The Potential Role of Electrolytic Hydrogen in Canada

Home , Heavy water

AECL-7676

ATO MIC E H E R G Y fl&B L'ENERGIE ATOMIGUE OF CANADA LIMITED \^^W DU CANADA LIMITEE

THE POTENTIAL ROLE OF ELECTROLYTIC HYDROGEN IN CANADA

Rdle potentiel de I'hydrogene electrolytique au Canada

M. HAMMERLI

Chalk River Nuclear Laboratories Laboratoires nucWairas de Chalk River

Chalk River, Ontario

March 1982 mars ATOMIC ENERGY OF CANADA LIMITED

THE POTENTIAL ROLE OF ELECTROLYTIC HYDROGEN IN CANADA by Martin Hammerli

Chalk River Nuclear Laboratories Chalk River, Ontario KOJ 1JO 1982 March

AECL-7'176 L'ENERGIE ATOMIQUE DU CANADA, LIMITEE

Rôle potentiel de l'hydrogène ëlectrolytique au Canada

par

Martin Hanmerli

Rësumë

Le rôle potentiel de l'hydrogiine électrolytique au Canada est évalué pour la période allant de 1980 â 2025, seulement pour application à grande échelle. Les utilisations actuelles de l'hydrogène et plus particulièrement de l'hydrogène électrolytique sont commentée? brièvement et les procédés de production d'hydrogène font l'objet d'une description sommaire. Seul l'hydrogène provenant du gaz naturel, du charbon ou de^ 1'electrolyse de l'eau doit être considéré pour les applications à grande échelle au Canada au cours de la période susmentionnée.

Des estimations de coût de l'hydrogène électrolytique sont obtenues grâce à une équation paramétrique. Les valeurs pour les technologies canadiennes d'electrolyse de l'eau qui sont unipolaires et uniques en leur genre sont comparées avec celles de 1'electrolyse bi- polaire. Les deux sous-produits de la production de l'hydrogène par electrolyse, à savoir l'eau lourde et l'oxygène sont évalués. Bien que le crédit du sous-produit qu'est l'oxygène est spécifique au site, le crédit du sous-produit qu'est l'eau lourde ne l'est pas.

Des projections de coût pour l'hydrogène provenant du gaz naturel et du charbon et pour l'hydrogène electrolytique sont basées sur des hypothèses simples mais réalistes. Toutes les données de coût sont fournies en dollars canadiens constants de 1980.

L'hydrogène électrolytique basé sur des sources énergétiques primaires non fossiles est également considéré comme une autre option de combustible liquide pour le Canada ainsi que les alcools.

Le potentiel commercial de l'hydrogène en général est évalué en fonction d'une référence et d'un scénario d'utilisation accrue pour les applications traditionnelles et potentielles de l'hydrogène. A partir des estimations de coûts et des évaluations de marché, la demande potentielle peur l'hydrogène électrolytique est estimée pour la période considérée. Les résultats montrent que le potentiel commercial de l'hydrogène électrolytique sera très grand en 2025. Les implications de ce résultat pour les industries concernées font l'objet de discussions. Finalement, le besoin de recherche et développement dans les technologies énergétiques à base d'hydrogène est commenté.

Laboratoires nucléaires de Chalk River Chalk River, Ontario KOJ 1J0 Mars 1982

AECL-7676 ATOMIC ENERGY OF CANADA LIMITED

THE POTENTIAL ROLE OF ELECTROLYTIC HYDROGEN IN CANADA by Martin Hammer]i

ABSTRACT

The potential role of electrolytic hydrogen in Canada is assessed for the period 1980 to 2025 for large-scale uses only. Present uses of hydrogen, and specifically electrolytic hydrogen, are discussed briefly and hydrogen production processes are summarized. Only hydrogen derived from natural gas, coal, or electrolysis of water need be considered for large-scale applications in Canada during the period of interest.

Cost estimates of electrolytic hydrogen are obtained from a parametric equation. Values for Canada's unique unipolar water electrolyser technologies are compared with those for bipolar electrolysers. Both by-products of electrolytic hydrogen production, namely heavy water and oxygen, are evaluated. While the oxygen by-product credit is site-specific, the heavy water by- product credit is not.

Cost projections for hydrogen derived from natural gas and coal, and for electrolytic hydrogen are based on simple but realistic assumptions. All cost data are given in constant 1980 Canadian dollars.

Electrolytic hydrogen, based on non-fossil primary energy sources, is also considered as another "liquid fuel option" for Canada along with the alcohols.

The market potential for hydrogen in general is assessed based on a reference and a higher use scenario for both the traditional and potential uses of hydrogen. From cost estimates and market assessments, the potential demand for electrolytic hydrogen is estimated for the period in question. Results show that the market potential for electrolytic hydrogen is large by the year 2025. The implications of this result for the relevant industries are discussed. Finally, the need for research and development in hydrogen energy technologies is discussed.

Chalk River Nuclear Laboratories Chalk River, Ontario KOJ 1J0 1982 March

AECL-7676 "In the mid- to late-1990's there will be a major worldwide oil shortage as the Middle East production peaks out. The resulting escalation in oil prices will severely stress the capability of the United States to produce coal and shale. Now my crystal ball becomes aloudy> but I see an alarming possibility of our not being able to keep up with demand. This time there is no escape route such as "importation". THE ENERGY INDUSTRY AND ITS RESEARCH TEAMS WILL BE SEVERELY CRITICIZED FOR NOT HAVING HAD THE FORESIGHT TO PLAN AHEADi AND THE "HYDROGEN COMMUNITY" WILL BE ACCUSED OF NOT BEING READY WHEN IT WAS NEEDED." *

w Derek P. Gregory Chicago 1978 July 28

* Emphasis by author of this report. TABLE OF CONTENTS

Page

1. INTRODUCTION 1

2. PRESENT USES OF HYDROGEN 2

2.1 Major Uses of Hydrogen 2 2.2 Uses of Electrolytic Hydrogen and Its 2 By-Products 2.3 Summary and Conclusions 3

3. HYDROGEN PRODUCTION PROCESSES 4

3.1 Introduction 4 3.2 Comments on Large-Scale Electrolytic 5 Hydrogen Production 3.3 Summary and Conclusions 6

4. COST OF ELECTROLYTIC HYDROGEN 6

4.1 introduction 6 4.2 Parametric Cost Equation 7 4.3 The Canadian Unipolar Electrolyser 8 Technologies 4.4 The ir>81 and 1983 Unipolar Technologies 8 4.5 Comparison with Existing Technologies 9 4.6 Sensitivity Analysis 11 4.7 Summary and Conclusions 13

5. BY-PRODUCTS OF ELECTROLYTIC HYDROGEN 13

5.1 Heavy Water By-Product Credit 13

5.1.1 Introduction 13 5.1.2 Basic Description of the CECE-HWP 14 5.1.3 Heavy Water Credit 15 5.1.4 How Much Heavy Water from 17 Hydrogen Production?

5.2 The Oxygen By-Product Credit 18

5.2.1 Introduction 18 5.2.2 Oxygen Credit 18

5.3 Combined Credits 19 5.4 Summary and Conclusions 19 TABLE OF CONTENTS CONT'D

Page 6. COST PROJECTIONS FOR HYDROGEN 20 6.1 Introduction 20 6.2 Hydrogen from Natural Gas 20 6.3 Hydrogen from Coal 21 6.4 Electrolytic Hydrogen 22 6.5 Summary and Conclusions 24 7. HYDROGEN: ANOTHER LIQUID FUEL OPTION? 25 7.1 Introduction 25 7.2 Oil Equivalent Electrolytic Hydrogen Costs 25 7.3 Other Liquid Fuel Options 25 7.4 How Much Electrolytic Hydrogen as a Fuel Option? 26 7.5 Summary and Conclusions 28 8. MARKET POTENTIAL FOR CHEMICAL HYDROGEN 28 8.1 Introduction 28 8.2 Chemical Hydrogen Demand Projections 28 8.2.1 Ammonia Production 29 8.2.2 011 Refining 29 8.2.3 Synthetic Fuel 30 8.2.4 Methanol Production 31 8.3 Summary and Conclusions 31 9. THE POTENTIAL MARKET FOR ELECTROLYTIC HYDROGEN 32 9.1 Introduction 32 9.2 Electrolytic Hydrogen Market Projections: 32 Chemical 9.3 Electrolytic Hydrogen as a Direct Fuel 33 9.4 Summary and Conclusions 34 10. PROSPECTS FOR RESEARCH AND DEVELOPMENT IN HYDROGEN ENERGY TECHNOLOGIES 35 10.1 Introduction 35 10.2 Hydrogen Production 36 10.3 Energy Storage and Conversion with Hydrogen 37 10.3.1 Introduction 37 10.3.2 Load-Levelling Options 37 TABLE OF CONTENTS COMT'D

Page

10.3.3 Energy Conversion Options: 37 Fuel Cells 10.3.4 Energy Conversion Options: 40 The Direct-Fired Hydrogen-Oxygen Superheater 10.3.5 DC Power Supply: The Acyclic 40 Generator

10.4 Hydrogen Uses 41

10.4.1 Introduction 41 10.4.2 Traditional Uses 41 10.4.3 New Uses 43 10.5 Hydrogen Storage and Transmission 46 10.5.1 Introduction 46 10.5.2 Metal Hydrides 46 10.5.3 Liquid Hydrides 48 10.5.4 Underground Storage 49 10.5.5 Other Hydrogen Storage Methods 50 10.5.6 Transmission 51 10.6 Materials Research 52 10.7 Other R & D Needs 53 10.8 Summary and Conclusions 54 11. CONCLUSIONS 56

11.1 Prospects for Electrolytic Hydrogen 56 11.2 When Will Electrolytic Hydrogen Be Competitive? 56 11.3 Implications for the Water Electrolyser Industry 57 11.4 Implications for the Electric Utilities 57 11.5 Opportunities for Other Industries 57 11.6 Heavy Water and Oxygen By-Products 57 11.7 Hydrogen as a Fuel 58 11.8 Overall Conclusions 58

12. ACKNOWLEDGEMENTS 59

13. REFERENCES ' 59

14. LIST OF TABLES 67

15. LIST OF FIGURES 97

16. APPENDIX A 113 - 1 -

THE POTENTIAL ROLE OF ELECTROLYTIC HYDROGEN IN CANADA 1. INTRODUCTION The total hydrogen demand in 1978 in Canada was estimated (1) at 11.8 x 109 m3 with an energy equivalent of 151 P.]*. This amount of hv- drogen is equivalent to the energy production fror. . 5000 MW electricity generating complex operating at 80% of capacity for one year. An ex^rv-le of such a complex is the combined Bruce A and B CANDU** nuclear power station, operated by Ontario Hydro. For comparison, the amount of energy used annually in Canada for road transport (2) is about 1400 PJ, which is equivalent to the energy output of 54,000 MW of electricity generating capacity or nine Bruce nuclear stations operating at 80% of capacity. The total installed electricity generating capacity (3) in Canada in 1979 was 77,072 MW. Thus, from an energy point of view, hydrogen is minor but significant in Canada today.

Electrolytic hydrogen is less important because of its present high cost relative to hydrogen derived from fossil resources. It is estimated (4) that only about 0.12% of the 1978 hydrogen supply in Canada was derived from electrolysis of water. This amount of electrolytic hydrogen, namely 13.7 x 106 m3, requires an 8.1 MW electrolysis plant. However, hydrogen in general and electrolytic hydrogen in particular may play a more significant role in Canada in the future (5, 6, 7, 8). The prospects for electrolytic hydrogen rest on the premise that electricity prices will not increase as rapidly as those of fossil fuels. Thir, has certainly been the case for electricity derived from nuclear and hydro power since the world oil crisis in 1973. In fact, Melvin (8) argues con- vincingly that in real dollars the cost of electricity from an expanding system of nuclear and hydroelectric plants could even remain constant. Canada faces an oil shortage but not necessarily an energy crisis. Substituting electricity for imported oil (9) in such a stationary application as space heating is an important first step towards oil self-sufficiency for Canada. Substituting electrolytic hydrogen, based on non-fossil primary energy sources, is a logical extension of electricity substitution for oil in areas where electricity cannot be applied readily. Other options besides electricity and electrolytic hydrogen for oil substitution are discussed by Dixon (10) in his review of energy in Canada. This report examines the potential role of electrolytic hydrogen in Canada, both as a chemical and as an energy medium, in relation to cost projections of hydrogen from other sources. These cost projections, as well as hydrogen demand projections, are based on simple assumptions which are

* 1 PJ = 1 petajoule = lO*5 joule = (approx.) 1012 BTU ** CANDU = CANada Deuterium Uranium - 2 -

clearly stated. The period considered is 1980 to 2025, and the objective is to see where electrolytic hydrogen may become important on a large-scale in Canada. The results of this analysis should aid energy planners who must deal with these and other options. Research and development opportunities in Canada in the hydrogen field are discussed. Technologies particularly suitable for Canadian adaptation and/or development are emphasized.

2. PRESENT USES OF HYDROGEN 2.1 Major Uses of Hydrogen The 1978 hydrogen supply in Canada of 11.8 x 10^ m3 was divided (I) as shown in Fig. 2.1. Ammonia is the largest consumer at 43%. "Other" uses include direct reduction of iron ore to produce sponge iron pellets as well as direct reduction of tungsten and some nickel ores. These metallurgical applications consume the bulk of the hydrogen in this category; the very small fraction of electrolytic hydrogen is also included. Non-energy uses of hydrogen accounted for 55% of the total. Oil refineries consumed an estimated (1) 33%. The production of synthetic crude oil (syncrude) from Alberta's oil-sand bitumen used 12% to bring the total consumption of hydrogen in the "Indirect Energy" sector to 45%. Such potential uses of hydrogen as in upgrading of heavy oil deposits (II) and coal gasification or liquefaction will increase the demand for hydrogen in the "Indirect Energy" sector. Also, conventional crude oils are getting heavier and therefore require more hydrogen addition. This sector is therefore expected to grow in the future. 2.2 Uses of Electrolytic Hydrogen and Its By-Products Because of its relatively high cost, electrolytic hydrogen is now used only in specialty applications where its high purity is of importance, or in medium-sized markets that are too large to use bottled hydrogen economically but too small for on-site production based on fossil resources. Thus, with few notable exceptions, electrolytic hydrogen plants in the world today have capacities of about 5 x 10^ m^/a to about 9 x 10^ m-fya, corresponding to direct current (DC) input power requirements* ranging from 2.5 kW to 5 MW. By contrast, an annonia plant producing 1000 metric tons per day requires 84,000 m3/h of hydrogen (7.4 x 108 m^a) or a 400 MW electrolysis plant with a 100% capacity factor. Such a capacity factor is possible as discussed later.

Based on 2.0 V per unit cell or an overall energy efficiency for electrolysis of 74%. - 3 -

Present uses of electrolytic hydrogen with plants in the size range given above a>-e listed in Table 2.2.1, Section A. These uses reflect the interesting properties of hydrogen. A few electrolytic hydrogen plants in the 100 MW range do exist, for example, at Ryukan in Norway and at the Aswan dam in Egypt. Both plants produce hydrogen for ammonia synthesis and both use hydroelectricity. Such was also the case in Canada from the 1940's until 1972 (12) at Trail, British Columbia, where the Consolidated Mining and Smelting Company operated an electrolysis plant which, at its peak, produced hydrogen at 14,500 m3/h (13). The primary product of this 90 MW plant (12) was, however, the pure oxygen which was used in metallurgical processes: the by- product hydrogen was used in an ammonia fertilizer plant. Between 1943 and 1956, heavy water (D2O) was also extracted as a second by-product (13), making this Canada's first industrial heavy water plant. Heavy water is required as moderator and coolant in the CANDU nuclear fission power reactors. Both the oxygen and heavy water by-product credits are evaluate-1 later. Incidentally, heavy water is sti'1 being extracted at the Ryukan plant in Norway as a valuable by-product (13).

Some heavy water is also used for isotopic labelling of chemical com- pounds but this market is small compared with the nuclear energy application. In principle, electrolytic oxygen may be used in all markets now served by air liquefaction plants. Present economics appear to favour the liquefaction process, but it is conceivable that history may repeat itself in circumstances where needs for both oxygen and hydrogen exist in cloce proxim- ity. A process proposed by Stuart (4) where all three products from water electrolysis are recovered is shown in Fig. 2.2. The gasifier is operated under reducing conditions to yield mainly carbon monoxide and hydrogen. Almost any solid fuel, ranging from coal to combustible municipal waste and other biomass could be used (4). Oxygen from the electrolyser and steam from an auxiliary boiler are fed to the gasifier, while the hydrogen is added to the carbon monoxide and hydrogen produced in the gasifier. The resultant gas mixture now has the correct stoichiometry for methanol production, but other uses are also possible. Whether such a scheme is or could be economic is beyond the present scope, but it serves to illustrate interesting possibil- ities for synergistic effects with the products of water electrolysis. 2.3 Summary and Conclusions Hydrogen is not^ directly used as a fuel today, although 45% of the 1978 supply in Canada was consumed in the production of fuel from crude oil and tar sands. Ammonia synthesis is the largest single user. Electrolytic hydrogen serves mainly small markets and speciality applications such as hydrogenation of foods. Plants are typically between 2.5 kW and 5 MW in size. Where cheap hydroelectricity is secu ed and fossil - 4 -

resources have to be imported, electrolytic hydrogen plants in the 100 MW range exist today, but not in Canada. Electrolytic hydrogen has two by-products, namely oxygen and heavy v.ater. The latter is used on a large scale as moderator and coolant in the CANDU nuclear reactor. Synergistic effects are possible with all three products of water electrolysis. For example, synthesis gas could be produced (Fig. 2.2) by coupling an electrolysis plant with a solid fuel gasifier.

3. HYDROGEN PRODUCTION PROCESSES 3.1 Introduction Established and potential processes for hydrogen production are reviewed elsewhere (14). These processes are summarized briefly in Table 3.1.1. Electrolysis of water is today the only industrial hydrogen production process which is not based on fossil resources. This statement is true only if the primary energy used to generate the required electricity is non- fossil such as hydraulic, geothermal, nuclear or solar. Thermochemical (14) and other processes not based on fossil resources are i:"! the early stages of development or are not commercially viable; although scientific and technological breakthroughs are possible, it is unlikely that any of these processes will be commercially viable for large- scale hydrogen production, at least until the turn of the century. Since only large-scale hydrogen production is being considered here, only three industrial processes are important, namely, (a) Steam reforming of natural gas; (b) Coal gasification; (c) Electrolysis of water.

Steam reforming of natural gas and catalytic reforming of hydrocarbons in oil refining are by far the most important processes for hydrogen production in Canada today. Partial oxidation of naphtha (14) and other hydrocarbon fractions from oil refining is not considered here as a process for large-scale hydrogen production because the price of crude oil, and therefore of its products, is expected to increase faster than the prices of other energy sources. In regions where natural gas is not readily available, coal gasification is the next choice, while electrolysis of water is currently not competitive for large-scale hydrogen production, as stated earlier. - 5 -

3.2 Comments on Large-Scale Electrolytic Hydrogen Production Both steam reforming of natural gas and coal gasification for producing nydrogen are typical chemical processes for which plants are designed to operate efficiently over a relatively narrow range around the rated throughput. Furthermore, changes in throughput usually involve large increments since individual process units are few in number to take advantage of the economies of scale. By contrast, an electrolysis plant can be operated over a range from about 10% to over 100% of capacity. Moreover, the electric current which governs the throughput can be varied continuously over this range. This flexibility is due not only to the modular construction of a large plant but also to the range of acceptable gas evolution rates per unit of electrode area. The rate of gas generation par unit of electrode area is related to the current density, expressed as kA/m^ or A/cm^, through the Faraday constant. In general, the higher the current density, the higher is the voltage of a single cell. Thus, the electrical energy cost per unit of gas produced increases as the airrent density increases, while the size of the electrolysis plant, and hence the capital charges, decreases. The optimum trade-off between operating cost and capital cost thus depends on the unit electrical energy cost and the cost of capital. For che same unit electricity cost and interest rate, different electrolyser technologies will have different optimized operating parameters depending on their relative capital costs. A corollary of this is that lower capital cost electrolyser technologies can and do compete with higher cost ones (15), even though the latter may operate at a hiqher energy efficiency (lower single cell voltage).

Because of the inherent flexibility of an electrolysis plant, it is possible to design cells for a specific rated current density and corresponding rated cell voltage, but with the option to operate the plant at higher current densities providing that auxiliary equipment is oversized to accept flows greater than the rated values. Therefore, it is possible to operate an electrolysis plant at an annual capacity factor of 100% of the rated value by compensating for shutdowns by operating for periods at over 100% of the rated value. This concept is inherent in the parametric cost equation for electrolytic hydrogen developed in Appendix A. Because an electrolysis plant can be operated over a wide and continuous range of capacity factors, it has potential for electricity load levelling either at the generation site or anywhere on the grid. Commercial water electrolysers contain an alkaline electrolyte which is usually a strong solution of potassium hydroxide. Research and development (14) in alkaline water electrolysis will result in Advanced Alkaline Water Electrolysis Technologies (see Section 4.4). Water electrolysis can also occur in acidic solutions, such as sul- furic acid, but the acid system is not practical relative to the alkaline one (14). However, when the acid is in the form of a solid ion-exchange - 6 -

membrane, such a system may be practical for large-scale hydrogen production and this concept is being developed by the General Electric Company (14).

3.3 Summary and Conclusions

Only three industrial processes for large-scale hydrogen production are important, at least until the turn of the century. These are reforming of natural gas, coal gasification and electrolysis of water. Therefore, these are the only ones considered in this study.

At present, steam reforming of natural gas is the most economical process while electrolysis of water is not competitive in Canada for large-scale hydrogen production.

Electrolysis is the only process today which does not depend on fossil resources, provided the electricity for the process is non-fossil in origin.

An electrolysis plant can inherently be operated over a wide and continuous range of capacity factors. This feature is attractive for storing electricity as hydrogen during off-peak periods.

4. COST OF ELECTROLYTIC HYDROGEN

4.1 Introduction

Costs of electrolytic hydrogen are estimated from a parametric equation for the Canadian unipolar* electrolyser technologies under development (16). While there are basic differences (14) between the unipolar and bipolar electrolyser designs, the two compete in today's electrolytic hydrogen market and are likely to do so in the future large-scale (^100 Mw or greater) market. Regardless of basic type of electrolyser, each manufacturer is striving to adapt his technology from the nominal kW to the MW module in order to decrease the unit capital cost. Each manufacturer is also attempt- ing to increase the operating current density for the same reason. Simul- taneously, design operating voltages for a single cell are decreasing to increase the energy efficiency,^ , from the present 75% to 80-90%. Just how successful these development efforts (e.g., 17, 18) will be remains to be seen, but, since the present technologies are largely based on old cell designs, there is justification for optimism.

