is 4m.

Significant amounts of corrosion can be seen.

Figure 2.28 Lyness Pier (Hoy)

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2.5.21 Hoy - Longhope

Terminal overview

The ferry can berth overnight as the location offers shelter.

Structures and condition

Fuel is available for members of the Orkney Marine Fuel Co. from a bunded tank located on the pier.

Figure 2.29 Longhope Pier (Hoy)

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3 FUTURE VESSELS AND FUEL TYPES OPTIONS

3.1 NATURAL GAS

3.1.1 Fuel Properties

The following will describe the use of both Compressed Natural Gas (CNG) as well as Liquid Natural Gas (LNG); both feasible states of natural gas. The main component of natural gas is Methane (CH4). Both of these states of natural gas are colourless and odourless; however an odorant can be introduced for ease of detection. As a result of its makeup there is zero sulphur emissions produced through its use and carbon dioxide (CO2) emissions are also significantly reduced compared to traditional Diesel fuel. It is for this reason CNG and LNG are recognised as among the cleanest fossil fuel available. Additionally, CNG and LNG can be substituted for biogas, which is seen as a renewable natural gas.

Manufacture

Natural gas has a very low energy density in its natural state. Compression and liquefaction are used to increase this in order to make storage and transportation feasible. The production of either CNG or LNG is not possible in Orkney. The entire future demand of these fuels would be imported.

Diaphragm compressors are a common method employed in the process of compressing natural gas. It relies on a number of compression stages through a series of chambers in order to reach the required density. Another method used is the reciprocating compressor which uses pistons driven by a cranks shaft to compress the gas.

The process of liquefaction of natural gas is done in order to produce a product that is easy to transport by road or sea; the liquid form of natural gas is the most efficient way to transport the fuel in such methods. Thus, the main purpose of LNG is to be able to deliver natural gas to customers where pipelines are not possible. After transport, the gas is often returned to a gaseous state before use.

In the production of LNG the gas is first “sweetened” in which impurities are removed. This would include the removal of water, acid gases (Hydrogen Sulphide (H2S) and/or CO2), heavy hydrocarbons and other particles that could have a detrimental impact during liquefaction. Liquefaction then occurs when the temperature of the sweetened natural gas is dropped to -160°C; at which point the volume that the natural gas takes up is now just 1/600th of that in gaseous form. It is at this temperature where LNG is at boiling temperature at atmospheric pressure (1 bar).

Current LNG infrastructure within the UK would result in the necessity to transport fuel by road-based transport tankers from England. Orkney‟s closest supply of natural gas is the pipeline that lands at St. Fergus, near Peterhead, from fields in the North Sea7. This would require additional LNG infrastructure in the vicinity of St. Fergus to make the gas transportable and to allow its utilisation as a fuel.

Cost

Understandably the unit cost of CNG and LNG will follow the market value of natural gas. Figure 3.1 below illustrates the changing market value of natural gas over the last five years. This highlights that natural gas is experiencing some of the lowest prices in recent years. This is a result of the development of shale gas across the world driving the cost down. This will also directly result in lower cost for LNG and CNG.

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Figure 3.1 Natural Gas Market Price8

Figure 3.2, below, details work conducted by University College London (UCL) to project the changing cost of marine fuels. The figure shows that LNG is predicted to remain at a very steady unit price over the coming decades. It is the only fossil based fuel that does not have an ever increasing cost year on year. Unfortunately this work did not take CNG in consideration. It was also not possible to obtain the same level of cost prediction for CNG, but it can be reasonably assumed a similar trend to that of LNG.

Figure 3.2 Global Commons fuel price forecasts9 (HFO: Heavy Fuel Oil, MDO: Marine Diesel Oil, LSHFO: Low Sulphur Heavy Fuel Oil, LNG: Liquefied Natural Gas)

The Danish Maritime Authority produced a study placing the approximate cost of LNG infrastructure with a 10 year payback range between £150.04/tonne (small scale) and £91.26/tonne (large scale)10.

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Three significant factors in determining the viability of a LNG terminal are:

 The capacity of closest terminals;

 Regional demand for LNG by the maritime sector; and

 Demand from additional sectors (power generation, road transport, etc.).

Even though this work was conducted for LNG, there would be close similarities with CNG.

It is recognised that purpose built vessels fuelled from LNG are 10 - 25% more expensive than vessels fuelled from diesel. The necessary insulated storage tanks result in the greater costs of these vessels. Growing interest in LNG as a maritime fuel has been attributed to the more stable nature and lower cost of LNG fuel compared to conventional marine fuel. As a result, it is estimated that an operator of these would still expect a period of five to eight years to recover these additional costs11.

Safety, Codes and Standards

Examples of regulations concerning the use of natural gas include:

 IMO Interim Guidelines on LNG as fuel MSC 285(86);  IMO draft International Code of Safety for Ships using Gases or other Low-flashpoint Fuels (IGF Code);  NNV GL rules for gas as ship fuel:

o DN rules for classification of ships, Part 6, Chapter 13 Gas-Fuelled Ship Installations; and

o GL rules for Classification and Construction, VI, 3, 1 Guidelines for the Use of Gas as Fuel for Ships.  DNV GL Recommended Practice RP-0006 on the development and operation of LNG bunking facilities;  DNV GL. Standard. DNVGL-ST-0026:2014-04. Competence related to the on board use of LNG as fuel12;  ISO technical specification for supply of LNG as fuel to ships (ISO TS 18683)13; and  IMO: International Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk. The International Gas Code (IGC)14.

Storage

Storing natural gas in a compressed form will increase its energy density by 200 times, whereas in liquid form this increases the energy density by approximately 600 times. In order to achieve the density of LNG natural gas is typically cryogenically cooled to -160°C. Due to a phenomenon known as auto refrigeration LNG will remain at cryogenic temperature with a sealed tank at constant pressure. In this state LNG is suspended in a state of “boiling”. This will remain the case as long as the LNG boil-off vapour is allowed to vent out of the tank. This will ensure the tank remains at a constant pressure. The length of time at which the tank can hold vaporised LNG before having to vent it is called the “Holding Time”. Regulations dictate this time, and in the United States for example this time is five days15. At sea this boil-off can be used as fuel, and on land the boil-off can be injected into a gas grid network, if one is available16. If the LNG being stored within the tank is not to a certain level of purity of methane then the constant boil- off during storage will result in the release of a greater portion of the desired methane compared to the other impurities. This is referred to as “weathering”17.

This limitation in the storage of LNG for prolonged periods of time is not applicable to the storage of natural gas in compressed gaseous form. Storage of natural gas as CNG is also technologically simpler than LNG. This is an alternative that is also found in applications around the world. CNG does not benefit from as high an energy density as LNG, but it does allow the exclusion of processes to lower its temperature; which would provide comparative cost

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savings to its production. However, CNG is typically stored at pressures between 200 and 250 bar in order to make it viable for transport and use18. These tanks are significantly heavier due to reinforcement and bigger due to the lower energy density. An additional benefit of CNG is that it can remain stored indefinitely without any energy loss19. This means that a vehicle fuelled by CNG can remain unused for longer than an equivalent LNG vehicle; which would start venting vaporised fuel after a number of days. The capacity of a tank to store CNG is also subject to temperature of the gas. For example, if a tank is allowed to warm up for any reason the gas inside will expand as it also warms up; thus reduce the energy density. This characteristic also limits the rate of refuelling. If the rate of refuelling is too high then the gas will again expand due to warming20.

Table 3.1 describes the different types of CNG storage tanks available and their comparative weight and cost. The general rule of thumb being that the lighter tanks are more expensive. These tanks will all contain the gas until it is required and result in no energy loss during storage; unlike the storage of LNG, as described in the previous paragraphs.

Table 3.1 CNG Storage Tank Comparison21

Type Construction Weight (%) Cost (%)

Type-1 All metal (aluminium or steel) 100 40

Type-2 Metal liner reinforced by composite wrap (glass or carbon fibre) around 55-65 80-95 middle (hoop wrapped)

Type-3 Metal liner armoured by composite wrapping (carbon fibre or glass) 25-45 90-100 around the complete cylinder (fully wrapped)

Type-4 Plastic gas-tight liner reinforced by composite wrap around entire tank 30 90 (full wrapped)

Transportation

Traditionally CNG was used when a fuel was required and piped network was available, such as main gas grid. LNG was then used as a more dense state of natural gas that was more financially feasible for road or sea transport, bridging the gaps between CNG supply and energy demand.

Both LNG and CNG can be transported by road tanker where required. This would generally only be required when a piped network is not possible. If the scale of demand for either fuel was not sufficient for minimum shipping quantities then this would need to be met by road tankers. Figure 3.3 below shows a picture of the road tanker utilised in the refuelling of the Glutra with LNG.

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Figure 3.3 LNG Refuelling of Glutra22

There are generally three methods of refuelling that are viable for natural gas vessels. The diagram below (Figure 3.4) demonstrates these for LNG, but CNG would be carried out in approximately the same manner:

1. Ship-to-ship transfer;

2. Truck-to-ship transfers

3. Refuelling directly from shore side storage facilities.

The latter two options would be expected for Orkney Ferries‟ vessels, depending on the location of the vessel during refuelling. It is unlikely that the scale of demand in Orkney would be met by an additional bunking vessel.

Figure 3.4 Natural Gas Bunkering Solutions23

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All around the world the majority of the transportation of LNG is done by sea. Double-hulled tankers are used for this. The inner hull is designed to remove the chance of leakage in cryogenic states, and the outer hull is designed to absorb impacts to the structure and remove risk to the ship and crew. Ships designed to transport LNG are constantly monitoring for signs of leakages and equipment designed for this can detect holes within the insulation the size of a pin head24.

Due to the properties of LNG, in comparison to that of conventional diesel, a vessel carrying the fuel would require 150% the storage capacity to carry the same level of energy. However, since LNG is lighter, it would weigh approximately 24% less.

As the UK does not currently own or operate a liquefaction plant the country solely relies upon imports of LNG for its current demand. Three terminals are currently operation. These are:

 South Hook (Pembrokeshire), operated by Qata Petroleum and ExxonMobil;  Isle of Grain (Rochester, Kent), operated by National Grid Grain LNG;  Dragon (Pembrokeshire), operated by BG Group and Petronas; and

In comparison to the established LNG bulk shipping industry, the CNG bulk shipping industry is still forming. World Maritime News reported in 2014 the construction of the world‟s first CNG carrier; with estimates at the time for completion in May 201625. As such it would be expected that any requirement for CNG in the near future would be through the delivery by road tankers or the regasification of a LNG supply.

Market

The cost competiveness of natural gas predominantly comes from being cheaper than current conventional marine fuels. It has been predicted that this will become more lucrative when comparing the growing price of these conventional fuels and the lower rate of growth in price and the increase of the more abundant reserves of natural gas. Additionally, the price of LNG has remained relatively stable in comparison to conventional oil fuels. Natural gas reserves around the world are predicted to be greater than those of crude oil. For example Qatar, which has relatively low oil reserves compared to its neighbouring countries, has natural gas reserves that could potentially last for 160 years at current production levels.

With reference to the utilisation of natural gas vehicles (NGVs), in 2014 the global number of NGVs was estimated to be approximately 16 million, with a reported annual growth of 30%26. Countries like the United States already have significant networks of CNG and LNG fuelling stations for road based vehicles. Examples in Europe include Germany, operating in excess of 900 CNG stations; Italy, with approximately 810 stations; and the Netherlands, with over 130 stations. Currently, the UK is lacking behind. However a number of projects targeting the use of heavy-duty fleets exist. These are described below in Table 3.2.

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Table 3.2 Examples of LNG Projects in the UK27

Company Number of Total Fleet Description Start Date Vehicles

DHL 101 7,500 Dual-fuelled LNG vehicles refuelled by 2011 BOC at DHL‟s Bawtry depot

John Lewis 8 2,700 (570 Dual-fuelled vehicles. 35-55% CNG 2012 tractors) linked to biomethane plant

Muller Wiseman 21 increase to 40 1,000 Dual-fuelled vehicles. 55% LNG. 2 LNG 2007 stations operated by Chive

Stobart 5 increased to 25 2,350 Dual-fuelled vehicles. 65-70% LNG 2010

Tesco 35 2,000 BioLNG/LNG (15/85) supplied by 2013 GasRec to Daventry depot

Although the number of LNG fuelled vessels continues to increase, there are many ship-owners that are not ready to commit to the move from the more conventional marine diesel fuel. However, under international standards a number are making new vessels “LNG-ready” for future conversion28.

In comparison, the number of CNG fuelled vessels is very minor. As discussed previously, the lower energy density has hindered CNG from competing against LNG. The case study below describes the emergence of CNG as an approved fuel in the 1980s. Since this time only a small number of vessels, most of which have been for demonstrative purposes, have been deployed. It was not possible to obtain an exact number still in operation today.

Case Study

The Accolate II (Figure 3.5), a limestone carrier, is recognised as the first class ship to be approved to be fuelled by CNG. Originally constructed in 1982, the vessel operates out of Adelaide, South Australia, and is still in operation today. The fuel is stored on-board in 21 vertical bottles (0.5m by 9m) at 160 bars, with a nominal capacity of 1,500 L29. It was assessed that the additional capital expenditure due to the natural gas systems would require just three years to payback as a result of the cheaper fuel30.

Figure 3.5 Accolade II31

An investigation by Durham University looked into the prospect of an ever-increasing globalisation of the natural gas market and how this would impact upon the UK. Their investigation acknowledged that to the greater extent that this

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growing market is a positive change across the world, but that it also exposes some countries to the highs and lows of the international trading markets. The report highlighted that the UK remains susceptible to changing fluctuating international demands. For example in 2011 the UK import of LNG reached a peak when the country took delivery of fuel originally intended for the United States, but was diverted to the UK market as a result of the growing Shale Gas market within the US making LNG less financially lucrative. This level of import then fell away in light of the earthquake and tsunami event in Japan in 2011, which in turn resulted in the removal of nuclear power generation. LNG fuel was sent to Japan to provide power generation capacity. As a result of this the UK imports dropped; this trend continued through 2012 and 201332. Additionally, the report went on to highlight a correlation between oil prices and LNG imports. As oil prices dropped significantly in 2014, LNG imports became more frequent.

3.1.2 Direct Burning Propulsion

Performance

The use of natural gas is not a limiting factor for marine traffic. As the case study below highlights, it is technologically feasible to produce high speed passengers vessels solely fuelled from natural gas.

Case Study

The vessel, Francisco (Figure 3.6), is claimed to be the world‟s first high speed car and passenger ferry. It has the capacity to carry 1000 passengers as well as 150 cars, while reaching speeds greater than 50 knots. The vessel has the capacity to operate on LNG as well as conventional marine fuel. The catamaran hull is propelled by two Wartsil LJX 1720 SR waterjets which are driven by a pair of GE Energy‟s LM2500 2.2MW gas turbines. The ferry was launched in Tasmania, Australia, in late 2012, and passed sea trails in 2013. The vessel operated between Buenos Aires, Argentina, and Montevideo, Uruguay33.

Figure 3.6 Francisco

Technical Maturity and Deliverability

LNG as a marine fuel is a mature technology. There is a steadily growing number of purpose built vessels powered by LNG since the construction of the MF Glutra in 2000; the world‟s first purpose built LNG fuels ferry. Opting for purpose

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built vessels allows for greater flexibility in the design to match the particular requirements of the fuel; such as the lower energy density.

Case Study

The MF Glutra (Figure 3.7) was built in order to make use of the country‟s production of natural gas, and also reduce the dependency on diesel fuel. The vessel vaporised the LNG fuel and supplied this to four 675kW engines; which in turn powered a corresponding number of 720kVA electrical generators. The two 1MW motors supplied power to twin 34 propeller thrusters at each side of the vessel . Owing to the change in fuel, Nitrous Oxide (NOx) emissions have been tested to be approximately 80% lower than that from conventional diesel fuel. The Glutra was awarded “Ship of the Year 2000” by Skipsrevyen Magazine for its innovative design at the time.

Figure 3.7 MF Glutra35

Retrofitting natural gas propulsion systems in place of diesel fuelled systems is also technically feasible. But it is understood that this would need to be assessed on a case by case basis as an existing vessel would have very little flexibility in design36. The case study below discusses the successful retrofitting of the Bergen Viking, a 95m tanker, with LNG propulsion in 2015.

Case Study

The Bergen Viking (Figure 3.8), a 95m tanker which was converted in 2015 from diesel-electric to LNG-electric propulsion37. This involved the removal of four of the six original diesel motors with two larger LNG generators sets. The dual tank configuration allowed for bunkering of a greater portion of fuel or the utilisation of dual fuel.

Figure 3.8 Bergen Viking38

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The on-board technical maturity of CNG is comparative to that of LNG; CNG has been in use for a number of decades. However, the delivery of CNG to the point of demand still requires additional development.

Cost

Capital Cost

A study conducted by BC Ferries in Canada estimated that retrofitting a ferry could cost between CAD$10 - 50 million (£4.9 - 24.56 million). But a purpose built LNG fuel ferry could cost between CAD$60 - 150 million (£29.5 - 73.7 million)39.

A report produced by Lloyds Register estimate an approximate capital expenditure for direct LNG burning vessels at $1.65 million/MW. This would be the same cost for mono or dual fuel systems40.

UCL produced a report in 2014 investigating the drivers of novel fuels for shipping. With reference to the CAPEX of LNG direct combustion, storage is in the region of $1,200/kW (~£830/kW), engine costs in the region of $400/kW (~£277/kW) and complete vessel costs of approximately $1,750/kW (~£1,210/kW)41.

Swedish ferry operators Rederi AB Gotland have commissioned shipbuilders, Guangzhou Shipyard International, in China, to produce two ferries powered by LNG fuel. The vessels are due to arrive in Sweden in 2017 and 2018; each costing approximately SEK 1 billion (£80.25 million). The ferries will have the capacity to carry 1,650 passengers, as well as an unknown capacity for vehicles42.

There is little information available that specifically details the capital expenditure associated with purpose built CNG fuelled vessels. It is believed this is in partly due to the relatively novel nature of this technology and low numbers of vessels currently deployed. However, the configuration of CNG vessels would be similar to that of a combustion engine vessel operating with a dual fuel configuration. The main differences will be in the cost of the storage tanks; these will be relatively expensive compared to tanks for conventional marine diesel vessels.

Operational Cost

As found with the other methods of utilising LNG as a fuel, there are inherent cost savings found as a direct result of LNG being cheaper than conventional fuel. This is successfully demonstrated through the case study below, which describes a study conducted by BC Ferries into the potential cost savings of retrofitting their fleet of passenger ferries.

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Case Study

BC Ferries, in British Columbia, Canada, operate the MV Queen of Capilano (Figure 3.9). This ferry was built in 1991 and has the capacity to carry 100 cars and a total of 457 passengers and crew43. A study carried out by the company estimated that if this vessel were to be retrofitted to operate solely on LNG fuel then CAD$1.9 million (£0.93 million) would be saved in fuel cost annually. The company operates 12 vessels in the same class presenting potential savings nearing CAD$29 million (£14.24 million) each year44.

Figure 3.9 M.V. Queen of Capilano45

British Columbia, Canada, was also home to CNG powered passenger vessels. These were retro-fitted from conventional marine diesel fuel to dual-fuel engines. For example, the MV Klatawa was built in 1982 and then three years later it was converted to operate on CNG fuel. All gas storage and pipelines were positioned on top of the deck as mitigation to safety concerns. After a four year operation in this configuration it was deemed a financial success and the reduced operating cost would result in an eight year payback period. Further retrofitting of the MV Kullet with the lessons learnt from the MV Klatawa resulted in further cost savings that could result in a five year payback period46.

Market

LNG has been used as a fuel for the shipping since the 1960‟s. But this was solely by LNG carriers until 2000 when Norway built a LNG powered ferry. As described previously, the MV Glutra was the world‟s first LNG power ferry. As of October 2015, approximately 73 vessels powered by LNG operate around the world (73% in Norway, 14% in Europe, 7% in America and 7% in Asia & Pacific regions)47. Two years previously, this number was just 42. DNV GL has estimated that this could grow to 600 vessels by 202048. There are currently in the order of 80 LNG powered vessel projects confirmed around the world.49.

As worldwide interest in LNG fuel and associated technologies continues to grow so does the international capacity to produce it. In 2014 the global capacity of natural gas liquefaction was 301 Million Tonnes Per Annum (MTPA). This was up by approximately 10MTPA from 2013‟s global capacity50.

To date the UK has been slow in its uptake of LNG as a fuel for transport. It is currently lagging behind many countries throughout Europe and the rest of the world. As of the beginning of 2016 there are only five locations available for refuelling land-based transport; a planned station in Edinburgh being the sole location within Scotland51.

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With reference to the liquefaction plants, the UK does not currently operate one and depends upon imports of LNG for any local demand. Regasification terminals within the UK include the Isle of Grain terminal, the South Hook terminal and the Dragon terminal52.

Currently Qatar utilises its natural gas reserves and stands as the country with the greatest liquefaction capacity. Over the coming years, countries like Australia, America and Canada are making very significant investments into the industry in order to expand their own capacities. This is especially true for Australia who has projects with a combined capacity of 58MTPA planned by 2018; which will then stand as the largest global capacity held by a single country. The growing use of shale gas has provided the market with growing sources of Methane; the main component of LNG. Bio- gas can also be sourced from waste sites. The strong commitment to the industry world-wide indicates strong confidence in the market for LNG and the security of supply.

Environmental Implications

In the use of LNG and CNG as fuels, the production of CO2 is reduced by 30% and particle emissions are nearly removed completely, compared to the use of conventional fossil fuels. When burned in a gas turbine to produce electricity, Sulfur dioxide (SO2) emissions are effectively eliminated and the majority of CO2 emissions are also removed53.

Additionally, if containment of LNG is lost and a spill occurs then there would not be any mixing with water or soil. The gas would vaporise and evaporate into the air. The gas would form a white visible cloud as it reacted with water in the air. In the case of CNG containment failure the gas would dissipate vertically since methane is lighter than air. In an open space this would result in minor safety concerns, as methane is a Greenhouse Gas (GHG) and has an environmental impact. However, it should be noted that Orkney does have significant farmer community with cattle numbers in excess of 100,000. This would have a much larger contribution to quantities of methane than fuel leakages.

Limitations

Many of the limitations associated with CNG have been discussed previously. These principally come down to the low energy density and the requirement for additional development in delivery infrastructure.

The perceived limitations in the utilisation of LNG as a storable and transportable energy supply include the necessity to ensure it remains at constant pressure while preserved at constant boiling point (-160°C). This will involve boil-off and deterioration upon the quality of the LNG over a prolonged period of time. Mitigating this would involve ensuring a relative correlation between supply and demand; and minimising the quantity of LNG needed in storage.

The natural gas shipping market is still developing; this is especially true in the UK. Neighbouring countries are currently utilising the benefits of this low emission fuel and there stands a potential for the UK to profit from this by providing a fuel hub for passing vessels through Orkney‟s strategic position between Europe and the Atlantic. This would require significant capital expenditure with an understanding of financial return.

Suitability

The use of natural gas as a fuel for the inter-island ferry fleet is technologically feasible and could significantly impact upon the fleets current exhaust emissions. Additionally, a CNG or LNG infrastructure for the ferry fleet in Orkney could also produce an infrastructure for road transport in Orkney. This could accelerate the regions move from conventional petrol and diesel fuelled vehicles, and also attract vehicles owners who are currently reluctant to move towards electric vehicle options. As mentioned previously, there is also the potential that if Orkney embraced LNG to a large enough scale then this would provide services to the maritime industry on a greater scale through an energy hub for transiting

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shipping vessels. However, embedding an natural gas infrastructure in Orkney would be capital intensive and committing to this option would have to be decided upon with care.

3.1.3 Natural Gas Hybrid Propulsion

Natural gas hybrid vessels operate similarly to other hybrid vehicles, in that they would be primarily fuelled by CNG or LNG, but also utilise energy storage to maximise the efficiency of the combustion process of the fuel. The case study below, of the Texelstroom, describes such a vessel.

Case Study

A Dutch ferry operator has rolled out the construction of a hybrid ferry powered from CNG. The vessel, the Texelstroom (Figure 3.10), also has the capacity to operate off ultra-low sulphur fuel. The fuel used will be combusted in order to provide power to the electric propulsion and 1.6MWh battery bank. An array of solar panels is also employed to provide a significant proportion of the hoteling power demand; thus reducing the power demand on the engine54.

Figure 3.10 Texelstroom55

Performance

The case study of the Viking Lady, below, describes the hybridising of its propulsion due to the vessels variety of operations and working conditions.

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Case Study

The FellowSHIP III research program, between DNV GL, Eidesvik Offshore and Wärtsilä, resulted in sea trials of the Viking Lady (Figure 3.11); claimed to be the most environmentally friendly vessel operating today. The hybrid electric engine is dual-fuel configuration which allows it to operate on marine diesel or LNG. A molten carbonate fuel cell provides additional power generation capacity. The fuel cell could be powered by LNG and the boil off from the LNG tanks56. The trial period for this fuel cell was completed in 2012 and is still in operation. Additionally a 450kWh lithium- ion battery levels out energy demand and acts as a buffer and covers the load variations. This results in higher fuel economy and emission savings57.

Figure 3.11 Viking Lady58

The Viking Lady operates in smooth waters off ports and harbours, and also experiences turbulent open-waters while supplying to offshore rigs and tankers. The capacity of the vessel allows it to transit through these conditions, service harbours and also operate using dynamic positioning capabilities. It has been reported that the on-board energy storage, in the form of a lithium-ion battery, allows for greater response time and less fluctuating loads upon the engines. During operations in and around harbours, the Viking Lady will operate solely on the battery which results in the more significant advantages of the propulsion configuration. Eidesvik Offshore, the company which owns the Viking Lady, has reported that they believe that all vessels in the future will have batteries and they do not believe they will build another ship without a battery on board59.

Technical Maturity and Deliverability

Hybridising natural gas vessels is still relatively new. The component parts are commercialised but the number of vessels deriving propulsion capabilities from either CNG or LNG power supplies and energy storage technologies are extremely low; only in the region of three or four are currently in operation. These exist in a prototype/demonstration fashion.

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Cost

Capital Cost

The 320kW fuel cell currently employed by the Viking Lady, which was installed in 2009 and has been in operation since, cost approximately €12 million (£9.12 million)60. The University College London‟s (UCL) Energy Institute now believes that unit costs for fuel cell technologies that can operate off LNG are in region of USD1,000/kW (£700/kW)61.

Carol Raucci of the UCL Energy Institute details that in 2014 the unit cost of a vessel propulsion system powered by a fuel cell running off LNG would cost approximately US$2,500/kW (£1,723/kW). This would be less than half the cost for an equivalent vessel fuelled by hydrogen, but more than the capital cost of a vessel with methanol as the primary fuel. In each example it is the storage medium that drives the difference in cost.

It was not possible to obtain capital costs associated with the hybrid version of CNG vessels. However it is expected that this would be similar to that of LNG vessels with the allowance of different fuel storage costs.

Operational Cost

It has been estimated that the capital cost associated with the fitting of a hybrid system will result in fuel savings that could potentially result in a payback period of a number of years. Operational costs will be dependent upon the circumstances of the vessel and the supply of fuel. But solely hybridising a vessel will reduce fuel costs by approximately 15%. An example of such a case is described in the case study below.

Case Study

Fannefjord (Figure 3.12), operated by Fjord1 in Norway, is the world‟s first ferry operating completely on LNG and also complimented by on-board battery energy storage. It was originally constructed in 2010 and retrofitted from a gas- electric vessel and re-entered active operation in January 2016. It is estimated that this conversion will result in a 15% reduction in fuel consumption compared to pre-retrofitting. The ferry has the capacity to carry 390 passengers and 125 cars. The battery fitted to the vessel is a 410kWh Lithium Polymer batter produced by Convus Energy62.

Figure 3.12 MF Fannefjord63

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Market

A significant movement is being made towards LNG as a fuel for maritime transport; as previously discussed DNV GL estimated in the region of 600 LNG fuelled vessels to be in operation by 202064. This is also the case for hybridising vessels with electrical energy storage. It is very reasonable to assume that this type of vessel will have a significant presence across different sectors, including freight (case study below) in the coming years. It is unclear at this time how the market is moving towards hybrid CNG vessels with plans for only the Texelstroom, discussed previously, currently in development.

Case Study

Seaspan Ferries have ordered the production of two electric hybrid ferries (Figure 3.13). Both ferries will have the capacity to operate on either diesel or LNG fuel. On-board energy storage will come in the form of 546kWh advanced Lithium-ion polymer batteries. The ferries are being constructed in Spain but are due for operation between Vancouver and Vancouver Island in 2016. They will operate solely for the transportation of freight trailers65.

Figure 3.13 Seaspan LNG Hybrid Ferries

Environmental Implications

Hybrid vessels fuelled from natural gas have the benefit of maximising the efficiency of the combustion engine while capturing excess energy, and feeding shortfalls in power, from on-board energy storage. Doing this will reduce the quantities of fuel burnt and thus the associated emissions. As previously discussed, LNG and CNG already have a significantly lower footprint than conventional marine fuels, and hybridising this with an energy storage medium improves upon this further.

Limitations

Limitations around the use of LNG as a fuel for hybrid vessels include the reach of the current infrastructure for supplying the fuel. Within the UK LNG is imported mainly to the south of the country and then any supplies to the north of Scotland would have to be transported by road. Transporting this fuel in this manner retracts from the effective environmental benefits of employing the fuel. This would also be the case for CNG, but with the additional impact due to the lower energy density in this state. This would result in greater transport requirements to match the same quantity energy as LNG.

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Just as with conventional vessels fuelled by natural gas, the storage of the fuel would be a considerable impact to the design. The larger tanks compared to marine diesel, the time limit before venting of LNG boil-off and the low energy density of CNG would affect the design flexibility and operating parameters of a vessel.

Suitability

In reference to performance, LNG hybrid vessels already prove they are more than capable to operate effectively in all manner of conditions; this is especially the case with the Viking Lady. As long as an LNG infrastructure can be effectively introduced parallel to the introduction of any LNG fuelled vessels, then Orkney could significantly benefit from this type of passenger ferries. Emissions content would be significantly lower, fuel economy would be maximised, lower maintenance requirements due to less loading on the engine and favourable manoeuvrability from electric propulsion.

Just as previously discussed with CNG vessels, there is potential for a hybridised version to be feasibly operated in Orkney. The inclusion of on-board storage allows greater flexibility to fit a greater number of conditions found among the islands.

The main limiting factor would be the LNG fuel. The fuel is a finite fossil fuel with emissions associated in its combustion and significant capital and operational costs associated with the introduction of the fuel to Orkney. Movements towards any LNG fuelled vessels would have to be taken with an educated idea of risks, returns and future proofing of the technology.

Another factor limiting this would be whether the additional expense of on-board energy storage and the management system allow the CAPEX of the whole vessel to remain within an acceptable limit for the route it is being considered for.

3.2 BIOFUELED SYSTEMS

Biofuels are made from biomass or bio-waste material, using the biological carbon fixation phenomenon. This process consists of taking inorganic carbon (gaseous or aqueous) and transforming it into organic compounds contained in the material. In biofuels, the fixation occurs in months or years, whereas in a fossil fuel it occurs over thousands or millions of years. Biofuels can be in the form of hydrocarbons, alcohols or gas and are used as substitutes for liquid and gaseous fossil fuels such as petroleum fuels (gasoline, paraffin, kerosene, diesel, LPG, crude oil).

3.2.1 Fuel Properties

There are two different categories within biofuels. First generation biofuels are usually made from edible portions of plants whereas second generation are derived from non-edible feedstock. The properties of these biofuels are shown in

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Table 3.3.

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Table 3.3 Biofuels characteristics66

Fuel type Feedstock Energy density (MJ/kg)

First generation fuels

Bioalcohol Starches from wheat, corn, sugar cane, molasses, -Ethanol potatoes, other fruits 30 -Propanol 34 -Butanol 36.6

Biodiesel Oils and fats including animal fats, vegetable oils, 37.8 nut oils, hemp, algae

Green Diesel Made from hydrocracking oil and fat feedstock 48.1

Vegetable oil Unmodified or slightly modified -Castor oil Chemically identical to fossil fuels diesel 39.5 -Olive oil 39 -Fat 32 -Sunflower 40

Bioethers Dehydration of alcohols N/A Additives to other fuels that increase performance and decrease emissions, particularly ozone

Second generation fuels

Cellulosic ethanol Made from wood, grass, inedible parts of plants

Algae-based biofuels More expensive than other biofuels but can yield 10 Can produce any of the fuels - 100 times more fuel per unit area mentioned above

Biohydrogen From algae breaking down water 700 (compressed to 700 times atm pressure)

Methanol Inedible plant matter 19.7

Dimethylfuran From fructose found in fruits and some vegetables 33.7

Fischer-Tropsch biodiesel Waste from paper and pulp manufacturing 37.8 Chemical reaction that makes hydrocarbon from CO and H

Solid Biofuels Everything from wood and sawdust to garbage, -Wood agricultural waste, manure 16 - 21 -Dried plants 10 - 16 -Bagasse 10 -Manure 10 - 15 -Seeds 15

Biogas Produced via anaerobic digestion of organic wastes See sections on hydrogen and Bio-hydrogen LNG Bio-methane

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Manufacture

First generation biofuels are made from grain, seeds and sugar crops. They only use a small portion of the plant material, usually edible, and are produced via simple processing. Fermentation of starches (corn, wheat, potatoes) and sugars (sugar cane or sugar beets) can produce ethanol or butanol fuels, and transesterification of plant oils (rapeseed, soybeans, sunflower, coconut, palm, jatropha, vegetable oil, recycled cooking oil and animal fat) can produce biodiesels. The transesterification process is a chemical reaction occurring when alcohol is added to crude vegetable oil and which tears the fat molecules apart, leaving only the combustible hydrocarbons.

