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Feasibility Study of Hydrogen Production Using Electrolysis and Wind Power in Patagonia, Argentina

Permanent Link: http://ufdc.ufl.edu/UFE0022329/00001

Material Information

Title: Feasibility Study of Hydrogen Production Using Electrolysis and Wind Power in Patagonia, Argentina
Physical Description: 1 online resource (107 p.)
Language: english
Creator: Giudici, Federico
Publisher: University of Florida
Place of Publication: Gainesville, Fla.
Publication Date: 2008

Subjects

Subjects / Keywords: Mechanical and Aerospace Engineering -- Dissertations, Academic -- UF
Genre: Mechanical Engineering thesis, M.S.
bibliography   ( marcgt )
theses   ( marcgt )
government publication (state, provincial, terriorial, dependent)   ( marcgt )
born-digital   ( sobekcm )
Electronic Thesis or Dissertation

Notes

Abstract: Argentina has been experiencing an important economic growth in the last years, with a consequent increase in energy consumption that is being covered with a higher consumption of fossil fuels. In order to support its development, Argentina must assure a local sustainable energy source, making use of its renewable energy sources. While there is a huge potential for wind power in Patagonia, it is very far from energy consumption centers. For long distance energy transmission, the use of hydrogen as an energy carrier could provide several advantages. This study evaluated the technical feasibility and estimated the cost of producing hydrogen with electrolysis utilizing electricity from a wind farm located in Patagonia, and transporting it using a 2,100 km pipeline. It was found that wind turbine technology is mature and commercially available although the cost of electricity produced in this way is still not competitive if environmental costs are not included. The electrolysis technology is also commercially available for small-scale production, but it is not proven yet for large-scale productions and research in this area is still necessary. The cost estimated for delivered hydrogen was found to be high compared with the price of fossil fuels it would replace. However, the environmental cost of using fossil fuels was not evaluated. Finally the water consumption was estimated and the possibility of using seawater analyzed.
General Note: In the series University of Florida Digital Collections.
General Note: Includes vita.
Bibliography: Includes bibliographical references.
Source of Description: Description based on online resource; title from PDF title page.
Source of Description: This bibliographic record is available under the Creative Commons CC0 public domain dedication. The University of Florida Libraries, as creator of this bibliographic record, has waived all rights to it worldwide under copyright law, including all related and neighboring rights, to the extent allowed by law.
Statement of Responsibility: by Federico Giudici.
Thesis: Thesis (M.S.)--University of Florida, 2008.
Local: Adviser: Ingley, Herbert A.

Record Information

Source Institution: UFRGP
Rights Management: Applicable rights reserved.
Classification: lcc - LD1780 2008
System ID: UFE0022329:00001

Permanent Link: http://ufdc.ufl.edu/UFE0022329/00001

Material Information

Title: Feasibility Study of Hydrogen Production Using Electrolysis and Wind Power in Patagonia, Argentina
Physical Description: 1 online resource (107 p.)
Language: english
Creator: Giudici, Federico
Publisher: University of Florida
Place of Publication: Gainesville, Fla.
Publication Date: 2008

Subjects

Subjects / Keywords: Mechanical and Aerospace Engineering -- Dissertations, Academic -- UF
Genre: Mechanical Engineering thesis, M.S.
bibliography   ( marcgt )
theses   ( marcgt )
government publication (state, provincial, terriorial, dependent)   ( marcgt )
born-digital   ( sobekcm )
Electronic Thesis or Dissertation

Notes

Abstract: Argentina has been experiencing an important economic growth in the last years, with a consequent increase in energy consumption that is being covered with a higher consumption of fossil fuels. In order to support its development, Argentina must assure a local sustainable energy source, making use of its renewable energy sources. While there is a huge potential for wind power in Patagonia, it is very far from energy consumption centers. For long distance energy transmission, the use of hydrogen as an energy carrier could provide several advantages. This study evaluated the technical feasibility and estimated the cost of producing hydrogen with electrolysis utilizing electricity from a wind farm located in Patagonia, and transporting it using a 2,100 km pipeline. It was found that wind turbine technology is mature and commercially available although the cost of electricity produced in this way is still not competitive if environmental costs are not included. The electrolysis technology is also commercially available for small-scale production, but it is not proven yet for large-scale productions and research in this area is still necessary. The cost estimated for delivered hydrogen was found to be high compared with the price of fossil fuels it would replace. However, the environmental cost of using fossil fuels was not evaluated. Finally the water consumption was estimated and the possibility of using seawater analyzed.
General Note: In the series University of Florida Digital Collections.
General Note: Includes vita.
Bibliography: Includes bibliographical references.
Source of Description: Description based on online resource; title from PDF title page.
Source of Description: This bibliographic record is available under the Creative Commons CC0 public domain dedication. The University of Florida Libraries, as creator of this bibliographic record, has waived all rights to it worldwide under copyright law, including all related and neighboring rights, to the extent allowed by law.
Statement of Responsibility: by Federico Giudici.
Thesis: Thesis (M.S.)--University of Florida, 2008.
Local: Adviser: Ingley, Herbert A.

Record Information

Source Institution: UFRGP
Rights Management: Applicable rights reserved.
Classification: lcc - LD1780 2008
System ID: UFE0022329:00001


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1 FEASIBILITY STUDY OF HYDROGEN PRODUCTION USING ELECTROLYSIS AND WIND POWER IN PAT AGONIA, ARGENTINA By FEDERICO A. GIUDICI A THESIS PRESENTED TO THE GRADUATE SCHOOL OF THE UNIVERSITY OF FLOR IDA IN PARTIAL FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE UNIVERSITY OF FLORIDA 2008

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2 2008 Federico A. Giudici

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3 To my nephew, Santino.

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4 ACKNOWLEDGMENTS I would like to thank m y family for the support they have given me all these years, even being so far from here. I am also very grateful to have had the opportunity to work with Dr. H. A. Ingley, III. He was not only a great advisor but also a friend. Also, I appreciate the effort of the members of my committee, Dr. Schueller and Dr. Sherif. Finally, I thank the people wo rking with the Fulbright Commission in the United States and Argentina for making this project possible.

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5 TABLE OF CONTENTS page ACKNOWLEDGMENTS...............................................................................................................4 LIST OF TABLES................................................................................................................. ..........7 LIST OF FIGURES.........................................................................................................................8 LIST OF ABBREVIATIONS........................................................................................................ 10 ABSTRACT...................................................................................................................................11 CHAP TER 1 INTRODUCTION..................................................................................................................12 Hydrogen as an Energy Carrier.............................................................................................. 12 Background......................................................................................................................12 Hydrogen as an Energy Carrier....................................................................................... 13 Renewable Energy and Energy Storage.......................................................................... 14 Hydrogen Production.......................................................................................................16 Hydrogen Storage............................................................................................................17 Energy Distribution.........................................................................................................20 Hydrogen Utilization.......................................................................................................22 Electrolyzers...........................................................................................................................23 Electrolysis of Water....................................................................................................... 23 Process Description.........................................................................................................24 Electrolyzers Classification.............................................................................................27 Alkaline electrolyzers............................................................................................... 28 PEM electrolyzer......................................................................................................29 Solid oxide electrolyzers.......................................................................................... 31 High-pressure electrolysis........................................................................................32 Relative Sizing of an Electrolyzer...................................................................................34 Water Cons um ption......................................................................................................... 34 By-Product Oxygen......................................................................................................... 36 Current State of Electrolyzers Development................................................................... 36 Wind Power............................................................................................................................37 Initial Site Selection........................................................................................................40 Micrositing......................................................................................................................41 Argentina and Patagonia Case................................................................................................ 42 Introduction to Feasibility Study............................................................................................46 2 METHODOLOGY................................................................................................................. 49 Process Description................................................................................................................49 Process Schematic........................................................................................................... 49

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6 Capacity Calculation....................................................................................................... 50 Wind farm................................................................................................................51 Electrolysis system................................................................................................... 51 Water consumption.................................................................................................. 52 Storage......................................................................................................................52 Hydrogen pipeline....................................................................................................53 Technical Feasibility.......................................................................................................... .....53 Economic Feasibility........................................................................................................... ...54 Capital Investment........................................................................................................... 54 Operating Costs............................................................................................................... 55 Return on Investment......................................................................................................55 Hydrogen Cost.................................................................................................................55 Data acquisition and model assumptions........................................................................ 56 Wind speeds and wind farm..................................................................................... 56 Electrolysis system................................................................................................... 60 Storage and distribution facilities............................................................................. 63 By-product oxygen................................................................................................... 64 3 RESULTS...............................................................................................................................66 Technical Feasibility.......................................................................................................... .....66 Economic Feasibility........................................................................................................... ...66 Water Cons um ption.............................................................................................................. ..71 4 CONCLUSIONS.................................................................................................................... 73 Conclusions.............................................................................................................................73 Recommendations for Future Studies..................................................................................... 74 APPENDIX A HYDROGEN PROPERTIES.................................................................................................75 B MAPS.....................................................................................................................................79 C WIND POWER CALCULATION DATA............................................................................. 84 D CALCULATIONS.................................................................................................................. 90 LIST OF REFERENCES.............................................................................................................103 BIOGRAPHICAL SKETCH.......................................................................................................107

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7 LIST OF TABLES Table page 1-1 Hydrogen and other fuels pr operties related to storage. .................................................... 18 1-2 Types of electrolyzers........................................................................................................28 1-3 Change of hydrogen production by pressure .....................................................................33 1-4 ASTM specifications for reagent water............................................................................. 35 1-5 Characteristics of largest commercially available electrolyzers as of December 2003 ..... 37 1-6 Standard wind classification at 50 meters. .........................................................................39 1-7 Renewable energy extraction limits for Argentina and the world ..................................... 44 2-1 Typical breakdown cost for a 10 MWe wind farm............................................................56 2-2 Electrolyzer energy consumption estimated developement............................................... 60 2-3 Electrolyzer cost data.........................................................................................................62 2-4 Pipeline installati on costs in 2008 dollars ..........................................................................63 A-1 Lower and higher heating values of hydrogen and fuels.................................................. 75 C-1 REpower 5M technical data............................................................................................... 85 C-2 Wind power data for the wind farm site utilizing a single REpower 5M turbine. .............88 D-1 Capacity calculation assumptions...................................................................................... 90 D-2 Cost calculation assumptions............................................................................................. 91 D-3 Capacity calculations...................................................................................................... ...92 D-4 Lowest cost calculations fo r different plant capacities.. .................................................... 93 D-5 Lowest hydrogen cost breakdown for different plant capacities....................................... 96 D-6 Highest cost calculations fo r different plant capacities. .................................................... 97 D-7 Highest hydrogen cost breakdown for different plant capacities..................................... 100 D-8 Hydrogen cost breakdown without transportation. ..........................................................101 D-9 Comparison of different estimations for the cost of hydrogen produced. ....................... 102

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8 LIST OF FIGURES Figure page 1-1 Simple alkaline electrolyzer............................................................................................... 25 1-2 Alkaline electrolyzers..................................................................................................... ...28 1-3 Schematic of electrolysis cell with PEM........................................................................... 30 1-4 Major components of a horizontal axis wind turbine........................................................ 39 1-5 Wind farm array schematic................................................................................................ 41 1-6 Argentine population....................................................................................................... ..43 1-7 Composition of Argentine energy offer in 2006................................................................ 44 1-8 Evolution of the composition of Argentine electricity generation..................................... 45 2-1 Process schematic.......................................................................................................... ....50 2-2 Annual oxygen production in Argentina............................................................................ 64 3-1 Hydrogen cost for different production capacities............................................................. 67 3-2 Calculated required wind farm area................................................................................... 68 3-3 Total capital investment for different production capacities ............................................. 69 3-4 Comparison of the estimated hydrogen cost against different published estim ations....... 69 3-5 Comparison of electricity costs us ed to estim ate the hydrogen cost................................. 70 3-6 Estimated hydrogen cost breakdown (lowest cost)............................................................71 3-7 Water consumption for different plant capacities.............................................................. 72 A-1 Energy density by weight for various storage forms.........................................................76 A-2 Energy density by volume for various storage forms........................................................ 77 A-3 Cycle efficiency for various storage forms........................................................................ 78 B-1 Location of Argentina in the world.................................................................................... 79 B-2 Argentine map showing average wind speed at 50 m above ground and Patagonia......... 80 B-3 Patagonias topography..................................................................................................... .81

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9 B-4 Argentine population di stribution per province. ................................................................ 82 B-5 Patagonia map showing average wind sp eed at 50 m above ground and permanent rivers..................................................................................................................................83 C-1 REpower 5M power curve.................................................................................................84 C-2 SIG Elico................................................................................................................. .........86 C-3 SIG Elico, main screen.................................................................................................... 86 C-4 SIG Elico, wind power information screen...................................................................... 87 C-5 Wind rose for data point 1.................................................................................................88 C-6 Probability density function of the w ind speed for data point 1........................................ 89

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10 LIST OF ABBREVIATIONS AC: Alterna te current. ASME: American Society of Mechanical Engineers. ASTM: American Society for Testing and Materials. DC: Direct current. FC: Fuel cell. GJ: Gigajoule (109 joules). gpm: Gallons per minute. GW: Gigawatts (109 watts). HHV: Higher heating value. HVDC: High-voltage direct current. ktoe: Kilo tonne of oil equivale nt (1 ktoe = 41.868 GJ = 11.63 MWh). lpm: Liters per minute. MPa: Mega Pascal (106 Pascal). MW: Mega Watt (106 watts). MWe: Electrical megawatt. MWh: Megawatt-hour. Nm3: Normal cubic meter. It is a measure of quantity of gas, equal to a cubic meter at 273.15 K and 101.325 kPa. PEM: Polymer electrolyte membrane or proton exchange membrane. PV: Photovoltaic. scf: Standard cubic foot. It is a measure of quantity of gas, equal to a cubic foot at 60F and either 14.696 pounds pe r square inch (1 atm) or 14.73 psi (30 inHg) of pressure. SMR: Steam methane reformation. STP: Standard temperature and pressure (25C and 1 atmosphere pressure).

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11 Abstract of Thesis Presen ted to the Graduate School of the University of Florida in Partial Fulfillment of the Requirements for the Degree of Master of Science FEASIBILITY STUDY OF HYDROGEN PRODUCTION USING ELECTROLYSIS AND WIND POWER IN PAT AGONIA, ARGENTINA By Federico A. Giudici August 2008 Chair: H. A. Ingley, III Major: Mechanical Engineering Argentina has been experiencing an important economic growth in the last years, with a consequent increase in energy consumption that is being covered with a higher consumption of fossil fuels. In order to support its development, Argentina must assure a local sustainable energy source, making use of its renewable energy sources. While there is a huge potentia l for wind power in Patagonia, it is very far from energy consumption centers. For long distance energy transmission, the use of hydrogen as an energy carrier could provide se veral advantages. This study evalua ted the technical feasibility and estimated the cost of produci ng hydrogen with electroly sis utilizing electricity from a wind farm located in Patagonia, and transpor ting it using a 2,100 km pipeline. It was found that wind turbine technology is mature and commercially available although the cost of electricity produced in this way is still not competitive if environmental costs are not included. The electrolysis technology is also commercially available for small-scale production, but it is not proven yet for largescale productions and research in this area is still necessary. The cost estimated for delivered hydrogen was found to be high compared with the price of fossil fuels it would replace. However, the environmenta l cost of using fossil fuels was not evaluated. Finally the water consumption was estimated an d the possibility of using seawater analyzed.