The calculated total elect-olytic hydrogen costs are compared with costs for existing technologies and a sensitivity analysis is included. Lastly, the heavy water and oxygen by-product credits are evaluated.

In the unipolar design individual cells in a tank are connected in paral- lel, whereas in the bipolar design or filter press electrolyser they are connected in series electrically. See Reference 12 for more details. - 7 -

4.2 Parametric Cost Equation A parametric equation for estimating the total cost of electrolytic hydrogen was developed by LeRoy and Stuart (15). The derivation of their equation is given in Appendix A. Two additional terms have been added to account for the capital and operating cost of compressing the hydrogen from atmospheric pressure to 3.45 MPa (500 psi), based on data of Darrow et ai. (19). The complete expression was derived in terms of dollars per gigajoule of hydrogen based on the higher heating value* of hydrogen of 285.8 kJ/mol at 25°C, which is equivalent to a theoretical cell voltage of 1.^81 V. LeRoy and Stuart based their expression on 1.49 V or 70°C and therefore the constants in their expression are slightly different from those used here.

The total cost of electrolytic hydrogen is C($/GJ) given by the expression:

[1] C = Ci + C2 + C3 + C4 + C5 + C6 where Ci = the capital cost component for cells and accessories

C-2 = installation-related costs C3 = rectifier costs

C4 = electricity cost for electrolysis C5 = capital cost component for gas compression

Cs = electricity cost for gas compression

By adjusting the various factors (see Appendix A) of equation [1] intelligently, it should be possible to arrive at a good estimate of the total cost of electrolytic hydrogen for each of the various electrolyser approaches (14), be it atmospheric pressure, bipolar, unipolar, or the SPE technology**. Such estimates were made by LeRoy and Stuart (15) who showed that the total cost of electrolytic hydrogen for the various advanced technologies were very similar at an assumed electricity cost of 1.5

Teledyne Energy Systems has recently derived a sophisticated computer program for estimating the total electrolytic hydrogen cost and results (20) suggest that the total cost of hydrogen will be similar for their projected

* This includes the latent heat of condensation of water. ** SPE = Solid Polymer Electrolyte technology being developed by the General Electric Company (see reference 17). - 8 -

advanced alkaline bipolar concept as for the General Electric SPE bipolar technology. 4.3 The Canadian Unipolar Electrolyser Technologies In view of the competition which already exists among electrolyser manufacturers and which should increase as tf-.e market increases, the author has chosen to concentrate on the Canadian electrolyser technology in the cost estimates. This choice is further justified because projected total costs of electrolytic hydrogen appear to be the same, at least to a first approximation, regardless of the particular developing electrolyser technology chosen (16, 20). The parameters for the past (1978) and future Canadian unipolar electrolyser technologies are summarized in Table 4.3.1. The data are taken from references 15 and lfi and corrected to 1980$ using a factor of 0.94 (21) for converting 1977 US$ to 1977 Cdn.$, a consumer price index ratio of 1.17 to convert 1977$ to 1979$, and assuming a 9% inflation factor for 1980. Thus, the dollars are mid to late 1980 dollars. As Table 4.3.1 shows, the possible operating current density more than doubles and the capital cost decreases by 12% as the technology improves from the past industrial unipolar Stuart cells to the 1983 technology. Simultaneously, the plausible operating voltage also decreases by about 12% and, since electricity costs account for 70-80% of the total cost of hydrogen, this represents a reduction of 8-10% in the total cost of hydrogen.

4.4 The 1981 and 1983 Unipolar Technologies Because there are no technical or economic reasons at this time to question the parameters given for the unipolar "1981 technology" (see Table 4.3.1), the author has chosen these coupled with the 1980 commercial rate of 2$/kWh for electricity for customers in the 100 MW range, as the Reference Case. In the province of Ontario, this rate would have applied to a direct customer assuming a capacity factor of 0.9 for the electrolysis plant operating on interruptible "B" power at 10 to 50 kV (22). Interruptible "B" power is quite suitable for a dedicated electrolysis plant (23). Similar 1980 electricity costs for the same type of direct customer would have applied also in the province of Quebec. Ontario has large hydroelectric and nuclear generating capacity. Quebec has large hydroelectric generating capacity.

To reflect expected improvements, the total hydrogen cost has also been calculated for the unipolar "1983 technology" on the assumption that this technology will be developed according to the parameters given in Table 4.3.1. Values chosen (see Table 4.4.1) for several, but not all, of the parameters of the cost equation in the Appendix are identicel with those of LeRoy and Stuart (15, 16). The capital recovery factor, K = 0.2, is based on the assumption of 16%/a return on capital, 2%/a for insurance and ad-valorem taxes and 2%/a for operation and maintenance costs. The value of 0.28 for the capital recovery factor, KQ, assumes (16) capital charges of 16%/a, - 9 -

operation and maintenance charges of lOX/a and ad-valorem taxes plus insurance of 2%/a. A leading Canadian manufacturer of transformer and rectifier equipment confirmed the 1980 price of $40/kW for the rectifier, complete with transformer and switch gear (24). This cost is based on a 5-100 MW electrolyser plant with characteristics suitable for either the 1981 or 1983 unipolar technologies, but not necessarily for bipolar designs. It should also be noted that this cost is considerably lower than the $65/kW (US, 1977) of reference 15, Wi11 respect to hydrogen compression costs, a convincinq case is made in reference 16 that $724/kW of compressor power is a realistic capital cost.

While the above assumptions and chosen values are open to discussion, they appear to be reasonable for a modern automated unipolar electrolyser plant. In any event, the major cost of electrolytic hydrogen is the electricity cost so that reasonable deviations from the above chosen values have relatively little effect on the total hydrogen cost, with the exception of the operating single cell voltage.

The results are given in Table 4.4.2 for the various components of an installed ( 100 MW) Unipolar Electrolyser Plant for the 1978, 1981 and 1983 unipolar technologies. The total hydrogen costs based on 2

4.5 Comparison with Existing Technologies The total cost of hydrogen based on the 1978 unipolar technology (15) for parameters given in Table 4.4.1 is $11.19/GJ. Of this, 76% covers the electrical energy at 24/kWh, 19.2% the total capital costs and 4.7% is required for compression.

Considering the assumptions made the value of $11.19/GJ compares quite well with $9.64/GJ for the 100 MW case which may be calculated from Johnson and Verma's (25) recent analysis for the same technology based on an 18% interest rate, a 20 year equipment life and 2

Teledyne Energy Systems of Maryland is a newcomer to the field and at present does not have a large commercial unit available. That is presumably why their total cost is about a factor of two higher and the capital 'cost component about a factor of 3 to 4 higher than those of the others. It is expected that when their technology matures and is scaled-up, they will also be competitive (20). As stated earlier, those manufacturers with a well-established water electrolyser business are fiercely competitive as the relative total hydrogen costs in Table 4.5.1 show. The difference in total costs is no more than 5%. Since only the Lurgi technology (excluding Teledyne at present) is based on a high pressure (3 MPa or 441 psi) electrolyser module, the calculated (this work) compression cost was subtracted in this instance to arrive at a total hydrogen cost that is on the same basis aa the atmospheric pressure technologies, assuming Johnson and Verma (25) omitted compression costs from the latter. The capital cost components for the Lurgi and Norsk Hydro bipolar technologies are 47% and 16% higher than those for the Electrolyser Corp. unipolar technology for a 50 MW plant. This comparison is not strictly fair to the Lurgi technology because their costs are based on a 3.5 MW plant. Nevertheless, the capital costs are in the expected order since a pressurized electrolyser, in the bipolar configuration, requires much closer tolerances and heavier construction than the unipolar tank-type atmospheric-pressure cell. As expected, those of the present technologies with the highest capital costs also have the lowest energy costs, i.e., the lowest operating single cell voltages. Otherwise they would not be able to compete. Two other European manufacturers of commercial water electrolysers, namely Brown Boveri of Switzerland and DeNora of Italy, were not included in reference 25. Both companies market atmospheric-pressure electrolysers of the bipolar configuration and both compete in the international market. Therefore, the total hydrogen costs for these present technologies are expected to be very similar to those for the Norsk Hydro technology (Table 4.5.1) and their inclusion would not alter the picture given above. Because the total hydrogen cost of $9.81/GJ for the Reference Case with 1981 unipolar technology is comparable to those for existing technologies, it may be concluded that the assumptions used for this case are conservative. This gives credibility for the sensitivity analysis which will be presented, in spite of the fact that estimates as high as $23/GJ for electrolytic hydrogen* costs have appeared (26) at 3

* Assumes 1980 Canadian dollars are equivalent to 0.85 US dollars. - 11 -

For the sake of completeness the latest cost projection (27) for GE's SPE advanced electrolyser technology is about 12 US$/106 BTU or 13.36/GJ at 3

Thus, the advanced alkaline water electrolysis technologies, be they unipolar or bipolar, are likely to compete successfully with GE's bipolar SPE technology, which is based on an acid membrane (see reference 12 for more details).

4.6 Sensitivity Analyses The previous section has presented the methodology and assumptions made in calculating the total hydrogen cost for the Canadian unipolar technologies. In this section a sensitivity analysis is presented for the unipolar 1981 and 1983 technologies. The base value chosen for each variable is indicated in brackets in Table 4.6.1. Note that the sensitivity analysis for the 1983 technology is based on an electricity cost of 3

Perhaps the parameter of greatest interest is the plant utilization or capacity factor, P, since several studies (15, 19, 25 and 28) have presented arguments for load-levelling within a utility by producing electrolytic hydrogen in the off-peak periods. The effect of P on the electrolytic hydrogen cost is shown in Fig. 4.1 for both the 1981 and 1983 technologies each at 2

reactor may be large enough to adequately cover hydrogen delivery and storage costs in the context of a well-integrated industrial energy park. The latter concept is receiving serious consideration in the Province of Ontario with respect to industrial steam delivery adjacent to the Bruce Nuclear Power Development (29).

Doubling the capital cost of the cells increases the total hydrogen cost 15% and 12%, respectively, for the 1981 and 1983 technologies (see Table 4.6.1). Likewise, increasing the capital recovery factor for the electrolyser equipment by 25% to 0.25 increases the hydrogen cost by b% and 4%, respectively.

The effect of electricity cost on the total hydrogen cost is shown in Fig. 4.2 for the range 0.3 to 3

Decreasing the operating cell voltage from 1.9 V to 1.8 V decreases the electrical energy cost by 5.3% as it should since the electrolysis energy required is directly proportional to the operating cell voltage, V-j.

Since total compression costs represent only about 5% of the total hydrogen cost in both cases, doubling compression costs will only increase the total hydrogen cost by a^out 5%. Also, the capital cost contribution for compression (C5 of equation [1]) represents 55% and 45% of the total compression costs of $0.529/GJ and $0.648/GJ corresponding to electricity costs of 2 and 34/kWh, respectively. Therefore, atmospheric-pressure electrolysers are likely to continue to compete with high pressure electrolysers for the forseeable future. Decreasing the fraction of cell-plus-accessories costs that are independent of the operating current density, fj, from 0.9 to 0.5 increases the total hydrogen cost by only 1.9% and 2.4%, respectively, for the 1981 and 1983 technologies. Similarly, increasing the fraction of cell-plus-accessories costs to cover installation-related costs, f2, from 0.45 to 0.6 increases the total hydrogen cost by only 1.8% and 1.1%, respectively, for the 1981 and 1983 technologies.

The above results are summarized in Table 4.6.1 for easy reference. Because plausible changes in the various parameters were considered in this sensitivity analysis, these changes may vary considerably from one to the other. Therefore, it is easier to compare the effect of one parameter with that of another on a normalized basis. The normalized sensitivity factors were calculated based on the relative change in the total hydrogen cost for the same percentage change in each parameter and normalized to the parameter with the least effect on total hydrogen cost. The latter turned out to be the total compression cost. The normalized sensitivity factors for the various parameters are listed in Table 4.6.2. From this table it is apparent that the plant - 13 -

capacity factor has the largest effect on the total hydrogen cost, if very low capacity factors are considered. However, when varied from 0.9 to 0.5, this factor becomes less important and for the 1983 technology at 3

4.7 Summary and Conclusions

A parametric cost equation first developed by LeRoy and Stuart (15) was modified to include the cost of compression for atmospheric-pressure electrolyser technologies and is presented in Appendix A.

Competition in the present electrolytic hydrogen market among manufacturers of electrolysers is strong and the total hydrogen costs are very nearly the same. This is so for two reasons:

(a) electricity costs account for about 75% of the total hydrogen cost;

(b) electrolyser technologies with higher capital costs operate at lower voltages per unit cell than those with lower capital costs.

Competition will probably continue to be strong.

Electrolytic hydrogen costs were calculated for the Canadian unipolar electrolyser technologies. Values of $11.19/6J, $9.81/GJ and $8.94/GJ were obtained for the present 1978, 1981 and 1983 technologies, respectively, assuming 2

A sensitivity analysis shows the most important factors are plant capacity factor, electricity cost and cell voltage.

A change in the plant capacity factor from 0.9 to 0.5 changes the hydrogen cost less than 20%. This, plus the inherent operating flexibility of an elecurolyser, may make electrolytic hydrogen attractive for utility load-levelling, especially in the context of an industrial energy park being considered for the Bruce Nuclear Power Development in Ontario (29).

5. BY-PRODUCTS OF ELECTROLYTIC HYDROGEN

5.1 Heavy Mater By-Product Credit

5.1.1 Introduction

Probably because Canada is one of the few countries which has developed a heavy water nuclear power reactor for commercial use, the heavy water (D2O) by-product credit has been almost universally ignored. Yet, this credit is not sensitive to location of an electrolysis plant, unlike the - 14 -

oxygen by-product credit, since the finished product (99.8 wt% D2O) is small in volume relative to the gases produced and valuable enough that transportation costs are not a consideration. These ideas have been presented previously, not, only for electrolytic hydrogen (28, 30) but also for hydrogen in general (31) as well as for combinations of electrolytic and non- electrolytic hydrogen streams (32).

Currently, Canada produces all its heavy water by the bithermal Girdler-Sulfide (GS) process, which is based on deuterium exchange between water and hydrogen sulfide gas, because it is the cheapest stand-alone process for large volume production (33). There are several other processes for producing heavy water of commercial importance or potential which have been reviewed in reference 33. Here it will suffice to outline the basic principles of only the Combined Electrolysis Catalytic Exchange-Heavy Water process (CECE-HWP). Th"e same general principles apply also to the separation of tritium, the only radioactive isotope of hydrogen, from light and heavy water streams (34). The CECE-HWP is being developed at Chalk R^ver (35) for continuous protium removal from heavy water moderator and batch upgrading of heavy water contaminated with light water.

5.1.2 Basic Description of the CECE-HWP

In the CECE-HWP shown schematically in Fig. 5.1, the electrolytic hydrogen, already depleted in deuterium relative to the electrolyte by virtue of the kinetic isotope effect (36) inherent in the hydrogen evolution reaction, steadily loses most of its remaining deuterium as it moves up the catalyst column in counter-current flow with the feed water trickling down into the electrolysis cell. The water becomes enriched in deuterium according to reaction [2] and its isotopic analogues as it passes down the catalyst bed:

C2] HDgas Thus, the overall deuterium profile is one in which the deuterium concentration in the water increases from top to bottom of the column, while in the gas phase the deuterium concentration decreases from the bottom to top. Reaction [2], which is an equilibrium isotope effect, probably occurs in two consecutive steps (37), viz:

catalysy t HD + H HDgas + H2°vaPou H + HDO gas 2°vaPour *=* 2gas vaPour and

HDOvapour + H2°lia,uid^H2°vapour + HDOliquid

In practice, reaction [3] requires a catalyst whereas reaction [4] can take place on any surface. In the CECE-HWP, reactions [3] and [4] can both be carried out in a trickle bed reactor containing Stevens1 wet-proofed catalyst (38) which - 15 -

remains active in the presence of liquid water. Stevens1 original catalyst is being developed by Butler and co-workers (39). The best catalysts are based on highly dispersed platinum deposited on carbon and bound and wet- proofed to an inert support with Teflon (37). Since platinum is the active metal, the hydrogen gas must be free of poisons such as carbon monoxide and hydrogen sulfide. Electrolytic grade hydrogen is thus ideal for this catalyst. The dehumidifier (see Fig. 5.1) not only dries the depleted hydrogen gas but also transfers to the feed water the deuterium in the water vapour carried by the hydrogen gas.

The scrubber between the catalyst column and the electrolysis cell serves the following functions:

(a) removes entrained electrolyte in the hydrogen gas; (b) adjusts the humidity of the hydrogen to the conditions prevailing in the column, which need not be the same as those in the cell; (c) thermostats the humidified gas to the column temperature;

(d) transfers deuterium from the water vapour entrained in the hydrogen gas to the 1'quid water.

The last function is very important since the deuterium concentration of the water vapour in the hydrogen leaving the electrolysis cell could easily be 3-10 times larger than that in the water at the bottom of the exchange column (28). This difference is mainly dependent on the magnitude of the effective electrolytic H/D separation factor, which in turn depends on the cathode material and the operating conditions of the electrolysis cell (36).

Any type of water electrolysis cell may be used in the CECE-HWP. If the cell contains a liquid electrolyte, such as 25-30 wt% solution of KOH, the salt of the electrolyte must be removed from the product stream before it can be fed to the next higher stage. Alternatively, the feed water for the second stage may be conveniently obtained from the oxygen drier under certain operating conditions. Only three stages are required to enrich natural water at about 140 parts per million D/(H+D) to reactor grade at 99.8 wt% (28). The first, second and third stages represent about 95%, 4.855 and 0.2%, respectively, of the total plant volume (28).

5.1.3 Heavy Water Credit

The gross dollar value of heavy water per GJ of hydrogen has been calculated (31} as a function of three independent variables, namely,

(a) R, the fraction of deuterium recovered which depends on the process and process conditions; - 16 -

(b) D^, the deuterium concentration in the feed water which depends on geographic location and has values ranging from about 133x10-6 to 148xlO"6 D/(H+D) in Canada (40);

(c) xD?0> tne Pfice of reactor grade heavy water ($/kg). The general expression for the gross dollar value of heavy water per GJ of hydrogen is:

[5] Gross D;:0 Credit ($/GJ) = 70.1 DF' based on the fact that the amount in grams of heavy water which can be recovered per GJ of hydrogen is:

4 [6] Recoverable D20 (g/GJ) = 7.01 x 10 DpR. For the CECE-KWP, practical recoveries, R, in the range 0.65-0.75 are possible (30). The price of reactor grade heavy water used here of $291/kg is based on the US published (41) price of $214/kg in 1977 US dollars corrected to 1980 Canadian dollars. Therefore, assuming Dp = 140 x 10"6 D/(H+D) and R = 0.65, the recoverable amount of heavy water per GJ of hydrogen is 6.38 g/GJ from equation [6] and, with X2Q = $291/kg, equation [5] yields:

Gross D2O Credit ($/GJ) = $1.86

Of course we are more interested in the net heavy water credit. Data accumulated since 1969 on the catalyst (39) and process in small pilot plants (e.g., 32) suggests the process 1s feasible both technically and economically. Based on these data, a reasonable estimate for the cost of the heavy water recovery system (excluding the electrolysis plant) may be obtained by assuming this cost is 25% of the total hydrogen cost, excluding electricity costs for hydrogen production and compression (C4 and C$ in equation [1]). This results in a heavy water recovery cost of $0.54/GJ for the reference hydrogen cost of $9.81/GJ (see Section 4.5). Therefore, we get:

Net D2O Credit ($/GJ) = $1.32

This value for the net credit is in general agreement with estimates made by LeRoy (42) and is comparable with the oxygen by-product credit discussed later.

The heavy water recovery cost estimate of $0.54/GJ obtained here may be compared with estimates from a previous assessment (43). The total capital cost, including the hydrophobic catalyst, for the heavy water recovery system was estimated in reference 43 at $11.57 x 106 (1978$) for a 400 MW electrolytic hydrogen plant. This yields a heavy water capital recovery cost 6 of $0.31/GJ based on V-j = 1.9 V, P = 0.9, K = 0.2, DF = 140 x 10" D/(H+D), R = 0.65 and converting 1978 to 1980 dollars. In this same study (43) the operating costs for the heavy water recovery system alone was estimated at $0.54 x 106 (1978$) per annum, which corresponds to $0.06/GJ here. - 17 -

Therefore, the total heavy water recovery cost is $0.37/GJ based on data of reference 43. This is about 30% lower than the estimate of $0.54/GJ calculated here.

A small demonstration plant for the CECE-HWP is being built by Noranda-Electrolyser, in close collaboration with AECL, at the Hydro-Quebec Research Institute (IREQ) located at Varennes near Montreal. It will help to determine recovery costs.

Since the costs of any new processes have a tendency to escalate as the technology becomes established, it is prudent to be conservative. Thus, a net heavy water credit of $1.25/GJ is assumed for inclusion in the hydrogen cost projections. This allows a h«avy water recovery cost of $0.61/GJ of electrolytic hydrogen produced.

5.1.4 How Much Heavy Mater from Hydrogen Production? At present there is an excess of supply over demand for heavy water so that a new heavy water plant is not likely to be committed in Canada before about 1990. However, it must be appreciated that even large electrolytic hydrogen plants could produce only relatively small quantities of by-product heavy water. For example, GS plants are typically built in two units each with a name plate capacity of 400 Mg/a and providing feed of about 15 wt% heavy water to a common water-distillation finishing unit (33). For the CECE-HWP, the electrolysis energy required to produce one kilogram of heavy water is (28):

[7] Electrolysis Energy (kWh/kg of D20) = 2.68 Vi/DF-R Assuming a cell voltage of 1.9 V (Reference Case), a heavy water concentration in the feed water of. 140 x 10 D/(H+D) and a heavy water recovery of 0.65, then 56 MWh/kg of heavy water would be required. Therefore, a 100 MW electrolysis plant operating in a CECE-HWP mode at a plant capacity factor of 0.9 would produce:

100 x 365 x 24 x 0.9 x 10 = 14 Mg of ^ per year 56 In other words, the size of the electrolysis plant in a CECE-HWP mode would have to be:

100 x 40° - 2860 MW 14 to produce 400 Mg of heavy water per year which is still only half the capacity of a modern GS heavy water plant.

Because relatively modest amounts of heavy water could be produced as a by-product of electrolytic hydrogen (or other hydrogen streams), by-product heavy water could help to smooth the supply-demand curve in the future. In the long run, however, it is conceivable that all of the required heavy water could be produced as a by-product of hydrogen production. For example, - 18 -

the recoverable heavy water per exajouie (10^ J, MQ15 BTU) is given by the expression:

[8] Recoverable D20 (Mg/EJ) = 7.01 x 10? DFR With Dp = 140 x 10"6 and R = 0.65, the recoverable heavy water is 6,400 Mg/EJ. This amount of heavy water is roughly equal to three times the annual name-plate production from the present Canadian capacity and illustrates the potential of the CECE-HWP in the context of a mat'ire hydrogen- electric economy of the future. One exajoule of energy is about one-tenth of Canada's total annual energy demand (10).

