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HYDROGEN ENERGY

by Reinhold Wurster and Dr. Werner Zittel, Ludwig-Bölkow-Systemtechnik GmbH, Ottobrunn, Germany

Published at the Workshop on Energy technologies to reduce CO2 emissions in Europe: prospects, competition, synergy, Energieonderzoek Centrum Nederland ECN, Petten, April 11-12, 1994

Table of Contents

ABSTRACT

A description of the technologies for hydrogen production, conditioning, storage, handling, transport, and for the application in possible transport, domestic, industrial and other uses is given.

The current state of application of hydrogen technologies is depicted and their potentials for development are estimated.

From this information base and on the basis of ongoing R & D activities in the field of hydrogen technologies, the foreseeable possible state of the art for the year 2020 is derived.

The technical potential of hydrogen technologies in all fields of application is developed for the target year 2050 and the penetration of the energy economy is anticipated.

Causes which affect, impede or support the large-scale applications of hydrogen technologies are addressed. Strategic considerations on hydrogen and its future are given.

1. INTRODUCTION

Hydrogen is presently used in the energy sector only in industrial applications. The hydrogen originates almost completely from chemical processes as by-product or as industrial raw material.

When hydrogen is produced as a commercial product, then its usually generated via steam reforming of natural gas, via partial oxidation of oil or via electrolysis of water. Hydrogen is then either an intermediate product, as in the case of ammonia synthesis, or it is an auxiliary agent as in the cases of float glass production, metallurgy, fat hardening, chemicals production, semiconductor industry or generator cooling. One of the few cases where hydrogen is used as a commercial product presently, is the sector of space applications where hydrogen serves as liquid propulsion fuel.

Since several years, hydrogen is discussed as as a component of an electricity-hydrogen energy system, as clean energy carrier and fuel. Mainly due to cost reasons, partly also due to the not yet sufficiently advanced state of infrastructural development, hydrogen has not yet found its way into wider spread energy applications. During the most recent years, several hydrogen demonstration projects have been implemented or initiated worldwide (Solar-Hydrogen-Bavaria/ SWB, Euro-Québec Hydro-Hydrogen Pilot Project/ EQHHPP, World Energy Network Using Hydrogen/ WE-NET). On the other hand, environmental constraints subsequently have led to or spurred discussion on legislatory activities in order to reduce emissions related to fossil energy use (US Clean Air Act/ Californian ULEV and ZERO emission legislation, planned EC energy and CO2tax). Many specialists see chances for hydrogen applications to emerge in niches such as vehicle applications in polluted metropolitan areas.

2. DESCRIPTION OF HYDROGEN TECHNOLOGIES

Departing from present hydrogen usage, mainly as feedstock for the chemical industry and as liquid fuel (LH2) for space application, hydrogen is gradually on its way to develop to a secondary energy carrier. Thus hydrogen might become a means for energy storage and a medium of energy transport in a possible electricity/ hydrogen energy system. For this purpose it has to be provided on a large-scale and for some time to come electrolytically.

Presently, almost all commercial hydrogen is produced from fossil sources. If hydrogen is produced electrolytically then hydro-electricity is today's source of energy. An overview on hydrogen production and consumption provides table 1 for the cases 'worldwide' and 'Germany'.

Remark: The status and development of currently employed commercial hydrogen technologies is documented in the data sheets of chapter 9. If data given for 2020 or 2050 are identical with 1994 data, no realistic forecasts were available or speculations should be avoided.

2.1 Hydrogen Production and Conditioning Technologies

The presently used concepts for hydrogen production on a commercial basis are steam reforming of natural gas, partial oxidation of oil products and electrolysis of water.

Potential other ways to produce hydrogen are biogenic production, thermolysis and pyrolysis. Out of these, at medium term, pyrolysis of biomass or also water vapour reforming of biomass seem to have good perspectives in an energy economy abating CO2 emissions, besides water electrolysis operated by non-fossil electricity. Hydrogen can be produced from natural gas via steam reforming and CO2 emissions can be postponed or avoided by extracting the CO2 and injecting it into emptied gas field under pressure.

Furthermore, hydrogen can be produced very efficiently from natural gas and electricity completely free of CO2 by production of carbon black as marketable product via the Kværner process.

Table 1: Sectors of Production and Use of Hydrogen

Abstract

1. Introduction

2. Description of Hydrogen Technologies

3. Current State of Application of Hydrogen Technologies

4. Expected State of the Art in Western Europe by the Year 2020

5. Estimated Technical Potential in Western Europe for the Target Year 2050

6. Remarks on Market Implementation, Public Acceptance, Policy Implications, R&D Priorities, Costs, Barriers, Disclaimers, etc.

7. Literature

8. List of Most Important Abbreviations

9. Parametric Data Sheets for Selected Hydrogen Technologies

Sectors of Production and Use Germany World

[109 Nm3/ yr]

Status: 1986 / Source: Ad-hoc-Auschuß beim BMFT, Solare Wasserstoffwirtschaft, Bonn, 1988

In order to use gaseous hydrogen in the marketplace, hydrogen has to be conditioned, i.e. transformed into a transportable a/o storable form. For hydrogen transport in gas pipelines it has to be compressed or ad-mixed to natural gas. For long distance transport in smaller quantities the most practical as well as economic way is to transport hydrogen in liquid form at cryogenic temperatures. If hydrogen shall be stored over longer periods (e.g. seasonal storage) it can be transformed into liquid hydrides (methanol, methyl-cyclohexane, ammonia) or stored as pressurized gas in underground caverns. For mobile as well as stationary small-scale storage, hydrogen has to be conditioned preferably to either pressurized gaseous hydrogen, bound to metal hydrides, liquefied at cryogenic temperatures or cryo-adsorbed at an optimized pressure/ temperature balance.

2.2 Hydrogen Storage Technologies

Various storage concepts for hydrogen have been developed in the recent years. The concepts which are already commercial or on the way to commercialization are depicted below:

Gaseous Hydrogen: Moderately pressurized hydrogen at large quantities and as stationary form of storage (several 10,000 Nm3 at about 1 - 1.5 MPa) is stored in spherical vessels. Even larger quatities (several million Nm3 at pressures between 3 to 6 MPa) can be stored in porous aquifer storage caverns underground (e.g. ICI, England).

For some industrial applications hydrogen is stored in small high pressure bottles (50 Nl/ 20 MPa) or in medium size high pressure cylindrical vessels (10 - 20 m3/ > 20 MPa).

High pressure cylindrical storage vessels for pressurized gaseous on-board hydrogen storage in vehicles are presently under development. The pressure levels aimed at are 20-30 MPa. The materials used for advanced tanks are plastic composite structural materials with steel or aluminum liners for the inner vessel.

Metal Hydrides: Metal hydride storages usually are charged with pressurized hydrogen of between 3 and 6 MPa. Suitable metal alloys provide spaces in their lattice where hydrogen atoms can be accommodated. The hydriding heat set free when absorption of hydrogen occurs has to be removed from the hydride storage in order to avoid damage of the storage containers. High temperature hydrides (temperature level at which the hydrogen discharging process starts again) are more efficient than low temperature hydrides. In automobile applications only low temperature waste heat is available from engine cooling. Therefore, mainly low temperature hydrides are used for automobile applications. Most recently experiments with medium temperature hydrides have started. Metal hydride storage systems are also regarded as a very safe way to store hydrogen in domestic applications.

Sponge Iron: The sponge iron storage during the charging process makes use of reduction of Fe3O4 by either hydrogen or carbon monoxide, liberating either water vapour or carbon dioxide and leaving Fe as a product. When discharging of the storage shall occur, water vapour is inserted and clean moist hydrogen gas obtained from the oxidation reaction. Advantage of this process is that hydrogen rich gases obtained from hydrocarbons and used for charging the storage do not need a shift reaction or a selective oxidation downstream. Advantage of this storage concept furthermore is its very low investcosts of approx. 1.5 ECU/ kWh (at least one order of magnitude cheaper than its competitors) and its still acceptable weight (half that of hydrides, double that of pressurized H2 storage) at atmospheric operational pressure levels.

Hydrogen Production

Direct Production:

Steam-Reforming of Natural Gas and Naphta

Partial Oxydation of Heavy Oil

Production as By-Product:

Petroleum Industry (Gasoline Reforming)

Petrochem. Industry (Ethylen Production)

Other Chemical Industry

Chlorine Alkali Electrolysis

Coal Refining (Coke Gas)

9.0

6.0

3.0

10.0

2.5

3.6

0.9

0.9

2.1

310

190

120

190

90

33

7

10

50

Total 19.0 500

Hydrogen Application

Non-Energy Use:

Chemical Industry

Metallurgical and Glass Industry

Indirect Energy Use:

Petroleum Industry

Synthetic Fuels

Direct Energy Use:

Industry (Process Heat)

Other Uses

6.4

6.0

0.4

3.6

2.7

0.9

9.0

8.4

0.6

240

230

10

100

160

Total 19.0 500

Liquid Hydrogen: LH2 is stored in small tanks of 100 l to up to stationary spherical tanks of some 2,000 m3. All tanks have a vacuum-insulation between inner and outer wall of the tank system. The large volume tanks usually have perlite insulation, whereas the medium to smaller size and all mobile tanks have a vacuum super-insulation consisting of a number of some 30 aluminum foil layers separated by a type of plastic foils or mats.

The evaporation rates (evaporation of LH2 into GH2) of modern LH2 tanks typically are in the order of 0.1% per day for large volume stationary tanks (several 100 m3 to several 1,000 m3), 1% for mobile cylindrical delivery tanks (38 to 55 m3) and around 1.7% - 3% for small vehicle storage tanks (about 100 l to 400 l), depending on the specific requirements and layout.

