Generation, of the energy carrier HYDROGEN In context with ... D8.2 Final report on... · Figure 9...

NyOrka 12/18/2008

SIXTH FRAMEWORK PROGRAMME

Project no: 502687 NEEDS New Energy Externalities Developments for Sustainability INTEGRATED PROJECT Priority 6.1: Sustainable Energy Systems and, more specifically, Sub-priority 6.1.3.2.5: Socio-economic tools and concepts for energy strategy. Deliverable n° 8-5 RS1a Life cycle approaches to assess emerging energy technologies Technology specification: Generation, of the energy carrier HYDROGEN In context with electricity buffering generation through fuel cells Corresponding author: [email protected] Due date of deliverable: June 2008 Start date of project: 1 September 2004 Duration: 48 months Organisation name for this deliverable: Icelandic New Energy Project co-funded by the European Commission within the Sixth Framework Programme (2002-2006) Dissemination Level PU Public X

PP Restricted to other programme participants (including the Commission Services)

RE Restricted to a group specified by the consortium (including the Commission Services)

NyOrka 12/18/2008

Specific acronyms ............................................................................................................... 4 1 Structure ...................................................................................................................... 5

1.1 The data sources ................................................................................................... 5 2 Hydrogen..................................................................................................................... 5

2.1 Methods and pathways for production ................................................................. 6 2.2 Electrolysis ........................................................................................................... 8 2.3 Process description of electrolysis ....................................................................... 9 2.4 Life Cycle Evaluation of the Electrolysis .......................................................... 12

2.4.1 Material flow data and sources ................................................................... 14 3 Results ....................................................................................................................... 15

3.1.1 Key emissions and land use ........................................................................ 15 3.1.2 Contribution analysis for the main life cycle phases .................................. 16

3.2 Additional information ....................................................................................... 17 3.2.1 Spatial disaggregation ................................................................................. 18

4 Electrolysis technology development pathways ....................................................... 19 4.1 Hydrogen roadmaps and policy .......................................................................... 21 4.2 Criteria for hydrogen applications ...................................................................... 23

4.2.1 Efficency of production .............................................................................. 23 4.2.2 Quality criteria ............................................................................................ 23 4.2.3 On site production of hydrogen; grid criteria ............................................. 24 4.2.4 Quantitative criteria .................................................................................... 26 4.2.5 Where would the hydrogen come from? ..................................................... 26 4.2.6 Niche markets ............................................................................................. 27

4.3 Cost of hydrogen production from two sources ................................................. 29 4.4 Future scenarios – cost comparison ................................................................... 33 4.5 Price trends in future .......................................................................................... 35

4.5.1 The potential role of hydrogen in a future energy supply system ............... 37 4.5.2 Integrated systems ....................................................................................... 39

5 Technology development perspectives ..................................................................... 39 6 Specification of future technology configurations .................................................... 41 7 Conclusions ............................................................................................................... 42 8 References ................................................................................................................. 43 9 Annex ........................................................................................................................ 46

NyOrka 12/18/2008

Figure 1 Overview of energy streams, from source to user phase. Any source of energy can become a source of hydrogen and therefore it may give all regions an opportunity for local production and specific local use. .............................................................................. 7 Figure 2 A schematic overview of the process flow within the three main types of electrolysis .......................................................................................................................... 9 Figure 3 An overview of the connected components of an electrolytic fuel station anno 2003................................................................................................................................... 11 Figure 4 The main life cycle phases of a hydrogen filling station. ................................... 12 Figure 5 Main components of an electrolytic hydrogen filling station. ............................ 13 Figure 6 Contribution analysis for electrolytic hydrogen production, when using UCTE grid mix. Refer to figure 7 for comparison with grid mix based on renewable sources. .. 16 Figure 7 Comparison of key emissions using UCTE electricity grid and the Icelandic electricity grid. .................................................................................................................. 17 Figure 8 Energy road-maps for the new century predict that fuel types for transport, will contain gradually less carbon.. .......................................................................................... 19 Figure 9 Presentation of the context between hydrogen supply and demand. ................. 20 Figure 10 An overview of expected proportion number of hydrogen vehicle penetration on the world market according to various sources............................................................ 22 Figure 11 Hydrogen or electricity by cable? Pathways for hydrogen import to Europe have been mapped by the ‘Encouraged’ project. .............................................................. 27 Figure 12 The system setup in Ramea ............................................................................. 28 Figure 13 Measured cost of Equipment, site preparation, investment and operation cost (2005) for electrolyser per kg hydrogen; electricity cost = 10 ct/ kWh; Nitrogen cost = 0,5 €/ Nm3 ............................................................................................................................... 31 Figure 14 Measured cost of equipment, site preparation, investment and operation cost (2005) for a steam reformer per kg hydrogen – electricity cost = 10 ct/ kWh; natural gas cost = 5 ct/ kWh; nitrogen cost = 0,5 €/ Nm3. .................................................................. 32 Figure 15 Cost burden from hydrogen purfication criteria ............................................... 32 Figure 16 Future scenario: Reformer – Electrolyser; cost for electricity set at 0,10 € per kWh ................................................................................................................................... 35 Figure 17 Composition of cost factors using projected learning effect but based on current yet upscaled technology. Electrolyser scenario 600 Nm3/h and 170 plants; cost per kg hydrogen - electricity cost = 10 ct/ kWh; nitrogen cost = 0,5 €/ Nm3 .................. 36 Figure 18 Steam Reformer scenario 600 Nm3/h and 170 plants; cost per kg hydrogen. Electricity cost = 10 ct/ kWh; natural gas cost = 5 ct/ kWh; N2 cost = 0,5 €/ Nm3, all using fore .......................................................................................................................... 37 Figure 19 A hydrogen test system that is intended to monitor and raise total energy efficiency. .......................................................................................................................... 39

NyOrka 12/18/2008

Table 1 The characteristics of electrolysis units available worldwide ............................. 10 Table 2 List of selected electrolytic technology and general configurations .................... 12 Table 3 Description of LCA phases .................................................................................. 13 Table 4 Parameters for the studied hydrogen production facilities in current situation. .. 13 Table 5 Material and energy flows allocated to the production of current electrolytic hydrogen production plants. .............................................................................................. 14 Table 6 Key emissions and land use of the reference plants. ........................................... 16 Table 7 Temporal disaggregation for hydrogen production ............................................. 18 Table 8 Spatial disaggregation for hydrogen production facilities. .................................. 18 Table 9 Influential factors for the integration of hydrogen in the energy system ............. 22 Table 10 Information on size and amount of energy needed to run four different sizes of hydrogen stations. ............................................................................................................. 25 Table 11 Needed number and size of new transformers within Reykjavik’s grid system if hydrogen is produced on site near main transport routes. ................................................ 25 Table 12 Cost composition of three sizes of electrolytic hydrogen stations based on costs of new equipment and operation costs as experienced during 5 years of operation in Reykjavik. The price is in Isk where 100Isk=1€ ............................................................. 30 Table 13 Boundary conditions for electrolyser and steam reformer set for comparison of production cost of hydrogen. ............................................................................................ 34 Table 14 Parameters that are used to scale up future cost reduction potentials ................ 34 Table 15 Total share of hydrogen vehicles according to the Hy-Ways scenarios; Pessimistic – very optimistic scenario. A Realistically optimistic would set hydrogen penetration at 2% of the vehicle fleet by 2020 and up to 50% in 2050. ........................... 38 Table 16 Market share scenarios of stationary applications presented in the European hydrogen road map ........................................................................................................... 38 Table 17 Hydrogen production technology datasheet: Electrolysis ................................. 41

Specific acronyms FC: fuel cell GCV: Gross Calorific Value H2 : chemical formula of hydrogen, HHV: higher heating value LCA: Life Cycle Analysis LCE Life Cycle Engineering LHV: Lower heating value Nm3: Normal cubic meters; metric unit for quantifying hydrogen volume at 0°C and

1atm pressure

NyOrka 12/18/2008

1 Structure The goal of this chapter is to shed light on the technology that is currently and foreseen to be used to produce hydrogen which can become an important energy carrier and describes policies and road maps concerning its market penetration. Only an optimistic scenario suggesting maximum expected penetration of hydrogen as an electric buffer and fuel for transport is presented. An LCA description and cost estimates follow for a contemporary hydrogen production system as are trends for the future settings. Reflections are given about the expected development of the components and materials within the selected pathway, electrolysis in combination with renewable energy systems, space and energy requirements and cost perspectives including the external costs.

1.1 The data sources As of yet, no major investment has been made in a real scale system that is to survive throughout the timeframe of the NEEDS project: 2005 – 2050. No single technological winner has been selected neither for a final strategy to produce nor to use hydrogen as an energy carrier in stationary applications. Therefore it is currently impossible to give a detailed Life Cycle Analysis of any future hydrogen equipment. Reports, policy papers, technological previews have been emerging since 2005 and prove to be controversial. Information for the following paper has been collected from European, Asian – Pacific, Canadian and Japanese sources as well as reports that have emerged from the International Energy Agency, and the Hydrogen Implementation Agreement. (IEA/HIA) Interviews have been conducted and singular questions sent to developmental managers in strategic positions in industries in Norway, Canada and Germany and weighed against experience of running hydrogen systems for transport in Iceland and Germany during the period 2003 – 2008. It is hereby acknowledged that the staff at ,,Hydro Electrolysers” and the project partners in HyFLEET:CUTE have by far, added most value to the preset selection for this report.

2 Hydrogen Hydrogen, H2, is an energy carrier, not to be found in natural conditions but can be extracted from numerous materials and energy sources; energy will be lost in the production phase. Hydrogen is the lightest element on Earth1, usually composed of one proton and one electron and forms a diatomic volatile gas, H2, with boiling point at 20.4°K. Hydrogen can be liquefied under high pressure and extreme cooling which demands energy expenditure. Explosions may occur at a mixture of hydrogen and air between 4 and 75% by volume. The same amount of energy bound in 1liter of gasoline is approx 3Nm3 under atmospheric pressure2 but that amount would weigh only 270 grams. The energy contents are 3.00KWh/Nm3 or 12.75 MJ/Nm3 or 144MJ/kg. While a gasoline tank on a vehicle may take 50 litres of fuel, a hydrogen tank on a similar vehicles made in 2003 would hold less than 2 kg of hydrogen and give roughly a driving range of 150 km.

1 www.britannica.com gives a good insight into chemical and physical properties of hydrogen 2 Nm3 stands for normal cubic meters because it is measured at 0°C and 1,013bar pressure.

NyOrka 12/18/2008

The weight of the full hydrogen tank is still higher than that of the gasoline fuel tank because of the material and safety requirements of the container; Materials must withstands corrosive attack from hydrogen and oxygen and can hold extreme pressure as well as prevent diffusion through walls and system connection. Whereas hydrogen is highly volatile, disperses extremely fast, burns with an invisible flame and must be extremely pure to make fuel cells work properly, then hydrogen production, storage and distribution must be optimised along every step within the energy conversion path. Further conversion factors have been issued in tables and explained in various languages3.

2.1 Methods and pathways for production

Three main methods exist for the mass production of hydrogen; Steam reforming, partial oxidation, and electrolysis. Emerging technologies are thermolysis and thermo-chemical cycles, which have not been built yet and operate at temperatures above 1000°C. The classic methods are described in text books such as CJ Winter’s: Hydrogen as an energy carrier4.