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12 CHAPTER 1 INTRODUCTION The objective of this thesis is to evaluate the feasibility of utilizing hydrogen as an energy carrier for the electricity produced by wind turbines in the Argen tine Patagonia. W hile there is a huge potential for wind power in Patagonia, it is around 2,100 km away from energy consumption centers. The electricity produced in this way, could be delivered utilizing hightension lines, but the use of hydr ogen would provide several advantages that could make this latter option more attractive. There are studies comparing hydrogen pipelines with high voltage transmission for long distance distribution that show that hydrogen would be the best option for distances over 1,000 or 2,250 km (620 or 1400 mile s) depending on the study [1]. Also these hydrogen pipelines would provide additional en ergy storage, and the use of hydrogen would solve the problem of linking the production with the demand. Fina lly, hydrogen can be utilized with many different technologies, lik e fuel cells, internal combustion engines, etc; that are used in a wide range of applications, from electricity generation to transportation. All these reasons might make hydrogen a viab le option to meet Argentine energy needs. This thesis evaluated this option by calculating the cost of hydrogen delivered to Buenos Aires, the technologies currently available, and the water resources necessary. Hydrogen as an Energy Carrier Background Significant impacts on th e world economy are based on the use of fossil fuels. The adoption of these fuels allowed for an incredibly rapid development in the last 150 years, but its use also brought unexpected consequences. Th eir use caused pollution and the generation of greenhouse gases that contribute to global warmi ng. There is still discus sion if the accumulation of CO2, a product of the combustion of fossil fuels, is the main contributor to global warming,

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13 but there is no doubt that the levels of this gas in the atmosphere are increasing in a way that cannot be naturally balanced by th e environment. Finally, there ar e limited fossil fuel reserves on the planet. These reserves are being depleted and becoming increasingly difficult to extract, causing energy costs to escalate and making other energy sources more economically feasible. There are also political and economical ramifi cations of this dependence on fossil fuels. Political instabilities greatly affect fossil fuel prices, whic h reflects in the economies of importing and exporting countries. In the particular case of developing countries, as they require increasing amounts of energy for their growing ec onomies, the availability and price of fossil fuels play a determining fact or in their development. As the world population and development continue to increase, the energy demand will increase too. It is generally accepted that soone r or later the oil produc tion will peak and then begin to decrease. This could be caused by the in evitable depletion of the resources, or what would be desirable, by the gradual introduction of new, more environmentally friendly, renewable energies. Governments ar e starting to realize that it is necessary to address this problem now, so different efforts are being made to evaluate the possible sustainable alternatives. Hydrogen as an Energy Carrier One option that has been proposed for a l ong tim e is the use of hydrogen as an energy carrier. Hydrogen has many properties that make it a good choice for this use. Examples include: The simplest and most abundant element. High energy density (energy content per unit weight). Non-polluting utilization. Can be used for transportation, generati on of electricity and production of heat. Efficient utilization and conversion. Safe when using the appropriate technology. Can be produced from numerous feedst ocks or renewable energy sources. It can be stored as liquid, gas or solid as a metal hydride.

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14 It can be transported over large distances with very low losses. Tables A-1 in the appendix lists differe nt properties for hydrogen and other fuels. Even though hydrogen is the most common element, it cannot be f ound naturally in the gaseous state, so it is not an energy source by itself and must be produced. Also, hydrogen utilization is non-po lluting, since the only product of combustion is water (when utilized with the appropriate technologies); but the wa y it is produced could be polluting. It is for these reasons that a hydrogen economy has been frequently presented as a sustainable solution to the energy problem. A hydrogen economy refers to a system where hydrogen is the principal energy ca rrier. While it has many advantag es to the current utilization of fossil fuels, it can be argued that there are many losses involved in all the transformations necessary. The production of energy will always require th e use of resources, so it is desirable to obtain the highest efficiency po ssible. But efficiency is not the only criteria when evaluating sustainability. Other factors, like environmental impact or associated resources depletion should be evaluated through a life cycle analysis. While in the beginning establishing a hydrogen economy might be too ambitious, hydrogen could be the best answer to smaller sc ale problems, like energy storage, storage for intermittent renewable energies or energy transport along long distances. Renewable Energy and Energy Storage Many renew able energy sources (like wind a nd solar) are intermittent and fluctuating naturally. In photovoltaic systems, energy production is dependent on the availability of sunlight, and in wind turbines on wind blowing in a determ inate velocity range. In resources with these characteristics, supplemental conversion by energy st orage is essential if th e demand is to be met at all times.

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15 The ability to store the electrical energy ma kes the power system a reliable source of electric power both day and ni ght or under any weather condition. PV systems with battery storage are used all over the world to provide electricity for lights, sensors, recording equipment, switches, appliances, telephones, televisions, etc. Larger wind power systems with battery backup, are being developed and tested in di fferent parts of the world, and even hybrid wind/solar systems, that complement each other, are being tested and optimized. There are also other reasons for including en ergy storage in the system. For example, it provides stabilization of the electricity output, the possibility to regulate the voltage and control the system frequency, manage peak loads, improve power quality, defer upgrade investments and provide uninterruptible power for many industrial and commercial applications. As written before, the energy produced by these sy stems must then be stored if its intended to use it when energy production is unavailable. There are different technologies to achieve the goal of storing different forms of energy and re leasing it later according to the needs. Some different forms in which energy can be stor ed include heat, mechanical, chemical or electrochemical. Figures A-1 and A-2 in the appendix compare different storage methods. Ideal requirements for energy storage would be rapid access to the energy stored and the ability to supply it in th e different energy forms. In the case of wind power and PV systems, an energy storage system that allows the regeneration of electricity with high cycle efficiency is necess ary. There are some systems that are particularly suitable to st ore high-quality forms of ener gy, like electric or mechanical. (Figure A-3) One system that is being studied and tested is the combination of electrolyzers and fuel cells. The idea is to produce hydrogen using an electrolyzer when the production exceeds the

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16 demand, store it, and then use it to produce electric ity in a fuel cell when the demand exceeds the production. Another option is to use a regenerative fuel cell that is a fuel cell that can work both ways, producing electricity with a hydrogen supply, or producing hydrogen with a DC source. Hydrogen Production The m ain processes currently used to produ ce hydrogen are steam reformation of natural gas, partial oxidation of hydrocarbon s, and coal gasification; all processes that use fossil fuels as a feedstock. With these methods, and depending on the cost of the fuel utilized, the cost of hydrogen is between 6-14 $/GJ [2]. Electroly sis is used when the purity of hydrogen is important, and new ways of producing hydrogen are being investigate d, including biological production using algae, photo-electrochemical water splitting and thermochemical processes. The methods of production have different costs and genera te different emissions of pollutants. Any sustainable approach to the problem should involve the use of renewable energies that would limit the impact on the environment. Following this line of thought, it is proposed to use electrolysis of water along with electricity genera ted from renewable sources. In this case, environmentally speaking, the main concern would be the water usage needed to produce the hydrogen, realizing that wate r is also a valuable resource. The approach to hydrogen production that most governments are analyzing is the one using fossil fuels because of the lower costs. But from the sustainability point of view, this does not solve the problem of depleting the fossil fuel resources, and carbon sequ estration technologies would be needed to eliminate the emission of green house gases. Even with CO2 storage, there is still risk of leakage. Steam methane reformation (SMR) is a ma ture technology that produces the hydrogen with the lowest cost. The process consists of re acting the feedstock (usually methane) with steam at elevated temperatures between 700 and 925C to produce syngas. The syngas is a mixture of

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17 hydrogen and carbon monoxide (CO) that then goes through a water shift reaction that increases the content of hydrogen. The mixture obtained contains hydrogen and CO2. Finally the hydrogen is separated from the CO2 using different methods like membrane separation, wet scrubbing or pressure swing absorption. Partial oxidation of heavy hydrocarbons catalyt ically reacts liquid or gaseous hydrocarbons with superheated steam and oxygen at around 60 0C. The reaction produces a mixture of H2, CO and CO2, and a shift reaction is again used to incr ease the content of hydrogen, that is then separated from the mixture. The feedstock is co mbusted to obtain the en ergy required to drive the process, producing pollutants like NOX, SOX and CO2. To avoid the emission of NOX pure oxygen must be used for the combustion, wh ich requires an air separation plant. Coal gasification is a process used to c onvert solid carbon into a syngas, composed primarily of carbon monoxide, hydrogen and othe r hydrocarbons such as methane. In the gasifier, coal and steam are intr oduced at high pressure and temper ature. Also a lean quantity of oxygen is delivered, so the coal partially oxid izes instead of burning, and produces CO and H2. Finally, a shift reaction is used to transform the CO in additional H2 in the presence of steam. Coal has less H2 than other hydrocarbons, so the H2 comes principally from the steam. This means that big quantities of water are used in this process. Also big quantities of CO2 are produced, so it is necessary to apply capture a nd sequestration technolog ies that are still not completely developed. The same process can be used with a wide range of solid feedstocks like heavy refinery residuals or biomass. Hydrogen Storage Like other gases, hydrogen can be stored under pr essure in containers that are suitable for its high diffusivity, but the energy density in volu m e obtained in this way is very low. Other storage methods, that are being curr ently investigated, try to make use of different properties of

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18 hydrogen to solve this problem. Liquid hydr ogen and hydrogen combined in metal hydride structures or carbon based nanotubes are some of the alternatives being investigated. Table 1-1 summarizes some properties of hydroge n and other fuels that are important for storage. Particularly the hi gh diffusivity, along with the wi de range of flammability and explosivity, require a better cont ainer structure than in the case of storing other gaseous fuels. Table 1-1. Hydrogen and other fuels properties related to storage. Property Hydrogen Methane Gasoline Minimum energy for ignition (10-3J) 0.02 0.29 0.24 Flame temperature (C) 2045 1875 2200 Auto-ignition temperature in air (C) 585 540 230-500 Maximum flame velocity (m/s) 3.46 0.43 Range of flammability in air (vol. %) 4-75 5-15 1.0-7.6 Range of explosivity in air (vol. %) 13-65 6.3-13.5 1.1-3.3 Diffusion coefficient in air (10-4 m2/s) 0.61 0.16 0.05 Compressed gas storage is the simpler form of storing hydrogen. Hydrogen must be compressed because of its low volume density, as explained before, but even compressing to 2030 x 106 Pa, which is the pressure used in current cont ainers, the density obtained is still less than 10% of that of oil (Figures A1 and A-2). This is one of the main disadvantages of using hydrogen, but on the other hand the higher efficiency achieved in fuel cells or other hydrogen technologies partially compensates for this weak ness. For large storage needs, it has been proposed to use natural caverns, aquifers, or depl eted petroleum and natural gas fields for storing compressed hydrogen, but of course this depends on the availability of such resources. Also containers capable of resisti ng up to 70 MPa are being develope d using materials like Kevlar fibers [3]. It is practical to achieve storage densities higher than 0.05 kg of hydrogen per 1 kg of total weight [2]. Another concern with this kind of storage is the need of a compressor and its associated energy consumption. This can be solv ed using high-pressure electrolysis, a very efficient way of obtaining hydrogen at high pressure.

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19 Another option for compressed gas storage is using the pipelines used for the transport of hydrogen. Hydrogen pipelines can be hundreds of m iles long, which repres ent a large volume of hydrogen. A large amount of hydrogen can then be stored or recovere d with a slight difference in the operating pressure of the pipeline [4]. The next storage option for hydrogen is lique faction. This increases the volume density, but since the temperature for hydrogen liquefaction is 20K, the containers and connections must be extremely well insulated. Also very clea n hydrogen is required along with several compression cycles to obtain an energy density between 4 or 5 times lower than conventional fuels (Figures A-1 and A-2). Als o, the liquefaction process require s an amount of energy equal to one third of the energy stored in the liquefied hydrogen [2]. Metal hydride storage is a promising technology in which certain metal alloys are used to store hydrogen. Hydrogen atoms are inserted in spaces inside the lattice of suitable metals and/or alloys forming metal hydrides. Th e storage is safe, near loss-fr ee at ambient pressures, and the lattice absorption cycle even cleans the gas as bigger molecules can not make it through the lattice. To produce the transfer, modest amounts of heat must be added or extracted. The densities achieved more than double the ones for liquid hydrogen, but are still far from conventional fuels (Figures A-1 and A-2). And when the mass of the metal or alloy is taken into account, the best achievable gravimetric storage density is about 0.07 kg H2/kg of metal for high temperature hydride such as MgH2 [2]. Finally, research in nanofibres has lead to ne w materials that would theoretically allow for the storage of hydrogen inside nanotubes made of carbon at densities that would exceed the ones for metal hybrids and with a much lower total weight. Also hydrogen can be stored in glass

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20 microspheres of approximately 50 m diameter. To fill the microspheres they must be heated to increase the gas permeability. The rel ease is achieved in the same way. All the technologies for hydrogen storage mentioned before require compressors to reach the desired pressures. Only in the case of meta l hydrides they can be avoided. Compressors used for hydrogen only require minor modifications to the seals because of the high diffusivity of hydrogen molecules. They can be standard axial, radial or reciprocating piston-type compressors [4]. Compression to high pressures is done in multiple stages. The first stage usually reaches to 0.3-0.4MPa (45-60 psig). To reach high pressu res of 25-30MPa (3,600,400 psig), a previous compression stage takes the hydrogen to 3-4MPa (435-580 psig) [4]. Even metal hydrides can be used for compressing hydrogen because with higher desorption temperatures the pressure of the hydroge n released increases. Using different hydrides with different desorption temperatures in series, really high pressures of up to 100MPa can be reached [4]. The advantage in this case is that heat is used to reach the compression and the heat extracted from the absorption of one of the stag es can be used in the desorption of another. Energy Distribution The m ain technology in use for electricity distribution is high-voltage alternating current. High-voltage direct current (HVDC) has become competitive for applications where large distances are involved or when it is necessary to c onnect grids with different frequencies [5]. It is not only very efficient for transmitting large amounts of power over long distances, but also solves many problems of reliability and stabilit y issues associated with connecting renewable energies schemes, like wind farms, to the main grid. An option not tested yet is the use of hydroge n for energy transmission. It might seem that converting electricity to hydrogen, and then back to electricity, would not make much sense,

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21 especially because of the losses involved in the transformation, but there are different reasons that could support the use of hydrogen. Hydrogen would allow for the transport of high energy densities that make it competitive when large amounts of energy and power must be transmitted over long distances. Also there are many health and environmental concerns with high voltage transmission lines [6]. Hydrogen also has the flex ibility to be used with a range of different technologies as mentioned before. Finally, in the case of intermittent renewable energies, it would act as an energy storage that would help couple the production with the demand. Hydrogen, like other gases, can be transmitte d in several ways. The technology for the storage and transportation of compressed or liquefied hydrogen is commercially available. Special containers are used for transport by sh ip, and smaller ones for transport by railroad or roads. It is possible to obtain higher energy de nsities using other stor age methods like metal hydrides or carbon nanotubes. Of course the weight of the container is ve ry important in these cases since it would affect the transportation cost. One of the solutions proposed for hydrogen di stribution is the use of hydrogen pipelines. Typical hydrogen pipelines in operation carry between 310-8,900 kg/h (685-20,000 lb/h) at pressures between 1-3 MPa (145-435 psig). They can be found in industria l areas in the United States, Canada, and Europe. The longest hydroge n pipeline in operation goes from northern France to Belgium and is 400 km (250 miles) long [4]. Hydrogen transport through pipelines requires larger diameter pipi ng and more compression power th an natural gas for the same throughput. However, the pressure losses are sma ller requiring less reco mpression stations. The general consensus is that these pipelines co st between 1.3 and 1.8 the cost of natural gas pipelines [2].