Cryo-Adsorption: Gaseous hydrogen at low temperatures (150 - 60 K) is physically adsorbed on porous material, mostly active carbon. The storage densities achievable lie between those of LH2 storage systems and high pressure systems. This might provide characteristics requested by mobile applications. At 3.5 MPa some 25 g H2/ l can be stored at 77 K which is about 30% of the density of LH2 or equivalent to 30 MPa pressurized storage. At the same pressure but at 175 K some 8 g H2/ l can be stored which is equivalent to 10 MPa of pressurized storage.

Liquide Hydrides: Liquide hydrides are chemical compounds which have the capability of binding hydrogen, such as methyl-cyclohexane, ammonia, methanol, etc.. The advantage of this method of storing hydrogen is its storability over longer periods in more or less stable conditions. Therefore, it might be possible to store hydrogen in a seasonal storage, i.e. from summer to winter time, in a comparatively small volume and only with hydrogenation and dehydrogenation but without storage losses. The disadvantage of liquid hydride storage for emission-free or reduced automotive applications is the need for on-board dehydrogenation which would require a dehydrogenation unit on-board a vehicle, causing additional dead weight. Also the hydrogen carrier substance (toluene in the case of methyl-cyclohexane) has to be collected and recycled for hydrogenation, representing additional dead weight.

2.3 Hydrogen Transport and Handling

Liquid Hydrogen: Transcontinental transport of liquid hydrogen has been investigated in the EQHHPP /4/ assuming a barge carrier concept. Five vacuum super-insulated tanks of 3,600 m3 (l=29m x d=18 m) geometrical volume, each mounted on a barge, are transported by a specially designed barge carrier ship cross-atlantic. The barges serve as land-side as well as ship-side storage for LH2. The invest costs for one barge are calculated to be in the order of 4½ MECU. The barge carrier capable of accommodating five barge tank containers would lie in the order of 33½ MECU.

The evaporation rate of the designed barge tank will be 0.1 %/d, resulting in a 0.05 MPa pressure build-up during a 9 day 5,500 km voyage across the northern Atlantic. The filling pressure of 0.125 MPa thus will be increased to 0.175 MPa, whereas the maximum allowable pressure would be 0.5 MPa. The barge tanks will be emptied to 5% of its volume, the remaining LH2 assuring cryogenic temperature conditions in the tanks, thus allowing the recirculation of cold gasfied hydrogen to the liquefaction plant and to avoid heating-up and cooling down of the tank which would incur big thermal losses.

An up-scaling of this design would lead to barge tank vessels of approx. 48 m in length and 27 m in diameter and a resulting transport volume of approx. 23,000 m3. Due to very unfavourable ship dimensions (breadth of ship about double breadt of storage vessel) a new ship and vessel design would become necessary, such as e.g. a SWATH-ship design with also disconnectable LH2 transport containers as designed by HDW /8/.

First steps into transcontinental transport of LH2 can be realized also step by step by starting with standardized commercial vacuum super-insulated ISO 40 ft containers (40 m3 LH2) right now. Then switching to larger container designs such as double length 80 ft containers (100 m3) and then jumbo containers (270 - 600 m3) can be made available as soon as markets have developed.

Distribution of LH2 to the consumer via road or rail can be effected by containerized or by trailer transport in existing ISO containers or commercially existing liquid hydrogen truck trailers. Also vehicle refuelling stations for LH2 vehicles will be served by containerized or trailer delivery.

Liquid hydrogen refuelling of hydrogen vehicles and aircraft will be possible with advanced refuelling equipment. Filling nozzles which can be disconnected in cryogenic state will allow the subsequent refuelling of many units in short time, comparable with today's refuelling processes of conventional fuels. Refuelling times of 5 - 15 minutes for cars and buses will be feasible soon and of half an hour for aircraft are expected feasible.

Gaseous Hydrogen: Gaseous hydrogen can be provided via truck delivery in cylindrical high pressure vessels (20 MPa) for very small quanitities and only over short distances economically. In the future, large quantities of gaseous hydrogen can be provided only via centralized and decentralized pressurized pipeline systems economically (0.4 - 6 MPa). Hydrogen produced far away from the consumer will be delivered in high pressure (6 - 8 MPa) long distance pipeline systems. Locally produced hydrogen gas will be distributed in medium (2 MPa) or low pressure (0.4 MPa - 0.04 MPa) pipeline systems. Compressor stations, valves and gaskets of existing pipeline systems for natural gas have to be adapted to hydrogen use in case the construction material of these pipelines is suited for hydrogen transport.

Refuelling stations for compressed hydrogen vehicles will be served from such pipeline systems if nor delivered in liquid form. Hydrogen will be compressed to the storage pressure level of typically 5 MPa (metal hydrides) or compressed hydrogen storage (20 - 30 MPa) via compressor systems. Also hydrogen produced by decentralized electrolysers at refuelling stations will be conditioned in the same way. Refuelling times of some 5 - 15 minutes per vehicle will be realistic.

Hydrogen in Liquid Hydrides: Liquid hydrides (ammonia, methanol, cyclo-hexane) can be handled in the same way as they are handled presently regarding all requirements related to the handling of chemicals or car fuels.

2.4 Hydrogen Applications in the Transport Sector

Propulsion concepts under investigation for hydrogen fulled ground and airborne vehicles are internal combustion engines (ICE) such as piston and rotary engine, external combustion engine (ECE) such as the Stirling engine and fuel cells (Alkaline Fuel Cell - AFC, Phosphoric Acid Fuel Cell - PAFC, Proton Exchange Membrane Fuel Cell - PEMFC) and gas turbines.

The internal combustion engines developed for passenger cars so far are functioning with external mixture formation. In order to improve the volumetric power output of engines operated with excess air/ fuel ratio, especially of heavy duty engines, a switch to internal mixture formation and high pressure hydrogen injection (3 - 1.5 MPa) is necessary in order to achieve low NOx values. Rotary engines due to their inherently independent combustion chamber design generally have less problems with backfiring and produce lower NOx values than piston engines. Also in the case of external combustion engines due to the external combustion process emission values can be adjusted and controlled more easily.

Fuel cell propulsion in conjunction with onboard hydrogen storage can provide a zero emission propulsion concept, if low temperature fuel cells such as alkaline or proton exchange membrane cells are used. They can avoid the evolution of nitrogen oxides and other typical emissions related to today's car fuels completely. Fuel cell drive concepts with highly efficient electric drive systems can provide very fuel efficient solutions for vehicle propulsion, two to up to three times as efficient as ICE with mechanical transmission systems and therefore seem to be the most promissing option for clean and low-noise vehicle propulsion of the future. Achievable fuel efficiencies (stored onboard energy - useful wheel traction) range in the order of 20% - 28 % for internal combustion engines and of 45% - 55% for methanol or hydrogen fuel cell powered electric drives. Since in the data sheets given for vehicle applications in chapter 9 no efficiencies are mentioned for the propulsion concepts, average efficiencies of 0.23 for hydrogen ICE with mechanical transmission and 0.25 for ICE electric drive, 0.27 for Stirling electric and 0.55 for PEM fuel cell electric shall be assumed over the typical operating profile.

For the propulsion of aircraft, only gas turbines are suited. As conventional kerosene jet engines step by step will be improved in their fuel economy and emission behaviour in the next years, also hydrogen optimized concepts will profit from these efforts. The emissions of hydrogen modified jet turbines generally have lower overall emissions since they avoid sulphur, carbon and hydrocarbon emissions completely. The remaining emissions are water vapour and nitrogen oxides. Water vapour emissions cannot be avoided but NOx emission behaviour may be improved significantly. Tests in order to clear the NOx emission reduction potential of hydrogen powered jet turbines are presently under investigation /5/.

2.5 Hydrogen Applications in the Industrial and Utility Sector

Hydrogen can be used in various applications in the industrial and utility sector. In industry hydrogen is used in metallurgy, food industry, float glass production, chemical sythesis processes, mineral oil industry as well as for industrial process heat (see table 1). In the utility sector hydrogen production/ combustion may be used as load-levelling instrument. Also hydrogen for peak demand electricity production can be imagined in grids with small over-capacities. Hydrogen stored in liquid hydrides even can provide a

means of seasonal storage and thus replace pumped hydro-storage e.g. in alpine regions. In a later hydrogen-electricity economy hydrogen can play a role in many of today's utility applications.

First applications in the utility sector might occur in the primary and secondary management of the energy production capacities connected to the electricity grid. From existing electricity generating capacities, excess capacities can be used during off-peak periods to produce hydrogen electrolytically. This hydrogen will be stored and can be used either for fuelling transport vehicles or for providing peak power or seasonal energy.

In urban hydrogen networks imaginable one day, decentralized cogeneration applications based on fuel cell technology seem to be the most efficient way of providing heat and electricity. Both, the European Commission as well as some industrial companies regard the way of transforming natural gas into hydrogen in locally centralized installations first, before using it in fuel cell applications as the preferable option /11/. The advantage is the simpler systems technology on the application side and the investment in only a few reforming plants instead of many decentralized ones. Such local urban hydrogen networks need not to have a larger capacity than presently existing reforming plants, i.e. approx. some 10 MW to 100 MW. Additional advantage of these more centralized reforming installations is that they might be equipped more easily with CO2 purification equipment or that a clean process such as that developed by Kvaerner in Norway may be used. Such local urban hydrogen networks also will provide hydrogen to commercial and industrial users as well as to vehicle refuelling stations. A final configuration of many of such local urban network clusters might lead into an over-regional interconnection of these clusters, similar to today's natural gas grids. Such larger grids then will also be suited to deliver hydrogen to industrial users for production of industrial electricity and process heat in cogeneration, as raw material, etc.