Approximately 95 percent of hydrogen is currently produced via steam reforming. Steam reforming is a thermal process that involves reacting natural gas or other light hydrocarbons with steam. This is a three-step process that results in a mixture of hydrogen and carbon dioxide, which is then separated by pressure swing adsorption, to produce pure hydrogen. Steam reforming is considered the most energy efficient commercialized technology currently available (η = 75-82%), and is most cost-effective when applied to large, constant loads. In this case the hydrogen must be transported to the market and purified to fit the use within PEM fuel cells. Research is being conducted on improving catalyst life and heat integration, which would lower the temperature needed for the reformer and make the process even more efficient and economical. Recent demonstrations where hydrogen vehicles, especially buses have been tested in real transport service, difficulties have arisen with small scale gas-reformers of the size that would fit hydrogen refuelling stations5 These problems have not been defined properly within the industry but refer to both operational and purity problems. Due to these discoveries the reforming technology that has been referred to as straight forward exercise of down-scaling an established technology before broad on site applications the reforming procedures will not be addressed within this chapter of future technology pathways. Partial oxidation (auto-thermal production) of fossil fuels is another method of thermal production. It involves the reaction of fuel with a limited supply of oxygen to produce a hydrogen mixture, which is then purified. Partial oxidation can be applied to a wide range of hydrocarbon feedstock, including light hydrocarbons as well as heavy oils and hydrocarbon solids. However, it has a higher capital cost because it requires pure oxygen

3 An Icelandic/english version is to be found on www.newenergy.is/publications. 4 Winter, Carl-Jochen & Joachim Nitsch eds 1988; Hydrogen as an energy carrier, technologies, systems, economy (translation from: Wasserstoff als Energieträger) Springer Verlag, Berlin, New York. 5 HyFleetCute; the hydrogen bus demonstrations in Berlin, Nov 2008, presentation by Total;

NyOrka 12/18/2008

to minimize the amount of gas that must later be treated. In order to make partial oxidation cost effective for the specialty chemicals market, lower cost fossil fuels must be used. Current research is aimed to improve membranes for better separation and conversion processes in order to increase efficiency, and thus decrease the consumption of fossil fuels. The direct use of natural gas in the energy mix is growing rapidly, not the least as fuel for transport and is therefore in direct competition with hydrogen on the market. Central production of hydrogen from natural gas demands a different approach to distribution and infrastructure as compared with hydrogen that is made in a distributed manner; mainly with electrolysis from water or directly from solar power plants.

Figure 1 Overview of energy streams, from source to user phase. Any source of energy can become a source of hydrogen and therefore it may give all regions an opportunity for local production and specific local use.

NyOrka 12/18/2008

Electrolysis, the splitting of pure water with electricity will be described later in more detail as this is the selected technological pathway in this work package of NEEDS. Electrolysis has been in use for decades, and it is currently subjected to further technological evolution for higher efficiency, minimal environmental effects and use with fluctuating electric input. The modularity of the equipment and the possibility to install onsite production facilities near the market gives higher flexibility for location choices and evades the need for heavy investment for hydrogen distribution. The wide range of methods for production, storage and use phase of hydrogen is shown in figure 4. The oval at the lower half of the figure indicates which technical specifications will be addressed in the report. While making hydrogen with electrolysis from water and energy all renewable energy forms that give rise to electricity and or high heat can be considered for the process. According to the International Energy Agency, the year 2000 48% of hydrogen was derived from Natural gas, 18% from Coal and 30% from oil through gasification and 4% from electrolysis. The total quantity was about 500 billion Normal m3 annually The application methods are as varied as are the options for transportation from the hydrogen source to the users. Figure 1gives an overview of some of the hydrogen production and application options that are currently in use. The following criteria will form a frame will be set as boarders for the study: Minimisation of environmental effects, boosting efficiency and minimisation of the cost of handling and distribution as well as built in safety requirements. The scope here is though set around the methods that use water as the source of hydrogen and renewable energy to run the process. 48% of hydrogen was derived from Natural gas, 18% from Coal and 30% from oil through gasification and 4% from electrolysis. The total quantity was about 500 billion Normal m3 annually

2.2 Electrolysis As mentioned the third family of production methods is electrolysis or splitting of water with an electric current. Electricity is lead through water and the water molecules split into oxygen at the anode and hydrogen at the cathode. The oxygen can be collected and used for specific purposes such as industry or aquaculture. One example of electrolysis from a chemical process but is not included further whereas the hydrogen is not as pure and the amounts are limited hydrogen production: the Lurgi process that produces hydrogen as a side-product from the production of Chlorine and sodium compounds. The purity if hydrogen made from water is higher and this is essential for PEM Surely hydrogen can be collected from chemical industry, yet it may not be enough in the long run and industries that only produce hydrogen for the energy market will be put near to the markets while chemical plants are usually kept away from human settlements. Therefore options that can make hydrogen on a large scale must be defined.

Three types of industrial electrolysis units are used today. Two involve an aqueous solution of potassium hydroxide (KOH), which is used because of its high

NyOrka 12/18/2008

conductivity, and are referred to as alkaline electrolyzers. These units can be either unipolar or bipolar. The unipolar electrolyser resembles a tank and has electrodes connected in parallel. A membrane is placed between the cathode and anode, which separate the hydrogen and oxygen as the gasses are produced, but allows the transfer of ions. The bipolar design resembles a filter press. Electrolysis cells are connected in series, and hydrogen is produced on one side of the cell, oxygen on the other. Again, a membrane separates the electrodes.

The third type of electrolysis unit is a Solid Polymer Electrolyte (SPE) electrolyser. These systems are also referred to as PEM or Proton Exchange Membrane electrolysers. In this unit the electrolyte is a solid ion conducting membrane as opposed to the aqueous solution in the alkaline electrolyser. The membrane allows the H+ ion to transfer from the anode side of the membrane to the cathode side, where it forms hydrogen. The SPE membrane also serves to separate the hydrogen and oxygen gasses, as oxygen is produced at the anode on one side of the membrane and hydrogen is produced on the opposite side of the membrane.

Electrolytic units are currently capable of producing the largest amounts of hydrogen, and today are in use worldwide mostly the lye based technology, the selected case for the NEEDS . The LCA analysis is based on The PEM electrolysis unit is the newest of the technologies and is the cleanest candidate for future hydrogen production. Because the similarities with PEM fuel cells and PEM electrolyser it is foreseen that this unit will develop into the same unit: A reversible fuel cell! It is used for electrolysis to produce hydrogen AND for the electric production from hydrogen. Prototypes of these are

2.3 Process description of electrolysis

Regardless of the technology, the overall electrolysis reaction is the same:

H2O → ½ O2 + H2

Figure 2 A schematic overview of the process flow within the three main types of electrolysis

NyOrka 12/18/2008

Different processes will use different pieces of equipment. For example, PEM units will not require the KOH mixing tank, as no electrolytic solution is needed for that type. Another example involves water purification equipment. Water quality requirements differ across electrolysers but water purifiers can also be essential according to the quality of the available water. Some units include water purification inside their hydrogen generation unit, while others require an external deionizer or reverse osmosis unit before water is fed to the cell stacks. A water storage tank may be included to ensure that the process has adequate water in storage in case the water delivery is interrupted6.

Table 1 The characteristics of electrolysis units available worldwide

For systems that do not include a water purifier, one is added in the process flow. Each system has a hydrogen generation unit that integrates the electrolysis stack, gas purification and dryer, and heat removal. Electrolyte circulation is also included in the hydrogen generation unit in alkaline systems (up to 30% mixture). The integrated system is usually enclosed in a container or is installed as a complete package. Oxygen and purified hydrogen are thereafter lead to respective compressors or liquefaction processes depending on the selected transportation pathways. In addition to the listed manufacturers, there are several less known electrolyser manufacturers in US, Europe, India, Japan and China. Several of these manufacture for indigenous supply only. The energy required to produce hydrogen with water electrolysis varies slightly for the different electrolysers, according to Table 1. Despite the amount of energy required for the electrolysis process, the conversion efficiency is high, in the range of 80 to 85 % with reference to the gross calorific value (GCV). The size of an electrolyser can be varied. The economies of scale only apply partially to this type of hydrogen production (see Table 12). An optimization between the sizes of production units, storage capacity and distribution systems (as well as land costs) must be found according to the size of the user group. The first version of the European Hydrogen Handbook7 suggest a safety zone around hydrogen fuel stations in the range of 7 – 13

6 Iain Alexander Russel, Hydro Elecrtolysers personal communication, email 10th of Dec 2006 and 7 Hy-Approval handbook of hydrogen stations is still a living document, whereas the content has not been approved in all European states. See: http://www.hyapproval.org/publications.html

NyOrka 12/18/2008

meters. In references from the USA, land cost has been reported to be little less than the capital cost for the station8.

Figure 3 An overview of the connected components of an electrolytic fuel station anno 2003. For the purpose of simulation the configuration, size and load can be varied theoretically between the components to find the optimal running conditions according to demand or other criteria9 10 Electric-current density is low when applied for today’s technology, typically 1 – 2 kA/m2. In addition to significantly improving the energy consumption, it also dictates the number of cells and hence the area or footprint required. An increase in current density in the magnitude of 5 – 10 times, without a significant increase in power consumption, as is expected in future electrolysers. Table 2 gives an overview of the main manufacturers and the configuration for the technology.

8 Yang, Christopher and Joan Ogden 2006 Determining the lowest cost H2 delivery mode article pending to be publised in the international journal of hydrogen energy. 9 Ulleman Oystein, for IEA, hydrogen implementation agreement, annex 18, integrated hydrogen systems subtask B, simulations of hydrogen systems. 10 Ulleberg, Oystein, Susan Schoenung,Maria Maack, Bengt Ridell et al, World Hydrogen Energy Conference, WHEC, Conference paper 2007

NyOrka 12/18/2008

Table 2 List of selected electrolytic technology and general configurations11 Technology; type of electrolyser

Conventional Advanced alkaline Inorganic membrane

PEM SOFC High temp. steam

Development stage

Commercial large scale units

Prototypes and commercial

Commercial units

Prototypes and commercial units

Lab-stage and commer-cial units

Cell voltage (V) 1.8-2.2 1.5-2.5 1.6-1.9 1.4-2.0 0.95-1.3 Current density (A/cm2)

0.13-0.25 0.2-2.0 0.2-1.0 1.0-4.0 0.3-1.0

Temperature (°C) 70-90 80-145 90-120 80-150 900-1000 Pressure (bar) 1-2 <120 <40 <400 <30 Cathode

Stainless steel or Ni

Catalytic or non-catalytic active Ni

Spinel oxide based on CO

C-fibre and Pt Ni

Anode Ni Catalytic or non-catalytic active Ni

Spinel oxide based on CO

Porous Ti and proprietary catalyst

Ni-NiO or Peroskite

Gas seperator

Asbestos 1.2-1.7 Ohm/cm2

Asbestos <100°C Teflon bonded PBI K-titanate >100°C 0.5-0.7Ohm/cm2

Patented polyantimonic acid membrane 0,2-0,3Ohm/cm2

Multilayer expanded metal screens

None

Electrolyte 25-35%

25-40% KOH 14-15% KOH Perfluro-sulfonic KOH

Solid Y2O2 acid membrane 10-12mils thick 0.46 Ohm/cm2

Stabilized ZrO380

Cell efficiency (GJ H2/GJ el)

66-69 69-77 73-81 73-84 81-86

Power need (kwh/Nm3H2)

4,3-4,9 3,8-4,3 4,8 3,6-4,0 2,5-3,5

Key Players

Stuart, Hydro Electrolysers,Teledyne

Stuart, FZ Jeulich, Stuart Stuart, Hamilton, Sunstrand, Proton Energy, Hydrogenise, Fuji, Avalance

LLTL Techno-logy Manage-ment

2.4 Life Cycle Evaluation of the Electrolysis For each of the technologies the four phases fuel supply, operation, production, and disposal of the facility have to be considered while carrying out the LCA. A rough description of the life cycle of a hydrogen filling station is shown in figure 1.1 and presented in table 1.1.