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22 There are studies that compar e the transmission of energy in the form of hydrogen through pipelines with electricity over a long distance. (Justi, 1987; Colu ccia et al., 1994 Oney et al., 1994; Keith and Leighty, 2002) [7 ]. Hydrogen pipelines would be economically preferable to conventional electrical transmission lines for distances over 1,000 to 2,250 km, depending mainly on the amount of energy de livered per unit time [1, 2, 4]. Ot her studies affirm that some modern natural gas pipelines could be used for hydrogen transmission only requiring the upgrade of the valves [3, 4]. The main concern with these pipelines is that hydrogen may penetrate the steel, making it brittle and favoring the deve lopment of cracks; but research done on the materials used in modern pipelines shows this is not probable [3]. Current hydrogen pipelines are constructed of 10-12 in (0.25-0.30 m) commercial steel and operate at 1-2 MPa (145-435 psig) in comparison to natural gas mains that can be as large as 5 ft (2.5 m) in diameter and work at 7.5 MPa (1,100 psig) [4]. Studies show that for large quantities of hydr ogen, pipeline delivery is the cheapest option, except in the case of transport across the ocean. The next cheapest method would be the transport of liquid hydrogen. Pipeline delivery has high cap ital investment costs, but the operation costs are low and consist primarily of the compressor power costs [4]. Hydrogen Utilization One of the drivers for research on hydroge n is the fact that hydrogen conversion technologies into other form s of en ergy are usually more efficient than that of other fuels. Also hydrogen creates little or no emissi ons, only water or water vapor. Hydrogen can be used in internal combusti on engines with effici encies around 20% higher than gasoline engines. The only products of hydrogen combustion in air are water vapor and small amounts of nitrogen oxides (typically an order of magnitude less than emissions from

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23 comparable gasoline engines) [2]. It can also be used in turbines and jet engines, with the same emissions. Hydrogen can also be combusted with pur e oxygen to produce steam at nearly 100% efficiency; or combusted with air in the pres ence of a catalyst at much lower temperatures (ambient 500 C) avoiding the formation of nitrogen oxides. Finally, the most promising technology is th e electrochemical gene ration of electricity using fuel cells. In a fuel cell, hydrogen co mbines with oxygen without combusting in an electrochemical reaction, produci ng water and direct current el ectricity (DC). Depending on the electrolyte used, the fuel cells (FC) can be categ orized as: Alkaline fuel cells, polymer electrolyte membrane or proton exchange membrane fuel cells (PEM), phosphoric aci d fuel cells, molten carbonate fuel cells or solid oxide fuel cells. Fuel cells have many advantages over internal combustion engines. They are more efficient and produce no pollutants, but they are still expensive mainly because of the materi als used and the low production volumes. Electrolyzers Electrolysis of Water The m ost abundant source of hydrogen is wate r. Hydrogen can be produced from water using a process called electrolysis, where an electric current is used to split water into oxygen and hydrogen. This process was discovered in 1800 by William Nicholson and Sir Anthony Carlisle. Electrolysis is the most promisi ng option for hydrogen production from renewable resources. When used with renewable sources of electricity, it can prod uce hydrogen with zero or near zero green house gas emissions. As only wa ter is used in the process, it can produce 99.9995% pure hydrogen and oxygen. Water electrolysis is a matu re technology, and it has b een used for production ranging from a few cm3/min to thousands m3/h. It is relatively efficient (>70%), but because it needs high

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24 quality electricity, hydrogen produced by wate r-electrolysis is expensive (>$20/GJ using hydrogens higher heating value and assuming electricity cost of about $0.05/kWh) [2, 7]. In the ideal case, 8.9 liters of water and 39 kWh of el ectricity will produce 1kg of hydrogen at 25C and 1 atmosphere pressure (S TP). The volume of 1kg of hydrogen at STP is 11.24 m3. The device used to produce chemical reactions for electrolysis is called an electrolytic cell. An electrolytic cell is a type of el ectrochemical cell in which an elec tric current is used to drive a non-spontaneous reaction [8]. A group of cells connected in series is called a stack. Although electrolysis is only res ponsible for a very small per centage of the current total hydrogen production, it is expected to have a very important role in the future due to the possibility of using electricity from renewable sources. Electricity from wind, solar, hydro or waves power could be used to produce hydrogen with very low green house gases emissions. Electrolysis using electricity from wind power is expected to be the cheapest way to produce hydrogen as wind turbine cost reduces a nd fossil fuels become more expensive [9]. Process Description In alkaline water electrolysis, a reduction r eaction takes place at the cathode (negative charge), where water splits in hyd rogen gas and hydroxide ions (OH-). The OHions then migrate to the anode (positive charge) where th ey are oxidized forming oxygen, water and 2 free electrons. The electrons then flow to the cathode completing the cycle. When hydrogen and oxygen react together to pr oduce water, energy is produced. The heat generated by the reaction is called enthalpy of formation ( H) and is equal to the Gibbs free energy ( G) plus the entropy heat of water formation (T S). Inversely, to decompose water into

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25 hydrogen and oxygen, it is necessary to provide electrical energy equal to G and heat equal to T S. Figure 1-1. Simple alkaline electrolyzer. For isentropic electrolysis, the voltage required is proporti onal to Gibbs free energy represented by Faradays Law (Equation 1-1). G nF E (1-1) Where: G is Gibbs free energy of reaction n is the number of electrons transferred F is Faradays constant E is the cell voltage The negative sign is necessary because the voltage input is considered negative by convention. The sign of G determines if the reaction is or not spontaneous, being negative for spontaneous reactions. We obtain then: E G nF H T S nF (1-2) eOHO2 H2 Cathode Anode Dia p hra g m

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26 For water at STP: G = 14.93 kWh/lbmH2 (50,941 Btu/lbmH2) Considering this G and F = 9.648531x104 Coulombs/mol, the corr esponding reversible voltage is E = 1.23 V G represents the energy that must be supplied as electricity to drive the reaction. The enthalpy of formation of hydrogen is 18.01 kWh/lbm H2 (61,451 Btu/lbm). The remaining 3.08 kWh/lbm (10,510 Btu/lbm) must be supplied by heat from the surroundings in reversible electrolysis. By the second law of thermodynamics, entr opy production increases the required voltage. In the process, the entropy is in the form of heat, supplying the re st of the energy needed for the reaction. By replacing G with the higher heating value (HHV) of H2 in Faradays law, we obtain the thermoneutral voltage (E = 1.47 V), which is in reality, the minimum voltage necessary to obtain the reaction. Real electrolyzers require even higher voltage s due to many different factors like ohmic resistance of the electrolyte (mainly becau se of the formation of vapor bubbles on the electrodes), concentration polari zation, voltage gradients at the electrode/electrolyte interface caused by the slow reaction rate, and wire and components resistance. The actual electrolysis voltage can be estimate d by considering the different effects that take place in the electrolyzer. It is a functi on of the thermodynamic pot ential, the activation overpotential, exchange current density, the ohmic overpotential and the overpotential due to concentration losses (mass transport). The activat ion overpotential, exchange current density and the overpotential due to concentration losses can be categorized as effects due to electrode kinetics.

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27 The activation overpotential can be estimat ed using the Butler-Volmer equation. The Butler-Volmer equation relates the current dens ity with the activation overpotential and is derived considering the kinetics of the reactions. This equations neglects mass transfer effects. The mass transfer depends mainly on the concen tration of reaction products, which can be ascertained only by experiments. Ohmic overpotential is the increase in the vol tage required due to ohmic resistance. For example, in an alkaline electrolyzer, the ohmic re sistance of a cell is composed of the electrodes, the current collectors, the bipolar plates, the gas-electrolyte sepa rators and the electrolyte layer between the electrodes and gasseparatiors. The ohmic losses ca n be expressed by Ohms law, and vary with temperature and also due to variation in void fraction of gas bubbles. Finally, the parasitic losses must be included in order to evaluate the overall performance of an electrolysis system. These are associat ed with auxiliary systems, like electricity rectification, power regulati on, voltage regulator, water trea tment and supply, water-gas separation, cooling water system, feed water pum ps, etc. Also gas loss during de-oxidation and drying should be considered. There are different ways of describing the e fficiency of electrolyzers. We can define its stack efficiency, overall efficiency, energy e fficiency and water to hydrogen conversion efficiency. Electricity is one of the main co mponents in the cost of hydrogen produced with electrolyzers. Then, the electrical energy efficiency is particularly important. Electrolyzers Classification Electrolyzers are class ified depending on the electrolyte used. Table 1-2 shows the most important technologies used and their operation conditions.

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28 Table 1-2. Types of electrolyzers. Operation variables Alkaline PEM Solid Oxide Temperature 100 150 C 80 100 C 500 800 C Capacity* (Nm3/h) 485 26 100 Max. output pressure* (MPa) 44.8 20 Efficiency* 73% 65%-80% *Maximum achieved in lab or commercially available. Alkaline electrolyzers Alkaline electrolyzers use an alkaline solution (of sodium or potassium hydroxide) that acts as the electrolyte. These electrolyzers have been commercially available for many years. They can be configured as unipolar (ta nk) or bipolar (filter press) designs. In the unipolar design, the elec todes are submerged in the alkaline electrolyte, inside a tank. The electrolyte is a 20%-30% solution of pota ssium hydroxide in pure water. Each cell is connected in parallel. These electrolyzers are simp le to manufacture and repair, but they can only operate with low current densitie s and temperatures. Current designs can operate at high pressure outputs, up to 41MPa (6,000 psig). Figure 1-2. Alkaline electrolyzers. A) Unipolar (tank) design. B) Bipolar (f ilter-press) design. The bipolar or filter-press design consists of a series of electrodes and separating diaphragms clamped together. The result is a sma ller electrolyzer that can operate with higher

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29 current densities and pressures. Th e cells are connected in series in this case, requiring a higher voltage. The disadvantage is th at the maintenance is more complicated. Figure 1-2 shows schematics of both alkaline electrolyzers configurations. PEM electrolyzer Polym er electrolyte membrane or pr oton exchange membrane (PEM) electrolyzers use a solid specialty plastic material as electrolyte instead of an alka line (KOH) electrolyte. General Electric created the first PEM el ectrolyzers in 1966, due to the development of perfluorinated ion-exchange membranes Nafion by DuPont. When applying a voltage higher than the thermoneutral voltage (1.482 V), water is split at the anode in oxygen, prot ons and electrons. The protons go through the polymer electrolyte membrane and combine at the anode with electrons to form hydrogen. The passage is accompanied by elec troosmotic drag (water transport through the membrane). PEM electrolyzers are simpler than alkaline el ectrolizers, can be operated in a variable power input mode and can generate hydrogen at pressures up to 20MPa (2,900psi), with very little additional power consumption [7]. The main barrier for the mass production of PEM electrolizers is the high cost of the materials needed. The membrane, the noble metals for the electrocatalyst, and construction materials like Ti, make the PEM electrolizer mo re expensive than other kinds, but around 70% of the cost of hydrogen produced corresponds to electricity, compensating for the higher electrolizer cost. Overtime, PEM electrolyzers will experien ce some degradation in performance. An increase in the voltage is expected because of equilibration of water content in the membrane and oxidation of catalyst and other metallic com ponents. There are also issues with PEM electrolyzers operating under intermittent pow er conditions. As hydroge n and oxygen production

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30 is proportional to the current density, at very low loads the production of the gases may be lower than the permeation rate through the electrolyt e, mixing with each other and thus generating dangerous conditions inside the el ectrolyzer. Another problem is re lated to the work temperature of the electrolyzer. It takes some time for the electerolyzer to r each its nominal temperature, so intermittent operation could keep the electrolyzer from reaching this temperature and working at its highest efficiency. Figure 1-3. Schematic of electrolysis cell with PEM. Adapted from [10]. PEM electrolyzers can be designed to work at high pressures, reducing the need of compressor work. Hydrogen must be compressed fo r storage, and doing so while producing it in the electrolyzer shows to be more energy efficien t than using compressors With higher pressure, the voltage needed in the electrolyzer is reduced and the higher pressure allows the electrolysis to occur at temperatures above 100C. The resistance of the membrane decreases with

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31 temperature, improving the efficiency of the proc ess. Finally, the gas bubble volume is smaller, improving the water transport, redu cing looses in the electrolyzer. Proton Energy Systems supplies electrolyzers that generate hydroge n at 1.4 MPa (200 psig), but they have been reported to operate at 20 MPa (3000 psig) in the laboratory. The higher pressure during the process requires a sligh tly higher voltage, corresponding to isothermal compression work. It is then the most effici ent way of obtaining high-pressure hydrogen. The only loss is the higher permeation of hydrogen through the membrane. The efficiency of the electrolyzer is invers ely proportional to the cell potential, which in turn is determined by the current density, which in turn directly corre sponds to the rate of hydrogen production per unit of electrode active area [7]. More hydrogen can be produced with a higher voltage, but at lower efficiencies. Typically a vol tage of 2V is selected. Permeation of hydrogen through the membrane also reduces the efficiency. This is usually insignificant for low pressures, but is important for pressures over 10 MPa. The losses due to the auxiliary equipment and voltage regulation must also be considered. Typical industrial electrol yzers have electricity cons umptions between 4.5 and 6.0 kWh/Nm3, corresponding to an efficiency of 65-80% [7]. Voltages regulators usually have a high effici ency, but for a narrow power range. In the case of a highly variable power input, the efficiencies can be significantly lower. Solid oxide electrolyzers Solid ox ide electrolyzers use a solid cera mic material as the elec trolyte that selectively transmits negatively charged oxygen ions at elevat ed temperatures [11]. The way they generate hydrogen is a little different. At the cathode, water combines with electrons from the external circuit to form hydrogen gas and negatively ch arged oxygen ions. The oxygen ions pass through

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32 the membrane and react at the anode to form oxygen gas and give up the elec trons to the external circuit. Solid oxide electrolyzers must operate at temperatures high enough for the solid oxide membranes to function properly (about 500 800C). The solid oxide electrolyzers can effectively use heat available at these elevat ed temperatures (from various sources, including nuclear energy) to decrease the amount of el ectrical energy needed to produce hydrogen from water. High-pressure electrolysis Even though it would be expect ed to have m any beneficial aspects, there is not much experience or literature on high-pressure electro lysis. Since less power is required to compress liquid water than gaseous hydrogen, it is logical to conclude that to electrolyze high-pressure water would require less energy than to compress gaseous hydrogen electrolyzed at ambient or low pressures. Also, as a conventional mech anical compressor is not required, the overall efficiency is expected to impr ove. However, the reversible cell voltage increases significantly with increasing pressure [12]. In high-pressure electrolysis, a water-feed pump becomes essential. In the case of alkaline electrolyzers, electrolyte circulation pumps are also required for better removal of the heavier bubbles formed at high pressure [12]. The higher pressure causes a small reduction of the enthalpic voltage, thermoneutral voltage and higher heating voltage of water electrolysis, which favor s this kind of electrolysis if perfect insulated conditions are assumed. In practice, the electr ode activation, ohmic losses and leakage current increase the electrolysis voltage much beyond the thermoneutral voltage causing the need of heat removal from the stack.

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33 As explained before, the total energy required for electrolysis can be supplied in form of electric energy and heat. The change of enthalpi c energy with pressure is negligible, but the proportion of electrical and heat energy vary with pressure and temperature. The reversible voltage, which is a mayor part of the electrical energy required, increases with pressure, while the entropy heat decreases, keeping the enthalpi c voltage almost unchanged for temperatures under 100C. A theoretical study at Toyohashi University of Technology in Japan tried to quantify the difference in energy required for ambient and high-pressure PEM electrolysis to produce hydrogen at 700 atm. They calcula ted the power required by a water pump to deliver water at 700 atm, the power required to compress gaseous H2 to the same pressure, and the ideal power requirements for electrolysis at ambient and at 700 atm pressure (Table 1-3). They concluded that when the pump and compressor efficiencies are assumed to be 50%, high-pressure electrolysis requires 5% less power [13]. It is important to note th at the effect of pressure on the electrolyzers overpotentials we re not taken into account. Table 1-3. Change of hydrogen production by pressure [13]. Pressure (MPa) High-Pressure electrolysis Ambient electrolysis Wpump + Welec,298,p (kW) Welec,298,p + Wcomp (kW) 0.101325 237.2 237.2 10 254.5 (0.36) 264.2 (27.0) 22.064 257.8 (0.80) 269.9 (32.6) 40 260.6 (1.45) 274.3 (37.1) 70 263.8 (2.53) 278.7 (41.5) Values in () represent the pumping or compressing power at 50% efficiency. Another study by C. A. Schug, characterizes the performance of a 100 kW pilot-alkalineelectrolyzer running inside a pressure vessel to obtain high-pressure electrolysis. The stack was kept inside the pressure vessel, achieving almost no pressure di fferent between the inside and outside of the stack. The influen ce of the pressure on the electroly zer efficiency was found to be

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34 small, and the system was safe, easy to maintain and flexible enough for all kinds of electrical power, referring in particular to intermittent renewable power sources [14]. Presently, the cost of an atmospheric electr olyzer including a co mpressor is 30% lower than the cost of a high-pressure electrolyzer to produce hydrogen at the same pressure [12]. The same study indicates that the energy consumed by a 71MPa electrolyzer would be 16% higher than an atmospheric electrolyzer and compressor combination. Finally it s uggests that the use of atmospheric electrolyzers is preferable to highpressure ones for fluctu ating energy sources for their better dynamic response. Relative Sizing of an Electrolyzer An electroly zer run with wind generated electricity can be sized to use the maximum power that can be produced, but it will operate with the power available from the generators, that depend on the wind availability. Another option is to use electrolyzers with a lower capacity, which will work at a higher capacity (and usually better efficiencies) except for periods of high wind when some generated power would be unutili zed. One must also consider the performance degradation with time. Water Consumption. The theoretical feedsto ck water consumption can be obtained from stoichiometry of the water splitting. H2O H2 1 2 O2 (1-3) From the stoichiometry illustrated by Equation 1-3, the feedstock water needed is approximately 9 times the mass of hydrogen prod uced. Then, the theoretical water consumption is of 1 litter of water per 1.24 Nm3 of hydrogen. Due to different losses (water vapor in the hydrogen and oxygen, etc) the actual use is 25% highe r. It was found that current systems utilize on average almost 12 kg of water pe r kg of hydrogen produced [15 17].