Second generation biofuels are made from non-edible feedstock such as crop residues or purpose-grown grasses and woody crops. They can be produced via biochemical (enzymatic hydrolysis) or thermochemical processes. Biochemical products are ethanol or butanol and thermochemical products are FTL (Fischer-Tropsch liquids), methanol, or dimethyl ether. Large-scale biomass gasifier technologies are commercially ready and can be combined with coal in electricity generation plants.

The different production processes and their outputs are shown in Figure 3.14.

Figure 3.14 First and second generation biofuels production processes in comparison with fossil fuels

Safety, Codes and Standards

Biofuels may be produced at the domestic scale (biodiesel from waste oil). In the UK, Waste Management License applies to biofuel production when there is more than 1,000L of waste cooking oil stored at one time. For non- commercial production, the guidance for storage is it must be done in containers that are strong enough and unlikely to burst or leak, and within a suitable secondary system to contain any fuel that escapes. Biofuel production systems must also meet the Control of Major Accident Hazards Regulations.

Other regulations:

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 EU CEN Fuel Standards, EN 14214 (fatty acid methyl esters/biodiesel), EN 15376 (bioethanol)  Renewable Energy Directive (RED, 2009/28/EC)  European Commission‟s White Paper Transport (2011)  Fuels Quality Directive (FQD, 2009/30/EC)  Control of Major Accident Hazards Regulations 1999  ATEX Directive  Pollution Prevention and Control Regulations 2000  Dangerous Substances and Explosive Atmospheres Regulations (DSEAR) 2002, the Management of Health and Safety at Work Regulations (MHSW) 1999, The Control of Substances Hazardous to Health Regulations (COSHH) 2002, the Manual Handling Operations Regulations (MHOR) 1992, and the Fire Scotland Act F(S)A 2005

 The Biofuels and Other Fuel Substitutes (Payment of Excise Duties etc.) Regulations 2004 (SI 2004/2065), Amendments 2007 (SI 2007/1640), (SI 2007/3307)  The Excise Warehousing (Energy Products) Regulations 2004 (SI 2004/2064)  The Warehousekeepers and Owners of Warehoused Goods Regulations 1999 (SI 1999/1278) („WOWGR‟)  The Hydrocarbon Oil, Biofuels and Other Fuel Substitutes (Determination of Composition of a Substance and Miscellaneous Amendments) Regulations 2008 (SI 2008/753)

Performance

Land-use efficiency for biofuels is measured in kilometres per year (km/yr) of vehicle travel achievable with the biofuel produced on one hectare. Starch-based first-generation biofuels have the lowest land-use efficiency, while sugar- based first-generation biofuels exhibit about double this efficiency and second-generation fuels about triple. Another way to measure land-use efficiency is to measure the annual yield per hectare (Figure 3.15).

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Figure 3.15 Potential outputs of biofuels per hectare per annum67

The energy balance of biofuels depends on the location of production: in 2008 in the USA, producing 1 unit of corn ethanol required 0.7 units of fossil energy while sugar cane ethanol in Brazil only required 0.1 unit of fossil energy per unit of ethanol. Moreover, the reduction of greenhouse gas (GHG) emissions associated with a biofuel replacing a petroleum fuel varies with the type of biofuel and production process. In general, first-generation biofuels provide low lifecycle GHG emission reductions, sugar cane ethanol shows a higher reduction and second-generation have a larger reduction potential.

In terms of fuel efficiency, one gallon of pure biodiesel (B100) has 103% of the energy contained in one gallon of gasoline (same for LNG) or 90% of the energy of one gallon of diesel. Ethanol and methanol are less efficient (a gallon of ethanol E100 has around 65% of the energy of a gallon of gasoline and one gallon of methanol represents 49% of the energy of a gallon of gasoline). However, for these three biofuels, blends are more efficient, the usual being B20 (20% biodiesel/80% diesel; 99% efficient compared to 100% diesel) and E10 (10% ethanol/90% diesel). Moreover, blending reduces damaging engines by decreasing the variation from diesel as far as fuel characteristics are concerned.

Storage

Gaseous products are very volatile and need to be compressed or liquefied to be stored. Biogas can be hydrogen or methane produced through digestion process. It will thus not be further discussed in this section as it is the same process as described for LNG and hydrogen (see sections 3.1 and 3.4 for further information on storage).

Liquid biofuels are relatively easy to store and quite stable. Normal acid proof storage tanks are suitable for biodiesel storage. However, deposits in the tank can cause clogging of filters. Biofuels degrade faster than conventional diesel

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due to ageing and oxidation, which can lead to an increase of the corrosion activity and the formation of deposits. High temperatures, sunlight and the presence of oxygen can speed up this process. Biodiesel with high levels of saturated fatty acids are more stable, like rapeseed based biodiesel. American studies estimate that the least stable biodiesel can be stored up to six to eight months. Oxidation preventive agents can also be added to the biodiesel to increase the storage time.

The fuels must be stored at a certain temperature depending on their cloud point; the temperature at which wax crystals start to form in the fuel. For example B100 should be stored at temperatures at least 8.3°C higher than the cloud point. Generally, storage temperatures of 7.2°C to 10°C are acceptable for most B100. However, some B100 fuels may require higher storage temperatures.

Transportation

Like storage, containers need to meet certain characteristics in order to reduce the risk of hazards. Biofuels can be transported via ship, rail and truck, with coloured diamond-shaped information placards. (Placards are part of an internationally harmonised system of communicating the dangers inherent in the transportation of hazardous materials. They also play a critical role in communicating the presence of hazardous materials to emergency responders, transport workers and regulatory enforcement personnel in the event of an incident).

Technical Maturity and Deliverability

First generation biofuels are already commercialised, with biodiesel and bio-ethanol at the front, as substitutes for transportation fuel. They can be used in standard engines but because of their different characteristics from conventional oil products, especially their viscosity and water content, blending with oil is advised to avoid damaging the engine. These blends are named according to their biofuel content; B20 and E10 contain 20% biodiesel and 10% ethanol blended with 80% and 90% conventional oil respectively. They can also be used pure but will require adapted engines.

Second generation fuels are not yet well-established on the global market. Even though they enable a higher land-use efficiency compared to first-generation biofuels as more plant material can be converted to biofuel, they also require more investments per unit of production and larger scale-facilities. They are mainly produced in industrialised countries, with capital-intensive technologies designed for large-scale installations and best economic achievement.

Maturity in the transport and shipping sector

Biofuels can be used in the transport sector in the form of biodiesel, bioethanol, biomethane, straight vegetable oil (SVO), dimethyl ether (DME), pyrolysis oil, hydrogenated vegetable oil (HVO) or some other derivation. Whichever form of biofuel is used, the application takes the form of drop-in fuels (i.e. used as direct substitution for current conventional fossil fuels and compatible with existing infrastructure and engine systems) or through new or redesigned infrastructure and systems. Technical problems, such as instability of on board stored fuel, corrosion and bio-fouling, arising from the use of certain biofuels in shipping are readily surmountable. Biofuel options in shipping are shown in Table 3.4.

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Table 3.4 Biofuel applications in shipping (International Renewable Energy Agency; IRENA 201568)

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Cost

Capital Cost

In the case of drop-in biofuels, the capital costs are low as they do not require large engine and infrastructure modification. The costs of infrastructure for biodiesel are about the same as the ones for petroleum diesel.

Methanol infrastructures however, are about six times as expensive, especially due to cost intensive storage tanks, according to a study made on buses69. There is currently one ferry in the world powered by methanol, see the case study below.

Case study

Stena Line launched in March 2015 the first methanol powered ferry, the Stena Germanica (Figure 3.16), in collaboration with Wartsila70. The ferry runs on the Kiel-Gothenburg route (about 225 Nautical miles) and cost 22M€ to build.

Figure 3.16 Stena Germanica

Operational Cost

Feedstock typically contribute to 80 - 90% of the (first generation) biofuel cost. Because prices of feedstock production vary, the price of biofuels is not stable. First generation biofuels cannot compete with oil prices unless they have subsidies; even sugar cane ethanol in Brazil which has evolved since the 1970s. In comparison, second generation biofuels have the potential for lower production prices as they can be made from lower-cost feedstock. Some fuel prices are gathered in Table 3.5.

Maintenance costs are slightly higher than for petroleum fuels; the estimation for methanol is about four times higher than for diesel/biodiesel. Moreover, due to the difference in efficiency, the volume of methanol fuel needed is twice more than diesel/biodiesel, which increases operation costs. Including maintenance, insurance and unexpected breakdowns costs into the operating costs, the increase is five times higher for methanol than for (bio-)diesel.

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Table 3.5 Estimated biofuel costs (from IEA 200771)

Average (in $/Litre of gasoline Best cost (in $/Litre of gasoline equivalent) equivalent)

Gasoline 0.3 - 0.4 (0.21-0.28 GBP)

Sugar cane ethanol 0.4 - 0.5 (0.28- 0.35 GBP) In Brazil: 0.3 free-on-board (0.21 GBP)

Maize, sugar beet ethanol 0.6 - 0.8 excl. subsidies (0.42- 0.56 0.4 - 0.6 with subsidies (0.28- 0.42 GBP) GBP)

Ligno-cellulosic ethanol 1.0 (0.7 GBP) Cost expected to reduce with process improvement, scaling up, waste feedstock

Biodiesel (in $/Litre of diesel Traditional transesterification of From animal fat: 0.4 - 0.5 (0.28- 0.35 equivalent) vegetable oil: 0.6 - 0.8 (0.42- 0.56 GBP) GBP) From lignocellulose: 0.9 (0.63) Potential reduction of 0.1 - 0.3 (0.07- 0.21 GBP)

Market

The most familiar use for biofuels is to substitute petroleum-derived transportation fuels. Ethanol in particular is well established for this purpose; it represented 50% of gasoline use in Brazil in 2006. Biodiesel made from oil-seed crops is the other well-known first-generation biofuel. Second-generation fuels are still being improved and are not yet competitive. Biofuel use in transport reached 4% of the fuel supply in the UK in 2014, but ethanol blending is limited at 4.75%. The Renewable Energy Association is pushing for E10 blends to help reach the 10% biofuel mandate set by the EU for 2020.

Other potential applications exist, such as cooking fuels which is especially relevant in rural areas in developing countries and have lower emissions of pollutants than solid cooking fuels (which can cause health damages). Heat can also be generated from biofuels. Projects in the UK include the use of biodigesters coupled with Combined Heat and Power (CHP) systems.

Environmental Implications

The use of fossil fuels in ships leads to emissions such as SO2, NOx and particulate emissions which can cause serious environmental and health issues. Using biofuels can reduce these emissions, but their combustion will still lead to some emissions (the combustion of biofuel with air as a reactant will lead to NOx emissions).

Biofuels are not carbon neutral. They can be considered to be a renewable energy because their combustion releases the same amount of CO2 that has previously been absorbed by the plants as they grow, thus not leading to any net increase in the concentration of CO2 in the atmosphere. However, fossil fuels are used when producing the raw material for biofuels, in particular in the fertilisers which release nitrous oxide, which is a very strong GHG. Moreover, some biofuels, like biodiesel, naturally contain sulphur which is oxidised during combustion, producing SO2. This gas dissolves in water to form an acidic solution which causes acid rain. Acid rain damages trees and buildings and increases the acidity of rivers and lakes which may jeopardise aquatic life survival. However, some sulphur can be removed from the fuel before it is used and SO2 can be filtered with powdered limestone.

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A study led by different European associations in 2007 stated that rapeseed based biodiesel could save 53% of GHG emissions compared to conventional diesel, taking into account the fertilisers and fossil fuels used in production. Second generation biofuels have significantly less emissions than first generation fuels, especially regarding nitrous oxide during production 72 . Biofuels are also biodegradable which is a great advantage compared to fossil fuels regarding environmental consequences in case of spills.

Limitations

Some ethical issues are of concern with the use of biofuels, such as the fact that some crops are grown only for biofuel production purposes while they could be used to feed people. This can cause food shortages and increases in the price of food, with impacts on food security in low-income food-importing countries. Moreover, it requires large amounts of land and water, and current energy-intensive agricultural practices are not energy efficient (net energy production far lower than gross energy input).

Other limitations may be the area and climate required to grow the targeted biomass. By driving expansion of agriculture into areas of high carbon stock (such as the Amazon rainforest), the emissions resulting from land-use change may outweigh any GHG savings the biofuels are able to offer. This also has an impact on the environment with the loss of specific habitats and species due to massive deforestation in order to plant biofuel crops (palm oil plantations in Indonesia).

Suitability

Biodiesel can be made at home using waste oil and fat73. This represents an opportunity for Orkney: such waste fat could be collected from households and transformed in a community plant to produce biodiesel. There is also some potential for biogas production via anaerobic digestion of organic waste, especially from food processing infrastructures (Table 6.3).

Algae are another source of biomass which can produce significant amounts of biofuels and which could suit Orkney, although habitat impact assessment should be carried out. However, this technology is not fully mature.

Additional Case Studies: Bio-ethanol and biodiesel are the most widespread biofuels, with the latter regarded as the most similar to ship fuel. Pure plant oils are also suitable for ship machinery running on heavier diesel oils. DME, biogas and wood-based pyrolysis oil are still upcoming technologies but may be suitable for new ships.

Some past projects74:

 A Canadian bioship project in 2006 showed the viability of using biodiesel B20 to run ships.  Maersk and Lloyd‟s marine tested biofuels on engines in 2010 - 2011. The fuels tested were biodiesel FAME (fatty acid methyl esters) blends up to 100%. The study proved the feasibility of FAME use in marine diesel engines.  In 2011, a consortium including Deen, PON Power and several other companies started a project to use bio-LNG for inland shipping.

 STX Europe Group, a European commercial shipping company, ordered in 2011 a ship that permanently runs on different types of liquid biofuels. The ship was built in Finland in 2012.

Current projects:

 GoodFuels Marine, Boskalis and Wartsila joined in 2015 in a two-year pilot project in the port of Rotterdam to offer vessels the option of sailing on frying oil.75

 The Channel Islands National Park Routine Services in California own two ships, the Pacific Ranger and Sea Ranger II, running on B100.76

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3.3 ELECTRICAL DRIVEN SYSTEMS

3.3.1 Fuel Properties

Electrical power has been powering and assisting ship propulsion for many years. However, this has nearly always been sourced from on-board diesel generators providing exactly the power at that moment to meet manoeuvring requirements. As additional technologies continue to develop they become a feasible contribution into the propulsion system either reducing the amount of diesel required, through efficiency maximisation; or removing the requirement completely, through the use of alternative energy storage mediums.

Manufacture

Orkney currently utilises 11kV and 33kV grids that stretch across the islands. The electricity in Orkney is sourced either locally from the diverse portfolio of wind, solar, wave and tidal renewable technologies; or from the UK national grid through two subsea cables. As of 2013 Orkney has generated more power throughout the year that it requires, thus making it a net exporter of renewable energy. However, Orkney remains periodically reliant upon imported power when local power generation drops. As coal and gas power generation is a significant portion of the generation mix within the UK this makes the imported power “brown” electricity as it has a carbon footprint.

3.3.2 Electrical Battery Driven Systems

Electrical battery driven systems refer to the sole use of electrical propulsion powered by energy held within on board battery banks. To date there remains to be the very few working example of this technology. The case study below describes the world‟s first full electric ro-ro ferry.

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Case Study

Ferry operator Norled, as of 2015, operates Norway‟s first full electric battery powered ferry at an approximate cost of 200 million Krone (~£20.5 million)77 called the Ampere (Figure 3.17). The vessel has the capacity to carry in the region of 360 passengers and 120 vehicles during its 34 daily 20 minute (5.6km) crossings. The vessel itself has two 450kW electric motors providing propulsion as well as a bank of lithium-ion batteries with a combined capacity of 1MWh. Due to the high number of daily crossings the turnaround time is relatively short (~10 minutes). In order to operate at 10 knots 400kW of power is required for the propulsion. Depending on weather and tidal condition a crossing can require in the range of 150 - 200kWh from the on-board batteries. As such, the Ampere’s battery has the capacity to make a number of crossings once fully charged. To charge directly from the local grid would result in significant periodic loads; which it is predicted would result in detrimental effects. Two 260kWh lithium-ion battery banks situated in small pier side structures were placed on each end of the vessels route in order to mitigate this. The vessel top-up charges from these batteries during passenger disembarking and embarking, and then charges from the grid during overnight periods when not in operation. The weight of lithium-ion batteries per unit of energy is greater than that of conventional marine fossil fuel. As a result of this the ship was designed and purpose built to be more streamlined and lighter; thus requiring less energy per trip. The Ampere replaces a vessel that was solely responsible for the burning of approximately one million litres of diesel per year and the emitting on 2,680 tonnes of CO2 and 37 tonnes of NOx78.

Figure 3.17 MF Ampere79

Safety, Codes and Standards

There is little in the way of regulations and codes specifically for the application of battery energy storage for propulsion systems. The following is a non-exhaustive list of examples available:

 IMO: A.647(16). Guidelines on Management for the Safe Operation of Ships and for Pollution Prevention80;

 GL: Rules for Classification and Construction: Ship Technology: Seagoing Ships81;

 DNV: Ships/High Speed, Light Craft and Naval Surface Craft. Part 6 Chapter 29. Electrical Shore Connection; and

 DNV: Ships/High Speed, Light Craft and Naval Surface Craft. Part 4 Chapter 8. Electrical Installations. Performance

Batteries

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The performance capacity of a battery can be measured in a number of ways including efficiency, cycle life, power density, energy density, etc. Table 3.6 details these characteristics of the main battery technologies commercially available.

Table 3.6 Battery technology comparison82

Battery Respons Energy Power Typical Energy Lifetime Cycle Typical Technology e Time Density Density Discharg Efficienc [a] Lifetime Applications [Wh/l] [W/l] e Time y [%] [cycles]

Lead Acid < sec 50 – 80 90 – 700 hours 75 – 90 3 – 15 250 – Off-Grid, 1500 Emergency supply, Time shifting, Power quality

Nickel < sec 15 – 80 75 – 700 hours 60 – 80 5 – 20 1500 – Off-Grid, Cadmium 80 – 110 (vented) 60 – 70 5 - 10 3000 Emergency (NiCd) 500 - 800 supply, Time Vented shifting, Power sealed quality

Nickel Metal < sec 80 – 200 500 – hours 65 – 75 5 – 10 600 – Electric vehicle Hydride 3000 1200 (NiMH) sealed

Lithium ion < sec 200 – 1300 – hours 85 – 98 5 – 15 500 – 10 Power Quality, (Li-ion) 400 10000 Network efficiency, Off- Grid, Time shifting, Electric vehicle

Zinc Air < sec 130 – 50 – 100 hours 50 – 70 > 1 > 1000 Off-Grid, 200 Electric Vehicle

Sodium < sec 150 – 120 – hours 70 – 85 10 – 15 2500 – Time shifting, Sulphur 300 160 4500 Network (NaS) efficiency, Off- Grid

Sodium < sec 150 – 250 – hours 80 – 90 10 – 15 ~ 1000 Time shifting, Nickel 200 270 Electric vehicles Chloride (NaNiCl)

Lithium-ion (Li-Ion) battery designs are better suited to meet the demands of more aggressive vessel goals than nickel-metal hydride (NiMH) batteries (currently used for HEVs). The flexible nature of Li-Ion technology, as well as concerns over safety, has prompted several alternative paths of continued technological development. Due to the differences among these development paths, the attributes of one type of Li-Ion battery cannot necessarily be generalised to other types.

Lithium-ion batteries are currently used in most portable consumer electronics such as cell phones and laptops because of their high energy per unit mass relative to other electrical energy storage systems. They also have a high power-to-weight ratio, high energy efficiency, good high-temperature performance, and low self-discharge. Most

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components of lithium-ion batteries can be recycled. Most of today's plug-in hybrid electric vehicles and all-electric vehicles use lithium-ion batteries, though the exact chemistry often varies from that of consumer electronics batteries, therefore, for the current assessment lithium-ion batteries are considered as first choice.

Charging

A charging infrastructure would be vital at most, if not all, piers to support plug-in electric vessels. Two types of charging points exist: fast charging point with DC chargers, and slow charging points with AC chargers. A bank of buffer batteries may be required, as seen in the case study of the MF Ampere, if the local grid could not cope with the high periodic loads of an electric ferry charging directly from the grid.

The efficiency of a slow charger is between 90% and 96% while fast chargers have an efficiency of between 91% and 92%. However, fast chargers can only reach such efficiency when the power output is 50kW; when the power output decrease to 2kW the efficiency is around 50%. It should also be noted that a fast charging point only charges the battery to around 95% of its capacity. For the same result, a bigger battery capacity will be required. This could increase the capital cost.

It is also important to notice that the ideal efficiencies are reached when having ideal conditions such as, battery temperature above 20oC and 10% state of charge. With a fast charging point, when the battery is cold the efficiency decreases to 88% for 50 Amp load current and to 82% for 25 Amp load current. This means that the fast charger is optimised for a warm battery and the full load current (125 Amp). When the state of charge of battery reaches 80%, we enter in a second charging cycle where the efficiency of the charger decreases from 85% to 50%. As previously stated, fast charging points only charges the battery to around 95% of its capacity. Perfect conditions are reached for our calculations and that the first cycle will count for 80% of the total charging time while the second cycle will count for 20%.

Electrical energy from Electrical energy for the slow charger the grid battery

•unit: kWh •η = 93% •unit: kWh

Overall system efficiency: ηAC = 93%

Electrical energy from Fast charger Electrical energy for the the grid battery •η = 91.5% •unit: kWh c1 •unit: kWh •ηc2 = 50%

• Overall system efficiency for first charging cycle: ηDC-c1 = 91.5%

• Overall system efficiency for first charging cycle: ηDC-c2 = 50%

Storage

Different way of storing the energy exists. For electricity, battery is the most commonly used technology. A range of batteries are available across the market. The technical differences between different batteries are predominantly

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down to the chemical composition of the cells and structural design. In order to make a comparison between the different types of batteries, a reference battery with a usable energy content of 1MWh is chosen. Depending on the battery technology the available power, volume, weight and price of the reference battery will differ significantly as shown in Table 3.7.

Table 3.7 Specifications of a 1MWh reference battery based on different technologies

Energy (MWh) Power (MW) Volume (m3) Weight (tons) Cycle life @ 80% Depth of Discharge

AGM‟s Lead-Acid 1 2 40.4 73.9 400 battery (Pb-Ac)

HE‟s Nickel-Metal 1 3 14.8 23.1 2000 Hybrid (NiMH)

HP‟s Nickel-Metal 1 29 21.1 38.5 2000 Hybrid (NiMH)

Molten Sodium 1 2.2 13.0 18.3 1500 Tetracholroaluminate (Zebra)

HE-MP‟s Lithium-Ion 1 4.4 5.9 9.4 3000 (Li-ion)

HP-ME‟s Lithium-Ion 1 23.6 9.6 13.6 3000 (Li-ion)

Altairnano‟s Lithium- 1 57 23.6 21.4 20,000 Titanate

Transportation

Due to the expanse of the national grid throughout Orkney, there should not be any requirement for the transportation of stored electrical energy. Pier-side connection should be easily available and additional infrastructure, in the way of charging points, will provide the power to the vessels in question.

Technical Maturity and Deliverability

Battery technologies continue to develop as the market demands smaller, more powerful and cheaper options. The market is well developed and very much commercialised. Nevertheless, the full electric ferry operating in Norway still remains the first and only vessel of its kind. It is still within its first year of operation and it is relatively unclear how the vessel will manage to cope under prolonged periods of time under its current operating parameters; high frequency of charge-discharge cycle seven days a week. Only time will tell through practised experience whether current technology meets requirements or needs further development.

Cost

Capital Cost

The capital cost of batteries is highly variable. Driven with the ever increasing use of portable electronics and electric vehicles, Lithium-Ion batteries in particular are experiencing significant reductions in the unit value. This will continue to be the case with auto manufacturers driving down prices further. Additional projections for the changing cost of

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some battery technologies over the next four years were also published by the International Renewable Energy Agency (IRENA) in 2015. These have been highlighted below in Table 3.8. It too demonstrates the significant drop in the unit cost of Lithium-Ion batteries.

Table 3.8 Current and projected capital cost for utility scale battery technologies (per kWh)83

Battery Technology 2014 2017 2020

Flow Batteries £480.62 £388.74 £247.38

Advanced Lead-Acid £424.08 £388.74 £353.40

Lithium-ion £388.74 £212.04 £141.36

Sodium Sulphur £378.14 £378.14 £353.40

Sodium Metal Halide £344.92 £328.66 £282.72

To date there remains to be a single operating full electric battery ferry, the MF Ampere. By taking this as an example it is possible to gain an approximate understanding of capital costs. The MF Ampere cost approximately £20.5 million to construct, with a power rating of 900kW and an energy capacity of 1.0MWh on-board and 820kWh onshore buff batteries.

Operational Cost

As previously discussed, there is little in the way of real world experience in electric ferries. However, with reference to maintenance, Lithium-Ion batteries require relatively little compared to Lead-Acid, and thus significantly reduced maintenance costs. Annual operational costs for lithium-ion batteries are in the region of £17.40/kW; compared to £20.90 for Lead-Acid.

Additionally, maintenance in comparison to conventional diesel engines should be drastically reduced with significantly fewer moving parts. These savings will go towards recouping the greater CAPEX costs.

Market

The electrical energy storage market is seeing year-on-year growth in terms of installed capacity and revenue. Figure 3.18, demonstrates the projections for the use of large scale batteries for utility purposes. The growing utilisation of electrical energy storage across multiple markets will expedite the continuing drop in the unit price of such technology.

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Figure 3.18 Global Utility Scale Battery Storage Capacity and Revenue Forecast84

Electric Vehicles (EVs) use batteries to store the electrical energy that powers the motor. EV batteries are charged by plugging the vehicle into an electric power source. EVs are sometimes referred to as Battery Electric Vehicles (BEVs). Units are available for vessels but historically have been designed for inland or benign waters where hull design can be optimised to be light and hydro dynamically shaped to provide least water resistance and therefore minimum propulsive power required. For such vessels the weight of the batteries needed to provide the power requirement is the critical element for the suitability.

Environmental Implications

Without the presence of a fuel burning engine on-board a full electric vessel there would not be any tailpipe emissions to consider. However, batteries can use hazardous and toxic materials. These should be handled with care and disposed of in a responsible manner for recycling where possible.

The only other source of emissions would come from the generation of the electricity used on board, and whether it has been sourced from renewable or fossil fuel methods.

Limitations

The main limitations with the use of an electrical battery driven system is the energy density of the energy stored. Currently batteries are not capable of storing the same level of energy as conventional fuels in the same given space. As a result, it isn‟t as easy to match range requirements.

Additionally, opportunities for top-up charging are required in order to compensate for the lower mileage range. Each route proposed for an electrical driven vessel would have to be assessed for feasibility. It would have to be determined whether periods at terminals offered long enough times for adequate charging to match the sailing distances required. As seen in the case study previously, the MF Ampere has 10 minute change over periods either end of its 34 daily crossings. The vessel was also specifically designed to compensate for the heavier battery based propulsion system. For example, the hull was made from aluminium instead of the more conventional steel.

Suitability

A full electric ro-ro ferry would be technologically suitable for servicing inter-islands routes in Orkney. This technology has already been deemed viable in Norway. However, it may not be suitable for all crossing with the current capacity

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of batteries and the charging times required. It is foreseeable that this would not be feasible for the longer crossings to the northern islands, such as Westray and Sanday. The cost of producing a vessel with enough battery capacity to make such crossings could be a significantly limiting factor. Additionally, the lifespan of current battery technologies is less than that required for the next fleet of vessels. It is understood that batteries could be expected to run effectively for approximately eight years, and a vessel would be needed for 25 - 30 years. The high cost of replacement would have to be considered in determining the feasibility of the design.

3.3.3 Flow Cell Systems

Flow Cell batteries are essentially an energy storage medium that acts similar to chemical batteries and fuel cells. The basic premise of the design of most flow cell batteries is to have two containers of oppositely charged liquids which are pumped independently into the energy conversion device; where electrical power is generated through the transition of electrons between the liquids (Figure 3.19).

Fuel Properties

Beyond the components of the flow cell itself, including the working fluids, the fuel is just electrical power; essentially the same as a typical battery. When the flow cell is charged, electrons pass from through the porous membrane from one electrolyte to the other. Then the reverse happens when power is supplied to a load.

Figure 3.19 Flow Cell85

The effectiveness of a flow cell battery to charge and discharge will demand upon the design of the system and the chemistries of the working fluids. Just a few of these examples include:

 Redox;  Iron-Chromium;  Vanadium;  Zinc-Bromine;  Zinc-Polyiodide;  Proton Exchange Membrane (PEM); and  Nano-network.

Flow cells are designed to be closed loop systems where the only inputs and outputs are electricity. However, some visions for the utilisation of flow cells include replacing depleted electrolyte fluid with that which has been pre-charged.

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This would cut down charging time and allows a system to fit a wide range of applications. This is the method envisioned for the prototype NanoFlowcell AG described in the case study below.

Case Study

NanoFlowcell AG, based in Liechtenstein, has developed a range of prototype high performance electric vehicles powered from on-board Nano-network flow cells86. The Quant e-Sportlimousine‟s technical specifications include 0 - 62mph in 2.8 seconds, a top speed of 236mph and an energy consumption of 0.322kWh per mile (speed dependant)87.

Safety, Codes and Standards

Flow Cell systems are deemed to be of very safe design; safer than many battery technologies. In part, this is down to the design of the system where the electrochemical fluids are kept safely separated until required. Flow cell batteries are still in very early stages of development and there are no regulations specifically concerning the application of the technology to maritime sectors.

Performance

Table 3.9, describes the characteristics of typical flow cell technologies currently available. Flow cells are predicted to be able to go through 10,000 full charging cycles without any degradation in performance or energy capacity.

Current flow cell systems can be expected to achieve 60% - 70% round trip efficiency88. This is not as high as other energy storage mediums such as Lithium-ion, but the higher life span and lower self-charge ensure the technology fits many applications.

Table 3.9 Flow Cell Technology Comparison89

Battery Respons Energy Power Typical Energy Lifetime Cycle Typical Technolo e Time Density Densit Discharge Efficienc [a] Lifetime Applications gy [Wh/l] y Time y [%] [cycles] [W/l]

Vanadium 10000 Time shifting, Redox Network Flow efficiency, Off- Battery Grid (VRFB)

Hybrid

Storage

As previously discussed, one of the main advantages of flow cell batteries is the ability to store the electrochemical components of the system in tanks to match the energy requirements of the greater system i.e. if more energy is required to fit the purpose, then the tanks can be scaled up to accommodate. Additionally, as seen with many energy storage media, loss is a significant factor in the efficiency of the system. However, loss is not a problem for flow cell batteries as the electrochemical components are only utilised when power is required, and they do not deteriorate over time while in storage.

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Transportation

The electrical fuel would most likely be delivered through shore side infrastructure to provide power directly to the ship. However, the design of flow cells would also allow for the interchanging of the batteries working fluids instead of the application of an electrical connection.

Technical Maturity and Deliverability

To a large extent the technology is still maturing to commercialisation. However, retailers are currently providing these technologies and a significant number of systems have already been deployed; generally on the grid utility sector.

Cost

Capital Cost

Currently capital costs of flow cell systems are being quoted as a hurdle for wider penetration of the energy storage market. Capital costs or a Vanadium Redox Flow system can currently be expected to be in the range of £415 - £485/kWh90. It has also been estimated that in order to make the technology commercially competitive with other energy storage technologies then the price will need to be closer to £70/kWh.

Imergy Power Systems (IPS), based in the United States, is another technology developer working on the capital costs of Vanadium Redox Flow systems. IPS believe that sources of recycled Vanadium, with slight impurities in it, will drop the cost associated with construction and thus lower the costs to the customers. Estimates put this method at approximately £200/kWh91.

Operational Cost

As there are few examples of operational flow cell systems it is not possible to attach figures to the operational cost of such systems. But as electricity is the fuel, then this would be the main cost attributed to its operation. However, the more complex design and the incorporation of pumps and sensors may lead to greater operating costs.

Market

The market for flow cell systems is ingrained in the energy storage market. Developments in these technologies are attempting to make unit costs competitive with other options, like Lithium-ion batteries.

The technology itself was originally developed by NASA in the 1970s and patents were held protecting the technology. Once these passed, a number of companies began developing the technology for the commercial market.

Currently there are no ships operating anywhere in the world sourcing power from flow cell battery technologies. Most operating flow cells are stationary on-land utility models. However, NanoFlowcell AG, based in Liechtenstein, are developing a range of high performance electric vehicles powered by on-board flow cells92.

Environmental Implications

As with the use of batteries, there are no emissions directly attributed to the use of flow cell systems. Any vehicle utilising this system to provide power to propulsion would produce zero “tailpipe” emissions.