Figure 4 The main life cycle phases of a hydrogen filling station.

11 IEA and OECD: Prospects for hydrogen and fuel cells 2005. The table is stated to be compiled from Prince-Richards S (2004) a Techno-Economic Analysis of Decentralized Hydrogen production. University of Victoria, Canada and Stuart (2005) Vanderborre IMET technology characteristics, Stuart energy, www.stuartenergy.com

NyOrka 12/18/2008

Table 3 Description of LCA phases

LCA phase Description

Fuel supply The station uses grid electricity and tap water to produce compressed gaseous hydrogen ready for use in fuel cells or internal combustion engines.

Production Manufacturing of electrolyzer, compressor and storage modules, dispenser, buffer tank, nitrogen bottles and walls and foundations. On-site assembly.

Operation Replacement of electrolyzer cell package, diaphragms and hydraulic oil for the compressor. Maintenance and overhaul materials for e.g. pipes and fittings, the nitrogen bottles are neglected as supplies due to low data availability. Lye (KOH) to facilitate the splitting of H2O, Nitrogen to flush the cell stack when the process is stopped or in time for maintenance or reparation, this function becomes less needed if the whole module is kept under pressure during i

Disposal All metals are recycled and are not included as the cut-off approach is used. It is assumed that all other materials are transported to landfill or recycling plant.

The hydrogen production facility is made from several modules which are manufactured separately and then assembled on-site. The most important of those can be seen in Figure 5 which shows the main division of the station into its main components.

Figure 5 Main components of an electrolytic hydrogen filling station.

The most important figures and statistics related to the hydrogen station modelled can be seen in Table 4.

Table 4 Parameters for the studied hydrogen production facilities in current situation.

Parameter Unit Current (as of 2003)

Electrolysis Electricity required kWh / kg GH2 62 - for electrolyser kWh / kg GH2 53 - for compressor kWh / kg GH2 8 Water required litres / kg GH2 10

NyOrka 12/18/2008

Storage pressure Bar 440 Production capacity kg GH2 / year 47250 Lifetime years 15 Area occupied m2 300

2.4.1 Material flow data and sources The model used here is based on an inventory compiled by Mailänder in 200312 which considered a hydrogen fuelling station from Norsk Hydro (now HydroStatoil13) assembled in Reykjavík and still in operation by 2008. The data came from the manufacturers of each module. The maximum output of the hydrogen fuelling station is 60 Nm3 H2/h at 15 bar or 5,394 kg/h which amounts to 180kW/h output in energy content. The simulation was altered as to make the results more relevant to current situation in Europe; therefore the hydrogen station was placed in central Europe and furnished by UCTE grid electricity. Table 5 Material and energy flows allocated to the production of current electrolytic hydrogen production plants. Component Material or service unit Per kg GH2 Electrolyser chromium steel 18/8, at plant kg 5,99E-03 nickel, 99.5%, at plant kg 7,05E-04 synthetic rubber, at plant kg 3,53E-05 reinforcing steel, at plant kg 1,87E-03 copper, at regional storage kg 5,40E-04 tube insulation, elastomere, at plant kg 2,40E-04 aluminum, production mix, at plant kg 1,55E-04 acrylonitrile-butadiene-styrene copolymer, ABS, at plant kg 5,64E-05 polyethylene, LDPE, granulate, at plant kg 1,41E-04 glassfiber, at plant kg 1,41E-04 cast iron, at plant kg 4,80E-05 nylon 66, glass-filled, at plant kg 1,76E-05 transport, lorry 32t tkm 9,91E-04 Diaphragm Compressor

reinforcing steel, at plant kg 1,75E-03

chromium steel 18/8, at plant kg 1,34E-03 cast iron, at plant kg 4,23E-04 ethylene glycol, at plant kg 4,94E-06 lubricating oil, at plant kg 1,27E-05 aluminum, production mix, at plant kg 4,23E-05 tube insulation, elastomere, at plant kg 1,06E-05 copper, at regional storage kg 3,17E-05 electricity, production mix UCTE kWh 7,05E-04 heat, natural gas, at industrial furnace >100kW MJ 2,54E-03 transport, lorry 32t tkm 3,62E-04

12 Mailänder, E. (2003). Life cycle analysis of hydrogen infrastructure for fuel cell driven buses in the public transport of Reykjavik, Diploma thesis, University of Stuttgart. 13 See description on www.electrolysers.com

NyOrka 12/18/2008

Storage Module chromium steel 18/8, at plant kg 5,93E-02 electricity, production mix UCTE kWh 6,77E-04 diesel, burned in building machine MJ 6,04E-04 transport, lorry 32t tkm 5,93E-03 Walls and Foundation reinforcing steel, at plant kg 6,35E-03 flat glass, coated, at plant kg 2,29E-03 gypsum fiber board, at plant kg 7,05E-05 silica sand, at plant kg 4,06E-02 concrete, normal, at plant m3 7,05E-06 concrete, exacting, at plant m3 9,17E-05 gravel, unspecified, at mine kg 1,27E+00 lubricating oil, at plant kg 1,41E-05 electricity, production mix UCTE kWh 3,53E-04 diesel, burned in building machine MJ 3,02E-02 transport, lorry 32t tkm 1,56E-01 Occupation, industrial area m2a 6,44E-03 Other Components reinforcing steel, at plant kg 1,16E-03 nitrogen, liquid, at plant kg 1,01E-04 chromium steel 18/8, at plant kg 2,85E-04 polypropylene, granulate, at plant kg 7,05E-06 transport, lorry 32t tkm 6,90E-02 Operation chromium steel 18/8, at plant kg 3,69E-02 nickel, 99.5%, at plant kg 2,82E-03 synthetic rubber, at plant kg 1,41E-04 reinforcing steel, at plant kg 5,50E-02 cast iron, at plant kg 2,54E-02 ethylene glycol, at plant kg 2,96E-04 lubricating oil, at plant kg 7,62E-04 electricity, production mix UCTE kWh 4,23E-02 heat, natural gas, at industrial furnace >100kW MJ 1,52E-01 transport, lorry 32t tkm 2,20E-01

3 Results 3.1.1 Key emissions and land use As a result of WP 1, a “minimum air pollutant list” to be used for the external cost assessment was defined between RS1a and RS1b. The emissions related to hydrogen production facilities are shown in the annex. The emissions shown in table 2.1 are an excerpt of this minimum list and were analysed to be most relevant for hydrogen production. They refer to one kilogram compressed gaseous hydrogen.

The main emission into air is carbon dioxide. Regarding all the emissions the vast majority comes from the fuel supply phase, i.e. the actual production of hydrogen by electrolysis (see Figure 6 below). The emissions from the manufacturing phase of the fuelling station are dominated by the amount of steel and concrete used.

NyOrka 12/18/2008

Table 6 Key emissions and land use of the reference plants. Parameter Path Unit Current

(as of 2003) Electrolysis Kg GH2 Carbon dioxide, fossil Air kg 2.84E+01 Carbon monoxide, fossil Air kg 1.36E-02 Methane, fossil Air kg 4.53E-02 Nitrogen oxides Air kg 5.19E-02 NMVOC Air kg 4.82E-03 Sulfur dioxide Air kg 1.17E-01

3.1.2 Contribution analysis for the main life cycle phases In a contribution analysis the key emissions are split into the four main life cycle phases. Figure 6shows their shares.

Interpretation

It can be assumed that using an electricity mix which relies mostly on renewable energy would result in greatly reduced emissions and therefore a greater proportional share for the manufacturing and operation phases. It is evident from figure 2.1 that the vast majority of emissions comes from the fuel supply phase, i.e. the actual production of hydrogen by electrolysis. This is due to the fact that a great amount of electricity is required for electrolysis, and so the source of electricity is very important. The UCTE production mix contains electricity produced from coal, oil, etc., so emissions from the fuel supply phase are considerable.

Contribution analysis for current electrolytic hydrogen production

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Carbon dioxide, fossil

Carbon monoxide, fossil

Methane, fossil

Nitrogen oxides

NMVOC

Sulfur dioxide

Construction Operation Fuel Disposal

Figure 6 Contribution analysis for electrolytic hydrogen production, when using UCTE grid mix. Refer to figure 7 for comparison with grid mix based on renewable sources.

NyOrka 12/18/2008

The emissions from the manufacturing phase is dominated by the amount of steel that is used in the storage module and the filling station itself, as well as the volume of concrete that is necessary for the foundation. The NOx and CO emissions are also a typical emission related to the combustion of fossil fuels, e. g. in diesel engines related to transportation of the manufactured modules to assembly site. The NMVOC emissions also come from the nickel from the electrolysers electrodes.

Using hydrogen to buffer renewable energy systems, such as a network of windfarms or solar plants, the electricity to run the operation would come from renewable sources as they actually do in the case plant (at Grjóthals, Reykjavik Iceland it is fed electricity from geothermal- and hydropower). The largest impacts may shift to the manufacturing phase of the module where the electricity comes from renewable sources.

To illustrate the importance of the source of the electricity used for hydrogen production, Figure 7compares the key emissions using the UCTE grid and the Icelandic electricity grid which is composed of 82% hydropower and 18% geothermal power).

The absolute values are too different between categories to show in a single graph, so a percentage graph is used instead. Should the electricity be derived from wind turbines the environmental impact would be even become less than for the Icelandic grid mix.

Grid mix comparison

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Carbondioxide

Carbonmonoxide

Nitrogenoxides

Sulphurdioxide

GroupNMVOC to

air

Methane

UCTE MixIS Mix

Figure 7 Comparison of key emissions using UCTE electricity grid and the Icelandic electricity grid.

3.2 Additional information Temporal disaggregation

The temporal disaggregation means the duration of and time between the phases with reference to start of commercial operation. Table 7 shows the values for the reference hydrogen production facilities with year number 1 as start year of commercial operation

NyOrka 12/18/2008

Lifetime of the station is assumed to be 15 years, although some individual modules may have a longer lifetime (up to 30 years). The fuel supply and operation emissions are evenly spread out over those 15 years.

Table 7 Temporal disaggregation for hydrogen production

Phase Unit Present

Electrolytic H2 Production

CONSTRUCTION Start year 0 End year 0

FUEL SUPPLY Start year 1 End year 15

OPERATION Start year 1 End year 15

DISPOSAL Start year 16 End year 16

3.2.1 Spatial disaggregation Table 2.3 provides information on where the main life cycle phases are located. They are allocated to five regions within Europe or to continents if they are outside of Europe.

Because the fuel supply phase is so dominating with regards to the emissions, the spatial disaggregation obviously depends heavily on the location of the facility. In this report the station is assumed to be located in central Europe (region 1), so all of the emissions from operation, fuel supply, and disposal occur there. The only part of the life cycle which happens outside of central Europe is the manufacturing of the electrolyser module, which takes place in Norway (region 4). Exact definition of the affected regions is found below.

Region 1: Belgium, Switzerland, Germany, France, Luxembourg, Netherlands Region 4: Denmark, Estionia, Finland, Greenland, Ireland, Iceland, Lithuania, Latvia, Norway, Sweden. Table 8 Spatial disaggregation for hydrogen production facilities.