2.6 Hydrogen Applications in the Domestic Sector

Hydrogen use in the domestic sector can replace all of today's uses covered by natural gas, town gas or by liquid petrol gas. Thus hydrogen can be used for boilers, for cooking stoves, for catalytic heater devices, for central heating furnaces as well as for efficient decentralized cogeneration applications for combined electricity and heat/ cold production.

The most efficient conversion concepts for households will be catalytic heat and hot water production and fuel cell heat or cold/ electricity production. Both technologies, catalytic heaters and fuel cells, can be configurated from very small initial power capacities to larger ones in modular form. Therefore, high flexibility and efficiency can be achieved from the very beginning. Catalytic heaters operating with hydrogen and air easily achieve 75% efficiency at the site of application. With hydrogen oxygen operation 99% are present state of the art. Low temperature fuel cells operate at 80 - 100 °C at efficiencies of about 60% in part load operation and of above 50% at design load. The waste heat at least is sufficient for hot water production.

3. CURRENT STATE OF APPLICATION OF HYDROGEN TECHNOLOGIES

3.1 Hydrogen Production and Conditioning Technologies

The hydrogen production technologies in commercial use today are catalytic steam reforming of natural gas and naphta, partial oxidation of hydrocarbons, pyrolysis of coal or crude oil derivates, gasoline reforming and catalytic cracking, dehydrogenation of hydrocarbons or other organic compounds, as well as electrolysis of water where cheap hydro-electricity is available. Hydrogen as by-product mainly is produced in chlorine-alkali electrolysis in chemical industry (see table 1).

Worldwide between 175 - 200 t/d of liquefaction capacity exist presently, about 135 t/d in the USA, approx. 20 t/d each in Canada and Europe, as well as smaller liquefaction plants in India, Russia and Asia. New capacities are presently being built in the USA. Very large capacities are planned in Japan until 2005.

3.2 Hydrogen Storage Technologies

Depending on the source of hydrogen, its transport distance to the user and its purity requirements, hydrogen is either stored in compressed gaseous or in liquid form. Liquid hydrogen is stored in 50 - 100 m3 tanks on site, e.g. at micro-electronics plants. At locations where hydrogen is not required in high purity also gaseous compressed hydrogen storage in cylindrical vessels at typically 4 - 5 MPa is usually on-site. For smaller quantities storage in bottles at 20 MPa is normal practice.

Very large quantities of gaseous hydrogen are stored in underground caverns by the British chemical company ICI since many years without any difficulties.

For automotive uses in prototype vehicles hydrogen is stored usually in metal hydride tanks (5 MPa) and in vacuum super-insulated LH2 tanks (0.4 MPa, 20 K). Also the first applications with compressed hydrogen storage (30 MPa) are in preparation. The first cryo-carbon-adsorption storage vessels are being tested more systematically in the USA for demonstration applications (e.g. 4 - 6 MPa and 60 - 150 K).

3.3 Hydrogen Transport and Handling

Gaseous hydrogen is transported in a pressurized pipeline system of 215 km length in Germany since more than half a century without any accidents. The annual throughput is about 250 million m3. Similar systems are operated by Air Products in the USA (approx. 170 km in total) and by Air Liquide in France (290 km).

Liquid hydrogen is transported in ISO 40 ft containers and truck trailers commercially on road, rail and ship in quantities of 35 m3 to 60 m3. Larger quantities of LH2 have been transported within NASA's space program in barges over distances of about 100 km. LH2 road transport in large cylindrical containers of 270 m3 and 600 m3 has been performed in the framework of ESA's Ariane space program. A (60 x or 20 x) down-scaled maritime transport container for 180 or 60 m3 of LH2 will be tested within the EQHHPP /5/ soon.

Refuelling stations for automobile applications are under development for compressed gaseous as well as for liquid hydrogen supply. Refuelling stations for metal hydride storages operated at between 5 to 6 MPa have been built and operated already 10 years ago. Presently a refuelling station for compressed hydrogen storage at 25 - 30 MPa is in development. For liquid hydrogen refuelling stations for passenger cars and city buses, allowing refuelling times of 10 - 15 minutes and subsequent refuelling of many vehicles, are developed as first prototypes and will be tested soon /5/.

3.4 Hydrogen Applications in the Transport Sector

Since more than 1½ decades several car makers (BMW, Daimler-Benz, Mazda) have developed prototype hydrogen powered passenger cars with internal combustion engines (piston, rotary) and some have tested them over hundreds of thousands of kilometers (Daimler-Benz, BMW). Also first fuel cell hydrogen passenger cars are under development (Energy Partners - USA, H-Power - USA, Renault/ Volvo - France/Sweden).

Presently also first city bus prototypes are under development or already in first driving tests [Internal Combustion Engine: Hydrogen Systems NV., MAN Nutzfahrzeuge AG, Daimler-Benz AG/ Fuel Cells: DoE/ DoT - Georgetown University (PAFC), Ballard-British Columbia (PEM), Ansaldo-De Nora (PEM), Air Products-Ansaldo-Elenco-Saft (AFC)].

In the USA first applications of fuel cell propulsion concepts for locomotives are in discussion for ULEV applications in California.

Hydrogen application in the aerospace sector presently occurs only in space applications due to its superior energy/ weight ratio. In aircrafts no commercial use occurs presently. In Russia, in a modified Tupolev 154 experimental aircraft the starboard jet engine was operated with liquid hydrogen over the full operating range during several test flights successfully. Combustion tests on a hydrogen optimized sector of a jet engine combustion chamber will be executed within the EQHHPP soon /5/.

3.5 Hydrogen Applications in the Industrial and Utility Sector

So far, no major applications are known from the utility sector.

In the industrial sector many applications of hydrogen exist (see table 1).

Hydrogen as a raw material at almost 90% is used for ammonia synthesis and for crude oil processing, about half of it in each of the both sectors. Of the remaining approx. 10%, half finds its way into methanol synthesis and the rest into direct reduction of iron ore/ scrap metal, metallurgy, float glass production, and other uses (organic chemicals and intermediate products, fats and oils, electronics). Larger amounts of hydrogen will be required for reformulated car fuels in the USA until the end of this decade.

In Germany in particular, the distribution of the non-energetic hydrogen use of approx. 6.2 billion standard cubic meters is as follows: ammonia (73.8%), methanol (1.9%), oxo-alcohols (8.5%), cyclo-hexane (1.9%), other hydrogenation processes (7.8%), direct reduction (5.5%), metallurgy (0.2%) and other uses as float glass, silicon industry and small users (0.4%).

The distribution of the indirect-energetic hydrogen use in Germany of approx. 3.6 billion standard cubic meters is as follows: hydro-cracking (27.4%), hydro-treating (47.3%), methanol as synthetic fuel (23.2%) and coal liquefaction (2.1%).

3.6 Hydrogen Applications in the Domestic Sector

With exception of a few private or governmental demonstration projects in Germany, Sweden, Switzerland and the USA, pure hydrogen has not yet found its way into the domestic sector.

In Germany, hydrogen is used only as constituent of coke or town gas at a volume of approx. ½ billion m3 annually.

4. STATE-OF-THE-ART IN WESTERN EUROPE BY THE YEAR 2020

The improved state of the art for the year 2020 in comparison to the present one mainly will be characterized by improved technical and economic parameters for technologies already in use or demonstration application today and by the becoming mature of technologies presently under development. The state of the art of these technologies is documented in the data sheets included in chapter 9 of this paper.

In a concise summary some expected achievements are highlighted.

Hydrogen will come either from natural gas or coal via reforming or gasification processes, as surplus from chemical processes or increasingly from renewable energy sources such as wind, biomass, hydro and solar. Hydrogen produced locally, interregionally or abroad will have to be transported to and fed into local urban hydrogen networks. There it will be efficiently distributed to the various clients of the local urban network such as cogeneration plants, industrial and commercial users, municipal services, domestic applications and automotive refuelling stations.

For small and medium size stationary applications as well as for mobile applications fuel cells increasingly will be the systems of choice. Their use in decentralized stationary applications will improve the energy efficiency of electricity and heat/ process heat/ cold generation significantly. The fuel cell technologies in use will be PAFC, MCFC, SOFC, PEMFC and FFFC [for abbreviations see chapter 8]. Applications for heat production will make use of efficient catalytic heater concepts available in modular concepts and in a wide range of capacity sizes.

Larger applications for stationary (peak) electricity generation with capacities of several 100 MW will be hydrogen operated combined cycle power plants.

In the transport sector, compact fuel cell systems such as the PEMFC, AFC and FFFC will power city buses, urban delivery and service vehicles and passenger cars. Hydrogen as a product will be carried on-board in compressed gaseous hydrogen tanks, in cry-adsorption tanks, in liquid hydrogen tanks or in improved metal hydride tanks or iron sponge storages, respectively hydrogen will be generated from methanol or natural gas via on-board reformers or in the case of methanol converted in a direct methanol fuel cell directly into electricity. The fuel efficiency of automobiles will be improved by fuel cell electric drives significantly in comparison to drives with internal combustion engine and mechanical transmission (about 2 to 2.5 times). Thus local emissions from vehicles will also be reduced dramatically, at its best to zero.

The first liquid hydrogen fueled jet airplanes will be operated. LH2 is the only form of hydrogen suited for aviation uses. Hydrogen also allows independence from primary energy resources, especially from limited crude oil resources. [Remark on lead times: The system life of an aircraft lies in the order of 25 years and it usually takes another 25 years to phase out all older aircraft still in use. In order to have a significant market share of hydrogen operated passenger aircraft in the year 2050, soon after the year 2000 hydrogen aircraft would have to be developed and step by step put into operation.]

5. ESTIMATED TECHNICAL POTENTIAL IN WESTERN EUROPE FOR THE TARGET YEAR 2050

Remark: The given hydrogen scenario is an experts' assumption, not an integrated computer simulation.