Limitations

A limitation of flow cell systems is the necessity of moving mechanical components and more complex designs. The pumps that move the fluids throughout the system, the sensors, fluid and power management systems are a constant requirement during operation. These provide a level of complexity to the design, parasitic losses, a larger physical footprint and points of potential failure. This potential does not exist in chemical battery technologies.

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Currently in most designs the full system is more expensive and larger, per unit of power, than conventional batteries. Additionally, as a less developed technology there are areas of uncertainty that have yet to be proven.

Suitability

As the market continues to grow it is very likely that flow cells will be applied to many varieties of marine vessels. It provides the potential to exploit the advantages of clean and cheap fuel, next to zero self-discharge and also the future capacity of “refuelling” in a matter of minutes. However, this technology currently remains closer to the demonstration phase of development, with a significant number of unknowns associated to cost, maintenance and longevity of the technology in practise. Flow cells are not close enough to commercialisation to be considered. As there are no current examples of flow cell systems being applied to ships, it would be unlikely that this would be a suitable option for power for the inter-island ferry fleet in the near future. The majority of companies developing this technology are targeting stationary utility applications; where space and weight are not a premium commodity. As such, it could sooner be envisioned that a flow cell system could compliment shore side support services, such as overnight power supply to vessels, prior to being a component of the on-board propulsion system. Electricity is an abundant commodity in Orkney, both on the mainland as well as the inner and outer islands. This could provide benefits compared to other systems that may require the import of fuels and additional infrastructure.

However, flow cells are still far too far from being truly commercialised and are therefore not a suitable option for Orkney‟s inter-island fleet.

3.3.4 Diesel Electric Driven Systems

Vessels classed as diesel-electric describe the use of conventional Internal Combustion Engines (ICE) in conjunction with electric motors in the propulsion system. Today, diesel propulsion systems power 99% of the world maritime fleet. This has a significant contribution to global GHG emissions. Diesel-electric plants have the potential to offer up several advantages to a diesel-mechanical plant. These are as follows:

 Lower fuel consumption and emissions due to the possibility to optimise the loading of diesel engines/gensets. The gensets in operation can run on high loads with high engine efficiency;  Better hydrodynamic efficiency of the propeller. Usually diesel-electric propulsion plants operate a fixed pitch (FP)-propeller via a variable speed drive. As the propeller operates always on design pitch, in low speed sailing its efficiency is increased when running at lower revolution compared to a constant speed driven CP-propeller. This also contributes to a lower fuel consumption and less emission for a diesel-electric propulsion plant;

 High reliability, due to multiple engine redundancy;  Reduced life cycle cost, resulting from lower operational and maintenance costs;  Improved manoeuvrability and station-keeping ability;  Increased payload, as diesel-electric propulsion plants take less space compared to a diesel-mechanical plant;  Lower propulsion noise and reduced vibrations; and  Efficient performance and high motor torques93.

Fuel Properties

A vessel operating in this configuration would completely rely on diesel, or equivalent combustible fuel, to power propulsion. Typically the ICE would power an electrical generator which in turn will provide power to electrical propulsion.

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Case Study

German ferry operator, Reederei Norden-Frisia, commissioned the construction of a diesel-electric passenger and car carrying ferry by shipbuilders Cassens Werft. The Frisia 111 (Figure 3.20) measures 74.3m by 13.4m, and has the capacity to carry approximately 1,348 passengers, 60 cars and 12 crew. The vessel was reported to have cost in the region of €20 million (£14.7 million) and employs fuel-efficient diesel- electric systems consisting of four 560kW marine diesel generators made by Mitsubishi94 and four electric power propellers produced by Voith Schneider. With this propulsion the vessel is capable of travelling at 12 knots.

Figure 3.20 Frisia 111

Safety, Codes and Standards

Regulations and codes for diesel electric vessels would be similar to that already adhered to by the current fleet; with particular reference to carriage of diesel fuel. This would not be expected to be a limiting factor. Codes already exist covering the vessels already in operation.

Performance

Propulsion systems of this category are capable of increasing overall efficiency by maximising the proportion of the time the ICE spends at its most effective rate of operation; which is typically in the region of approximately 70% of its maximum output. As a result of this more efficient operation, the demand on fuel can be expected to be in the region of 15% lower than conventional propulsion systems95.

Storage

Energy storage in diesel electric vessels would be completely in the form of a fuel tank for diesel fuels. No electrical storage is made available in this configuration.

Transportation

Infrastructure for the delivery of marine diesel already exists in Orkney which supports the current inter-island fleet.

Technical Maturity and Deliverability

Diesel-electric propulsion technologies are a tried and tested system, and can be considered as mature. The first diesel-electric vessels were built in the 1920s.

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Cost

Capital Cost

It was not possible to obtain a unit cost for the breed of propulsion system. However, as described in the above case study of the Frisia III the capital cost was approximately £14.7 million. For this cost the vessel was constructed with four 560kW (700kVA) diesel generators and four directional propellers, with the capacity to carry 1,348 passengers and 60 cars96. This approximately equates to £6,563/kW.

Operational Cost

Operational costs associated with fuel costs can be expected to be in the region of 15% lower than that currently seen in the operating fleet of diesel powered vessels. Fuel costs for a typical diesel-electric ferry have been quoted at approximately £7.50/km (dependent upon conditions); also reported to be only 20 - 25% of the OPEX for this vessel. Thus total operating costs can be loosely approximated to £30 - 37.5/km97.

Environmental Implications

With the greater efficiency of the use of conventional marine diesel, there is a correlating reduction in the emissions of pollutants from the vessel. The Frisia 111, as described previously, is said to be almost as effective as LNG driven vessels with a 90% reduction in emissions and a 99% reduction in particulates98. However, this is not solely from the more efficient use of fuel. An exhaust scrubber was also employed in order to make the exhaust fumes cleaner. The use of exhaust scrubbers can at the same time increase the amount of fuel required by 3% and also increase the level of maintenance required.

Limitations

Limitations within the use of diesel-electric engines include the fact that the on-board diesel engine still has to meet ever changing demands in propulsion and on-board hoteling power requirements. Without the inclusion of an energy storage medium to absorb excess power or supply shortfalls of power, the diesel engine will often operate out with its most efficient capacity and tend to require greater maintenance due to ware.

Additionally, fuel consumption is only in the region of 15% lower for diesel-electric in comparison to full diesel propulsion systems. With care this can reach the lower emissions of LNG propulsion systems. Other technologies can achieve greater levels of emission savings.

Suitability

A fleet of diesel-electric ferries would be suitable for the inter-island ferries routes. The only fuel required would be diesel and this is already made available for the entirety of the current fleet. Diesel-electric propulsion systems are a mature, tried and tested technology. This method of propulsion does not include the use of any relatively new technologies or fuels.

However, this method would not be the best fit for the goals of Orkney Ferries. Diesel-electric propulsion does result in fuel savings, but these are not significant. Additionally, emission savings that can be achieved, generally with the addition of an exhaust scrubber, would not meet that of the baseline through LNG propulsion systems.

3.3.5 Electric Hybrid Driven Systems

Hybrid electric vehicles (HEVs), plug-in hybrid electric vehicles (PHEVs), and all-electric vehicles (EVs), use electricity either as their primary fuel or to improve the efficiency of conventional vehicle designs.

HEVs combine an internal combustion engine with a battery and electric motor. This combination offers the range and refuelling capabilities of a conventional vessel, while providing improved fuel economy and often times lower

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emissions. This system also offers the backup capability if the batteries run out of charge. PHEVs are similar to traditional hybrids but are also equipped with a larger, more advanced battery that allows the vessel to be plugged in and recharged in addition to refuelling with diesel.

Hybrid technologies differ from the previously described diesel-electric systems due to the presence of an energy storage medium; typically a bank of battery cells.

 Hybrid Electric Vehicles HEVs are powered by an internal combustion engine or other power sources that can be run on conventional or alternative fuel and an electric motor that uses energy stored in a battery. HEVs combine the benefits of high fuel economy and low emissions with the power and range of conventional vessels. There are a number of examples of this type of system and they are readily available on the market. Scandline currently operate a fleet of diesel hybrids between Germany and Denmark; as highlighted in the case study below.

Case Study

The largest hybrid ferry currently operating is the MF Prinsesse Benedikte (Figure 3.21), operated by the Danish operator Scandlines. The vessel was constructed in 1997 and retrofitted in 2013 to operate has a diesel-electric hybrid. The ferry itself services the 20km route between Denmark and Germany. It operates fully electric at the start and end of its crossing and the diesel generators recharge the battery bank during the open-water sailing. By operating in the manor it is possible to reduce the fluctuating operation of the diesel generators and reduce fuel consumption as well as the corresponding emissions. The ferry essentially was converted from a diesel-electric vessel to a hybrid vessel with the introduction of a 2.7MWh lithium-ion battery to its propulsion system. The lithium-ion battery was supplied from a Canadian company, Corvus. It is predicted that the consumption of diesel will drop below 500kg per trip, down from 720kg; which is approximately a 30% saving. Savings such as this should result in a four year payback for the installation of the battery. Due to the capacity of the installed battery, the 300 car and 900 passenger capacity vessel could potentially travel for 30 minutes solely on battery power99.

Figure 3.21 MF Prinsesse Benedikte100

 Plug-in Hybrid Electric Vehicles PHEVs are powered by an internal combustion engine that can run on conventional or alternative fuel and an electric motor that uses energy stored in a battery. The vehicle can be plugged into an electric power source to charge the battery. The technology is available, but not as developed as conventional hybrid electric options. The case study below discusses the work Scandline is currently conducting in the field.

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Case Study

Ferry operator Scandines are planning a roll out of plug-in hybrid ferries; expanding upon the company‟s current fleet of hybrid vessels. The plug-in models will be charged up at either end of the journey and allow for the vessel to operate entirely on electric propulsion, sourced from on-board battery banks, for the first and last 20 minutes of the journey. During the one hour sailing in between these periods the conventional engine will provide any excess power to the batteries to recharge them 101 . It is expected that this will reduce emissions by 15% 102 . Scandlines are essentially employing hybrid technologies as a stepping stone towards zero-emission full-electric vessels by 2018.

Safety, Codes and Standards

The codes and regulations that a hybrid vessel would be expected to adhere to would be dependent upon the hybridised technologies it is employing. A vessel of this nature could be expected carry a number of combustible fuels such as diesel, LNG or hydrogen. The vessel would also have a level of energy storage, generally in the form of battery.

 DNV. Ships/High Speed, Light Craft and Naval Surface Craft. Part 6 Chapter 29. Electrical Shore Connection.  DNV. Ships/High Speed, Light Craft and Naval Surface Craft. Part 4 Chapter 8. Electrical Installations.

Performance

Due to the ability of the ICE to operate predominately at its most efficient capacity, fuel savings are a result of this. Caledonian MacBrayne (CalMac), operating on the west coast of Scotland, has a fleet of three hybrid electric vessels. It has been reported that these vessels result in a 38% reduction in fuel.

Storage

As described previously, the most common source of energy storage within a hybrid electric vehicle is conventional battery technologies. As the auto industry moves towards greater electrification of transport and development in battery technologies, this tends to be Lithium-ion. Lithium-ion offers better performance under the conditions imposed due to the typical operation of HEVs; which can include regular and short periods of charge and discharge events. The characteristics of lithium-ion, and other technologies, are discussed previously in Section 3.3.2.

Transportation

The requirement for the transportation of fuel would be particularly dependent upon the choice of technology employed. For example, a diesel electric hybrid would require no additional infrastructure as marine diesel is utilised by the current fleet. However, if LNG or hydrogen was opted for then this would require significant development to accommodate the storage and application of these fuels. Additionally, if a plug-in option was chosen then development of the electrical infrastructure would also be called for. It would be critical to ensure that each vessel would be charged from wherever it berths at each port of call.

Technical Maturity and Deliverability

Individually the technologies are commercialised, available for deployment and technically mature. However, the application of hybrid technologies to sea going vessels is still relatively new.

Cost

Capital Cost

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The hybrid vessels operated by CalMac on the west coast cost £12.3 million each. It is estimated that this is approximately three times more expensive than a conventional diesel powered ferry. These vessels are described in greater detail in the case study below.

Case Study

In 2013 Caledonian MacBrayne launched two hybrid electric ferries, built in Glasgow, to operate on the west coast of Scotland. The MV Hallaig, purpose built to operate the Skye to Raasay route, was constructed in 2011103. MV Locinvar was launched in 2013 and operates the crossing from Tarbert to Portavadia. The latest vessel in the fleet, MV Catriona was launched in late 2015 from the same Ferguson Yard in Glasgow. It has been quoted that the latter, which is of the same design across the three vessels, cost £12.3 million to manufacture; it is due to go through sea trials in the spring of 2016 before going into active service. The route on the west coast that the MV Catriona will service has yet to be announced104. All three vessels, measuring 45m in length, 12.2m in breadth and draughts of 1.73m, have the capacity to carry 150 passengers, 23 cars and two HGVs. The propulsion systems still rely mainly on diesel powered generator (350kW) which generates electric power, which in turn supplies power to the electrical propulsion units. On- board lithium-ion batteries, with total capacities of 700kWh, are charged with excess power from the generators, as well as being charged overnight from harbour-side grid power. Through the operations of the MV Hallaig and MV Lochinvar it has been analysed that fuel consumption is approximately 38% lower than that compared with the convention vessels previously servicing the same routes. It is also estimated that CO2 emissions will be reduced by 5,500 tonnes over the lifespans of each vessel105. It is hoped that this will result in a 20% reduction across the fleet of hybrid vessels during peak summer periods. But during quieter winter periods this will mean vessels operating solely on battery power resulting in minimal noise and zero emissions106.

Operational Cost

As previously discussed, the operational costs of lithium-ion batteries are approximately £17.40/kW. Working off the assumption that annual OPEX for a vessel is 5% of the CAPEX, and using the above case study as an example, a year cost is calculated as approximately £615,000 per year (£1,757/kW).

Environmental Implications

As previously discussed, hybrid technologies applied to vessels can be expected to see in the region of a 15% reduction in emissions. This is true where diesel is still the primary fuel. The application of other fuels such as LNG or hydrogen would significantly drop this further; as would the use of greater energy storage capacity.

Limitations

The main limitation that could be associated with the PHEV is the requirement for an electrical infrastructure available at most or every pier on the ferry route. Due to short stop over periods there may be the requirement to change with high volumes of electrical energy. This may bare too high a burden on the local grid and thus require the deployment of buffer batteries at each port. This will add addition capital expenditure and marginally extra operating costs; but reduce pressure on the grid.

Suitability

This option is technologically suitable for servicing the inter-island ferry routes in Orkney. The technology is currently available and currently employed by ferry operators.

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3.4 HYDROGEN FUELS SYSTEMS

3.4.1 Fuel Properties

Hydrogen is the smallest element in the periodic table. This is part of the reason why it is more complicated to store without losses from the containment vessel. Hydrogen is an extremely common element, but it rarely exists in its monoatomic form. It is nearly always found in other compounds such as water (H2O).

Hydrogen has a volumetric density of 0.08988g/L, and an energy density of 33kWh/kg (2kWh/l) and 107 turns from a liquid to a gas (boiling point) at -252.87°C108.

Manufacture

Hydrogen can be produced from a variety of feedstocks. These include fossil resources, such as natural gas and coal, as well as renewable resources, such as biomass and water with input from renewable energy sources (e.g. sunlight, wind, wave or hydro-power). A variety of process technologies can be used, including chemical, biological, electrolytic, photolytic and thermo-chemical. Each technology is in a different stage of development, and each offers unique opportunities, benefits and challenges. Local availability of feedstock, the maturity of the technology, market applications and demand, policy issues, and costs will all influence the choice and timing of the various options for hydrogen production109.

Water electrolysis was the first method used commercially to produce hydrogen back in the 1920s. Today the reforming of fossil fuels into hydrogen is the most common method of production. Electrolysis, where electricity splits water to hydrogen and oxygen, is a useful method for producing hydrogen from renewable energy sources like wind, solar and hydropower. In this way, hydrogen can play a role in balancing the grid when more renewable and intermittent energy sources are introduced110.

Conventional electrolysers, in order to ensure the safe generation of hydrogen, uses DC power, demineralised water and a cooling medium. In Figure 3.22, below, nitrogen has been included within the reaction, but this is not always the case for all electrolysers.

Figure 3.22 Electrolyser basic configuration

Electrolysis cells are characterised by their electrolyte type. There are various types of the electrolyser. There are two types of low-temperature electrolysis commercially available on the market: Alkaline and Proton Exchange Membrane (PEMEC). Solid oxide electrolysers are under development but are relatively untested.

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Proton Exchange Membrane Electrolyser

PEMECs (Figure 3.23) have been available commercially for many years, but historically not at large enough scales to be suitable for energy storage. Recently, a number of companies have announced their intention to develop large- scale electrolysers and target this market.

PEMECs have fast response times to meet fluctuations in electrical input and they can also be operated anywhere between zero and 100% of nominal capacity. PEMECs produce high-purity hydrogen, which can be used directly in many applications with no further purification required. Current drawback to PEMEC includes their unproven durability and scalability111.

Figure 3.23 Proton exchange membrane112

The main assets of the PEM technology are that it requires less complex Balance of Plant (BoP) to manage gas production, it is more dynamically responsive and it is simpler in construction than other technologies. However, it is relatively new in the marketplace, especially into the large-scale hydrogen production arena. Therefore, it can be electrochemically less efficient at hydrogen production and the perceived technical risk can be seen as higher than other more mature technologies.

Alkaline Electrolyser Cell (AEC)

AECs use an aqueous Potassium Hydroxide (KOH) solution (caustic) as an electrolyte that usually circulates through the electrolytic cells. AECs, Figure 3.24, are suited for stationary applications and are available at operating pressures up to 25 bars. AEC is a mature technology, with a significant operating record in industrial applications that allows remote operation113.

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Figure 3.24 Alkaline electrolyser114

The Alkaline technology has the longest track record in the industry and is the most mature electrolytic Hydrogen production technology available and, therefore, carries the least technical risk and can offer the potential for the most efficient production (in kWh/m3 of hydrogen). The control and BoP can be more complex with alkaline technology than with other methods, but it has been achieved to good effect for many decades across a variety of sectors.

Note that in an alkaline electrolyser, there is a need to use regenerative cartridges for reducing the maintenance activity on the system. The system automatically regenerates the cartridges when required and without any disruption on the Hydrogen production. Sometimes nitrogen is required to regenerate the purifier cartridges.

Solid Oxide Electrolyser Cell

Solid Oxide Electrolyser Cells (SOECs; Figure 3.25), operate at high temperatures, similar to solid oxide fuel cells. At these temperatures, water in the form of steam can be split more easily into hydrogen and oxygen due to the added energy contribution from the heat. Using a SOEC it is also possible to generate synthesis gas.

Advantages of this technique are the high efficiencies achievable, especially if the electricity and heat can be sourced renewably. Drawbacks to this technology would be the limited availability of renewable high-grade heat and electricity in the same location. This technology is still relatively young and untested when compared to PEMEC and AEC. There are no SOEC systems commercially available yet.

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Figure 3.25 Solid oxide electrolyte115

This technology is still in development. SOEC technology would be considered technologically too immature for a project of this nature and may carry additional technical risks that the end user may not wish to accommodate such as the risk due to the very high temperatures and thermal cycling involved in the Hydrogen production.

Table 3.10 Electrolysers technology overview

Option Components required Suitable model Approximate capital costs Availability

(All types)

PEMEC Electrolytic Cell Stack Commercially available 900kW electrolyser would cost 9 months in the region of £1m to £1.4m Balance of plant to support depending on the technology cell stack H production 2 and options selected such as supply of housing, cooling, etc. Control & monitoring AEC Commercially available 6 months Auxiliary Safety systems A 450kW electrolyser is £500k to £800k depending on options.

SO Early Unknown commercial/prototype

In order to operate an electrolyser two other steps are required: the water demineralisation and the hydrogen purification. They allow raising the hydrogen purity from 99%, the standard purity at the outlet of the electrolyser, to 99.999% with contaminants in the range of:

 <10ppm O2 in H2<10ppm N2 in H2

 < 1ppm H2O  -50C Dew point

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Demineraliser - water supply

In order to operate an electrolyser, there is a requirement for a supply of deionised water and therefore, a deioniser must be integrated into the hydrogen production system. This will produce deionized water from the readily available water supply. PEMEC electrolysers have shown operational issues when the quality of the deionized water is low. Therefore, high quality deionized water must be used if a PEMEC electrolyser is to be used.

The produced deionized water shall be fed to a water tank that will hold a reserve of water providing several hours of autonomy. The water will then be fed, automatically, to the electrolysis cells as required. In addition, a water deioniser will be installed to ensure the maximum performance from the electrolysis process.

Hydrogen purification

Most PEMEC electrolysers do not need hydrogen purification but other systems need a gas purifier to remove any trace of the alkaline solution and impurity from hydrogen steam, making the hydrogen produced suitable for high purity application. There are two types of hydrogen gas purification systems; one is integrated inside the electrolyser machine and the other one is external to the electrolyser. Both operate in the same way. However, there is a need for selecting an electrolyser with an auto-regenerative gas purification system. Though these auto-regenerative systems are more expensive, they provide a lower OPEX, hence providing a better operational duty. Note, that most PEMEC electrolysers do not use such a gas purification module.

Hydrogen generated can reach the purity of 99.999%, well within the specification of a hydrogen boat. In addition, the gas purifier includes a drying unit that is able to remove humidity content into the gas. In an alkaline electrolyser, as the gases leave the electrolyser they pass through a gas/liquid separator to remove any electrolyte carried over. This electrolyte is then recycled back to the electrolyser module. Finally, the gases are filtered through special micro porous cartridges to remove any trace liquid electrolyte remaining.

An output gas analysis sensor must be installed inside the gas generation area to continuously monitor and control the output hydrogen gas quality. There will be no effect on the purity with a variable input power and variable output rates.

Cost

An approximate CAPEX figure, from the Scottish Hydrogen and Fuel Cell Association (SHFCA), for the production of hydrogen through electrolysis is that a 1MW unit will cost approximately £1 million116.

A paper produced by the Department of Energy (DoE) provided breakdown estimates of the costs associated with the production, storage and dispensing of hydrogen from natural gas reforming as well as electrolysis. The paper recognised that currently it is cheaper to produce hydrogen form natural gas. It is for this reason the majority of hydrogen is produced in the fashion today. It continues by saying that further research and development is required to make electrolysis of water competitive, and that it will also be competitive as long as cheaper electricity is available117.

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Figure 3.26, below, shows the results of work conducted by Fuel Cells and Hydrogen Joint Undertaking (FCHJU) in 2013. The work included investigating the cost implications of using an Alkaline fuel cell and a PEM fuel cell. According to this work it cost approximately 25% less to produce hydrogen through an Alkaline fuel cell. Additionally, this work attached a CAPEX value to these two technologies of €1,100/kW (£846/kW) for Alkaline fuel cells and €2,090/kW (£1600/kW) for PEM fuel cells. These are expected to drop to €580/kW (£446/kW) and €760kW (£585/kW) by 2030 respectively118.

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Figure 3.26 Hydrogen Production Costs through Electrolysis119

Euro/kg CAPEX OPEX Wholesale Sub Total Grid Fess TOTAL Electricity and Levies

Alkaline 2.02 0.20 1.32 3.54 3.24 6.78

PEM 4.05 0.27 1.39 5.71 3.42 9.13

UCL has projected the cost of a number of fuels over the coming decades, up until 2050 (Figure 3.27). It clearly shows the significantly higher unit price of hydrogen throughout the whole period in question. However, from 2020 it is projected to remain a relatively stable commodity. Only LNG is capable of staying the same. Other more finite fuels are estimated to see steady year on year growing unit costs120.

Figure 3.27 Global Commons fuel price forecasts. (HFO: Heavy Fuel Oil, MDO: Marine Diesel Oil, LSHFO: Low Sulphur Heavy Fuel Oil, LNG: Liquefied Natural Gas)

Safety, Codes and Standards

With proper handling and controls, hydrogen can be as safe as, or safer than, other fuels we use today. Safety considerations associated with handling hydrogen include fire, explosion, and asphyxiation.

Existing codes, standards and guidance (not exhaustive):

 EIGA document 15196: Gaseous hydrogen installations

 British Compressed Gas Association (CP4 and GN2)  NFPA 50A: Standards for gaseous hydrogen systems at consumer sites

 German TRG 406: CGH2  ISO 15916: Basic considerations for the safety of hydrogen systems  ATEX (supply) Regs; SI192, 1996  Dangerous Substances and Explosive Atmospheres Regulations 2002

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 BS EN 60079 Electrical app. for explosive gas atmospheres  `Fuel cells: Understand the hazards, control the risks‟, HSG243, G. Newsholme  Compressors shall conform to CE/PED/ATEX standards.  Pressure equipment directive for hydrogen : PED and 97/23/EC  The transportable pressure equipment directive for hydrogen TPED and 2010/35/EU

Several codes and standards-related websites may be useful:

The ANSI Hydrogen Codes and Standards Portal. This website provides access to codes and standards that are critical to the jobs of building code officials, permitting officials, and fire safety officials. It contains a listing of codes and standards that are searchable by topic or organisation, including information on current status.

The DOE Hydrogen Fuelling Stations and Telecommunications Permitting website. This website provides a listing of hydrogen fuelling station and telecommunications fuel cell codes and standards searchable by topic or organisation. The objective of this website is to help local permitting officials deal with proposed hydrogen fuelling stations, fuel cell installations for telecommunications backup power, and other hydrogen projects. A permitting process section seeks to help project developers and the public understand the general procedures involved. Technology overviews of hydrogen fuelling station and telecommunications fuel cell use and searchable model code information should provide helpful information for local permitting officials to address project proposals.

The Hydrogen/Fuel Cells Codes and Standards Matrix. This website is dedicated to assisting the worldwide community working to develop and interpret fuel cell codes and standards.

Performance

The conversion of electricity into hydrogen has losses due to intrinsic technology and chemist principle. Losses of the system are described as follow:

Electrolyser requires about 5.5 kWh/Nm3 of hydrogen produced. This results in an efficiency for the electrolysis process of approximately between 50% and 78%; and

Often, hydrogen is then compressed up to 200 bars. In this case, the compressor requires additional energy; in the order of about 0.36 kWh/N m3 of hydrogen. This compression process is roughly 95% efficient.

Combining the above results the total system efficiency is about 47.6% (Figure 3.28).

Figure 3.28 Hydrogen Co-Burning Efficiency

Electrical energy Electrolysis Compression of Hydrogen tank from the grid process H2

•unit: kWh •η = 50% •η = 95% •unit: kgH2

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Storage

Hydrogen can be stored in a variety of ways, but for hydrogen to be a competitive fuel for vessels, the hydrogen vessel must be able to travel a comparable distance to conventional hydrocarbon-fuelled vehicles. Hydrogen can be stored as follows:

Compressed Gas and Cryogenic Liquid Storage

Hydrogen can be physically stored as either a gas or a liquid. Storage as a gas typically requires high-pressure tanks (5,000 – 10,000psi). Storage of hydrogen as a liquid requires cryogenic temperatures because the boiling point of hydrogen at one-atmosphere pressure is -252.8°C. A compressor is needed after the electrolyser, to apply high pressure to the hydrogen produced and store it.

Compressed gas storage media is the safest, most accessible and cheaply available storage medium. It is easily transportable, can be easily used in a refuelling station and has the shortest lead time storage for hydrogen. Storage times can be between two to six months depending on the pressure selected. For instance, a 200 bar storage system is two months and 900 bar system entails four to six months lead time. This can be explained by the fact that it is the most tried and tested form of hydrogen storage nowadays.

Liquefied storage is very challenging to implement and to maintain as liquefaction is the most difficult technology to manage as good thermal management is a must. There is a need for a thermal management system taking the heat out of the hydrogen storage during filling and supplying heat for hydrogen dispensing. This technology also requires a lot of infrastructures to cope with the very high pressures to keep it liquefied and it is also the least efficient technology with an energy cost overhead in the region of 1/3. The long lead time and the dependence on the geography of this technology should not be underestimated.

Furthermore, liquefied hydrogen storage is significantly more dangerous than other storage systems and will require a significant and lengthy safety assessment and procedures in place to prevent accidents.

Materials-Based Hydrogen Storage

Hydrogen can also be stored on the surfaces of solids (by adsorption) or within solids (by absorption). In adsorption, hydrogen is attached to the surface of a material either as hydrogen molecules or as hydrogen atoms. In absorption, hydrogen is dissociated into H-atoms, and then the hydrogen atoms are incorporated into the solid lattice framework. All of the storage options (other than storage of Hydrogen at production pressure) will require some form of post- processing either in the form of thermal and/or pressure management.

Metal hydride, Carbon Nano-tubes, Glass Microspheres

Metal hydride, Carbon nano-tubes and glass microspheres technologies have limited cycle life for large scale projects and can be very expensive. Furthermore, their long lead time and their dependence on geography are also to be considered.

Subterranean Cavern

A subterranean cavern will be very difficult to implement in the project area and cost considerably more than the alternatives already covered. Furthermore, its long lead time and its dependence on geography are also to be considered. The hydrogen storage options are summarised in

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Table 3.11.

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Table 3.11 Overview of hydrogen storage options

Option Components Suitable model Rough capital costs Availability required (All types)

Compressed gas All the storage Commercially Rack for 49 cylinders: £20k 2 – 6 months options (other than available depending on storage of H2 at the pressure Compressor of 200Nm3 capacity production selected (input 5 bar – output 200 bar): pressure) will £220k to £300k require some form

Liquefied storage of post-processing, either in the form of A 530 litres – 450 bar pressure

thermal and/or hydrogen (15kg of H2): £11k to Metal hydride, pressure £15k Carbon nanotubes, management Glass microspheres Compressor of 200Nm3 capacity Subterranean cavern Not suitable to (input 5bar – output 200 bar ): Orkney 300k to 450k

In the near term compressed hydrogen gas (CHG) and liquid hydrogen (lH2) are the most mature methods of hydrogen.

Transportation

While stored, the hydrogen can be easily transported in tanks.

Market

Hydrogen is a potentially emissions-free alternative fuel that can be produced from diverse energy sources. Research is under way to make hydrogen vehicles practical for widespread use. This technology is relatively new on the market and as such there are limited off the shelf products. There are also some legislative issues to overcome the use and carriage of hydrogen and although the MCA is working with some companies to develop guidance and coding, this is still under discussion.

The SHFCA does not see drastic changes in the hydrogen market in the UK up to 2020, but does see this changing by 2030 with further introductions of hydrogen vehicles, fuelling stations and micro and grid-scale Combined Heat and Power (CHP) units. However, the further utilisation of shale gas and fracking will impact upon the market interest in investing in and developing hydrogen economies further121.

UCL produced a report that included projections on the uptake of hydrogen over the coming decades. Part of this was to investigate the sensitivity of this take up depending on a number of variables; including carbon price, unit price of hydrogen, CAPEX, etc. The graph displaying the results is shown in Figure 3.29. It shows the cost of hydrogen is a key factor in the adoption of hydrogen fuelled vessels. This will be particularly relevant when attempting to direct hydrogen production to electrolysis instead of natural gas reforming; the latter is currently cheaper to produce122.

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Figure 3.29 Sensitivity analysis on the uptake of hydrogen between 2010 - 2050123

3.4.2 Hydrogen Co-Burning

Description and performance

Co-burning utilises hydrogen as a catalyst to increase fuel efficiency as hydrogen burns at around ten times the speed of petrol or diesel, propagating combustion. Small amounts of hydrogen increase the efficiency of a normal Internal Combustion engine around 10% - 15%.

Technical Maturity and Deliverability

This solution is at the concept stage. Some examples of diesel engines within land vehicles, such as vans, have been modified to run almost purely on hydrogen. Direct combustion hydrogen engines however still require a small amount of diesel for initial combustion and afterwards run on pure hydrogen. At this stage, there are no examples of marine vessels utilising this technology although there is some ongoing research into this area. However, in order to marinise this type of engine, modifications would be required.

Cost

Capital Cost

A co-burning engine, the size of a transit van, of around 150HP would cost in the region of £30,000 (approximately £268.20/kW). This cost is for a non-marinised model and additional modifications and expenditure would be required. Additionally, this is for the engine alone and not the complete vessel solution.

Operational Cost

There is currently little data available to makes estimates on the OPEX of a co-burning vessel. Assuming a standard OPEX of 5% of the capital cost results in £13.40/kW/year. Additional running costs would include maintaining hydrogen infrastructure, crew and unit costs of hydrogen.

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Market

Currently there are no ferries operating with co-burning engines; and it is currently unclear how this will change in the future, but it does provide a lucrative method for increasing the efficiency of conventional engines. As the world moves closer to hydrogen economies this method of propulsion may start to take steps towards being marinised on a bigger scale.

Environmental Implications

As hydrogen only has by-products of heat and water, there would not be any emissions to cause concern with its implementation. However, co-burning still requires the use of conventional fossil fuel; but at higher efficiency. The 10 - 15% increased efficiency in fuel performance should result in a proportionate reduction in fuel requirements and resulting emissions; such as Sulfur Oxide (SOx) and CO2.

Limitations

The co-burning solution can result in increasing engine “knock” due to the disparities in combustion time due to the volatile nature of hydrogen. This adds to the possible maintenance requirements as well as potential points of failure. Additionally, a hydrogen infrastructure would be required to facilitate this option; which would be complicated and capital intensive.