Electrolytic hydrogen Region Fuel Prod Op Disp % R1 100 70 100 100 % R2 % R3 % R4 30 % R5 % C1 % C2 % C3 % C4 % C5

NyOrka 12/18/2008

4 Electrolysis technology development pathways The drivers for using hydrogen as energy carrier or buffer for grids are:

• Distributed production i.e. near the customer • Diversification of energy sources and availability of water supply • Clean operation, - important in cities to lower sooth • Good integration possibilities with established electric systems and modules • Buffering opportunities to meet fluctuations between production and demand with

renewable energy systems • Stand alone applications in remote areas possible • Benign environmental effects during use phase • High energy quality characteristics • Combined heat and power production with use of certain Fuel Cells • Easy integration with upcoming transport schemes

During the first stages of introduction, hydrogen from industry and central gas reforming is seen as the main source. Hydrogen will be foremost used as fuel for transport with electric vehicles, and in figure 8 Hydrogen is placed as fuel at the future end for decarbonised fuel types, but hydrogen technology has been used in viable energy systems for decades Two main pathways are predicted for electrolysis when demand rises in the second and third decade of the 21st century; Electrolysis using PEM electrolysers on one hand and high heat, high pressure lye electrolysis on the other. The PEM technology is foreseen as a small module for specific applications while bulk production may require lye electrolysis, which is proven technology. High heat and pressure electrolysis should

occur at temperatures near 500°C (supercritical heat) or more and is foreseen in context with solar thermal tower technologies, high geothermal heat and nuclear power cooling facilities. Figure 8 Energy road-maps for the new century predict that fuel types for transport, will contain gradually less carbon.14. Due to purity demands, the selected hydrogen deployment technology will influence which production pathway is used. The PEM fuel cell

demands high purity while other types of fuel cells can use hydrogen mixed with other gaseous fuel. The PEM is promoted in context with transport drive trains as they are compact and operate at temperatures below 100°C. Recent developments have shown

14Minns David (editor) 2005, APEC 2030 Integrated Fuel technology roadmap

NyOrka 12/18/2008

small reversible PEM units (<10kw) that function as electrolysers and as fuel cells; reversible fuel cells. The development of PEM electrolysers has not been very successful so far, because of material tear. 3.1 Hydrogen hot spots

While defining hydrogen futures the most essential issues are prospects of material and efficiency developments as well as the financial aspects. 3.2 Main carriers and barriers influencing future technology development Hydrogen is foreseen only to have a 3% maximum market penetration on the European level by the year 202015 but its penetration is highly dependent on price of fossil fuel. The late integration is mainly due to high module costs, different, yet firm demands for safety, plus rapid changes in the technological development that still delays mass production of the final technological versions of fuel cells. The technology is still diversified and few evident winners have been pinpointed. Due to lack of international systems’ standards and very high demand for safe handling and inbuilt security as well as purity, and presumed high investment costs in the foreseen infrastructure. There is a dilemma whether standards should be set before the technology has reached maturity because many technical solutions are undergoing field tests until 2012. Considerable energy losses are to be expected on the Well–to-Tank (WTT) part of the Well to Wheel (WTW) pathway, - higher than for conventional fossil fuels.

But efficiency in the TTW part is currently the subject of all drive-train manufacturers. Hydrogen is a very flexible energy carrier, and will be used in hybrid systems in context with batteries whereas the raw material (water) and renewable energy for its production is considered limitless.

Figure 9 Presentation of the context between hydrogen supply and demand16.

15 Hy-Ways European Hydrogen roadmap. 16 European commission: Hydrogen Energy and Fuel Cells, a vision of our future, final report of the high level group, p 12. DG for Energy and Transport. EUR 20719

NyOrka 12/18/2008

4.1 Hydrogen roadmaps and policy The 2003energy policy paper: European Energy Outlook and Transport – Trends to 2030 states that fossil-fuel prices are foreseen to be static and therefore conventional fuel for transport i.e. oil products are considered to keep their market share. Hydrogen is neither mentioned for use in stationary application, CHP nor as fuel for transport17. Some of the Trend paper’s assumptions, such as price for oil, became highly inaccurate only 3 years after its publication. In 2002 the European Commission launched a policy outline regarding hydrogen specifically for Europe18. Hydrogen is linked to hopes for a more energy-self reliant Europe and its policies to decrease carbon emissions and leverage the risk of climate change by increasing the use of renewable local energy. Referring to Error! Reference source not found. it becomes evident that the outlined idea is to derive hydrogen from various sources, either energy carriers with carbon contents or from water through electrolysis. Carbon sequestration is discussed in the same context, if H2 is made centrally from fossil fuels such as gas. The EC supported HyWays19 project (2005– 2007) suggest that the maximum penetration target for hydrogen and fuel cell passenger cars in 2020 should be 3% of the total passenger car fleet. Car- manufacturers (for example GM in USA, Toyota in Japan, Daimler in Europe) state that the technological maturity for marketable FC vehicles will have arrived by 2010 but others20 aim to offer a different type of hydrogen drive train using high heat fuel cells by 2020. Still others manufacture vehicles for public transport that burn hydrogen in internal combustion engines. These vehicles will have integrated battery and hydrogen drive trains to raise efficiency, as will other types of vehicles using different energy carriers derived from renewable sources. In 2006 the European Commission issued a green paper listing a number of options for achieving sustainable competitive and secure energy supplies in the EU21 assuming that hydrogen will be available on the market both as fuel for vehicles and as a buffer in electric systems that are (partially) powered by renewable energy such as connected windfarms. By December 2006 scientists urged the European commission as well as governments and the UN to consider supportive measures to aid the introduction of hydrogen worldwide and a developmental centre whose goal is to facilitate the introduction of hydrogen in developing countries is in Turkey, a country that aims to become part of EU. The use of hydrogen in the transport sector will influence the speed of integration into stationary applications and technological spill-over will influence stationary applications. Current transportation of hydrogen in pipes as is already known from central Europe will 17 European Commission Directorate-General for Energy and Transport, 2003: European energy and transport trends to 2030. Prepared by National Technical University of Athens, E3Mlab 18 EC 2003, High level group to the commission: Hydrogen and fuel cells a vision of our future 19 A brief description of the project, its goals and tools is given at: www.hyways.de/project/description.html 20 Volkswagen, nov 2006 21 EurActiv EU news, policy positions and EU Actors online; 9th of March www.euractiv.com/Article?tcmuri=tcm:29-153252-16&type=News

NyOrka 12/18/2008

continue to be operated, but the speed of integration depends to a high degree on the proportional cost as weight against other types of transport fuel; the higher the price of oil products, the higher the price of fuels made with agricultural products and at the same time the more likelier will become extended use of hydrogen which is made in situ, either from gas or water.

0%

10%

20%

30%

40%

50%

60%

70%

80%

2010 2020 2030 2040 2050

Shar

e of

hyd

roge

n ve

hicl

es (%

)

HyWays High EU Fleet Penetration HyWays Low EU Fleet Penetration IEA World Fleet Penetration

IEA EU Fleet Penetration HFP SRA WETO-H2: H2 case (World)

IEA World Fleet Penetration MAP Scenario

Figure 10 Overview of expected proportion number of hydrogen vehicle penetration on the world market according to various sources22. The matrix of factors that are influential for the speed of hydrogen integration is shown in Table 9. Table 9 Influential factors for the integration of hydrogen in the energy system

22 Gudmundsdottir L. (2008) 23 Final report of HyApproval; harmonised European handbook for Hydrogen stations.

Levels Acts to speed up hydrogen system development

Acts to slow down the speed of hydrogen system development

Admini-strational

Deregulation and growing flexibility; growing use of fuel cells in transport; taxed carbon emissions.

Lack of harmonised hydrogen codes and standards; set restrictions for safety reasons, ignoring technology- and material developments23,

Financial Comparable prices with other transport fuels; Extended use of fuel cells

Lack of standards for purity criteria, these effect which type and life-time of fuel cells; efficient and eco-effective fuel chains from other sources;

Environ-mental

Externalities charged for all fuels. Available electricity grids. High integration of renewable energy power;

as well as minimal and recyclable use of scarce minerals (such as Pt).

Infrastructure

Good access to electric grid complex optimization between production, storage and distribution modules

NyOrka 12/18/2008

4.2 Criteria for hydrogen applications The production pathway selected for further analysis emphasises the electrolytic hydrogen production in as competitive and secure operation as possible and then adjusting these to optimal efficiency. The current bulk production method; steam reformation from gas will also be used as reference.

4.2.1 Efficency of production Current electrolysers show an efficiency of about 65 - 75% but the goal is to raise it up to 87% by 2020. In future models the technology may allow for electrolysis to be carried out under high pressure and partial substitution (up to 20%) of the electric energy with high heat. As a rule the efficiency of low pressure electrolysers is given with the following function:

Electr

HHsystem E

Hm 22 *=η

where mH2 : Mass of produced hydrogen HH2 : Heat value of hydrogen EElectr : Amount of electricity 24

If the pressure in the electrolyser is raised this is done only to reduce the volume of hydrogen and therefore the space of hydrogen stations. When high heat is added to the process the voltage can be lowered from 1,48Volt to 1,23Volt.

4.2.2 Quality criteria Modern PEM fuel cells are sensitive to impurities carried in hydrogen. The purity is sometimes simplified to four, five or six nines (99,99%; 99,999% and 99,9999%), but the tolerance is not equal for all impurities. Within the HyFLEET:CUTE project, the brake down of cost components of hydrogen revealed that monitoring and analysing the quality as well as purification of hydrogen has significant impact on its price. The PEM fuel cells are mostly applied in vehicles but for stationary applications other types are more cost effective and they can use a range of fuel types. The proportional in-stallation of fuel cell types is presented in the fuel cell chapter. From electrolytic hydrogen the impurities consist mainly of O2 that damages the coatings of PEM fuel cells. Impurities from gas-reformation can be H2O, CO, CO2 or N- compounds and those can harm PEM fuel cells but types of stationary FCs can withstand more impurity (see section on fuel cells). International standards for purity have not been set but are rather negotiated along the delivery chain. Drying and purification can raise prices and can become energy intensive within the reformation or gasification methods (see section on hydrogen costs). Whereas the NEEDS project is dedicated to hydrogen in

24 Faltenbacher Michael, PE International 2006, report on LCA of hydrogen production within CUTE cities

NyOrka 12/18/2008

stationary applications, but emphasis on renewable sources hydrogen costs from electrolysis will be compared to that made from gas.

4.2.3 On site production of hydrogen; grid criteria In later decades the ideal distribution is in high pressure pipelines, but this has as of 2008 not been implemented even as a pilot test25. If hydrogen is made with electrolysis the means of transport is in the form of electricity along established grids. Large electrolytic hydrogen production units demand large power intake. For a station that produces more than 500Nm3/h the power must be at least 2,25MW. Also, as power lines have limited capacity an optimal selection must be made between the reinforcement of the grid for electricity distribution and the delivery of hydrogen in the elementary form (via pipes and trucked in). If the grid is not capable of accepting all power that is produced during peak hours, for example from a network of wind farms, then the surplus could be changed to hydrogen on site and stored for times with higher customer demand. This is called hydrogen production from dump load and has been installed for example in Ramea, Newfoundland (see fig 12) Otherwise reinforcement of the grid capacity is an option. In 2008 a study on the optimal pattern for establishing hydrogen fuel stations in Reykjavik, Iceland was carried out. It can give an insight into how they affect the established grid if the demand for hydrogen rises. Results that are shown in Table 10 are according to three main criteria and a following assumption;

1) That electrolytic stations are erected close to step-down transformation points already established within the Reykjavik’s electricity distribution system

2) That their capacity has not been put to the full use 3) That these points lie close to large traffic routes. 4) Assumptions concerning vehicles are that they use 1,3kgH2/100km and will drive

around 12000km annually. The distribution system in the city is made of primary substations and 11kV cables that connect a number of distribution substations and terminate in circuit breakers, usually located between two possible input points from primary substations. In each substation the voltage is stepped down from 11kV to 400V and goes out in a few 400V cables which carry current to a number of small distribution cabinets scattered in the city.