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35 Different systems have different water quality requirements. For example, the manufacturer Distributed Energy System, re quires for its HOGEN RE PEM electrolyzer deionized (DI) water with a quality of 1 MegOhm -cm or better (ASTM Type II. See Table 1-4). Others include purifying systems in their electrolys ers, so they run directly on tap water. Another supplier, Teledyne Energy Systems Inc., requires fo r its Titan EC Generator Series also ASTM D1193-99, Type II water quality (m in. resistivity 1.0 MegOhm-cm). Table 1-4. American Society for Testing and Materials Standard (ASTM) specifications for reagent water ASTM Type I II III IV Conductivity @ 25C (microohms/cm) 0.056 1.000 4.000 5.000 Resistivity @ 25C (megaohms-cm) 18.200 1.000 0.250 0.200 Total Silica ( g/L) 3.000 3.000 500.000 Total Organic Carbon ( g/L) 50.000 50.000 200.000 Chlorides ( g/L) 1.000 5.000 10.000 50.000 Sodium ( g/L) 1.000 5.000 10.000 50.000 pH -* -* -* 5.000-8.000 -*The measurement of pH has been eliminated because th ese grades of water do not contain constituents in sufficient quantity to alter pH. Seawater can also be used for electrolysis with the condition that it is first treated to obtain the properties required. Reve rse osmosis can be used to treat salty water with a cost 2 to 3 times higher than treating c onventional water [18]. Most systems currently available do not re quire cooling water. But depending on the operation conditions and the electrolyzer utilized the electrode activation, ohmic losses and leakage current could increase the electrolysis voltage much beyond the thermoneutral voltage causing the need of heat rem oval from the stack. An example is Teledynes Titan EC Generator that requires a ma ximum flow rate of 189 lpm (50 gpm) at a maximum inlet temperature of 40C to produce 5 kg/hr of hydrogen (56 Nm3/hr). This is an extreme operation point informed by the supplier. Normally cooler water would be available reducing the water needs.

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36 By-Product Oxygen Oxygen is the second largest volum e industrial ga s, and is commercialized as a gas or as a liquid. It is produced using me thods like cryogenic air separation or vacuum pressure swing adsorption. It is used in many industries and applications, like chemical processing, glass manufacturing, health services, metal fabri cation and production, refining, pulp and paper production, water treatment, etc. Oxygen is a va luable by-product of electrolysis, and its commercialization can reduce the cost of the hydrogen produced. The usual ways of transporting oxygen are by bul k liquid delivery in tank trailers, by bulk gas delivery in tube traile rs, by pipeline or in cylinder and liquid containers. Current State of Electrolyzers Development Low-pressure electrolysis system s are comm ercially available today up to about 1.5 MPa (230 psia). Electrolysis at high pr essure, 10 to 69 MPa (1,500 psia to 10,000 psia) is theoretically the most efficient way to produce hydrogen, but no such systems are commercially available today. A few pilot scale demonstrations have been built (e.g., Mitsub ishi, Proton) and many companies are working in developing them. A study on the electrolytic hydr ogen production equipments comm ercially available as of December 2003 produced by five different compan ies shows the largest electrolyzer unit sold has a maximum production capacity of only 380,000 kg H2/year [15]. The units analyzed are Stuart IMET; Teledyne HM a nd EC; Proton HOGEN; Norsk Hydro HPE and Atmospheric; and Avalence Hydrofiller. With these capacities, for large hydrogen gene ration plants, a significant number of electrolyzers would be required. The largest electrolyzer commercially available is the Norsk Atmospheric Type No. 5040. Its characte ristic can be found in Table 1-5.

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37 Table 1-5. Characteristics of la rgest commercially available electrolyzers as of December 2003 [15] Units Norsk Hydro: Atmospheric Type No.5040 (5150 Amp DC) Stuart: IMET 1000 Teledyne: EC-750 Technology Bipolar Alkaline Bipolar Alkaline Bipolar Alkaline kWh/Nm34.8 4.8 5.6 Energy Required: System kWh/kg 53.5 53.4 62.3 Energy Required: Electrolyzer kWh/Nm3 4.3 Nm3/hr 300-485 90 42 Hydrogen Production Rate Kg/hr 27.0-43.6 8.1 3.8 System Power Requirement kW 2328 360 235.2 Reactants kg/hr 485 60 42 Product H2 kg/hr 43.4 5.4 3.8 Product O2 kg/hr 347 43 30 Conversion efficiency of H2O % 80 80 80 System Energy Efficiency* % 73 73 63 Production pressure psig 435 360 60-115 H2 Purity % 99.90.1 99.997 99.9998 Lifetime Years 7-10 10 15 Energy efficiency is defined as the higher heating value (HHV = 39 kWh/kg or 142 MJ/kg) of hydrogen divided by the energy consumed by the electrolysis system per kilogram of hydrogen produced. The electrolyzers presented in Table 1-5 reac h a pressure ranging from 0.4 3 MPa (60 435 psig) for the power requirements informed. In the future, it is expected to achieve a 50 kWh/kg range, or a system efficiency of 78%, but including compression of the hydrogen gas to 41 MPa (6000 psig) [15]. Current research on electrolyzers focuses on: Reducing the capital cost of the electr olyzer and improving energy efficiency. Integrating compression into the electrolyzer and avoiding the cost of a separate compressor needed to increase pr essure for hydrogen storage [11]. Wind Power W ind power refers to the use of wind turbines to transform the energy available in the mass of moving air created by thermal differences on the earth surfaces, into electrical or mechanical energy of practical use. We call a wind farm a group of wind turbines that are installed in a certain location for the production of electricity.

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38 Wind power for utility scale electricity produc tion is the fastest growing renewable energy at the present. This is because it is one of th e most economically competitive technologies with an actual cost of wind energy of 4 to 6 cents pe r kilowatt-hour [19]. There are currently 75 GW of installed capacity worldwide, mainly in Europe and the United States, but they are expected to increase to 260 GW by 2015 [20]. The United Stat es alone has 15 GW of installed wind power capacity, and is expected to be the fastest gr owing market with 48 GW by 2015. Europe, on the other hand, is expected to exceed 130 GW by 2015. The most common wind turbine for electric ity production is the horizontal axis wind turbine. In these turbines the ax is of rotation is parallel to th e ground. There are many variations depending on the rotor orientation (upwind or dow nwind), the hub design (ri gid or teetering), the rotor control (pitch vs. stall), the number of blades and how they are aligned with the wind (free yaw or active yaw). Figure 1-4 shows the main subsystems of a horizon tal axis wind turbine. The typical components of a wind turbine are: The rotor, consisting of th e blades (normally 2 or 3) and the supporting hub (rigid, teetering or hinged). The blades can be made of different materials and have different profiles. Finally, the rotor can be orie nted upwind or downwind of the tower. The drive train groups all the ro tating parts of the turbine be sides the rotor. It usually includes the shafts, gearbox, c oupling, mechanical break and generator (synchronous or induction). The nacelle that is the turbine housing. The main frame and yaw system, which can be free (self aligning) or active (direct control). The tower and foundation. The controls, including sensors, controllers, power amplifiers and actuators. The balance of the electrical system

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39 Figure 1-4. Major components of a horizontal axis wind turbine. Adapted from [21]. Current wind turbines require a minimum of Class 3 winds to operate. Table 1-6 shows the standard wind classification where we can see that class 3 winds start at a wind speed of 6.4 m/s. Below that, the wind power available is negligible at a utility scale. Table 1-6. Standard wind classification at 50 meters. Wind Power Class Wind speed (m/s) Wind power (W/m2) 1 0-5.6 0-200 2 5.6-6.4 200-300 3 6.4-7.0 300-400 4 7.0-7.5 400-500 5 7.5-8.0 500-600 6 8.0-8.8 600-800 7 8.8-11.9 800-2000 As the energy in the wind varies with the cube of the wind speed, the site selected for the installation of the wind farm will greatly affect its energy output.

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40 Initial Site Selection To determ ine the site for a wind farm, we must be able to estimate the power we would be able to obtain with a wind turbine. To calcula te the mean power that can be produced we use Equation 1-4. E TP ( U ) f ( U ) dU (1-4) Where U is the wind speed, P(U) is the power curve of the wind tu rbine, f(U) is the probability density function of the wi nd speed, and T is the time period. P(U) is a function that shows the power the wind turbine produces at each wind speed, and is given by the manufacturer of the wind turbin e. The probability dens ity function of the wind speed (PDF) is usually based on a Weibull distribu tion and is calculated ba sed on statistical data of wind speeds in the location. Other factors that must be considered when choosing the site are accessibility, land ownership, environmental, visual and sound effects, and radar interf erence. In the case of this study, the availability of a water source for the hydrogen production is an extra prerequisite. In addition, wind farms are usually extensive, since the turbines must be spaced at least 3 to 5 rotor diameters. The existence of roads, or the possibility of building them at reasonable cost is important, since many components of the wind farm, like wind turbine blades or transformers are big or very heavy. Also the connectivity to the grid s hould be assessed to see if the network could accept the generation of the wind farm. In the cas e of hydrogen production with the electricity produced, this would not be an issue. Finally, the opinion of the habitants of the zone is important and can have a determining influence in the establishment of a wind farm.

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41 Micrositing Micros iting is the process of determining the exact position of each wind turbine. For this task different software programs are used along with information obtained from the site. The terrain and wind characteristics, along with constraints like tu rbine separation, terrain slope, wind turbine noise, land ownership and wake eff ects are used by these programs to optimize the distribution to obtai n the maximum energy. There are numerous technical i ssues regarding the disposition of the turbines. As we said this depends on the terrain and wind resource, but it is also important to take into account the interaction of the turbines. The turbines downwi nd are expected to receive a slower wind due to the effect of the turbines upwi nd. Also the turbines upwind genera te turbulence that decrease the energy production downwind and increase the wake -induced fatigue in th e downwind turbines. The common terms for referring to wind turbin e arrays are illustrated in Figure 1-5. Figure 1-5. Wind farm array schematic [21]. Because of these factors, the energy produced by an array of wind turbines is lower than the energy that would be produced by adding the c ontribution of isolated turbines in the same wind. These losses are referred to as array losses, and are a function of the downwind and

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42 crosswind spacing, the wind turbin e characteristics, the number of turbines, the turbulence intensity and the wind rose (frequency distribution of the wind direction). To obtain array losses below 10% the turbines must be spaced 8 to 10 rotor diameters in the downwind direction and 5 rotor diameters in the crosswind [21]. Argentina and Patagonia Case Argentina is located in the southern portion of South Am erica, between 21 46 and 55 03 of latitude south. Contin ental Argentina has an area of 2,791,810 square kilometers (1,077,924 square miles), being the second largest country in Sout h America and the eighth in the world. Approximately 54% of this area corresponds to plains (prairies and savannahs), 23% to plateaus and another 23% to mountains. Its bounda ries are to the east with the Atlantic Ocean, Uruguay and Brazil; to the west with Chile, and to the north with Paraguay and Bolivia. The population of the country is 39.7 milli ons growing approximately 0.99% annually, resulting a population of 42.4 millions by 2015. Fi gure 1-6 illustrates an estimate of the population for the years 2000-2015. Argentina repr esents one of South Americas largest economies. Argentinas gross domestic pr oduct (GDP) grew by 9.02 percent in 2005, 8.64 percent in 2006 and 8.65 per cent by the end of the 3rd trimester of 2007 [22]. This high level of economic growth has led to a corresponding in crease in the demand for energy, especially natural gas. In the year 2006, the country consumed 56,782 th ousand tonnes of oil equivalent (1 toe = 41.868 GJ = 11.63 MWh) [23]. The total energy production was 85,517 ktoe; the main shares corresponding to natural gas and oi l (Figure 1-7). Argentina is a ne t exporter of energy, but due to the economic grow, it has been experiencing ener gy shortages, particularly of electricity and natural gas. The industrial sector consumed 18,059 ktoe in 2006. That represents 32% of the total

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43 energy consumption of the country. The main res ources consumed by the industry are natural gas (10,634 ktoe 59%) and electricity (4,058 ktoe 22%) [23]. Figure 1-6. Argentine population [22] The combined utilities produce 97,300 GW of electricity, and import 3,800 GW to supply a total consumption of 101,100 GW. Around 35% of th e electricity produced is hydroelectric, 7% nuclear, and the rest is produ ced using fossil fuels, mostly natural gas. In the year 2006 a total electricity production equivalent to 9,905 ktoe, requ ired 3,816 ktoe of hydropower, 2,219 ktoe of nuclear power, 11,358 ktoe of natural gas, and 2,223 ktoe of other fuels (mainly oil derivatives). But due to the increase in the de mand, and the fact that hydroelectric and nuclear capacity has remained constant in the last years, there has been an increase in the electricity produced with fossil fuels. This evolution can be seen in Figure 1-8. Not only these fuels are more expensive, but also the way the electric ity is produced is less efficient, with the corresponding increase in the pollutants emitted. It is then necessary to in vest in new facilities for the production of electricity, and it shoul d be done from a sustainable perspective.

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44 Figure 1-7. Composition of Argentine energy offer in 2006 [23]. The annual electricity consumption per pers on is around 1,500 kWh, and annual fossil fuel consumption per person is around 1.6toe [24]. Th ese values are between 2 and 4 times smaller than in developed countries. So to achieve a liv ing standard closer to developed countries the energy consumption per capita must increase. Argentina, thanks to its large renewable en ergy sources, is a good candidate for an early conversion to a hydrogen system [24]. The extr action limits for different renewable energy sources is presented in Table 1-7. Table 1-7. Renewable energy extraction lim its for Argentina and the world [24]. Energy source World Argentina Solar (direct) 200,000900 Wind power 4,000300 Thermo-oceanic 1,30020 Hydraulic 120 3 Total 205,4201223 Energy consumption 20006003.6 Area (km2) 126 1062.35 106Energy values in 1018 J per year

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45 Due to its location (Figure B-1), Argentina r eceives relatively less solar energy and more wind than the world average. It is clear in Table 1-7 that the potential for renewable energies is many times larger than the required energy consumption. Figure 1-8. Evolution of the composition of Argentine electricity generation. A study by Veziroglu [24], proposes the use of so lar energy in the north of the country and wind energy in the south for the production of hy drogen that would be dist ributed in the country by means of two main pipelines. Focusing on wi nd power, the main resources available are located in the Pata gonia (Figure B-2). Patagonia has very constant class 6-7 winds (Figure B-2). Its surface also has a low roughness (Figure B-3) and the pop ulation density is below 2.5 people per square kilometer (Figure B-4). All these characteristics make it a perfect place for wind energy applications. The main disadvantage is that it is very far from the consumption centers, requiring a very long distance energy transport.

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46 A plant to produce hydrogen using wind-generate d electricity requires the availability of the two main feedstocks to the process, wind and water. The selection of the site for a wind farm was already discussed in the Wi nd Power section. The electrolysis system adds the need of a water supply. Because of this reasons, the position chosen for the installation of the wind farm and electrolysis plant in the study, is approximately located at latitude 48'S and longitude 70'W in the Santa Cruz province (Figure B-5). The selection was motivated by the availability of the wind resource and the Chico River. There is no data available on the amount of water that can be obtained from the Chico River since there are no measuring stations on it. For that reason it is important to analyze the possibility of utilizing desalinated seawater for large hydrogen productions. Introduction to Feasibility Study A feasibility study is usually pr esented in a report where the feasibility of a project is established f rom a technical or an economic point of view. Such a study normally treats technical, managerial, economic, fi nancial, cultural, social, safety and political aspects of the project. Technical feasibility refers to the availability of the technology requi red for the enterprise, along with the technical capability of the personn el involved. In this particular case, the technology for harnessing the wind is commercially available and well tested, but electrolyzers are still in an early phase of development. The same applies to the transportation and storage of large quantities of hydrogen. The economic feasibility evaluates the project ability to produce benefits. A cost analysis is carried out for this purpose. Financial feasibility, on the other hand, also deals with the way the project will be funded.

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47 Cultural and social feasibility studies the wa y the project affects the community, if it will be culturally accepted and what changes will bring to the society affected. Safety and environmental feasibility is another aspect that should always be investigated. Not only has the legislation on these issues improved with the years, but also companies and the public have taken a more responsible approach to environmental problems. A life cycle analysis is a good tool to evaluate the enviro nmental impact of the project [17]. Finally, in some cases, it might be necessary to evaluate the political feasibility of the project. Political factors could compensate or even outweigh economic factors, propelling projects that might not be econom ically feasible or the other wa y around. This is particularly true in the case of renewable energies that are still not competitive with conventional energy sources so they need political support for their implementation. The feasibility study should start with an analys is of the need for the project, determining if the project is really necessary and if there is no other better way of satis fying that need. Then a preliminary analysis is done to calculate the means required for that objective and with this information starts the engineer ing and design. The engineering a nd design stage consists of a complete technical study, with evaluation of the technology require d. After this, it is possible to estimate the cost of the project, both initial and operational costs, with an acceptable precision. A financial analysis should be done at this point to study the expected cash flow. The next item to be studied is the impact of the project; asse ssing the environmental, social, cultural, and economic impacts that would affect the way the project is perceived by the public. Finally, a feasibility study will include the conclusions and recommendations, with a final evaluation supporting or disapproving the project.

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48 The aim of this thesis is to provide a first approach to the project, determining if it is technically feasible and providing a rough estimate of the cost s and investments required, in order to establish if a more detailed analysis if justifiable at the present time. For that purpose a literature search was carried out to determine if the equipment required is commercially available. Also cost estimations for the components were obtained from different publications and a final product cost was calculated and compar ed to other energy sources. Finally, the water required for the process was estimated taking into account that it is becoming a very important resource that could be scarce in the near future.