5.2 The Oxygen By-Product Credit

5.2.1 Introduction In contrast to the heavy water by-product credit, the oxygen by-product credit cannot be realized unless there is a market for the oxygen at or near the site of the electrolytic hydrogen plant. This is because the volume produced, being half that of the hydrogen output, is too large for inexpen- sive transportation over long distances. There may well be circumstances where the oxygen is considered the primary product, for example in "all current coal conversion schemes" (gasification or liquefaction) (44). In this case, however, the above arguments apply equally well to the hydrogen co-product. The most favourable circumstances are of course those where both the oxygen and hydrogen are required in about the 1 to 2 molar ratio in which they are produced. This situation favours the concept of an industrial energy-chemicals park. It is worth repeating that the heavy water by-product credit is applicable regardless of whether hydrogen or oxygen is the primary product and in this sense alone this credit is more likely to be realized than the oxygen by-product credit.

5.2.2 Oxygen Credit

The value of by-product oxygen associated with 1 GJ of electrolytic hydrogen may be calculated as:

2 [9] Gross 02 Credit ($/GJ) = 5.60 x 10- x02 where xg2 is the price of oxygen expressed in dollars per metric ton or tonne.

Based on a cell voltage of 1.9 V, a 100 MW electrolytic hydrogen plant would produce 377 tonnes of oxygen per operating day. For a similar capacity, Wuensche (45) gives a cost range of $20-$23 (1977 US dollars) per ton (2000 lbs) of oxygen for three versions of a modern cryogenic air separation plant. This price range converts to $25-$28 (1980 Canadian dollars) per tonne of oxygen. Therefore, from equation [9] we get:

Gross 02 Credit ($/GJ) = $1.49 ± 6% and this represents the maximum oxygen by-product credit one could expect. - 19 -

In the case of the Canadian atmospheric-pressure unipolar electrolyser technology, the oxygen gas would also need to be compressed. As a first approximation, this cost is estimated to be half* the total compression costs for hydrogen as calculated from equations [5] and [6], i.e., $0.26/GJ for the Reference Case. On this basis, we get:

Net 02 Credit ($/GJ) = $1.23 _+ 9% as the net oxygen credit per gigajoule of electrolytic hydrogen.

For the cost projections presented in Chapter 6, an oxygen by-product credit of SL25/GJ is assumed.

5.3 Combined Credits The total by-product credit (net) for oxygen and heavy water is here assumed to be $2.50/GJ of electrolytic hydrogen based on Sections 5.1.3 and 5.2.2.

If the combined by-product credit of $2.5O/GJ can be realized as out- lined here, it is interesting to note it would offset all but the electrolysis energy cost component for the Reference Case (see Table 4.4.2, 1981 technology).

5.4 Summary and Conclusions The heavy water and oxygen by-product credits are each estimated to be $1.25/GJ of electrolytic hydrogen, for a combined credit of $2.50/GJ.

The heavy water net credit is based on conservative estimates of the extra cost for the heavy water recovery system of the Combined Electrolysis £atalytic Exchange-Heavy Water Process (CECE-HWP), assuming a heavy water price of $

The oxygen by-product credit is more difficult to realize than the heavy water credit because of transmission costs except in the context of an industrial energy-chemicals park.

The combined oxygen and heavy water net credit of $2.50/GJ of electrolytic hydrogen, if realized, would offset all but the electrolysis energy cost for the Reference Case (see Table 4.4.2, 1981 technology).

Recall that the volume of oxygen produced is only half that of the hydrogen. - 20 -

6. COST PROJECTIONS FOR HYDROGEN 6.1 Introduction As stated previously, only three major sources of hydrogen need be considered in Canada for large-scale hydrogen production. These are natural gas reforming, coal gasification and electrolysis of water. The tine period considered in the cost projections is 1980 to 2025 and tfie latter date coin- cides with the final year of the hydrogen market assessment of the International Energy Agency (1). All cost projections are based on 1980 Canadian dollars so that the assumed escalation rates are over and above the inflation rate. The base costs for hydrogen from fossil resources are not necessarily current costs and the analysis presented is not meant to be absolute in any sense: rather, it provides a sketch over the next few decades which may be useful to planners of energy strategies and energy R and D programs. The cost comparisons are imprecise in the sense that crude oil costs are compared with natural gas costs and electrolytic hydrogen costs on an energy equivalent basis. Crude oil requires considerable processing (including energy to do so), natural gas requires little processing when used as a fuel, while electrolytic hydrogen is a pure chemical and clean fuel. On the other hand, no estimate has been made of the storage and distribution costs of hydrogen relative to these costs for natural gas or oil products. Environmental costs have also been neglected except to the extent they have already been included in referenced work of others.

The assumptions made in these cost projections are clearly stated but are certainly not the only reasonable ones one can choose. 6.2 Hydrogen from Natural Gas One of the objectives of the National Energy Program '46) is to replace oil with natural gas as much as possible. To stimulate such substitution, the ratio of gas prices to oil prices will fall from 80% in 1980 to 67% in 1983. For eastern Canada, the city gate price was $2.42 in 1980 and $3.84 in 1983 ($1983) per thousand cubic feet but the National Energy Program does not specify natural gas prices beyond 1983. The assumptions used here are (a) the natural gas price is pegged between 50% and 75% of the oil price in Canada for the period considered; (b) the oil price to which natural gas is pegged is the "world oil price" as presented in the discussion paper on liquid fuel options (47), namely, $38 per barrel in 1980 Canadian dollars; as such it represents what has to be paid for imported oil, or the opportunity price on the export market for any surplus Canadian oil; (c) a barrel of oil contains 6 GJ of energy so that the oil price in 1980 becomes $38 6 = $6.33/GJ; - 21 -

(d) the cost of reforming natural gas to produce hydrogen is equal to the cost of the natural gas in $/GJ, that is, the cost of hydrogen from natural gas is twice the cost of the natural gas; (e) the "world oil price" defined in (b) above will escalate 4% per annum in real terms, i.e., over and above inflation. Assumption (a) may be conservative both in the context of the National Energy Program as well as in the context of natural gas resources in the more remote areas of Canada. Such "frontier" natural gas will certainly be cost- lier to bring to the market place. Also, for export and supply reasons alone, it seems certain that natural gas will be closely pegged to the oil price in the 1990's in Canada. Indeed, it seems possible that, as oil De- cones even more expensive domestically and internationally, natural gas could reach the energy-equivalent price of crude oil in Canada around the turn of the century. Because natural gas is already a finished product as a fuel, while crude oil is not, natural gas would still be cheaper than heating oil. Assumption (d) also requires some comments. Since natural gas must be reformed into hydrogen and carbon dioxide, the cost of this hydrogen consists of the cost of the natural gas plus the cost of the reforming operation. Bailey (48) calculated a cost of $4.30/GJ for hydrogen based on $1.89/GJ for the natural gas feed. In other words, the cost of the hydrogen was about 2.3 times the cost of the natural gas feed. As a first approximation, then, it is assumed here that hydrogen from natural gas costs two times the cost of natural gas, a factor which was also used by Johnson and Verma (25). This factor of two may be high at high natural gas prices. However, the reforming process is only about 60% energy efficient, if there is no market for export steam. Therefore, high fuel costs would tend to increase the operating costs of the process significantly.

The assumed 4% annual escalation in the oil price, while arbitrary, seems to be quite realistic in view of the changes in imported oil prices in the last few years. The reader may prefer, however, to use either a lower or higher escalation factor. With the above assumptions the cost of hydrogen from natural gas in 1980 is $6.33/GJ and $9.50/GJ based on pegging natural gas at 50% and 75% of the assumed oil price, respectively. The projected hydrogen cost as a function of time is shown in Fig. 6.1. Note that the lower curve is also equivalent to the oil cost projections because for this curve we have assumed that natural gas costs one-half the oil price and hydrogen derived from natural gas costs two times the cost of natural gas. The upper curve in Fig. 6.1 assumes the natural gas cost is 75% of the oil price. 6.3 Hydrogen From Coal In the Canadian context, Bailey (48) has estimated the cost of hydrogen using the present Koppers-Totzek process and its second generation - 22 -

equivalent to be $8.50/GJ and $6.90/GJ, respectively. These cost estimates are based on a plant producing 9.3 x 10^ m^ of hydrogen per year at a plant capacity factor of 0.9 and a coal price at the mine-mouth of $9.33/tonne. Hydrogen derived from coal at a location remote from a mine would be more expensive because of transportation costs. Since these costs are site specific, no attempt is made to estimate them here. Here it will be assumed that hydrogen derived from coal in Canada would cost $8.50/G0 and $6.90/GJ for current and upgraded coal gasification technology in 1980, respectively. It is further assumed that the real cost of hydrogen from coal will escalate at 2% per annum. The lower escalation factor for coal is based on the premise that natural gas is more marketable than coal. Also, it provides another escalation rate for fossil-derived hydrogen in general. The curves shown in Fig. 6.2 for coal-derived hydrogen were calculated on this basis. For comparison, the hydrogen cost curves for natural gas (Fig. 6.1) are also shown in Fig. 6.2. With the assumptions made here, the cost of hydrogen derived from coal is cheaper than that for hydrogen derived from natural gas except for the lower cost projection for the latter between 1980 and 1985. This analysis, however, makes no attempt to assess the relative environmental costs inherent in these two hydrogen production technologies.

6.4 Electrolytic Hydrogen

Melvin (9) gives convincing arguments that, at best, Canada's electricity costs need not increase at all and, at worst, increase only about 30% over the next three decades in constant dollars. This situation is due to Canada's untapped resources of hydroelectric power and its CANDU nuclear reactors, both of which are capital intensive but have very low operating costs and are therefore inflation resistant. The Department of Energy, Mines and Resources recently forecasted 0.6% real escalation per annum for electricity costs in Canada (50). Because projected escalation rates for electricity costs in Canada are so small, zero escalation has been assumed in this study for the sake of simplicity. While this is not the most conservative approach, the difference between zero escalation and the other estimates is so small that it has little effect on the overall results.

In this study it is assumed that the chosen Reference Cost of $9.81/GJ for electrolytic hydrogen varies jH20%, giving a low estimate of $7.85/GJ and a high estimate of $11.77/GJ.

The assumed ±20% variation in the cost estimates of electrolytic hydrogen is roughly equivalent to a ±30% variation in the cost of electricity (see Table 4.4.2). The cost of $9.81/GJ is based on an electricity cost of 2

The high estimate of $11.77/GJ allows for higher electricity costs among the smaller Canadian utilities, i.e., from 2 to about 2.6

(b) With respect to technology improvements, the relatively near- term 1983 Canadian unipolar technology (see Section 4.3) would decrease the electrolytic hydrogen cost from $9.81/GJ to $8.94/GJ at 24/kWh. Further technology improvements (14) can be expected, that is, a lower operating cell voltage than 1.8 V and a higher operating current density than 320 mA/cm^, which were assumed for the 1983 technology (see Table 4.4.1). However, whether the lower limit of $7.85/GJ for 1980 costs can be achieved with improvements in the technology alone is debatable. (c) In Chapter 5, the net oxygen by-product credit and the net heavy water by-product credit were each estimated to be $1.25/GJ for a total net credit of $2.50/GJ. These are shown in Fig. 6.4, which is otherwise identical to Fig. 6.3. The heavy water by-product credit of electrolytic hydrogen production can always be realized in principle regardless of the location of the plant. If both of these credits can be realized, the $7.85/GJ cost would be reached with the 1981 technology; if only one credit is realizable, this cost could be reached with the 1983 technology, which is expected to be available by the time any plant planned now could be built. Another way to view the by-product credits is to assume the Reference Cost (which is also the average cost in Fig. 6.3) of $9.81/GJ for electrolytic hydrogen and subtract the credits which gives $7.31/GJ for electrolytic hydrogen. This is still somewhat lower than the lower cost of $7.85/GJ of Figs. 6.3 and 6.4.

The lower limit of $7.85/GJ for 1980 costs for electrolytic hydrogen seems justified by the above reasons. The electrolytic hydrogen cost projections based on the above assumptions are shown in Fig. 6.3 along with the cost projections for hydrogen derived from natural gas and coal. Electrolytic hydrogen is competing with hydrogen derived from both natural gas and coal during the 1980's! This is surprisingly soon and illustrates the need to include electrolytic hydrogen - 24 -

in studies of the replacement of fossil resources not only from the conservation but also the economic point of view. The result obtained here, that electrolytic hydrogen can soon compete with hydrogen derived from coal and natural gas, is consistent with the estimated trends (1) in the utilization of the hydrogen production processes for Canada, Japan, Sweden and Switzerland, all of which show electrolytic hydrogen to be the most probable production technology by the year 2005. In fact, of the other four countries (Belgium, Germany, Netherlands and USA) which participated in the International Energy Agency's hydrogen market assessment (1), only the Netherlands and the USA exclude electrolytic hydrogen as one of the most probable production processes by the year 2025. 6.5 Summary and Conclusions

The estimated lower 1980 costs for hydrogen from natural gas, coal and electrolysis are $6.33, $6.90 and $7.85 per gigajoule of hydrogen, respectively; the corresponding higher 1980 cost estimates are $8.50, $9.50 and $11.77.

The lower and higher 1980 cost estimates for hydrogen derive^ from coal are based on mine-mouth coal. Therefore, such hydrogen would cost more anywhere else.

Costs for the period 1980 to 2025 are projected on the assumption that the 1980 costs for hydrogen derived from natural gas and coal will escalate 4% and 2% per annum, respectively, in real 1980 Canadian dollars, while electrolytic hydrogen costs will only increase with the rate of inflation. The latter assumption is justified on the basis that Canadian electricity costs could stay constant in real terms, for reasons given in reference 9, and that electricity costs account for about 75% of the total hydrogen cost.

Electrolytic hydrogen is potentially competitive with hydrogen derived from both natural gas and coal in the 1980's!

Each by-product credit is estimated at $1.25/GJ of electrolytic hydrogen produced; the combined heavy water and oxygen by-product credit is $2.50/GJ.

The conclusion that electrolytic hydrogen can compete with hydrogen derived from coal and natural gas is consistent with the International Energy Agency's finding (1) that electrolysis of water is the most probable hydrogen production process in Canada by the year 2005.

The above results illustrate the need for including electrolytic hydrogen in studies of the replacement of fossil resources not only from the conservation but also from the economic point of view. This assumes that the primary energy source for such hydrogen is not a fossil fuel but rather inflation-resistant hydro or nuclear electricity. 7. HYDROGEN: ANOTHER LIQUID FUEL OPTION? 7.1 Introduction Hydrogen has the technical potential for replacing the present liquid fuels (gasoline, diesel fuel, aviation fuels) in the transportation sector either directly or as an intermediate chemical such as ammonia or methanol. In this chapter we are concerned only with comparing probable costs of electrolytic hydrogen with cost estimates for other liquid fuel options for the future. The added costs of combining the hydrogen with another element or elements (e.g., N2 to fora NH3) are not included and neither are storage and handling charges for hydrogen alone. This is probably a fair approximation since the comparison will be made with the costs of producing a barrel of crude oil from unconventional sources and the costs of producing other options per barrel of oil equivalent. Probable contributions which electrolytic hydrogen could make are also discussed. 7.2 Oil-Equivalent Electrolytic Hydrogen Costs The lower and higher cost estimates of electrolytic hydrogen without the oxygen and heavy water by-product credits are $7.85/GJ and $11.77/GJ, respectively (see Section 6.4). Assuming a net heavy water by-product credit of $1.25/GJ (see Section 5.1.3) then, on the basis of 6 GJ of energy per barrel of oil, these lower and higher cost estimates for electrolytic hydrogen are equivalent to about $40 and $63 per barrel of oil. That is, electrolytic hydrogen begins to compete with oil at $40 per barrel.* The oxygen by- product credit (see Section 5.2.2) has been omitted deliberately since it is not certain that a market for oxygen would exist at the site of hydrogen production. If there were an oxygen market, electrolytic hydrogen would begin to compete with oil at $32 per barrel. Even at $40 per barrel of oil equivalent electrolytic hydrogen shows promise as one alternative to oil within the time frame considered here. 7.3 Other Liquid Fuel Options What are the other alternatives with which hydrogen must compete and what are their estimated costs of production? The "Discussion Paper on Liquid Fuel Options" (47) is a convenient document to use for answering -these questions. Accordingly, possible liquid fuel options in 1980 are the alcohol fuels and compressed natural gas, either from natural gas wells or coal gasification plants. The estimated (47) production capacity by 1999 is limited to 50,000 bpd (bpd = barrels per day) with an estimated cost range of $20-$45 (1980 $) per barrel oil equivalent. New hydrocarbon fuels from natural gas (see reference 50) are capable of yielding 180,000 bpd in 1990 and their

* The OPEC countries agreed to a uniform price of $34 (US) per barrel in 1981 October. This corresponds to $41 (Cdn., 1981 October) or $38 (Cdn., 1980) per barrel, assuming an inflation rate of 12% per annum. - 26 -

estimated costs are in the range $30-$60 per barrel of oil equivalent. Methanol and ethanol from wood wastes are estimated to yield another 25,000 bpd at an estimated cost between $30 and $50 per barrel oil equivalent, depending on the transportation distances involved. Ethanol might also be produced from prime grains in special regions of Canada where this concept of using agricultural land and food products might be accepted on a limited scale. The cost for such ethanol is estimated to be in the range $50-$100 per barrel of oil equivalent with a question mark on the high estimate. Only 10,000 bpd are predicted for 1990 for ethanol from crops produced in special situations, with estimated costs between $50 and $70 per barrel of oil equivalent. These options are all shown in Fig. 7.1 as a function of cost per barrel of oil equivalent and the daily liquid fuel production for Canada's needs for 1990. The figure has been reproduced from reference 47 and the hydrogen data added. The cost estimates for electrolytic hydrogen, which have already been discussed, overlap those for new hydrocarbon fuels from natural gas and coal, as well as those for the biomass-alcohol options (see Fig. 7.1). This preliminary assessment indicates that by 1990, electrolytic hydrogen could compete economically with some of the other options being considered. As Fig. 7.1 shows, the estimated range of Canada's daily liquid fuel requirements (47) for 1990 are a minimum of 1.4 x 10° bpd to an uncertain maximum requirement of 2 x 106 bpd oil equivalent. Note that the minimum requirement can be met by conventional and unconventional indigenous oil resources, with changes in fuel specifications and refining practices. How- ever, if the requirement exceeds 1.6 x 106 bpd, other liquid fuel options will be needed. As Fig. 7.1 shows, hydrogen could play a direct role when the daily requirement exceeds about 1.8 x 10° bpd. Therefore, it is legit- imate to ask how much hydrogen could be produced for this requirement. 7.4 How Much Electrolytic Hydrogen as a Fuel Option? Since it will probably require the present decade to demonstrate hydrogen utilization in the Canadian transportation sector on a reasonable scale, it is doubtful that by 1990 hydrogen will be a realistic alternative to other options, such as compressed natural gas and propane. Hydrogen could play a role in stationary applications where it must compete with natural gas directly and not with hydrogen derived from natural gas. The cost of reforming natural gas is therefore not applicable in the fuel applications. Using otherwise the same assumptions as previously (see Section 6.4) the cost estimates for natural gas in 1980 are $3.17/6J and $4.75/GJ for the lower and higher cases, respectively. These values for natural gas as a fuel and the corresponding cost projections are shown in Fig. 7.2 along with the assumed oil price (upper curve) and the electrolytic hydrogen cost estimates, including the by-product credits. Recall that the oil curve in Fig. 7.2 is identical with the lower cost curve for hydrogen from natural gas (Fig. 6.1) and that it is assumed natural gas prices will track - 27 -

the assumed oil price at 50% and 7555, respectively, for the lower and higher cost estimates. Without by-product credits, electrolytic hydrogen becomes competitive with natural gas in the fuel applications around the beginning of the next century. With the heavy water credit only (see Section 5.1.3), the crossover occurs earlier. If it is assumed that the oxygen by-product credit could also be realized, the crossover is in the early 1990's. Conversely, electrolytic hydrogen is unlikely to be competitive with natural gas as a fuel before the 1990's even if both by-product credits could be realized.

Since electrolytic hydrogen could become economic as a fuel by the turn of the century, the following questions may be asked: "How large would these electrolytic hydrogen plants need to be and would we have the required electricity generating capacity"?

The first question can be answered as follows. To offset 100,000 bpd oil, containing 6 GJ of energy per barrel, we require:

9 100,000 x 6 x 10 ft 3,600 x 103 " L67 X 108 kWh

of hydrogen energy. At a capacity factor of 0.9 and an energy efficiency of 82.2% {which is equivalent to a single cell voltage of 1.8 V or 1983 technology), the size of the electrolysis plant which could produce hydrogen equivalent to 100,000 bpd of oil would be:

1.67 x 108 , 24 x 0.822 x 0.9 = 9'41 x 106 kW or ^-W-

This represents about 12% of the 1979 Canadian installed electricity generating capacity of 77.1 GW (3) and about 60% of the currently planned Canadian nuclear electricity generating capacity of 16.2 GW.

From the foregoing it appears technically, economically and practically feasible to replace 100,000 bpd of oil with electrolytic hydrogen by the year 2025 in Canada. While this quantity of oil is substantial from the point of view of electrolytic hydrogen, it is not very significant from the point of view of Canada's oil consumption.

The nuclear-based hydrogen alternative to liquid fuels is not limited by primary energy sources be they uranium or thorium for fission reactors (48) or deuterium for fusion reactors. This situation is portrayed in Fig. 7.1 by the arrows extending from the upper and lower cost estimates. The key point is that Canada has an indigenous electrolyser technology which, combined with inflation-resistant electricity from hydroelectric and nuclear stations, can provide a real upper limit to the cost of viable alternatives for transportation fuel. - 28 -

The hydrogen alternative becomes even brighter when one considers the environmental advantages of zero pollution from sulfur dioxide, carbon dioxide and carbon monoxide emissions associated with hydrogen combustion. How- ever, direct substitution of hydrogen for oil is not yet feasible technically nor economically on a large-scale. Indirect substitution is now possible technically: indirect substitution includes, for example, manufacturing methanol from electrolytic hydrogen and a carbon source such as lignite, etc. With methanol, the handling, storage and distribution problems associated with direct use of hydrogen are circumvented. 7.5 Summary and Conclusions Hydrogen has the technical potential for replacing present liquid fuels in transportation as well as stationary applications. The electrolytic hydrogen cost estimates, which include the net heavy water by-product credit, are equivalent to crude oil prices of $40 and $63 per barrel for the lower and higher estimates (discussed in Section 6.4), respectively. Electrolytic hydrogen cannot compete with natural gas as a fuel until about the turn of the century. It is technically, economically and practically feasible to replace 100,000 barrels of oil per day with electrolytic hydrogen indirectly, e.g., via methanol, by the year 2025 in Canada. Such substitution would require about 10 GW of electrolytic hydrogen plants. The feasibility of distributing this hydrogen directly and using it as a vehicle fuel, however, is uncertain. The hydrogen option based on nuclear electricity is not limited by primary energy resources.