25 Rouvroy, Steven Shell Hydrogen, HyFLEET:CUTE meeting, May 2008

NyOrka 12/18/2008

Table 10 Information on size and amount of energy needed to run four different sizes of hydrogen stations. Size of stations 60 Nm3 130 Nm3 485 Nm3 970 Nm3* INPUT Production capacity 60 130 485 970 Nm3/h B, Energy cost Specific energy constant 5 5 5 5 kWh/Nm3 Annual operational hours of grid 8.136 8.136 8.136 8.136 hours/year Installed power 0,3 0,65 2,425 4,85 MW Energy consumption 2.441 5.288 19.730 39.460 MWh Amount of hydrogen produced per year 43.886 95.085 354.742 709.484 Kg

Annual max number of passenger cars serviced 281 610 2.274 4.548 To construct hydrogen stations in the optimal order, the overall electric distribution system has to be investigated; what is the current use, the overall system capacity and can the high Voltage cables provide enough electricity to the ideal locations. Is the full capacity already in use or is there room for additional power transmission? The study only maps whether the areas’ electric grid networks can handle the required extra distribution or how it may be changed to fit the needed carrying capacity. The results from Reykjavik are presented in tables 5 and 6. In this case the grid has been built to deliver on peak demand (the 24th of Dec in the afternoon!) and is therefore ready to transport electricity to planned hydrogen stations in times of low demand, but the grid needs to be reinforced if the demand increases considerably. The maximum demand is measured at 77 A, but the grid is built to deliver 320 A. The unused capacity surplus is 178 A using 80% load. Table 11 Needed number and size of new transformers within Reykjavik’s grid system if hydrogen is produced on site near main transport routes.

Production capacity 60 130 485 970 Nm^3/h Current 433,0 938,2 3.500,2 7.000,4 A Transformers size 1 315 800 1250 1600 kVA 2 1250 1600 kVA 3 1250 kVA 4 500 kVA Max current obtained 455 1155 3608 7144 A

Establishing a hydrogen station in one location evidently draws energy from the whole system, and therefore shuts out the opportunity of building a second one in close vicinity of the first one. In all cases, medium to large electrolytic hydrogen stations proved to be

NyOrka 12/18/2008

the optimal choice, given that the number of hydrogen vehicles would grow 2015 from and replace 50% of gasoline vehicles by 2050.

4.2.4 Quantitative criteria In 2000 the annual world hydrogen production amounted to about 500 billion Nm3. Most of the hydrogen is made in centralized plants that typically produce 100.000 Nm3/h with steam reforming. The proportion is about 48% from natural gas, 30% from petroleum and 18% from coal. Hydrogen is used in industry and for that purpose distributed in selected regions in low pressure pipes from the place of formation to the users. More could be recuperated from industrial plants that currently burn off hydrogen that forms as a by-product in the process stream, but this type of hydrogen must meet relevant purity demands. Refer to In transport demonstrations 2001-2008 (ECTOS, CUTE, STEP, HyFLEET:CUTE26) decentralized stations produced hydrogen of the magnitude 50 – 100 Nm3/h and most upcoming electrolyses will be in the range of 100 – 1000 Nm3/h27. Hydrogen losses have been observed in production facilites. For hydrogen produced at on site stations from reformed gas the loss is detected in the pressure swing adsorption (PSA) unit, which is part of the steam-reformer system and in the electrolyser it is the deoxo-dryer unit. In the case of the PSA, the losses vary between 12,5 % and 22,5 %, depending on the hydrogen specification that is used, while the losses at the deoxo-dryer vary between 4 % and 6 %. Both losses and purity demands raise the unit price of hydrogen, but table 7 shows the recent composition of the cost of modules for electrolitic stations in three different sizes. Both criteria pose added cost on the hydrogen except if it can be used in fuel cells that can handle impurities and used to derive electricity close to its origins. Most relevant distribution of hydrogen made with renewable energy from water would be within an electric grid. Therefore the reinforcement of the grid may be inevitable but trucked in hydrogen may pose severe social opposition.

4.2.5 Where would the hydrogen come from? The cheapest method is to use excess hydrogen from large industrial gas plants and natural gas as a source for making hydrogen. This method can therefore be used for cost comparison and cost- optimisation. Secured supply is one of the important criteria in energy services that need to be addressed. Mature gas technology and direct applications as well as the small environmental gain from reforming gas to hydrogen discourages that pathway for long term hydrogen production but can give rise to further studies on cost development. Where would the hydrogen come from if Natural gas becomes less ideal? Ludwig Bölkow System Technik28 (LBST) published in 2005 a forecast stating that fossil fuel exploitation (including coal) would rapidly decrease after 2010, due to various 26 See further at www.global-hydrogen-bus-platform.com 27 Hydro Electrolysers Iain Alexander Russel, Pietro d’Erasmo; Hydro Elecrtolysers email 10th of Dec 2006 28 See further on www.LBST.de

NyOrka 12/18/2008

factors. As an alternative, LBST suggests to fill the gap for energy into Europe with imported biofuels and non-carbon energy from neighbouring countries.

North Africa:Solar powerWind power

Turkey:Biomass

Iceland:Geothermal powerHydro Power

Ukraine:Brown CoalHydro Power

Norway:Hydro Power

Bulgaria:Hydro Power BiomassGeothermal Power

Romania:BiomassHydro Power

Figure 11 Hydrogen or electricity by cable? Pathways for hydrogen import to Europe have been mapped by the ‘Encouraged’ project29.

4.2.6 Niche markets In 2006 there were 65 hydrogen fuelling stations listed as operational or planned in Europe30, mostly used to refuel buses. Hydrogen stations are foreseen to be introduced aligned with introduction of concentrated hydrogen fleets in certain communities. These would be the basic hubs that later connect and form hydrogen – regions such as is planned between Bergen, Norway, through the west coast of Sweden and across the Nordic Sea to Denmark31. Another niche market is backup–power storage for peak–load demand or buffering fluctuations between production and demand. Grid systems have limited capacity to accept fluctuating supply from production units such as wind mills. Hydrogen acts as an electricity storage that can deliver more power when the demand increases.

29 Encouraged EC project no 006588, Energy corridor Optimisation for European Markets of Gas Electricity and Hydrogen 6th FP. Coordinating organisation: Frauenhofer ISI, Martin Wietschel 30 www.h2stations.com 31 Hy-Nor project as presented at HyFLEET:CUTE general assembly, Reykjavik May 2008.

NyOrka 12/18/2008

Figure 12 The system setup in Ramea 32 Island economies or remote communities that suffer from high importation costs of fossil fuels may move faster towards hydrogen than other societies33 that have larger areas and abundant sources of biomass. Simultaneously, remote islands may have higher potential to utilise renewable sources that tend to accumulate with this geographical position, such as ocean energy, currents, wind and geothermal power. Orkney, north of Scotland considers to exploit strong currents and export hydrogen (rather than electricity via cables across protected nature reserves in Northern Scotland) when oil excavation decreases in the North Sea. In Germany preparations have been made to connect and coordinate wind farms and power distributors for testing hydrogen and fuel cells to buffer electricity onto the grid will start early 200734. A test project of this type was established in Utsira, Norway in 2005 and a continuously operating system was installed in the community Ramea in Newfoundland in 2004. Wind generated power had substituted about 10% of the energy demand by April 2008, saving the diesel oil that would have gone into the same thing. But the wind power and demand do not match. Therefore dump-loads will be used to generate hydrogen whereas the local grid installations do not accept the high peak production. This amounts up to 50% of the wind generated electricity on a constant basis. The Integrated system in Ramea is displayed in figure 12. Within the APEC (The Asian Pacific- Economic Cooperation), renewable energy and hydrogen is seen as entering first as a fuel for stationary CHP applications and later for

32 Jones, G: Wind-hydrogen diesil Energy Project at Ramea Newfoundland, presentation held at the North Atlantic Hydrogen Association conferenece, 25th of April 2008. 33 International seminar on the hydrogen economy for sustainable development; Geothermal Resources, current development and potentials www.un.org/esa/sustdev/sdissues/energy/op/hydrogen_seminar/hydrogen_seminar_programme.pdf 34 Holger Grubel, (personal communication, December 13 2006) Vattenfall power company , Germany

NyOrka 12/18/2008

transportation purposes, yet already before 202035 its market penetration is set at 5%, whereas China and India have already started their experimental use of hydrogen and fuel cells.

4.3 Cost of hydrogen production from two sources The most actual costs for hydrogen technology have been studied with real data derived from H2 bus demonstrations. Hydrogen vehicle operation in fleets will have spill-over effects to development of other sectors of society. The production stations are, undergoing their first field demonstrations and the figures can only give an indication of cost and efficiency, and therefore important as first points in a learning curve. Cited reports are deliverables from CUTE, HyFLEET:CUTE bus demonstration projects and the Icelandic SMART-H2 project. This section is presented as on overview of the current cost proportions and forecast for the production costs, when using real data (figs 13 – 17). Note it is based on the technology which is currently in use for hydrogen and is derived from small scale plants that fit transportation demonstrations. The most relevant parameters for the interpretation are:

• The actual systems used come from differnt manufacturers and have different boundary conditions such as production capacities. The production unit (PU) of all both steam-reformer system and the electrolyzer system produce 60 Nm³/h of hydrogen. Considering hydrogen losses that occur downstream of the production unit, the steam-reformer system yields a delivered quantity of 43.157 kg H2 /year, while the electrolyzer system delivers a quantity of 43.465 kg H2 / year.

• Of these produced quantities, 43.000 kg H2 /year (each system) are delivered to fuel cell buses, while the residual amount of hydrogen from the hydrogen filling station is considered as “overproduction” within the mass balance of the system.

• Initial costs for the steam-reformer based system amount to 1,75 Mio. € and to 1,74 Mio. € for the electrolyzer based system.