In comparison to the baseline scenario for 2050, the modified scenario for hydrogen involves lower overall utilization of oil and coal, but higher use of natural gas, hydro and especially renewable energies. The higher uses for nuclear and hydro are mainly caused by the transformation of off-peak electricity into storable hydrogen which does not need additional generation capacities. The significant reduction in oil use results from substitution of 60% in the transport sector out of which about 39% is achieved by hydrogen, approx. 9% by natural gas, 7% by methanol and 6% by electricity. Hydrogen will partly also be produced from syngas obtained by coal gasification in a transitional period. In such a transitional period, natural gas use is extended significantly into transport applications since also hydrogen will be produced CO2-free from natural gas initially. In industry part of coal and gas use as well as of electricity use will be replaced by hydrogen. Industrial heat is mainly produced in cogeneration from hydrogen.

Both, the use of natural gas and hydrogen as fuels as well as of electric propulsion in the transport sector will have supported the introduction of the fuel cell concept as very efficient drive. Half of the kerosene in aviation will be replaced by LH2. Most of the city buses as well as half of the passenger cars will be operated with hydrogen. Trucks and internal navigation are already partly switched to hydrogen, natural gas or methanol. The use of coal in commerce and residential has been reduced to 1/3, that of oil halfed, whereas the use of natural gas reduced by 1/4. These reductions have been compensated by hydrogen which is used efficiently in catalytic converters and in fuel cell cogeneration where it replaces electricity and heat consumption to some extent. Thus, hydrogen will be produced from off-peak electricity, from off-peak syngas from combined cycle coal gasification plants, from natural gas by (depending on electricity mix mainly) CO2-free processes (CO2 extraction as carbon black), from natural gas via reforming and CO2 depositing in emptied gas fields and from renewable resources such as hydro (also marine hydro), biomass, wind and solar.

Vehicle propulsion technology for road vehicles has been increased significantly for hydrogen fuel due to common use of low temperature fuels cells for cars as well as for heavy and light duty vehicles. Also part of the methanol applications will be operated with methanol fueled low temperature fuel cells.

The use of renewable energies has been extended significantly above that estimated in the baseline scenario to some 16%, supplying both, electricity for direct use as well as for hydrogen production. The provision of this renewable primary energy supply is achieved almost entirely without environmental disadvantages, locally as well as globally. The renewable energy sources, if not available locally on the spot, are available within the area of the investigated extended Europe thus representing mainly 'domestic' energy sources. A minor quantity of clean fuels, not higher than today's total energy imports, might be imported from abroad. The average efficiency for hydrogen production from all sources, fossil, nuclear as well as renewable ones, is assumed to be in the order of 0.66. Although the primary energy supply in the energy sector is increased by some 20% due to hydrogen production, the overall primary energy use is not increased due to higher efficiencies (- 10% primary energy use) achieved in the end use sector (transport, agricultural, commercial and residential).

Due to the necessity to switch to the use of cleaner fuel, coal and oil shall be used significantly less in the energy, residential, commercial, transport and where possible in the industrial sector. Efficiency due to use of cogeneration units and the use of renewable energy will be extended. The increase of renewables including hydro to approximately 16% of primary energy use in 2050 seems to be a very conservative approach compared with the scenarios discussed by outspoken renewables' propagators and thus not too unrealistic on the basis of the major structural changes in energy economy and transport sector which can be expected until 2050. If some may say these changes seem unrealistic since from present point of view unimaginable, the time frame of half a century certainly will have many surprises in store for humankind. If humankind really would decide to establish the described energy scenario including also hydrogen as a means for clean and efficient energy supply and thus really try to abate greenhouse gases this level of renewables' use will certainly be feasible or even could be extended much more - depending on the changes happening in the utility and domestic sector - within the given time.

ENERGY BALANCE 2050

END USE Coal Oil Gas Electr. Heat H2 MEOH Plast. Total

Industry 3391 195 4091 5938 24 2250 0 0 15.889,00

Transport 2 6469 1534 610 0 3674 1180 0 13.469,00

6. REMARKS ON MARKET IMPLEMENTATION, PUBLIC ACCEPTANCE, POLICY IMPLICATIONS, R&D PRIORITIES, COSTS, BARRIERS, DISCLAIMERS, etc.

Market Implementation: The introduction of hydrogen into the market as clean automotive fuel and as a clean energy carrier should be supported by a taxation law as envisaged by the European Commission for the combined treatment of the energy content and the CO2 emissions of a fuel. At least hydrogen produced in a clean way (i.e. carbon free) should be treated this way and given a competitive advantage over fossil fuels, thus easening the introduction of decentralized and renewable energies as well as of hydrogen into the present market. According to present national German taxation law no mineral oil tax is to be applied on hydrogen, notwithstanding from which primary source this hydrogen is produced.

Hydrogen should be introduced stepwise into the fuels market. In the years to come, fuel cell technology can be expected to enter into the market of decentralized cogeneration of electricity and (process) heat/ refrigeration, first in Japan and the U.S.A., then in other industrialized countries. All these applications would have to rely on natural gas or biomass as primary energy sources. Natural gas has to be converted to hydrogen at each plant separately, requiring as steam reformer plant, a shift reactor and a process control. In a future, local urban network of fuel cell applications it seems preferable to have locally centralized steam reforming or comparable hydrogen production installations supplying hydrogen to the consumers through hydrogen pipelines thus simplifying the technical and cost efforts for fuel production at each fuel cell plant dramatically. Such local urban hydrogen networks could provide hydrogen not only for fuel cell cogeneration plants but also for urban vehicle fleets such as buses, delivery and municipal vehicles.

Public Acceptance: Since natural gas is widely used in the energy economy and its use is steadily extended also into transport applications its degree of acceptance will be

Agriculture 7 190 180 180 7 224 0 0 788,00

Commerce 69 563 1386 3000 257 1083 0 0 6.358,00

Residential 306 403 3326 2800 331 2155 0 0 9.321,00

TFC 3.775,00 7.820,00 10.517,00 12.528,00 619,00 9.386,00 1.180,00 0,00 45.825,00

Distribution Losses 0 0 157,76 950,88 69,02 469,30 5,90 0 1.652,86

ENERGY SECTOR Coal Oil Gas Nuclear Hydro Renew. Electr. Heat Plast. H2/ (MEOH)

Total

Refineries 0 1319 35 0 0 0 83 0 0 0 1.437,00

Electricity Generation 10373 1381 4052 11242 2214 5250 -13.993,20 -959 1120 0 20.679,80

Heat Production 294 46 60 0 0 0 0 -200 280 0 480,00

H2 (MEOH) Prod. 1000 0 3500 1300 500 6800 0 0 0 -11.041,20 2.058,80

Own Use, etc. 470 41 1100 0 0 0 431,32 13 0 492,77 2.548,09

Subtotal 12.137,00 2.787,00 8.747,00 12.542,00 2.714,00 12.050,00 -13.478,88 -1.146,00 1.400,00 -10.548,43 27.203,69

PRIMARY ENERGY SUPPLY 15.912,00 10.607,00 19.421,76 12.542,00 2.714,00 12.050,00 0,00 -457,98 1.400,00 492,77 74.681,55

0,00

Feedstock 65 2282 420 1000 0 3.767,00

TRANSPORT 2050 Coal Oil Products Natural Gas Electricity H2 MEOH Total

Air 0 1420 0 0 1500 0 2.920,00

Road: Truck, Bus 0 2754 500 0 460 1055 4.769,00

Road: Car 0 2002 1000 300 1600 0 4.902,00

Rail 2 67 33 310 14 0 426,00

Internal Navigation 0 225 0 0 100 125 450,00

Non Specified 0 1 1 0 0 0 2,00

Total 2,00 6.469,00 1.534,00 610,00 3.674,00 1.180,00 13.469,00

A, R & C 2050 Coal Oil Products Natural Gas Electricity Heat H2

Total

Agriculture 7 190 180 110 7 224 718,00

Commerce SOUTH 1 214 491 1250 2 320 2.278,00

Commerce MIDDLE 68 309 873 1350 210 736 3.546,00

Commerce NORTH 0 40 22 400 45 27 534,00

Commerce TOTAL 69,00 563,00 1.386,00 3.000,00 257,00 1.083,00 6.358,00

Residential SOUTH 160 149 1261 1350 1 840 3.761,00

Residential MIDDLE 120 204 2000 1100 80 1247 4.751,00

Residential NORTH 26 50 65 350 250 68 809,00

Residential TOTAL 306,00 403,00 3.326,00 2.800,00 331,00 2.155,00 9.321,00

well established. The use of hydrogen is well established in chemical industry. Its use, starting in first niche markets, with selected automotive and utility applications will introduce the handling and application of hydrogen into the public sector step by step. Analogous concepts and standards as for natural gas will be developed and introduced for gaseous and liquid hydrogen thus creating confidence in its safe, efficient and environmentally compatible application among its users as well as acceptance in the public and by authorities.

Policy Implications: Hydrogen as a clean and efficient fuel can play its role best if emission reduced or zero emission applications are requested at high efficiencies and when it can be obtained flexibly from different primary energy sources.

Hydrogen can be used in decentralized small and medium size applications as well as in large-scale applications. Especially cogeneration applications can be realized more efficiently with hydrogen operated fuel cells. The same counts for fuel cell applications in vehicles.

R&D Priorities: Main focus in hydrogen R&D should be given to its production from renewable energies, its infrastructure (conditioning, handling, storage, distribution), its catalytical and electrochemical conversion and its introduction into the various markets. In general, the clearer and more reliable the boundary conditions are set up by governments in order to signal a structural change into the direction to renewable and cleaner energy technologies the sooner and the more profound industrial response will be. Many complaints from industry can be summarized as hinting on a defeciency in reliable and favourable boundary conditions encouraging more in-company R&D in the field of renewable energies and hydrogen technologies. The 4th framework program of the EU could assist in providing such more reliable and continuous boundary conditions.