8. MARKET POTENTIAL FOR CHEMICAL HYDROGEN 8.1 Introduction The main uses of hydrogen at present are chemical. These are discussed in Chapter 2 and shown in Fig. 2.1 for the year 1978. In this chapter, the Canadian market potential for hydrogen used for the production of chemicals, hydrocarbon fuels and synthetic crude oil (synfuel) is estimated for the period 1980 to 2025. The reference estimates are based on Bailey's assessment (49) as presented in reference 1. Since Bailey's estimates are stated (49) to be conservative, the effects of assuming larger growth rates were examined. 8.2 Chemical Hydrogen Demand Projections - 29 -

8.2.1 Ammonia Production Ammonia production consumed 5.1 On3, or 43% of the total Canadian hydrogen supply in 1978. It has been estimated (1) that this quantity would be increased to 10.9 Gm3/a by 2025. This gives an average annual growth rate of only 1.63% and is the basis for the reference demand projection (see Fig. 8.1). For the higher hydrogen demand projection included in Fig. 8.2, it is assumed that the above growth rate is doubled, i.e., 3.26% per annum and that the 1980 consumption is 5.2 Gto3. This yields a projected hydrogen demand of 22 Gm3/a by 2025. Note that the scale on the ordinate of Fig. 8.2 is larger than that of Fig. 8.1. A higher rate is justified not only on the basis that Bailey's growth rates are conservative (49), but also because Canada is expected to have a competitive edge in both natural gas and electricity prices over the next few decades. Doubling Bailey's growth rate is arbitrary and the reader may wish to use a different rate. 8.2.2 Oil Refining Some hydrogen is produced in normal refining operations but supplemen- tary volumes are required to meet the desired product mix. This additional hydrogen is typically produced by steam reforming of natural gas (52) at present. Because available crude oils are getting heavier on the average, more hydrogen is needed to arrive at the same product mix. It is estimated (52) that the hydrogen which should be added per barrel of crude oil will increase 3 from about 1.2 m -jn IQQQ t0 u m3 -jn 2015. Therefore, the hydrogen demand in this use sector is expected to increase in spite of the fact that the total demand for petroleum products is likely to decrease. Oil refining was the second largest user of hydrogen in 1978 at 33% of the total or 3.9 Gm3/a (1). Interpolation of the 1978 and 1985 estimates (1) gives 4.2 Gm3/a for 1980 for this use sector. The reference demand projection consists of straight line segments between this value and the values shown in Table 8.2.2.1 from reference 1. The results are plotted in Fig. 8.1 on this basis. For the higher demand projection in Fig. 8.2 the following assumptions were made: (a) the hydrogen demand is the same as for the lower estimate from 1980 to 1985; (b) for the period 1985 to 2025, the hydrogen demand increases from 4.9 Gm3/a in 1985 at 3% per annum. The 3% per annum growth rate in (b) above was calculated on the assumption that the annual hydrogen demand for the higher projection would be about double that of the reference projection by 2025. On that basis, the projected hydrogen demand is 16 Gm3/a in 2025 (see Fig. 8.2). - 30 -

The 3% growth rate is based on the assumption (52) that the Quebec and Ontario refineries together will have a shortfall of hydrogen of about 12 Gm^/a in 2015. One-half of this quantity, i.e., 6 Gn^/a, is based on the "upper sensitivity" curve of Fig. 1 of reference 51 for the year 2015. Although this estimate is the highest estimate for Ontario, refineries in the other provinces, e.g., Newfoundland and New Brunswick, are also expected to require more hydrogen per barrel of crude oil. Therefore, the higher estimate used here seems reasonable. 8.2.3 Synthetic Fuel Canada's oil sands and heavy oil deposits are important sources of synthetic fuel or crude oil. Since both bitumen from oil sands and heavy oil contain smaller fractions of hydrogen than conventional crude oils, more hydrogen is needed to achieve the predominant two to one ratio of hydrogen to carbon in most hydrocarbon fuels. Alternatively, carbon can be rejected to achieve the appropriate H:C ratio. This is wasteful of carbon but not with respect to energy, according to Taylor (53). A combination of carbon rejection and hydrogen addition is used in the present oil sands plants. In the future, however, it will be more prudent to conserve our dwindling carbon resources by adding hydrogen from an abundant source such as nuclear-based electrolytic hydrogen. Nuclear energy will more likely be applied first in oil sands processing as a source of heat for in- situ extraction (54). However, electrolytic hydrogen production could be a subsequent step. Coal liquefaction would require even larger quantities of hydrogen per unit of hydrocarbon produced. The integration of nuclear-based hydrogen, electricity and heat has been described in detail by Wojciechowski (55, 56) who considered both the oxygen and heavy water by-products of electrolytic hydrogen production. Synthetic fuels are produced by the Fischer-Tropsch synthesis followed by refining. In 1978, hydrogen for synthetic crude oil production accounted for 12% of the total hydrogen demand (see Fig. 2.1). The consumption was 1.4 Gm3 (1). The reference estimate for the projected hydrogen demand for synthetic fuel production is based on reference 1. The value of 1.7 Gm^ for 1980 is based on a linear interpolation of the 1978 and 1985 data of reference 1. As in the oil refining application, the reference demand projections are based on straight line segments between this value and those of Table 8.2.3.1. The results are included in Fig. 8.1 on this basis. For the higher demand projections the following assumptions were made: (a) the hydrogen demand is the same as for the reference estimate from 1980 to 1985; - 31 -

(b) for the period 1985 to 2025 the hydrogen demand increases from 2.5 Gm3/a in 1985 at 7% per annum. The 7% per annum growth rate in (b) above was calculated on the assumption that the annual hydrogen demand for the higher projection would be about double that of the reference projection by 2025. On this basis the projected hydrogen demand is 37.4 Qn3/a in 2025 (see Fig. 8.2). The higher estimate is justified partly because the reference one does not include any coal liquefaction plants (1) and partly because it is expected that in this time frame the carbon efficiency argument (discussed above) will be progres- sively applied to all processes for synthetic crude and fuel production on economic as well as carbon-conservation grounds. The 7% growth rate is practical since this has been the traditional growth rate in Canada for electricity generating capacity (9). 8.2.4 Methanol Production Hydrogen for methanol production accounted for about 9% of Canada's 1978 hydrogen demands. It is assumed in reference 1 that the hydrogen demand for methanol in Canada will remain constant until 1985 and then increase at the very small rate of 0.26% per annum between 1985 and 2025. Thus, the reference estimate shown in Fig. 8.1 is based on 0.9 Qn3/a in 1980-1985 and the above growth rate in 1985-2025. This rate assumes there is no demand for methanol as a gasoline blender (1) or as a fuel in its own right. Even though the higher- estimate, shown in Fig. 8.2, is based on a 3% per annum growth rate frci 1985 onward, the total hydrogen demand by 2025 is still only 2.51 Gm3/a compared to 0.9 Gm3/a for the reference estimate. If methanol should become important as fuel, the higher estimate used here is very conservative. On the other hand, hydrogen as fuel, considered in Chapter 7, could end ur as methanol or ammonia in the transportation sector. In this sense, the analysis here covers the methanol option quite adequately. 8.3 Summary and Conclusions While ammonia production was the largest user of hydrogen in 1973, in- dications are that synthetic fuels will consume the largest fraction in 2025. Hydrogen is already important in the energy field to increase the hydrogen to carbon ratio in oil refining and in the heavier remaining fossil resources, such as Canada's oil sands and coal reserves. Hydrogen for methanol production consumed only about 9% of the demand in 1978 and was the smallest of the large users identified. Even the higher projected demand case for methanol is modest but allows for some blending with gasoline. A major commitment to methanol as a transportation fuel would increase the hydrogen use projections given here for this chemical by the same order of magnitude as those given for hydrogen used as a fuel (see Figs. 8.1 and 8.2). - 32 -

9. THE POTENTIAL MARKET FOR ELECTROLYTIC HYDROGEN 9.1 Introduction In the preceding chapter the potential market for hydrogen from all sources has been computed for both a reference and a higher demand scenario covering the period 1980 to 2025. In this chapter the total demand for electrolytic hydrogen is estimated based on the electrolytic hydrogen cost projections of Section 6.4 and the hydrogen demand projections of Chapter 8. 9.2 Electrolytic Hydrogen Market Projections: Chemical Bdsed on Fig. 6.3, electrolytic hydrogen begins to compete with hydrogen derived from natural gas in 1985; since we are considering only large uses of hydrogen hera, there is no market for electrolytic hydrogen before then. Beginning in 1986, it is assumed that electrolytic hydrogen will cap- ture all new hydrogen demand in each sector. This is of course an oversim- plification". So is the inherent assumption that some of the existing hydrogen production facilities (based on fossil resources) would continue to operate at their respective 1985 levels throughout the period under consideration. Thus, the market penetration by electrolytic hydrogen is overestimated in the early years and possibly underestimated in the later years. However, the present treatment will illustrate roughly the potential size of the electrolytic hydrogen market. The cost at which electrolytic hydrogen begins to compete with hydrogen derived from natural gas is taken to be $7.85/GJ from Fig. 6.3 and does not include either the heavy water or the oxygen by-product credit. When electrolytic hydrogen is used as a fuel rather than a chemical, it must compete with natural gas directly as explained in Chapter 7. In this case, the crossover point where electrolytic hydrogen at $7.85/GJ begins to compete with natural gas occurs at the beginning of the year 2003 (see Fig. 7.2 and ignore by-product credits). With the above assumptions the demand for electrolytic hydrogen in Canada was calculated based on the hydrogen demand projections of Figs. 8.1 and 8.2 for the reference and higher hydrogen use cases, respectively. The results are given in Fig. 9.1. The artificial kink in each of the two curves in Fig. 9.1 between the years 2002 and 2003 reflects the fact the data of Fig. 9.1 exclude the direct hydrogen fuel option until the year 2003, whereas the hydrogen demand projections of Figs. 8.1 and 8.2 do not (see Section 9.2 for assumptions). In reality the curves would be smoothed by demonstration projects before and conversion lag after the cost crossover. These kinks serve to remind the reader that hydrogen as a fuel must compete with natural gas which is always cheaper than hydrogen derived from natural gas. - 33 -

As Fig. 9.1 shows, the electrolytic hydrogen demand in the traditional uses and as a fuel could be about 30 Qm3/a and 100 Gn3/a by the year 2025 for the reference and higher demand scenarios, respectively. These quantities of hydrogen would require about 140 TWh and 450 TWh of electrical energy based on 1.9 V per single cell (1981 technology) as is indicated by the ordinate scale on the extreme left of Fig. 9.1. The corresponding electrical generating capacity is indicated by the ordinate scales on the right-hand side of Fig. 9.1 for plant capacity factors of 0.8 and 0.2. About 20 GW and 60 GW of electrolyser plant capacity would be required to meet the projected reference and higher demand by 2025, assuming a plant capacity factor of 0.8. These power requirements represent 26% and 78% of Canada's 1979 electricity generating capacity (3) of 77.1 GW. The capacity factor of 0.2 represents the use of off-peak generating capacity for hydrogen production. It is apparent that very large scope for load-levelling would exist if it were possible to make economical use of hydrogen produced at variable rates. 9.3 Electrolytic Hydrogen as a Direct Fuel When manufactured from non-fossil primary energy sources, hydrogen is a substitute for fossil fuels. While such substitution is not expected to be competitive with other alternatives until about the turn of the century (see Chapter 7), hydrogen as a fuel could be a significant fraction of the hydrogen demand by 2025. Hydrogen as a direct fuel will likely be produced electrolytically in the time frame considered here for the following reasons: (a) Electrolysis of water is the only commercial process for producing non-fossil-derived hydrogen (14); (b) Canada has indigenous water electrolysis technologies; (c) Canada now enjoys and is expected to continue to enjoy relatively cheap eletricity; (d) Electrolytic hydrogen is expected to be competitive with hydrogen derived from natural gas by about the year 2000.

The assumptions chosen for the reference and higher estimates of the projected hydrogen demand for this application are based on what could be achieved technically. Thus, the reader will appreciate that substituting electrolytic hydrogen for oil will require decades. Economic constraints are superimposed onto the resultant hydrogen demand projections in Section 9.- below. The higher estimate of the projected hydrogen demand for fuel applications is based on the followi..; assumptions: (a) 200,000 bpd of oil will be replaced with an energy equivalent amount of electrolytic hydrogen, nanely 34.4 Gm3/a, by 2025; - 34 -

(b) a 100 MW electrolysis plant is in operation by 1990 as a demonstration project, producing 0.183 Gto3/a. This assumes a single cell voltage of 1.8 V (1983 technology in Section 4.4) and a plant capacity factor of 0.9; (c) production is increased linearly between 1990 and 1995 to the equivalent of a 1000 MW electrolysis plant by 1995 (1.83 Gn3/a);

(d) between 1995 and 2025, the hydrogen demand increases from 1.83 Gm3/a in 1995 at an annual rate of 10.3%, which is calculated to meet the production level assumed in (a).

The resultant demand curve is included in Fig. 8c2 so that this curve may be compared with those for the other hydrogen applications. The reference estimate for the hydroqen fuel option is based on the assumption that the growth rate in electrolytic hydrogen capacity is one-half of that for the higher estimate between 1995 and 2025, i.e., 5.13%. Assumptions (b) and (c) for the higher estimate also apply here. On this basis, the projected hydrogen demand is 8.2 &n3/a in 2025 (see Fig. 8.1) and this quantity is equivalent to 48,000 bpd of oil on an energy basis.

Both of these estimates are optimistic from an economic point of view. From a technical point of view, however, these estimates could be achieved. For example, the electricity required to meet the 34.4 Gm3/a hydrogen demand in 2025 for the higher estimate represents only 20% of Melvin's (9) estimated electricity generating capacity available for electricity substitution for fossil fuels by 2000. Melvin's estimate (9) is based on two reasonable assumptions.

(a) the traditional growth rate of 7% per annum "for Canada's electricity generating capacity is adhered to; (b) the demand for electricity for conventional uses follows a 4% per annum growth rate.

To produce 34.4 Qn3/a of hydrogen requires an electrolyser plant of 19 GW with a capital investment in 1980 dollars of about $0.75 x 109 based on the 1983 technology (see Section 4.4) and a plant capacity factor of 0.9.

9.4 Summary and Conclusions The demand for electrolytic hydrogen for large chemical uses, which are now served mainly by hydrogen derived from natural gas, is expected to start in 1985 and increase so that by 2025 this demand could reach about 30 Gm^/a and 100 &n3/a for the reference and higher hydrogen demand scenarios, respectively. Hydrogen as a direct fuel could become important at about the turn of the century. It is estimated that between 50,000 and 200,000 barrels per day of oil could be replaced with electrolytic hydrogen by the year 2025, if suitable end-use technology is available. - 35 -

Assuming the traditional growth rate of 7% annum for electricity generating capacity, but a decreased demand rate for conventional electricity uses of 4% per annum, substitution of 200,000 barrels per day of oil with an energy equivalent amount of electrolytic hydrogen would require about 20% of the alectn'city which could be generated by 2000 for substitution of fossil fuels. To produce the quantities of electrolytic hydrogen projected in 2025 would require electrolyser plant capacity of between 20 GW and 60 GW, based on a single cell voltage of 1.9 V and a plant capacity factor of 0.8. The potential market for electrolytic hydrogen in Canada is thus substantial for the reference hydrogen demand scenario and large for the higher one by the end of 2025. The scope for load-levelling with electrolytic hydrogen would be very large if it were possible to make economical use of hydrogen produced at variable rates.

10. PROSPECTS FOR RESEARCH AND DEVELOPMENT IN HYDROGEN ENERGY TECHNOLOGIES 10.1 Introduction In view of prospects for electrolytic hydrogen in Canada a serious look at the research and development needs in hydrogen energy technology is warranted. The Canadian perspective was kept in mind for all the sections below, particularly the fact that electrolytic-grade hydrogen conic! be available. While not all possible needs for research and development in hydrogen technologies are included in this chapter, examples covering most aspects are given. Relative priorities for the various R & 0 subjects have not been assessed and would depend to some extent on cost estimates that have not yet been performed. Technologies particularly suitable for Canadian adaptation and/or development are empiiasized.

Needs for R & D in the following hydrogen technologies are covered: (a) electrolytic hydrogen production; (b) energy storage and conversion with hydrogen; (c) traditional and new uses of hydrogen; (d) hydrogen storage and transmission; (e) materials research. Sustained R & D is particularly important in those areas which will allow utilization of the hydrogen energy option consistent with the national - 36 -

goal for energy self-sufficiency. These areas consist of (a) fuel cells for both mobile and stationary applications; (b) hydrogen storage technologies, particularly for on-board (vehicles) storage; (c) hydrogen utilization as a fuel (both in internal combustion engines and in fuel eel? power plants) in comparative tests with other fuel options, not only for the transportation sector, but also for stationary applications; (d) materials research and testing under conditions appropriate to ensure safe utilization. Hydrogen technologies which could permit more efficient use of our electricity generating capacity are discussed; they need directed R & D. 10.2 Hydrogen Production It has been shown (14) that electrolysis of water will be the important hydrogen production process for large-scale production which is net based on fossil fuels. Therefore, the major R & D effort in hydrogen production will continue to emphasize electrolysis. There are two basic objectives for such R & D: (a) energy efficiency - to reduce the applied single cell voltage and thereby reduce the electricity cost per unit of hydrogen produced; (b) capital cost - to increase the operating current density on the electrodes to reduce the specific size and hence specific capital cost of an electrolysis plant. The cost of the electrical energy for the electrolysis process represents 76% at 2

10.3 Energy Storage and Conversion With Hydrogen 10.3.1 Introduction^

The large scope for electric utility load-levelling by hydrogen production was noted earlier. An economical means of hydrogen storage and technologies for reconversion of hydrogen to electricity at high efficiency are required. Hydrogen production could then fill the load valleys while reconversion met the peaks.

10.3.2 Load-Levelling Options The above objectives could be met partially at the municipal-electnc- utility level by the hybrid electric-hydrogen space heating concept for the home or apartment building. In such a system electricity would supply the base heat requirement while catalytic combustion of hydrogen, produced at off-peak hours at the municipal level, would provide the peak requirement. The hydrogen would be stored for distribution to individual homes in an appropriate storage container yet to be developed. Such combustion could have the added benefit of increasing the humidity in the home during dry cold winter days. This scheme requires a cheap, reliable hydrogen storage system. The concept has merit as a dispersed load-levelling system for electric utilities and deserves serious consideration if only because virtually all of the energy content of the hydrogen is utilized. The catalytic combustor (see Section 10.4.3) and the electric-hydrogen interface system also require R & 0. For load-levelling at the generating station, the hydrogen could be produced there, stored nearby as a gas (possibly underground in natural caverns) and reconverted to electricity to meet the peak demand. Other options include piping the hydrogen generated at the station to the large consumers of gas. This option could only be viable in the long term where a hydrogen distribution system is in place. In the short term, hydrogen could be added to the natural gas system up to about 5% by volume (5) with no changes in user hardware. 10.3.3 Energy Conversion Options: Fuel Cells Reconversion of hydrogen to electricity could be by a fuel cell, a direct-fired superheater (see Section 10.3.4) or a gas turbine. Gas turbines, with their lower energy efficiency, a: e not deemed to be as appropriate for Canada for the long term as fuel cells with their higher energy efficiency. These are discussed next. United Technologies Corporation and Westinghouse Electric Corporation in the United States are both actively developing the fuel cell option for electric utilities, but only to meet their peak demands (60). The energy source is presently naphtha but will include hydrogen derived from coal later. The technology status is as follows. - 38 -

United Technologies Corporation claims to have an 11 MW (electric) water-cooled commercial prototype ready for market (60). This is their third generation of the phosphoric acid fuel cell. The Westinghouse cell, also based on the phosphoric acid electrolyte, is air cooled. They plan to build two 7-10 MW prototypes (60) which are scheduled to commence operating in late 1986 or early 1987. Opportunities o-" R & D in fuel cells exist for Canada in spite of the above programs for the following reasons: (a) because the acid fuel cells are designed to operate on naphtha or other fossil-derived hydrogen, they must be operated at a relatively high temperature (^200°C) to minimize poisoning of the highly dispersed platinum anode electrocatalyst; (b) a substantial fraction of the cost of these fuel cells is tied up in the naphtha reformer and hydrogen purification sections, since the carbon monoxide levels in the reformed hydrogen are too high and poison the catalytic electrodes; (c) the higher the operating temperature the lower is the theoretical energy efficiency of the hydrogen-oxygen fuel cell, which is just the reverse of a water electrolyser (see Fig. 3.2 of reference 14). In Canada, where we could have electrolytic grade hydrogen, the available phosphoric acid fuel cells should be modified and tested accordingly. Cost projections from US studies for these fuel cells are therefore not applicable because the Canadian versions without the fuel reformer and hydrogen purification systems are expected to be substantially cheaper. It makes good sense in Canada to have a low temperature ( < 100°C) alkaline fuel cell for transportation and other applications (61) where the shorter start-up times are an advantage, particularly in the winter. The carbon dioxide in the air fed to the cathode of an alkaline fuel cell must be removed to prevent the formation of solid carbonate. This has been done successfully by the Belgians (62), who have an alkaline fuel cell for road transportation at the prototype stage. The anode electrocatalyst is based on platinum but could conceivably be replaced with a non-noble metal electrocatalyst (62) in the next generation cell. To meet Canadian needs, Canada should adapt the Belgian alkaline fuel cell in both the transportation and utility applications. This would require a fuel cell test bed as well as an appropriate R & D program for scale-up of the basic cell components. This test facility would also be used for adapting the phosphoric acid fuel cells to electrolytic hydrogen.

For the longer term, R & D opportunities exist in developing the reversible water vapour electrolyser/hydrogen-oxygen* fuel cell based on

It would operate on air in the fuel cell mode. - 39 -

ceramic hydrogen ion conductors as the solid electrolyte (63). In the electrolysis mode (DC power is applied), water vapour is electrolysed to give oxygen and hydrogen gas; in the fuel cell mcwle (DC power is obtained), hydrogen and oxygen (pure or from air) recombfine electrochemically to produce water vapour. An estimated 20-30 years of -sustained R.D&D is likely required for technical development to the industrial scale. Because this system can operate (63) at about 300°C, its materials problems are much more tractable than those of the earlier but competing systems based on ceramic oxygen ion conductors (64) operating at 800-1000°C.

Bench-scale work on the ceramic hydrogen ion conductors was initiated (63) in 1979 as a co-operative program between Queen's and McMaster Universities. A bench-scale fuel cell program, based on these same solid electrolytes, has been approved recently at the Canada Centre for Mineral and Energy Technology (CANMET) (65). These materials are fundamentally very interesting since they owe their high ion conductivities to three-dimensional tunnel structures (66). These solid electrolytes could be used in many other electrochemical devices, e.g., batteries and gas sensors.