The total consumption of energy amounts to 5,7kWh/Nm³ H2 for both hydrogen producing systems. In the case of the steam-reformer, this includes 4,7 kWh/Nm³ H2

natural gas. The amount 5,7 kWh/Nm³ H2 also includes the energy consumption for the compression of the hydrogen up to 350 bar at 15 °C. Electric energy, which meets the entire energy demand of the electrolyzer based system and 1kWh/Nm³ H2 at the steamreformer system is assumed to be purchased for 0,10 €/kWh and natural gas is assumed to be purchased for 0,05 €/kWh. These prices are varied within one similation to show the price elasticity. The cost contributions would be composed within the hydrogen supply chain, the cost of monitoring the quality and purification. The presentation is derived with GaBi4 a software tool for Life Cycle Engineering. LCA costs of dismantling and externalities. The quality criteria were found to be relevant during the project CUTE project accounts for these in their current and future cost estimations36. 35 Minns David (editor) APEC2030 Integrated Roadmap Nov 2005: Future fuels for the APEC region 36 Faltenbacher Michael Wittstock TREN/05/FP6EN/ S07.52298/019991

NyOrka 12/18/2008

In Table 12 the cost of hydrogen from three different sizes of electrolytic station are shown. The water is set constant according to the footprint of the plant, as is the custom in Reykjavik, but after use with fuel-cells the water could be collected and reused in the same plant. Larger plants use proportionally less Nitrogen. The footprint of the plant does not need to grow linearly with the size of the station if pressure is increased for example from 1,5 MPa to 3MPa during the production phase. Within the CUTE project a cost contribution analysis was made using data from the ten hydrogen stations used in the demonstrations. The range of cost was quite broad and therefore figures 13 – 17 display three cost scenarios based on actual cost from different sites, where the process had the least and most cost as well as the average cost. Table 12 Cost composition of three sizes of electrolytic hydrogen stations based on costs of new equipment and operation costs as experienced during 5 years of operation in Reykjavik.37 The price is in Isk where 100Isk=1€

Figure 13 shows the overall hydrogen cost for 1kg H2 produced electrolyser (manufacture 2003) within the CUTE demonstration boundary conditions using the set cost for electricity at 10ct/kWh. The red lines shown indicate the average diesel cost for 1 kg hydrogen equivalent (120 MJ net cal) as of 30th of January 2006 with and without taxes. This is the normal reference point while studying bus fuel

Deliverable No. 1.5, Report on the findings regarding optimised hydrogen purity Mr. Bastian 1, Dr.-Ing. 2 37 Gudmundsdottir Lilja (2008): Analysis of the electric grid in Reykajvik, Greenland and Faroe Islands, MSc project at the University of Iceland, financed by the North Atlantic Hydrogen Association.

2.323.529 1.186.289 1.008.345Production capacity 130 485 970 Nm3/h

A, InvestmentElectrolyser 80.549.000 115.070.000 195.619.000Other equipment cost 161.098.000 345.210.000 586.857.000Installation and start-up cost 60.411.750 115.070.000 195.619.000

Total investment cost 302.058.750 575.350.000 978.095.000 krB, Energy Specific energy constant 5 5 5 kWh/Nm3Needed installed power 0,65 2,425 4,85 MW

C, Operation and maintenance costOperation and control cost per year 847.500 847.500 847.500Maintenance (material) per year 4.832.940 9.205.600 15.649.520Maintenance (staff) per year 6.000.000 12.000.000 15.000.000Water and nitrogen 2.400.000 4.800.000 8.400.000

Total operation cost 14.080.440 26.853.100 39.897.020 kr. Per year

NyOrka 12/18/2008

Figure 14 shows similar analysis for cost of 1kg compressed hydrogen produced by steam reforming within the CUTE boundary conditions (7 kWh natural gas per Nm3 hydrogen produced) see also Table 13. Costs for natural gas are set as 5ct/ kWh and electricity of 10 ct/ kWh. The upper red line indicates the cost within the CUTE demonstration boundary conditions which have been used as if the on site steam reformer was to be operated at full load (4,7 kWh natural gas per Nm3 hydrogen produced). The non operational cost proportional to total costs for steam reforming is greater than 50% in all scenarios. They are therefore important when performing an economic analysis of on-site hydrogen production. The cost for electricity does not influence the overall share of the non operational cost significantly. This is based on the fact that the ratio for the actual CUTE consumption figures the ratio of the gas to electricity consumption is 7:1.

Electricity costs: 10 ct per kWh

0 €

2 €

4 €

6 €

8 €

10 €

12 €

14 €

16 €

18 €

20 €

min average max

€ pe

r kg

hyd

roge

n

Site preparation Investment Electrolyser, compressor, dispenser

Investment storage Maintenance infrastructureoperation

~ 3,4 €~ 1,7 €

Diesel 120 MJ

w/o tax

incl. tax

Figure 13 Measured cost of Equipment, site preparation, investment and operation cost (2005) for electrolyser per kg hydrogen; electricity cost = 10 ct/ kWh; Nitrogen cost = 0,5 €/ Nm338

38 Wittstock Bastian, Michael Faltenbacher; 2007, del 1.5: Report on the findings regarding optimised hydrogen purity. EC funded project: HyFLEET:CUTE, contract no 2/161. TREN/05/FP6EN/ S07.52298/019991

NyOrka 12/18/2008

0 €

2 €

4 €

6 €

8 €

10 €

12 €

14 €

16 €

18 €

20 €

min average max

€ pe

r kg

hyd

roge

nSite preparation Investment Electrolyser, compressor, dispenser


4,7 kWh gas/ Nm3 H2

- full load -

4,7 kWh gas/ Nm3 H2

- full load -

4,7 kWh gas/ Nm3 H2

- full load -

~ 3,4 €~ 1,7 €

Diesel 120 MJ

w/o tax

incl. tax

Figure 14 Measured cost of equipment, site preparation, investment and operation cost (2005) for a steam reformer per kg hydrogen – electricity cost = 10 ct/ kWh; natural gas cost = 5 ct/ kWh; nitrogen cost = 0,5 €/ Nm3 . As mentioned, the criteria for purity of the hydrogen used with different types of fuel cells may add cost. Direct cost effects are, for instance, increased costs of monitoring- devices or increased costs for external analyses. Indirect cost effects are reduced production quantities for a tighter specification. The effects are shown on Figure 1539.

Figure 15 Cost burden from hydrogen purfication criteria

39 HyFLEET:CUTE, Del no 1.5 Wittstock Bastian and Michael Faltenbacher: Reporting on the findings regarding optimised hydrogen purity Nov 2007

NyOrka 12/18/2008

4.4 Future scenarios – cost comparison Referring to the policy chapter and European alternative fuels policy then hydrogen should constitute 2% of the fuel market by 2015 (and 3% by 2020). 170 hydrogen plants each with 10 times greater capacity of most current stations or 600Nm3 are needed to feed about 12500 hydrogen buses into this scenario, according to given parameters in the character of buses40. Still the NEEDS project does not account for transport energy, the stationary fuel cells would mostly run on less pure feed stock. As shown in section 4.3 the cost of hydrogen production depends to a high extent on the rate of the needed feedstock, natural gas for reformation or price of electricity and water availability for electrolysis. (Water can be collected from vehicles and reused). The production quality fluctuates somewhat between these two production methods but PEM fuel cells are a more likely candidate to be used with hydrogen that is made from dump-load power from fluctuating RE (grid) systems whereas they are more flexible in operation. When setting the price of electricity at 0,10€ as the mean cost of electricity from RE as suggested in a recent report made for the European renewable energy council41, a cost calculation can be presented as which production technology is preferable in fluctuating power settings. No increase in life time has been incorporated in the hydrogen production stations but an expected learning curve decrease of cost (similar to the foreseen cost reduction as are presented in the Hy-Ways European Hydrogen Road map p15) has been incorporated as these 170 sites are inaugurated as well as 375.000€ for site preparation in each case and similar costs for storage for the two types of hydrogen production. When comparing the hydrogen production costs calculated in this study with cost numbers provided by other studies it is essential to carefully consider the boundary conditions that have been applied. These figures relate to actual measured data with running first generation equipment and the parameters for future forecasting are also restricted to specific boundaries. Note that while using eventually electricity that is dumped from renewable generation the price of electricity may be set less than 10€c. Table 13 shows the boundary conditions on which the calculations for on-site hydrogen production stations are based and refer to CUTE project conditions as presented by Marc Binder and Michael Faltenbacher42. The relevant economic parameters are shown in Table 14.

40 These assuptions are listed in deliverable 6 page 26 41 EREC (European renewable energy council) 2006: Renewable (r)evoltution; a sustainable oecd europe energy p. 29 42 Binder Marc and Michael Faltenbacher ; Economic Analysis of the hydrogen infrastructure , Clean Transport for Europe, deliverable 6. EC funded project no NNE5-2000-113

NyOrka 12/18/2008

Table 13 Boundary conditions for electrolyser and steam reformer set for comparison of production cost of hydrogen.

Electrolyzer Steam Reformer

Time of operation 20 years 20 years

electricity [kWh/ Nm3]CUTE ∅: 5,8 [kWh/ Nm3]

Future scenario: 5,5 [kWh/ Nm3]CUTE ∅: 1,0 [kWh/ Nm3]

Future scenario: 0,6 [kWh/ Nm3]

natural gas [kWh/ Nm3] -----CUTE ∅: 7,0 [kWh/ Nm3]

CUTE (full load): 4,7 [kWh/ Nm3]Future scenario: 4,2 [kWh/ Nm3]

nitrogen [Nm3/ Nm3] 0,015 [Nm3/ Nm3] 0,12 [Nm3/ Nm3]

average utilization [capacity] 95% 95%

down days per year 10 days 10 days

Maintenance

Reformer modul ----- once during lifetime

Electrolyser modul once during lifetime -----

Mol Sieve once during lifetime once during lifetime

Catalyst of reformer module ----- every 5 years

Activated carbon ----- depends on sulphur content

Deoxo catalyst every 3 years -----

Compressorservice intervals between 4 month (min) to 2 years (max), dependend on

compressor type and input pressure

Usage (total filling station)

replacement

Table 14 Parameters that are used to scale up future cost reduction potentials

Parameter name description Electrolyser Steam ReformerIRR [% pa] Internal rate of return 12 12

P [ ] Factor of cost decrease - learning curve 0,9 0,96-tenth factor upscaling 0,7 0,6use_time [a] Utilization period 20 20use_ratio [%] Utilization ratio 95 95Downdays [d] Down time in days per year 10 10

Figure 16 three areas represent the cost of hydrogen production correlated with a range of cost for natural gas.

1) Blue area: When costs of gas is in the range of 0,035 and 0,103€/kWh then steam reformation would be less costly than electrolysis where electricity price is set at 0.1€/kWh

All steam reforming scenarios (min, average and max indicated by three red horizontal lines) are less cost- intensive compared with the respective electrolyser min scenarios.

2) Cyan area: When cost of gas is in the range of 0,103 and 0,127€ the cost of hydrogen production depends on equipment, maintenance and preparation cost, which can vary between sites and manufacturers:

Within this range the overall equipment, maintenance and preparation costs are decisive in determining the preferable hydrogen production technology.

3) Yellow area: If price of gas is above 0,130€ then electrolysis is cheaper

NyOrka 12/18/2008

All steam reforming cost scenarios (min, average and max) are more cost intensive compared with the respective electrolyser max scenarios.

Results for 0,1 € per kWh electricity

0

2

4

6

8

10

12

14

0,03

5

0,04

5

0,05

5

0,06

5

0,07

5

0,08

5

0,09

5

0,10

5

0,11

5

0,12

5

0,13

5

0,14

5

0,15

5

0,16

5

€ per kWh natural gas

€ pr

o kg

hyd

roge

n

Electrolyzer min Electrolyzer average Electrolyzer max

Steam Reformer min Steam Reformer average Steam Reformer max

pro electrolyzerprosteam reformer

dependent on overall equipment, maintenance and preparation costs

SR minSR max

Elec minElec max

Figure 16 Future scenario: Reformer – Electrolyser; cost for electricity set at 0,10 € per kWh

When the cost for electricity and natural gas is within this range, a detailed analysis of the non operational cost is necessary to determine the preferable technology. The price of natural gas has slowly been rising since 1975 but peaked in October 2005. Also to be noted: competitiveness would if course also be skewed by diesel prices, such as were to be found in 2008.