Costs: In order to introduce hydrogen into the market already in an early stage, a step by step approach should be considered, taking into account the economic advantage of each alternative: hydrogen from natural gas, from chemical production and from biomass being the cheapest alternatives, followed by large-scale hydropower, then from wind energy and finally solar hydrogen.

Already today, hydrogen from off-peak electricity can be produced as vehicle fuel competitive untaxed at least with taxed natural gas. Also electricity production from natural gas via cost improved alkaline fuel cell technology can be produced competitively /11/ and CO2-free.

In the following, some cost estimates (free production plant not including transport costs) for the various hydrogen production technologies are given.

Regulatory Barriers: In the special case of hydrogen existing codes and regulations usually do not include or reflect hydrogen as a product itself. This refers to most national gas codes as well as to international codes as e.g. those for the maritime transportation of liquid gases as ruled by the International Maritime Organization (IMO) in London which include only liquefied petroleum gas (LPG) or liquefied natural gas (LNG) but not liquefied hydrogen (LH2). Also ISO does not reflect hydrogen yet. For a successful and efficient planning and design process for a new technology or concept to be applied on a worldwide basis as well as for a successful marketing, an extension of such codes to the technology or concept in question is mandatory. In the case of international rules as set up e.g. by the IMO, application for modification or amendments will only be successful when brought up by at least two or more member countries. Whenever specific pilot or demonstration projects start into such technologies which are not yet included in existing national or international codes and regulations it is worthwile to start also into application work for amending missing regulations (as presently practised on ISO level within the EQHHPP). Applications should always be filed by several interested partners which for international codes as e.g. IMO or ISO should come from different member countries. Pilot or demonstration projects therefore are very valuable and helpful for the advancement of technology also in this aspect by providing safer grounds for later realization (establishment of safety rules, construction codes, and operating instructions).

Economic Barriers: The main barrier for all clean or renewable energy carriers or fuels is that their relative benefits to the environment (producing lesser pollution e.g.) as well as the social and external costs of present energy and fuel use are not reflected in their prices. Thus hydrogen from clean sources, being more expensive than from fossil fuels, cannot be competitive.

Disclaimers: The data used is mainly taken from the literature listed in chapter 7 and from contacts to industries and institutions working a.o. in the field of hydrogen. The material provided in the paper reflects the best judgement of the authors in the light of the information available to them at the time of preparation. Any use of the information contained in this paper or any reliance on or decision to be made based on it, are sole responsibility of the party using the information. No responsibility is taken over by the authors or LBST for any negative consequences or damages suffered by any third party as a result of using these data or of decisions made or actions taken based on this paper.

7. LITERATURE

For today, the following hydrogen production costs can be achieved:

Large-scale hydro-electricity: 2.5 - 5 ¢ECU/ kWhH2,th

Biomass conversion: 4.5 ¢ECU/ kWhH2,th

CO2-free from natural gas: 4.6 - 6 ¢ECU/ kWhH2,th

Surplus nuclear electricity: 5 - 7 ¢ECU/ kWhH2,th

Wind farms: 7.5 - 15 ¢ECU/ kWhH2,th

Solar parabolic trough plants: 15 - 20 ¢ECU/ kWhH2,th

For the year 2020 the following cost reductions seem feasible:

Biomass conversion: 2.5 ¢ECU/ kWhH2,th

Wind farms: 3.7 - 6 ¢ECU/ kWhH2,th

Solar parabolic trough plants: < 10 ¢ECU/ kWhH2,th

/1/ Instrumente für die Entwicklung von Strategien zur Reduktion energiebedingter Klimagasemissionen in Deutschland / durch LBST bearbeitete Unterbereiche: Wasserstofferzeugung, Wasserstoffeinsatz im Kraftwerksektor, Wasserstoffspeicherung, -transport und -verteilung, Wasserstoff-Verflüssiger, H2/O2-Dampferzeuger/ im Rahmen des Forschungs- und Entwicklungsprojekts für das Bundesministerium für Forschung und Technologie/ Unterauftrag durch IER der Universität Stuttgart, Dezember 1992

/2/ Bedeutung, Einsatzbereiche und technisch-ökonomische Entwicklungspotentiale von Wasserstoffnutzungstechniken, Zentrum für Sonnenenergie- und Wasserstoff-Forschung Baden-Württemberg (ZSW) - Deutsche Forschungsanstalt für Luft- und Raumfahrt (DLR) - Ludwig-Bölkow-Systemtechnik GmbH (LBST), Stuttgart - Ottobrunn, März 1992

/3/ Bedingungen und Folgen von Aufbaustrategien für eine solare Wasserstoffwirtschaft - Materialienband II 'Schlüsseltechnologien', Untersuchung für die Enquete-Kommission des Deutschen Bundestages "Technikfolgen-Abschätzung und -Bewertung", Ludwig-Bölkow-Systemtechnik GmbH (LBST) - Deutsche Forschungsanstalt für Luft- und Raumfahrt (DLR) - Forschungsstelle für die Energiewirtschaft (FfE), Ottobrunn, Mai 1990

/4/ Euro-Québec Hydro-Hydrogen Pilot Project Phase II, Executive Summary, Joint Management Group Hydro-Québec and Ludwig-Bölkow-Stiftung, D. Kluyskens, O. Ullmann, R. Wurster, Montréal and Ottobrunn, March 31, 1991 (European part carried out under contracts no. 3549-88-12 PD ISP D and 3723-89-05 PC ISP D given by the European Atomic Energy Community)

/5/ Status of the Euro-Québec Hydro-Hydrogen Pilot Project [EQHHPP], R. Wurster, proceedings of 4th Annual U.S. Hydrogen Meeting 'The Transition to Commercial Applications' of The National Hydrogen Association, Washington, March 25-26, 1993, pp. 5-1 to 5-15

8. LIST OF MOST IMPORTANT ABBREVIATIONS:

orwegian Hydro Energy in Germany (NHEG) - Final Report, Study on behalf of the "Bundesministerium für Forschung und Technologie" Germany, the Commission of the European Communities, "Det kongelige olje- og energidepartement" Norway, Norsk Hydro a.s and Ludwig-Bölkow-Systemtechnik GmbH, by the Norwegian-German Partnership (Norsk Hydro a.s - K. Andreassen, N. Henriksen, A. Oyvann and Ludwig-Bölkow-Systemtechnik GmbH - U. Bünger, O. Ullmann), 15.05.1992

/7/ Norwegian Hydro Energy in Germany (NHEG), K. Andreassen, U.H. Bünger, N. Henriksen, A. Oyvann and O. Ullmann, Int. J. Hydrogen Energy, Vol. 18, No. 4, pp. 325-336, 1993

/8/ Seetransportsystem für Flüssigwasserstoff, Backhaus, Fehr, Krapp, in Entwicklungen in der Schiffstechnik, Statusseminar 1989, Herausgeber Germanischer Lloyd, Verlag TÜV Rheinland GmbH, Köln, 1989

/9/ Hydrogen as an Energy Carrier: Technologies, Systems, Economy/ Translation of: Wasserstoff als Energieträger/ Carl-Jochen Winter, Joachim Nitsch eds., Springer Verlag, New York Berlin Heidelberg, 1988

/10/ Renewable Energy - Sources for Fuels and Electricity, Editors: T.B. Johansson, H. Kelly, A.K.N. Reddy, R.H. Williams, Exec. Editor: Laurie Burnham, Island Press, Washington D.C. - Covelo, California, 1993

/11/ 3. Industrieseminar Brennstoffzellen, veranstaltet vom Zentrum für Sonnenenergie- und Wasserstoff-Forschung, Neu-Ulm, 25. - 26. Januar 1994 [Beiträge von Dr. P. Zegers, Europäische Kommission Brüssel ('Urban Fuel Cell Network') und K.-H. Tetzlaff, Hoechst AG ('Die Fallfilm-Brennstoffzelle, ein Multitalent')]

/12/ Wasserstofftechnologie - perspektiven für Forschung und Entwicklung, Herausg. D. Behrens, DECHEMA, Frankfurt, 1986

/13/ Advanced Composites Storage Containment for Hydrogen & Methane, K.S. Young, Proceedings 8thWHEC, Hawaii, Jul. 1990

/14/ Producing hydrogen and carbon black from hydrocarbons, Kværner information brochure 11.93 and personal communications with Kværner Engineering A.S.

/15/ Hydrogen as an Energy Carrier, P.E. Morthorst, L.H. Nielsen, L. Schleisner, Risø National Laboratory, Roskilde, Denmark, December 1993

/16/ Hydrogen as an Energy Carrier - Technologies, Systems, Economy, C.-J. Winter and J. Nitsch (Eds.), Springer-Verlag, 1988

AFC Alkaline Fuel Cell

(C)GH2(Compressed) Gaseous Hydrogen

ECE External Combustion Engine

ECE External Mixture Formation

EQHHPP Euro-Québec Hydro-Hydrogen Pilot Project

FFFC Alkaline Falling Film Fuel Cell

ICE Internal Combustion Engine

IME Internal Mixture Formation

IMO International Maritime Organization

ISO International Organization for Standardization

LH2Liquid Hydrogen

MCFC Molten Carbonate Fuel Cell

MH Metal Hydrides

PAFC Phosphoric Acid Fuel Cell

PEMFC Protone Exchange Membrane Fuel Cell

SOFC Solid Oxide Fuel Cell

Steam Reforming 1994 2020 2050

Type LINDE Process

Net Unit Capacity MWth387 387 387

Annual Hydrogen Output 106 GJ/ yr

106 m3 H2/ yr

8.6

800

8.6

800

8.6

800

Efficiency max.