The hydrogen-halogen energy storage system (67) is another example of a reversible electrolyser/fuel cell system for storing electricity as chemical energy. Chlorine and bromine were the halogens chosen (67). The auth- ors (67) claim that the hydrogen-chlorine system is developed to ihe point where it could be constructed "at the present time" (1979).

In the electrolysis mode (DC power is applied), hydrochloric acid (aqueous) is dissociated electrochemically into hydrogen and chlorine gas; in the fuel cell mode (DC power is obtained), chlorine and hydrogen gas re- combine electrochemically to produce hydrochloric acid (aqueous). The energy efficiency* of a 20 MW/200 MWh system consisting of ten 2 MW/20 MWh modules is 67% and the average calculated cost of the electricity produced is 6.5

The hydrogen-bromine system is not as well defined but has better potential. Laboratory data are needed such as bromine solubility in hydrogen bromide solutions at various temperatures and pressures (67). Also, the electrolysis cell for this system needs considerable R & D both at the bench and prototype scale. Such R & D may be justified for the following reasons:

(a) the energy efficiency is 70% and thus a little higher than that of the chlorine analogue;

(b) the system pressure is much lower (< 0.°»5 MPa) than that of the chlorine analogue, which is designed for 4.2 MPa.

* electric-to-electric - 40 -

Thus, capital costs are expected to be significantly lower and operation easier for the bromine relative to the chlorine system. The hydrogen-halogen reversible electrolyser/fuel cell systems appear to merit consideration as options for electricity storage devices for Canadian electric utilities. 10.3.4 Energy Conversion Options: The Direct-Fired Hydrogen Oxygen Superheater

The concept of a direct-fired superheater, which burns the electrolytic hydrogen and oxygen (not air), has merit as an efficient reconverter. In the scheme proposed by Combustion Engineering-Superheater Ltd. (59) steam from the nuclear steam generator is superheated by the combustion of hydrogen and oxygen which itself produces superheated steam. In effect, the outlet temperature of CANDU steam is raised from about 300°C to about 440°C, increasing the Carnot efficiency from 40% to 52%. Advantages and disadvantages claimed for such a scheme, in which the electrolysis plant operates 50% of the time (4000 h/a), are summarized in Table 10.3.2.1. The efficiency of energy recovery for the peaking operation is of the order of 70%.

The advantages appear to outweigh the disadvantages. Synergisms noted are: simultaneous by-product heavy water production with off-peak power, increased heat-to-electricity conversion efficiency, and load-levelling.

Two major areas requiring development are .. burner and the overall system chemistry of the light water steam cycle.

10.3.5 DC Power Supply: The Acyclic Generator

Water electrolysis plants require large direct electric currents (up to 100 kA per module) at low voltages (^500 VDC). Turbine-generator sets are usually designed to produce alternating currents that are relatively small at high voltages. What is obviously required for dedicated hydrogen production is a direct current (DC) generator with efficiency and cost characteristics similar to an alternating current (AC) generator. The AC to DC power conditioning hardware is thereby eliminated. This represents a significant advantage since this power conditioning hardware typically costs three times the generator cost and internal energy losses are 2 to 3% (66). However, conventional brush-commutator DC generators do not qualify for these reasons (68):

(a) their energy efficiency is lower (94-96% typical);

(b) their costs are as high as or higher than those of AC generators; (c) they are limited in size to about 10 Mw (electrical), mainly because of current density limitations at the brushes. - 41 -

Fortunately, the acyclic DC generator meets the basic requirements of efficiency and cost. Although it has been demonstrated in significant sizes, it has not achieved a full industrial-product status. The General Electric Co. (69) has perfected a liquid-metal (sodium-potassium eutectic alloy) current-collection system which is the key to a practical industrial machine. A 25 MW (electrical) acyclic generator of this type is installed in a special test facility at the US Air Force - Arnold Engineering Development Centre, Arnold Air Force Station, Tennessee (68). For an electrolyser plant, GE have projected an acyclic generator design that, when used in numbers, would meet both the available shaftpower condition and the electrolyser input requirements. Since large electrical conductors are required for the large OC currents, the acyclic generator should be as close to the electrolyser modules as possible. Water-cooled aluminum bus bars could be used. The largest power input for an acyclic generator which does not require superconducting field coils is 62.5 MW. The output is 250 kA at 250 V (4) and the conversion efficiency (excluding bus-bar losses) is 98 to 9955 for shaft power to electricity (70). Foh et al. (70) describe a system based on a high temperature gas cooled nuclear reactor with an electric output of 1080 MW. The reactor supplies energy to three helium gas turbines; each turbine in turn is connected to six 60 MW acyclic generators which supply DC power to electrolyser modules. Further development and field trials in industry in Canada seem justified in view of the potential advantages of the acyclic generator. Interesting synergistic effects are expected, especially in conjunction with liquid hydrogen production and superconductors. 10.4. Hydrogen Uses 10.4.1 Introduction The traditional chemical uses of hydrogen do not require major new R & D programs, but new applications of hydrogen, particularly those where hydrogen would be used as a fuel, require R & D for hydrogen systems appropriate to Canada and its climate. In this section, the prospects for R & D in old and new uses of hydrogen are discussed briefly. 10.4.2 Traditional Uses The scope for R & D in, for example, the manufacture of ammonia using electrolytic hydrogen instead of hydrogen derived from methane is limited to engineering and systems studies since the basic reactions are well known. However, if the required nitrogen is derived from an air separation plant, then the by-product oxygen will be five times larger with electrolytic - 42 -

hydrogen, namely, 0.5 moles per mole of ammonia instead of 0.1 as with fossil-derived hydrogen. This situation calls for prudent systems planning and favours the concept of an energy-chemicals park. Because natural gas reformers would not be required with electrolytic hydrogen, the flow sheet for ammonia manufacture would be quite different and may require pilot plant studies for optimization. Electrolytic hydrogen could be introduced into an existing ammonia plant on a partial basis with concomitant recovery of by-product heavy water from the fossi1-derived hydrogen as well as from the feed water for the electrolyser (32). As mentioned previously, R & D on the heavy water recovery system is being pursued (see Section 5.1.2). Hydrogen usage in reducing metal ores is not new although the reducing gas is usually a mixture of carbon monoxide and hydrogen which is produced by reforming natural gas. Note that hydrogen can act as a reductant as well as an energy carrier. Direct reduction of iron ores at Sidbec-Dosco's plant at Contrecoeur, Quebec, by the Midrex process (5) represents only a small fraction of the more common blast furnace operations. About 80% of the iron and steel industry in Canada is located in Ontario (71) and here coal, coke and coke oven gas are the chief energy sources for the conventional processes. The industry is of interest from the standpoint of energy substitution because of the large quantities of energy used. There is, therefore, very large scope for electricity in the iron and steel industry, both as a direct input and as electrolytic hydrogen. Also, large quantities of oxygen are used in steel making so that the prospect for use of the by-product oxygen is good. There- fore, this industry should be a prime target for serious consideration for electricity and hydrogen substitution of fossil resources. Credible cost analyses of new flow sheets is a necessary first step. These should take into account the economic benefit due to desulfurization with hydrogen, since this process emits zero sulfur dioxide in principle and negligible amounts in practice. Desulfurization with hydrogen produces hydrogen sulfide gas, which, although highly toxic, is more easily recovered and converted into innocuous elemental sulfur (5).

Opportunities for applied R fi 0, especially process design and materials, are expected. Application of the plasma torch to several steel making processes (72) would also require R & D. The plasma torch can, in principle, operate on any gas including oxidizing, reducing (e.g., hydrogen) or inert types, depending on the desired end result. Stelco in Hamilton (72) are interested in reducing the specific coke requirement in their blast furnaces. This would first be accomplished by heating natural gas in the plasma torch to supply heat (2000-2400°C) and carbon to compensate for missing coke (72). Direct reduction with hydrogen as the gas is an obvious next step. Direct reduction of sulfide ores in a single step would be much less complex than the current practice (5) of matting, convecting and electrolytic refining. However, direct reduction of sulfide ores is considerably more difficult than for oxide ores because the equilibrium pressure of hydrogen sulfide in hydrogen at typical reactor temperatures is less than 0.5% - 43 -

while the corresponding water vapour pressure is greater than 50% for oxide ores (5). As a result, large quantities of hydrogen gas would need to be re- circulated while only small quantities of hydrogen sulfide gas could be removed per pass. Thus, while direct reduction of sulfide ores has been demonstrated (73), there is a need for R & D. Experiments with the plasma torch discussed above may be particularly fruitful. Sherritt Gordon Mines Ltd. are using hydrogen derived from natural gas for pressure reduction of nickel, cobalt and copper solutions from which the respective metals precipitate out as fine powders (74). They used 26 Mm^ of hydrogen in 1980 which is expected co increase by 46% by 1990. Hydrometallurgical processes have fewer environmental problems than the more traditional pyrometallurgical processes. Therefore, R & D should be encouraged in this field in view of the potential competitiveness of electrolytic hydrogen. While the use of hydrogen in metallurgical processes is small today (see Fig. 2.1), this use sector is expected to grow dramatically over the time period being considered here. The iron and steel industry could very well be the "sleeper" among the potential users of large quantities of hydrogen. 10.4.3 New Uses Opportunities for new uses of hydrogen are greatest in the transportation sector. Direct or indirect (e.g., as ammonia) hydrogen substitution for oil products in transportation is important, since 44.4% of the oil demand in 1980 in Canada was consumed in this sector (75) (see Table 10.4.3.1). Also, hydrogen is the cleanest burning fuel for the internal combustion engine but hydrogen storage and distribution are major obstacles to overcome. The first application of hydrogen in road transportation will probably occur in fleet operations (trucks and taxis) where storage, distribution and handling problems are easier to overcome. The scope for substitution is large in these fleet operations alone since they consume about 60% of the total requirement for road transportation in Ontario (76).

Because of our cold winters, electric-battery vehicles are handicap- ped for the following reasons: (a) poor performance at low temperatures; (b) no by-product heat for vehicle interior. This could make hydrogen a more attractive means for substituting electricity in this sector for Canada. In Canada R & D in this sector needs to focus on hardware projects designed to demonstrate the technical and economic feasibility of using hydrogen relative to other options. Thus, the Urban Transport Development Corporation in Kingston, Ontario, is in the process of converting a diesel engine (100 h.p.) to hydrogen as part of its overall evaluation program on alternate fuels for transportation (76). It is possible that one or two - 44 -

prototype hydrogen transit buses will be tested under this program in Toronto in time for the 5th World Hydrogen Energy Conference, scheduled for 1984 in that city. Comprehensive testing and evaluation programs are required for technology developed outside Canada such as, for example, the Daimler-Benz car based on a metal hydride storage system (77), or the Japanese liquid hydrogen car (78). Mission oriented R & D is required for developing new hydrogen fuel cells as the power plants for electric cars. The reversible water vapour electrolyser/fuel cell, discussed in Section 10.3.3, could be such a Canadian development that has the potential to replace the internal combustion engines in road, rail and marine transportation. This would be a long-term option since the ceramic hydrogen ion conducting electrolytes, on which its operation depends, have only recently been discovered (79). A near option, which also requires dedicated R & D, would be the adaptation and scale-up of the Belgian low temperature alkaline fuel cell, discussed in Section 10.3.3. Note that both fuel cells could serve in either stationary or mobile applications, although the design parameters would be quite different.

The main advantages of fuel cells over internal combustion engines are

(a) higher energy efficiencies because fuel cells are not limited by the Carnot cycle as are heat engines; hydrogen to electricity conversion efficiencies of 50-60% have been achieved with the Belgian fuel cell (80); (b) no moving parts and therefore its operation is silent;

(d) the only emission is water since the operating temperature is too low for the formation of nitrogen oxides. These advantages provide the incentive for major R & D expenditures.

A disadvantage of the fuel cell for the car is its relatively poor performance for peak power. This problem may be solved with the hybrid battery-fuel cell electric car; the fuel cell meets the base power requirement for long range while the battery provides the peak power for accelera- tion. Considerable R & D is required to bring these concepts into reality.

Liquid hydrogen offers a viable long-term option to fossil-based aviation fuels. Comparison studies for both subsonic and supersonic aircraft have shown that the liquid hydrogen fuelled aircraft is "superior in almost every respect" (81) to the Jet A fuelled version. Table 10.4.3.2 provides a summary of significant data for a 400 passenger, 10,190 km range subsonic aircraft (81). Demonstration of the liquid hydrogen fuelled aircraft (LH2 aircraft) will likely occur as a result of a multinational co-operative - 45 -

effort (53) via the International Energy Agency, which will include Canada. Opportunities for R & 0 exist in providing the proper ground facilities for refuelling at one or more of the major airports. Such hardware as an appropriate pump for liquid hydrogen will have to be developed for a range of pumping rates. Liquid hydrogen is also the only form of hydrogen which is feasible for the trans-continental railway. Metal hydride storage is likely to be too costly and heavy relative to liquid hydrogen for long distances, although it may be a suitable method for inter-city railways which are within reach of a single hydrogen production plant. The conventional diesel-electric power system for locomotives could eventually be replaced by a silent fuel-cell- electric power system. Moving the railroads off oil and onto the hydrogen alternative is discussed in reference 82. Technical areas of uncertainty (82) with respect to the hydrogen-converted diesel engine are listed in Table 10.4.3.3. Appropriate R & D would eliminate these. There are only three companies (General Motors Corp., General Electric Co., and MLW Industries) which manufacture the diesel locomotives currently powering US and Canadian locomotives (82). Since MLW Industries is located in Montreal, Canada has a unique opportunity to participate. A joint US-Canada project to investigate alternative fuels for diesel in the "medium speed" category was therefore proposed (83), but this project excluded hydrogen. The Canadian Advisory Committee on Hydrogen (83), an ad hoc committee advising the then Minister (Hon. A Gillespie) of the Department of Energy, Mines and Resources, recom- mended that hydrogen be included. The need for R & D becomes apparent from the different characteristics of the fuels: gasoline, diesel oil and liquid hydrogen, listed in Table 10.4.3.4. Although hydrogen has about three times the gravimetric energy density of the other two fuels, it requires about four times the volume (as a cryogenic fluid). The extra volume required is not a serious drawback for the railway locomotive: the liquid hydrogen would be carried in a tender. Thus, liquid hydrogen offers a long-term option for indirect electrification of the railways in Canada which may be cheaper than direct electrification. An example of a new use of hydrogen outside the transportation sector per se is the concept of a catalytic recombiner for hydrogen and oxygen (air) to produce heat and water vapour (see Section 10.3.2). The catalyst, usually platinum or palladium, allows recombination without explosion and such a device has the advantage of liberating 100% of the energy (lower heating value if steam is not condensed) contained in the hydrogen fuel. Chalk River could play a significant role in the development of such a recorabiner for space heating because of the expertise in hydrophobic dispersed platinum catalysts for hydrogen isotope exchange (39). A hydrophobic catalyst is expected to have significant advantages in the present application over conventional hydrophilic ones. Adoption of this concept hinges on a satisfac- tory hydrogen distribution or storage system. The concept has merit as an option, not only for load-levelling at the municipal-electric-utility level (see Section 10.3.2), but also for space heating in apartment buildings, shopping malls, factories and schools. - 46 -

10.5 Hydrogen Storage and Transmission 10.5.1 Introduction Large users manufacture their own hydrogen at the rate at which it is used for the production of some other chemical, e.g., ammonia and methanol. This avoids the cost and danger of storing large quantities of hydrogen. Transmission is by flow through pipes. For smaller users, hydrogen is most often stored as a gas at pressure. Transmission is by hauling gas cylinders or in tube trucks. Hydrogen is also stored as a cryogenic liquid for space applications, such as the Space Shuttle. Transmission from the producer's site to the user's site is by transport trailer (84). In the future, hydrogen could also be stored as a metal hydride or as a liquid hydride, such as ammonia. Underground storage in natural caverns is also a possibility for large bulk storage. Research and development opportunities in these new methods are briefly examined. 10.5.2 Metal Hydrides The exploitation of hydrogen as a fuel for road transportation requires a method for storing it safely and compactly. One of the safest methods for storing hydrogen (85, 86) is as a metal hydride. Daimler-Benz have advanced this approach further than any other automobile manufacturer (77). Thus, they are testing 30 Mercedes-Benz vans purely on hydrogen and 11 cars using hydrogen (for town driving) and gasoline (for highway driving) alternately (87). Hydrogen storage is by metal hydrides (77, 87) in all cases. The technology is advanced to a remarkable degree as is the overall systems planning. For example, in the 30 vehicle test in Berlin, the hydrogen is taken from the existing town gas (a mixture of mainly carbon monoxide and hydrogen) by pressure swing absorbers (87). Cars can apparently be refuelled in 10 minutes and vans in 1 to 10 hours. Although the above achievements are impressive, metal hydrides have the following disadvantages: (a) they have a low energy density (88) on a weight basis relative to gasoline (see Table 10.5.2.1) even though on a volume basis some metal hydrides contain more hydrogen than liquid hydrogen itself (see Table 10.5.2.2.); (b) the rate of absorption may be affected by small amounts of impurities, e.g., oxygen; (c) they have a tendency to spall upon repeated absorption-desorption and the resulting fines can cause excessive pressure drops; - 47 -

(d) they are more expensive than the gasoline tank. The data of Table 10.5.2.1 show the superiority of gasoline for storing energy over the other fuels considered. If the container is included, hydrogen stored as a liquid holds more energy on a volume and a mass basis than hydrogen stored as a light-metal hydride: both have energy densities about three to four times poorer than gasoline. Metal hydrides containing a heavier metal, e.g., nickel, have still smaller energy densities (see item 5, Table 10.5.2.1) than the light-metal hydrides.

In spite of these drawbacks, metal hydrides have attracted development effort for both mobile and stationary application (89). For mobile applications, the concept of the hybrid hydrogen-gasoline car (77, 87) alleviates some of the present problems and would allow for an orderly transition to a new technology. If the hybrid system is operated on a mixture of hydrogen and gasoline, the thermal efficiency of the engine increases substantially when compared to gasoline alone (90)! This is another example of a synergistic effect caused by the use of hydrogen.

The iron-titanium hydride system has been tested on an engineering scale at the Brookhaven National Laboratory in cooperation with the Public Service Electric and Gas Company of New Jersey for production of peak electric power (89). The basic system consisted of a water electrolyser, a hydride storage vessel and a fuel cell. The concept of storing electricity by the production, storage, and reconversion of hydrogen has thus been demonstrated and a preliminary design of a 26 Mw (electric) peaking plant has been completed (91).

Another stationary application of these materials is the hydride compressor (4). Such a compressor has no moving parts, requiring only heat exchange for the hydrogen absorption and desorption processes. It could replace mechanical compressors for hydrogen pipelines, etc.

Continued R & D on metal hydrides is justified for the following reasons: (a) although metal hydrides are inferior to gasoline, they have better potential than batteries (92) as power sources for road transportation as Table 10.5.2.3 illustrates;

(b) there are potential stationary applications for storing hydrogen as metal hydrides in which their low energy densities are not a serious drawback;

(c) the concept of the metal hydride compressor deserves serious consideration since it could be a vary reliable device, especially with electrolytic grade hydrogen; - 48 -

(d) the kinetics of hydrogen absorption in metals and alloys, and a study of the consequences on mechanical properties is important in materials research not only in hydrogen systems but also in general; (e) the mechanisms of poisons for the hydrogen adsorption reaction need to be understood so that charging times can be as short as possible and maintained for many charge-discharge cycles; (f) tritium storage by metal hydrides is already important for fission nuclear reactors and fuel reprocessing: it will become even more important for nuclear fusion reactors. With appropriate R & D it should be possible to tailor the metal hydride properties to a particular application. 10.5.3 Liquid Hydrides A chemical such as ammonia can be considered a liquid hydride for these reasons: (a) ammonia, although a gas under standard conditions of temperature and pressure, is easily liquefied; (b) ammonia can be "cracked" over a catalyst at ^ 700°C to release hydrogen (93). Liquid hydrogen itself can be considered a liquid hydride as can methanol. Another liquid source of hydrogen is methyl cyclohexane (94) which can undergo the following reaction: dehydrogenation [10] Methyl cyclohexane(liquid) g. ' **" Toluene(liquid) + Hydrogen(gas) hydrogenation This is an example of a recyclable liquid hydrogen carrier. The dehydrogenation reaction requires a catalytic reaction at 300°C (94). Its main advantage is that hydrogen can be stored at ambient conditions, but the hydrogen storage capacity is only 6.1% by weight which results in a 5.3 weight ratio of methyl cyclohexane to gasoline (compare with Table 10.5.2.1). A regional hydrogen filling station for about 10,000 people (1000 cars) where the toluene is hydrogenated has been considered in conjunction with district heating. Thus, for such a station a 6 MW (electric) electrolysis plant (operating eight hours during the night) and hydrogenation plant for producing 18.5 tons of methyl cyclohexane per day cculd supply about 73 GJ (thermal) per day at 200°C for district heating (94), since the hydrogenation reaction is exothermic. This heat originated largely from the exhaust gases of the cars (94) which supply the heat required for the dehydrogenation reaction. Because the electrolysis plant uses off-peak power and there is a substantial credit for district heating, this hydrogen storage and distribution concept is considered to be competitive (94) for Switzerland with gasoline at - 49 -

0.4 Swiss francs per litre.* The catalyst for the on-board dehydrogenation reaction requires a lot more development (94) to increase its lifetime and reliability. Ammonia and methanol production are well established but the application of these in road transportation requires continued R & D in safety and handling procedures. The concentration levels of nitrogen oxides formed when hydrogen is burned with air in an internal combustion engine are below the limits now mandatory in the US (93). However, it is possible that these emission levels could be lowered further with appropriate R & 0 on engines and fuel-feed systems. Development of a hydrogen storage system for the automobile which contains at least 10% by weight of usable hydrogen** is considered feasible but remains to be achieved. In general, distribution of methanol, ammonia or methyl cyclohexane/ toluene requires no new technology. Among these, ammonia is considered to be the leader at present (93) when all factors are taken into consideration. 10.5.4 Underground Storage Underground storage of hydrogen appears to be the best way of storing large amounts of hydrogen energy, such as may be produced for seasonal load- levelling by a large electric utility. Facilities for underground storage of gases fall into two categories: (a) porous media storage, e.g., sandstones or porous carbonates; (b) cavern (natural or man-made) storage. Most underground storage of natural gas occurs in category (a), either in partially depleted oil or gas fields or in aquifers (95). Natural gas is also stored in solution-mined salt caverns. Typical storage pressures (95) for natural gas are 7 to 14 MPa. Fob et al. (95) have taken into account the different properties of hydrogen relative to natural gas in their analysis of underground storage of hydrogen. They concluded that: "There appear to be no major gaps in either technology or operational procedure for underground hydrogen storage (except, perhaps, for unspecified material for very high-pressure storage fields)." However, because of the different volumetric heating values and compressibilities of natural gas and hydrogen, the total energy throughput of hydrogen service is a factor of two to four lower than for natural gas service. Imperial Chemical Industries at Teesside in England are operating solution-mined salt caverns for storing 95%