4.5 Price trends in future Other influential costs for the production are material costs of stainless steel (with Nickel and Chromium being the key alloying elements) and copper, and to a reduced extend also aluminium. Purification costs and quality monitoring of hydrogen made with either method should not be neglected. These may amount to 12-13% of the production costs using either steam reformation or electrolysis. Hydrogen infrastructure equipment will become more costly with higher energy prices. The energy conversion cannot be improved very much for the low temperature electrolysers. The conversion efficiency of today’s electrolysers is already high and therefore basic research should address areas where a significant cost reduction in hydrogen costs can be achieved. The only way to reduce the energy consumption further would be to increase the process temperature (e.g. to 800° C). This, so called high temperature electrolyser, has great energy savings but substantial material challenges. Adding pressure only keeps the volume of the generated hydrogen down and would save space and therefore land use.

NyOrka 12/18/2008

The following areas or topics should therefore be considered:

• Increasing efficiency and stability of electrodes for alkaline electrolysers to obtain increased current density and possibly reduce cell voltage throughout. The water molecule can be split at 1,23 volts at the ideal high heat conditions instead of 1,48volts in the current lye electrolysis.

o Catalyst research, with the aim of reducing the use of precious material. o Electrode design – zero gap and porosity of electrode with effective transport

of gas from the electrode, • Synthetic materials research to increase durability and lifetime, particularly if high

heat is used to substitute for a part of the electricity. • Diaphragm material research to achieve synthetic materials with low resistance and

high threshold pressure

Electricity costs: 10 ct per kWh

0 €

2 €

4 €

6 €

8 €

10 €

12 €

14 €

16 €

18 €

min average max

€ pe

r kg

hyd

roge

n

Site preparation Investment Electrolyzer, compressor, dispenser


CUTE ∅ status quo

CUTE ∅ status quo

CUTE ∅ status quo

Figure 17 Composition of cost factors using projected learning effect but based on current yet upscaled technology. Electrolyser scenario 600 Nm3/h and 170 plants; cost per kg hydrogen - electricity cost = 10 ct/ kWh; nitrogen cost = 0,5 €/ Nm3

NyOrka 12/18/2008

0 €

2 €

4 €

6 €

8 €

10 €

12 €

14 €

16 €

18 €

min average max

€ pe

r kg

hyd

roge

n

Site preparation Investment Reformer, compressor, dispenser


CUTE ∅ status quo

CUTE ∅ status quo

CUTE ∅ status quo

Figure 18 Steam Reformer scenario 600 Nm3/h and 170 plants; cost per kg hydrogen. Electricity cost = 10 ct/ kWh; natural gas cost = 5 ct/ kWh; N2 cost = 0,5 €/ Nm3, all using fore

The cost comparison made within the CUTE /HyFLEET:CUTE project indicates that non-operational cost are likely to decrease in the future. This is due to decreased cost of the other than operational cost as a result of up-scaling and learning curve effects and decrease of operational cost resulting from an increase of energy efficiency in the future. On the other hand, if the electricity that is used to operate the electrolysis is rather rescued or “dumped pðewer” rather than bought, the price may become even lower.

4.5.1 The potential role of hydrogen in a future energy supply system In January 2007 the project Encouraged43 published its results from looking into the potential import of gas, hydrogen and electricity to Europe. The report builds on the Hy-Ways scenarios for hydrogen which are still in formulation. The forecast outlines two alternative market development scenarios – High (corresponding to ‘Very optimistic scenario’) and Low (‘realistically optimistic scenario’) until 2050. The most pessimistic scenario would then be the one which is foreseen in the EU Energy trends policy paper (2003): European Energy Outlook and Transport – Trends to 2030, which states that oil products keep their market share at least until 2030. Hydrogen is neither mentioned for use in stationary CHP application nor as fuel for transport44. According to the pessimistic scenario the penetration would be 0 by 2030. A different scenario was presented from the Hy-Ways project, s European Hydrogen Roadmap45 as shown in Table 15

43 Energy corridor optimisation for European Markets of Gas, Electricity and Hydrogen (ENCOURAGED, project no: 006588, 6th Framework Program, Scientific Support Policy (3.2). Project manager Martin Wietschel, Frauenhofer ISI 44 European Commission Directorate-General for Energy and Transport, 2003: European energy and transport trends to 2030. Prepared by National Technical University of Athens, E3Mlab 45 Hy-Ways, European Hydrogen Roadmap available at: www.HyWays.de

NyOrka 12/18/2008

Table 15 Total share of hydrogen vehicles according to the Hy-Ways scenarios; Pessimistic – very optimistic scenario. A Realistically optimistic would set hydrogen penetration at 2% of the vehicle fleet by 2020 and up to 50% in 2050.

Table 16 indicates the market share scenarios of stationary applications from the Hy-ways project, the penetration is almost negligible until 2050. Table 16 Market share scenarios of stationary applications presented in the European hydrogen road map Total (%) share in residential sector

2010 2020 2030 2040 2050

High penetration - > 1 4 8 10 Low penetration - 0,1 0,5 2 5 Total share in commercial sector

2010 2020 2030 2040 2050

High penetration - 0,3 1,3 2,7 3,3 Low penetration - - 0,2 0,7 1,7 The ‘HyWays Low penetration scenario’ envisions only 5% of all households are assumed to have a 1 kWe system installed. In northern countries, micro-CHP is assumed to be mainly used for space heating where district heating has not been installed, but in southern countries more for cooling. In addition the total hydrogen-based CHP installed in the tertiary sector (i.e. offices) is assumed to be 30% of the total power in the residential sector. Intermediate values for 2020, 2030 and 2040 are derived through (non-linear) interpolation. It is worth noting, that system design which is currently in development for example in Europe, USA and Japan (Figure 19) it may be unrealistic to separate between hydrogen and stationary and transportation applications. A systematic approach could raise total energy chain efficiency. The one in figure 16 is composed of electrolysis, heat management and fuel cells. Hydrogen is made with off peak electricity, either from the grid or local renewable installations. Heat goes to temperate a well insulated office building and the hydrogen to power its equipment and fill staff vehicles. If Hydrogen is produced on distributed sites, the fuel would both be used in the building and to fill vehicles of the company or the staff that works in the area, but the demand may be saturation.

Total share of car fleet [%] 2010* 2020 2030 2040 2050

High <0,3 1% 3,3% 23,7% 54,4% 74,5% Low - 0,7% 7,6% 22,6% 40%

NyOrka 12/18/2008

4.5.2 Integrated systems The efficiency of an energy chain that starts with renewable energy and ends with hydrogen for use in various applications may never be able to compete with the infrastructure and well to tank efficiency provided in the carbon era. Yet the source for renewable energy is said endless and the water becomes recyclable. The efficiency criteria do not prevent the use of the unlimited sources. Some of the most advanced studies in integrated, diversified and flexible systems are currently undertaken in Japan where research has been looking into raising efficiency in integrated systems not only in separate components. The cleanliness and the flexibility of using hydrogen is considered a driver because of added customer value and new opportunities for the Japanese industry46.

Figure 19 A hydrogen test system that is intended to monitor and raise total energy efficiency.

5 Technology development perspectives Hydrogen storage and transportation, system efficiency as well as material development are the most important points for hydrogen technology development. The electrolysers will go through high pressure to high heat and pressure electrolysers but in the far future electrolysers are foreseen to merge with fuel cells. Transportation of hydrogen is bound to be ineffective in small amounts, especially in the gaseous phase. Liquefaction decreases efficiency by 10 – 15%. Transferring electricity is likely to interact with distribution of hydrogen and vice versa. Kozawa et al have

46 OKAMOTO Hideyuki, Yoshiaki KAWAKAMIP, Yoshiyuki KOZAWA, Makoto AKAIP P Total Energy System Engineering by Coring Metal Hydride Tanks

NyOrka 12/18/2008

proposed that even though the contemporary fuel cells only display 50% conversion efficiency this can be optimized through other system components. If the surface area and thickness of a reversible PEM stack is adjusted, counter current flow of the oxygen and hydrogen implemented and specific design deployed to keep the humidity at around 60% (plus the heat which is released is put to full use), then the efficiency of the whole system could reach 80% in the full cycle (electricity – hydrogen – electricity and heat)47. Those figures give a real competitive edge against current thermal power systems. PEM electrolysers Hydrogen storage has been under securitization for several decades. The US Department of Energy has set the target for 6.5% hydrogen weight of the storage medium. Sodium- Borohydrides (NaBH4) (recyclable solid hydrogen carrier48), metal hydride mixtures, carbon mircrofibres, glass microstructures, salt-pellets soaked with ammonia, liquefaction and even soap solutions have been reported as possible storing agents49,50. Currently high pressure tanks made from steel and strengthened with carbon-fiber coatings have evolved most rapidly and are used by most car manufacturers. Hydrogen distribution has been foreseen by trucking in for small markets, (pressurized) gas pipe systems for lager market51 or liquefaction and transportation in barge ships over larger distances. These keep the hydrogen in enormous spheres that can be kept in dock while the hydrogen flow is connected to a land based piping system. Synthetic materials together with high pressure applied in the cell stacks on electrolysers, prove to be more capable of handling fluctuations in power input and are therefore especially suitable in combination with renewable energy sources. These types of electrolysers have become available in the market during the last decade, but mainly for small capacities. The future challenge for these materials will be to cope with higher pressure and larger capacity electrolysers. The PEM electrolyser was introduced to the market recently, but only for small capacities (Proton’s cell stack is currently max. 2 Nm3/h). The energy consumption is high and the lifetime of the cell stack or MEA (Membrane Electrode Assembly) is a challenge. For large units the KOH or alkaline electrolysis under 30atm pressure is still seen as the most efficient solution. Whereas data is available for the inventory of the Norsk Hydro electrolyser, that type has been selected as a representative in the detailed study. It is said to have the highest energy efficiency including compression. The future NH types of electrolysers will be used as an

47 Kosawa Yoshiyuki 2004: Pioneering of Genral purpose uses of hydrogen as a possible energy carrier in the future, Energy and resources, 25. no 5. 48 Millienium cell gives a description of NaBH4 characteristics www.millenniumcell.com/fw/main/Hydrogen_as_Fuel-30.html 49 A good overview is given by Fuel cell store refer to: http://fuelcellstore.com/information/hydrogen_storage.html 50Korean researches reported to Nature November 2005 51 Yang, Christopher and Joan Ogden 2006 Determining the lowest cost H2 delivery mode article pending to be publised in the international journal of hydrogen energy.

NyOrka 12/18/2008

example of the trends but comments have been sought from developmental experts in order to ground the realistic possibilities. This is the essence of the hydrogen handling chain; it is likely to be produced locally from various sources, transported minimally unless it is generated as a by-product in industry or produced centrally from gas or other carbon sources where the carbon dioxide can be sequestrated as well. All extra handling poses extra costs because of the low energy density pr volume hydrogen. Large electrolytic centers will therefore be connected to nuclear power stations and gasification, but smaller units, even local (home, office buildings, and community centers) power stations may be coupled to off grid renewable energy conversion equipment. As of yet, the hydrogen technology is in rapid development and therefore investments in large systems has not occurred; investors are waiting for more mature components. Price for petrol and decreased cost of an entire new infrastructure must give added value to the investors and the public before major changes will occur. The bio-fuel chain still has a stronger stand on the world market as a newcomer in the environmental technology sector.