% 81.2 81.2 81.2

Pressure Level Input

Output

MPa

MPa

4

3

4

3

4

3

Direct Specific

CO2 Emissions

kg/ m3 H2

m3CO2 /m3H2

0.82

0.435

0.82

0.435

0.82

0.435

Plant Lifetime yr 25 25 25

Annual Availability h/ yr 8,000 8,000 8,000

Investment Costs

[total installed plant]

ECU/kW 250 250 250

9.2 Kværner Process for Hydrogen and Carbon Black Production from Natural Gas and Electricity

9.3 Partial Oxidation of Heavy Hydrocarbons

Kværner Process 1994 2020 2050

Type (20 modules)

Net Electric Unit Capacity MWe110 110 110

Annual Output

- Hydrogen

- Carbon Black

106 Nm3/ yr

t/ yr

800

200,000

800

200,000

800

200,000

Efficiency max. % 99 99 99

Pressure Level Input

Output

MPa

MPa

0.5

0.2

0.5

0.2

0.5

0.2

Direct Specific CO2 Emissions kg CO2/ m3H20 0 0



Total Plant Investment Costs 106 ECU 150 120 115

Partial Oxidation of Hydrocarbons 1994 2020 2050

Type LINDE Process


Efficiency max. % 69.5 69.5 69.5

Pressure Level MPa 5 5 5

9.4 Partial Oxidation of Coal:

9.5 Hydrogen by Biomass Reforming:

Specific CO2 Emissions kg/ m3 H2

m3 CO2 /m3H2

1.35

0.53

1.35

0.53

1.35

0.53

Plant Lifetime yr


Investment Costs


ECU/kW 440 440 440

Partial Oxidation of Coal 1994 2020 2050

Type LINDE Process


Efficiency max. % 54.9 54.9 54.9

Pressure Level MPa

Specific CO2 Emissions kg/ m3 H2

m3CO2 /m3H2

2

0.807

2

0.807

2

0.807



Investment Costs


ECU/kW 500 500 500

Biomass Steam Reformer 1994 2020 2050

Type: Johnssen & Partner

Reformer + PSA

- biomass input (dry matter)

- water input

kg/ h

kg/ h

Nm3/h

928

700

2103

928

700

2103

928

700

2103

9.6 Electrolysis:

- raw gas output

- hydrogen output (> 99%)

- installed H2 capacity

Nm3/h

MWth

1295

4

1295

4

1295

4

- Process Efficiency of hydrogen to biomass [lhv]

- H2 content in dry raw gas

- Steam to biomass rate

%

%

-

84

> 61

1.61

84

> 61

1.61

84

> 61

1.61

Pressure Level MPa 0.2 0.2 0.2

Operating Temperature °C 750 750 750

Specific CO2 Emissions m3/ m3H2

m3/ m3 CO2, incorp.

0.33

< 1

0.33

< 1

0.33

< 1



Plant Investment Costs

Hydrogen Product Costs

ECU/kW

ECU/kWhth

900

0.047

500

0.025

500

0.025

Pressurized Electrolysis 1994 2020 2050

Type of Diaphragm CaTiO3-Cermet CaTiO3-Cermet ZrO2Y2O3

Unit Capacity MWe 1 3½ 3½

Efficiency HHV

LHV

%

%

82

69

90

76

95

80

Cell Area

Number of Cells

m²

-

1.5

150

2

80

2

271

Pressure Level

Temperature Level

MPa

°C

3

160

3

160

3

1,000

Overload Factor % 30 35 35


9.7 Compression of Hydrogen:

9.8 Liquefaction of Hydrogen:

Annual Availability h/ yr 2,000 - 8,300 2,000 - 8,300 2,000 - 8,300

Investment Costs

[total installed plant] ECU/kW 500 350 550

Compression of Hydrogen 1994 2020 2050

Type: Piston Compressor 4HB 3K 400/

3HB 3KT 315

1.5--> 28.6 MPa/

0.1--> 2.2 MPa

1.5--> 28.6 MPa/

0.1--> 2.2 MPa

1.5--> 28.6 MPa/

0.1--> 2.2 MPa

Unit Capacity MW 1.5 / 0.36 1.35 / 0.34 1.35 / 0.34

Efficiency % 93 / 94 94 / 94.3 94 / 94.3

Pressure: Input Level

Output Level

MPa

MPa

1.5 / 0.1

28.6 / 2.2

1.5 / 0.1

28.6 / 2.2

1.5 / 0.1

28.6 / 2.2

Throughput m3 H2/ h 7,200 / 2,000 7,200 / 2,000 7,200 / 2,000



Investment Costs

[total installed plant] ECU/kWth ? ? ?

Liquefaction 1994 2020 2050

Type of Process Claude Pressurized Oxygen Expansion

Magnetocaloric Refrigeration

Unit Capacity MWth-LH2

MWe

20 - 100

6.6 - 32.9

100

22.8

100

12.7

Efficiency % 69 77 87

Specific Electricity Consumption kWhe/

kg LH2

13 9 5

Pressure Input Level MPa 3 3 3

9.9 Hydrogenation Process:

9.10 Dehydrogenation Process:

Throughput t LH2/ h 2.53 2.53 2.53


Annual Availability h/ yr 4,400 - 8,300 4,400 - 8,300 4,400 - 8,300

Investment Costs


ECU/kWth1,000 1,000 1,000

Hydrogenation of Toluene 1994 2020 2050

Type of Process IFP IFP IFP


MWe

77

7.65

77

7.65

77

7.65

Efficiency %

kmol MCH/kmol H2

90.5

0.3315

90.5

0.3315

90.5

0.3315

Spec. Electr. Consumption kWhe/ kg MCH 0.242 0.242 0.242

Specific Product H2

Balance Toluene

Methyl-Cyclohexane

kmol/ h

kmol/ h

kmol/ h

974

329

333

974

329

333

974

329

333


Throughput t / yr 262,299 262,299 262,299



Investment Costs


ECU/kWth900 900 900

Dehydrogenation of

Methyl-Cyclohexane

1994 2020 2050

9.11 Pressurized Hydrogen Storage:

Type of Process IFP IFP IFP


MWe

75.4

24.1

75.4

24.1

75.4

24.1

Efficiency %

kmol H2/kmol MCH

75

2.94

75

2.94

75

2.94

Specif. Electr. Consumpt. kWhe/ kg H22.436 2.436 2.436

Specific Product MCH

Balance H2

kmol/ h

kmol/ h

333

950

333

950

333

950


Throughput t / yr 262,299 262,299 262,299



Investment Costs


ECU/kWth360 360 360

Pressurized H2 Storage 1994 2020 2050

Type: underground cavern storage

[storage of renewable H2/

(conventl. H2)]


(conventl. H2)]


(conventl. H2)]

Utiliz. Storage Volume m3 3.34 x 106 3.34 x 106 3.34 x 106

Net Capacity GW 12.1 12.1 12.1

Efficiency % 97.1 97.1 97.1

Specific Capacity GWh/GW 12 12 12


Temperature Level °C ambient ambient ambient

System Lifetime yr 25 25 25

Annual Availability h/yr 2,160 (- 8,300) 2,160 (- 8,300) 2,160 (- 8,300)

Investment Costs

Product Cost Increment

ECU/kW

cECU/kWh

30

0.37

30

0.37

30

0.37


Type: above ground

Utiliz. Storage Volume m3 4,500 4,500 4,500

Net Capacity kW 340 340 340


Specific Capacity kWh/kW 700 - 1,000 700 - 1,000 700 - 1,000





Investment Cost ECU/k 600 - 1,000 600 - 1,000 600 - 1,000


Type: automobile/ 50 l steel composite composite

Utiliz. Storage Volume m3 8.9 14 14

Efficiency % approx. 90 93 93

Specific Capacity kWh/kW < 30 > 30 > 30




Annual Availability h/ yr 600 600 - 1,000 600 -1,000

Investment Costs ECU/kW 300 < 300 < 300

9.13 Hydrogen Storage in Sponge Iron:

Metal Hydride H2 Storage 1994 2020 2050

Type: LaNiH, TiFeH, MgNiH

Utiliz. Storage Volume m3 37 at 280 kg 37 at 280 kg 37 at 280 kg


Specific Capacity

l/ kgalloy

l / lalloy

150 - 400

1,200 - 1,300

150 - 400

1,200 - 1,300

150 - 400

1,200 - 1,300

Pressure Level MPa 3 - 6 3 - 6 3 - 6

Temperature Level low

of Hydride Type high

°C

°C

40 - 70

80 - 300

40 - 70

80 - 300

40 - 70

80 - 300


Annual Availability h/ yr 500 - 8,000 500 - 8,000 500 - 8,000

Investment Costs ECU/kW 200 - 700 100 - 300 100 - 300

Sponge Iron H2 Storage for Bus Applic. 1994 2020 2050

Type: H-Power Fe3O4

System Volume l/kg 0.58 0.58 0.58

H2 Storage Volume l/kg 406 406 406

System Weight (bus with 300 km operating range) kg 1,050 1,050 1,050


Specific Capacity kWh/kg 1.5 1.5 1.5

Pressure Level MPa ambient ambient ambient

Temperature Level

- storing/operating

- starting for FC

- starting for ICE

°C

°C

°C

ambient

200 - 300

300 - 400

ambient

200 - 300

300 - 400

ambient

200 - 300

300 - 400

System Lifetime yr 10 + 10 + 10 +

Annual Availability h/ yr --> 8,300 --> 8,300 --> 8,300

9.14 Liquid Hydrogen Storage:

Investment CostsECU/kg

ECU/kWh

0.6

1.3 - 1.7

0.6

1.3 - 1.7

0.6

1.3 - 1.7

Liquid H2 Storage 1994 2020 2050

Type: stationary

Utiliz. Storage Volume m3 270 270 270

Efficiency [5% transfer losses + 60 day storage] % approx. 90 approx. 90 approx. 90

Specific Capacity kWh/kW > 50 > 50 > 50

Pressure Level MPa < 1.5 < 1.5 < 1.5

Temperature Level °C - 253 (20 K) - 253 (20 K) - 253 (20 K)

Evaporation Rate % / d 0.1 0.1 0.1



Investment Costs

Energy (Dis-/)Charge Cost

ECU/kg-H2

cECU/kg-H2

18 - 25

45 - 75

20

70

20

60

Liquid H2 Storage 1994 2020 2050

Type: automobile

Utiliz. Storage Volume m3 0.130 0.130 0.130

Efficiency fuelling losses

15 d storage losses

total efficiency

%

%

%

10

25 - 30

60 - 65

5

15

80

< 5

15

< 80

Specific Capacity kWh/kW ?? ?? ??