* excludes all taxes; one Swiss franc is equal to about 67 cents (mid-rate as of December 31st, 1980). ** based on the weight of the fuel storage system on-board. - 50 -

purity hydrogen (96) at a nominal pressure of 5 MPa. Three caverns are operated in a "wet" mode using saturated brine. The brine from these caverns is displaced by pressurized hydrogen and is stored in surface ponds until needed to displace the stored hydrogen. Brine from the ponds is then pressurized to a level slightly above the pressure of the stored hydrogen. The storage system can operate on a pressure differential of 0.4 MPa in addition to the static head of the brine, due to the depth below the surface of 365 m. To prevent additional leaching of the salt caverns, the brine is maintained at the saturated level and its temperature is controlled to ensure the cavern walls are not subjected to thermal shock. The above brine-compensated storage mode for bulk hydrogen has the following advantages over the conventional method: (a) the necessity of a base gas to provide the reservoir pressure is largely eliminated; (b) the reservoir can be operated at a constant pressure, which simplifies above-ground facilities; (c) the problems of mixing with another gas in the reservoir are eliminated. However, the cost of removing and injecting brine into the caverns is an additional cost not applicable to the conventional mode. Suggested (95) R & D includes: (a) hydrogen environment embrittlement studies on selected materials in the pressure range 7 MPa to 35 MPa; (b) possible effects of potential "odorants" and "colorants" on embrittlement or reactions with reservoir minerals; (c) studies to determine how much natural gas can exist in a predom- inantly hydrogen system for hydrogen burners to function safely and efficiently: up to 20% hydrogen in nat : al gas is suitable for methanol burners; (d) a comparative cost analysis of the "wet" salt cavern brine- compensated storage mode (96). 10.5.5 Other Hydrogen Storage Methods Hydrogen storage in glass microspheres (^40 um in diameter) for automotive applications (97) is a relatively new method for storing hydrogen. However, they are presently too bulky and thus range-limited for mobile applications (93). They may prove to be suitable for stationary applications. Glass microspheres are cheaper than metal hydrides and are available commercially (97). Research and development of this storage method is required to increase the hydrogen content per unit volume and unit weight and to demonstrate the concept on a pilot-plant scale. - 51 -

Hydrogen storage by the use of cryoadsorbents (sea Table 10.5.5.1) in the temperature range 65 to 150 K has been studied on the bench-scale (98). Hydrogen storage capacities under isothermal conditions of 4 to 5.2% on adsorbent mass basis were measured: these are comparable to those of some of the metal hydrides (see Table 10.5.2.2). The concept has potential for stationary applications but is not very practical for mobile ones except in conjunction with liquid hydrogen storage. Here, the cryoadsorbent could be used to minimize losses due to boil-off. Cryoadsorbers are expected to be competitive with other hydrogen storage alternatives for daily and weekly storage at an electric utility, for example. The storage efficiency is about 91 to 97% on an energy basis depending on the temperature of the cryoadsorber (98). p development work is required as well as basic studies. The latter include: (a) the kinetic behaviour of non-isothermal hydroqen discharge behaviour at higher temperatures (up to 140 K from 78 K); (b) the determination of the factors which influence the amount and rate of adsorption of hydrogen on activated carbon powders. 10.5.6 Transmission Bulk transmission of gases is routinely accomplished using pipelines. Experience with hydrogen transmission in small pipelines is summarized in Table 10.5.6.1. The footnote in Table 10.5.6.1 raises the interesting question of whether "pure" hydrogen is more likely to cause hydrogen embrittlement than "dirty" hydrogen. According to Leeth (100), "almost all of the observed hydrogen embrittlement has involved very pure hydrogen". This could be of special concern in the context of electrolytic-grade hydrogen although Leeth states that "small amounts of oxygen, carbon monoxide and other gases are effective in inhibiting hydrogen embrittlement" under pipeline conditions. Fundamental surface and near-surface chemistry is required to eluci- date the appropriate rate constants for hydrogen sorption into the pipeline materials. Since embrittlement failures have usually been associated with welds, studies at and around welds are particularly important.

Comparative transmission costs for natural gas versus hydrogen are given in Table 10.5.6.2 from three different sources. The Institute of Gas Technology computations are high because the cost of the hydrogen (assumed to be electrolytic) used to drive the compressors was five to ten times higher (100) than that assumed by the General Electric and EURATOM people. In general, hydrogen transmission costs about 1.5 times as much as natural gas, where the pumping energy costs are the same. Hydrogen also requires about 1.5 times the pumping power of natural gas. For a minimum cost hydrogen pipeline at 10 TJ/h (1013J/h), about 0.5% of the energy flow is required for pumping for pipelines long enough to utilize fully at least one compressor station. - 52 -

The above calculations have not considered the potential reduction in hydrogen pumping costs via the concept of the metal hydride compressor {see Section 10.5.2). 10.6 Materials Research Research and development of materials suitable for use in hydrogen environments has been mentioned in several of the above sections in this chapter. Hydrogen embrittlement is an especially difficult phenomenon to quantify for any given material and use conditions. The usual thermodynamic and diffusion relations cannot predict accurately the final distribution of hydrogen and the kinetics of the processes (101) involved. This is so because hydrogen permeation is significantly influenced bv surface conditions, particularly oxide films, and internal defects and impurities that trap dif- fusing hydrogen (101). Since it was discovered about 100 years ago that hydrogen can drasti- cally reduce the strength and ductility of steel (102), substantial phenome- nological knowledge about hydrogen embrittlement has been acquired and has been extended to many other types of materials (102). In the oarne period, many industrial failures have been traced to the effects of hydrogen (102). Failure is often catastrophic because it occurs at an unexpectedly low stress relative to behaviour in the absence of hydrogen (and it has an unpredictable and highly variable incubation period for reasons given above). Behaviour of this type in a structural material can obviously lead to catastrophic failures. For example, a hydrogen pressure vessel*, which had been in service for 12 years at 10 MPa, burst and caused an estimated $4 million damage (102). Such failures must clearly be avoided in any material which will be exposed to hydrogen be it a transmission line, a valve, or a compressor, etc.. While there is already a great deal of information, albeit largely empirical, on the hydrogen embrittlement phenomenon, it is clear that continued R & D is vital especially for new systems designed to operate at higher stress levels. The German experience in transmitting hydrogen gas without incidents for 30 years at 1.8 MPa (see Table 10.5.6.1) is really not relevant to a long distance hydrogen pipeline which must operate at pressures of at least 14 MPa** for cost equity with a natural gas pipeline (102). Such pressures require care in choice of steels (102). This can be done as illu- strated below, in spite of the fact that recent experiments at ambient temperature at hydrogen pressures up to 69 MPa indicate that, of some fifty structural alloys tested, all show evidence of susceptibility to hydrogen embrittlement (101). It would be attractive to have a non-destructive means of in-service inspection, or better continuous monitoring, to detect the onset of hydrogen embrittlement. This might be an area for fruitful R & D and nuclear analytical techniques could be important.

* 1.85 m in diameter, 6.75 m long, with a 5 cm thick wall made from ASTM A517-F steel. ** This is about double that for existing natural gas pipelines. - 53 -

The present state-of-the-art in high pressure hydrogen gas storage and transmission is represented by the following installation. Rocketdyne Division of Rockwell International are operating a rocket engine test stand for hydrogen fuel at Santa Susana, California. At this facility, hydrogen gas at about 100 MPa is stored in stainless-steel-1 ined steel vessels and transmitted in "21Cr-6Ni-9 Mn" stainless steel pipes (two) to the test stand. Metering and control valves are stainless steel. Material costs are at least a factor of five higher relative to conventional linepipe steel (102).

Research, development and, above all, demonstration under actual use conditions are required in materials selected for any hydrogen gas application at high pressures but ambient temperatures, at moderate to high pressures at elevated temperature, e.g., moving compressor parts, and at all pressures at high temperatures. the concept of replacing stainless steel liners with low cost plastic liners for ambient temperature applications should be fully explored for storage vessels and pipes. If liners are not used, particular attention must be paid to all aspects of the welding process since failures have often occurred at or in regions adjacent to welds (102). If liners are used, appropriate measures must be developed, and applied to ensure integrity of the liner. Quality assurance is important in all aspects of hydrogen service and it may even be necessary to revise the ASME Pressure Vessel Code (102).

With respect to handling hydrogen as low-pressure metal hydrides, R & D should be encouraged to study possible effects at the hydride-contain- ment interface where the possibility exists of hydrogen atom transfer even at room temperatures.

For liquid hydrogen service, the technology for storage and handling is well established (84). Fortunately, at cryogenic temperatures no hydrogen embrittlement is observed (102). Therefore, as long as hydrogen effects during ambient temperature excursions are allowed for and controlled, e.g., by reducing the pressure as the temperature is increased, no hydrogen damage is expected in liquid hydrogen systems.

10.7 Other R & D Needs Prior to implementation of any hydrogen system technology, there exists the need for research effort in areas and disciplines other than those dealing with hardware developments. These areas and disciplines are listed in Table 10.7.1.

Where information already exists, e.g., safety codes for use of hydrogen, this needs to be reviewed and updated as new hydrogen technologies are developed.

Where the information originates in a foreign country, it should be reviewed and changed appropriately to meet Canadian needs. For example, Hord (103) has reviewed hydrogen safety regulations, codes and guidelines for the US. Similarly, Zweig (104) has considered the possible health benefits which would be derived from a planned hydrogen-electric community. His study - 54 -

includes health benefits based on data from the Riverside, California, Air Pollution Abatement Program (104). 10.8 Summary and Conclusions Opportunities for research, development and demonstration are summarized in Table 10.8.1. The present status in Canada of each hydrogen-technology item is indicated for the three types of research activities, namely, (a) Basic Research; (b) Development (including pilot plants); (c) Demonstration (projects suitably scaled-up for commercial use). Whether Canadian effort is required or not is also indicated. The requirements for research indicated in Table 10.8.1 are based on the following assumption: Canada will require hydrogen technologies beginning in the last decade of this century for chemical uses of hydrogen and in the first decade of the next century for fuel uses of hydrogen. For some hydrogen-technology items no basic research is indicated, but only in the sense that these items have been demonstrated at the bench- scale. Basic research is required in nearly all hydrogen technologies to advance our knowledge and understanding. Canadian hydrogen-hardware items, which are technologically feasible and probable by the year 2025, are summarized in Table 10.8.2. This list is not necessarily complete, nor is it intended to indicate only committed projects. Of the hydro gen-hardware items listed in Table 10.8.2, R & D is currently going on in items 1, 2, 3, 5, 10 and 14; in all cases the level of effort would need to be increased significantly to meet the time objectives indicated. Hydrogen-hardware items which have particular relevance for Canada, where electrolytic-grade hydrogen could be available, are: (a) the Belgian alkaline fuel cell (suitably adapted for Canada's climate) for road transportation; (b) the phosphoric acid fuel cell for stationary application but without the present fossil fuel (e.g., naphtha) reformer system to produce the hydrogen; - 55 -

(e) the direct-fired hydrogen-oxygen superheater as a topping cycle for the CAMDU reactor and other steam sources. The alkaline fuel cell could displace a significant fraction of the oil now used in road, rail and marine transportation by 2025.

The metal hydride compressor, with no moving parts, is an exciting concept which should be developed in Canada as quickly as possible, not only for national use, but also for the world market.

The Carnot efficiency for the conversion of nuclear steam at 300°C to electricity could be increased from 40% to 52% at 440°C with the direct-fired hydrogen-oxygen superheater. An increase in the real efficiency of about eight percentage points, i.e., from 29% to 37% is anticipated, which would probably give rise to a very large benefit-to-cost ratio.

On-board hydrogen-storage systems for road transportation remain to be developed. Sustained R & D is deemed necessary for this key element.

Research on better batteries suitable for a hybrid battery/fuel cell electric car should be encouraged. Many hydrogen energy systems possess synergisms, which are not always apparent at first glance. Those must be included, even in first-round systems analyses and cost estimates.

Hydrogen usage in metallurgical processes, including hydrometallurgical ones, offer the potential for substituting indigenous electricity for foreign coal in, for example, steel making.

"There appear to be no major gaps in either technology or operational procedure for underground hydrogen storage (except, perhaps, for unspecified material for very high-pressure storage fields)" (see reference 94).

Materials research for understanding and preventing hydrogen ernbrit- tlement in structural alloys is extremely important. Hydrogen embrittlement has not been observed at cryogenic temperatures; R & D may show why this is so.

Nuclear analytical techniques may be appropriate for non-destructive in-service testing for the onset of hydrogen embrittlement. The ASME Pressure Vessel Code may require revision for hydrogen service. - 56 -

Needs exist for non-hardware projects, such as cost-benefit analyses, environmental impact studies, safety analyses and quality assurance procedures (see Table 10.7.1).

11. CONCLUSIONS

11.1 Prospects for Electrolytic Hydrogen The most important conclusion of this work is that the long-term prospects for electrolytic hydrogen are good in Canada. The projected demand is between 30 Qn^/a and 100 Gm-Va by the year 2025, starting from practically zero in 1985. These estimates assume electrolytic hydrogen is used as a fuel by 2025 to replace about 50,000 bpd and 200,000 bpd of oil, respectively, on an energy equivalent basis. Even if it is assumed that electrolytic hydrogen will only be used as a chemical in the traditional indirect energy and non-energy uses (see Fig. 2.1), the projected demand in 2025 would still be between 24 and 64 Qm^/a.

11.2 When Will Electrolytic Hydrogen Be Competitive? Another major conclusion of this work is that it is only a matter of time before electrolytic hydrogen will be competitive. Just when depends on electric energy costs relative to those for fossil fuels and for hydrogen derived from them. These costs will obviously vary from region to region in Canada but it appears that tne two most populous provinces, Ontario and Quebec, will be among the first to implement electrolytic hydrogen for three reasons:

(a) Both provinces now rely on natural gas that has to be transported from the western provinces for their hydrogen needs.

(b) Neither province has access to low-cost indigenous coal supplies. (c) Both provinces have access to inflation-resistant electricity generating capacity in the form of nuclear or hydroelectric resources. Based on the cost projections (see Chapter 6) for hydrogen production from the three important processes, namely, coal gasification, steam reforming of natural gas and electrolysis of water, electrolytic hydrogen begins to compete as a chemical in 1985 and as a direct fuel in 2003 (see Chapter 7). These dates are of course sensitive to the assumptions made with respect to the costs of fossil fuels relative to electricity. For example, with the recent cost projections (50) from the Department of Energy, Mines and Resources of 2%/a real escalation for oil and 0.6%/a real escalation for electricity, electrolytic hydrogen would still be competitive by the mid-1990's in the chemical applications. - 57 -

11.3 Implications for the Mater Electrolyser Industry The projected demand for electrolytic hydrogen of between 30 Qn3/a and 100 Gm-fya in 2025 would transform the water electrolyser industry in Canada from its present relatively small size to a multi-billion dollar business. To meet the above demand, the present electrolyser capacity, which has an estimated (4) production rate of about 2 x 10"3 Gm3/a, would have to be expanded by a factor of about 20,000. Major expansion is estimated to begin in 1985 at the earliest. The projected growth rate over the forty year period (1985-2025), although large, is considered to be practical.

Electrolyser capacity of between 19 GW and 65 GW is required to meet electrolytic hydrogen demands between 30 Gm3/a and 100 Grvfya, assuming an average plant capacity factor of 0.8 and a single cell voltage of 1.9 V. The successful Canadian unipolar water electrolyser technology, which is being improved and scaled-up (16), is expected to meet the technical and economic requirements of the 100 MM - 1000 MW electrolyser plants that are needed to satisfy the projected demand. A new company, Electrolyser Inc., has already been formed to market the Canadian "1981" and "1983" improved unipolar water electrolysis technologies not only in Canada but also internationally. A commitment for a 100 MW demonstration plant in Canada is expected before 1985 (4).

11.4 Implications for the Electric Utilities To produce electrolytic hydrogen at annual rates of 30 Gm3/a to 100 Gm3/a by 2025 requires additional electricity generating capacities of 24 GW and 80 GW, respectively, assuming an average capacity factor of 0.65 (9), or 20 GW and 65 GW, respectively, assuming an average capacity factor of 0.8. The larger average capacity factor of 0.8 is justified if hydrogen is produced during off-peak periods. These generating facilities compare with the 71 GW existing in Canada (3) in 1979. Expansion of the electricity generating capacity to meet the extra demand from electrolytic hydrogen production facilities is feasible within the given time frame.

11.5 Opportunities for Other Industries Opportunities for growth in Canada's other industries (apart from the water electrolyser industry) and the construction industries would result from the appropriate expansion of the electricity generating capacity.

Further opportunities for other industries can be expected at about the turn of the century if R & D on hydrogen storage, utilization, and safety is successful. These opportunities could become substantial if, for example, hydrogen were able to penetrate the transportation sector.

11.6 Heavy Water and Oxygen By-Products The potential for producing heavy water as a by-product of electrolytic hydrogen production is significant. For example, about 2,400 tonnes of - 58 -

reactor grade (99.8%) heavy water could be recovered annually from 30 &n3/a of electrolytic hydrogen. This compares with the 1980 committed heavy water production capacity of about 2,200 tonnes per annum.

Heavy water rep-esents such a small fraction of the corresponding hydrogen and is valuable enough that transportation costs are not important. Therefore, this by-product is in principle realizable at any large electrolytic hydrogen plant.

By contrast, the oxygen by-product credit is site-specific since transportation costs are significant. For this reason, production of electrolytic hydrogen in an integrated industrial energy-chemicals park is a likely development. Each by-product has the same net value of $1.25/GJ of electrolytic hydrogen produced, for a combined sum of $2.50/GJ.

11.7 Hydrogen as a Fuel The hydrogen fuel option based on nuclear electricity is not limited by the primary energy source.

The present analysis shows (see Chapter 7 and Section 9.3) that it is technically, economically and practically feasible to supply the equivalent of 50,000 to 200,000 bpd of oil with electrolytic hydrogen by the year 2025 in fuel applications. Technology for storage and distribution of hydrogen is lacking as is technology for mobile use. However, when hydrogen is used as an indirect fuel, for example methanol, some end-use problems are solved.

Cost estimates for electrolytic hydrogen, including the net heavy water by-product credit, are equivalent to crude oil prices of $40 to $63 per barrel. Natural gas is seen as the main competitor to electrolytic hydrogen in fuel applications in Canada.

11.8 Overall Conclusions Electrolytic hydrogen has the potential to become an important energy carrier in Canada for renewable hydro and virtually inexhaustible nuclear electricity. The orderly transition from an energy economy mainly based on fossil resources, especially oil (10), to an electric-hydrogen economy could begin in this century but will take the next century or more to complete.

Because of Canada's availability of relatively low cost hydro and nuclear electricity, electrolytic hydrogen could compete with hydrogen derived from fossil resources as early as 1985. Therefore, the prudent energy strategy for Canada is quite different from that of the United States of America where electricity prices are generally much higher. - 59 -

Adoption of the electrolytic hydrogen option as early as possible on a realistic scale would conserve our fossil resources, decrease our depend- ence on foreign oil, reduce sulfur dioxide and carbon dioxide emissions, create jobs in secondary industries and stimulate the concept of the industrial energy-chemicals park. It could also make us a world leader in certain hydrogen technologies. Economic and technological uncertainties relate primarily to the utilization, rather than the production of hydrogen. Exploitation of the full potential of hydrogen will require new technology, notably for storage, utilization and reconversion to electricity, but also for many aspects of handling and distribution. Extensive R & 0 will be necessary to provide the new technology. This should include safety-related studies as for any other fuel. It is time to start making choices and "placing bets" (69) in those hydrogen technologies most appropriate for Canada. Hydrogen derived from water is the near-perfect energy currency for all our energy transactions, except for the direct uses of electricity, in the post fossil fuel era because mother nature recycles the product of combustion as rain and sometimes as snow in Canada.

12. ACKNOWLEDGEMENTS It is a distinct pleasure for the author to thank Mr. A.K. Stuart and Dr. R.L. LeRoy for many helpful discussions about the Canadian unipolar electrolyser technologies in particular and hydrogen in general. The construc- tive criticisms by Dr. J.B. Taylor of the final draft are gratefully acknowl- edged. The author owes much to Messrs. J.A.L. Robertson and J.G. Melvin for their guidance, encouragement and many helpful suggestions throughout the course of this work. He is also indebted to Dr. D.P. Jackson, not only for the computer calculations and graphs, but also for his sincere interest.

13. REFERENCES

1. International Energy Agency Report, "Assessment of Potential Future Markets for the Production of Hydrogen from Water", (Consolidated Final Report prepared by the Commission of the European Communities, Joint Research Centre), September 1980. 2. Statistics Canada, "Quarterly Report on Energy Supply-Demand in Canada", Cat. 57-003, 1978-IV, 1978. 3. Department of Energy, Mines and Resources, "Electric Power in Canada: 1979", Report ER-80-7, 1980. - 60 -

4. A.K. Stuart, private communication.

5. R.L. LeRoy, The Metallurgical Society of CIM, Annual Volume, 1978, p.l.

6. T.H. Lefebvre (Chairman), "Energy Alternatives", Report of the Special Committee on Alternative Energy and Oil Substitution to the Parliament of Canada, (Available from the Department of Supply and Services, Ottawa, Cat. No. XC 2-321/2-01E), 1981.

7. A.C. Johnson, Chairman, Ontario Hydrogen Energy Task Force, private communication.

8. J.B. Taylor, Chemistry in Canada, 33(2), 18 (1980).

9. J.G. Melvin, Atomic Energy of Canada Limited, Report No. AECL-7067, September 1980.

10. R.S. Dixon, Atomic Energy of Canada Limited, Report No. AECL-6807, December 1980.

11. G. Lunin, A.E. Silva and J.M. Denis, Chemistry in Canada, 33(3), 17 (1981). •

12. B. McLaughlin, private communication.

13. C. Jackson, in "Industrial Electrochemical Processes", ed. A.T. Kuhn, Elsevier Publishing Co., N.Y., 1971, p. 159.

14. M. Hammerli, Atomic Energy of Canada Limited, Report No. AECL-7682. May 1982. 15. R.L. LeRoy and A.K. Stuart, in "Industrial Water Electrolysis", eds. S. Srinivasan, F.J. Salzano and A.R. Landgrebe, The Electrochemical Society, N.J., Vol. 78-4, 1978, p.117.

16. R.L. LeRoy and A.K. Stuart, in "Hydrogen Energy Progress", eds. T.N. Veziroglu, K. Fueki and T. Ohta, Pergamon Press, N.Y., Vol. 4, 1981, p. 1817.