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49 CHAPTER 2 METHODOLOGY Process Description Process Schematic The total process can be di vided into three m ain components: the wind farm, the electrolysis system, and the hydrogen stor age/distribution system (Figure 2-1). The wind farm collects the energy from the wind using the wind turbines, and converts it into electrical power. The electric ity could be AC or DC. In the case of electrolysis with wind power, it would be interesting to investigate the production of DC since electrolyzers run with DC current. In that case no conversions would be necessary, eliminating the need for additional equipment and improving the overall efficiency. However, high power turbines are available only with alternate current generators. The electricity produced by the wind turbines must then be conditioned before powering the electrolysis process. A singl e AC-DC converter can take the turbine AC generator voltage and provide an appropriate voltage to the electrolyzer. Also the power must be smoothed before being supplied to the electrolyzer, because its variability can increase the internal wear, the impurities in the hydrogen produced and the energy losses of the electrolyzer [26]. To run the electrolysis, it is not only necessa ry the have the electricity from the wind farm but also a water supply for feedstock and coolin g. The feedstock water, which will ultimately be split into hydrogen and oxygen, must be purified and deionized. Therefore, a water treatment facility is also needed. The output of the electrolyzer system is hydrogen and oxygen at a pressure that depends on the technology used. It is convenient to utilize high-pressure electrolyzers. In this way the more efficien t compression can be achieved, along with a higher efficiency electrolysis process.

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50 Finally, to provide for the stor age and distribution of the pr oduct, the plant must include enough storage for the final product along with the distribution pipelines to transport the gas. This section of the process would also include the compressors necessary to reach the desired pressures, depending on the type of storage selected. Also an auxiliary power system is also re quired to provide the power needed to run compressors, pumps, lighting, control systems, etc, using the hydrogen produced by the plant. Figure 2-1. Process schematic. Capacity Calculation To calculate the capacity of the plant we can start from the wind farm or from the desired hydrogen output. In any case, the relation between the different pr ocesses is the same and the only difference is with which data we enter in to the model. First we must define how the different systems relate to each other so we can relate the wind availability to the final hydrogen production. The electricity produced by the wind farm will be determined by the characteristics of the wind and the wind turbines utiliz ed, losses in the conversion and conditioning, and other factors

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51 like turbines reliability and maintenance. The tota l electrical power available for the electrolyzers relates to the hydrogen production through the electrolyzer energy consumption and its efficiency. Finally, we must estimate the losses in the storage and di stribution by leakage of hydrogen. Wind farm The annual energy yield by a wind farm can be calculated by adding the contribution of each turbine. The energy generated by each turb ine, as explained in the introduction, depends on the turbine power curve and the wind speed distri bution. For a particular turbine in a specific site, we can define the annual cap acity factor as the quotient of the energy generated during a year (MWh) and the turbine rated power (MW) times the number of hours in a year. The same definition can be extrapolated to the wind farm. The rated power of a wind farm is obtained by adding the rated power of the turb ines used. Then we must consider the array losses. An array efficiency can be defined as the coefficient between the annual energy produced by the array and the energy that would be produced by an isolated turbine in the same position multiplied by the number of turbines in the array. Finally, before the electricity can be utilized for electrolysis, it is necessary to match the power and voltage. The devices for voltage regula tion can be designed with efficiencies as high as 93-95%, but this efficiency might be ach ieved only in a narrow power range [2]. Electrolysis system The hydrogen produced in the elect rolyzers is a function of the electricity available and can be calculated by dividing it by the electrolyzers energy consum ption. The electrolyzer energy consumption is the amount of energy requi red to produce a certain amount of hydrogen. Another way of characterizing an electrolyze r is by its efficiency. The electrolyzer efficiency can be defined as the energy in the hydrogen produced, usually using the higher

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52 heating value (HHV), divided by the energy used to produce it. In this way, the total hydrogen production would equal the product of the total energy available times the efficiency of the electrolyzer and divide d by the HHV of hydrogen. In many models developed for energy storage [2 7], the efficiency of electrolyzers is not considered constant since it runs at different power according to the electricity produced by the wind farm. For this study, it was considered that due to the magnitude of the production, and the availability of multiple electrolysis modules, it would be possible to control the electrolysers in use to obtain a maximum performance by running the operational ones at their maximum efficiency. With proper wind forecasts, these peri ods of inactivity can be used for maintenance, reducing maintenance downtimes in the production. Water consumption Hydrogen conversion ef ficiencies of 80% were assumed for the model, resulting in 11.25 kg of water required to produce 1 kg of hydrogen (11.13Nm3). This would not include the cooling water. The information on cooling water requirements for electrolyzers is very scarce. Some studies assume that the cooling water is included in the 80% c onversion efficiency [16, 17], based on information of electrolysis systems commercially available. These systems are small and do not require cooling. Teledynes Ti tan EC Generator requ ires a maximum flow rate of 189lpm (50gpm) at a maximum inlet temperature of 40C to produce 5 kg/hr of hydrogen (56 Nm3/hr). This is the requirement specified by the manufacturer for an extreme condition, considering the use of rather hot water. That represents a maximum of 2268 l/kg of hydrogen produced. This water is used for cooling a nd must be available to run the process. Storage The am ount of storage needed depends on th e annual throughput and storage time. Once the storage required is determined, the equipmen t necessary will depend on the technology used.

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53 It is important to remember that if the hydrogen is to be transported in pi pelines, and particularly in this case where the distances are large, th e pipelines might provide enough hydrogen storage. For example, reducing the pressure from 20 MPa to 15 MPa in a 2,100 km pipeline of 0.25 m diameter would represent 442 tons of hydrogen (4.92 million NM3). For this model, no onsite storage was consid ered. It was assumed that all the production would be sent to the pipeline, and differences between the production and consumption would be handled by varying the operation pressure of the pipeline. Another option would be to connect the wind farm to the power grid and supply electricity to it when the demand for hydrogen is low. This option was not studied but could be subject of future research. Hydrogen pipeline Even though there are studies on the transportation of hydrogen in natural gas pipelines, for the calculations of the m odel it was assumed the construction of a new pipeline that would run from the site where the electrolysis system is located to the coast, and then north, parallel to the existing natural gas lines, to Buenos Aires, where the main consumption centers are located. This would require 2,100 km (1,300 miles) of pipeline. The pipeline was assumed to have a diameter of 0.25 m (10 in.), a delivery pressure of 20 MPa (2,900 psia), and a pipeline gas temperature of 10C. At these conditions the pipeline would be holding approximately 3.94 107 Nm3 of hydrogen (3.54 106 kg) that is 1.32 days of production for a 1 1010 Nm3 annual hydrogen production. Technical Feasibility To determ ine the technical feasibility a lite rature search was conducted for each of the different components of the proc ess. The main components are the wind farm, the electrolysis system and the storage and distribution system.

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54 Economic Feasibility Different researchers have de veloped several m odels for th e calculation of hydrogen cost [9, 28-31]. The model chosen for this study is an adaptation from the one used by Mirabal [9], which was originally created by Steinberg and Cheng of Brookhaven National Laboratory in 1989 [28]. The model divides the cost in three main areas the capital investment of the plant, the annual operating costs and the re turn on the investment. As it was originally conceived to compare different production techno logies, the data were normalized to a single year to allow for comparison. This was not necessary for this study since we are only planning to estimate the cost for the final product in the partic ular case of wind power electrolys is. Also, the studies presented by Mirabal and Steinberg and Cheng, for the case of water electrolys is, considered the electricity as a feedstock, while we included the complete wind farm in the calculation of the cost. The cost of the different components found in th e literature did not alwa ys agree. For that reason, in such cases, the lowest and highest costs found were used to calculate a minimum and a maximum hydrogen cost. Table D-2 in the Appendix D summarizes the costs assumed for the different components. All the lo west costs were used to calc ulate the minimum hydrogen cost, and in the same way, all the highe st were used to calculate th e maximum hydrogen cost. The cost of hydrogen produced with this process would then be expected to fall in this range. Capital Investment The capital investm ent includes the cost of the facilities, in terest during the construction and working capital and any other startup expe nses. Again the cost can be divided among the wind farm, the electrolysis system and the storage/distribution system.

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55 The interest was assumed as 10% for the equipm ent and facility cost, the startup expenses 2% of the equipment cost and for the working capital 2 months of the operation and maintenance costs were included. Operating Costs The operatin g costs include the cost of th e feedstock, maintenance, labor and other expenses necessary to run the facility. In the case studied, the electric ity is obtained from the wind, th en, the only feedstock is the water used in the system. Since th e water is assumed to be obtain ed from a river, no cost is considered except that necessary to treat th e water before going in the electrolyzer. Return on Investment The return on the investm ent accounts for the profit expected to be obtained from the investment. The percentage assigned to the pr ofit will determine the payback time. The annual return on the investment was assumed to be 20% of the total capital investment. Hydrogen Cost The hydrogen cost is calculated as the total revenue required per year divided by the hydrogen production. The total annual revenue required is the annual return on the investm ent plus the annual depreciation and the total annual operation costs. The hydrogen production used is the total available as a final product, i.e. the total produced mi nus the losses in the storage and transportation. The annual depreciation was simply calculated as the division of the total equipment and facilities cost by the total projec t life; and the return on the investment as a percentage of the total capital investment. Finally, the use of electrolysi s to produce hydrogen has a va luable by-product, oxygen. If the oxygen can be commercialized, the total cost can be distributed between these two products resulting in a lower hydrogen cost. To evaluate this, the costs of transporting the oxygen, the size

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56 of the market and price of oxygen must be evaluated, and a credit for by-product oxygen estimated. Data acquisition and model assumptions The following sections detail the assum ptions us ed in the calculation of the capacity of the plant and cost of the hydrogen pr oduced. The values were obtained fr om the literature and in the cases were large variations were found in the cost of a componen t, the lower and higher cost were assumed to calculate a mi nimum and a maximum hydrogen cost. The assumptions used in the capacity calcula tion can be found in Table D-1 in Appendix D, and the assumptions for the cost calculation are available in Table D-2. Table D-2 shows the values used to calculate the minimum and the maximum hydrogen cost. The minimum cost uses the lowest values for the components found in th e literature, while the maximum cost uses the highest. The minimum and maximum hydrogen costs calculat ed in this way define a range in which the actual hydrogen cost produced with the process described is expected to fall. Wind speeds and wind farm The setting up of a wind far m requires ma ny activities that are necessary for the installation of the wind turbines, from pla nning and management to the construction of foundations and access roads. For onshore installation in flat terrain, the tota l investment cost can be estimated to be 1.3 times the cost of the turbines [32]. For other site s, like remote or upland areas, the costs are usually highe r. A typical breakdown of cost s are detailed in Table 2-1. Table 2-1. Typical breakdown cost for a 10 MWe wind farm [32]. Component % of total cost Wind turbines 65 Civil works (including foundations) 13 Wind farm electrical infrastructure 8 Electrical network connection 6 Project development and management costs 8

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57 In that case the total investme nt cost would amount to 1.54 times the cost of the turbines. In the particular case of this study, the location selected is flat but remote but due to the size of the project a factor of 1.3 was used in the calcul ations. Since the price fo r the turbines available is for installed turbines, and considering that th e civil works represent 10% of the turbine cost, a factor of 1.18 of the insta lled turbine cost for the to tal investment was assumed. The Repower 5M, manufactured by REpower Systems AG, was the turbine chosen for the theoretical model. With a rated power of 5MW and a 126-meter ro tor diameter, it is one of the largest in the world. The specifica tions of this turbine can be f ound in the Appendix A, in Table A-1, and its power curve can be found in Figur e A-1. The information was obtained from the wind turbine brochure provided by REpower Systems AG [33]. The specifications for this turbine were input into the SIG Elico to calculate the capacity factor and annual energy capacity for these turbines in stalled in the site selected. SIG Elico or Mapa de Potencial Elico Argentino (Argentine Wind Power Map) is software developed by the Subsecretara de Coordinacin y Contro l de Gestin del Ministerio de Planificacin Federal, Inversin Pblica y Servicios (Sub secretary of Coordination and Management Control of the Federal Planning, Public Investment a nd Services Ministry) and the Centro Regional de Energa Elica (Wind Power Regional Center) that contains wind speed information and calculates the power that could be obtained at any location by a given turbine. It also contains information on roads, permanent rive rs, electricity distributi on lines and cities. The information included comes from the model GTOPO 30, a global digital model of terrain elevation, information gathered by Argen tine satellites, and the Global Land Cover Characterization of the U.S. Geological Surve y. The wind speed information represents data compiled for 5 years gathered from different mete orological stations in th e country. The software

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58 includes maps of wind speeds, energy density, te rrain and roughness. Images of the software can be seen in Figure C-2 to C-4. The software calculates the annual energy that could be obtained by the wind turbine in a chosen location using the wind data, the terrain roughness and the turbine power curve. It also gives the annual capacity factor corresponding to th e turbine rated power. For the site selected the annual capacity factor aver aged between 54 and 55%. A fact or of 54% was used in the calculations. The wind rose and probability densit y function of the wind speed plot for the site selected are included in the Appendix C in Fi gure C-5 and C-6. Table C-2 shows the capacity factors and other information calc ulated by the software for the REpower 5M turbine located in different points in the area. Regarding the area needed for the wind farm, it was determined from the literature that it could be assumed that 5 MW of wind turbine cap acity could be installed per square kilometer [30]. In the case of the REpower 5M turbine, considering 10 rotor diameters for downwind spacing, and 5 for crosswind, we can assume an a rray efficiency of 90%. Assuming that 80% of the land is usable, we obtain a turbine density of one turbine per squa re kilometer (5 MW/km2). To estimate the investment necessary for the wind farm a literature search was carried out, resulting in the conclusion that investment co sts are typically expressed in the cost of the electricity per kWh. Information on the cost of wind turbine installation is scarce and highly variable. A report from Lawrence Berkeley National Laboratory summarizes information on wind power installed in the United States be tween 1982 and 2006. According to the report, due to the weakness of the dollar, the rising cost of materials and energy (e.g., steel and oil), a shortage of components and turbin es, a move of the manufacturers to increase their profitability and an up-scaling of turbine size and sophistication, the wind turbin e cost has began to increase

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59 in the year 2006 [35]. Af ter many years of decline, the cost of installed projects started to rise, driven by the increase in turbine costs. The report indicates an average of $1,680/kW for installed projects in the year 2006 and could reach as high as $1,800/ kW in future years [35]. For wind turbines, the average value for 2006 is $1,100/ kW and includes the turb ine, tower, erection, and limited warranty and service agr eements [35]. This means that the cost of an installed 5MW turbine should be in the order of $5.5 million. As a point of comparison, the Energy Information Administration reports that curren t construction costs for a typical natural gas or coal plant range from $536 per kilowatt for combined-cycle techno logies to $1,367 per kilowatt for coal-steam technologies. For the model calculation a lowest cost of $4 million and a maximum of $6 for a 5 MW installed turbine were assumed, although it would be expected that due to th e size of the project, the localization of parts by the manufacturer of the wind turbin e and the economy of scale the cost could be reduced. With respect to Operation and Maintenance Costs (O&M), the information available is not only scarce, but also has been changing drastically in the last few years. There is some experience now to estimate these costs, but the technology has been changing fast so it is not easy to extrapolate historical data. The average of available data shows a sharp decrease of the annual operation and maintenance cost for the last few years, being as low as $8/MWh for 2006 [35]. It is also true that O&M co sts are expected to increase as turbines age, but at the same time they are expected to decrease with larger turbines and more sophi sticated designs. It would also be expected that the costs would reduce with th e size of the project. For the model, the annual O&M costs were assumed to be $8/MWh.