Pressure Level MPa 0.3 - 0.4 0.3 0.3

Temperature Level °C - 253 - 253 - 253

Evaporation Rate % / d 1.7 - 2.0 1 1

9.15 Cryo-Adsorption Hydrogen Storage:

9.16 Transport of Gaseous Hydrogen in Pipelines


Annual Availability h/ yr 100 - 300 300 - 600 300 - 600

Investment Costs


ECU/kW

cECU/kWh

approx. 100,000 approx. 5,000 < 5,000

Cryo-Adsorption Storage 1994 2020 2050

Type: automobile

Utiliz. Storage Volume

m3

g H2

g carbon

0.01655

230

2,400

0.01655

230

2,400

0.01655

230

2,400

Efficiency % > 90 > 90 > 90

Specific Capacity g/ l 34 > 34 > 34

Pressure Level MPa 5.4 approx. 5 approx. 5

Temperature Level °C - 123 (150 K) > - 123 > - 123

Evaporation Rate % / d 0 0 0


Annual Availability h/ yr 300 - 600 600 - 1,000 600 - 1,000

Investment Costs ECU/kg-H2 500 ? 500 ? 500 ?

Pressurized H2 Pipeline

Long-Distance Transport 1994 2020 2050

Type: high pressure

Net Transport Capacity GWth 24 48 72

Annual Throughput

Annual Delivery

kWh/ yr

kWh/ yr

200 x 109

173 x 109

400 x 109

345 x 109

900 x 109

774 x 109

9.17 Transport of Gaseous Hydrogen in Pressurized Vessels:

9.18 Transport of Hydrogen in Cryogenic Liquid Form:

Efficiency % 86.6 86.2 86.2

Pressure Level Operation

Output

MPa

MPa

8

6.2

10

5.6

10

5.9

Pipeline Diameter mm 1,400 1,700 2,000



Investment Cost ECU/kWth 580 480 400

Pressurized H2 Transport Vessel 1994 2020 2050

Type: large train cargo


Net Capacity MWth 9 9 9


Specific Capacity kWh/kW 3.6 3.6 3.6





Investment Costs ECU/kW 100 10O 100

Containerized Liquid Hydrogen Storage in Mobile Transport 1994 2020 2050

Type: vacuum super-insulation ISO 40 ft

LAL ISO 40 ft

ISO 40 ft

trans. shield

Geom. Storage Volume

Utiliz. Storage Volume

m3

m3

45

40.5

55

49.5

60

54

9.19 Hydrogen in Passenger Cars:

Efficiency (ref. holding time, incl. transf.) % approx. 80 approx. 90 approx. 95

Specific Capacity (ref. quantity delivered over chain) kWh/kW 4,700 5,300 6,100

Max. Pressure Level MPa 1.2 0.5 0.4


Heat Leak W 50 45 40


Holding Time d 30 30 30



Investment Costs ECU/kW 1,200 1,000 900

Containerized Maritime LH2 Transport 1994 2020 2050

Type: vacuum super-insulation 5 barge containers in carrier ship

5 barge containers in carrier ship

5 discon. tanks in SWATH carrier ship


Efficiency (incl. transf.) % 90 - 95 95 95

Specific Capacity kWh/kW 1,900 1,900 ??




Holding Time d 30 - 50 30 - 50 30 - 50



Investment Costs


(incl. ship + 5 tanks)

ECU/kW

cECU/kWh

1,160

2.5

1,000

2

< 1,000

< 2

Liquid Hydrogen Passenger Car 1994 2020 2050

Type: LH2 travel sedan travel sedan travel sedan travel sedan

Propulsion Concept ICE/ EMF ICE/ EMF ICE/ EMF

Annual Driving Range km 10,000 50,000 50,000

Propulsion Power kWth 120 120 120

LH2 Fuel Consumptionkg/ 100 km

l/ 100 km

2.88

41

2.3

33

1.9

27

Tank Storage Volume l 122 130 130

Tank Evaporation Rate %/ d < 2 1.7 < 1


Temperature Level °C - 253 - 253

LH2 Tank Fuelling Losses % 5 - 10 2 2

Refuelling Time h 0.2 - 1.0 0.1 0.1

NOx Emission g/ kWh < 1 < 0.1 < 0.1


Investment Costs ECU/kW 2,000 450 400

Metal Hydride

Hydrogen Passenger Car 1994 2020 2050

Type: MH2 sedan [1.5 t] city car [1.0 t] city car [< 1.0 t]

Propulsion Concept ICE/ EMF ICE/ IMF ICE/ IMF



GH2 Fuel Consumption

kg/ 100 km

m3/ 100 km

3.0

33.3

1.2

13.3

1

11.0

Tank Storage Volume m3 45 33 28

Max. Pressure Level MPa < 5 < 5 < 5


GH2 Tank Fuelling Losses % thermal thermal thermal

Refuelling Time h 0.25 0.17 0.1

9.20 Hydrogen in City Buses:

NOx Emission ppm from lubricant oil from lubricant oil from lubricant oil


Investment Costs ECU/kW 600 450 400

Liquid Hydrogen Fuel Cell Car 1994 2020 2050

Type: mid size sedan

[1.5 t]

city travel car

[1.0 t]

city travel car

[< 1.0 t]

Propulsion Concept PEM-FC electric PEM-FC electric PEM-FC electric


Propulsion Power

kWe, FC

kWe, Battery

30

50

40

25

60

-

LH2 Fuel Consumption kg/ 100 km 1.5 0.55 0.4

Tank Storage Volume l LH2 60 55 20

Tank Evaporation Rate % / d 1.7 - 2.0 1.0 - 1.5 1.0



LH2 Tank Fuelling Losses % 10 5 < 5


NOx Emissionppm

g/ kWh

0

0

0

0

0

0


Investment Costs ECU/kW 4,000 500 - 700 500

Liquid Hydrogen City Bus 1994 2020 2050

Type: LH2 'MAN type'

Propulsion Concept ICE/ EMF ICE/ IMF ICE/ IMF




l/ 100 km

12

170

10

140

9

125


Tank Evaporation Rate %/ d < 3 < 3 < 3



LH2 Tank Fuelling Losses % 10 3 2


NOx Emission g/ kWh < 7 < 1 < 1


Investment Costs ECU/kW 10,000 1,500 1,200

Compressed Hydrogen City Bus 1994 2020 2050

Type: CGH2 'MB type'

Propulsion Concept ICE/ IMF ICE/ IMF ICE/ IMF



GH2 Fuel Consumptionkg/ 100 km

l/ 100 km

12

170

10

140

9

125

Tank Storage Volume l 450,000 450,000 450,000

Max. Pressure Level MPa 30 30 30



NOx Emission g/ kWh < 1 < 1 < 1


Investment Costs ECU/kW 5,000 1,300 1,100

9.21 Hydrogen in Ship Applications:

Liquid Hydrogen City Bus 1994 2020 2050

Type: LH2 'Ansaldo type'

Propulsion Concept PEM-FC electric PEM-FC electric PEM-FC electric


Propulsion Power

kWe, FC

kWe, Battery

50

70

120

-

100

-


l/ 100 km

9

127

7.5

106

5.5

78


Tank Evaporation Rate % / d < 3 1.7 1.5



LH2 Tank Fuelling Losses % 10 3 2


NOx Emissionppm

g/ kWh

0

0

0

0

0

0


Investment Cost ECU/kW 6,000 2,300 2,300

Liquid Hydrogen Carrier Ship 1994 2020 2050

Type: LH2 Fuel Storage

Propulsion Concept Internal Combustion Engine

Electric Drive

Steam Injected Gas Turbine

Electric Drive

PEM FC

Electric Drive

Ship length m 180 320 320

Ship Displacement t 18,700 104,000 104,000

LH2 Transport Capacity t 1,000 8,150 8,150

9.22 Hydrogen in Aviation:

Annual Operating Range km/ yr 170,000 200,000 200,000

Trial Speed km/h 32.4 31.5 31.5

Propulsion Power

Efficiency Engine

kW

%

10,600

45

41,000

50

41,000

55 - 60

LH2 Fuel Consumption kg/ km 14 95 85 - 80

Net Tank Storage Volume m3 2,200 17,000 15,000 - 14,000

Tank Evaporation Rate % / d 0.1 0.1 0.1



LH2 Tank Fuelling Losses % < 10 < 5 2.5


NOx Emission g/ kWh X.0 < 1.0 0


Investment Costs

Cost per Transport of Energy

ECU/kW

ECU/kWhth

3,200

1.018

6,000

0.905

approx. 6,000

approx. 0.905

Liquid Hydrogen Aircraft A 310 2000 2020 2050

Type: LH2 DASA Airbus Demonstrator Series Aircraft Series Aircraft

Propulsion Concept LH2 Jet Turbine LH2 Jet Turbine LH2 Jet Turbine

Operating Range km 1,850 5,000 5,000

Annual Operating Hours h / yr - 3,500 3,500

Propulsion Thrust kN 2 x 230 2 x 230 2 x 230

LH2 Fuel Consumption kg/ Block Fuel 770nm 4,100 4,000 3,600

Tank Storage Volumem3

t

84

6

190

13.5

170

12

Tank Evaporation Rate % / d approx. 3 approx. 3 approx. 3


9.23 Electricity Production from Hydrogen via Internal Combustion and Gas Turbine Processes:


LH2 Tank Fuelling Losses % 10 5 2.5


NOx Emission

H2O Emission

g/ kg H2 Fuel

g/ kg H2 Fuel

g/ kg kerosene equiv.