Suitability

However technically feasible hydrogen co-burning would be in Orkney, there is still a considerable level of emissions that would result from the significant quantities of conventional diesel fuel required. However, co-burning hydrogen with currently available diesel does offer the potential to act as a stepping stone towards greener technologies in the future as other technologies commercialise.

3.4.3 Direct Combustion Systems

Description and Performance

The hydrogen combustion engine is a modified version of the gasoline-powered combustion engine. Basically, it uses the energy released by the combustion of the fuel that has been injected into the combustion chamber. The efficiency of such an engine is generally quoted around 42% (Figure 3.30). Knowing this efficiency and the required rated power of the engine we are able to calculate the consumption of hydrogen of the engine for a return trip.

Figure 3.30 Direct Combustion Propulsion Efficiency

Direct H combustion 2 Mechanical energy H2 motor

•unit: kgH2 •η = 42 % (cheetah's •unit: kW system)

Overall system efficiency: ηhc = 42%

Technical Maturity and Deliverability

The direct combustion of hydrogen is an available technology and can be considered as commercial. However, there are few examples of this being applied to the maritime sectors. This will likely change with growing interest in hydrogen as an energy storage medium, but currently this can be considered as a maturing technology.

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Cost

Capital Cost

Capital cost of a direct combustion propulsion system can be approximated to £298/kW. This does not include the necessary infrastructure to bring hydrogen to Orkney.

Operational Cost

Operational costs for direct combustion have been calculated, at 5%, to be in the region of £14.20/kW per year for maintenance; this does not include the cost of hydrogen or crew.

Market

Direct burn hydrogen is considered an option for small seagoing vessels. The technology is being researched with a small vessel manufacturer in the UK. The challenge is the weight of the hydrogen storage tanks required to produce the power required. Hydrogen can be used in existing IC engines with modification.

Environmental Implications

Solely utilising hydrogen to produce power is an extremely clean form of power generation with the only emission being pure water vapour. The only significant environmental consideration is the sourcing of hydrogen that has been sourced from fossil fuels and transported to Orkney for utilisation instead of producing it locally from renewable energy via an electrolyser unit.

Limitations

As highlighted previously the unit cost of a vessel powered by hydrogen will cost significantly more than an equivalent vessel power by LNG or methanol. There is also the hurdle of the significant CAPEX that will be associated with the necessary infrastructure to bring hydrogen bunking to Orkney.

Additionally, it is unclear to what level Orkney will be able to produce its own hydrogen from electrolysis sourced from renewable energy. This could have direct impacts upon the applicability of this technology and how many routes could be serviced.

Suitability

There is potential for hydrogen vessels to be incorporated into Orkney‟s inter-island fleet. Orkney is already embracing hydrogen as an energy storage medium in the near and distant future. It holds significant potential to absorb a portion of the current curtailment experienced on the grid, and would be close to remove maritime based emissions.

However, there are very few working examples of vessels currently operating on direct combustion of hydrogen; and none on the ferry scale. This should be taken into consideration when considering the risk associated in adopting the technology. Additionally, the level of hydrogen infrastructure that would be required to accommodate a fleet of this breed of vessels could potentially be too expensive to be viable.

3.4.4 Fuel Cell Enhanced Systems

Description and Performance

An on-board system using fuel cells converts chemical energy into mechanical energy in two steps. First the fuel cells convert the chemical energy from hydrogen into electricity using a chemical reaction with oxygen. The electricity produced is then used to run an electric motor that will provide the mechanical energy necessary to make the ship

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move. The efficiency of the whole fuel cell system, including the engine system, was quoted to be 52%124 (Figure 3.31) while the efficiency of an electric motor was quoted to be 85%.

Figure 3.31 Fuel Cell Propulsion Efficiency

Mechanical H Fuel cell system 2 energy

• unit: kgH2 • η = 52% • unit: kW

Safety, Coding and Regulations

Fuel cell technology is relatively novel to the maritime industry and ferry sector. However, DNV currently have regulations in place covering the use of fuel cells, highlighted below.

 DNV. Ships/High Speed, Light Craft and Naval Surface Craft. Part 6 Chapter 23. Fuel Cell Installations125.

Technical Maturity and Deliverability

There are three types of fuel cells that could be used: PEM, alkaline and SOFC. PEM fuel cells are most suitable for small boat applications and are used in buses and demonstration passenger vehicles. PEM fuel cells operate at relatively low temperatures, have high power density, and can vary output quickly to meet shifts in power demand. PEMs are well-suited to power applications where quick startup is required, such as automobiles or forklifts. The suitable model for small boat application are the PEM fuel cells.

Cost

Capital Cost

UCL estimates fuel cell stacks can be expected to cost in the region of $1,000/kW (£700/kW) and the full CAPEX of a hydrogen fuel cell vessel is in the region of $5,400/kW (£3,737/kW) 126.

UCL does also report that vessels sourcing fuel for fuel cells from LNG and methanol can expect to see CAPEX in the region of $2,400 (£1,660/kW) and $1,800/kW (£1,245/kW) respectively. The lower costs are predominately from the significantly lower CAPEX associated with fuel storage: $4,000/kW (£2,767/kW) for hydrogen, $1,200/kW (£830/kW) for LNG and $500/kW (£346) for methanol.

Operational Cost

Operational costs for fuel cell vessels have been calculated to be in the region of £23.40/kW127.

Market

Fuel cells are identified as a serious option for certain types of seagoing vessels and examples of fuel cells are becoming available. There are two options within fuel cells:

 Full fuel cells: the fuels cell is a direct drive where the fuel cell will supply all of the power to propel the boat as well as the internal boat electrical equipment; and

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 Hybrid drives: the fuel cell provides the power to charge batteries which run the engine.

Scotland already has a hydrogen industry based in the transport sector of Aberdeen with the world‟s largest fleet of hydrogen fuel cell buses. The demonstration period of the first ten vehicles is due for completion in 2017, after which further buses will hopefully be deployed. Additionally, bodies such as the FCHJU are aim to deploy approximately 1,000 hydrogen fuel cell buses across Europe; with developments being focused on further hydrogen powered vehicles and the further utilisation of electrolysis to boost the ability to employ variable renewable as an energy source128.

UCL have made predictions on the application of fuel cells with maritime sectors. They believe that by 2020 fuel cells will be in the region of greater than 1MW, and by 2025 they will surpass the 2MW scale129.

Environmental Implications

Utilising fuel cell units to produce power is effectively just as clean a method of power generation as direct combustion of hydrogen; the only emissions will be water vapour. However, there are also the same concerns of the sourcing of hydrogen and whether it is derived from natural gas reforming or water electrolysis; the former has significant up- stream emission implications.

Limitations

The challenge with both systems is the weight of the fuel cells and hydrogen storage required to produce the power required for a vessel. Additionally, there is little experience of the use of fuel cells to provide primary power to a vessel‟s propulsion; and zero examples of vessels of the scale of ferries. This is developing technology with limited maritime experience; even if this is to date generally considered as successful. As seen in the other utilisations of hydrogen as a fuel, a significant infrastructure would be required among a number of the islands in order to sufficiently accommodate bunkering of the fuel; significantly adding to the necessary capital expenditure.

Suitability

As previously discussed, hydrogen and fuel cell propulsion holds significant potential for Orkney‟s inter-island ferries. It could provide the power and energy capacity required to service many, if not all, of the current routes, while also providing a means of energy storage for the portfolio of variable renewables situated on the islands. However, fuel cells in this capacity have significantly limited experience and it could reasonably be argued that employing fuel cell technology as the primary means of propulsion at this time would be a costly and risky direction to take.

3.5 OTHER NOVEL POWER/FUEL SYSTEMS

3.5.1 Wind Driven Propulsion

Soft Sails or DynaRigs

Conventional soft-sails attached to yards and masts offer a proven, mature technology capable of directly harnessing the propulsive force of wind. Technological advances in the yacht-racing industries can now be incorporated into commercial use. Sails can be deployed as either primary or auxiliary propulsion and can be either retrofitted to existing vessels or incorporated into new vessel designs. Current market leaders include Greenheart‟s 75dwt freighter (Figure 3.32) and B9 Shipping‟s 3,000dwt bulker. The latter design features versions of Dyna-Rig systems (proven on the super yacht Maltese Falcon) that are operated automatically from the bridge, enabling wind to be harnessed more easily, keeping crew sizes comparable with fossil-fuel powered ships and allowing easy access to hatches for loading

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and discharging cargoes130. The freighter developed by Greenheart deploys a more conventional jib and mainsail combination.

Figure 3.32 Greenheart's soft-sail freighter (left) and B9 Shipping’s 3,000dwt bulker (right)

Wingsails or Rigid Sails

In contrast to traditional soft-sails, which are flexible, these are wing-shaped foils with varied geometry and configurations. They can be deployed as single foils or multiple foils attached to a single base. Depending on the size of the vessel, the available deck space and other restrictions, multiple sets can be deployed131. Current proposals include use on large ships (e.g. UT Wind Challenger and EffShip‟s project which includes using rigid sails capable of reefing down on telescoping masts for heavy weather or in-port situations). Various forms of fixed wings have been proposed since Japanese experiments in the 1980s. These include the Walker Wing sail, fitted to the 6,500dwt Ashington, in 1986. Trials then did not demonstrate substantive savings and some technological barriers are still to be overcome with this design approach. An Italian shipping innovation company, Seagate, has patented folding delta wing sails for retrofitting to existing ships, including ro-ro, container ships and car carriers. There are also various rig configurations that can be used on small-scale freighters and catamarans for local use, especially in island communities or as auxiliary power to a wide range of existing small-scale, conventionally powered craft.

A UK company, Oceanfoil, has revisited the wing sail and is offering a new patent for a revised and improved design that became available for retrofitting in the beginning of 2015 (Figure 3.33).

Figure 3.33 Example of Oceanfoil's fuel-assist aerofoil wingsail technology (Source: Oceanfoil.com)

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Designed as a fuel assist technology to a conventionally powered vessel, Oceanfoil‟s wing sail technology allows a vessel to operate at the required speed with reduced engine propulsion. Each wing sail consists of three aerofoils attached to a tail fin or rudder, with each sail resembling the wing of an aeroplane positioned vertically. Each wing sail is free to move on a central bearing and when not in use remains in a feathered mode. There are two main wing sail position settings; ahead thrust or astern thrust. The astern thrust can also be used to slow the vessel.

A vessel can be equipped with up to six Oceanfoil® wing sails, ensuring optimal performance and effective directional force for propulsion to be harnessed from the wind. The number of wing sails fitted varies as a result of calculations conducted by a team of naval architects. Smaller vessels may perform optimally using two or three wing sails, while larger vessels may require up to six wing sails.

Oceanfoil‟s wing sails are automatically controlled via a computer from the bridge so do not require crew resource. Once turned on, the computer will automatically optimise the position of the wing sails relevant to the wind for maximum efficiency. During recent trials in model testing, as well as Computational Fluid Dynamic Analysis the technology has been shown to deliver potential reductions in fuel consumption of up to 20%132.

Flettner Rotors

These are cylindrical structures (fixed, telescopic or collapsible), mounted on the deck and spun mechanically. Using motors powered by the ship‟s electrical supply, the cylinders spin to use the Magnus effect and generate forward thrust. The technology was first proven in the 1920s on a number of ships, but was largely forgotten until the oil crisis in the early 1980s which saw the oceanographer, Captain Jacques Cousteau, and his team introduce the „TurboSail‟, a non-rotating fan-driven design, on his research vessel Alcyone. In 2010 Enercon began trials of the 12,800dwt E-Ship 1 with four Flettner rotors powered initially by the exhaust gas from the main conventional turbine motor. Retrofitting Flettner rotors to bulkers and tankers up to VLCC class is being actively considered although the use of deck space for different ship types is a key consideration. There are now modern concept designs adopting Flettner style rotors. Examples of this technology are shown in Figure 3.34.

Figure 3.34 Ships using rotor sails (Magnus effect) Alcyone (left) and E-Ship 1 (right)

Conclusions

Wind-assisted propulsion is one of the few technologies potentially offering double digit fuel savings with relatively short payback periods01. Recent technological advances in materials, automation and control systems, weather routeing systems and computational fluid dynamics mean that the industry today is better positioned to overcome previous challenges. However, challenges related to safety, operation and performance optimisation need to be addressed for each of the aforementioned technologies133.

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There is potential for soft sails to be utilised by Orkney ferries and given the strong wind resource in Orkney, the uptake of this conventional technology with modern application could reduce the running costs and emissions of vessels. At present retro-fitting with soft sail technology is not practiced as the technology requires specific adaptations to hull design etc. in order to operate efficiently.

Fixed sail technology also has potential to be utilised, however at present it is unclear if the technology would be suitable for the relatively small vessels that make up the fleet. Oceanfoil highlight that their technology is scalable from “small coastal vessels to the largest bulk carriers and very large crude carriers”, but the relatively large amounts of deck space required to accommodate cars and other cargo and the resulting space that the addition of wing sails would take up, could limit the feasibility of this concept. These are also important considerations for the potential use of Flettner rotors.

Overall, wind-assisted propulsion is unlikely to be the most appropriate method to reduce the carbon footprint of the Orkney inter-isles ferry fleet. The use of these technologies (particularly wing sails and Flettner rotors) is more suited to the merchant shipping industry which travel long distances and carry heavy loads, whilst having relatively large amounts of free deck space to accommodate the necessary infrastructure. The short routes and often strong gusty wind conditions experienced throughout Orkney could limit the use of sails if winds are too strong. Furthermore, retrofitting of existing vessels with wind-assisted technology is unlikely to provide the greatest benefit as performance optimisation is best achieved through new build technology. It is conceivable that if a new build ferry was to be suggested as the most appropriate option to reduce the carbon footprint of the fleet, then other options that would provide a greater reduction in emissions and help overcome the curtailment of energy experienced in Orkney‟s outer Isles (e.g. hydrogen production) may be a more practical option.

3.5.2 Compressed Air and Liquid Nitrogen

Compressed air and liquid nitrogen represent two alternative sources of energy storage for ship propulsion. Both require an input of energy during production (liquid nitrogen) or compression (air). As with hydrogen the necessary energy requirement can be derived from conventional and non-fossil fuels or renewable sources together with the same caveats. Furthermore, being energy storage media they exhibit similar system behaviours to those of the more conventional battery or capacitor technologies.

An assessment of the usefulness of these storage media will depend on their system mass for the amount of energy required between recharge. However, inherently these are low energy density propulsion methods. To successfully deploy these media it would be necessary to include pressure vessels and, in the case of liquid nitrogen, cryogenic systems: both well-known technologies in land-based systems. In the case of compressed air there would be the potential danger of blast if a tank for some reason ruptured. However, the technology for protecting compressed gas tanks from shock, in for example a collision scenario, is well known in the container and railway industries. Corrosion of pressurised tanks in a marine environment may also present a problem and suitable inspection regimes would be essential.

On land, compressed air energy storage is used only in conjunction with diesel or gas turbines; the compressed air feed means that the pre compressor is not needed, and therefore the prime mover (main engine) can operate with approximately 15% greater efficiency.

With compressed air storage, the considerable amount of energy used to compress the air is not all stored on board the ship as the hot compressed air is allowed to cool to room temperature. This heat energy is lost. Therefore, to obtain substantial energy from the pure expansion of this stored compressed air (without using it in the compressor of a prime mover); low-grade heat must be provided to supply the required energy. Sea water heat exchangers are a possible source of this heat. The same situation arises with liquid nitrogen; a source of low-grade heat is required to drive the evaporation and create a useful pressure.

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Being energy storage media they have the advantage of generating no CO2, NOX or SOX emissions to the atmosphere when in use on board the ship.

Some potential advantages and disadvantages of the technology

Advantages:

 Compressed air and nitrogen generate no CO2, NOX or SOX emissions to the atmosphere when in use on board a ship;  Uses land-based sources of non-fossil fuel power for creation;  Tank storage technologies are well understood; and  Although these are low energy density methods of energy storage, the short routes operated by Orkney inter- island ferries could be suited to these forms of storage.

Disadvantages:

 A supply infrastructure and distribution network would need to be developed;  The size, pressure rating and cryogenic capabilities, in the case of nitrogen, of the ship storage tanks will determine the amount of energy storage and hence usefulness of the concept;

 There is an attendant blast risk with high pressure tanks should fracture be initiated;  Corrosion can be a significant issue in salt-laden environments with high pressure tanks; and  Largely untried in the marine industry for propulsion purposes.

3.5.3 Anhydrous Ammonia

Anhydrous ammonia is a dangerous, poisonous gas, but it can be compactly transported as a liquid in pressurised tanks at about 30 bar or cryogenically in unpressurised tanks. This is a bulk industrial commodity, and can be burned in both diesel engines and gas turbines. While it emits no CO2 at the point of use, it cannot be considered „carbon-free‟ unless its manufacture (on land) does not emit carbon dioxide, which is not currently the case. Its calorific value is about half that of diesel, so storage requires some adaptation but much less than carrying hydrogen.

Some potential advantages and disadvantages of the technology

Advantages:

 No greenhouse gas emissions on board ship;  No sulphur emissions;  There is mature, bulk manufacture of 130 million tonnes a year which is very scalable; and  Can be produced renewably resulting in very little emissions. Disadvantages:

 Handling requires new procedures for dangerous gases;  New bunkering facilities and infrastructure required worldwide;  Some additives needed to promote ignition in diesel engines;  Traditionally made from natural gas, so always more expensive than LNG; and  There are some corrosion issues which need to be overcome134.

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3.5.4 Solar Photovoltaics and Hybrid Systems

Solar photovoltaic (PV) applications use electricity generated by PV cells. All advances in this fast evolving technology are available for maritime transport use. The primary limitations are the lack of sufficient deployment area for the PV panels and the energy storage required. Recent advances in energy storage technology offer higher potential and better prospects for solar PV powered propulsion systems for ships in the short term, but full ship propulsion using solar PV requires further technical development and is likely to be confined to very small ships135.

The previously mentioned Greenheart design for a 220 gross tonnage freighter proposes using solar charged lead-acid batteries to provide auxiliary propulsion for its primary sail rig. Batteries may offer a potential hybrid solution in conjunction with other modes of propulsion for some small to medium-sized ships, provided that their recharging does not increase the production of other harmful emissions. OCIUS Technology‟s SolarSailor design uses hybrid fixed sails in tandem with solar PV arrays, both sail and deck mounted as shown in Figure 3.35.

Figure 3.35 OCIUS technology's solar sailor design utilising fixed sails with PV panels136 (see also Section Wingsails or Rigid Sails)

These have now resulted in commercially competitive harbour ferries in Australia, Hong Kong and Shanghai and show strong promise for deployment on larger ships. Japan-based Eco Marine Power is developing a large solar-sail Aquarius MRE (Marine Renewable Energy) system for tankers and bulkers. WWL‟s proposed E/S Orcelle zero-emissions137 car carrier is proposing a similar set-up with solar panels incorporated into large fixed wing sails that can harness power in sail mode or when deployed horizontally on deck. The Auriga Leader project138 by NYK and Nippon Oil Corporation in 2008/09 saw 328 solar panels fitted to a 60,000 gross tonnage car carrier providing 40kW, about 10% of the ship‟s power while stationary in dock. It was also the first ship to direct solar power into the ship‟s main electrical grid. The solar panels produced 1.4 times more energy on the ship at sea than at port in Tokyo but the overall contributions to propulsive power were minimal.

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Some potential advantages and disadvantages of the technology

Advantages

 Relatively cheap method of electricity production; and  Supply of solar energy is greatest at times of greatest energy demand.

Disadvantages

 Limited deck surface area on vessels which does not interfere with cargo handling (could be overcome by adopting solutions as shown in Figure 3.35); and

 Limited power output has demonstrated that the power attainable would only be sufficient to augment the auxiliary power demands.

Solar PV (and also wind) could potentially be used to charge shore-based battery systems supporting rechargeable electric propulsion units for smaller scale car ferries operating on very short routes. It also has applications in augmenting other electric supplies for most shore-side infrastructure. In order to accrue the greatest benefits, this type of use needs to be coupled with low carbon and other power saving technologies. Solar (along with wave energy and wind turbines) may have a future role to play in providing initial energy for hydrogen separation from seawater for hydrogen fuel cell technology.

3.5.5 Wave Energy

Current wave power plant designs suggest that an entirely new design concept will be needed to be readily applicable to the shipping sector‟s energy needs. The small numbers of developers in this field are attempting to learn from biology and mimic the manner in which dolphins and pelagic fish use muscle energy in marine environments. The ambitious E/S Orcelle car carrier by Wallenius Wilhelmsen Logistics (WWL) proposes using a series of 12 underwater flaps (fins) (in combination with solar and wind energy), which are modelled on the tail movements of Irrawaddy dolphins. The aim is to harness and convert wave energy in the ocean to create propulsion and generate electricity and hydraulic power for ship‟s systems139.

3.5.6 Nuclear

The use of nuclear power in maritime propulsion has been in use since the 1950‟s and helped revolutionise naval military operations. The large amounts of energy that is produced together with infrequent re-fuelling requirements (>10 years), lent itself to the powering of military vessels. Nuclear-powered vessels are mainly military submarines and aircraft carriers; however nuclear propulsion has proven essential in the Russian Arctic where operating conditions (large power requirements and difficulties associated with refuelling) are beyond the capability of conventional icebreakers.

A nuclear-powered ship is constructed with the nuclear power plant inside a section of the ship called the reactor compartment. The components of the nuclear power plant include a high-strength steel reactor vessel, heat exchanger(s) (steam generator), and associated piping, pumps, and valves. Each reactor plant contains over 100 tons of lead shielding, part of which is made radioactive by contact with radioactive material or by neutron activation of impurities in the lead.

There is potential for nuclear propulsion to be implemented into commercial shipping operations, e.g., cruise liners, bulk carriers and supertugs. However, the small routes covered by the Orkney inter-island ferry service, the small vessels that make up the fleet, safety concerns and the astronomical costs associated with commissioning and decommissioning procedures mean it is not suitable and is therefore not considered further in this report.

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4 REGIONAL AND NATION INTEGRATION

4.1 LEGISLATION AND PLANNING IMPLICATIONS

Some of the proposed technologies, e.g. hydrogen and full electric options may require upgrades to or development of new shore side infrastructure. Hydrogen production would require the installation of electrolysis, compressor and storage devices while electricity storage would involve installation of either large scale batteries, vehicle mounted batteries or small transportable pod-type batteries. There is also the potential for batteries to be stored directly on the vessel which as well as allowing the potential for charging at any voltage, at other locations, may decrease the impact on the pier and conservation area as no storage equipment would be needed on the pier itself.

The following section provides a summary of the planning requirements related to the development of these infrastructure options.

4.1.1 National Legislation and Advice

National Planning Policy for Scotland is set out in the Scottish Planning Policy (SPP), the Scottish Government‟s policy on how nationally important land use planning should be addressed across the country. The proposed development is in line with and addresses key policies within the SPP such as promoting rural development and supporting a low carbon economy. Supplementary Planning Advice Notes (PANs) set out advice on good practise and inform technical planning matters.

The National Planning Framework (NPF) is the Scottish Government‟s long term strategy for the spatial development of Scotland. Within this National policy, the Government is committed to developing Scotland‟s renewable energy potential and reducing greenhouse gas emissions by 2050 whilst the existing environment and communities are protected. Developments which are classed as „national‟ or „major‟ require a statutory pre-application consultation with the community before a planning application can be submitted. National developments are identified in the NPF and major developments defined in planning regulations.

Under Planning Advice Note (PAN) 1/2013: Environmental Impact Assessment (EIA), EIAs are required if a development is likely to have a significant effect on the environment due to its nature or size (Schedule 1). Moreover, for more sensitive environments i.e. if the project affects an area of a World Heritage Site, National parks, etc. then EIAs are also required for Schedule 2 developments that exceed specified thresholds (e.g. industrial installations for the production of electricity, steam and hot water when the area of development exceeds 0.5 hectares). The local planning authority should determine whether the project is of a type listed in Schedule 1 or Schedule 2 of the regulations.

The main document used for planning application determination is the Orkney Local Development Plan (adopted April 2014). This plan details policies and proposals on a spatial strategy for land development in Orkney over the next 10 - 20 years.

OIC recognise that the planning system has a key role to play in delivering sustainable development, and planning decisions should promote development that safeguards and enhances the long term needs of the economy, society and the environment, whilst being mindful of the responsibilities set out in the Vision Statement. These are factors which are highlighted in Scotland‟s first Land Use Strategy through its Principles for Sustainable Land Use. The Spatial Strategy and policies of the Local Development Plan are consistent with these principles, and they seek to ensure that future development planning decisions in the County are well informed and will deliver enduring benefits to Orkney.

The impacts of the different technology infrastructures are largely site dependent and there are certain considerations that must be made when developing infrastructure at particular sites. For example, sites with conservation status (e.g.

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Stromness, Kirkwall, Balfour village and St Margaret‟s Hope) require special consideration. Within the Orkney Local Development Plan, Policy HE4: Conservation Areas, states the development will only be permitted where it is consistent with and appropriate to the character and setting of the Conservation Area. OIC must be consulted for any development on the pier as it rests within an urban conservation site. However, Policy SD6 of the Orkney Local Development Plan: Renewable and Low Carbon Energy Developments, states that renewable schemes will be supported if sufficient information is provided to show that the development will not cause significant effects either individually or cumulatively. Assessment of sites should also take into consideration the risk from coastal flooding and where appropriate include a communal Sustainable Drainage Scheme (SuDS) area. Requirements for drainage are detailed in Policy D4: Sustainable Drainage Systems. More detailed information on the specific planning issues affecting specific sites around Orkney can be found in the Orkney Local Development Plan140.

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5 SCREENING METHODOLOGY: ABSOLUTE ASSESSMENT

The screening process is part of the „optioneering‟ process that is used to assess each of the options against different criteria and to select the most suitable ones. There are no strict rules for deciding which options to take forward. The overall screening process was divided between a preliminary process, which was a way to coarsely scope out the most irrelevant technologies, and a secondary process, which was more refined.

The methodology used in this report acts by scoring each technology against assessment factors. The focus is on the highest positive and negative scores, bearing in mind that the assessment matrix is a log scale and all the assessment factors (such as safety, cost, etc.) have been designed to have a score between -2 and 2; the lower the score, the less suitable the technology. For each assessment factor, the scores hold a different significance as described in Appendix 1.

In addition to this scoring system, each assessment factor, or criteria, has a different importance (or weight) in the overall assessment. The importance factors are a means of ranking the different criteria by priority from 1 to 5, 5 being the most important. They are by definition subjective and vary dependent on the requirements for a specific project. The score obtained through the previous scoring process by each technology against each assessment factor is then multiplied by this importance factor.

The methodology can thus be divided into two phases: the scoring phase, where technologies are assessed against each assessment factor; and the weighting phase, where the weights are taken into account in order to determine which technology is the most suitable for a given project. Table 5.1 below summarises the methodology for two different technologies and three assessment factors (A, B and C) with different importance factors (a, b and c).

Table 5.1 Summary of the methodology for the screening process

Assessment A B C factor Total Non Non Non Weighted Weighted Weighted weighted weighted weighted

Technology 1 1 a x 1 -1 b x -1 0 c x 0 a-b+0

Technology 2 -2 a x -2 2 b x 2 1 c x 1 -2a+2b+c

Phase 1: scoring phase Phase 2: weighting phase

The score is referred to as „weighted‟ when the importance factors are taken into account. The total only takes into account weighted scores. In general, technologies with a negative total score will be considered as unsuitable while a technology with a positive score will be deemed suitable. The technology with the highest score will be considered as the most suitable and the one with the lowest score as the least suitable.

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5.1 PRELIMINARY SCREENING PROCESS

A preliminary screening process was undertaken in order to filter out any options with limited feasibility. The options taken forward into the secondary screening process are considered practical to implement as well as being generally acceptable. In total, 16 technologies were screened. After the preliminary screening process, the remaining options will be studied further before being processed through a second screening process.

5.1.1 Assessment Factors

The description of the assessment factors used to score the technologies is provided in Table 5.2.

Table 5.2 Details of the expanded assessment factors for the preliminary screening process

Category Assessment factors Descriptions

Market The time needed for the technology to be commercially available. Time to market readiness

Financial weight of a technology: it includes the operational and Finance Overall cost capital costs related to the required equipment. Other costs are not considered here (transport, crew training, etc.).

Capacity of a technology to conform to relevant laws and Regulation Regulatory compliance regulations.

Very strong tides and sea conditions, which could cause issues for a number of the concept vessels already in circulation, often Suitability of technology occur in Orkney. This factor evaluates the capacity of the Technical technology to cope with such conditions. characteristics Availability of manufacturing, energy production and storage Availability of infrastructures. The more local the solution, the more suitable the infrastructure technology.

For the preliminary screening, all the criteria were considered of equal importance (i.e. no weight/importance factor applied).

The detailed scoring process for the preliminary scoring process is available in Appendices 1 and 2.

5.1.2 Results from the Preliminary Screening

Figure 5.1 presents the main results from the preliminary screening process.

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Figure 5.1 Primary screening results

Hydrogencombustiondirect - Waveenergy Compressedair Flowcell systems Anhydrousammonia LiquidNitrogen Nuclear Sailssoft and ridgid Biomass HydrogenCo-burning - HydrogenFuel - Cells Electricalbattery drivensystems CompressedNatural Gas Biofueledsystems Electrichybrid Driven systems Diesel Dieselelectric driven systems LiquidNatural Gas 30

-10

Totalweighted Scoring -20 Suitable Technologies Non suitable technologies -30

Only technologies with a score greater than zero were considered as suitable for the preliminary screening phase.

The eight remaining options that will be studied further in the secondary screening process are:

 Liquid Natural Gas technology;

 Diesel-electric driven systems;

 Electric hybrid driven systems;

 Biofueled systems (first generation biofuels);

 Compressed Natural Gas technology;

 Electrical battery driven systems;

 Direct hydrogen combustion systems;

 Fuel cells technology; and

 Co-burning (hydrogen and conventional diesel) systems.

Although vessels powered by diesel-mechanical propulsion were included in the preliminary screening process (for the sake of completeness) and as expected, scored highly; the fact that this study is assessing low carbon solutions, means this technology is out with the scope of this study and is therefore not considered in the secondary screening process.

The table in Appendix 1 gives the detailed results of the preliminary screening. The score is referred to as “weighted” when the importance factor is taken into account.

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The optioneering shows that the diesel-electric technology is the most suitable (when diesel-mechanical is discounted) with the criteria considered. The wave energy system is the least suitable.

5.2 SECONDARY SCREENING PROCESS

Phase 2 screening ensures that the options taken forward could be used effectively in an Orkney context. Ideally, the full screening process will provide between two and four suitable options to be taken forward to the shore side design analysis.

5.2.1 Assessment Factors

A description of the assessment factors used to score the criteria is provided in Table 5.3.

In order to provide the most robust results it was decided that the secondary screening process should take into account the variability in the Orkney inter-isles ferry routes. The routes vary in a number of factors, including size of vessel required, fuel requirements, the distance of route and the subsequent regulatory requirements (e.g. outer isles classed as sea-going so subject to strict regulation). As previously discussed in section 2.2, three levels have been assigned to group routes according to these factors (see Figure 2.1).

The secondary screening process will be run for each of these route levels in order to avoid scoping out particular technologies that would perhaps be more suited to, for example, shorter routes, but which would achieve an overall low score due to their inability to service the longer routes.

Table 5.3 Details of the expanded assessment criteria

Category Assessment Assessment factors Importance factors factors

This factor covers the level of risk that would be associated with a particular fuel/technology. It is considered to cover several aspects, such as how quickly and easily the technology and its required Risk 5 infrastructure could be implemented, any potential drawbacks to the implementation of a technology (e.g. safety concerns) and the potential future viability of the proposed fuel/technology.

Ability to deliver This is related to the ability of particular fuel types to energy be able to meet and surpass the energy requirements Technical 5 requirement for of particular routes. characteristics route(s)

This factor aims to assess the potential infrastructure requirements of the technology ranging from large Infrastructure amounts of infrastructure being required at all ports, 3 requirements which receives a low score, to minimal upgrades which receives a high score.

This factor assesses the fuel cost and maintenance Operational cost cost. It does not take into account embedded 3 infrastructure.

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Category Assessment Assessment factors Importance factors factors

Required energy This factor aims to assess how efficiently particular input relative to technology types use energy to generate propulsion. propulsion This reflects the amount of energy needed to be 2 output purchased to achieve the required output. (efficiency)

This is related to the ability of a particular Robustness and fuel/technology type to be able to service particular flexibility of the routes, with no requirement for changes in the current 2 service timetable, coupled with its ability to provide cover to Socio-economic other routes whilst other vessels are out of service.

This is related to the ability of a particular technology Impact on to relieve pressure on grid constraints, particularly in 1 curtailed energy the outer isles.

Local content – This relates to the ability of the technology to create opportunities for short, medium or long term opportunities to local 1 local business businesses and employment. and employment Environmental

This is related to the emissions reduction capability of Impact on the fuel/technology ranging from minor reductions in 1 emissions emissions to no emissions.

5.2.2 Results from the Secondary Screening

The results of the secondary screening are separated for each route level and are presented in Figure 5.2 to Figure 5.4. The maximum score which can be reached according to the weights used is 46. The technology is considered „most suitable‟ if the final score is over 20, and „least suitable‟ if the final score is under 15.