17. S. Srinivasan, F.J. Salzano and A.R. Landgrebe, eds., "Industrial Water Electrolysis", The Electrochemical Society, N.J., Vol. 78-4, 1978.

18. A.A. Strub and G. Imarisio, eds., "Hydrogen As An Energy Vector", D. Reidel Publishing Co., Holland, 1980.

19. K. Darrow, N. Biederman and A. Konopka, Int. J. Hydrogen Energy, ?., 175, (1977).

20. M.R. Yaffe, Brookhaven National Laboratory Report No. BNL-51276, April 1980. - 61 -

21. Supplement to the Bank of Montreal Business Review, September, 1979, p. 8. 22. Ontario Hydro, "Direct Customer Rates" for 1980. 23. A.J. Petrella, Ontario Hydro, private communication. 24. F. Lacas, private communication. 25. K.E. Johnson and A. Verma, Proceedings of the 15th Intersociety Energy Conversion Engineering Confe>ence5 Vol, XXII, 2015 (1980). 26. R.I. Berry, Chemical Engineering, 87(4), 80 (1980). 27. J.H. Russell, in "Hydrogen Energy Progress", eds. T.N. Veziroglu, K. Fueki and T. Chta, Pergamon Press, N.Y., Vol. 1, 1980, p.3. 28. M. Haminerli, J.P. Butler and W.H. Stevens, Int. J. Hydrogen Energy, ±, 85 (1979). 29. J.W. Hilborn, J.S. Glen, W.A. Seddon and A.G. Barnstaple, Atomic Energy of Canada Limited, Report No. AECL-7066, August 1980. 30. M. Hammerli, W.H. Stevens and J.P. Butler, "Separation of Hydrogen Isotopes" ed. H.K. Rae, American Chemical Society, Symp. Series No. 68, 1978, p. 110. 31. M. Hammerli, Int. J. Hydrogen Energy, 5_, 409 (1980). 32. K. Harmerli, R.L. LeRoy, J.P. Butler and A.S. Denovan, Int. J. Hydrogen Energy, 6_, 167 (1981). 33. H.K. Rae, "Separation of Hydrogen Isotopes", ed. H.K. Rae, American Chemical Society, Symp. Series No. 68, 1978, p.l. 34. J.P. Butler and M. Hammerli, US Patent No, 4,190,515, February 26, 1980. 35. M. Hammerli and J.P. Butler, US Patent No. 4,191,626, March 4, 1980. 36. M. Hammerli, J.P. Mislan and W.J. Olmstead, J. Electrochem. Soc. 117, 751 (1970). 37. J.P. Butler, J.H. Rolston and W.H. Stevens, "Separation of Hydrogen Isotopes", ed. H.K. Rae, American Chemical Society, Symp. Series No. 68, 1978, p. 93. 38. W.H. Stevens, US Patent No. 3,888,974, 1975. 39. J.P. Butler, Separation Science and Technology, 15(3), 371 (1980). - 62 -

40. R.M. Brown, E. Robertson and W.M. Thurston, Atomic Energy of Canada Limited, Report No. AECL-3800, Janaury 1971. 41. Anon, Nucleonics Week, 18(12), 11 (1977). 42. R.-L. LeRoy, private communication. 43. "Electrolytic Hydrogen/Heavy Water Study: Report of the Project Manager and Economic Analysis". An assessment carried out by TransCanada Pipe Lines (project manager), the Province of Manitoba and Atonic Energy of Canada Limited, August 1979. (Available from Atomic Energy of Canada Limited, Chalk River, as AECL-MISC(CAN) 209 (unpublished report)). 44. D.P. Burke, Chemical Week, 127(2), 18 (1980). 45. R. Wuensche, 29th Annual Meeting of the Petroleum Society of CIM, Calgary, June 13-16, 1978, Paper No. 78-29-44. 46. The National Energy Program, Energy, Mines and Resources, Report EP-80-4E, 1980 (Cat. No. M23-12/80-4E). 47. Discussion Paper on Liquid Fuel Options, Energy, Mines and Resources, Report EP-80-2E, 1980 (Cat. No, M23-12/80-2E). 48. R.E. Green and R.M. Williams, Atomic Energy of Canada Limited, Report No. AECL-6963, April 1980. 49. P.S. Bailey, International Energy Agency Report, "Assessment of Potential Future Markets for the Production of Hydrogen from Water in Canada", Second Draft Final Report, 1980. 50. Department of Energy, Mines and Resources, "Nuclear Policy Review: Background Papers", Report No. ER81-2E, 1980. 51. E.A. Symons and A.I. Miller, Atomic Energy of Canada Limited, Report No. AECL-7258, March 1981. 52. "Potential for the Utilization of Hydrogen in Ontario Refineries", Draft Report for the Ontario Hydrogen Energy Task Force by the Ontario Petroleum Association, Toronto, dated 1981 February 4. 53. J.B. Taylor, private communication. 54. A.R. Bancroft, private communication. 55. B.W. Wojciechowski, Hydrocarbon Processing, 58(7), 105, (1979). 56. B.W. Wojciechowski, Hydrocarbon Processing, 59(7), 153 (1980). 57. J. Fischer, H. Hofmann, G. Luft and H. Wendt, AIChE Journal, 26(5), 794 (1980). —— 58. A. Teitsma, M. Sayer, S.L. Segel and P.S. Nicholson, Materials Research Bulletin, K3» 1611 (1980). 59. F.W. Hochmuth, private communication and internal report. 60. R. Gale, The Energy Daily, 9(128), 1 (1981). 61. D.S. Scott, 0. McCammond, C.A. Ward, G.C. Weatherly, R.D. Venter and J.S. Wallace, "Study of the Fuel Cells and Analysis of Options for Their Development in Canada", Phase II Final Report, prepared for Defence Research Establishment (Ottawa) and Transport Canada, July 1980. 62. H. Van den Broeck, M. Alfenaar, G. Hovestreydt, A. Blanchart, G. Van Bogaert, M. Bombeke and L. Van Poucke, in "Hydrogen Energy System", eds. T.N. Veziroglu and W. Seifritz, Pergamon Press, N.Y., Vol. 4, 1978, p. 1959. 63. M. Sayer, A. Teitsma and P.S. Nicholson, "The Selection, Preparation and Characterization of Ceramic Hydrogen Ion Conductors", Final Report, Phase I under DSS Contract No. 0SX79-00047, December 1980 (also available from M. Hammerli). 64. H.S. Isaacs, S. Srinivasan and I.L. Harry, eds. "Proceedings of the Workshop on High Temperature Solid Oxide Fuel Cells", Brookhaven National Laboratory, Report No. BNL-50756, April 1978. 65. T.A. Wheat, private communication. 66. T.A. Wheat, "Ionically Conducting Ceramics and Their Applications", Canada Centre for Mineral and Energy Technology, Report No. ERP/MSL 78-47 (OP & J), February 1978. 67. P.M. Spaziante, G.C. Sioli, and R. Trotta, "Hydrogen/Halogen Energy Storage System: Safety, Performance and Cost Assessment", Brookhaven National Laboratory, Report No. BNL-51070, February 1979. 68. W.J.D. Escher and T.D. Donakowski, Int. J. Hydrogen Energy, 1(4), 389 (1977). 69. J.R. Burnett and F.L. Kaestle, Direct Current 8, 196 (1963). 70. S.E. Foh, W.J.O. Escher and T.D. Donakowski, in "Hydrogen for Energy Distribution", Proceedings of Symposium held in Chicago, July 24-28, 1978; Institute of Gas Technology, Chicago, January, 1979, p. 339. 71. J.G. Melvin, private communication. 72. "Plasma technology offers steelmakers a moderization transfusion at a low cost", Metal Producing, 21» 55 (1981). - 64 -

73. "Quebec researchers show fluid-bed reduction is promising for base metals", Canadian Chemical Processing, 62(3), 16 (1978). 74. J.W. Gulyas, private communication. 75. "Energy Update", Energy, Mines and Resources, Report No. E 181-4E (Cat. No. M23-13/81-4E).

76. 0=0. Taylor} private communication. 77. H. Buchner, Int. J. Hydrogen Energy, 2. 385 (1978). 78. S. Furuhama, M. Hiruna and Y. Enomoto, Int. J. Hydrogen Energy, 2» 61 (1978). 79. M. Sayer, E. Prasad and P.S. Nicholson, "Ceramic Hydrogen Ion Conductors", Report under DSS Contract No. 04SX.31155-9-6607, November 1979 (also available from M. Hammerli/. 80. H. Van den Broeck, G. Hovestreydt, W. Keuning, M. Alfenaar, "Vehicles with Fuel Cells: Dream or Reality", Paper presented at the 26. Haupttagung of the Deutsche Gesellschaft fur Mineralol- wissenschaft und Kohlechemie E.V., Berlin, October 4-6, 1978. 81. G.D. Brewer, Int. J. Hydrogen Energy, £, 169 (1979). 82. "Moving the Railroad off of Oil: The Hydrogen Alternative", Escher Technology Associates, Report No. ETA PB-77-3C, June 1977. 83. M. Hammerli, secretary, "Minutes of the 2nd Meeting of the Canadian Advisory Committee on Hydrogen" EMR, Ottawa, January 16, 1979. 84. F.J. Edeskuty and K.D. Williamson, Jr., in "Hydrogen: Its Technology and Implications", eds. K.E. Cox and K.D. Williamson, Jr., CRC Press, Ohio, Vol. II, 1977, p. 51. 85. J.J. Reilley and G.D. Sandrock, Scientific American, 224J2), us (1980). 86. R.L. Cohen, J.H. Wernick, Science, 214(4525), 1081 (1981). 87. H. Buchner, in "Entwicklungslinien in Kraftfahrzeugtechnik und Strassenverkehr", Forschungsbilanz 1979, Der Bundesminister fur Forschung und Technologie, Verlag TUV Reinland GmbH, Koln 1980, p. 338. 88. J.H. Kelley and E.A. Laumann, "Hydrogen Tomorrow: Demands and Technology Requirements", Report of the NASA Hydrogen Energy Systems Technology (HEST) Study, Jet Propulsion Laboratory Report No. JPL-5040-1, December 1975. - 65 -

89. J.J. Reilly, in "Hydrogen: Its Technology and Implications", eds. K.E. Cox and K.D. Williamson, Jr., CRC Press, Ohio, Vol. II, 1977, p. 13. 90. F.W. Hoehn, R.L. Baisley and M.W. Dowdy, "Advances in Ultraclean Combustion Technology using Hydrogen-enriched Gasoline", in Proc. 10th Intersociety Energy Conversion Conf., Institute of Electrical and Electronics Engineers Inc., N.Y., 1975, p. 1156. 91. A.H. Beaufrere, F.J. Salzano, R.J. Isler and W.S. Yu, Int. J. Hydrogen Energy 1(3), 307 (1976). 92. N.P. Yao, "Advanced Secondary Batteries for Electric Vehicle Propulsion", Advanced Transit Association, International Conference, Hyatt Regency, Indianapolis, April 25-28, 1978. (Conf.-780426-2). 93. G. Strickland, "Ammonia As a Hydrogen Energy-Storage Medium", Brookhaven National Laboratory, Report No. BNL-28293, August 1980. 94. M. Taube and P. Taube, in "Hydrogen Energy Progress" eds. T.N. Veziroglu, K. Feuki and T. Ohta, Pergamon Press, N.Y., Vol. 2, 1980, p. 1077. 95. S. Foh, M. Novil, E. Rockar and P. Randolph, Brookhaven National Laboratory, Report No. BNL-51275, December 1979. 96. J.H. Kelly and R. Hagler, Jr., Int. J. Hydrogen Energy 5(11), 35 (1980). 97. A. Mezzina, M. Bonner and F.J. Salzano, "Chemical/Hydrogen Energy Storage Systems", Brookhaven National Laboratory, Report No. BNL-51226, May 1980. 98. C. Carpetis and W. Peschka, Int. J. Hydrogen Energy, 5(5), 539 (1980). - 99. S.L. Robinson, in "Hydrogen for Energy Distribution", Proceedings of Symposium held in Chicago, July 24-28, 1978; Institute of Gas Technology, Chicago, January 1979, p. 453. 100. G.G. Leeth, in "Hydrogen: Its Technology and Implications", eds. K.E. Cox and K.D. Williamson, Jr., CRC Press, Ohio, Vol II, 1977, p. 3. 101. M.R. Louthan, Jr. and G.R. Caskey, Jr., Int. J. Hydrogen Energy, 1(3), 291 (1976). 102. A.W. Thompson, in "Hydrogen: Its Technology and Implications", eds. K.E. Cox and K.D. Williamson, Jr., CRC Press, Ohio, Vol II, 1977, p. 85. 103. J. Hord, Int. J. Hydrogen Energy, 5(6), 579 (1980). - 66 -

104. R.M. Zweig, in "Hydrogen Energy System", eds. T.N. Veziroglu and W. Seifritz, Pergamon Press, N.Y. Vol. 4, 1978, p. 2231. - 67 - LIST OF TABLES

Table 2.2.1 Present Uses of Electrolytic Hydrogen Table 3.1.1 Summary of Hydrogen Production Processes Table 4.3.1 Present and Projected Parameters for Canada' s Unipolar Electrolyser Technologies Table 4.4.1 Values of the Parameters Used in Calculating the Total Hydrogen Cost for the 1978, 1981 and 1983 Unipolar Technologies Table 4.4.2 Calculated Cost Estimates of Various Components of a Unipolar Electrolyser Plant (^100 MW) Table 4.5.1 Cost Comparison of Present Unipolar (1978) and Bipolar Electrolyser Technologies based on Data of Reference 25 Table 4.6.1 Summary of Sensitivity Analysis for the 1981 and 1983 Unipolar Technologies Table 4.6.2 Normalized Sensitivity Factors for Various Parameters Table 8.2.2.1 Hydrogen Demand Projections for Oil Refining: Reference Estimate Table 8.2.3.1 Hydrogen Demand Projections for Synthetic Fuel Production: Reference Estimate Table 10.3.2.1 Advantages and Disadvantages of the Direct- Fired H2/O2 Superheater Concept Coupled to a CANDU Reactor Table 10.4.3.1 Oil Consumption by Sector in Canada in 1980 Table 10.4.3.2 Comparison of Parameters for the Liquid Hydrogen Versus Jet A Fuelled Subsonic Transport Aircraft Table 10.4.3.3 Hydrogen-Converted Diesel Engine: Areas of Technical Uncertainties Table 10.4.3.4 Characteristics of Gasoline, Diesel Oil and Liquid Hydrogen Table 10.5.2.1 Comparison of Storage Requirements of hueis for Vehicles - 68 - LIST OF TABLES CONT'D

Table 10.5.2.2 Properties of Some Binary Metal Hydrides

Table 10.5.2.3 Energy Density Comparison: Automotive Power Sources Table 10.5.5.1 Properties of Some Cryoadsorbents for Hydrogen Storage

Table 10.5.6.1 Hydrogen Pipeline Experience

Table 10.5.6.2 Comparative Transmission Costs for Hydrogen and Natural Gas Table 10.7.1 General Opportunities for Research and Development Required Prior to Implementation of Hydrogen Systems Technologies Table 10.8.1 Summary of Suggested Research, Development ;nd Demonstrations of Hydrogen Technologies in Canada

Table 10.8.2 Summary of Hydrogen Hardware Developments which are Technologically Possible and Probable before the Year 2025 - 69 -

TABLE 2.2.1 PRESENT USES OF ELECTROLYTIC HYDROGEN

A. 2.5 kW TO 5 MW PLANTS

1. Electricity generator cooling. 2. Hydrogenation of foods. 3. Hydrogenation of industrial chemicals. 4. As a chemical reducing agent in: (a) powdered metals production \b) metallurgical processing c) electronic components manufacture (d) production of float glass 5. Filling weather balloons. 6. Bottled hydrogen for miscellaneous uses.

B. ^ 100 MM PLANTS

1. Ammonia production.

2. Heavy water recovery as a by-product. - 70 -

TABLE 3.1.1

SUMMARY OF HYDROGEN PRODUCTION PROCESSES

PROCESS REMARKS

1. Steam Reforming of Most important commercial process for Natural Gas large-scale H2 production in 1980.

2. Partial Oxidation of Some 200 large plants around the world Heavy Oil today usually support ammonia production.

3. Electrolysis of At present important only for small-scale Water (S5 MM) H£ production usually because of high purity of K2.

4. Water Vapour Requires high temperature steam (M000°C). Electrolysis Demonstrated on bench scale. R&D in progress aimed at reducing temperatures to 3OO-7OO°C.

5. Open Electrochemical Requires water and at least one more Cycl es chemical as feed. Electrolysis cell is more complicated than that for 3. Demon- strated on bench scale.

6. Thermochemical Cycles

(a) Pure Cycles Require a high temperature (-\<1000oC) source. Demonstrated on bench scale.

(b) Hybrid or Require a high temperature Thermo- source. Electrolysis cell is same as for Electrochemical 5. Demonstrated on bench scale. Cycles

7. Coal Gasification Old technology mature and improved technology in pilot stage. Could become important for large-scale production.

8. Steam-Iron-Coal May compete with process 7 because process Gasification 8 does not require pure oxygen. Process 8 also produces by-product steam or electricity. - 71 -

TABLE 3.1.1 CONT'D

PROCESS REMARKS

9. Photoelectrolysis Difficult to combine unit cells in series. Prospects are poor relative to process 4 for large-scale production. Demonstrated in principle but anode cor- rosion is a major problem to be solved. 10. H2 Production With Has the best prospects of the solar- the Photochemical based direct H2 production processes. Diode Is at the early research stage.

11. Biological H2 Has best potential for treating inor- Production (Algae ganic and organic wastes, but, because and Bacteria) H2 yields are low and reaction times long, it will not likely compete with process 10. Demonstrated on bench scale. 12. Photolysis of Water With (a) Ruthemium Has potential but must compete with pro- Complex cess 10. In early research stage. (b) The Plasma Requires directed plasma source and a Torch (Simulating "window" of the appropriate wavelength the Sun) characteristics. Only process not yet demonstrated by man. 13. Direct Thermal Theoretically feasible. Requires mem- Splitting of brane for separating products from Water reactants. Requires a very high temperature source (>2000°C). Not yet demonstrated fully in the laboratory. 14. Radiolysis of Energy efficiency is too low due to back- Water or any reactions. Demonstrated on the bench System Containing scale. Hydrogen 15. Co-Production of Wi Co-production processes may become with Other Chemicals important within the chemical industry. e.g., C12 and NaOH - 72 -

TABLE 4.3.1 PRESENT AND PROJECTED PARAMETERS FOR CANADA'S UNIPOLAR ELECTROLYSER TECHNOLOGIES*

UNIPOLAR TECHNOLOGY

PARAMETER 1978 1981 1983 TECHNOLOGY TECHNOLOGY

1. Rated Current Density, 134 134 134 ir (mA/cm2) 2. Rated Cell Voltage, 2.04 1.82 1.74 Vr (V) 3. Possible Operating 134 200 320 Current Density, i (mA/cm^) 4. Operating Cell Voltage 2.04 1.9 1.8 Vi (V) 5. Cost (1980$) of Cells 190 159 156 + Accessories ($/kW Vr) 6. Cost/m^ of Separator 159 388 364 Area @ i, Vj

* Based on data in references 15 and 16 adjusted to 1980$. TABLE 4.4.1

VALUES OF THE PARAMETERS USED IN CALCULATING THE TOTAL HYDROGEN COST FOR THE 1978, 1981 AND 1983 UNIPOLAR TECHNOLOGIES

PARAMETER 1978 1981 1983 NAME SYMBOL TECHNOLOGY TECHNOLOGY TECHNOLOGY COMMENTS

Basic Cell Cost k ($/kWh) 190 159 156 Data from reference 15 adjusted to 1980$

Rated Current ir (mA/cm2) 134 134 134 Reference 15 Density

Rated Voltage vr (v) 2.04 1.82 1.74 Reference 15 Fraction of Basic fl 0.9 0.9 0.9 Reference 15 Cell Cost Independent of ir Capital Recovery K 0.2 0.2 0.2 Equivalent to 16%/a Factor* return on capital* Plant Capacity P 0.9 0.9 0.9 Assumed plant capacity Factor factor Operating Current i (mA/cm2) 134 200 320 Data from reference 16 Density

Operating .oltage Vn- (V) 2.04 1.9 1.8 Data from reference 16 TABLE 4.4.1 CONT'D

PARAMETER 1978 1981 1983 NAME SYMBOL TECHNOLOGY TECHNOLOGY TECHNOLOGY COMMENTS

Fraction of Basic f 0.45 0.45 0.45 Reference 15 Cell Cost for 2 Installation of Plant Electricity Cost P ($/kUh) 0.02 0.02 0.02 Assumed electricity cost Rectifier 0.96 0.96 0.96 Reference 15 and 24 Efficiency Rectifier Cost *R ($/kW) 40 40 40 Reference 24 Capital Recovery K 0.28 0.28 0.28 Reference 16 Factor for c Compressors

Compressor Cost xc ($/kW) 724 724 724 Reference 16 Compressor Cost nc 0.95 0.95 0.95 Reference 19

* Includes 2% to cover operating and maintenance and 2% for ad-valorem taxes (reference 15). TABLE 4.4.2

CALCULATED COST ESTIMATES OF VARIOUS COMPONENTS OF A UNIPOLAR ELECTROLYSER PLANT (-vlOO MW)

1978 1981 1983 TECHNOLOGY TECHNOLOGY TECHNOLOGY ITEM(S) $/GJ % $/GJ % $/G0 %

1. Cells + Accessories (C^)* 1.07 9.6 0.97 9.9 0.62 4.9 2. Installation + Startup (C£) 0.64 5.7 0.52 5.3 0.41 3.3

3. Installed Rectifier (C3) 0.43 3.9 0.38 3.8 0.36 2.8 4. Total Capital and 2.14 19.2 1.86 19.0 1.38 11.0 Installation* (C, + C? + C3)

5. Electrical Energy @ 2

7. TOTAL H2 COST** (C) 11.9 100 9.81 100 8.94 100

* Terms of equation [1] (for exact expressions see APPENDIX A).