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60 Finally the cost of renting the land for the in stallation of the wind turbines was included in the operation and maintenance costs of the wind fa rm. There is no experience on land rental with this purpose in Argentina. The existing wind fa rms are located in land owned by the utility. The value was estimated to be between $1000 a nd $1500 per installed MW per year, based on conversations with personnel from the Ar gentine Sub secretary of Coordination and Management Control of the Federal Planning, Public Investment a nd Services Ministry. Electrolysis system As there are no large-scale electrolys is commerci al systems, it is hard to estimate the costs of the eletrolyzers. Currently, electrolysis is only used in small scale (up to 11,590 Nm3 H2/day), and it is found that the main cost in the hydrogen produced is the cost of the electricity used, being 58% and the capital costs only 32% (using electricity fr om the grid) [15]. For the calculations, different estimations obtained from the literature were evaluated to obtain the costs for capital investment and operation and maintena nce per kilogram of hydrogen produced. Also, different publications were reviewed for the modeling of the electrol yzer performance [15, 36, 37]. Even though there are no data for large-scale electrolyzers, there ar e many designs of such plants with capacities up to several hundred MW The information is summarized in Table 2-2. Table 2-2. Electrolyzer energy consumpti on estimated developement [36, 37]. Data source 1995 (kWh/Nm3)* 2010 Projected value (kWh/Nm3) 2050 Optimistic value (kWh/Nm3) Fluor-Daniel 4.4 n/a n/a Norsk Hydro 4.9 4.1-4.3 3.6-3.7 Teledyne Brown 4.3 3.8 2.5 Stuart Energy 4.7 n/a n/a Model Value 4.0 Normal Cubic Meter (Nm) is a measures of the quantity of gas equal to a cubic meter of volume at 0C (273.15 K) and 101.325 kPa. Density of H2 = 0.0899 kg/Nm3 The Fluor Daniel Inc value correspo nds to a 100 MW plant producing 21,788 Nm3/h with an energy consumption value of 4.4 kWh/Nm3. The Norsk Hydro data is for a 265 MW plant

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61 producing 396 million Nm3/yr. The Teledyne Brown Engineering data are for their HP size hydrogen generating plant. The data from Stuart Energy Systems Inc. are for a central electrolysis plant producing 38 tons of hydrogen per day [37]. A study from the National Renewable Energy La boratory that analyzed the production of hydrogen from renewable sources, estimated curr ent electrolyzer technology requires 53 kWh to produce a kilogram of hydrogen (4.76 kWh/Nm3) [30]. This would be a 75% efficient system based on the H2 HHV, and includes the electrolysis stack, auxiliary systems and other losses. It was found in the literature that an energy consumption of around 4 kWh/Nm3 is a reasonable assumption for the year 2010, and rates of around 3.6 kWh/Nm3 are estimated for the year 2050 [16]. The output pressure was assumed to be 40 MPa, that is the objective for the next years, although some systems already reach this pressure but with higher electricity consumption. In the future, the costs of PEM electrolyzers ar e expected to be lowe r than for conventional alkaline electrolyzers. Different publications estimated costs between $32 and $55/GJ ($4.45$7.65/kg H2 year) for alkaline systems of 500 kW to 12 MW and $13/GJ ($1.81/kg H2 year) for a 530 MWe PEM system [38]. Mirabal estimate d an equipment and facility cost of $275.32 million for an annual hydrogen production of 11,870,000 GJ/year (85,396 tons/year) for 20 years project life [9]. This corresponds to $23.19/GJ year ($3.22/kg H2 year). Another recent publication that evaluated several hydrogen production methods for the short and medium term, estimates the cost of the to tal capital investment for water electrolysis in the year 2020 to be $2.39/kg H2 year (considering $1.54 = ) and annual operation and maintenance costs of $0.12/kg H2 year plus $0.04/kg H2 year for a 1000 Nm3/h pressurized alkaline electrolyzer [39]. Al so, Steinberg and Cheng estimate d the cost for hydrogen production

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62 for a production capacity of 2.4 106 Nm3/day (33 109 scf/year). Their total capital investment, including facilities, interest, startup costs and working capital wa s of $131.8 million ($1.66/kg H2 year), and annual operating costs, wit hout including feedstoc k electricity, of $13.6 million/year ($0.17/kg H2 year) [28]. The values were convert ed to the same unit and compared in Table 2-3. The estimations used in the calc ulations are also shown in the table and were chosen according to the most recent reference. Table 2-3. Electrolyzer cost data Reference Year Total capital investment ($/kg year of hydrogen) Annual O&M costs ($/kg year of hydrogen) [28] 1989 1.66 0.17 [38] 1999 1.81 7.65 [9] 2003 3.22 [39] 2007 2.39 0.16 Model 1.8-3 0.16 With respect to water treatment, large-scale reverse osmosis systems are treating conventional water at $0.26 per 1000 liters ($1 per 1000 gal) [18]. The cost for treating seawater is around $0.53 $0.79 per 1000 liters ($2 3 per 1000 gallons) [18]. For the calculations, this cost was included in the operation and mainte nance costs of the electrolysis system. There is no legislation in Argentina rega rding the consumption of water for energy production in the form of hydrogen. Initially there is usually no charge fo r extracting water from rivers for process in factories or utilities. Due to the amount of water nece ssary and the fact that the water does not return to the source, it will be required to assess the e ffects of its extraction and work with the authorities to establish if a price should be paid for the consumption, and the maximum quantities available for a sustainable production. For very large production there is the possibility of utilizing seawater at a higher cost du e to the necessary desalination. It is very hard to estimate a cost for the water at this time; th erefore the model assumes the cost of treating the

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63 water as the total water cost. The value used is $0.26 per cubic meter for conventional water, and $0.53-$0.79/m3 for seawater. Storage and distribution facilities As explained before, it was assum ed that no la rge storage was necessary since the pipelines would provide all the storage necessary. The cost of the pipelines was calculated with the length and cost per kilometer obtained from the literatu re. With an output pressu re from the electrolyzer of 40 MPa, there is no compression work necessary to supply the pipeline. A large fraction of the cost of a pipeline is its installation, and it doe s not differ much from the installation of natural gas pipelines. For that reason, the cost of a hydr ogen pipeline can be estimated with good accuracy. Table 2-4 shows the typical costs for some pipelines [4]. The costs were available in 1995 dollars and were co nverted using an inflation rate of 1.39 obtained from the Inflation Calculator from the Bureau of Labor Statistics. Table 2-4. Pipeline installa tion costs in 2008 dollars [4] Length Cost km mi $ $/km $/mi Source 78.4 48.7 $25,020,000 $319,000 $514,000 TransCanada Pipeline, Ltd. 1996 108.5 67.4 $116,760,000 $1,076,000 $1,732,000 TransCanada Pipeline, Ltd. 1996 46.9 29.1 $66,720,000 $1,423,000 $2,293,000 TransCanada Pipeline, Ltd. 1996 731 454 $1,264,900,000 $1,730,000 $2,786,000 TransCanada Pipeline, Ltd. 1993 561 349 $533,760,000 $951,000 $1,529,000 TransCanada Pipeline, Ltd. 1997 40.2 25 $7,367,000 $183,000 $295,000 NYSEG 1996 The main portion of operation and maintenance costs for pipelines is the compressor power and maintenance. The hydrogen losses are expected to be very low since in the case of natural gas they are lower than 1% [4]. Many studies i ndicate that pipelines are the cheapest means to transport large quantities of hydrogen, except in th e case of transport across the ocean, in which case the transport of liquid hydrogen by ship is cheaper. The costs for O&M estimated by different studies are $0.39/kg ($0.18/lb) fo r the United States and between $0.90-$1.20/kg

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64 ($0.41-$0.53/lb) for a particular case of a pipeli ne from North Africa to Central Europe (3,300 km / 2,050 mi) [4]. For the model a minimum and maximum pipeline cost of $600,000/km $1,000,000/km ($960,000/mile $1,600,000/mile) was assumed for the 2,100 km (1,300 miles) pipeline; and an operation and maintenance cost of $0.4/kg $1/kg ($0.18/lb $0.45/lb). By-product oxygen We can estim ate the size of Argentine oxygen market by analyzing the statistics for oxygen production. Figure 2-2 shows the annual oxygen pr oduction in Argentina from 1995 to 2006. It can be seen that the production is increasing steadily, and that it grew around 5% in 2005 and 2006 reaching around 175 million cubic meters in 2006. Figure 2-2. Annual oxygen production in Argentin a. Source: INDEC, Industrial Product Statistics, December 2007. A by-product oxygen credit of $40/ton ($0.057/m3) was used in some estimations of the hydrogen cost [28]. An average price for oxyge n in Argentina was found to be around 70/ m3 ($490/ton). Assuming a market share of 10%, only 17.5 million cubic meters of oxygen would be commercialized annually (0.3% of the total oxygen production for a plant producing 1 1010

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65 Nm3 of hydrogen per year), generating $1 million credit annually (at $40/ton). This would represent a negligible reduction of the cost of the hydrogen produced. Fo r this reason the credit for by-product oxygen was not includ ed in this study. In future studies the possibility of exporting oxygen should be analyzed.

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66 CHAPTER 3 RESULTS Technical Feasibility The technic al feasibility of the project was determined by reviewing the literature on the different components and analyzing the technical aspects of integr ating these com ponents into a production system. The wind power technology is well proven and cu rrently commercially available. It can be considered a mature technol ogy although it is still consta ntly improving [3, 19-21, 32, 35]. There are already some commercially available electrolyzers, but the technology for the production of very high volumes of hydrogen is s till under development. However, electrolyzers are modular, so any capacity can be reached by combining individual units. There are also many designs for large-scale electrolyzers, and even though a large-scale (over 1 million Nm3/day) electrolyzer has not been built, electrolysis is a very developed technology and it is reasonable to consider that such a system can be built. In the case of storage and transportati on of hydrogen, the technologies necessary are mature and commercially available [2]. Recently hydrogen pipeline construction was added to the ASME B31.12 code. In conclusion, the technology necessary for th e integration of the components into an operable system is available. Perhaps the effi ciency of the electrolysis and cost of windgenerated power are not favorable at this time, but they are expected to improve considerably in the near future. Economic Feasibility A range of costs (m inimum and maximum) of hydrogen delivered to Buenos Aires, located 2,100 km (1,300 miles) from the hydrogen plant, wa s estimated for different production sizes.

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67 Buenos Aires was chosen as the final destination for the hydrogen because the population in Argentina is centralized in that region (Figure B-4), so it is where the most energy is consumed in the country. For a pipeline of that length it was found that the price of hydrogen decreases drastically until a hydrogen annual production of approximately 1 1010 Nm3 (Figure 3-1). For higher capacities the price still decreases but no so sharply. The delivered hydrogen price for that capacity would be between $31.9/GJ and $50.4/ GJ ($4.43/kg $7.01/kg) c onsidering hydrogens HHV. The wind farm required would have a rated power of 11 GW consisting of 2,200 5MW turbines and requiring an area of approximately 2,200 km2 (Figure 3-2). The calculations and assumptions are included in Appendix D. Figure 3-1. Hydrogen cost for different produc tion capacities calculated based on assumptions listed in Tables D-1 and D-2. Data ava ilable in Tables D-3, D-4, D-6 and D-8.

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68 Figure 3-2. Calculated re quired wind farm area. The total capital investment fo r a plant of this capacity is estimated to be between $12.5 and $19.4 billion, and for the pipeline between $1.5 and $2.5 billion (109). The total capital investment for the hydrogen plant is comprise d of $10.5 $16.01 billion for the wind farm and $2.02 $3.35 for the electrolysis system. The tota l capital investment in cluding the pipeline is then $14 $21.9 billion for a plant producing 1 1010 Nm3 of hydrogen per year (Figure 3-3). The estimated costs agree well with other publis hed values (Figure 3-4). They might seem slightly higher, but this can be explained by the cost assumed for the wind-generated electricity (Figure 3-5). The electricity prices used in the other esti mations are based on prices of wind-generated electricity for market conditions. These values agree with current values and estimations. For example the average price for electricity in 2006 was $36/MWh, but these pr ices are subsidized by the receipt of any available state and federal incentives and the value that might be received through the separate sale of renewable energy certificates [35]. Therefore they do no reflect the actual wind generated electricity costs.

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69 Figure 3-3. Total capital investment for diffe rent production capacities calculated based on assumptions listed in Tables D-1 and D-2 in Appendix D. Data available in tables D3, D-4 and D-6. Figure 3-4. Comparison of the estimated hydrogen cost against different published estimations. The costs were corrected to 2007 dollars fo r comparison. Data available in Table D-9 in Appendix D.

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70 Figure 3-5. Comparison of electric ity costs used to estimate the hydrogen cost. The costs were corrected to 2007 dollars for comparison. Data available in Table D-9 in Appendix D. Analyzing the cost breakdown it was found that if the transportation of hydrogen is not considered, the main cost component is the wind farm (81 82% of the cost) and the rest (18 19%) corresponds to the electrolysis system. If we consider that the cost component of the wind farm relates to the electricity cost in othe r estimations, the model agrees well with other publications. Other breakdowns s how the feedstock (includes electricity from wind power) representing 81.9% of the hydr ogen cost, the capital costs 14.1% and O& M costs 4.0% [28]. Another case shows that electricity accounts for 58%, and capital co sts for 32% [15]. In this case the difference can be explained by the higher el ectricity costs. Figure 3-6 shows the cost breakdown for hydrogen for the lowest cost estimation. As a comparison, steam methane reformation produces hydrogen at a cost of around $5.44 $7.46/GJ (using hydrogens HHV), where the feedst ock costs are 52%-68% of the total cost

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71 and the remaining mostly capital charges [38]. So if the cost of methane were to double, the cost of hydrogen from this process would reach $8.7 $11.94/GJ. When the transportation is included (Figure 3-6 B), it accounts for 21-27% of the hydrogen cost, when considering a production of 1 1010 Nm3 of hydrogen per year. This is important to remember since the cost of tran sportation through pipelines is very dependent on the amount of hydrogen transmitted. Figure 3-6. Estimated hydrogen cost breakdown (lowest cost). Data available in Tables D-5 and D-8. A) without the pipeline and B) includi ng the pipeline for delivery to Buenos Aires Water Consumption The total water feedstock consum ption amount s to a total of 30,500 cubic meters per day for a plant capacity of 1 1010 Nm3 of hydrogen per year (average 3 107 Nm3 of hydrogen per day). The amount of water required for different capacities is shown in Fi gure 3-7. The cost of treating that amount of water was estimated to be $3 million per year. This represents around 0.06% of the total hydrogen cost without tran sportation. This assumes that the water is essentially a free resource, whic h could change in the future.

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72 If seawater were used at doubl e or triple treatment cost, th e effect on the hydrogen cost for large-scale production would be negligible. So from the economic point of view, the use of seawater is feasible. Figure 3-7. Water consumption for different pl ant capacities calculated based on assumptions listed in Table D-1. Data available in Table D-3. ASSUMPTION Electrolyzer water conversion efficiency: 80%

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73 CHAPTER 4 CONCLUSIONS Conclusions The cost ana lysis performed used data obtained from the literature. With the available data, a range of hydrogen costs was calculated. The de livered hydrogen cost was found to be between $31.9 and $50.4/GJ ($26.3 $38.7/GJ without transportation). The price of hydrogen produced with this technology is not comp etitive with natural gas in th e Argentine market, where the current price for natural gas for large consum ers without tax is around $1.05/GJ (considering $1 equivalent to 3.15 Argentine pesos) [40]. However, in the beginning, hydrogen would compete with liquid fossil fuels. A price of gasoline of $3/gal, which include s taxes, represents $22.88/GJ. The estimated cost of delivered hydrogen is 39 -120% higher. Without transportati on or storage, the cost of hydrogen is only 14.9-69.1% higher than gasoline at $3/gal. The cost of hydrogen produced by steam me thane reformation is around $5.44 $7.46/GJ. The hydrogen cost without transportation produ ced with electrolysis using wind power electricity would be between 2.5 and 6.1 times higher. When comparing hydrogen with other fuels there are different factors to consider. Hydrogen utilization is usually more efficient than other fuels. Also we mu st consider the hidden costs of utilizing fossil fuels, like pollution and the emission of green house gases. This is very difficult to quantify, but as the legislation re gulating these emissions increase, the use of hydrogen might become more convenient. Considering all the information presented, the study concludes: The construction of a plant for producing hydr ogen using water electrolysis using windgenerated electricity is technically feasible.

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74 The technology for electrolysis has not reached ye t the efficiency assumed in the study and no plant of such capacity has ever been built. From the economic point of view, but without considering the environm ental cost of fossil fuels, hydrogen produced in this way is stil l not competitive with liq uid fossil fuels like gasoline. Even considering the large un certainty in the costs calc ulated, the cost of hydrogen produced in this way is still t oo high to justify a more detailed analysis; at least until there is a breakthrough in the technology or a strong reduction of the costs. Recommendations for Future Studies Even if the costs estimated in this thesis mi ght discourage a more detailed analysis at the present time, some recommendations for future studies can include: A better estimation of the cost s involved should be carried out with collaboration of potential suppliers of wind turb ines and electrolyzers, partic ularly if an improvement in electrolyzers efficiency takes place. Other factors that might favor the use of hydrogen, like pollution, a global transition to a hydrogen economy or the assurance of a local energy source should be assessed. The wind resource in Patagonia is important, so other ways of transporting the energy from Patagonia, like HVDC, should be studied and compared.