Note: Unlike in the preliminary screening, electric hybrids have been separated into two categories which are „Diesel electric hybrid‟ and „Alternative fuel electric hybrid‟ due to a need to score differently different types of hybrids. Thus „Alternative fuel electric hybrid‟ concerns LNG electric hybrid, CNG electric hybrid, and Hydrogen electric hybrids.

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Figure 5.2 Results from the secondary screening for route level 1.

10 Most suitable technologies 5 Suitable technologies Least suitable technologies 0

Figure 5.3 Results from the secondary screening for route level 2.

10 Most suitable technologies 5 Suitable technologies Least suitable technologies 0

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Figure 5.4 Results from the secondary screening for route level 3.

10 Most suitable technologies 5 Suitable technologies Least suitable technologies 0

For route level 1 (Figure 5.2), the best ranked technologies are LNG, electric hybrid systems and electric battery systems, closely followed by hydrogen fuel cells, hydrogen direct combustion, diesel systems and CNG.

For route level 2 (Figure 5.3), the best ranked technology is LNG, followed by electric hybrids, diesel systems and CNG.

Finally, for route level 3 (Figure 5.4), the best ranked technology is LNG, followed by electric hybrids, diesel systems, and CNG.

Figure 5.5 summarises the results, allowing a comparison of the fuel suitability for each route level. It is to be noted that some technologies score suitability highly depending on the route level while others do not vary with it. This is due to the fact that in the first case, the technology is limited by size/weight and thus the power duration is limited too, whereas in the second case, the power duration is longer.

It should be noted that the weights in Table 5.3 completely depend on the panel that fixed them. Modifying the weights, especially increasing the importance of the technologies being low carbon, changes the scores, putting electricity, hydrogen and electric hybrids forward in the ranking (Figure 5.5).

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Figure 5.5 Overall results of the secondary screening process: fuel suitability to each route level. 30 Weighted total 25 level 1 level 2 level 3 20

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6 FUEL SCENARIOS COMPARISON

This chapter compares the different fuels that have passed the full screening process. Section 6.2.1, below, focuses on the conversion of the current fuel usage to the consumption it would represent considering each of the potentially suitable fuels.

The analysis compares the consumption for the different fuels and matches these to current requirements. It also considers the infrastructure upgrades the different options would require.

6.1 ORKNEY’S INFRASTRUCTURE

Orkney has an integrated energy system where decisions and technologies applied in one area of energy management have important implications in other areas of energy management. The adoption of new technologies that reduce the dependence on hydrocarbons in the marine transport sector may require extensive upgrades of infrastructure in regards to the hydrogen, biofuel and electric ferry scenarios.

The infrastructure issues for the low carbon scenarios investigated are compared using the following objectives affecting Orkney:

 high fuel import costs – objective to reduce fuel imports;  a super-abundance of renewable energy distributed in potentially useful locations – objective to maximise the distributed renewable energy resources at respective harbours; and

 a wish to extend Orkney‟s reputation for clean energy innovation – distributed and centralised energy scenarios for potential vessels.

Each ferry terminal will have unique infrastructure requirements depending on the existing buildings, distance from resource and space for new infrastructure. However, there is also a potential for cost sharing opportunities by utilisation of the energy which is currently going to waste through the limits imposed by the constrained electrical grid in Orkney. The suitability of technology are categorised as follows:

 grid capacity and pinch points;  ability to deliver and transport the renewable generation and conversion technology; and  availability of space and the suitability of locations for construction of any energy storage or generation facilities required.

With regards to the above issues, the report examines the infrastructure requirements of the low carbon ferries for the whole of Orkney as well as for individual harbours and ferries, where applicable, in the following sections:

 energy availability and distribution;  transport and storage of potential fuel;  potential site locations; and  legislation and planning implications for construction and operations.

6.1.1 Current and Potential Electrical Infrastructure

Orkney has a broad energy mix including both conventional imported fuels and renewable energy comprising wind, solar, wave and tidal energy. All marine fuel is imported into Orkney. There is also a large quantity of

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embedded energy imported into the island in terms of fertilisers and ammonia. Orkney has the potential to produce further renewable energy that may be suitable for marine transport through the production of hydrogen from surplus (currently curtailed) wind energy, biofuel based hybrids and electric based ferry operations.

This section of the report investigates the existing energy resources and their distribution across the islands through the following:

 existing grid infrastructure; and  potential renewable energy resources available to each harbour.

Grid Components

Import/Export via Subsea cables: The Orkney grid comprises a mix of wind, tidal, wave and gas energy all linked by two 33kV (20MVA) subsea interconnectors to mainland Scotland. This allows generators on Orkney (mainly wind but also wave, tidal, solar and gas) to export electricity to the Scottish mainland and for energy to be imported from the mainland when generators on the islands are not generating enough to meet local demand. Orkney has over recent years become a net exporter of electricity. This is attributed to the increase in the number of wind generators on the island.

Local Grid: The 33kV interconnectors are connected to fifteen 33/11kV substations around the isles and internally there are several spurs and circuits with one of these circuits connecting the north isles to the mainland. The grid has been divided into Zones of Distribution to cater to the increase in wind generation which saw the islands become a net exporter of electrical energy amidst challenges of curtailment for newer generators.

Electrical Battery Storage: Scottish Hydro Electric Power Distribution (SHEPD) has connected the UK's first large scale battery to the local electricity distribution network on Orkney. This 2MW battery (800kWh) was commissioned in 2013 and is now operational. By introducing energy storage, this project aimed to allow energy that would otherwise be constrained from the network to be stored, and thus allow more renewable generation onto the network. The trial project will investigate how large scale batteries could play a role in the release of capacity on the electricity distribution network and explore how the intermittency issues affecting renewable generation could be resolved.

Non-renewable Power Generation

Kirkwall Power Station is a diesel powered generator that ceased regular operation in the late 1990's after the second cable across the Pentland Firth was commissioned. It currently runs monthly for test purposes and covers faults and system outages on mainland links.

Flotta Gas Turbine: Crude oil comes ashore at the Flotta Oil Terminal and a fraction of this is used at the terminal for heating and electrical generation. The oil terminal uses gas extracted from the crude oil for onsite heating and to power five (3MW) gas turbine generators. The peak terminal power demand is 4MW with excess exported to the national grid via its 10.5MW grid connection.

Renewable Energy Based Electrical Composition (based on the Orkney Energy Audit 2014)

Small scale wind turbines (up to 50kW): Data on planning permissions granted by OIC show a total capacity of 6031.6kW for small turbines (under 50kW). The majority of these turbines are between 5 and

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20kW. In September 2012, SSEPD imposed a moratorium on all new generation, except the very smallest generators that are classed as G38; which has a limit of 3.6kW per phase.

Orkney currently has about 11% of all the wind turbines in the UK and 5% in terms of installed capacity, which are registered for FITs. It should be noted though that not all of these are in the under 50kW turbine size bracket.

Large scale wind turbines (above 50kW): According to OIC there is 43.623MW of installed capacity from large wind turbines (of 50kW and above) in Orkney, with a further 17.143MW scheduled for construction with approved planning permission. The most common large scale wind turbines are 900kW and 2MW turbines. There is also planning permission granted for more turbines between 500kW and 900kW.

Wave and Tidal: EMEC has wave and tidal test facilities located at Billia Croo and the Fall of Warness respectively. The tidal test site has a grid connection of 4MW and the wave test site has a grid connection of 7MW. Even though the technologies are at an early stage of development, the output of energy from these sites is expected to rise in the future. The Crown Estate held a leasing round for commercial and demonstration marine energy projects in the Pentland Firth and Orkney Waters (PFOW) in 2011. There are currently leases held for 550MW of wave energy project and 530MW of tidal project in Orkney waters.

Active Network Management

The main challenge to the Orkney grid is the limit imposed by transmission and distribution lines between the internal zones of distribution as well as between the Orkney and the Scottish mainland. Renewable energy produced within the islands is predominantly generated from wind turbines. The north isles in particular have a problem of being on constrained connections which lead to them being switched off during periods of over production.

The Active Network Management (ANM) system is an electrical distribution technology that monitors the electrical network and controls the distributed generation. It was introduced in Orkney to allow further operators to connect to the grid at their own risk of curtailment without substantial upgrades being necessary. The system receives real time information from network measurement points.

The network is divided into Distribution Network Operator (DNO) zones as illustrated by Figure 6.1 below. When a limit at these the inter zone connection points is reached the system will control the ANM generation to reduce their output or shut them down temporarily.

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Figure 6.1 Orkney’s DNO Zones for ANM

There is potential for the ferries in Orkney to take up the existing curtailed energy by use of low carbon options such as through the implementation of electrical and hydrogen based ferry technologies. However, it is important to note that the potential for constraint reduction may be limited by other factors such as route and technology selection which will determine the times and locations at which the vessels can refuel and whether this matches geographically and temporally with the curtailed energy, as well as the availability of energy storage.

Types of Generation Connection

The adoption of low carbon fuel options derived from electrical energy will be dependent on the grid capacity in Orkney as well as the location of the pinch points at generation and consumption times as shown in the ANM figure above (Figure 6.1). A solution in matching the ferry requirements with the curtailed energy sources requires an analysis of the following classes of distributors allocated by the DNO:

Firm Generation

Operators with a Firm Generation (FG) connection are able to operate without constraint in the event of the loss of either one of the two submarine cables to the mainland. The amount of generation that can be connected in this way is based on the capacity of the smaller mainland submarine cable circuit (20MVA) plus the minimum demand in Orkney. This amounts to a maximum of 26MW (based on a previous minimum demand condition of 6MW).

Non-Firm Generation

Operators with a Non-Firm Generation (NFG) connection are able to operate as long as both submarine circuits are in service. In the event of the loss of a submarine cable circuit this group will be signalled to cease operating. The theoretical capacity for NFG is the power rating of a single submarine circuit, approximately 20

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MW. This group will be tripped in the event of a loss of a submarine cable circuit and the power export flow exceeding 20MVA. The theoretical capacity for NFG plus FG amounts to 47MW which is made up of both submarine cables plus the local minimum demand. The amount of NFG capacity is 21MW.

New-Non-Firm Generation

New-Non-Firm Generation (NNFG) is actively managed, by the ANM system, based on the capacity available on the Orkney network due to load variation and diversity in output from existing FG and NFG. According to SSE, there is confirmed NNFG of 22.4MW in Orkney.

Existing Dockside Electrical Supply

OIC Marine Services supply electricity (both 240V and 440V) at most of the piers they operate. Consumption figures for 2013/14 are given in Table 6.1 below.

Table 6.1 Orkney harbours electricity consumption 2013/2014 (Source: OIC)

Pier Electricity consumption in kWh

Burray pier 149

Kirkwall harbour 364,606

Hatston terminal 69,918

Kirkwall marina 22,750

Lyness ferry terminal 13

Lyness Golden Wharf 107,852

Rousay pier 963

Sanday pier 1,056

Loth pier Sanday 1,128

Scapa pier 2,101

Stromness harbour 227,104

Stronsay pier 8,117

Tingwall jetty 11

Westray harbour 4,121

Total 809,889

6.1.2 Current and Potential Biomass Resource

Biomass comes into Orkney in a number of forms ranging from logs, wood pellets, eco-logs, peat and waste wood. However applications for the low energy carbon ferries would involve technologies that are based on ethanol and biodiesel, which can be obtained from vegetable oil, waste oil/fat etc, and biogas (bio-hydrogen, bio-methane) from organic wastes. These biofuels can be mixed with other potential sources, for instance bio-

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hydrogen could be mixed with hydrogen produced via electrolysis and bio-methane with LNG, in order to diversify the production systems and increase the local share in the process.

The potential for biofuel in Orkney is as illustrated in Table 6.2 below:

Table 6.2 Orkney's Biofuel Potential141

Waste type Orkney household waste (Tonnes)

Arising Composted Recycle

Used oils 62 0 62

Vegetal wastes 1,026 691 0

Anaerobic Digesters

There are no longer any operational Anaerobic Digesters (AD) plants in Orkney; however the Westray Development Trust was successful in securing financial support through the Scottish Community and Householder Renewables Initiative (SCHRI) to undertake research on anaerobic digestion.

Table 6.3 below illustrates the potential quantity of bio-waste that can be used in the implementation of low carbon ferries for transport. Studies using organic wastes in a digester have shown that this technology can produce bio-hydrogen and bio-methane.

Table 6.3 Bio waste resource potential142

Bio-wastes Quantity

Animal waste from abattoir 1700t

Fish processing wastes 6000t

Orkney Cheese 13,000m3

Orkney Creamery 470m3

Highland Park pot ale 19,000t

Highland Park effluent 28,000m3

Municipal wastes inorganic* 2,750t

Municipal wastes organic* 2,750t

*Approximately 9,000t of municipal waste is exported to Shetland to feed the district heating plant in Lerwick. These are not taken into account in this table. Potential of food processing waste per harbour

The potential for food processing wastes to be utilised has been found to be only located on the mainland, Westray and Papay as illustrated in Table 6.4 below. Other islands have fish farms, fisheries and cattle which are all processed on the Orkney mainland and are thus included in the figures below.

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Table 6.4 Food processing waste resource potential143

Food processing wastes

Mainland (Kirkwall Harbour) Abattoir near Kirkwall (1,700t)

Orkney Creamery (470m3)

Orkney Cheese (13,000m3)

Highland Park (19,000t pot ale and 28,000m3 effluent)

Orkney Fishermen‟ Society (500t)

Westray and Papay Westray Processors (200t)

Energy Value in Burned/Exported Waste

Embodied energy within waste streams can be used in a digester for the production of biofuel for potential ferry operations. Orkney‟s waste that would otherwise go to landfill or incinerated, is currently sent to Shetland. Here, the majority of it is used in their waste to heat plant, and the rest is composted, recycled or landfilled. The Energy Recovery Plant is operated by Shetland Islands Council (SIC) and provides the principal heat source for the Lerwick District Heating Scheme; run by Shetland Heat Energy and Power Ltd. The waste shipped from Orkney has a calorific value of about 11MJ per kg (11GJ/tonne).

It is important to note that municipal waste comprises 14,500t/yr, 9,000 tonnes of which are sent from Orkney to Shetland each year to feed the incineration plant; 5,500 tonnes of waste remain on Orkney of which only 50% contains organic material.144

6.2 INFRASTRUCTURE UPGRADE REQUIREMENTS

Depending on the fuel considered (the fuels being those that passed the second screening process), different scenarios can be considered. The options consider the means of supplying the different fuels in Orkney. LNG would need to be fully imported and biofuels at least partially to meet the demand to power ferries as local production is not possible or limited due to resource availability. Electricity and hydrogen on the other hand are fuels which can be produced locally in sufficient amounts to power the ferries. In the case of electric hybrid vessels, there is an electrical storage capacity incorporated into the propulsion system. If the vessel is a plugin hybrid then the electricity would be supplied through shore-side grid infrastructure. Otherwise, the electricity to charge the on-board batteries for non-plugin hybrids would be generated on-board from the primary engine and require no shore-side infrastructure.

The impacts in Orkney resulting from either scenario will be socio-economic and physical with the requirements of new infrastructures to be built. These will be discussed in this section.

6.2.1 Fuel Conversion

The fuel conversion calculations are based on the energy densities and system efficiencies for each fuel as shown in Table 6.5 below145,146,147.

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Table 6.5 Fuel per unit energy densities and system efficiencies

Fuel Energy Density Fuel Overall System Efficiency unit kWh kWh/kg

Marine gas oil 1 L 10.7 12.7 0.5

Biodiesel (B100) 1 L 9.8 10.9 0.5

Ethanol (E100) 1 L 6.9 8.9 0.5

Methanol (100%) 1 L 4.8 5.47 0.5

Liquefied Natural Gas 1 L 7.2 13.3 0.42

Compressed Natural Gas 1 L 2.5 13.3 0.42

Hydrogen at 0oC, 1atm 1 Nm3 3 33.3 0.52

Hydrogen at -252.87oC, 1atm 1 L 2.36 33.3 0.42

Electricity (renewable) 1 kWh 1 0.11 0.77

The figures for efficiencies in Table 6.5 only take the engine/propulsion system and some additional equipment (battery, fuel cell) into account. Additionally, it should be noted that there may be a number of other efficiencies not included within this work. For example it is understood that gearboxes within the propulsion system may result in 2-6% energy losses depending on the scale and function of the gearbox. The proportion of energy loss will correlate to the rotational speed of the combustion engine and the speed of the electrical generator; the greater the change the greater the energy loss. This report works on the assumption that there will be no direct driven propulsion systems, but electrical propulsion systems for greater flexibility.

Using the overall system efficiency and fuel energy density of the current vessels within the Orkney Ferries fleet, the equivalent energy consumption was calculated. Taking the engine efficiency for each alternative system into account, it was then possible to calculate the potential fuel consumption for each system. The results are shown below in Table 6.6.

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Table 6.6 Current fuel consumption per vessel per year and equivalents for other fuels

(litres)

quivalent quivalent

direct burn direct

fuelcell

Vessel 2015 in usage Fuel (Litres) (B100) Biodiesel (litres) equivalent equivalent Ethanol (litres) equivalent Methanol (litres) (litres) equivalent LNG E CNG (L) equivalent Hydrogen - equivalent Hydrogen (L) (kWh) Electric Full

MV Earl Sigurd 664,640 725,678 1,030,674 1,481,593 1,175,868 3,386,499 2,897,510 3,587,393 4,617,953

MV Earl Thorfinn 715,360 781,056 1,109,326 1,594,657 1,265,601 3,644,930 3,118,625 3,861,154 4,970,358

MV Eynhallow 156,400 170,763 242,533 348,642 276,700 796,895 681,829 844,169 1,086,675

MV Golden Mariana 22,470 24,534 34,845 50,089 39,753 114,490 97,958 121,282 156,123

MV Graemsay 77,410 84,519 120,042 172,560 136,952 394,422 337,470 417,820 537,849

MV Hoy Head 345,454 377,179 535,704 770,075 611,170 1,760,170 1,506,013 1,864,587 2,400,232

MV Shapinsay 151,506 165,419 234,943 337,731 268,040 771,957 660,491 817,751 1,052,668

MV Thorsvoe 120,022 131,044 186,121 267,549 212,341 611,541 523,238 647,819 833,919

MV Varagen 657,985 718,412 1,020,354 1,466,758 1,164,094 3,352,590 2,868,497 3,551,473 4,571,714

Total 2,911,247 3,178,606 4,514,542 6,489,654 5,150,519 14,833,494 12,691,630 15,713,447 20,227,492

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6.2.2 Scenario 1: Imported or partially imported fuel

Importing fuels implies an increase in the shipping and road haulage of substances requiring specific handling and safety measures and infrastructures. Terrestrial storage infrastructure would also need to be built in one or several locations depending on the vessels to be powered by the fuel considered.

Natural Gas Ferries (LNG and CNG)

An LNG or CNG infrastructure within Orkney would require the introduction of significant changes to existing infrastructure. Bunkering facilities would have to be introduced to refuelling ports. This would generally need to be located where the boats dock overnight. The simplest solution would see refuelling conducted on the mainland: Kirkwall, Tingwall, Houton and Stromness. This would limit the capital expenditure required as there would only be building on the Mainland and not a number of units on islands where building project tend to be more expensive.

A natural gas solution would not provide any benefit to Orkney‟s curtailed grid as it would not apply an additional electrical load to that used by the current fleet. However, a natural gas solution could still apply an electrical load on the outer islands through the cold ironing requirements of the ferries. Thus, the benefit of applying these loads among the islands to absorb a portion of curtailment would have to be weighed against the additional refuelling facilities to accommodate these vessels. If this was the case then a study would be required to determine the vessels overnight power requirement and the feasibility of the current infrastructure among the islands to meet these. Additionally, the predicted consumption of LNG or CNG would be required in order to size bunkering and refuelling capacities. Table 6.6 previously outlined predicted consumption of fuels converted from current diesel use. It was calculated that approximately 5.1 million litres of LNG or 14.8 million litres of CNG would be required to meet current route requirements.

Biofuel Powered Ferries

The potential for production of first generation biofuel for Orkney ferries seems very limited. There is no significant resource to locally produce bio-ethanol and bio-methanol, and the amount of biodiesel that could be produced from waste oil collection is considerably lower than the vessel requirement.

Thus these biofuels would need to be imported if it was opted to power one or more ferries on biofuels. However, bio-methanol and bio-ethanol efficiencies being significantly lower than biodiesel, using these biofuels to power ferries in Orkney may require more space than is feasible (the volume of fuel needed would increase to over 55% for ethanol and 120% for methanol). Therefore, biodiesel will be the only biofuel to be considered in this study.

The characteristics of biodiesel are very similar to petroleum diesel and as it is usually uses blended (B20), the change from the current situation in term of infrastructure would be minimal. The operational cost would be higher than petroleum diesel, as biodiesel is more expensive and slightly less efficient. If targeting minimal infrastructure changes, powering Orkney ferries with B20 would suit all routes, while using B100 would suit level 1 and 2 routes, bearing in mind that B100 powered ferries would require approximately 10% more fuel than the current usage (Table 6.6). However, the carbon reduction benefits to Orkney and to the environment would be low in comparison to other technologies described in this study.

6.2.3 Scenario 2: Local fuel production

The selection of low carbon ferries systems using electricity would involve tracking ANM response to total power flows at key “pinch-points” within the Orkney distribution grid. With an increase in electric demand by ferry charging or hydrogen production the wind turbine outputs could be effectively increased hence reducing the curtailed power. Supervisory Control and Data Acquisition (SCADA) systems that are linked to the

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production and curtailment patterns of specific generators will determine the appropriate size and technology for each harbour ensuring appropriately matched loads against generation.

This section aims to match the current curtailment of the grid to the amount of energy being used by the vessels. For the purposes of this analysis, it was assumed that the low carbon ferries will maintain the same routes with the same number of sailings in one period.

In order to make estimates of the grid balancing benefits, the study investigated the trends and factors affecting the grid pinch points. It was observed that curtailment generally occurs when:

 local consumption is less than average local generation (e.g. when the air temperature is higher in the summer). Local consumption has also been observed to peak during the waking and evening hours which is a general trend across the UK. Consumption of electricity is the lowest in the middle of the night; and

 local electricity generation is above average during periods of higher resource (e.g. sustained winds especially in the winter).

Any grid balancing benefits will aim to match the generation or storage of fuel from the electricity produced by the grid at the times of lowest consumption from the local grid.

Implementation

Grid balancing opportunities with low carbon ferries is only feasible with real-time control of variable generation resources and effectively increasing uptake of renewable energy by the ferries to coincide with the times of highest curtailment.

Technology selection will thus be dependent on three main factors:

 refuelling/charging time (based on vessel schedules);  effect of increased electric demand on the grid; and  Availability and cost of new infrastructure to support new technologies (distribution equipment, cables and connectors).

Potential solutions will select the ports that are suited to the varying electrical supply from the renewable energy matrix of wind, wave and tidal energy to produce stored energy that can be harnessed by the vessels for transit. In the case of electrical charging, onsite battery powered storage can be used to balance out the variable supply within the individual island system.

In conjunction with this, a multi criteria analysis comprising timetables, charging times and refuelling times whilst determining the exact load on the grid will assist in choosing the most appropriate ratios of technology implementations across the isles. It should also be noted that the addition of more demand creates a risk that at instances of low renewable energy supply the grid needs to supply the required energy.

Electric Ferries

Assessment of Grid Balancing Benefit

Night time charging of electric and hybrid electric ferries matches the timetable schedules of the current routes offered by the ferries. Various modifications should allow vessels to carry out overnight charging depending on the docking station. Electrical consumption paired with the variable generation profiles of Orkney‟s renewable energy resources can also be matched by using on shore battery storage.

In order for charging between the isles, a successful implementation may require high speed charging infrastructure that supply power at a higher current. This may place a greater strain on the grid if implemented in locations where there are no pinch points.

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The grid will be influenced by the following charging options:

 Charging at port of departure and turnaround port – such an option will allow charging points on specified islands to be utilised on a continuous basis. This scenario is not likely to be suitable for the longer sailings across the outer Orkney isles;

 Charging at port of departure and port of arrival, return on same day – such an option will require a suitable timetable to allow for sufficient charging or rapid chargers. This will place a significant demand on the grid at any given time. This may be suitable for easing daytime curtailment when the local domestic demand is low; and  Charging at port of departure and charging at port of arrival, ready to sail the next day – such a scenario is likely to be the most practical. This allows for utilisation of night time generation.

Geographical Suitability of Technology

The suitability of electric ferries in Orkney matches the geographical outlook of the isles. During the night, ferries can be plugged into the grid for a slow overnight charge, whereas during the day fast charging may be used to allow for shorter interchange periods. Given the considerable amount of power required during fast charging, implementation of electric ferries will likely be implemented with storage banks which will further allow for a smoothing of the generation and demand curves in the curtailed zones on a day to day basis.

Zone of Influence

An intervention of electric ferries could match with both Orkney wide power generation as well as with generation in the outer zones. The implementation of charging points at various ferry terminals across the isles would be critical for the round trips involved in the transportation of passengers and cargo. These would subsequently assist in moving electrical demand closer to outlying production in DNO zones 1, 2, 3 and 4 (see Figure 6.1).

The zonal influence of electric ferries is presented in Table 6.7. This was estimated based upon current diesel consumption among the fleet. The assumptions used included that diesel engines have an efficiency of 50%, whereas electric engines have efficiency of 77%. From these it was possible to estimate the level of curtailment that could potentially be absorbed by electric ferries.

Table 6.7 gives an estimate of the average potential power requirements of a full electric vessel scenario which is based on annual marine gas oil consumption averages. The following assumptions were made in the calculation of the estimated average uptake of power: Diesel Engine Efficiency (ηD) at 0.5; Electric Motor Efficiency (ηE) at 0.77; and 1 litre of diesel fuel is equivalent to 40MJ = 11.1kWh.

Table 6.7 Potential curtailed energy absorption through ferries

Vessel Service Route DNO Annual Fuel Electrical Power Zone Consumption (2015) Equivalent Required (kWh) MV Earl Sigurd North Isles 1,2 664,640 4,617,953 MV Earl Thorfinn North Isles 1,2 715,360 4,970,358 MV Eynhallow Rousay, Egilsay, Wyre 1 156,400 1,086,675 MV Golden Mariana Westray, Papa Westray 1 22,470 156,123 MV Graemsay Graemsay, North Hoy Core 77,410 537,849 MV Hoy Head South Isles 3 345,454 2,400,232 MV Shapinsay Shapinsay 2 151,506 1,052,668 MV Thorsvoe Shapinsay, South Isles 2 120,022 833,919 MV Varagen North Isles 1,2 657,985 4,571,714

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However, it should be noted that a load at a particular location will not automatically result in absorbing the curtailment at that location, and allowing further generation of the local turbines. The turbines currently connected to Orkney‟s ANM system are in a priority system; operating on a first connected, last to be turned off list. Thus, additional infrastructure would be required in order to directly benefit the turbines in the location of charging. Otherwise the absorption of curtailment will effectively be for Orkney as a whole.

Hydrogen Ferries

Assessment of Grid Balancing Benefit

Hydrogen production has significant potential for moving electrical demand closer to outlying production in DNO zones 1, 2, 3 and 4 (see Figure 6.1). Hydrogen electrolysers and fuel cells can be scaled to meet the marine vessel demand in Orkney to provide sufficient power for the ferries scheduled route. Moreover, a mix of production can be achieved by considering biomass digestion (on Orkney‟s mainland).

Hydrogen presents an ideal match for curtailed energy in that it can be tied in with the ANM in order to match the production times of the hydrogen. Ideally the production could be linked to when the energy is being curtailed in the sites across Orkney‟s mainland. With the possibility of hydrogen refuelling stations located on both the outer isles and the Mainland this technology becomes applicable for both centralised as well as decentralised applications of low carbon transport on the Orkney grid.

Zone of Influence

The energy requirement will vary between the island routes. Table 6.8 illustrates what the equivalent energy uptake effect a scenario of hydrogen direct burn and fuel cell application would have on the grid. The estimates are based on assumptions made from reverse process engineering of energy consumption of the current vessels in 2015. Other assumptions are that hydrogen fuel cell engines have an efficiency of 52% whereas direct-burn engines have an efficiency of 42%.

Table 6.8 Full Hydrogen Scenario and Grid Implications

Vessel DNO Zone Energy Used Hydrogen Production Hydrogen Production (kWh) Energy Required - Fuel Energy Required - Cell (kWh) Direct Burn (kWh) MV Earl Sigurd 1,2 1,972,459 3,287,432 4,931,148

MV Earl Thorfinn 1,2 2,078,709 3,464,515 5,196,773

MV Eynhallow 1 469,581 782,635 1,173,953

MV Golden Mariana 1 49,467 82,445 123,668

MV Graemsay Core 226,902 378,170 567,255

MV Hoy Head 3 920,387 1,533,979 2,300,969

MV Shapinsay 2 446,040 743,400 1,115,100

MV Thorsvoe 2 345,454 575,757 863,635

MV Varagen 1,2 1,882,261 3,137,101 4,705,652

With regards to suitability for curtailment, the solution of renewable electricity for hydrogen production for powering ferries is highly favourable to the outer isles where the most power is curtailed.

Hydrogen powered ferries are suitable for relatively short ferry routes in Orkney whereas the flexible intermittent production of hydrogen matches the grid constraint issues. This is possible particularly by matching production of hydrogen from electrolysers to the instances of peak generation and storing this until a ferry docks onto the harbour. The operation of these electrolysers could be paired with the variable generation

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profiles of Orkney‟s renewable resources as this technology can easily be ramped up and down to match demand.

6.2.4 Scenario 3: Electric hybrids

Electric hybrids use two different fuels: electricity from a battery and a second fuel which may be gas oil, LNG or hydrogen. These hybrid systems have increased efficiencies compared to the non-hybrid ferries and thus lower the fuel consumption by around 30%.

The battery can be charged by the engine operating as a motor or via a cable/charging facility at the harbours.

As explained above, if the second fuel considered is LNG or gas oil, it would need to be imported while if the second fuel was to be hydrogen, it could be produced in Orkney through electrolysis using curtailed electricity from wind generation. If less fuel is required the size of infrastructure required will also be 30% smaller than for non-hybrid systems.

6.3 OTHER SHORE SIDE FACTORS INFLUENCING TYPE OF ENERGY SUITABLE FOR SUPPLY TO VESSEL

For each harbour, the development of selected alternative energy infrastructure would involve port modifications to accommodate charging of vessels as well as to house the transformers and substations in the case of electric ferries. Hydrogen vessels would require hydrogen production and loading on sites close to the ferries to minimise losses in transportation and storage costs. In addition to that the potential resources required for the ferries would include the installation of electrolysers and battery charging stations which involve building costs. The use of other fuels, such as LNG, would include sourcing delivery from outside Orkney, storage facilities on an adequate scale and shore side refuelling facilities.

6.3.1 Interface with Existing Infrastructure

There will be a potential for disruption of existing services during retrofits for cold ironing, installation of electrolysers and works involving plugin supplies. The scope of works for the construction of the renewable energy facilities would involve quay construction works, general civil engineering works and equipment sourcing and supply. The nature of construction involves large risks with regards to the proximity to water as well as interaction with existing facilities. It would be necessary to undertake a risk assessment with regards to operational hazards with the potential siting of hydrogen fuel as well as the increase in high voltage in operational areas of the port with regards to electrical power for charging as well as for cold iron operations.

The system of interconnected technological systems generally comprises:

 Electrical infrastructure at ports (substation, transformers, cables and connectors);  Electrical infrastructure on ships (retrofits or new builds); and  Connection and control solutions to ensure personnel safety and seamless power transfer.

6.3.2 Interaction with Port Authority

Any developments on the shore side would involve compliance with the relevant port regulations and requirements. An outline of the infrastructure schedule would be designed to fit the ferry retrofits and replacements in order to ensure seamless integration of the services. Consultation with the public authority in conjunction with other relevant parties be used to ensure the safety regulations are met.

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6.3.3 Shore Side Equipment

Equipment common among the low carbon ferries scenarios for charging/refuelling systems are listed below:

 Multi Drive Section;  DC –AC Inverter;  Three phase line filter;  Transformer;  Switchboard;  Control Panel; o Incoming Isolator;

o 415/110v ac transformer;

o Distribution circuit breaker; o Processor;

o G2 Compliant Power Supply Device;

o 8 Channel Analogue Input Modules; o Digital Input Modules;

o Digital Output Modules;

o TU810 Termination Units; o TU818 Termination Units;

o Module Bus Cluster Modems;  HMI Panel; o PC;

o HMI;

o Backup System; and  Transformer 33kV to 11kV or less.

6.3.4 Potential Site Locations

The implementation of low carbon ferries will require a number of onshore facilities which may range in size from standardized 20ft to 40ft containers such as in the case of hydrogen and electric battery banks. Each implementation will be sized for its own additional infrastructure requirements. There may be unused buildings close to the respective harbours which may be suitable for housing the potential low carbon fuel facilities.