Usually electricity is the only source of energy used in electrolysis. But the process is exothermic. It has been shown that the electrical energy can at least partially be replaced by heat.52 Research is ongoing on high heat electrolysis, but when electrolysis is carried out in temperatures above 700°C 10 – 20% of the electricity can be saved. Currently the cost and efficiency of electrolysis is not competitive to using steam reforming from carbon containing fuel. A reversible fuel cell /electrolyser has been demonstrated as an experimental unit.

6 Specification of future technology configurations Table 17 Hydrogen production technology datasheet: Electrolysis53

ELECTROLYSIS (30 BAR OUT) 2020 Unit Specific hydrogen capacity (out) 2.500 kW(H2) Specific investment cost 500 €/kW Total investment 1.250.000 € Annual operating hours 8.000 h/a Lifetime 20 a Annual hydrogen production 20.000.000 kWh(H2)/a Operation and Maintenance 1,5 % of investment Annual Operation and maintenance 100.000 €/a Annuity 127.315 €/a Total annual cost 146.065 €/a Efficiency (electricity-hydrogen) 70 %

Input electricity 1,4286 kWh(El.)/kWh(H2)

Output hydrogen 1 kWh

52 Mansilla1 Christine, Jon Sigurvinsson1, André Bontemps, Alain Maréchal, François Werkoff: Heat management for hydrogen production by high temperature steam electrolysis, CEA, 2005 53 HySociety, 2003, Basic table of carriers and barriers, edited and updated by FhG-ISI, 2005 and Icelandic New Energy 2006

NyOrka 12/18/2008

7 Conclusions The first 8 years of this millennium have provided evidence that new energy carriers are essential to substitute the fossil fuel supply chain that mankind has depended on for 150 years. Several millennia before that time all economy used solar energy and its derived forces. Eventually all direct forms of solar power will substitute the energy that had been trapped by photosynthesis and geological pressure into energy rich carbon compounds. When this era arrives, hydrogen will be used as the most flexible energy vector. In the meantime technological advancements need to raise energy efficiency along the delivery chain but the environmental effectiveness to deliver power without environmental damage is inherent in hydrogen as long as it is correctly handled.

NyOrka 12/18/2008

8 References Andreas Hofer Hochdrucktechnik GmbH 2006: Diaphragm Compressors – Models. www.andreas-hofer.de/english/htm/produkte/kompressoren_membran2.htm

EC 2003, High level group to the commission: Hydrogen and fuel cells a vision of our future

EC Directorate-General for Energy and Transport, 2003: European energy and transport trends to 2030. Prepared by National Technical University of Athens, E3Mlab

EC funded project HY-FLEET:CUTE See further at www.global-hydrogen-bus-platform.com

EC funded project: Euro Hyport, Ingolfsson Hjalti P.; Feasibility study for the export of hydrogen from Iceland to the European continent, 2003 WP2 hydrogen Production and WP3 Transport of hydrogen

EC funded project: Hy-Approval, handbook of hydrogen stations is still a living document, whereas the content has not been approved in all European states www.hyapproval.org/publications.html EC funded project: HyFLEET:CUTE European project no:

EC funded project: HySociety, 2003, Basic matrix of social carriers and barriers in the integration of hydrogen; Matrix edited and updated by FhG-ISI, 2005 and Icelandic New Energy 2006

EC funded project: HyWays – a hydrogen road map for Europe: www.HyWays.de

EC supported project no: 006588, 6th FP: ENCOURAGED, Scientific Support Policy Project manager Martin Wietschel, Frauenhofer ISI

EC supported project: Clean Transport for Europe CUTE; Faltenbacher Michael, PE International 2006, report on LCA of hydrogen production within CUTE cities, status of report is confined to partners.

EC supported project: CUTE, NNE5-2000-113, Clean Transport for Europe, Binder, Marc and Michael Faltenbacher; 2007 Economic Analysis of the hydrogen infrastructure, deliverable 6.

EC: Hydrogen Energy and Fuel Cells, a vision of our future, final report of the high level group, p 12. Directorate-General for Energy and Transport. EUR 20719

Encyclopaedia Britannica www.britannica.com

NyOrka 12/18/2008

EREC (European renewable energy council) 2006: Renewable (r)evoltution; a sustainable OECD Europe energy p. 29 A report compiled by Greenpeace for the council.

EurActiv EU news, policy positions and EU Actors online; 9th of March www.euractiv.com/Article?tcmuri=tcm:29-153252-16&type=News

European news, www.euractiv.com/Article?tcmuri=tcm:29-153252-16&type=News

Fuel cell store; Overview for hydrogen storage options is given by: http://fuelcellstore.com

Gudmundsdottir Lilja (2008): Analysis of the electric grid in Reykajvik, Greenland and Faroe Islands, MSc project at the University of Iceland, financed by the North Atlantic Hydrogen Association.

Hy-Nor: Nordic hydrogen highway connecting 3 countries. Ulfs Hafseld: presentation at the North Atlantic Hydrogen Association, Reykjavik May 2008.

IEA and OECD: Prospects for hydrogen and fuel cells 2005. The table is stated to be compiled from Prince-Richards S(2004) a Techno-Economic Analysis of Decentralized Hydrogen productin. University of Victory Canada and Stuart 2005 Vanderborre IMET technology characteristics, Stuart energy, www.stuartenergy.com

Jones, G: Wind-hydrogen diesel Energy Project at Ramea Newfoundland, presentation held at the North Atlantic Hydrogen Association conference, 25th of April 2008.

Kauffman Matthew, US department of Energy, presentation during US Electrolysis, 2003, Workshop proceedings from Electrolysis production of hydrogen from wind and hydropower, Washington DC. Sept 2003

Kerry-Ann (2007) Fuel Cell Today Large Stationary Survey Fuel Cell Today; www.fuelcelltoday.com/

Kosawa Yoshiyuki 2004: Pioneering of Genral purpose uses of hydrogen as a possible energy carrier in the future, Energy and resources, 25. no 5.

LBST: Physical and chemical characteristics of hydrogen and conversion factors or ‘Efnis og eðliseiginleikar vetnis’ 2003, Icelandic New Energy: www.newenergy.is/publications.

Ludwig Bölkow System, Hydrogen and renewable energy, report available at: www.LBST.de Mailänder, Ellen 2003: Life Cycle Assessment (LCA) of Hydrogen Infrastructure for Fuel Cell Driven Buses in the Public Transport of Reykjavik. Studiengang Umweltschutztechnik, University of Stuttgart.

NyOrka 12/18/2008

Mansilla1 Christine, Jon Sigurvinsson1, André Bontemps, Alain Maréchal, François Werkoff: Heat management for hydrogen production by high temperature steam electrolysis, CEA, 2005

Millienium cell: NaBH4 characteristics www.millenniumcell.com/fw/main/

Minns David (editor) APEC 2030 Integrated Roadmap Nov 2005: Future fuels for the Asian Pacific Economic Cooperation region

Nature, November 2005 Short News, Korean researches Norsk Hydro Electrolysers AS 2006: Appendix A: ECTOS Fuelling Station Description, Norsk Hydro Electrolysers AS 2006: Products – Hydrogen Filling Stations. www.electrolyzers.com. Norsk Hydro Electrolysers AS 2006: Technical Drawings, Hydrogen Filling Station 60 Nm3 H2/h for Iceland.

Norsk Hydro; Hydro Electrolysers www.electrolysers.com

Okamodo Hideyuki, Y Kawakam ip, Y Kozawa, M Akai, Integrated hydrogen modules Total Energy System Engineering by Coring Metal Hydride Tanks Ballard, (March 2006) as presented by Geoff Budd; for CUTE, Scope of Supply, Utility Requirements, Performance Data. TREN/05//FP&EN/S0755298/019991 deliverable 1.5 to be issued for the public in 2009, , Vancouver Canada

Ulleberg, Oystein, Susan Schoenung, Maria Maack, Bengt Ridell et al, World Hydrogen Energy Conference, WHEC, Conference paper 2007

Ulleberg Oystein, 2008 IFE, Norway for IEA, Hydrogen Implementation Agreement, annex 18; Integrated hydrogen systems, subtask B, simulations of hydrogen systems, www.iea.org / hia

UNDP and DESA; International seminar on the hydrogen economy for sustainable development; Geothermal Resources, current development and potentials www.un.org/esa/sustdev/sdissues/energy/op/hydrogen_seminar/hydrogen_seminar_programme.pdf

UNEP and DESA and Icelandic Ministry for Industry and Commerce: 29th Sept 2006 International seminar on the hydrogen economy for sustainable development; Geothermal Resources, hydrogen seminar/programme.pdf

Watson Jim (ed) et al; UK Hydrogen Futures to 2050 Tyndall Centre; Tyndall Centre Working paper no 46, Feb 2004

Winter, Carl-Jochen & Joachim Nitsch, eds 1988; Hydrogen as an energy carrier, technologies, systems, economy (translation from: Wasserstoff als Energieträger) Springer Verlag, Berlin, New York.

NyOrka 12/18/2008

Wittstock Bastian, Michael Faltenbacher; 2007, del 1.5: Report on the findings regarding optimised hydrogen purity. EC funded project: HyFLEET:CUTE, contract no 2/161. TREN/05/FP6EN/ S07.52298/019991

Yang, Christopher and Joan Ogden 2006 Determining the lowest cost H2 delivery mode article pending to be publised in the international journal of hydrogen energy.

Personal communication Chr. Machens, Hydrogenics, Germany, Christoffer Kloed, Hydro-Statoil April 2008 Geoff Budd, Ballard, Vancouver Canada (March 2006) Hjalti P. Ingolfsson, Icelandic Hydrogen Holger Grubel, Vattenfall power company Germany (December 13 2006) Iain Alexander Russel, Hydro Elecrtolysers personal communication, 10th of Dec 2006 Jon Björn Skulason, Icelandic New Energy Monika Kentzler, Daimler, Germany Pietro d’Erasmo; Hydro Elecrtolysers email 10th of Dec 2006 Rouvroy , Steven Shell Hydrogen, HyFLEET:CUTE meeting, May 2008 Scott Staily, Ford Motor Corporations, division of fuel cell development , April 25th in Reykjavik

9 Annex Table 4.1: Minimum air pollutant list of the reference plants

Parameter Path Unit

Present Electrolytic H2 Production

kg GH2 Ammonia air kg 4,97E-04 Arsenic air kg 1,76E-06 Benzene air kg 1,67E-04 Benzo(a)pyrene air kg 7,69E-07 Cadmium air kg 3,65E-07 Carbon dioxide, fossil air kg 2,84E+01 Carbon monoxide, fossil air kg 1,36E-02 Carbon-14 air kBq 9,62E-01 Chromium air kg 8,14E-05 Chromium VI air kg 2,00E-06 Dinitrogen monoxide air kg 7,17E-04 Formaldehyde air kg 4,77E-05 Iodine-129 air kBq 9,77E-04 Lead air kg 4,12E-03 Methane, fossil air kg 4,53E-02 Mercury air kg 9,86E-07 Nickel air kg 1,95E-05

NyOrka 12/18/2008

Nitrogen oxides air kg 5,19E-02 NMVOC air kg 4,82E-03 PAH air kg 1,69E-06 PM2.5 air kg 7,82E-03 PM10 air kg 1,05E-02 PCDD/F (measured as I-TEQ) air kg 3,96E-12 Radon-222 air kBq 1,70E+04 Sulfur dioxide air kg 1,17E-01

Generation, of the energy carrier HYDROGEN In context with ... D8.2 Final report on... · Figure 9...

Documents

Transcript of Generation, of the energy carrier HYDROGEN In context with ... D8.2 Final report on... · Figure 9...