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75 APPENDIX A HYDROGEN PROPERTIES Table A-1. Lower and higher heating values of hydrogen and fuels [13]. Fuels Lower Heating Value (LHV) *1 Higher Heating Value (HHV) *1 Gaseous Fuels Btu/scf *2 Btu/lb *3 MJ/kg *4 Btu/scf *2 Btu/lb *3 MJ/kg *4 Gaseous Hydrogen 28952,226121331 59,816 139 Natural Gas 98320,26747.11,089 22,453 52.2 Liquid Fuels Btu/gal *2 Btu/lb *3 MJ/kg *4 Btu/gal Btu/lb *3 MJ/kg *4 Crude Oil 129,67018,35242.7138,350 19,580 45.5 Conventional Gasoline 116,09018,67943.4124,340 20,007 46.5 Reformulated Gasoline (RFG) 113,60218,20842.4121,848 19,530 45.4 California RFG 113,92718,27342.5122,174 19,596 45.6 U.S. Conventional Diesel 128, 45018,39742.8137,380 19,676 45.8 Low-sulfur Diesel 129,48818,32042.6138,490 19,594 45.6 Methanol 57,2508,63920.165,200 9,838 22.9 Ethanol 76,33011,58727.084,530 12,832 29.8 Residual Oil 140,35316,96839.5150,110 18,147 42.2 Liquefied Petroleum Gas (LPG) 84,95020,03846.691,410 21,561 50.2 Liquefied Natural Gas (LNG) 74,72020,90848.684,820 23,734 55.2 Propane 84,25019,90446.391,420 21,597 50.2 Solid Fuels Btu/ton *2 Btu/lb *5 MJ/kg *3 Btu/ton Btu/lb *5 MJ/kg *3 Bituminous Coal (as received) 22,460,60011,23026.123,445,900 11,723 27.3 Coking Coal (as received) 24,600,49712,30028.625,679,670 12,840 29.9 Woody Biomass (dry) 16,811,0008 ,40619.617,703,170 8,852 20.6 Herbaceous Biomass (dry) 14,797,5557,39917.215,582,870 7,791 18.1*1 The lower heating value (also known as net calorific value) of a fuel is defined as the amount of heat released by combusting a specified quantity (initially at 25C) and returning the temperature of the combustion products to 150C, which assumes the latent heat of vaporization of water in the reaction products is not recovered. The higher heating value (also known gross calorific value or gross energy) of a fuel is defined as the amount of heat released by a specified quantity (initially at 25C) once it is combusted and the products have returned to a temperature of 25C, which takes into account the latent heat of vaporization of water in the combustion products. *2 Btu = British thermal units; scf = standard cubic feet. *3 The heating values for gaseous fuels in units of Btu/lb are calculated based on the heating values in units of Btu/scf and the corresponding fuel density values. The heating values for liquid fuels in units of Btu/lb are calculated based on heating values in unit of Btu/gal and the corresponding fuels density values. *4 The heating values in units of MJ/kg, are converted from the heating values in units of Btu/lb. *5 For solid fuels, the heating values in units of Btu/lb ar e converted from the heating values in units of Btu/ton.

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76 Table A-1 continued. Fuels Density Gaseous Fuels grams/scf *2 Gaseous Hydrogen 2.51 Natural Gas 22.0 Liquid Fuels grams/gal Crude Oil 3,205 Conventional Gasoline 2,819 Reformulated Gasoline (RFG) 2,830 California RFG 2,828 U.S. Conventional Diesel 3,167 Low-sulfur Diesel 3,206 Methanol 3,006 Ethanol 2,988 Residual Oil 3,752 Liquefied Petroleum Gas (LPG) 1,923 Liquefied Natural Gas (LNG) 1,621 Propane 1,920*2 Btu = British thermal units; scf = standard cubic feet. 0 20000400006000080000100000120000140000 Crude oil Coal Dry Wood Hydrogen, gas (STP) Hydrogen, compressed gas 30x10^6 Pa Hydrogen, liquid Hydrogen, metal hybride (avg) Methanol Ethanol Inorganic salts, heat of fusion >300C Pumped hydro, 100 m head Compressed air Flywheels, steel (avg) Flywheels, advanced Lead-Acid (avg) Nickel-Cadmium Lithium ion Other advanced batterieskJ/kg Electrochemical Mechanical Thermal High Quality Thermal Low Quality Synthetic fuels Conventional fuels Figure A-1. Energy density by weight for various storage forms [3].

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77 050001000015000200002500030000350004000045000Crude oil Coal Dry Wood Hydrogen, gas (STP) Hydrogen, compressed gas 30x10^6 Pa Hydrogen, liquid Hydrogen, metal hybride (avg) Methanol Ethanol Inorganic salts, heat of fusion >300C Pumped hydro, 100 m head Compressed air Flywheels, steel (avg) Flywheels, advanced Lead-Acid (avg) Nickel-Cadmium Lithium ion Other advanced batteries Superconducting MJ/m310 Electrochemical Mechanical Thermal High Quality Thermal Low Quality Synthetic fuels Conventional fuels Figure A-2. Energy density by volume for various storage forms [3].

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78 00.10.20.30.40.50.60.70.80.91 Hydrogen, gas (STP) Pumped hydro, 100 m head Compressed air Flywheels, advanced Lead-Acid Battery (avg) Lithium ion Battery Other advanced batteries Superconducting Cycle efficiency Figure A-3. Cycle efficiency for various storage forms [3].

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79 APPENDIX B MAPS Figure B-1. Location of Ar gentina in the world.

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80 Figure B-2. Argentine map showing average wind speed at 50 m above ground and Patagonia. Source: Mapa de Potencial Elico Argentino (Argentine Wind Power Map) Average Wind Speed (m/s) Patagonia

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81 Figure B-3. Patagonias topography. Source: Mapa de Potencial Elico Argentino (Argentine Wind Power Map) Average vegetation height (m) Altitude (m)

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82 Figure B-4. Argentine population dist ribution per province. Source: Secretara de Ambiente y Desarrollo Sustentable. Jefatura de Gabinete de Ministros (http://www.ambiente.gov.ar/)

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83 Figure B-5. Patagonia map showing average wind speed at 50 m above ground and permanent rivers. Source: Mapa de Potencial Elico Argentino (Argentine Wind Power Map)Average Wind Speed (m/s) Site selected for the study

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84 APPENDIX C WIND POWER CALCULATION DATA Figure C-1. REpower 5M power curve

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85 Table C-1. REpower 5M technical data Design data Rated power 5,000kW Cut-in speed 3.5m/s Rated wind speed 13 m/s Cut-out speed 25 m/s onshore 30 m/s offshore Rotor Diameter 126 m Rotor area 12,469 m2 Rotor speed 6.9 12.1rpm (+15.0 %) Masses Nacelle (without rotor) Aprox. 290 metric tons Rotor Aprox. 120 metric tons Rotor blade Length 61.5m Type Graphite fiber composite (GFC )/Carbon fiber composite (CFC) shell construction with epoxy, pre-bent Yaw system Type Externally geared four-point bearing Drive system Gear motors with multi-disc brakes Stabilization Disc brake with h ydraulically operated brake shoes Gear system Type Two helical planetary st age and one spur gear stage or (optional) helical planetary step-up gear with on e spur gear step Transmission ratio i = approx. 97 Electrical system Generator type Double-fed asynchronous generator, 6-pole Rated power 5,000kW Rated rotor voltage 660V Rated stator voltage 950V Rated speed 670 1,170 rpm (+15.0 %) Power control Principle Electrical blade angle ad justment pitch and speed control Tower Type Steel tube or concrete tower or concrete/steel hybrid construction Hub height 100 / 117m onshore approx. 90 m offshore (depending on site conditions) Foundation Onshore Reinforced concrete foundation, depending on site conditions Offshore Substructure suitable for actual site Safety system Individually adjustable bl ades (electrically controlled) fail-safe system Extensive temperature and speed sensing system including built-in redundancy Fully integrated lightning protection Automatic fire protection system Shielded cables protecting people and machinery Rotor holding brake with soft-brake function

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86 Figure C-2. SIG Elico. 2006 Ministerio de Planificacin Federal Centro Regional de Energa Elica (Chubut) Figure C-3. SIG Elico, main screen. 2006 Minist erio de Planificacin Federal Centro Regional de Energa Elica (Chubut)

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87 Figure C-4. SIG Elico, wind power information screen. 2006 Ministerio de Planificacin Federal Centro Regional de Energa Elica (Chubut)

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88 Table C-2. Wind power data for the wind farm site utilizing a single REpower 5M turbine. Data point Latitude Longitude Average wind speed (m/s) Power density (W/m2) Annual energy produced (MWh/year) Capacity factor (%) 1 -48 37' 59" -70 7' 25" 14.16 3,799 23,380 53.39 2 -49 2' 9" -70 51' 0" 11.43 1,803 23,920 54.61 3 -48 12' 15" -70 25' 0" 12.51 2,508 24,270 55.42 4 -48 55' 35" -69 50' 20" 12.31 2,383 25,260 57.68 5 -48 21' 11" -69 46' 24" 13.88 3,420 22,820 52.10 6 -48 37' 59" -70 6' 53" 14.16 3,799 23,380 53.39 Model -48 17' -70 26' 23,650 54.00 Figure C-5. Wind rose for data point 1. Source: SIG Elico. 2006 Ministerio de Planificacin Federal Centro Regional de Energa Elica (Chubut)

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89 Figure C-6. Probability density f unction of the wind speed for da ta point 1. Source: SIG Elico. 2006 Ministerio de Planificacin Federa l Centro Regional de Energa Elica (Chubut)

PAGE 90

90 APPENDIX D CALCULATIONS Table D-1. Capacity ca lculation assum ptions. Wind Farm Turbines Rated Power (MW) 5 Rotor Diameter (m) 126 Crosswind spacing (rotor diam.) 10 Downwind spacing (rotor diam.) 5 Area required per turbine (km2)0.79 Wind Annual capacity factor54% Array Array Efficiency90% Voltage regulation / Conversion efficiency94% Land usability80% Electrolysis Consumption (kWh/Nm3)4 0 Consumption (kWh/kg)44.5 Electrolyzer water conversion efficiency80% Storage & Distribution Leakage losses 1% Pipeline length (km)2100 Diameter (m)0.25 Pipeline volume (m3)1.03E+05

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91 Table D-2. Cost calculation assumptions. Project Project life (years)20 Annual Interest (%)10% Startup costs (% of equipment cost)2% Return on the investment (%)20% Wind Farm Lowest Highest Capital investment Wind turbine unitary cost (million $)3.65.5 Total capital investment with respect to turbines cost1.181.18 Operation and Maintenance Annual O&M costs ($/MWh)88 Annual land rental ($/MW)10001500 Electrolysis Lowest Highest Capital investment Electrolyzer cost ($/kg H2)1.83 Operation and Maintenance Electrolyzer Annual O&M costs ($/kg H2)0.160.16 Conventional Water treatment ($/m3)0.260.26 Seawater treatment ($/m3)0.530.79 Hydrogen pipeline Lowest Highest Capital investment Pipelines cost (million $/km)0.61 Opertion and Maintenance Annual O&M costs ($/kg H2)0.41

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92Table D-3. Capacity calculations. Wind Farm Electrolysis Array ElectrolyzerWater Consumption Hydrogen (Final product) Oxygen Number of turbines Rated Power (MW) Annual energy from wind farm (106 MWh) Area (km2) Annual Hydrogen production (106 Nm3) Consumption (103 m3/year) Average water consumption (m3/day) Total annual production (106 Nm3) Average Daily production (106 Nm3) Equivalent annual energy (GWh) Total annual production (106 Nm3) 100 500 2 9950050613864961.41754252 200 1000 4 1981000101227729912.73508504 400 2000 8 39720012024554419825.470171007 600 3000 12 59530013036831729738.1105251511 800 4000 16 7944002404711089396410.9140332014 1000 5000 20 9925002505913861495513.6175412518 1200 6000 24 11916003607116633594616.3210503021 1400 7000 28 13897003708319405693719.0245583525 1600 8000 32 15888004809522177792821.7280664028 1800 9000 36 17869004910724950891924.4315744532 2000 10000 40 1985100051011827722991027.2350835035 2200 11000 44 2183 11005 11130 30494 10901 29.9 38591 5539 2400 12000 48 23811200612142332661189332.6420996042 2600 13000 52 25801300613154360381288435.3456086546 2800 14000 56 27781400714166388111387538.0491167049 3000 15000 60 29771500715178415831486640.7526247553 3200 16000 64 31751600816190443551585743.4561328056 3400 17000 68 33741700817201471271684846.2596418560 3600 18000 72 35721800918213498991783948.9631499063

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93Table D-4. Lowest cost calculations for diffe rent plant capacities. Values in million $. Wind Farm Capital Investment O&M Electricity Cost Wind Farm Rated Power (GW) Wind Turbine cost Total Wind Farm Interest Startup costs Working capital Total Annual O&M cost Annual Land Rental Total O&M costs Return on the investment Annual Depreciation Revenue required per year Cost of electricity ($/MWh) 0.5 360 425 42 7347716117951813064.9 1 720 850 85 146954321331913626064.9 2 1440 1699 170 29111909642663827252064.9 3 2160 2549 255 431728639639957310878064.9 4 2880 3398 340 582238181284132764144104064.9 5 3600 4248 425 722847721605165954180130064.9 6 4320 5098 510 8633572719261981145216155964.9 7 5040 5947 595 10139668122472311336252181964.9 8 5760 6797 680 11544763625682641527288207964.9 9 6480 7646 765 13050859028892971718324233964.9 10 7200 8496 850 144559545320103301909360259964.9 11 7920 9346 935 158 61 10499 352 11 363 2100 396 2859 64.9 12 8640 10195 1020 1736611454384123962291432311964.9 13 9360 11045 1104 1877212408416134292482468337964.9 14 10080 11894 1189 2027713362448144622672504363964.9 15 10800 12744 1274 2168314317480154952863540389964.9 16 11520 13594 1359 2308815271512165283054576415964.9 17 12240 14443 1444 2459416226544175613245612441864.9 18 12960 15293 1529 2599917180576185943436648467864.9

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94Table D-4. Continued. Electrolysis System Capital Investment O&M Wind Farm Rated Power (GW) Total Electrolysis Annual Interest Startup cost Working capital Total Electrolyser Annual O&M costs Water Treatment Annual O&M cost 0.5 81 8 2192 70.13 7 1 162 16 32184140.27 15 2 324 32 65367290.53 29 3 486 49 107551430.80 44 4 648 65 1310 735581.07 59 5 809 81 1612 919721.34 73 6 971 97 1914 1102861.60 88 7 1133 113 2317 12861011.87 103 8 1295 130 2619 14701152.14 117 9 1457 146 2922 16531302.41 132 10 1619 162 3224 18371442.67 147 11 1781 178 36 26 2021 158 2.94 161 12 1943 194 3929 22051733.21 176 13 2105 210 4231 23881873.47 191 14 2267 227 4534 25722013.74 205 15 2428 243 4936 27562164.01 220 16 2590 259 5238 29402304.28 235 17 2752 275 5541 31232454.54 249 18 2914 291 5843 33072594.81 264

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95Table D-4. Continued. Hydrogen Pipeline Capital Investment O&M Wind Farm Rated Power (GW) Pipeline cost Annual Interest Startup costs Working capital Total Annual O&M cost 0.5 1260 126 25 3141418 1 1260 126 25 6141736 2 1260 126 25 12142372 3 1260 126 25 181429108 4 1260 126 25 241435144 5 1260 126 25 301441180 6 1260 126 25 361447216 7 1260 126 25 421453252 8 1260 126 25 481459288 9 1260 126 25 541465324 10 1260 126 25 601471360 11 1260 126 25 66 1477 396 12 1260 126 25 721483432 13 1260 126 25 781489468 14 1260 126 25 841495504 15 1260 126 25 901501540 16 1260 126 25 961507576 17 1260 126 25 1021513612 18 1260 126 25 1081519648

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96Table D-5. Lowest hydrogen cost breakdow n for different plant capacities. Hydrogen cost breakdown Annual values ($/kg) Wind Farm Rated Power (GW) Wind Farm Depreciation Wind Farm Return on the investment Wind Farm O&M Electrolysis Depreciation Electrolysis Return on the investment Electrolysis O&M Pipeline Depreciation Pipeline Return on the investment Pipeline O&M Water treatment Cost of h2 ($/kg) Cost of H2 1 ($/GJ) 0.5 0.48 2.14 0.370.090.410.161.42 6.350.400.00311.8385.1 1 0.48 2.14 0.370.090.410.160.71 3.180.400.0037.9557.2 2 0.48 2.14 0.370.090.410.160.35 1.600.400.0036.0243.3 3 0.48 2.14 0.370.090.410.160.24 1.070.400.0035.3738.6 4 0.48 2.14 0.370.090.410.160.18 0.810.400.0035.0536.3 5 0.48 2.14 0.370.090.410.160.14 0.650.400.0034.8534.9 6 0.48 2.14 0.370.090.410.160.12 0.540.400.0034.7234.0 7 0.48 2.14 0.370.090.410.160.10 0.470.400.0034.6333.3 8 0.48 2.14 0.370.090.410.160.09 0.410.400.0034.5632.8 9 0.48 2.14 0.370.090.410.160.08 0.370.400.0034.5132.4 10 0.48 2.14 0.370.090.410.160.07 0.330.400.0034.4732.1 11 0.48 2.14 0.37 0.09 0.41 0.16 0.06 0.30 0.40 0.003 4.43 31.9 12 0.48 2.14 0.370.090.410.160.06 0.280.400.0034.4031.7 13 0.48 2.14 0.370.090.410.160.05 0.260.400.0034.3831.5 14 0.48 2.14 0.370.090.410.160.05 0.240.400.0034.3531.3 15 0.48 2.14 0.370.090.410.160.05 0.220.400.0034.3431.2 16 0.48 2.14 0.370.090.410.160.04 0.210.400.0034.3231.1 17 0.48 2.14 0.370.090.410.160.04 0.200.400.0034.3131.0 18 0.48 2.14 0.370.090.410.160.04 0.190.400.0034.2930.91 Considering hydrogens high heating value