6.3.5 Transport and Storage of Low Carbon Fuels Issues

Transport Issues

The accessibility of the ports would enable the potential equipment for the technology which weighs from 50kg to 1,000kg to be easily transported from the mainland. It is expected that challenges would be encountered in delivery during the winter months. For each harbour, the development of selected alternative energy infrastructure would involve port modifications to accommodate charging of the vessels or alternative fuel infrastructure as well as storage options. In addition to that the potential resources for the ferries would include the installation of electrolysers and battery charging stations which involve building costs. Included in

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the infrastructure assessment there could be options for cold ironing (section 6.3.6) and retrofitting and this may have some potential to disrupt existing services. The development of Orkney as a base for other sea users to access the alternative fuel source could also add potential customers and options for some fuels which is also being investigated by Orkney Islands Council.

The suitability of high speed electrical charging for each port will be dependent on the crossing times and turnaround times of the operating vessels as will other refuelling options.

Hydrogen production on islands may also require some inter island transport of the hydrogen. This will require specialist tankers and some new arrangements for the ferries. This is already being trialled as part of Community Energy Scotland‟s surf and turf project.

The exploration of renewable energy alternatives will involve the examination of infrastructure requirements which will be unique to each existing ferry port. These are broadly classed as grid, transport and construction developments. The nature of resources available in Orkney is widely variable in terms of seasonal variation, daily variation and hourly production variation and availability.

6.3.6 Overnight Cold Ironing

Cold ironing also known as Onshore Power Supply involves the switching off of the main engines of berthed vessels and running services such as refrigeration, cooling, heating, emergency lighting, cargo loading amongst others from a mains supply from the shore. The practice is currently growing in the shipping industry in Europe with more stringent measures to curb vessel emissions at docks.

Implementation

The implementation of cold ironing would involve a redesign of existing port infrastructure for each of the terminals. Design should comply with new international standards including: High Voltage Shore Connection (HVSC) by IEC, ISO and IEEE, IEC 60092-510 edition1 IEC/ ISO PAS. This will involve harmonising electric parameters in terms of creating uniform voltages and frequencies as well as the standards of cables and connectors.

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7 VESSEL DESIGN CHARACTERISTICS

7.1 INTRODUCTION

This section of the report analyses the results from the fuel modelling analysis and applies them to the different routes and islands to understand the local issues and constraints. It covers the main fuel types that have been assessed previously to be the most promising using the criteria contained in Section 6.

The section concentrates on data analysis while most of the background information is presented in the first half of this report. The figures presented are estimates in a number of cases and essentially point to the areas that would require detailed investigation prior to a fuel source or system being adopted.

The model that has been developed has used certain assumptions that can be refined as more information becomes available and then re-run to provide a more accurate assessment.

The three source fuels assessed are Natural gas, Hydrogen and Electric. This is followed by examining combinations of the three as hybrid systems. Each section looks at the impact locally on the infrastructure and vessels. The report then considers the overall impact of these low carbon fuels in an Orkney-wide context.

7.2 NATURAL GAS

7.2.1 Production/Fuel demand

Production of CNG or LNG within Orkney is not a viable solution as the process requires a gasification/liquefaction plant and although there is an oil terminal in Flotta the construction and operating costs involved for the fuel required would be unjustifiable. As such, the use of natural gas, both LNG and CNG, would solely rely on importing the fuel supply.

Transport of CNG is efficient over short distances (pipeline, road); for long distance transport, it is more efficient to liquefy it and re-gasify the natural gas at arrival terminal. Building a gasification plant in Orkney is not likely to generate any interest. Moreover, as shipping of CNG is still very new (Figure 7.3) and installing a pipeline through Pentland Firth would not be economically viable, it would be more appropriate to consider the road transport option.

There are two transport options for LNG, road transport from the production facility or LNG shipping (Figure 7.1, Figure 7.2). From Table 7.1 it can be seen that sea transport offers the best cost per unit of LNG. The issue with this option is the low quantity of LNG used (Table 7.2) and also the fact that it has a relatively short storage life before it needs venting (losses are approximately 0.08% per day). Having a limited quantity of LNG stored within Orkney would therefore need to be considered. There could be an opportunity to reduce costs by making Orkney an LNG hub which would require substantial infrastructure but the quantities could give transport efficiencies. Therefore, despite the higher cost per m3, road transport is likely to be the most suitable option at this time.

Table 7.1 Comparative transport costs of LNG

Transport type Capacity (m3) Cost from Grangemouth Cost per m3 Cost per Litre

Road 56 £2,000 £35.60 0.057

Sea (large scale) 138,000 £126,000 £0.91 0.001

Sea (smaller scale) 10,000 £30,000 £3.00 0.005

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Table 7.2 shows estimates of the annual and weekly average consumption of LNG and CNG for each route, based on the route analysis and current annual fuel usage.

Table 7.2 Average current annual fuel usage per route and potential LNG and CNG equivalent yearly and weekly demand (does not take MV Thorsvoe into account)

Overnight Route Fuel usage Annual LNG Annual Weekly Weekly port in 2015 equivalent CNG LNG CNG (litres of (litres) equivalent equivalent equivalent gas oil) (litres) (litres) (litres)

Kirkwall Eday 1,229,387 2,175,008 6,264,022 30,671 88,333

N. Ronaldsay 103,147 182,486 525,559 9,971 28,715

Westray 705,450 1,248,069 3,594,438 61,149 176,109

Rousay Rousay 156,400 276,700 796,895 7,770 22,377

Kirkwall Shapinsay 151,506 268,040 771,957 10,916 31,439

Houton Houton 345,454 611,170 1,760,170 21,067 60,672

Stromness Graemsay 77,410 136,952 394,422 2,751 7,922

Pierowall Papa Westray 22,470 39,753 114,490 2,172 6,255

Total 2,791,225 4,938,178 14,221,953 146,466 421,822

The import frequency for CNG could be once a year, but as the most suitable option is to consider road transport, it would equate to the same price per week. Therefore, for comparison purposes with LNG, weekly import has been selected, which would also allow a limited onshore storage size. Weekly road imported costs (including a one-week emergency storage) would be in the region of £8,349 (8 trucks) for LNG and £24,043 (22 trucks) for CNG.

The following figures illustrate examples of natural gas transport methods. Figure 7.1 gives an example of a currently operating LNG carrier. Figure 7.2 illustrates the types of containerised LNG tanks that could potentially be carried on- board a cargo vessel. Lastly, Figure 7.3 provides a concept diagram of a CNG carrier.

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Figure 7.1 LNG carrier ship 148

Figure 7.2 LNG tank containers, an alternative to LNG carrier ships 149, 150

Figure 7.3 Ship CNG carrier concept.151

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7.2.2 Storage

Different storage options exist for LNG and CNG, depending on the scale and location. The installations can be underground, above ground or floating. Considering floating storage tanks the land area requirement would be minimal. However, taking the rough Orkney weather and sea into account, this is not the safest option. Another floating option which is actively considered is to store the fuel in vessels; this would be possible in Scapa Flow which has already been used for LNG transhipment operations. Underground storage is usually set up in suitable geological formations (salt caverns for example) and for large scale facilities, none of these conditions exist in Orkney. Thus only above ground storage is taken forward in this study, most likely horizontal LNG cryogenic tanks (Figure 7.4) or pressurised CNG trailer tubes or spherical tanks (Figure 7.5 and Figure 7.6) as wind may be a hazard for vertical tanks.

Typical onshore LNG storage for Orkney would be horizontal cylindrical cryogenic tanks with a capacity of 200m3. This is due to the high windage of vertical tanks and visual impact in a relatively flat landscape. Some companies can manufacture tanks on demand according to personalised dimensions which could also be an option.

CNG storage may consist of horizontal pressurised tubes of 2.4 m3 each (packs of 10 tubes, 24m3)152.

Figure 7.4 Example of above ground horizontal LNG storage tanks.153

Figure 7.5 Horizontal above ground CNG storage in pressurised trailer tubes154

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Figure 7.6 Pressurised spherical tanks for onshore CNG storage155

Table 7.3 shows the potential LNG storage requirements for each route and the costs associated, based on a weekly import basis and considering a cryogenic tank storage infrastructure of 350kg/m3. Table 7.4 shows the potential CNG storage requirements for each route and the costs associated, based on a weekly import basis and considering a pressurised tank storage infrastructure of 128kg/m3.

Some additional emergency storage should be considered to prevent any shortages in the event of either import delay or onsite incident. The emergency storage in Table 7.3 and Table 7.4 is based on the average weekly fuel consumption of each vessel. The capital costs, or CAPEX, have been estimated for the overall infrastructure required (storage, control system, pipeline circuit) while the operational costs, OPEX, are assessed to be 5% of the CAPEX and take account of the costs related to fuel (cost of fuel and import).

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Table 7.3 Onshore LNG storage sizing and cost per route. (see also Table 7.7)

)

£/

) 3

Harbour (Route) OPEX

)

5,303 )

Required Required (L) Capacity size Storage (m week One emergency (L storage Additional (m size of cost Total £ storage (@ m Estimated CAPEX total (£) Estimated total (£)

Stromness (Graemsay) 2,751 4 2,751 4 45,375 49,912 67,681

Pierowall (Papa Westray) 2,172 3 2,172 3 35,831 39,414 28,824

Kirkwall (Shapinsay) 10,916 17 10,916 17 180,078 198,086 169,431

Rousay (Tingwall) 7,770 12 7,770 12 128,172 140,989 151,525

Houton Lyness) 21,067 33 21,067 33 347,522 382,275 360,777

Kirkwall (Eday) 30,671 48 30,671 48 505,966 556,563 987,932

Kirkwall (Westray) 61,149 95 61,149 95 1,008,740 1,109,614 857,870

Kirkwall (North Ronaldsay) 9,971 16 9,971 16 164,478 180,926 132,313

Total 2,416,162 2,657,778 2,756,351

Table 7.4 Onshore CNG storage sizing and cost per route.

£/

) 3

Harbour (Route)

)

al cost of of alcost

6,816 )

Required Required (L) Capacity size Storage (m week One emergency (L) storage Additional (m size Tot £ storage (@ m Estimated CAPEX total (£) Estimated OPEX total (£)

Stromness (Graemsay) 7,922 12 7,922 12 158,582 174,440 174,179

Pierowall (Papa Westray) 6,255 9 6,255 9 125,226 137,749 76,482

Kirkwall (Shapinsay) 31,439 46 31,439 46 629,364 692,300 445,315

Rousay (Tingwall) 22,377 33 22,377 33 447,953 492,748 393,665

Houton Lyness) 60,672 89 60,672 89 1,214,573 1,336,030 943,216

Kirkwall (Eday) 88,333 130 88,333 130 1,768,325 1,945,158 2,520,668

Kirkwall (Westray) 176,109 259 176,109 259 3,525,495 3,878,045 2,268,267

Kirkwall (North Ronaldsay) 28,715 42 28,715 42 574,843 632,327 351,085

Total 8,444,362 9,288,798 4,408,806

4 The total CAPEX include storage, control system and pipeline circuit which have been calculated as an additional 10% to the storage costs.

5 The total CAPEX include storage, control system and pipeline circuit which have been calculated as an additional 10% to the storage costs.

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7.2.3 Refuelling

Transport of fuel to the vessels can be performed by pipeline (if the storage area is close enough to the ferry terminal) or adapted trucks. The frequency of refuelling operation for each vessel may vary depending on the storage capacity on-board each vessel and the consumption. The most likely scenario would be to refuel each vessel between daily and four times a week, like the current situation.

7.2.4 Impact on Vessels

Switching vessels to LNG or CNG requires modifications to the whole system: adapted storage (dimensions depending on the vessels energy requirements) with design consistent with safety norms (the system needs a valve system allowing gas exit in the case of a hazard occurring), engine/propulsion system suited to the power requirements. There is also an implication of an upgrade in safety training for crews and members of the supply chain.

As far as weight is concerned, the bigger the tank capacity, the lower the ratio of weight/size.

Considering a daily refuelling frequency and the same storage technology as the one onshore (but sized to the vessel requirements), estimates of size, weight and costs associated with storage of LNG on vessels have been made for each route (Table 7.5). The capital costs, or CAPEX, have been estimated for the overall infrastructure required (storage, engine, propulsion, fuel pipe circuit) while the operational costs, OPEX, are assessed to be 5% of the CAPEX and do not take account of the costs related to fuel consumption as these were already considered in Table 7.3.

The same calculations have been made for CNG and are presented in Table 7.6.

Table 7.5 Size, weight and costs for on-board LNG storage and infrastructure for each route.

)

Harbour (Route) 3

£/m

5,303

Required Capacity (L) Capacity Required (m size Storage (L) storage Backup backup for Size (m storage (kg) Weight £ storage of cost Total (@ CAPEX total Estimated (£) OPEX total Estimated (£)

Stromness (Graemsay) 1,375 2 116 0.2 1,308 12,235 177,277 8,864

Pierowall (Papa Westray) 434 1 109 0.2 394 4,454 35,232 1,762

Kirkwall (Shapinsay) 2,662 4 133 0.2 2,363 22,930 232,607 11,630

Rousay (Tingwall) 1,110 2 66 0.1 1,086 9,641 149,038 7,452

Houton (Lyness) 4,213 7 237 0.4 3,309 36,502 339,467 16,973

Kirkwall (Eday) 6,816 11 188 2.4 6,337 68,740 555,072 27,754

Kirkwall (Westray) 11,465 18 1,396 2.2 8,743 105,497 593,667 29,683

Kirkwall (North Ronaldsay) 4,985 8 2,493 4 4,998 61,336 547,298 27,365

Total 321,336 2,629,657 131,483

6 Total CAPEX only considers the fuel and propulsion infrastructures.

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Table 7.6 Size, weight and costs for on-board CNG storage and infrastructure for each route.

)

Harbour (Route) 3

£/m

)

6,816

Required Capacity (L) Capacity Required (m size Storage (L) storage Backup storage backup for Size (m (kg) Weight £ storage of cost Total (@ CAPEX total Estimated (£) (£) OPEX total Estimated

Stromness (Graemsay) 2,376 6 335 0.5 2,608 43,000 209,580 10,479

Pierowall (Papa Westray) 751 2 313 0.5 894 15,653 46,991 2,350

Kirkwall (Shapinsay) 4,601 11 383 0.6 5,113 80,589 293,149 14,657

Rousay (Tingwall) 1,918 5 189 0.3 2,436 33,885 174,494 8,725

Houton (Lyness) 7,281 18 682 1.0 4,209 128,288 435,842 21,792

Kirkwall (Eday) 11,778 29 540 0.8 5,591 201,889 694,878 34,744

Kirkwall (Westray) 19,812 48 4,022 6 24,963 370,772 872,205 43,610

Kirkwall (North Ronaldsay) 8,615 21 7,179 11 11,248 215,566 709,239 35,462

Total 1,089,642 3,436,379 171,819

It should be noted that the figures in the above tables consider a backup system for safety reasons. This backup has been sized based on the amount of fuel required in order to run the vessel over the longest section of a route, in other words the longest potential distance to reach a harbour on the route.

The overall CAPEX to replace the Orkney vessels fuelling system (storage infrastructure and propulsion system) with a new LNG system is expected to be just over £2.6 million, and close to £3.4 million for a replacement with a CNG system.

7.2.5 Impact on Shore

Onshore LNG or CNG storage infrastructure may be located in different places but due to the importation requiring one central point this is most likely to be Hatston. Some smaller onshore storage might be required which could be supplied by tankers form the central storage facility. This would be the situation in Westray as the MV Golden Mariana is small and does not sail to the Mainland. The Hatston central storage option would easily allow transporting fuel via trucks to the other harbours on Orkney West Mainland (Stromness, Tingwall, Houton).

Table 7.7 and

Table 7.8, below, outline the size of the tanks that would be required for LNG and CNG respectively, as well as the area of land that would be needed for these facilities.

7 Total CAPEX only considers the fuel and propulsion infrastructures.

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Table 7.7 Total area requirement for onshore LNG storage installation, considering all vessels run on LNG. (Tank area: 15m x 5m; Safety zone buffer: 30m)

Area required Number of Area required Volume of storage (m3) (no buffer) 3 200m tanks (30m buffer included) m2 m2

Total (all routes) 456 3 225 5,625

*This figure represents the maximum area requirement, in the case the facility is completely surrounded by land. However, it could be considered to build it close to the shore which would reduce the safety area on the shore side.

Table 7.8 Total area requirement for onshore CNG storage installation, considering all vessels run on CNG (Tank area: 15m x 5m; Safety zone buffer: 30m)

Number of 24m3 tube Area required Area required Volume of storage (m3) 2 packs (10 (no buffer) m (30m buffer included) m2 tubes) Total (all routes) 52 1,239 3,900 24,000

Other onshore installations would comprise of a pipeline network to transport natural gas locally (from the storage facility to the vessels) and a road tanker refuelling station. An appropriate electrical control system should also be built for the facility. The CAPEX for the overall onshore facility is estimated to be approximately £2,657,778 for LNG (Table 7.3) and over £9,288,798 for CNG (Table 7.4). The staff using LNG/CNG onshore infrastructure would need to be re- trained appropriately.

7.2.6 Conclusion

It has previously been said in this study that natural gas would be a suitable fuel for ferries in Orkney, as far as efficiency is concerned. From this section, both LNG and CNG seem to be a feasible option to power the Orkney Ferries vessels in terms of infrastructure requirement. The overall CAPEX for the full replacement of the Orkney Ferries fuel system to LNG or CNG and the building of associated onshore infrastructures is estimated to be approximately £5.2 million and £12.7 million respectively; the LNG option is very similar to the CAPEX to renew the fleet and continue using the current gas oil system (Table 7.9). Considering that gas oil infrastructures already exist in Orkney, this solution is the cheapest; but it should be pointed out that if these infrastructures were to be added to the Capex, then LNG would actually be the cheapest option.

As far as OPEX is concerned, although the crew and maintenance costs may be 15 to 20% higher than for the current vessels, the fuel cost, which is the main operational cost, is over 30% less than marine gas oil (Table 7.9). It would also allow significant emissions reduction compared to the current situation (around 70% less CO2 emissions for LNG and 30% less for CNG).

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Orkney has the potential to become an international LNG or CNG hub. With LNG technology being more frequently used in the maritime sector, having an LNG supply in Orkney could potentially increase tourism related to LNG cruise ships. This would however require either larger storage infrastructure or more frequent import (three times a year instead of two) in order to allow extra supply. CNG is still at quite an immature stage for maritime applications but may have the same economic effect as LNG in the future.

Powering ferries with natural gas in Orkney also has a disadvantage; it has minimal impact on renewable energy production/demand as the fuel needs to be entirely imported. Hence the opportunities for the local community will be limited.

Table 7.9 Total capital and operational expenditures (include both onshore and vessel infrastructures) for LNG and CNG technologies (comparison with gas oil).

Technology Total CAPEX £ Total OPEX £

Gas oil with existing infrastructure 2,353,177 1,562,894

Gas oil without existing infrastructure 6,629,172 1,562,894

LNG 5,287,436 2,887,834

CNG 12,725,176 7,784,252

*These figures only consider infrastructures associated with fuel system (storage, engine/propulsion, additional equipment for onshore and vessel systems)

It should be noted that this section considered CNG and LNG separately, including for import. However, LNG being a better import solution and CNG easier to store, the better option would be to consider adding a compressor infrastructure in Orkney to transform imported LNG into CNG and use natural gas as CNG to power the vessels.

7.3 FULL ELECTRIC

7.3.1 Production

Ideally the power supply for any electric ferry operating in Orkney would be sourced from local renewable energy; the most likely being from the wind turbines dispersed among the islands. In the ideal scenario, every additional kilowatt- hour of electrical demand added as a result of charging electrical ferries would be matched from pre-existing wind turbines.

As has been discussed previously within this body of work, and common knowledge among the Orkney Islands, there is a level of curtailment on the current portfolio of wind turbines due to grid limitations. The relatively significant loads ferries of this type could hold the potential to reduce portions of this curtailment, and in turn revenue among the turbine operators.

Table 7.10 below details the calculations completed to understand the daily quantity of power required to fuel full electric vessels equivalent to the current diesel fleet. The fuel consumption is based upon understanding times of operation and average fuel consumption. It should be noted that the energy requirement is based upon the sailing time alone, as it is assumed that a vessel of this type would expend very little energy while berthed at each stop in order to conserve energy; as seen in the MV Ampere case study, which uses vacuum berthing mounts. Additionally, a conversion rate of 10.7kWh/Litre was used to calculate the electrical energy equivalent; assuming diesel combustion

140 OIC LOW CARBON FERRIES – FEASIBILITY STUDY

energy efficiency of 30% and electrical system efficiency of 77%, the summed total if all of the vessels were converted to full electric propulsion would result in 77,906 kWh daily electrical demand.

A significant proportion of large-scale wind turbines in Orkney are in the range of 900 kW. Thus, for every 900 kWh of energy required to power a ferry, a turbine of this rated capacity could potentially remain generating for an additional hour. The turbines however rarely run at full capacity due to weather conditions, therefore 40% capacity factor was also assumed in order to conduct these calculations. Table 7.10 also aims to demonstrate the approximate hours and number of turbines required to generate enough power using 900 kW wind turbines. This ranges from 4.7 hours of power generation for the sailing from Westray to Papa Westray and 125.1 hours for the Kirkwall to North Ronaldsay. These calculations taken further identify the approximate number of 900 kW turbines that would be required; these have been rounded up to the nearest turbine. These range between one and six turbines for these routes, as identified below.

Table 7.10 Required Energy Consumption and Wind Generation

Overnight Route Average daily Full Electric Required Wind Wind Turbines Port fuel usage (kWh) Turbine Required (litres of gas Generation oil) (hours)

Kirkwall Eday 3,853 26,768 74.3 4

Kirkwall North Ronaldsay 2,818 19,579 54.4 3

Kirkwall Westray 6,481 45,028 125.1 6

Rousay Rousay 1,380 4,359 12.1 1

Kirkwall Shapinsay 1,505 10,456 29 2

Houton Houton 2,382 16,547 45.9 2

Stromness Graemsay 777 5,401 15 1

Pierowall Papa Westray 246 1,706 4.7 1

Total 19,441 129,843 360.7 20

Turbine owners can receive additional income by reducing the time they are curtailed if the local demand is increased. There is the potential for them to offer electricity to a local system at a reduced rate as they can still claim subsidy (ROCs or FITs). This is not necessarily straight forward as they need to have a separate switching system.

7.3.2 Storage

In the immediate future, charging would almost certainly be in the form of Lithium-ion batteries. Banks of batteries can be scaled up in order to meet demand. For safety reasons it has been assumed that at the very minimum a vessel should be able to complete a full return trip of its longest route on a single charge. Additionally, the vessel should have on-board an identical propulsion system capable of operating in isolation from the other; recommendations laid out previously. Thus, the vessel should be capable of completing its route at least four times under normal operating conditions; these precautions act as mitigating measures against the possibility of charging facilities at one location being unavailable for any reason, or a fault occurring within one of the propulsions systems. Another option would be to reduce the level of contingency on-board storage for more robust on-shore charging facilities. However, it is concerned a more probable scenario for a vessel of this type to be approved with the suggested level of contingency storage.

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Through correspondence with John Perry, Technical Director of Denchi Power Ltd, battery manufacturer and supplier based in Thurso, it was clarified that through the continuing development of the battery sectors that unit prices could drop to £500/kWh by mid-2017. Some analysts predict the potential for the cost of lithium ion batteries to drop a further 50% in the following five years156.

It is highly probable that due to the power required to charge full electric vessels over a relatively short time period that buffer batteries would be required for daytime charging. This would minimise the strain on the grid and allow for very rapid charging. The energy capacities of the on-board and on-shore batteries are addressed in greater detail in section 7.3.4 and section 7.3.5 respectively.

An additional consideration is the life span of potential batteries. Replacement of cells would be necessary through the lifetime of a vessel. This would especially be the case with constant rapid charging of the on-board batteries, which has the potential to reduce longevity of the batteries life-span. It is unlikely that the life-span of current battery technologies would match that of the required life expectancy of new ferries. This would have to be incorporated when analysing operation and maintenance practices.

7.3.3 Refuelling

Due to the capacity of currently available batteries, it would be expected that charging facilities would be required at every stop. This is the ideal scenario for minimising the on-board energy storage capacity required as well as mitigating the risk of a particular charging facility being offline; timetabling and vessel design could ensure the vessel would have enough stored energy to reach the next charging facility in the event of malfunction.

Figure 7.7, below, shows the onshore infrastructure used at both ends of the route services by the MF Ampere in Norway. Box A, on the bottom left, highlights the use of vacuum berthing mounts that remove the requirement of the vessel to expel energy through the use of positioning thrusters while berthed. Box B, on the right, highlights the charging tower which incorporates the buffer battery and pulley mounted charging plug. This shore side infrastructure only requires a single person to operate them and maximises charging time due to their time efficiency.

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Figure 7.7 Shore side recharging infrastructure. (A) Vacuum berthing mounts (B) Charging tower with buffer battery and plug on a pulley system

A B

Similar concepts would be expected if full electric vessels were to be incorporated in Orkney‟s inter-island fleet. Charging times would be short, generally between five, ten or 15 minutes, under the current timetables, and some journeys are prohibitively long for this technology. The required charging times has been discussed in the following section 7.3.5 (Impact on-shore); this addresses the impact of charging requirements and times required. Unfortunately due to the unique nature of this currently operating vessel, it is not possible to obtain unit costs of these shore side technologies.

7.3.4 Impact on Vessels

The following calculations on the impact of vessel designs, initially, assume that any new vessels would aim to match the schedules employed by the current diesel fleet. Feasibility of new fuels meeting the demands of these routes can then be determined as well as impact mitigation as a result of short-comings in the new fuel; i.e. route alterations, longer stops, etc.

In order to calculate the minimum energy requirement for the on-board battery, the current diesel requirements of the vessels was converted to the equivalent electrical energy. By understanding the energy that would be needed for each of the crossings among the inner and outer islands the energy required could be calculated.

This breakdown of the energy requirements per vessel, detailed previously in Table 7.10, highlights the necessary energy requirements of a full electric ferry under current timetables. Table 7.11 details the recommended on-board battery capacity for equivalent full electric ferries to replace the different Orkney Ferries vessels currently in operation. This also includes the estimated weight, size and cost of the battery banks required in order to cover these distanced. The direction taken was to calculate the energy requirement of the longest distance a vessel would have to travel before recharging again; this would be the capacity for the primary battery bank. This would then be matched by the secondary battery bank.

In order to complete these calculations the following assumptions were made:

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 Battery weight: 0.11 kWh/kg;  Battery Size: 300 kWh/m3; and  Battery Cost: £500 /kWh.

Table 7.11 Required batteries capacity for longest trips and backup system

Harbour (Route) Required Full Trip Requirement Full On-Board Requirement Capacity (including backup) (kWh) Size Weight Cost (£) Size Weight Cost (£) (m3) (kg) (m3) (kg)

Stromness 742 2.5 6,745 370,980 4.9 13,490 741,960 (Graemsay) Pierowall (Papa 427 1.4 3,877 213,253 2.8 7,755 426,507 Westray) Kirkwall 523 1.7 4,753 261,408 3.5 9,506 522,815 (Shapinsay) Rousay (Tingwall) 257 0.9 2,339 128,623 1.7 4,677 257,246 Houton (Lyness) 931 3.1 8,459 465,268 6.2 16,919 930,536 Kirkwall (Eday) 6,145 20.5 55,865 3,072,564 41.0 111,730 6,145,129 Kirkwall 7,401 24.7 67,278 3,700,293 49.3 134,556 7,400,585 (Westray) Kirkwall (North 9,789 32.6 88,993 4,894,628 65.3 177,986 9,789,256 Ronaldsay) TOTAL 26,214 87 238,309 13,107,017 175 476,619 26,214,034

Taking the case study of the MF Ampere, the designs of this vessel saw it fit to have a vessel that could make approximately five complete crossings on a single charge. This allows for the possibility of continued operation in the face of system failure of one of the two propulsion systems, as well as the possibility of one of the charging facilities going off line.

The MF Ampere has to propulsion systems with batteries rated at 500 kWh, 1 MWh in total, which can be isolated from each other if required. This is illustrated below (Figure 7.8) in the line diagram of its propulsion system. This same design methodology has also been adopted in the calculations below.

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Figure 7.8 Line diagram of MF Ampere propulsion system157

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Table 7.12, below, demonstrates the result of amending the conditions of sizing the on-board battery. In this scenario both the primary and secondary batteries have the capacity to meet the energy requirements for one full return trip instead of just the longest distance within a return trip. It can be seen that there is a significant increase in size, weight and cost. The total cost of propulsion would increase approximately 209%. It is for this reason this work has taken forward the former scenario.

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Table 7.12 Required batteries capacity for full return trip and backup scenario

Harbour (Route) Required Full Trip Requirement Full On-Board Requirement Capacity (including backup)

(kWh) Size Weight Total cost of Size Weight Total cost of (m3) (kg) storage £ (m3) (kg) storage £ Stromness 900 2.5 8,184 370,980 4.9 16,367 741,960 (Graemsay) Pierowall (Papa 853 2.8 7,755 426,507 5.7 15,509 853,013 Westray) Kirkwall 1,046 3.5 9,506 522,815 7.0 19,011 1,045,631 (Shapinsay) Rousay 872 2.9 7,926 435,908 5.8 15,851 871,816 (Tingwall) Houton (Lyness) 3,309 11.0 30,085 1,654,681 22.1 60,170 3,309,362

Kirkwall (Eday) 13,384 44.6 121,671 6,691,913 89.2 243,342 13,383,826

Kirkwall 15,009 50.0 136,448 7,504,656 100.1 272,897 15,009,312 (Westray) Kirkwall (North 19,579 65.3 177,986 9,789,256 130.5 355,973 19,578,512 Ronaldsay) TOTAL 54,952 183 499,561 27,396,716 365 999,121 54,793,433

The limitations of full electric propulsion systems become evident. In order to mitigate the risk of faults and breakdowns occurring during operation, systems become very heavy, large and costly. It should be noted that the calculations above are also solely for the battery banks alone, and do not include energy management technologies; such as prognostic and conditioning monitoring equipment.

Another important factor into the costing of a fleet of full electric vessels is the propulsion. Through research a figure of £400/kW was obtained for approximating the cost of such electrical propulsion. Taking the power rating of the current vessels operating within the Orkney Ferries fleet it is possible to approximate the cost of these components in the equivalent full electric vessels.

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Table 7.13, below, details the breakdown of this cost per vessel; as well as the summed total. An additional 5% was added to estimate the cost of on-board infrastructure costs. Thus, in order to equip every vessel would cost approximately £3,076,080; ranging from £40,740 to £663,600.

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Table 7.13 Electric Motor Costs

Harbour (Route) Power (kW) Power (kW) Total System Cost CAPEX (£) (£)

Stromness (Graemsay) 2 Mirrlees, 743kW each 1,486 208,800 219,240

Pierowall (Papa Westray) 2 Mirrlees, 743kW each 1,486 38,800 40,740

Kirkwall (Shapinsay) 2 Caterpillars, 790kW each 1,580 264,800 278,040

Rousay (Tingwall) 2 Volvo Penta, 331kW each 662 176,400 185,220

Houton (Lyness) 2 Volvos, 220.5kW each 441 382,400 401,520

Kirkwall (Eday) 2 Volvos, 478kW each 956 594,400 624,120

Kirkwall (Westray) 1 Gardner, 97kW 97 632,000 663,600

Kirkwall (North Ronaldsay) 2 Volvo Penta, 261kW each 522 632,000 663,600

TOTAL 2,929,600 3,076,080

7.3.5 Impact on-shore

The direction taken in order to ascertain the estimated cost of on-shore storage was to make estimation the average current fuel consumption, in litres of fuel, among the different routes and convert this to the level of electrical energy, in kWh, that vessel would require access to along that route to recharge. Table 7.14 details the results of these calculations and illustrates the level of capacity that should be made available along a vessels route, and the approximate cost of this capacity.

Table 7.14 On-shore Battery Capacity Cost

Harbour (Route) Required Capacity (kWh) Total Storage Cost (£) CAPEX (£)

Stromness (Graemsay) 900 370,980 408,078

Pierowall (Papa Westray) 853 426,507 469,157

Kirkwall (Shapinsay) 1,046 522,815 575,097

Rousay (Tingwall) 872 435,908 479,499

Houton (Lyness) 3,309 1,654,681 1,820,149

Kirkwall (Eday) 13,384 6,691,913 7,361,104

Kirkwall (Westray) 15,09 7,504,656 8,255,121

Kirkwall (North Ronaldsay) 19,579 9,789,256 10,768,182

TOTAL 52,238 27,396,716 30,136,388

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These calculations are taken further in order to understand the level of impact upon the grid and the feasibility of charging the on-board batteries under the time constraints of the current time tables. In order to determine these the time tables have been examined to understand the longest journey a vessel has to complete in order to reach a particular destination; this is highlighted below in Table 7.15. It is assumed that this would be the level of energy required in order to rapidly charge the vessel back to full capacity. As the table indicates this is working on the ideal assumption of deploying an appropriately scaled bank of batteries along each stop of the route.