15

9,000

3,300

< 15

9,000

3,300

< 15

9,000

3,300


Investment Costs per Aircraft (Production of in Total 450 Units, 1.5 BECU Total Development Costs)

MECU < 73 73 73

Internal Combustion Engine (ICE) Industrial Cogeneration System 1994 2020 2050

Unit Capacity kWe 1,200 1,200 1,200

Cogen.System Capacity kWe 2,400 2,400 2,400

Efficiency electric

thermal

total

%

%

%

37 (H2/

48 Air)

85

> 40 (H2/

45 Air)

> 85

> 40 (H2/

45 Air)

> 85

Pressure Level H2

Air

MPa

MPa

0.1 - 0.25

0.1 - 0.25

0.5

0.5

0.5

0.5

Operating Temperature °C > 130 > 130 > 130



Investment Costs

[total installed plant] ECU/kW 900 1,150 1,150

Unit Capacity

- Electric, Gas

- Electric, Steam

- Thermal

kWe

kWe

kWth

8,600

8,000

18,000

8,600

8,000

18,000

8,600

8,000

18,000

Efficiency electric

thermal

total

%

%

%

47 (H2/

35 Air)

82

49 (H2/

33 Air)

82

49 (H2/

33 Air)

82

Pressure Level H2

Air

MPa

MPa

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

Operating Temperature °C


Annual Availability h / yr 6,000 6,000 6,000

Investment Costs

[total installed plant ECU/kW 1,200 1,200 1,200

Intercooled Steam Injected Gas Turbine (ISTIG) Peak Electricity Generation System 1994 2020 2050

Unit Capacity

- Electric kWe 100,000 100,000 100,000

Efficiency electric %

45 - 50

(H2/ Air)

55

(H2/ Air)

55

(H2/ Air)

Pressure Level H2

Air

MPa

MPa

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

0.11 - 0.2

Operating Temperature °C


Annual Availability h / yr 800 800 800

Investment Costs

[total installed plant ECU/kW 750 750 750

Gas Turbine/ Steam Turbine (CCGT) Industrial Cogeneration System 1994 2020 2050

9.24 Electricity Production from Hydrogen via Fuel Cell Processes:

Proton Exchange Membrane (PEM) Fuel Cell System 1994 2020 2050

Unit Capacity kWe 10 10 - 40 10 - > 40

System Capacity kWe 10 - 100 10 - 500 10 - > 500

Efficiency UHV (O2)

LHV (Air)

%

%

56

51

64

59

65

60

Pressure Level H2

O2

Air

MPa

MPa

MPa

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2


Load Range % 25 - 150 25 - 150 25 - 150


Annual Availability h/ yr

Investment Costs

[total installed plant] ECU/kW approx. 4,000 300 250

Alkaline Fuel Cell (AFC) System 1994 2020 2050

Unit Capacity kWe 7 10 - 40 10 - > 40

System Capacity kWe 7 - 100 10 - 200 10 - > 200

Efficiency UHV (O2)

LHV (Air)

%

%

61

54

75

69

75

69

Pressure Level H2

O2

Air

MPa

MPa

MPa

0.15

0.15

0.15

1.0

1.0

1.0

1.0

1.0

1.0


Load Range % 25 - 150 25 - 150 25 - 150



Investment Costs

[total installed plant ECU/kW approx. 3,000 1,000 700

Falling Film Alkaline Fuel Cell System (FFFC)1994

(Laboratory) 2020 2050

Unit Capacity kWe 3 3 - 3,000 3 - 5,000

System Capacity kWe 3 up to 30,000 up to 700,000

Efficiency Electric

Thermal

%

%

77

20 - 40

77

20 - 40

77

20 - 40

Current Density H2/O2

H2/Air

Cell Voltage H2/O2

H2/Air

kA/ m2

kA/ m2

mV

mV

7

3

950

750

7

3

950

750

7

3

950

750

Pressure Level H2/O2

H2/Air

MPa

MPa

2.1

0.1

2.6

0.1

2.6

0.1

Operating Temperature

H2/O2

H2/Air

°C

°C

100

80

100

80

100

80

Load Range % 5 - 300 5 - 300 5 - 300

Plant Lifetime yr ? 25 25

Annual Availability h/ yr ? 8,300 8,300

Investment Costs

[total installed plant ECU/kW ? 150 100

Phosphoric Acid Fuel Cell

(PAFC) Cogeneration System 1994 2020 2050

Unit Capacity kWe 200 1,000 1,000

Cogen.System Capacity kWe 10,000 100,000 > 100,000

Efficiency electric

thermal

total

%

%

%

45

38

83

50

42

92

50

42

92

Pressure Level H2

Air

MPa

MPa

0.3

0.3

0.5

0.5

0.5

0.5

Operating Temperature °C 150 - 200 150 - 200 150 - 200



Investment Costs

[total installed plant] ECU/kW approx. 3,000 1,250 1,250

Molten Carbonate Fuel Cell

(MCFC) Cogeneration System 1994 2020 2050

Unit Capacity kWe < 100 1,000 1,000

Cogen.System Capacity MWe < 0.1 2 - 50 2 - 50

Efficiency electric

thermal

total

%

%

%

55 (CH4/

38 Air)

93

57 (H2/

35 Air)

92

57 (H2/

35 Air)

92

Pressure Level H2

Air

MPa

MPa

0.3

0.3

0.5

0.5

0.5

0.5




Investment Costs ECU/kW approx. 3,000 1,250 1,250


9.26 Hydrogen in Catalytic Converter Processes:

Solid Oxide Fuel Cell

(SOFC) Cogeneration System 1994 2020 2050

Unit Capacity kWe < 10 100 > 100

Cogen.System Capacity MWe < 0.05 0.2 - 2 > 2

Efficiency electric

thermal

total

%

%

%

60 (CH4/

35 Air)

95

57 (H2/

38 Air)

95

57 (H2/

38 Air)

95

Pressure Level H2

Air

MPa

MPa

0.5

0.5

1.5

1.5

1.5

1.5

Operating Temperature °C 800 - 1,000 800 - 900 800



Investment Costs

[total installed plant] ECU/kW approx. 3,000 1,000 < 1,000

H2/O2 - H2/Air Catalytic Burner 1994 2020 2050

Unit Capacity kWe 1 - 30 1 - 50 1 - 50

Efficiency thermal (air)

- stove

- heating

%

%

%

~ 100

50

90

~ 100

50

90

~ 100

50

90

Emissions H2O

< 1ppm NOx

H2O

< 1ppm NOx

H2O

< 1ppm NOx

Operating Temperature °C 800 600 - 800 600 - 800

H2 Input Pressure MPa 10-3 10-3 10-3



Investment Costs ECU/kW 1,000 50 50

9.27 Hydrogen in Other Industrial Uses:

Hydrogen Reduction of Iron Ore 2000 2020 2050

Type of DRI Process modified FB

LURGI Circofer advanced 1994 process

advanced 1994 process

Unit Capacity t-HM/ Unit 500,000 500,000 500,000

European Total Production 106 t-HM/ yr 1 15 130

Product Balance

Fine Ores

Dry Coal

Syngas-H2

O2

Electrical Energy

Annual Syngas-H2 Consumption

t/ t-HM

t/ t-HM

Nm3/ t-HM

Nm3/ t-HM

kWh/ t-HM

109 Nm3/ yr

1.52

0

600

310

100

0.6

1.52

0

600

310

100

approx. 9

1.52

0

600

310

100

approx. 78


Capacity Factor h / yr 8,300 8,300 8,300

Investment Costs

[total installed plant ECU/t-HM 180 100 100

Direct H2/ O2 - Steam Generator 1994 2020 2050

Unit Capacity MWe 43 70 70

Efficiency thermal % 99 99.5 99.5

Steam Pressure Level MPa 4 - 9 4 - 9 4 - 9

Steam Output kJ/s 36 59 59

Operating Temperature °C 560 - 950 560 - 950 560 - 950


Annual Availability h / yr 18 18 18

Investment Costs

[total installed plant] ECU/kW 60 55 55

9.28 Hydrogen in the Domestic Sector:

Pressurized Electrolysis/ Fuel Cell Redox Unit 1994 2020 2050

Type of Membrane Nafion® 117 ? ?

Unit Capacity kWe 1 1 - 10 1 - 10

Efficiency EL-HHV

EL-LHV

FC-HHV

FC-LHV

%

%

%

%

82

69

60

50

90

76

70

60

95

80

75

65

Cell Area

Number of Cells

m²

-

0.005

30

0.01

50

0.01

100

Pressure Level

Temperature Level

MPa

°C

3

80

3

100

3

100

Overload Factor % 50 50 50



Investment Costs

[total installed plant] ECU/kW 50,000 350 300

HYDROGEN ENERGY - netinform · HYDROGEN ENERGY by Reinhold Wurster and Dr. Werner Zittel,...

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Transcript of HYDROGEN ENERGY - netinform · HYDROGEN ENERGY by Reinhold Wurster and Dr. Werner Zittel,...