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97Table D-6. Highest cost calculations for different plant capacities. Values in million $. Wind Farm Capital Investment O&M Electricity Cost Wind Farm Rated Power (GW) Wind Turbine cost Total Wind Farm Interest Startup costs Working capital Total Annual O&M cost Annual Land Rental Total O&M costs Return on the investment Annual Depreciation Revenue required per year Cost of electricity ($/MWh) 0.5 550 649 65113728161 17 1462819094.9 1 1100 1298 1302261455322 34 2915538094.9 2 2200 2596 2604411 2911643 67 58211075994.9 3 3300 3894 3896617 4366965 101 873165113994.9 4 4400 5192 5198822 58221286 134 1164220151894.9 5 5500 6490 64911028 72771608 168 1455275189894.9 6 6600 7788 77913234 87321929 201 1746330227894.9 7 7700 9086 90915439 1018822411 235 2038385265794.9 8 8800 10384 103817645 1164325612 268 2329440303794.9 9 9900 11682 116819850 1309828814 302 2620495341694.9 10 11000 12980 129822056 1455432015 335 2911550379694.9 11 12100 14278 1428 242 61 16009 352 17 369 3202 605 4176 94.9 12 13200 15576 155826467 1746538418 402 3493660455594.9 13 14300 16874 168728673 1892041620 436 3784715493594.9 14 15400 18172 181730878 2037544821 469 4075770531494.9 15 16500 19470 194733084 2183148023 503 4366825569494.9 16 17600 20768 207735289 2328651224 536 4657880607394.9 17 18700 22066 220737495 2474254426 570 4948935645394.9 18 19800 23364 2336396101 2619757627 603 5239990683394.9

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98Table D-6. Continued. Electrolysis System Capital Investment O&M Wind Farm Rated Power (GW) Total Electrolysis Annual Interest Startup cost Working capital Total Electrolyser Annual O&M costs Water Treatment Annual O&M cost 0.5 135 13 31152 70.13 7 1 270 27 52305140.27 15 2 540 54 115609290.53 29 3 809 81 167914430.80 44 4 1079 108 2210 1218581.07 59 5 1349 135 2712 1523721.34 73 6 1619 162 3214 1828861.60 88 7 1889 189 3817 21321011.87 103 8 2159 216 4319 24371152.14 117 9 2428 243 4922 27411302.41 132 10 2698 270 5424 30461442.67 147 11 2968 297 59 26 3351 158 2.94 161 12 3238 324 6529 36551733.21 176 13 3508 351 7031 39601873.47 191 14 3778 378 7634 42642013.74 205 15 4047 405 8136 45692164.01 220 16 4317 432 8638 48742304.28 235 17 4587 459 9241 51782454.54 249 18 4857 486 9743 54832594.81 264

PAGE 99

99Table D-6. Continued. Hydrogen Pipeline Capital Investment O&M Wind Farm Rated Power (GW) Pipeline cost Annual Interest Startup costs Working capital Total Annual O&M cost 0.5 2100 210 42 7235945 1 2100 210 42 15236790 2 2100 210 42 302382180 3 2100 210 42 452397270 4 2100 210 42 602412360 5 2100 210 42 752427450 6 2100 210 42 902442540 7 2100 210 42 1052457630 8 2100 210 42 1202472720 9 2100 210 42 1352487809 10 2100 210 42 1502502899 11 2100 210 42 165 2517 989 12 2100 210 42 18025321079 13 2100 210 42 19525471169 14 2100 210 42 21025621259 15 2100 210 42 22525771349 16 2100 210 42 24025921439 17 2100 210 42 25526071529 18 2100 210 42 27026221619

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100Table D-7. Highest hydrogen cost brea kdown for different plant capacities. Hydrogen cost breakdown Annual values ($/kg) Wind Farm Rated Power (GW) Wind Farm Depreciation Wind Farm Return on the investment Wind Farm O&M Electrolysis Depreciation Electrolysis Return on the investment Electrolysis O&M Pipeline Depreciation Pipeline Return on the investment Pipeline O&M Water treatment Cost of hydrogen ($/kg) Cost of H2 1 ($/GJ) 0.5 0.73 3.27 0.38 0.15 0.680.162.3610.60 1.010.00319.34139.2 1 0.73 3.27 0.38 0.15 0.680.161.185.32 1.010.00312.8892.7 2 0.73 3.27 0.38 0.15 0.680.160.592.68 1.010.0039.6569.4 3 0.73 3.27 0.38 0.15 0.680.160.391.79 1.010.0038.5761.7 4 0.73 3.27 0.38 0.15 0.680.160.291.35 1.010.0038.0357.8 5 0.73 3.27 0.38 0.15 0.680.160.241.09 1.010.0037.7155.5 6 0.73 3.27 0.38 0.15 0.680.160.200.91 1.010.0037.5053.9 7 0.73 3.27 0.38 0.15 0.680.160.170.79 1.010.0037.3452.8 8 0.73 3.27 0.38 0.15 0.680.160.150.69 1.010.0037.2352.0 9 0.73 3.27 0.38 0.15 0.680.160.130.62 1.010.0037.1451.3 10 0.73 3.27 0.38 0.15 0.680.160.120.56 1.010.0037.0650.8 11 0.73 3.27 0.38 0.15 0.68 0.16 0.11 0.51 1.01 0.003 7.01 50.4 12 0.73 3.27 0.38 0.15 0.680.160.100.47 1.010.0036.9650.0 13 0.73 3.27 0.38 0.15 0.680.160.090.44 1.010.0036.9249.8 14 0.73 3.27 0.38 0.15 0.680.160.080.41 1.010.0036.8849.5 15 0.73 3.27 0.38 0.15 0.680.160.080.39 1.010.0036.8549.3 16 0.73 3.27 0.38 0.15 0.680.160.070.36 1.010.0036.8249.1 17 0.73 3.27 0.38 0.15 0.680.160.070.34 1.010.0036.8048.9 18 0.73 3.27 0.38 0.15 0.680.160.070.33 1.010.0036.7848.8 1 Considering hydrogens high heating value

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101Table D-8. Hydrogen cost breakdo wn without transportation. Hydrogen cost breakdown without transport Annual values ($/kg) Cost assumption Wind Farm Depreciation Wind Farm Return on the investment Wind Farm O&M Electrolysis Depreciation Electrolysis Return on the investment Electrolysis O&M Water treatment Cost of hydrogen without transport ($/kg) Cost of H2 without transport ($/GJ)1 Lowest 0.48 2.140.370.090.410.16 0.0033.6626.3 Highest 0.73 3.270.380.150.680.16 0.0035.3738.7 1 Considering hydrogens high heating value

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102Table D-9. Comparison of different estimati ons for the cost of hydrogen produced by el ectrolysis using wind generated electricity. The costs were corrected to 2007 dollars for comparison. Reference Year Capacity (Nm3/day) Electricity cost ($/kWh) Published value Hydrogen cost ($/GJ)1 Published value Inflation from model year to 2007 4 Electricity cost ($/kWh) Inflation corrected Hydrogen cost ($/GJ)1 Inflation corrected Model Delivered 27.4 106 0.065 0.095 31.9 50.4 0.065 0.095 31.9 50.4 Model No transportation 0.065 0.095 26.3 38.7 0.065 0.095 26.3 38.7 [28] 1989 2.68 106 0.049 19.23 2 1.67 0.082 32.1 2000 0.25 106 20.2 1.24 25 [38] 2010 0.28 106 11 1.24 13.6 [9] 2003 2.68 106 0.04 20.75 1.13 0.0452 23.4 [15] 2005 0.011 106 0.0483 29.23 3 1.06 0.0512 31 1 Considering hydrogens high heating value. 2 Credit for by-product oxygen considered. 3 Electricity price does not consider source. 4 Source Inflation Calculator from the Bureau of Labor Statistics

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103 LIST OF REFERENCES [1] A. L. Hedstrm M. Saxe, A. Folkesson, C. Wallmark, K. Haraldss on, M. Bryngelsson, P. Alvfors, Key factors in pla nning a sustainable energy future including hydrogen and fuel cells, Bulletin of Science Technology Society 2006; 26: 264 [2] S.A. Sherif, F. Barbir, T.N. Verizoglu, Wind energy and the hydrogen economy review of the technology, Solar Energy, 2005;78:647-660 [3] B. Srensen, Renewable Energy, Its physics, engineering, environmental impacts, economics & planning, Third Edition, Elsevier Academic Press, Amsterdam; Boston, 2004. [4] W. A. Amos, Costs of storing and tran sporting hydrogen, National Renewable Energy Laboratory, Golden, Colorado, November 1998 [5] P. Jones, B. Westman, From generation to grid, Refocus, 2007;8:38-42 [6] IARC. Static and extremely low frequency el ectric and magnetic fi elds. IARC Monographs on the Evaluation of Carcinogenic Risks to Humans. International Agency for Research on Cancer; Lyon, pp. 80, 2001 [7] F. Barbir. PEM electrolysis for production of hydrogen from renewable energy sources. Journal of Solar Energy, 2005;78:661-669. [8] J. McMurry, R. Fay, Chemistry, Upper Saddle River, NJ : Prentice Hall, 2001 [9] Mirabal, S. T., An economic analysis of hydrogen production technologies using renewable energy resources, Masters th esis, University of Florida, 2003. [10] S.A. Grigoriev, V.I. Porembsky, V.N. Fateev. Pure hydrogen production by PEM electrolysis for hydrogen energy. International Journal of Hydrogen Energy, 2006;31:171 175 [11] DOE. U.S. Department of Energy, Energy E fficiency and Renewable Energy Hydrogen, Fuel Cells & Infrastructu re Technologies Program, http://www1.eere.energy.gov/hydrogenandfuelcells/product ion/electro_processes.htm l, Last accessed July 2007 [12] A. Roy, S. Watson, D. Infield, Comparison of electrical energy efficiency of atmospheric and high-pressure electrolysers, Interna tional Journal of Hydrogen Energy, 2006;31:19641979 [13] K. Onda, T. Kyakuno, L. Hattori, K. Ito, Pred iction of production power for high-pressure hydrogen by high-pressure water electrolysis, El sevier, Journal of Power Sources, 2004;32: 64-70

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104 [14] C.A. Schug, Operational characteristics of high-pressure, high effi ciency water-hydrogenelectrolysis, International Journa l of Hydrogen Energy, 1998;23(12):1113-1120 [15] J. Ivy, Summary of electrolytic hydroge n production, Milestone Completion Report, NREL/MP-560-36734, National Renewable En ergy Laboratory; Golden, Colorado, September 2004 [16] A. Contreras, F. Posso, T. N. Veziroglu, Modeling and simulation of the production of hydrogen using hydroelectricity in Venezuela, International Journa l of Hydrogen Energy 2007;32:1219-1224 [17] P. L. Spath, M. K. Mann, Life cycle assessment of renewable hydrogen production via wind/electrolysis, Milestone Completion Report, National Re newable Energy Laboratory; Golden, Colorado, February 2004 [18] K. Betts, Desalination, desalination everyw here, Environmental Science & Technology, 2004;38(13), 246-247 [19] S. Dolan, Life cycle assessment and emergy s ynthesis of a theoretical offshore wind farm for Jacksonville, Florida, Thes is, University of Florida, 2007 [20] Keith Hays, Windpower markets surge, Rene wable energy focus, September/October 2007, pp. 42-45. [21] J. F. Manwell, J. G. McGowan, A. L. Roge rs, wind energy explained, theory design and application, John Wiley & Sons Ltd, 2002 [22] INDEC. Instituto Nacional de Estadstica y Censos de la Repblica Argentina. http://www.indec.mecon.ar/, Last accessed January 2007. [23] Balance Energtico Nacional, Serie 1960-2005, Avance ao 2006 (Provisorio). Secretaria de Energa. Repblica A rgentina. June 2007 [24] T. Veziroglu, Hydrogen Energy System and Ar gentina, Academia Nacional de Ciencias, Crdoba, Rep. Argentina, Miscelnea N, 2002 [25] A. B. Badiru, Managing Industrial Development Projects A Project Management Approach, Springer Verlag, New York, 1993 [26] H. De Battista, R. J. Mantz, F. Garelli, Power conditioning for a wind-hydrogen energy system, Journal of Power Sources, 2006; 155:478-486 [27] I. Segura, A. Prez-Navarro, C. Snchez, F. Ibez, J. Pay, E. Bernal, Technical requirements for economical viability of electri city generation in stabilized wind parks, International Journal of Hydrogen Energy, 2007; 32:3811-3819. [28] M. Steinberg, H. Cheng, Modern and Prospective Technologies for Hydrogen Production from Fossil Fuels, International Jour nal of Hydrogen Energy,1989; 4(11):797-820.

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105 [29] B. Kroposki, J. Levene, and K. Harrison, P.K. Sen, F. Novachek, Electrolysis: Information and Opportunities for Electric Power U tilities. Technical Report NREL/TP-581-40605, National Renewable Energy Laborator y, Golden, Colorado, September 2006. [30] J. Ivy Levene, M. Mann, R. Margolis, A. Milbrandt, An analysis of hydrogen production from renewable electricity sour ces, Solar Energy, 2007; 81:773-780 [31] H. Karasawa, Cost Evaluation for Centraly zed Hydrogen Prodcution, Progress in Nuclear Energy, 2005; 47(1-4):512-518. [32] T. Burton, D. Sharpe, N. Jenkins, E. Bossanyi, Wind Energy Handbook, John Wiley & Sons, New York, 2001 [33] REpower 5M Product Brochure. http://www.repower.de/fileadmin/download/produkte/RE_PP_5M_uk.pdf Last accessed March 2008 [34] World Energy Assessment: Overview 2004 Up date, United Nations Developm ent Programme, New York, 2004 [35] R. Wiser, M. Bolinger, Lawrence Berkeley National Laboratory, Annual Report on U.S. Wind Power Installation, Cost and Performance Trends: 2006, U.S. Department of Energy, Washington, DC., May 2007 [36] P. Kruger, Electric power requirement in the United States for la rge-scale production of hydrogen fuel, International Journa l of Hydrogen Energy, 2000; 25:1023-1033 [37] P. Kruger, Electric power requirement in California for large-scale production of hydrogen fuel, International Journal of Hydrogen Energy, 2000;25:395-405 [38] C.E.G. Padr, V. Putsche, Survey of the Economics of Hydrogen Technologies, National Renewable Energy Laboratory, Golden, Colorado, September 1999 [39] F. Mueller-Langer, E. Tzimas, M. Kaltschm itt, S. Peteves, Techno-economic assessment of hydrogen production processes for the hydr ogen economy for the short and medium term, Elsevier, International Jour nal of Hydrogen Energy, 2007;32:3797-3810 [40] Gas Natural BAN S.A., Tarifas Fina les a Usuarios (Sin Impuestos), http://www.gasnaturalban.c om .ar/CIWeb/Jsp/tarifa.jsp Last accessed March 2008 [41] Norsk Hydro Hydrogen Technologies. http://www.hydro.com/electrolysers/en/produc ts/product_dev elopment/index.html, Last accessed December 2007 [42] Av lence LLC, http://www.avalence.com/ Last accessed Decem ber 2007

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107 BIOGRAPHICAL SKETCH Federico Giudici was born in Mar del Plata, Argentina, in 1978. He lived there until th e end of the year 2000 when he finished his studie s in mechanical engineering at the Universidad Nacional de Mar del Plata as valedictorian of his class. In the follo wing years he lived and worked in different cities in Argentina, star ting with a short internship in an Exxon Mobil's refinery, to continue in a T oyota's factory. In the year 2005 he worked with Doctors Without Borders, a humanitarian NGO, for some months in Guatemala. At his return, he was granted a Fulbright scholarship to pursue a Master of Science in mechanical engineering at the University of Florida. At Florida he worked under Dr. H. A. Ingley in the Alte rnative Energy Laboratory focusing on renewable energies.