Table 7.15 On-shore Energy Storage Capacity

Destination (Origin) Distance (km) Energy (kWh) Kirkwall (N. Ronaldsay) 54.9 9,767 N. Ronaldsay (Kirkwall) 54.9 9,767 Kirkwall (Stronsay) 34.5 6,132 Kirkwall (Westray) 30.7 5,472 Westray (Kirkwall) 30.7 5,472 Sanday (Kirkwall) 29.8 5,308 Eday (Kirkwall) 26.1 4,639 Stronsay (Eday) 11.7 2,081 Flotta (Houton) 9.7 930 Houton (Flotta) 9.7 930 Lyness (Houton) 9.5 910 Shapinsay (Kirkwall) 7.0 525 Longhope (Lyness) 5.4 514 Moaness (Stromness) 8.5 461 Stromness (Moaness) 8.5 461 P. Westray (Westray) 4.9 427 Rousay (Tingwall) 6.6 250 Tingwall (Rousay) 6.6 250 Graemsay (Moaness) 4.1 223 Egilsay (Rousay) 4.3 165 Wyre (Egilsay) 4.3 162

It is commonly found within the timetable that vessels stop along the route for approximately 10-15 minutes before sailing to the next destination. Understanding the required energy needed during charging and the time available during stopovers, it is possible to calculate the required power capacity of the battery. Table 7.16, below, breaks down what power would be required during charging to replenish the batteries after having covered the longest distance under the current time tables. This is broken down into a number of time brackets to indicate how altering the time table could significantly reduce infrastructure requirements.

For example, when a hypothetical electric ferry arrives at Eday, under the current time table, 4,639 kWh would be needed during its shortest stopover (ten minutes). This translates to charging at approximately 27.8 MW for 10 minutes in order to recharge the energy spent arriving from Kirkwall. Clearly this is not feasible due to the expense of infrastructure and strain that would be imposed upon the local grids.

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Through calculation it has been estimated that the electrical connection used in the case study of the MF Ampere is 1,200 kW. This rate has been assumed to be a feasible power rating for charging. This in turns helps indicate which crossings remain applicable to charging an electric ferry under various charging times.

Table 7.16, below, indicates which crossings under different charging times remains under the proposed 1,200 kW power limit. The table shows that a vessel servicing the MV Hoy Head route between Houton and Lyness is feasible as long as charging times are greater than 45 minutes. Additionally, a vessel meeting the requirements of the MV Graemsay, would need in excess of 20 minutes charging; which is currently significantly longer than would be capable under the current time table. While these routes have potential, the routes to the north islands require too much power during too long a stopover to be viable under current timetables.

Table 7.16 indicates the following short and medium range crossings that are potentially viable for electric ferries under this condition:

 Shapinsay -> Kirkwall;  Lyness (Hoy) -> Houton;  Stromness -> Graemsay -> Moaness (Hoy); and  Tingwall -> Rousay -> Egilsay -> Wyre.

Table 7.16 Power Requirement per Destination over Time

Destination (Origin) Energy Power Requirement (kW) (kWh) 10 20 30 45 1 hour minutes minutes minutes minutes Kirkwall (N. Ronaldsay) 9,767 58,601 29,301 19,534 13,022 9,767 N. Ronaldsay (Kirkwall) 9,767 58,601 29,301 19,534 13,022 9,767 Kirkwall (Stronsay) 6,132 36,793 18,396 12,264 8,176 6,132 Kirkwall (Westray) 5,472 32,830 16,415 10,943 7,296 5,472 Westray (Kirkwall) 5,472 32,830 16,415 10,943 7,296 5,472 Sanday (Kirkwall) 5,308 31,848 15,924 10,616 7,077 5,308 Eday (Kirkwall) 4,639 27,832 13,916 9,277 6,185 4,639 Stronsay (Eday) 2,081 12,485 6,242 4,162 2,774 2,081 Flotta (Houton) 930 5,581 2,791 1,860 1,240 930 Houton (Flotta) 930 5,581 2,791 1,860 1,240 930 Lyness (Houton) 910 5,460 2,730 1,820 1,213 910 Shapinsay (Kirkwall) 525 3,150 1,575 1,050 700 525 Longhope (Lyness) 514 3,082 1,541 1,027 685 514 Moaness (Stromness) 461 2,767 1,383 922 615 461 Stromness (Moaness) 461 2,767 1,383 922 615 461 P. Westray (Westray) 427 2,563 1,282 854 570 427 Rousay (Tingwall) 250 1,503 751 501 334 250 Tingwall (Rousay) 250 1,503 751 501 334 250 Graemsay (Moaness) 223 1,338 669 446 297 223 Egilsay (Rousay) 165 987 494 329 219 165 Wyre (Egilsay) 162 971 486 324 216 162

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It should be noted that if charging was increased to 2,000 kW this would make these routes significantly more viable under current timetable requirements. The rate of charge will directly impact upon the time required to full charge a battery again. If it is only possible to charge at a lower power this will decrease the number of crossings viable under the current timetable; longer stop over times would be required to mitigate this scenario. Another option is to timetable the vessel, understanding that it will not fully charge after very short stopover periods. 7.3.6 Conclusion

The above analysis suggests that full electric vessels are not suitable for the longer ( level 3) routes that service the north isles. There is very real potential however for this technology to service the shorter (level 1) routes and reduced potential for the medium (level 2) routes, under certain charging conditions.

The CAPEX required to fit every vessel with a full electric propulsion system would be significant. The components discussed previously breakdown as follows within the different route levels:

Table 7.17 CAPEX (£)

CAPEX (£) Level 1 Level 2 Level 3 Total

On-board Storage 1,226,890 1,796,127 24,501,719 27,524,736

Electric Propulsion 259,980 864,780 1,951,320 3,076,080

On-shore Storage 964,260 2,874,745 26,384,408 29,259,153

Total 1,224,240 5,535,652 52,837,447 59,859,969

Taking the assumption that all routes were serviced by electric vessels then the grid would see an estimated 129,843 kWh of electrical demand could be imposed upon the local grid daily. Expected operational procedures would expect this load to be fluctuating though the day; large fluctuations through the busiest times of the day and uniform charging rates through the night. However, as previously discussed this could result in approximately 20 turbines required to meet this demand; a number that would suggest further turbines could be connected to the grid as a result of this.

It should also be noted that a recommendation has been made for further examination of grid infrastructure in the proximity of potential sites of charging facilities. Current infrastructure will dictate the level of expenditure required to deploy the full range of technologies needed. For example, laying of additional power cables close to berthing locations, higher rated cables to meet time constraints due to time tabling, the applicability to retrofit current piers with berth and charging units. Through correspondence with SSE it was made clear that this level of power demand for vessels with full electric propulsion would require significant changes and upgrades.

The calculated capacity of energy storage required to meet the demands of these routes is significant. This results in potential for additional revenue through providing services such as grid balancing facilities. Clearly this could only be possible when the vessels are berthed and charging overnight. But this potential could impact upon the significant expenditure associated with this technology.

7.4 HYDROGEN

Hydrogen holds the potential to be utilised as a fuel in a number of ways; however some are more developed and commercialised than others. The following details the cases for using hydrogen within a fuel cell and as a direct combustion fuel. For this investigation compressed hydrogen has been chosen in as the state of hydrogen to compare the effectiveness of these two propulsion technologies. In reality, liquid hydrogen could also be another fuel that is

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available for commercial purposes, but it was deemed that compressed hydrogen held the best potential for accurate comparative results and was more suitable for Orkney‟s situation. Liquid hydrogen has to be stored at -253C which requires additional energy through its liquefaction and transportation as a result of the complex tanks and infrastructure requirements.

7.4.1 Production

As discussed previously, hydrogen holds a very real and significant potential of being produced locally through electrolysis from renewable energy, including absorbing the present overproduction of power that is causing some wind turbines in the islands to be curtailed. There is also the potential for the import of hydrogen though road tankers and dedicated transport, but this would leave the fleet relatively sensitive to fluctuating market prices; as would be the same case for any imported fuel. Producing the fuel on the smaller islands is the preferred option as this gives the greatest benefits by using there already curtailed turbines as a source of energy. The question is which routes could feasibly be fuelled by hydrogen; and what scale of production would be required to meet this demand.

The site of production itself would depend on a number of factors such as the condition of the grid link, the water supply, proximity to island inhabitants and transport links. Siting on the Mainland would be most advantageous for the project‟s associated costs and logistics.

The table below ( Table 7.18) details the calculated daily fuel consumption for the current routes and how this would equate for vessels powered by fuel cells and direct combustion propulsion systems. From these calculations it can be assumed that 5,774 kg and 7,149 kg of hydrogen would be the minimum amount required daily for fuel cell and direct combustion propulsion system respectively under current timetabling.

Table 7.18 Daily Hydrogen Consumption

Overnight port Route Average Daily Fuel Hydrogen Hydrogen Consumption (litres) Equivalent (kg) - Equivalent (kg) - Fuel Cell Direct Combustion

Kirkwall Eday 3,853 1,190 1,474 Kirkwall North Ronaldsay 2,818 871 1,078 Kirkwall Westray 6,481 2,002 2,479 Rousay Rousay 1,380 194 240 Kirkwall Shapinsay 1,505 465 576 Houton Houton 2,382 736 911 Stromness Graemsay 777 240 297 Pierowall Papa Westray 246 76 94 Total 19,441 5,774 7,149

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Table 7.19 also highlights the total recommended on-board storage including a contingency quantity of hydrogen that equates to the volume, in kg, required to complete a single journey along a particular route. For example, the Stromness to Moaness route would require an additional 15 kg for fuel cell propulsion contingency on top of the 178 kg required for daily use; this equates to a total of 194 kg of recommended on-board hydrogen storage.

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Table 7.19 Total On-Board Storage

Harbour Direct Combustion Fuel Cell

(Route) Required Backup Total On- Required Backup Total On- Capacity storage (kg) board Capacity storage board (kg) Storage (kg) (unit) Storage (kg) Stromness 297 25 332 240 20 260 (Graemsay) Pierowall (Papa 94 23 117 76 19 95 Westray) Kirkwall 576 29 605 465 23 488 (Shapinsay) Rousay 240 14 254 194 11 205 (Tingwall) Houton 911 51 962 736 41 777 (Lyness) Kirkwall (Eday) 1,474 338 1,812 1,190 273 1,463

Kirkwall 2,479 302 2,781 2,002 244 2,246 (Westray) Kirkwall (North 1,078 539 1,617 871 435 1,306 Ronaldsay) Total 7,149 1,322 8,471 5,774 1,068 6,842

Table 7.20, below, continues by relating the above data to the quaintly of electricity required to produce the recommended volumes of hydrogen. In order to produce 1 kg of hydrogen from electrolysis, 50 kWh of electrical energy is required158. From the table below it can be seen that fuel cells would require approximately 150% more power to meet production requirement than that for direct combustion.

Table 7.20 Generation Power

Harbour (Route) Direct Combustion Fuel Cell

Required Energy for Required Energy for Capacity (kg) Production Capacity (kg) Production (kWh) (kWh) Stromness (Graemsay) 297 14,850 240 12,000 Pierowall (Papa Westray) 94 4,700 76 3,800 Kirkwall (Shapinsay) 576 28,800 465 23,250 Rousay (Tingwall) 240 12,000 194 9,700 Houton (Lyness) 911 45,550 736 36,800 Kirkwall (Eday) 1,474 73,700 1,190 59,500 Kirkwall (Westray) 2,479 123,950 2,002 100,100 Kirkwall (North Ronaldsay) 1,078 53,900 871 43,550 Total 7,149 357,450 5,774 288,700

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Table 7.21, below, estimates the costs required in deploying electrolyser units scaled to the required of hydrogen. This is working on the approximate £1,000/kW figure159 for CAPEX. The average power required to power the electrolyser is represented in kW and assuming hydrogen production through 90% of a 24 hour day. This highlights that an estimated 16.5 MW and 13.4 MW of power demand could be imposed upon the local grid as a result of matching daily hydrogen demand for direct combustion and fuel cell respectively.

Table 7.21 Electrolyser Cost

Harbour Direct Combustion Fuel Cell

(Route) Energy for Electrolyser Electrolyser Energy for Electrolyser Electrolyser Production Rating (kW) Cost (£) Production Rating (kW) Cost (£) (kWh) (kWh) Stromness 14,850 688 687500 12,000 556 555,556 (Graemsay) Pierowall 4,700 218 217593 3,800 176 175,926 (Papa Westray) Kirkwall 28,800 1333 1333333 23,250 1,076 1,076,389 (Shapinsay) Rousay 12,000 556 555556 9,700 449 449,074 (Tingwall) Houton 45,550 2109 2108796 36,800 1,704 1,703,704 (Lyness) Kirkwall 73,700 3412 3412037 59,500 2,755 2,754,630 (Eday) Kirkwall 123,950 5738 5738426 100,100 4,634 4,634,259 (Westray) Kirkwall 53,900 2495 2495370 43,550 2,016 2,016,204 (North Ronaldsay) Total 357,450 16549 16548611 288,700 13,366 13,365,741

As previously stated, the ideal scenario would be for Orkney‟s wind turbines to feed the energy requirement of the electrolysis process.

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Table 7.22, estimates how the production of hydrogen relates the potential to match this calculated demand through typical wind turbines in Orkney. The assumption made for this is that the majority of large-scale turbines are rated at approximately 900 kW and with generate at rated capacity 40% of the year. From the table is can be seen that the calculations result in an estimated 40 900 kW turbines would be required to fuel a full fleet of hydrogen vessels; either fuel cell or direct combustion.

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Table 7.22 Required Wind Turbine Generation

Harbour (Route) Direct Combustion Fuel Cell

Energy for Wind No. of Energy for Wind No. of generation Generation Turbines generation Generation Turbines (kWh) Required (kWh) Required (hours) (hours) Stromness 14,850 41.3 2 12,000 33.3 2 (Graemsay) Pierowall (Papa 4,700 13.1 1 3,800 10.6 1 Westray) Kirkwall 28,800 80.0 4 23,250 64.6 3 (Shapinsay) Rousay (Tingwall) 12,000 33.3 2 9,700 26.9 2 Houton (Lyness) 45,550 126.5 6 36,800 102.2 5 Kirkwall (Eday) 73,700 204.7 9 59,500 165.3 7 Kirkwall (Westray) 123,950 344.3 15 100,100 278.1 12 Kirkwall (North 53,900 149.7 7 43,550 121.0 6 Ronaldsay) Total 357,450 992.9 46 288,700 801.9 38

It is recognised that the key to achieving low hydrogen costs is through the high rate of utilisation of the electrolysis equipment and low electricity prices. This can be achieved through appropriately scale of the system and arrangements with turbine owners. Targets for the production of hydrogen in 2015 was £7.92/kg; and a target of £4.40/kg in 2025160. Thus, average unit costs of electrolysers continues to change as further developments are made. However, utility scale units add £1,000/kW161 to the capital expenditure.

An example of a current project in Orkney developed to investigate the feasibility of using hydrogen is the Surf „n‟ Turf project. This project was initiated in order to mitigate the effects of the grid constraints among the islands. The concept is for tidal developers at EMEC‟s test site on Eday and local wind generation to feed power into the electrolysers to produce hydrogen as an energy storage medium. This hydrogen will be shipped to Kirkwall harbour, where a 75 kW fuel cell will provide power to the outer island ferries overnight as well as harbour buildings. An illustration of this operating is found in Figure 7.9.

Figure 7.9 Surf 'n' Turf162

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The unit that has been chosen for the Surf „n‟ Turf project is ITM Power‟s HGas360 electrolyser. The 50 W unit has the capacity to produce 120 Nm3/hour of hydrogen gas at normal pressure and temperature. This volume equates to 10.79 kg/hour. An additional 100 kW, 600 kW in total, is also required to power the compressor as well as the water and coolant pumps163.

7.4.2 Storage

The Surf „n‟ Turf project discussed previously, is currently in line to utilise 250 kg of mobile storage that will be filled when required and then transported to Kirkwall. Four banks of interconnected tanks will provide the capacity to store 500 kg of compressed hydrogen at 200 bar on site164.

Storage of hydrogen on-shore would most likely be limited to key locations. These locations would have a high probability of being within close proximity to sites of production. The storage options discussed within this assessment is compression. Compressed hydrogen storage is the most developed and simplest option; only a compressor and suitable tank is required. The cost of compressed tank are in the region of £32/kWh (£490/kg).

Table 7.18, above, details the results of the calculations into the hydrogen demands of vessels fitted for direct combustion or fuel cell propulsion. To store 1 kg of liquid hydrogen the tank will weigh 15 kg; including the weight of valves and heat exchanges. Liquid hydrogen also provides a level of design freedom due to its lower pressure which allows the design of the tank to avoid the necessary cylindrical shape of pressurised tanks165. Gaseous hydrogen must be compressed to 200 bar (29,000 psi) in order to achieve the same energy density of liquid hydrogen166. Even at this pressure a tank for compressed hydrogen gas tanks would weigh approximately 100 kg for 1 kg of fuel167.

The tables below breaks down the calculated weight of hydrogen required on-board, the full and empty weight of the storage tank and also the approximate cost of the storage tanks; this is done for direct combustion propulsion (

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Table 7.23) and fuel cell propulsion (Table 7.24) requirements respectively.

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Table 7.23 On-Board Storage Solution Weight and Cost for Fuel Cell

Harbour (Route) Total On-board Empty Tank Weight full Total Storage CAPEX (£) Fuel (kg) Weight (kg) (kg) Cost (£)

Stromness 260 3,900 4,160 71,022 78,124 (Graemsay)

Pierowall (Papa 95 1,425 1,520 25,854 28,439 Westray)

Kirkwall 488 7,320 7,808 133,107 146,418 (Shapinsay)

Rousay (Tingwall) 205 3,075 3,280 55,967 61,563

Houton (Lyness) 777 11,655 12,432 211,889 233,078

Kirkwall (Eday) 1,463 21,945 23,408 399,022 438,925

Kirkwall 2,246 33,690 35,936 612,392 673,632 (Westray)

Kirkwall (North 1,306 19,590 20,896 356,044 391,648 Ronaldsay)

Total 6,842 102,600 109,440 1,865,297 2,051,827

Table 7.24 On-Board Storage Solution Weight and Cost for Direct Combustion

Harbour (Route) Total On-board Empty Tank Weight Total Storage CAPEX (£) Fuel (kg) Weight (kg) full (kg) Cost (£)

Stromness (Graemsay) 297 4,455 4,752 87,932 96,725

Pierowall (Papa Westray) 94 1,410 1,504 32,010 35,211

Kirkwall (Shapinsay) 576 8,640 9,216 164,799 181,279

Rousay (Tingwall) 240 3,600 3,840 69,292 76,221

Houton (Lyness) 911 13,665 14,576 262,339 288,572

Kirkwall (Eday) 1,474 22,110 23,584 494,028 543,431

Kirkwall (Westray) 2,479 37,185 39,664 758,200 834,020

Kirkwall (North Ronaldsay) 1,078 16,170 17,248 440,816 484,898

Total 7,149 107,235 114,384 2,309,416 2,540,358

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The calculated numbers within the above table represent the recommended capacity for on-board storage assuming refuelling daily. For on-shore storage it is recommended that the level of storage capacity includes contingency measures. Table 7.25 shows the recommended quantities of fuel to be stored on-shore includes the daily requirements and a week‟s supply. This table also includes the estimate cost of such storage.

Table 7.25 On-shore Storage

Harbour (Route) Fuel Cell Direct Combustion

Required Backup Total Required Backup Total Storage Capacity Storage Storage Capacity Storage Cost (£) (kg) (kg) Cost (£) (kg) (kg)

Stromness (Graemsay) 240 480. 196,444 297 595 243,216

Pierowall (Papa Westray) 76 379 124,099 94 470 153,647

Kirkwall (Shapinsay) 465 1,906 646,519 576 2,360 800,452

Rousay (Tingwall) 194 1,357 422,783 240 1,680 523,446

Houton (Lyness) 736 3,679 1,203,644 911 4,555 1,490,226

Kirkwall (Eday) 1,190 5,356 1,784,866 1,474 6,632 2,209,834

Kirkwall (Westray) 2,002 10,679 3,457,380 2,479 13,221 4,280,566

Kirkwall (North Ronaldsay) 871 1,741 712,088 1,078 2,156 881,633

Total 5,774 25,257 8,547,824 7,149 595 10,583,020

7.4.3 Refuelling

As previously stated, figures for the on-board capacity for hydrogen fuelled ferries has been calculated assuming daily refuelling. If this does not fit in with daily operations for Orkney Ferries then the capacity of the on-board tanks need to be scaled in order to meet suitable refuelling scheduling.

Refuelling of the vessels would most likely be in the form of tanker that would refuel each ferry while docked on the Mainland. This may involve timetabling conflicts for vessels that don‟t dock on the Mainland overnight. Alternatives to this scenario are to install additional storage facilities among the islands or to ensure long enough stopovers on the Mainland. Minimising the movement of refuelling infrastructure would significantly reduce capital costs and logistical hurdles.

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Table 7.26 SmartFuel hydrogen tube trailer168

7.4.4 Impact on Vessels

To date the use of hydrogen for vessel propulsion, either as direct combustion or through fuel cells, is very limited. As such there are very few case studies to derive real world data from. However, through the accumulation of data it has been possible to make estimates of some of the associated costs. The table below display the results of the calculations for the cost of the on-board storage and engine costs. A figure of 5% on top of both these costs was used for an estimate of on-board infrastructure cost. Also operational cost (OPEX) was taken at 5%, in the absence of more accurate data.

Table 7.27, below, graphs the component costs for a fuel cell driven system fuelled by compressed hydrogen, rated from the current diesel fleet for illustrative purposes. The CAPEX ranges from £88,257 to £1,579,192; with the respective OPEX being £4,413 and £78,960.

Table 7.27 Breakdown Costs of Fuel Cell Propulsion

Vessel Total Cost of Total CAPEX (£) OPEX (£) Storage (£) System Cost (excluding fuel) (£)

Stromness (Graemsay) 71,022 313,200 403,433 20,172

Pierowall (Papa Westray) 25,854 58,200 88,257 4,413

Kirkwall (Shapinsay) 133,107 397,200 556,822 27,841

Rousay (Tingwall) 55,967 264,600 336,595 16,830

Houton (Lyness) 211,889 573,600 824,763 41,238

Kirkwall (Eday) 399,022 891,600 1,355,154 67,758

Kirkwall (Westray) 612,392 891,600 1,579,192 78,960

Kirkwall (North Ronaldsay) 356,044 891,600 1,310,026 65,501

Total 1,865,297 4,281,600 6,454,242 322,712

The same calculations were made in order to approximate the cost breakdown for a direct combustion propulsion system (Table 7.28). As can be derived from comparing Table 7.27 and Table 7.28, direct combustion is the cheaper solution with reference to capital costs.

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Table 7.28 Breakdown Costs of Direct Combustion Propulsion

Vessel Total Cost of Total System CAPEX (£) OPEX (£) Storage (£) Cost (£) (including fuel)

Stromness (Graemsay) 87,932 208,800 311,569 15,578

Pierowall (Papa Westray) 32,010 38,800 74,350 3,718

Kirkwall (Shapinsay) 164,799 264,800 451,079 22,554

Rousay (Tingwall) 69,292 176,400 257,977 12,899

Houton (Lyness) 262,339 382,400 676,976 33,849

Kirkwall (Eday) 494,028 594,400 1,142,849 57,142

Kirkwall (Westray) 758,200 632,000 1,459,710 72,986

Kirkwall (North 440,816 632,000 1,126,457 56,323 Ronaldsay) Total 2,309,416 2,929,600 5,500,967 275,048

As can be seen, the storage makes for a clear majority of the total cost of the propulsion system in both cases. Thus, sizing this correctly could result in cost efficiency. It should be noted that these cost represent approximate calculations for the propulsion systems alone and not the whole vessel.

7.4.5 Impact on-shore

The necessary quantities of hydrogen required daily have been discussed previously within section 7.4.2 (Storage). The previous section in question discussed the required daily quantities of hydrogen to meet demand as well as addressing the contingency quantities to mitigate the risk of supply disruption; which in this case was assumed to be one week worth of fuel at minimum.

Placing of storage will depend on factors such as safety; current and required infrastructure; available and possible transport links; and which routes, if any, can be served by this fuel.

The on-shore storage for the hydrogen let would be substantial in volume and cost. The cost alone could reach £10.5 million.

7.4.6 Conclusion

As previously mentioned, University College London conducted a study into the projected uptake of hydrogen in shipping. Part of this work was to produce a sensitivity analysis of this uptake between 2010 and 2050. As such it was predicted that the unit cost of hydrogen was the main factor in the project future; followed by the capital cost and fuel cell efficiency169. It is the hydrogen cost which locally based electrolysers have the potential to affect. Investing in local production through electrolysis will reduce the risk of exposure of Orkney Ferries to varying external hydrogen markets.

Taking the previous calculations into consideration it is possible to start gaining a picture of the required costs to shift the current fleet al to hydrogen if desired.

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Table 7.29 and Table 7.30 breakdown the on-shore

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Table 7.29 Direct Combustion Propulsion Total System Costs

CAPEX (£) Level 1 Level 2 Level 3 Total

On-Shore Costs 1,033,747 5,730,833 15,787,199 22,551,779

On-Board Costs 385,919 1,386,031 3,729,017 5,500,967

Total 1,419,666 7,116,864 19,516,216 28,052,746

Table 7.30 Fuel Cell Propulsion Total Systems Costs

CAPEX (£) Level 1 Level 2 Level 3 Total

On-Shore Costs 582,655 4,628,750 12,751,199 17,962,604

On-Board Costs 491,690 1,718,181 4,244,372 6,454,243

Total 1,074,345 6,346,931 16,995,571 24,416,847

Clearly these do not account for the full extent of costs these vessels would account for; examples including infrastructure deployment for fuel production, transportation and refuelling as well as crew training.

There is very real potential to implement a hydrogen solution among the fleet of inner and outer island ferries. This could potentially almost remove carbon emissions from the services and account for significant social benefits for the islands through the absorption of major quantities of grid curtailment.

7.5 ELECTRIC HYBRIDS

7.5.1 Production

Electric hybrid systems comprise an electric system using a battery and a complimentary system powered by another fuel. In the case of this study, the second system could be LNG, hydrogen, or marine gas oil. The proportion of the hybrid can vary but for this analysis, it will be assumed 30% electric – 70% second fuel. Both systems may be used separately or simultaneously. Using the systems simultaneously can increase the overall efficiency, allowing a better fuel usage (smart battery system).

During low to mid power cruising (around 2/3 of maximum hull speed) the electric motor can drive the vessel using the energy stored in the battery bank. When the batteries are depleted then the main engine switches in to drive the vessel. At this time the electric motor automatically becomes a generator and recharges the batteries. Once the batteries are recharged the motor can switch back to electric drive. Alternatively the energy in the batteries can be reserved to silently drive high power appliances when anchored at the end of the day.

In the case of a hydrogen-electric hybrid, the entire quantity of the fuel needed would be produced in Orkney, as explained in the two previous scenarios. The electrolyser required will be 30% smaller than the one considered in the cases of full hydrogen vessels.

In the other cases, electricity would still be generated in Orkney while the second fuel, either LNG or gas oil, would be imported as explained previously.

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7.5.2 Storage

Storage options are the same as the ones described for non-hybrid cases. Only the sizing of the infrastructure would differ as only 70% of the fuel is needed, which makes the overall onshore storage cost lower than for non-hybrid vessels. Moreover, it has been estimated that no battery storage is required at the harbours as the electric storage on- board vessels may be recharged overnight through an electric cable or during the day with the vessel motor.

Table 7.31 Type of on-shore infrastructure per fuel and refuelling frequency.

Fuel Infrastructure Refuelling frequency

Gas oil Bunded tanks Seasonal (once in the summer period, once in the winter period)

LNG Cryogenic Tanks @350kg/m3 Weekly

CNG Pressurised tube trailer @200bar, 128kg/m3 Weekly

Hydrogen - Fuel Pressurised Tube Trailer (compressed H2 at Daily Cell 350bar) @25kg/m3

Hydrogen - Pressurised Tube Trailer (liquid H2) @70kg/m3 Daily Direct burn

Electricity Electric connection (cable) On demand

Table 7.32, below, provides a breakdown of the on-shore components and costs for hybrid vessels across the different routes currently serviced by Orkney Ferries.

Table 7.33 details the total of cost of these technologies.

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Table 7.32 On-shore storage infrastructure and costs for 30% electric hybrid vessels.

)

(L) L

Harbour (Route) Fuel

Required Required Capacity (m3) Size week One emergency ( storage Additional (m3) size Cost Storage £ CAPEX Overall £ Overall OPEX annual £ Gas oil with existing infrastructure Stromness 31,282 22 1,555 1 0 5,372 26,843 (Graemsay) Gas oil without existing infrastructure 31,282 22 1,555 1 53,723 59,095 26,843

LNG 2,751 3 2,751 3 31,762 34,938 47,376

CNG 7,922 8 7,922 8 111,007 122,108 121,925

Hydrogen - Fuel Cell 3,389 7 6,778 13 137,511 407,858 87,293

Hydrogen - Direct burn 4,196 8 8,392 17 170,251 504,967 108,077

Electricity 9,681

Gas oil with existing infrastructure Pierowall 12,934 9 1,228 1 0 2,317 8,215 (Papa Westray) Gas oil without existing infrastructure 12,934 9 1,228 1 23,169 25,486 8,215

LNG 2,172 2 2,172 2 25,081 27,590 20,176

CNG 6,255 6 6,255 6 87,658 96,424 53,537

Hydrogen - Fuel Cell 1,251 2 5,352 11 86,870 176,606 28,250

Hydrogen - Direct burn 1,070 3 6,627 13 107,553 218,656 34,976

Electricity 2,810

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)

(L) L

Harbour (Route) Fuel

Required Required Capacity (m3) Size week One emergency ( storage Additional (m3) size Cost Storage £ CAPEX Overall £ Overall OPEX annual £ Gas oil with existing infrastructure Kirkwall 65,003 45 6,170 4 0 11,644 53,167 (Shapinsay) Gas oil without existing infrastructure 65,003 45 6,170 4 116,445 128,089 53,167

LNG 10,916 12 10,916 12 126,055 138,660 118,602

CNG 31,439 32 31,439 32 440,555 484,610 311,720

Hydrogen - Fuel Cell 6,561 13 26,899 53 452,563 994,578 180,665

Hydrogen - Direct burn 8,123 16 33,304 66 560,317 1,231,383 223,680

Electricity 18,948

Gas oil with existing infrastructure Rousay 67,518 47 4,392 3 0 11,765 54,742

Gas oil without existing infrastructure 67,518 47 4,392 3 117,650 129,415 54,742

LNG 7,770 8 7,770 8 89,720 98,692 106,067

CNG 22,377 23 22,377 23 313,567 344,924 275,565

Hydrogen - Fuel Cell 2,735 5 19,146 38 295,948 532,634 161,797

Hydrogen - Direct burn 3,386 7 23,704 47 366,412 659,452 200,321

Electricity 19,560

Gas oil with existing infrastructure Houton 345,454 240 11,908 8 0 58,467 139,053

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)

(L) L

Harbour (Route) Fuel

Required Required Capacity (m3) Size week One emergency ( storage Additional (m3) size Cost Storage £ CAPEX Overall £ Overall OPEX annual £ Gas oil without existing infrastructure 345,454 240 11,908 8 584,670 643,137 139,053

LNG 21,067 23 21,067 23 243,266 267,592 252,544

CNG 60,672 62 60,672 62 850,201 935,221 660,251

Hydrogen - Fuel Cell 10,382 21 51,911 103 842,551 1,712,912 384,198

Hydrogen - Direct burn 12,854 26 64,271 128 1,043,159 2,120,749 475,673

Electricity 43,204

Gas oil with existing infrastructure Kirkwall 545,709 441 17,336 14 0 107,330 438,594 (Eday) Gas oil without existing infrastructure 545,709 441 17,336 14 1,073,306 1,180,636 438,594

LNG 30,671 33 30,671 33 354,176 389,594 691,552

CNG 88,333 91 88,333 91 1,237,828 1,361,611 1,764,468

Hydrogen - Fuel Cell 16,795 33 75,578 150 1,249,406 2,646,025 1,194,776

Hydrogen - Direct burn 20,794 41 93,573 186 1,546,884 3,276,031 1,479,246

Electricity 153,753

Gas oil with existing infrastructure Kirkwall 294,986 238 34,563 28 0 62,821 252,363 (Westray) Gas oil without existing infrastructure 294,986 238 34,563 28 628,204 691,025 252,363

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)

(L) L

Harbour (Route) Fuel

Required Required Capacity (m3) Size week One emergency ( storage Additional (m3) size Cost Storage £ CAPEX Overall £ Overall OPEX annual £ LNG 61,149 67 61,149 67 706,118 776,730 600,509

CNG 176,109 181 176,109 181 2,467,847 2,714,632 1,587,787

Hydrogen - Fuel Cell 28,253 56 150,680 299 2,420,166 4,801,370 849,740

Hydrogen - Direct burn 34,979 69 186,556 370 2,996,396 5,944,554 1,052,060

Electricity 88,227

Gas oil with existing infrastructure Kirkwall 59,372 48 5,636 5 0 12,392 38,690 (North Ronaldsay) Gas oil without existing infrastructure 59,372 48 5,636 5 123,921 136,313 38,690

LNG 9,971 11 9,971 11 115,135 126,648 92,619

CNG 28,715 30 28,715 30 402,390 442,629 245,760

Hydrogen - Fuel Cell 12,284 24 24,569 49 498,462 1,478,444 163,065

Hydrogen - Direct burn 15,209 30 30,419 60 617,143 1,830,454 201,890

Electricity 12,900

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Table 7.33 Total on-shore storage infrastructure and costs for 30% electric hybrid vessels

Total size of storage (m3) Total storage cost (£) Total CAPEX (£) Total OPEX (£)

Total for gas oil hybrid with existing infrastructure 0 0 272,108 1,360,749

Total for gas oil hybrid without existing infrastructure 1,154 2,721,088 2,993,196 1,360,749

Total for LNG hybrid 319 1,691,313 1,860,445 2,278,530

Total for CNG hybrid 867 5,911,053 6,502,158 5,370,098

Total for hydrogen fuel cell hybrid 878 5,983,477 12,750,429 3,398,868

Total for hydrogen direct combustion hybrid 1,087 7,408,114 15,786,245 4,125,007

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7.5.3 Refuelling

Electric hybrid systems allow a higher flexibility in terms of refuelling, compared to full electric. The electric battery could be charged daily, either via an electric cable at the overnight harbour or using the second fuel system as a generator. This implies that it could run out of energy before the end of the day, but as there is a second system, it would not be an issue.

The second fuel system should aim for a refuelling frequency of every two to four days in the case of LNG or gas oil, and daily for hydrogen. This is due to the fuel availability and on-board storage size: local hydrogen production would be about continuous and refuelling daily would allow limited storage size both onshore and aboard the vessels, while natural gas or gas oil are imported fuels, so available in any amount targeted, and easier to store.

7.5.4 Impact on Vessels

On-board infrastructure ould be smaller than for non-hybrid designs. Considering a 30% battery powered system and 70% other fuel system, volume and costs for storage infrastructures have been calculated in Table 7.35, the total storage cost being the addition of the battery storage and the second fuel. The CAPEX has been estimated for the overall infrastructure required (storage, engine, propulsion, fuel pipe circuit) while the OPEX is assessed to be 5% of the CAPEX and do not take account of the costs related to fuel consumption as these were already considered in Table 7.32.

Table 7.34 Type of storage infrastructure on-board vessels per fuel and refuelling frequency.

Fuel Infrastructure Refuelling frequency

Gas oil Tank Daily (70%)

LNG Cryogenic Tank @350kg/m3 Daily (70%)

CNG Pressurised MCP (200 bar @ 128kg/m3) Daily (70%)

Hydrogen - Fuel Cell MCP (200 bar @ 25kg/m3) Daily (70%)

Hydrogen - Direct burn MCP (200 bar @ 25kg/m3) Daily (70%)

Electricity Battery (@300kWh/m3 and 110Wh/kg) Per 30% trip with return

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Table 7.35 On-board storage infrastructure and costs for 30% electric hybrid vessels.

Harbour (Route) Fuel Required Unit Size Backup storage Size for backup Storage Cost Weight full Overall Overall Capacity (m3) (unit) (m3) (£) (kg) CAPEX (£) OPEX (£) (unit)

Stromness Gas oil 458 kg 0.5 55 0.1 1,426 837 165,927 8,296 (Graemsay) LNG 521 kg 1 63 0.2 8,851 1,084 173,723 8,686

CNG 521 kg 4 63 0.5 31,107 2,384 197,092 9,855

Hydrogen - Fuel 168 kg 7 20 0.8 51,378 3,015 382,807 19,140 Cell

Hydrogen - 208 kg 8 25 1.0 63,611 3,733 286,031 14,302 Direct burn

Electricity 270 kWh 0.9 135,028 2,455 361,019 18,051

Pierowall (Papa Gas oil 145 kg 0.17 51.72 0.06 545 267 31,127 1,556 Westray) LNG 165 kg 0.5 58.79 0.2 3,385 323 34,109 1,705

CNG 165 kg 1 59 0.5 11,896 1,123 43,046 2,152

Hydrogen - Fuel 53 kg 2 18.97 0.8 19,649 1,153 81,742 4,087 Cell

Hydrogen - 66 kg 3 23.48 0.9 24,327 1,428 66,284 3,314 Direct burn

Electricity 256 kWh 0.85 127,952 2,326 175,090 8,754

Kirkwall Gas oil 888 kg 1.04 63.40 0.07 2,638 1,308 211,300 10,565 (Shapinsay) LNG 1,009 kg 3 72 0.2 16,379 1,931 225,728 11,286

CNG 1,009 kg 8 72 0.6 57,564 4,141 268,972 13,449

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Harbour (Route) Fuel Required Unit Size Backup storage Size for backup Storage Cost Weight full Overall Overall Capacity (m3) (unit) (m3) (£) (kg) CAPEX (£) OPEX (£) (unit)

Hydrogen - Fuel 325 kg 13 23.25 0.9 95,076 5,580 516,890 25,845 Cell

Hydrogen - 403 kg 16 28.78 1.2 117,714 6,908 401,639 20,082 Direct burn

Electricity 314 kWh 1.05 156,845 2,852 442,727 22,136

Rousay Gas oil 370 kg 0.44 31.19 0.04 1,113 841 140,084 7,004

LNG 421 kg 1 35.46 0.1 6,910 906 146,171 7,309

CNG 421 kg 3 35 0.3 24,286 2,256 164,415 8,221

Hydrogen - Fuel 136 kg 5 11.44 0.5 40,112 2,354 319,948 15,997 Cell

Hydrogen - 168 kg 7 14.16 0.6 49,663 2,914 237,366 11,868 Direct burn

Electricity 262 kWh 0.87 130,772 2,378 322,531 16,127

Houton Gas oil 1,405 kg 1.65 112.84 0.13 4,209 1,790 305,560 15,278

LNG 1,597 kg 5 128.27 0.4 26,135 2,625 328,581 16,429

CNG 1,597 kg 12 128 1.0 91,850 5,325 397,583 19,879

Hydrogen - Fuel 515 kg 21 41.38 1.7 151,707 8,903 761,572 38,079 Cell

Hydrogen - 638 kg 26 51.23 2.0 187,827 11,023 598,739 29,937 Direct burn

Electricity 993 kWh 3.31 496,404 9,026 922,744 46,137

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Harbour (Route) Fuel Required Unit Size Backup storage Size for backup Storage Cost Weight full Overall Overall Capacity (m3) (unit) (m3) (£) (kg) CAPEX (£) OPEX (£) (unit)

Kirkwall (Eday) Gas oil 2,647 kg 3.11 868.21 1.02 9,752 3,988 493,135 24,657

LNG 2,583 kg 7 847.07 2 51,968 4,630 537,462 26,873

CNG 2,583 kg 20 847 7 182,643 10,630 674,670 33,734

Hydrogen - Fuel 833 kg 33 273.26 10.9 301,666 17,703 1,282,539 64,127 Cell

Hydrogen - 1,032 kg 41 338.32 13.5 373,491 21,919 1,055,766 52,788 Direct burn

Electricity 4,015 kWh 13.38 2,007,574 36,501 2,751,813 137,591

Kirkwall (Westray) Gas oil 4,453 kg 5.24 774.85 0.91 14,503 5,844 498,123 24,906

LNG 4,345 kg 12 755.99 2 77,284 6,881 564,043 28,202

CNG 4,345 kg 34 756 6 271,617 17,701 768,093 38,405

Hydrogen - Fuel 1,402 kg 56 243.88 9.8 448,622 26,328 1,436,843 71,842 Cell

Hydrogen - 1,735 kg 69 301.94 12.1 555,437 32,596 1,246,808 62,340 Direct burn

Electricity 4,503 kWh 15.01 2,251,397 40,934 3,007,827 150,391

Kirkwall (North Gas oil 1,936 kg 2.28 1,383.07 1.63 9,208 3,471 492,564 24,628 Ronaldsay) LNG 1,889 kg 5 1,349.40 4 49,069 4,189 534,417 26,721

CNG 1,889 kg 15 1,349 11 172,453 9,539 663,970 33,199

Hydrogen - Fuel 609 kg 24 435.30 17.4 284,835 16,716 1,264,867 63,243 Cell

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Harbour (Route) Fuel Required Unit Size Backup storage Size for backup Storage Cost Weight full Overall Overall Capacity (m3) (unit) (m3) (£) (kg) CAPEX (£) OPEX (£) (unit)

Hydrogen - 755 kg 30 538.95 21.6 352,653 20,696 1,014,146 50,707 Direct burn

Electricity 5,874 kWh 19.58 2,936,777 53,396 3,727,476 186,374

Table 7.36 Total on-board storage infrastructure and costs for 30% electric hybrid vessels

Total storage cost £ Total CAPEX £ Total OPEX £

Total for gas oil hybrid 8,286,144 14,049,046 702,452

Total for LNG hybrid 8,482,729 14,255,461 712,773

Total for CNG hybrid 9,086,165 14,889,068 744,453

Total for hydrogen fuel cell hybrid 9,635,794 17,758,434 887,922

Total for hydrogen direct combustion hybrid 9,967,472 16,618,005 830,900

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By comparing the figures from the above tables with the previous cases, it can be seen that the storage costs on-board the vessels and thus the capital costs are significantly higher for hybrids due to the currently high battery costs (over £8 million as shown in Table 7.35 and Table 7.36). However, savings occur on operational costs due to 30% reduced fuel consumption. Table 7.37 below demonstrates the comparison of costs between hybrid and non-hybrid vessels. Cells in green represent savings associated with hybrid options, and cells in red represent great costs by opting for hybrid options.

Table 7.37 Extra costs and savings considering hybrids over non-hybrids.

Hybrid CAPEX (hybrid)/ Additional CAPEX OPEX (hybrid)/ Saving associated technology CAPEX (non- (£) OPEX (non- with OPEX (£) hybrid) ratio hybrid) ratio

Gas oil hybrid 6.09 11,967,978 1.32 500,307

LNG hybrid 3.05 10,828,470 1.04 103,469

CNG hybrid 1.68 8,666,050 0.82 -1,385,479

Hydrogen Fuel cell hybrid 1.23 5,750,892 0.92 -397,198

Hydrogen direct combustion hybrid 1.15 4,331,765 0.87 -714,303

Another concern would be the weight added to the ship by the battery storage compared to single fuel storage. This will impact the suitability of the technology to the vessel and route considered.

7.5.5 Impact on Shore

On-shore infrastructures would comprise fuel storage (for LNG, CNG, hydrogen or gas oil) as described in the previous sections and potentially electric cables at harbours to charge the batteries overnight. No on-shore batteries are required and the storage sizing for the second fuel will be 30% smaller than for the non-hybrid cases. Hence the overall onshore infrastructure will be cheaper than for single fuel ferries. CAPEX concerning on-shore developments are lower for hybrids than for non-hybrids (about 30% lower for hydrogen fuel cell and 40% for LNG). Running costs are also lower as less fuel is consumed.

7.5.6 Conclusion

The second screening process showed that hybrids suit all types of routes. From this section, hybrids seem to be a feasible option to power Orkney Ferries vessels in terms of infrastructure requirement. In terms of costs however, although the CAPEX for on-shore infrastructures are lower, the investments for vessels will be very large. The overall capital costs for the full replacement of the Orkney Ferries fuel system and the building of associated onshore infrastructures is estimated to be between £14.3 and £32.5 million depending on the hybrid technology considered, the cheapest being gas oil hybrid (Table 7.38). Thus it may be of interest to consider this technology for only a part of the fleet.

As far as operational costs are concerned, the reduction in fuel consumption may reach up to 30% and is associated with lower operational costs. It would also allow significant emissions reduction compared to the current situation (15% carbon reduction for gas oil hybrid, 79% for LNG hybrid, 50% for CNG, approximately 100% for hydrogen hybrid). Moreover, hybrid ferries in Orkney could have an impact on the use of curtailed

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energy as there is the option to charge vessel batteries overnight. The overall annual OPEX is between £2 and 5 million depending on the technology, the cheapest being gas oil hybrid.

Table 7.38 Total capital and operational expenditures (include both onshore and vessel infrastructures) for the hybrid technologies considered.

Technology Total CAPEX (£) Total OPEX (£)

Gas oil hybrid with existing infrastructure 14,321,155 2,063,202

Gas oil hybrid without existing infrastructure 17,042,243 2,063,202

LNG hybrid 16,115,906 2,991,303

CNG hybrid 21,391,227 6,114,552

Hydrogen fuel cell hybrid 30,508,863 4,286,790

Hydrogen direct combustion hybrid 32,404,250 4,955,907

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8 CONCLUSION

Within this section we have made some comments on the outcomes of the report from our observations. These may well change as the costs and systems are refined.

8.1 CARBON SAVINGS

In terms of carbon emissions, all the different technologies considered show lower results than the current situation. Figure 8.1 illustrates this by comparing each system with gas oil for the amount of CO2 released per year (based on the annual consumptions previously estimated) and the percentage of carbon reduction it represents.

Figure 8.1 Annual amount of carbon released per technology and reduction compared to gas oil.8

CO2 released per year Carbon reduction

10,000 -100%

8,000 -80%

6,000 -60%

4,000 -40%

2,000 -20%

0 0% LNG

-2,000 CNG 20%

Gasoil

LNGhybrid CNGhybrid

-4,000 FullElectric 40%

Gasoil hybrid Total CO2 releasedper year(t)

-6,000 hybrid 60%

Hydrogen-fuel cell Carbonreductioncompared gas to oil (%)

-8,000 80%

Hydrogencellfuel hybrid Hydrogendirect combustion -10,000 Hydrogen-direct combustion 100%

Considering the annual consumption of gas oil for Orkney Ferries, the amount of carbon released nearly reaches 9,000 tonnes, which is higher than every other fuel considered in this study. Switching to LNG would reduce emissions by 17%, CNG by 29%, hydrogen by 39% for fuel cells and 25% for direct combustion, and full electric by 72%. Hybrid technologies using 30% less fuel than non-hybrids show lower emission rates.

Considering the potential targets of 20% and 50% carbon reduction for marine transport by 2020 (red lines on the above graph), this would exclude the gas oil and LNG options.

8 The results for electricity are based on the Orkney Energy Audit 2012 (131gCO2/kWh). It has since then decreased to lower than 100gCO2/kWh.

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Note on Figure 8.1: These figures take production into account, which is why the results for CNG and LNG are different and electric and hydrogen are not null. Considering these elements would increase the difference with gas oil, especially for hydrogen and electricity which can be produced in Orkney.

Figure 8.2 shows the amount of carbon released for every £ invested (based on the CAPEX previously calculated) for each technology considered. The amount of carbon saving is the difference between the current emissions from gas oil and the other fuel systems.

Figure 8.2 Amount of carbon released per £ invested for each technology and carbon saving compared to gas oil.

Total CO2 released per capex (kgCO2/£) Carbon saving

LNG CNG

-1 Gasoil

LNGhybrid

CNGhybrid FullElectric

-2 hybrid oil Gas

hybrid

Hydrogen-fuel cell Total CO2 releasedper CapexCO2/£) (kg

-3

Hydrogencellfuel hybrid Hydrogendirect combustion -4 Hydrogen-direct combustion

The result for gas oil is about 3.8kg CO2/£, which is the highest of the fuels considered. This is due to both low CAPEX figures (the infrastructures already exist in Orkney) and high carbon content.

In comparison, the result is 63% less for LNG, over 85% less for every other technology and close to zero for the full electric option.

8.2 INFRASTRUCTURE COSTS

One of the significant conclusions to take from this analysis is the cost implications from the different scenarios. From the analysis of the fuels available there are potentially large differences in the cost of the vessel solutions; both in terms of CAPEX and OPEX. Within the comparison of the fuels available the current use of gas oil has been included for completeness, even though this is not considered as a potential recommendation.

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8.2.1 CAPEX

The graphs in Figure 8.3 show the capital costs for both non-hybrid and hybrid technologies. (Note: some bars have figures written in them; these bars go beyond the scale chosen for the graphs and the figure represents the actual amount).

LNG came out as the cheapest option, second to gas oil. The higher costs for LNG are as a result of the infrastructure that would be required to facilitate delivery, bunkering and refuelling of LNG. It is then interesting to note that at the current time replacing the current fleet with another gas oil fleet would still be the cheapest option but there would be no carbon savings or curtailed energy usage. It has also been calculated that if hypothetically the infrastructure for gas oil was not already in place in Orkney then deploying so would result in gas oil being more expensive to implement than LNG.

CNG, being the other natural gas solution, follows LNG as the next most expensive option for Orkney. It is hindered in comparison to LNG due to the lower energy density and higher storage costs. However, CNG is still significantly cheaper than the remaining hydrogen and full electric options.

If every route became serviced by full-electric ferries then this solution would have a CAPEX greater than all other screened fuels; and more than twice that of the next fuel, direct combustion hydrogen. The limiting factor in full-electric solutions is the inhibiting cost of batteries. Per unit of energy, batteries remain the most expensive form of energy storage. It is for this reason why hybridising vessels would add significant cost to the vessels. However, it should be noted that batteries are seeing the fastest reduction in cost due to the significant cross-industry R&D. John Perry, of Denchi Power Ltd, predicts that in 2017 the unit cost of batteries should drop to £500/kWh. Energy Storage Update is a division of FC Business Intelligence, an independent market research company, which have also predicted a 50% reduction in the unit of cost of batteries in the next five years. This is an interesting prospect for the ferry links in Orkney as along with hydrogen fuel there is a significant potential benefit to Orkney through the use of curtailed energy. The graph below (Figure 8.4) aims to illustrate the impact on CAPEX if the unit cost of batteries was 50% cheaper than that used in Figure 8.3.

It would reasonably be expected that new ferry solutions would not begin to be implemented until the next two or three years. So taking this into consideration differing battery costs could potentially change the conclusions of this report.

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Figure 8.3 Capital expenditures (per route level and total) for (a) non-hybrid technologies and (b) hybrid technologies.

(a) (b)

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Figure 8.4 Comparison between current and future capital expenditures per route level and total for hybrid technologies, considering a 50% reduction of battery costs in five years.

Level 1 (short routes) Level 2 (medium routes) Level 3 (long routes) Total Level1 -50% Level 2 -50%

Level 3 -50% Total -50%

30 Millions

15 CAPEX CAPEX £ in

0 Gas oil hybrid Gas oil hybrid LNG hybrid CNG hybrid Hydrogen Fuel Hydrogen direct (with existing (without existing cell hybrid combustion infrastructures) infrastructures) hybrid

8.2.2 OPEX

The graphs in Figure 8.5 show the operational costs for both non-hybrid and hybrid technologies. (Note: some bars have figures written in them; these bars go beyond the scale chosen for the graphs and the figure represents the actual amount).

Here again, LNG came out as the cheapest option, second to gas oil. This is due to the low cost of LNG and relatively high energy density which allows a limited amount of fuel required. The next most expensive solution would be electricity, followed by fuel cells and hydrogen direct combustion, while CNG would be the most expensive one for each route level and in total, because of its low energy density and thus higher import cost.

Hybrid technologies allow some reductions in OPEX compared to the non-hybrid cases. For example CNG would see an 18% drop in annual running costs while hydrogen systems would approximately see a drop of 10%.

Considering the predicted 50%reduction in the unit of cost of batteries in the next five years, electric hybrids would allow further savings (up to 21% for CNG compared to non-hybrids), including lower LNG OPEX compared to the non-hybrid case. The graph below (Figure 8.6) aims to illustrate the impact on OPEX if the unit cost of batteries was 50% cheaper than that used within this work.

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Figure 8.5 Operational expenditures (per route level and total) for (a)non-hybrid technologies and (b) hybrid technologies.

(a) (b)

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Figure 8.6 Comparison between current and future operational expenditures per route level and total for hybrid technologies, considering a 50% reduction of battery costs in five years.

Level 1 (short routes) Level 2 (medium routes) Level 3 (long routes) Total Level 1 -50% Level 2 -50%

Level 3 -50% Total -50%

6 Millions

3 OPEX £ OPEX in

0 Gas oil hybrid LNG hybrid CNG hybrid Hydrogen Fuel cell Hydrogen direct hybrid combustion hybrid

Note: the outcomes of the carbon analysis and cost analysis show different „best options‟. Indeed, the cheapest option (gas oil) is also the one with the highest carbon footprint, while the most environment friendly one (electric) is the most expensive. Thus the „best option‟ depends on the criteria of the deciding panel (see Executive Summary and Figure 8.7, Figure 8.8, Figure 8.9 below).

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Figure 8.7 Secondary screening for level 1 routes with varying weightings on the importance of carbon savings, and associated CAPEX (a) and OPEX (b).

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Figure 8.8 Secondary screening for level 2 routes with varying weightings on the importance of carbon savings, and associated CAPEX (a) and OPEX (b).

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Figure 8.9 Secondary screening for level 3 routes with varying weightings on the importance of carbon savings, and associated CAPEX (a) and OPEX (b).

There could also be an option for some heat recovery from some of the systems which ahs not been factored into the figures but which would benfit the OPEX figures. Orkney harbours noticed a 50% reduction in electrical use when heat recovery was added to the Gramsay.

8.3 CURTAILED ENERGY

As mentioned throughout the report, Orkney suffers from significant levels of curtailment of the renewable energy capacity on the islands; most of which being large scale turbines. The ability to address this could have a measurable societal benefit to the local population as the majority of these curtailed turbines are community owned.

Through the analysis of the power demands of full-electric and hydrogen ferries, being the options that could create significant electrical demand, it was possible to approximately calculate the energy required to fuel these vessels, to meet current route requirements. Then by making assumption in wind power generation it was possible to approximate the number of wind turbines required to meet the demand of a these technologies across different routes. The assumptions included a capacity factor of 40% and the wind turbines rated at 900 kW which is a common size in the islands. Table 8.1, below, illustrates the results of these calculations.

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Table 8.1 Required Energy Consumption and Wind Generation

Average daily Wind Turbines Wind Turbines Wind Turbines Overnight fuel usage Required – Required – Route Required – Port (litres of gas Hydrogen Direct Hydrogen Fuel Full Electric oil) Combustion Cell

Kirkwall Eday 3,853 4 9 7 Kirkwall North Ronaldsay 2,818 3 7 6

Kirkwall Westray 6,481 6 15 12 Rousay Tingwall 1,380 1 2 2 Kirkwall Shapinsay 1,505 2 4 3

Houton Lyness 2,382 2 6 5 Stromness Graemsay 777 1 2 2 Pierowall Papa Westray 246 1 1 1

Total 19,441 20 46 38

If the hydrogen required was produced on Orkney, instead of imported, then a hydrogen solution would need twice as many turbines as a full-electric ferry solution. This is due to the significantly greater energy efficiency of battery energy storage than hydrogen generation and storage. All three of these options would produce enough power demand to remove grid curtailment and allow space on the grid for the deployment of additional turbines. This would clearly be very dependent upon the grid reinforcement and planning permission. But the implications of this could include significant revenue to Orkney and turbine owners.

It should also be noted that even though this study took the approach that a 900 kW wind turbine represented an average turbine in Orkney, there would be an even greater potential for the deployment of smaller domestic renewables.

Orkney has placed itself as a global focal point in the movement towards a renewables future. With an extensive portfolio of renewable technologies, energy management systems, electric vehicles and now hydrogen production through electrolysis, there is every reason to continue this pursuit and consider these feasible novel technologies. Currently on a global scale, there are considerably few ferries drawing power from either full-electric or hydrogen propulsion. As such Orkney holds the potential to again set a standard for renewable energy utilisation.

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8.4 MODULAR STORAGE

One of the key restrictions on the alternative fuels is the energy storage on board the vessel. The current use of gas oil is undoubtedly convenient. There is an extensive well developed infrastructure, storage is cheap and easy, and the energy density allows the vessels to operate for long periods before refuelling is required. For CNG, LNG and hydrogen with a lower energy density than Fuel oil the storage space is an issue on board the vessel. For full electric vessels the recharging time during many stop-overs only last 10-15 minutes. To meet this time constraint would require significant power demands to recharge the batteries. A modular design for the fuel storage technologies has the potential to meet some of the hurdles impeding the fuel‟s use. A prime example of this would be the swapping of on-board batteries during shorter stops. It could be expected that this would require a lorry-sized space on the ferry with a hook-up point situated next to it. By avoiding the requirement for rapid charging for a fixed on-board battery and separate on-shore battery solution, the interchangeable batteries of a modular solution could be trickle charged while situated on the shore and not in use. Charging at a lower power would be healthier for the battery, prolonging life-span and minimising running costs. Also, the vessel would not then exceed the current stopover times, which would contribute towards acceptance of the technology. This ability to change batteries instead of allowing enough time to fully charge batteries during stops could also potentially have implications on the volume of on-board storage required. If the vessels can change the battery at the next stop then this will limit the amount of contingency storage, which will have direct implications on the CAPEX of the vessel. Through further consultation with John Perry of Denchi Power Ltd it is acknowledged that there may be some technical issues to overcome since this would be a new technique, but these would not result in significant hurdles.

Modular fuel containers for CNG and LNG fuels imported from England would also minimise the number for deliveries required as these could be stacked on an appropriately scaled cargo vessel. These containers could then potentially be delivered to the required refuelling locations, or placed directly onto purpose built vessels. This would work on the similar assumption to the battery option, where empty storage containers would be replaced with full ones.

The additional benefit of modular storage would be the potential for vessels to meet the requirements to cover the distances to a dry dock under their own propulsion. The vessel, which would not be carrying any passengers or vehicles, could be carrying additional batteries or fuel containers to maximise the on-board energy capacity.

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9 APPENDICES

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Appendix 1 Absolute preliminary screening process results

Time to market and time Capital and operating Compliance with current Suitability for sea Technical maturity and to MCA proposal cost regulations conditions deliverability Technology Total Non Non Non Non Non Weighted Weighted Weighted Weighted Weighted weighted weighted weighted weighted weighted

Diesel 24 2 6 1 3 2 6 2 6 1 3

Diesel electric 24 2 6 1 3 2 6 2 6 1 3 driven systems

Liquid Natural 24 2 6 1 3 2 6 2 6 1 3 Gas

Compressed 15 1 3 0 0 2 6 1 3 1 3 Natural Gas

Electric hybrid 21 2 6 0 0 2 6 2 6 1 3 driven systems

Biofueled 18 1 3 1 3 2 6 1 3 1 3 systems

Electrical battery 12 1 3 0 0 0 0 1 3 2 6 driven systems

Hydrogen - direct 9 1 3 0 0 0 0 1 3 1 3 combustion

9 2 6 0 0 0 0 1 3 0 0 Hydrogen - Fuel

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Cells

Hydrogen - Co- 6 1 3 0 0 0 0 0 0 1 3 burning

Biomass -6 -1 -3 0 0 0 0 -1 -3 0 0

Sails soft and -9 -2 -6 1 3 2 6 -2 -6 -2 -6 rigid

Nuclear -12 2 6 -2 -6 -2 -6 -1 -3 -1 -3

Liquid Nitrogen -15 -2 -6 -1 -3 -2 -6 -1 -3 1 3

Anhydrous -18 -2 -6 -1 -3 -2 -6 -1 -3 0 0 ammonia

Compressed air -24 -2 -6 -1 -3 -2 -6 -1 -3 -2 -6

Flow cell -24 -2 -6 -1 -3 -2 -6 -1 -3 -2 -6 systems

Wave energy -27 -2 -6 -2 -6 -2 -6 -1 -3 -2 -6

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Appendix 2 Assessment factors and importance factors

Minor negative Neutral Key Major negative -2 Minor positive +1 Major positive +2 -1 0 Category Assessment Importance

factors factors

Longer term 5 - Medium term 2 - Short ( within 2 Commercially Market readiness Time to market 3 Concept 10 5 years years) available

Capital and Operating cost Overall cost 3 Very high costs High costs Average costs Low costs Very low costs

Compliance with current Regulation in Regulation 3 No Yes regulation process

Not currently Designed Suitability of the Difficult for use Adapted to sea 3 adapted to sea Suitable specifically for sea technology sea travelling travelling travelling travelling Technical characteristics Large Commercial Availability of Pre commercial Available 3 infrastructure available Available locally infrastructure infrastructure nationally requirement infrastructure

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Figure 9.1 Non-weighted score per technology and per assessment factor Figure 9.2 Weighted score per technology

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Appendix 3 Secondary screening process scoring – Route level 1

Technical Socio-economic Environmental

Required Ability to Robustness Local content energy

deliver and Impact – input Impact energy Infrastructure Operational flexibility on opportunities (Additional Risk relative to on CO2 requirement requirements cost of the curtailed for local criteria) Total propulsion emissions for each given energy business and output

route service employment non weighted non

Technologies weightedTotal (efficiency) 24 Liquid Natural Gas 6 1 2 1 1 0 2 -2 0 1 0 23 Hydrogen - Fuel Cells 10 0 2 1 1 0 1 2 1 2 0 23 Hydrogen - direct combustion 10 0 2 1 1 0 1 2 1 2 0 15 Hydrogen - Co-burning 4 0 2 1 0 -1 2 0 0 0 0 21 Electrical battery driven systems 9 1 1 -1 2 2 0 2 0 2 0 17 Diesel electric hybrid 2 1 2 0 1 -1 2 0 -2 -1 0 20 Diesel electric driven systems 1 1 2 2 1 -1 2 -2 -2 -2 0 17 Diesel 0 1 2 2 0 -1 2 -2 -2 -2 0 14 Biofueled systems (first generation) 1 1 2 1 -1 -1 2 -2 -1 0 0 20 4 1 2 1 0 0 2 -2 0 0 Compressed Natural Gas 0 22 Alternative fuel electric hybrid 8 0 2 1 1 0 2 0 1 1 0

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Appendix 4 Secondary screening process scoring – Route level 2

Technical Socio-economic Environmental

Required Ability to Robustness Local content energy

route service employment non weighted non

Technologies weightedTotal (efficiency) 24 Liquid Natural Gas 6 1 2 1 1 0 2 -2 0 1 0 15 Hydrogen - Fuel Cells 8 0 1 0 1 0 1 2 1 2 0 15 Hydrogen - direct combustion 8 0 1 0 1 0 1 2 1 2 0 10 Hydrogen - Co-burning 3 0 1 1 0 -1 2 0 0 0 0 14 Electrical battery driven systems 7 1 0 -1 2 2 -1 2 0 2 0 17 Diesel elecric hybrid 2 1 2 0 1 -1 2 0 -2 -1 0 19 Diesel electric driven systems 1 1 2 2 0 0 2 -2 -2 -2 0 17 Diesel 0 1 2 2 0 -1 2 -2 -2 -2 0 14 Biofueled systems (first generation) 1 1 2 1 -1 -1 2 -2 -1 0 0 17 3 1 2 1 -1 0 2 -2 0 0 0 Compressed Natural Gas 22 Alternative fuel electric hybrid 8 0 2 1 1 0 2 0 1 1 0

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Appendix 5 Secondary screening process scoring – Route level 3

Technical Socio-economic Environmental

Required Ability to Robustness Local content energy

route service employment non weighted non

Technologies weightedTotal (efficiency) 24 Liquid Natural Gas 6 1 2 1 1 0 2 -2 0 1 0 15 Hydrogen - Fuel Cells 8 0 1 0 1 0 1 2 1 2 0 15 Hydrogen - direct combustion 8 0 1 0 1 0 1 2 1 2 0 10 Hydrogen - Co-burning 3 0 1 1 0 -1 2 0 0 0 0 6 Electrical battery driven systems 5 1 -1 -2 2 2 -1 2 0 2 0 17 Diesel electric hybrid 2 1 2 0 1 -1 2 0 -2 -1 0 19 Diesel electric driven systems 1 1 2 2 0 0 2 -2 -2 -2 0 17 Diesel 0 1 2 2 0 -1 2 -2 -2 -2 0 14 Biofueled systems (first generation) 1 1 2 1 -1 -1 2 -2 -1 0 0 17 3 1 2 0 0 0 2 -2 0 0 0 Compressed Natural Gas 22 Alternative fuel electric hybrid 8 1 1 1 1 0 2 0 1 1 0

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Appendix 6 Assessment factors and importance factors for secondary screening

Minor negative Neutral Minor positive Major positive Major negative -2 Key +1 +2 -1 0

Category Assessment Importance

factors factors

Risk 5 Very high High Moderate Minor None

Ability to Needs to refill Can manage deliver energy Cannot reach the Needs to refill Can manage 5 before end of several trips requirement for next port at every stop one trip. the full trip. without refill. each route

Large amount of new Infrastructure Infrastructure Infrastructure Minimal Infrastructure 3 infrastructure required at needed at < required at 20 upgrades requirements required at all most ports 50% of ports - 50% of ports required Technical ports

At least 15% 1-15% higher 1-15% Lower At least 15% Operational No change from 3 higher cost than cost than cost than lower cost than cost baseline baseline baseline baseline baseline

Required energy input System System System relative to System efficiency System over 2 efficiency 20 - efficiency 40 - efficiency 60 - propulsion <20% 80% efficient 40% 60% 80% output

(efficiency)

Full flexibility Robustness Route specific Some flexibility Moderate Flexibility and and no time and flexibility 2 and timetable and time flexibility and minimal time table of the service constrained limitations time limitations limitations restrictions Socio-economic Moderate Uses large Overcomes Impact on Minor amounts amounts of amounts of curtailment with curtailed 1 No impact of curtailed curtailed curtailed additional energy energy energy electricity capacity

Local content

– opportunities No significant Minor Short term Medium term Long term for local 1 effect opportunities opportunities opportunities opportunities business and Environmental employment

Impact on CO2 No significant Minor Moderate Significant 1 No emissions emissions effect reductions reductions reductions

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121 Personal correspondence with Nigel Holmes. Scottish Hydrogen and Fuel Cell Association (2013)

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212 OIC