** Totals may not agree, because of rounding off. - 76 -

TABLE 4.5.1

COST COMPARISONS OF PRESENT UNIPOLAR (1978) AND BIPOLAR ELECTROLYSER TECHNOLOGIES BASED ON DATA OF REFERENCE 25

BIPOLAR UNIPOLAR

TELEDYNE, LURGI, NORSK HYDRO, ELECTROLYSER CORP., ITEM MARYLAND FRANKFURT OSLO TORONTO 0.08 MW 3.5 MW 50 MW 50 MW 100 MW

1. Type Bipolar Bipolar Bipolar Unipolar Unipolar Pressurized Pressurized Atmospheric Atmospheric Atmospheric

2. Capital(a) 10.27 3.36 2.65 2.29 1.90 Cost ($/GJ)

3. Electricity(b) 10.12 7.32 6.96 .74 7.74 Cost ($/GJ)

4. TOTAL H2 20.39 10.15(c) 9.61 10.03 9.64 COST ($/GJ)

5. RELATIVE 2.12 i.O5 1.00 1.04 1.003 TOTAL H2 COSTS

Notes: (a) 18% interest rate, 20 year equipment life (b) Electricity cost (? 2

TABLE 4.6.1

SUMMARY OF SENSITIVITY ANALYSIS FOR THE 1981 AND 1983 UNIPOLAR TECHNOLOGIES

1981 TECHNOLOGY 1983 TECHNOLOGY PARAMETER (Base Value NEW VALUE CHANGE IN NEW VALUE CHANGE IN in brackets) OF PARAMETER H2 COST OF PARAMETER H2

1. Plant Capacity 0.5 +18% 0.5 +11% Factor (P = 0.9) 0.2 +77% 0.2 +47%

2. Cost of Cells, 318 +15% 312 +12% 1981 (xk=$159/kWh) 1983 (xk=$156/kWh)

3. Capital Recovery 0.25 + 5% 0.25 + 4% Factor (K = 0.2)

4. Electricity Cost 3

5. Operating Voltage 1.8 V -5.4% 1.9 V +5.6% 1.9 V for 1981 1.8 V for 1983

6. Compression Costs Doubled +5.4% Doubl ed +5.1% (see APPENDIX A)

7. Cells + Access- 0.5 +1.9% 0.5 +2.4% ories Costs (f] = 0.9)

8. Installation- 0.6 +1.8% 0.6 +1.1% Related Costs (f2 = 0.45) - 78 -

TABLE 4.6.2

NORMALIZED SENSITIVITY FACTORS FOR VARIOUS PARAMETERS

NORMALIZED SENSITIVITY FACTOR

PARAMETER 1981 1983 COMMENTS TECHNOLOGY TECHNOLOGY

1. Plant Capacity Factor, P 370 417 P = 0.9 •*• 0.2 148 10 P = 0.9 •*• 0.5

2. Operating Cell Voltage, 37 39

3. Electricity Cost, p 28 33

4. Capital Recovery 7 6 Excludes Factor, K Compressors

5. Capital Cost of Cells, 6 5 In $/kW of DC in fj, Installation-Related 2.0 1.3 Based on Costs, f2 f2 = 0.45+0.6

7. Fraction of Cell Plus 1.6 2.1 Based on Accessories Cost, f], f] = 0.9-*0.5 Independent of Operating Current Density

8. Total Compression 1 1 Based on doubling Costs: total compression $0.529/GJ for 1981 costs. $0.648/GJ for 1983 - 79 -

TABLE 8.2.2.1 HYDROGEN DEMAND PROJECTIONS FOR OIL REFINING: REFERENCE ESTIMATE

H2 DEMAND YEAR (6m3/a) COMMENTS

1980 4.2 Interpolated from data of reference 1 1985 4.9 Reference 1 2005 6.7 Reference 1 2025 7.1 Reference 1 - 80 -

TABLE 8.2.3.1 HYDROGEN DEMAND PROJECTIONS FOR SYNTHETIC FUEL PRODUCTION: REFERENCE ESTIMATE

H2 DEMAND YEAR (Gm3/a) COMMENTS

1980 1.7 Interpolated from data of reference 1 1985 2.5 Reference 1 2005 9.0 Reference 1 2025 19 Reference 1 - R1 -

TABLE 10.3.2.1

ADVANTAGES AND DISADVANTAGES OF THE DIRECT-FIRED H2/02 SUPERHEATER CONCEPT COUPLED TO A CANDU REACTOR*

A. Advantages

1. Peak power output of 1200 Mwe** net for 12 hours per day. 2. Steam flow for 1200 MWe peak power with superheat equal to that for 800 MWe base load power without superheat. 3. Continuous operation of complete system of reactor and superheater. 4. Efficient steam cycle without problems of separate fossil fuel fired superheater. 5. Smaller physical size of turbine although output bO% higher. 6. No external steam separator required for turbine and no live steam reheater. 7. Final moisture content of the steam is reduced by about a factor . of 2. 8. Production of 100 Mg of heavy water per annun (assuming 4000 h/a of cell operation) by the CECE-HWP as by-product.

9. All peaking equipment completely separate from reactor.

B. Disadvantages

1. Fufiling cost increased by about a factor of 1.3. 2. Handling hydrogen an added hazard. 3. Chemistry of steam-cycle may be more complicated due to effects of direct combustion on volatile additives or impurities in steam. 4. Capital cost increased by need for generator sized for peak load.

* Assumes an 800 MWe (net) or 850 MWe (gross) CANDU reactor. ** MWe Megawatt electrical - 82 -

TABLE 10.4.3.1 OIL CONSUMPTION BY SECTOR IN CANADA IN 1980

Fraction Consumed Sector (X)

1. Transportation 44.4 2. Residential and Farm 14.8

3. Other Industrial 13.7 4. Non-Energy Uses 10.4

5. Refinery Own 7.1

6. Commercial and Government 6.2

7. Electricity Generation 3.4

Source: Reference 75. - 83 -

TABLE 10.4.3.2 COMPARISON OF PARAMETERS FOR THE LIQUID HYDROGEN VERSUS JET A FUELLED SUBSONIC TRANSPORT AIRCRAFT

RATIO PARAMETER LH2 JET A FUEL JET A/LH2

1. Gross weight (kg) 168,830 232,060 1.37

2. Block fuel weight (kg) 21,620 72,370 3.35

3. Operating empty weight (kg) 103,300 107,360 1.04

4. Thrust (kg) per engine (N) 135,000 184,900 1.37

5. Wing area (m^) 296.8 380.3 1.28

6. Span (m) 51.7 58.5 1.13

7. Fuselage length (m) 65.7 60.0 0.914

8. Takeoff distance (m) 2440 2431 -

9. Landing distance (m) 1768 1584 -

10. Lift/drag (cruise) 17.4 19.1 1.10

11. Specific fuel 2.99 consumption (cruise)

12. Aircraft price 43.39 44.53 1.03 ($106 US)

13. Energy utilization 636 759 1.19 (kJ/seat km)

Source: Reference 81. - 84 -

TABLE 10.4.3.3

HYDROGEN-CONVERTED DIESEL ENGINE: ARCAS OF TECHNICAL UNCERTAINTIES

. Compression Ignition

. Hydrogen Admission Technique

. Utility of LHg* Refrigeration Effect

. Oxides of Nitrogen Emissions

. Ancillary and Auxiliary Systems

. Safety, Reliability and Maintainability

Source: Reference 82.

* LH2 = Liquid Hydrogen - 85 -

TABLE 10.4.3.4 CHARACTERISTICS OF GASOLINE, DIESEL OIL AND LIQUID HYDROGEN

DIESEL LIQUID PROPERTY GASOLINE OIL ; HYDROGEN

! 1. Specific Gravity 0.73 0.86 0.071 (g/c«|3)

2. Boiling Point (°C) 38 to 204 160 to 343 -253 (21 K)

3. Lower Heating Value Gravimetric (kJ/kg) 4.49 x 104 4.30 x 104 12.0 x 104 Volumetric (kJ/m3) 32.7 x 106 36.8 x 106 8.52 x 106

4. Stoichiometric Mixture 14.8 14.5 34.6

5. Flammable Limits (Air) 1.4 - 7.6% 0.7 - 5.0% 4 - 74% (Lower-Upper)

6. Ignition Temperature 257 254 574 (0°C)

7. Flas.ie Speed (m/s) 0.34 0.34 1.1

Source: Reference 82. TABLE 10.5.2.1 COMPARISON OF STORAGE REQUIREMENTS OF FUELS FOR VEHICLES Basis: Energy equivalent of 7.6 x 10"2 m3 (20 US gallons) of gasoline (2.40 GJ) without end use efficiency considerations

ABSOLUTE COMPARISON RELATIVE COMPARISON (Fuel/Gasoline)

Fuel Alone Fuel fi Container Fuel Alone Fuel & Container

FUEL Weight Volume Weight Volume kg m3 kg tr.3 Basis Basis Basis Basis

1. Gasoline 54 0.076 61 0.078 1.0 1.0 1.0 1.0 2. H2 (gas at 19.9 1.15 1021 1.87 0.37 15 17 24 20.7 MPa, 300 K) 3. H2 (liquid 19.9 0.289 160 0.289 0.37 3.8 2.6 3.7 at 0.1 MPa) b 4. H2 as MgH2 (a) 262 0.187 216 (a»b) 0.334 ( ) 4.9 2.5 3.5 4.3 b 5. H2 as MgNiH2 569 0.396 649 0.544 ( ) 10.5 5.2 11 7.0 6. Methane (gas at 47.9 0.351 227 0.782 0.89 4.6 3.7 10 20.7 MPa, 300 K) 7. Methane (liquid 47.9 0.115 109 0.456 0.89 1.5 1.8 5.8 at 0.1 MPa) 8. Ammonia (liquid 129 0.203 206 0.379 2.4 2.7 3.4 4.9 at 300 K) 9. Hydrazine 153 0.153 166 0.171 2.8 2.0 2.7 2.2 10. Methanol 118 0.149 129 0.161 2.2 2.0 2.1 2.1

Source: Reference 88. 3 Notes: (a) Assumes theoretical yield of hydrogen, density of MgH2 = 1.4 g/cm . (b) Includes 2.2 kg and 0.03 m3 allowance for heat exchange means and ancillary equipnent to charge and discharge MgH2 or MgNiH2. - R7 -

TABLE 10.5.2.2 PROPERTIES OF SOME BINARY METAL HYDRIDES

Weight Percent Heat of Formation Hydride Hydrogen NH* kJ/mol

LiH 12.7 5.9 -90.9

A1H3 10.i - -11.3

CaH2 4.2 5.1 -175

MgH2 7.6 6.6 -75 NaH 4.8 5.1 -56.9

TiH2 4.0 9.1 -126

ZrH2 2.2 7.3 -166

LaH2 2.1 6.8 -208 UH3 1.3 8.4 -129

H2 (Liquid) 100 4.2 -

Source: Reference 89. * NH x 10^2 = number of H atoms per cubic centimetre. - 88 -

TABLE 10.5.2.3

ENERGY DENSITY COMPARISON: AUTOMOTIVE POWER SOURCES

Energy Conversion Net Energy Dens i ty Efficiency Density Power Source (Wh/kg) (%) (Wh/kg)

1. Lead/Acid Battery (a) Present 30 70 21.0 (b) Advanced 50 70 35.0

2. Lithium/Metal 150 70 105 Sulfide Battery

3. Iron-Titanium 516 30 154 Hydride (a,b)

4. Magnesium-Nickel 1,121 30 336 Hydride (a,b)

5. Magnesium Hydride 2,555 30 767 with 10% Ni (a,bfc)

6. Gasoline 12,880 23 2,962

Source: Reference 89.

Notes: (a) No allowance for container weight. (b) Based on available hydrogen, i.e., FoTiH1.7 * FeTiH0.1 etc- (c) Nickel present as TABLE 10.5.5.1 PROPERTIES OF SOME CRYOADSORBENTS FOR HYDROGEN STORAGE

Pore Pore Max. Stored Hydrogen Bulk Density Voltime Surface at 4.2 MPa, 78 K Material (g/cm3) (cm3/g) (m2/g) [g(H)2/kg adsorbent]

Nickel oxide-Silicate 1200-88-02 0.67 0.64 530 34

Nickeloxide-Silicate G 49 0.85 0.31 - 23

Silicagel KIESELGEL 40 0.59 0.65 650 31 00

Silicagel KIESELGELPERL 0.72 0.38 - 31

Activated Carbon SCHUMASORB 0.85 0.68 - 25

Activated Carbon NK 12 0.36 1.17 - 49

Activated Carbon BS 12 0.39 1.04 - 52

Activated Carbon F12/470 | 0.46 0.80 - 49

Activated Carbon F 12 0.38 1.08 1250 66

Activated Carbon F12/35O 0.35 1.25 68

Source: Reference 98. TABLE 10.5.6.1 HYDROGEN PIPELINE EXPERIENCE

Pipeline Age Diameter Length Location Steel (Years) (cm) (km) Hydrogen Comments

Air Products- Linepipe (Converted 9 10 8 "Pure" No Problems Texas Nat. Gas Pipeline) 5.5 MPa

Air Products- New-Schedule 40 Steel 6 20 19 "Pure" No Problems ' Texas 1.4 MPa

Germany Seamless 1015 Steel Greater 15-30 200 "Dirty" No Problems than 30 1.8 MPa

U3 NASA-KSC- 316 Stainless Steel 10+ 5 1.6 "Ultrapure" No Problems O Florida 41 MPa

Linde - - - 1.6-2 - -

South Africa - - - 80 - -

Los Alamos* 5 Cr-Mo Steel 8 2.54 6.4 "Pure" Leaked 3 a 14 MPa Cracked 4 a Abandoned

Source: Reference 99.

The Los Alamos pipeline was not cathodically protected, but was placof* in the vicinity of lines which were; thus external hydrogen charging occurred. The failure of the pipeline was probably not due to the high purity hydrogen it carried but due to electrolytically produced hydrogen [personal conmunication, F. Edeskatz, Los Alamos Scientific Laboratory, with S.L. Robinson of reference 98], - 91 -

TABLE 10.5.6.2 COMPARATIVE TRANSMISSION COSTS FOR HYDROGEN AND NATURAL GAS

RELATIVE TRANSMISSION COST* INSTITUTION Natural Gas Hydrogen

1. General Electric, 1.0 1.3 - 1.5 USA 2. EURATOM, Ispra, 1.0 1.4 - 1.6 Italy 3. Institute of Gas 1.0 2.0 - 3.0 Technology, USA

Source: Reference 100. * Per unit of energy - 92 -

TABLE 10.7.1 GENERAL OPPORTUNITIES FOR RESEARCH AND DEVELOPMENT REQUIRED PRIOR TO IMPLEMENTATION OF HYDROGEN SYSTEMS TECHNOLOGIES

Item Comments

1. Market Studies Must be updated periodically to reflect relative competitive position of hydrogen. 2. Comparative Economic Should include effect of by-product Evaluations credits and environmental benefits of using electrolytic hydrogen. 3. Cost-Benefit Analysis Expected to be particularly attractive for electrolytic hydrogen derived from non-fossil primary energy.

4. Systems Analysis Must include possible synergies both intra-system and inter-system.

5. Systems Engineering Must allow for hydrogen embrittle- mem

6. Safety Analysis May require changes in existing codes.

7. Safety Standards Foreign standards must be adapted to Canadian conditions.

8. Quality Assurance Particularly important if catastrophic failures due to hydrogen embrittlement are to be avoided.

9. Environmental Impact If hydrogen derived from non-fossil Studies sources is used, these are expected to be positive. 10. Studies of Impact on Important for an orderly, gradual Existing Technologies transition period.

11. Studies of Health Benefits A remote mining town and mining of a Hydrogen Community operations powered by electrolytic hydrogen is particularly relevant to Canada. TABLE 10.8.1 SUMMARY OF SUGGESTED RESEARCH, DEVELOPMENT AND DEMONSTRATIONS OF HYDROGEN TECHNOLOGIES IN CANADA

TYPE OF RESEARCH ACTIVITY

Basic Development Demonstration

SPECIFIC HYDROGEN Present Present Present TECHNOLOGY ITEM Status Required Status Required Status Requi red

1. ELECTROLYTIC PRODUCTION (a) Advanced Alkaline Ongoing Yes Ongoing Yes Ongoing Yes (b) Water Vapour Ongoing Yes "(a) ' Yes (a) Yes CO 2. ENERGY CONVERSION AND STORAGE (a) Catalytic Combustor Ongoing Yes Nil Yes Nil Yes for Space Heating (b) Direct-Fired H2/02 N/A No Nil Yes Nil Yes Superheater (c) Fuel Cells (i) Low Temperature N/A No Nil Yes Nil Yes Alkaline (ii) Medium Temperature N/A No Nil Yes Nil Yes Phosphoric Acid (iii) Reversible Mater Ongoing Yes (a) Yes (a) Yes Vapour Electrolyser/ Hydrogen-Oxygen Fuel Cell (iv) Hydrogen-Halogen ? Yes Nil Yes (a) Yes Systems (d) Acyclic Generator for DC Electricity with (i) Liquid-metal Brushes N/A No Ongoing No Ongoing Yes (ii) Superconducting Field ? Yes Yes (a) Yes Coils TABLE 10.8.1 CONT'D

TYPE OF RESEARCH ACTIVITY Basic Development Demonstration SPECIFIC HYDROGEN Present Present Present TECHNOLOGY ITEM Status Requi red Status Required Status Requi red

3. HYDROGEN USES (a) Traditional Uses (i) Chemical Industry N/A No N/A No Nil Yes (ii) Direct Reduction of Ongoing Yes Ongoing Yes ? Yes W Oxide Ores (iii) Plasma Torch for N/A No Nil Yes Nil Yes Steel Making (iv) Direct Reduction Ongoing Yes Nil Yes (a) Yes of Sulfide Ores (v) Hydrometallurgical Ongoing Yes Yes ? Yes Processes (0 (b) New Uses in Transportation (i) Diesel Enqine Ongoing Yes Ongoing Yes Planned Yes (ii) Fuel Cells (see text) Ongoing Yes Ongoing Yes (a) Yes (iii) Hybrid Battery/Fuel ? Yes Nil Yes Nil Yes Cell Car (iv) LH2 Aircraft Planned Yes Planned Yes Planned Yes (v) LH2 Train ? Yes ? Yes ? Yes 4. HYDROGEN STORAGE AND TRANSMISSION (a) Metal Hydrides Ongoing Yes Ongoing Yes ? Yes (b) Hydride Compressor N/A No Nil Yes Nil Yes (c) Liquid Hydrides(d) (i) Ammonia Ongoing Yes Ongoing Yes Planned Yes (ii) Methanol Ongoing Yes Ongoing Yes Planned Yes (iii) Methyl Cyclohexane Ongoing Yes Onqoing Yes Planned Yes (d) Underground Storage(e) ? Yes Nil Yes Nil Yes I TABLE 10.8.1 CONT'D

TYPE OF RESEARCH ACTIVITY Basic Development Demonstration SPECIFIC HYDROGEN Present Present Present TECHNOLOGY ITEM Status Required Status Requi red Status Requi red

(e) Glass Microspheres Onqoing Yes Ongoing Yes Planned Yes (f) Cryoadsorbents * 7 Yes Yes 7 Yes (g) Transmission Ongoing Yes 7 Yes Nil Yes 5. MATERIALS RESEARCH (a) Hydrogen EmbrittlementW Ongoing Yes Onqoing Yes Ongoing Yes (b) New Materials 7 Yes Nil i'es Nil Yes (c) Liners for Vessels and Pipes (i) Metal Ongoing Yes Ongoing Yes Ongoinq Yes (ii) Plastic Nil Yes Nil Yes (a) ' Yes (d) Welding (i) Materials Yes 7 Yes 7 Yes (ii) Procedures ? Yes ? Yes ? Yes

Notes: (a) Technologically too early for a coranitment on this scale. (b) For iron, only a demonstration using pure hydrogen is required since a mixture of hydrogen and carbon monoxide is already being used commercially. (c) Direct reduction in solutions is in use for nickel 4 cobalt and copper (see Section 10.4.2) but could be applied to other metals. (d) R, D & D is required for on-board hydrogen generators and for safety and handling criteria for these liquid hydrides. (e) R, 0 & D required on possible effects of "odorants" and "colorants" for hydrogen; underground storage has been demonstrated (see Section 10.5.4). N/A = Not Applicable TABLE 10.8.2 SUMMARY OF HYDROGEN HARDWARE DEVELOPMENTS WHICH ARE TECHNOLOGICALLY POSSIBLE AND PROBABLE BEFORE THE YEAR 2025

Fossi1 Fuel Substitution Type of by 2025 HYDROGEN When Plant or Unit HARDWARE Probable Hardware Small Medium Large Size

1. Alkaline Water 1985-1990 Demonstration J Large Electrolyser* Plant (100 MW) 2. Water Vapour/ 2000-2010 Demonstration / Large Electrolyser Plant (M MW) Fuel Cell* 3. Catalytic H2 1990-1995 Commercial / Small Combustor* 4. Direct-Fired 1985-1990 Commercial / Med i urn 10 CM H2/02 Superheater 5. Alkaline Fuel 1990-1995 Commercial / Small Cell* (low temp.) 6. Phosphoric Acid 1985-1990 Commercial j Medium Fuel Cell 7. Hydrogen-Halogen 1990-1995 Demonstration Med i un Reversible Electrolyser/Fuel Cell 8. Acyclic DC 1985-1990 Demonstration N/A** N/A N/A Medium Generator 9. Plasma Torch 1990-2000 Demonstration Med i um 10. Diesel Engine* 1984 (?) Demonstration Medium 11. LH2 Aircraft 1990-2000 Demonstration Large 12. LH2 Train 1990-2000 Demonstration / Large 13. Hydride Compressor 1985-1995 Demonstration N/A N/A N/A Medium 14. On-Board H2 1985-1990 Demonstration / Small Production for Road Vehicles*

* R & D is currently in progress in Canada in this area. ** N/A - Not Applicable. - 97 -

LIST OF FIG'">ES

Fig. 2.1: Industrial Uses of Hydrogen in Canada in 1978. Source: Reference 1. Fig. 2.2: Production of Synthesis gas using solid fuel in a gasifier in conjunction with electrolytic hydrogen. Source: Reference 4. Fig. 4.1: Electrolytic hydrogen costs for the 1981 and 1983 Canadian Unipolar Water Electrolysis technologies as a function of the plant electrolyser plant's capacity factor at electrical energy costs of 2

Fig. 4.2: Electrolytic hydrogen costs for the 1981 and 1983 Canadian Unipolar Water Electrolysis technologies as a function of the electrical energy cost at an electrolyser plant capacity factor of 0.9.

Fig. 5.1: Block diagram of the Combined Electrolysis Catalytic JExchange- Heavy Water process (CECE-MWP) "Tor recovery of by-product heavy water from electrolytic hydrogen.

Fig. 6.1: The cost of hydrogen derived from natural gas assuming natural gas tracks the "world oil price" of $38 per barrel at (a) 75% and (b) 50%. The world oil price is assumed to escalate at 4% per annum in constant 1980 Canadian dollars.

Fig. 6.2: The cost of hydrogen derived from coal for the Koppers-Totzek and 2nd Generation technology based on data of reference 48. A 2% per annum real escalation is assumed in the cost of this hydrogen. The data of Fig. 6.1 are also included for comparison.

Fig. 6.3: Electrolytic hydrogen cost estimates assuming: (a) the 1981 unipolar technology with an electricity cost cf 2

LIST OF FIGURES CONT'D

Fig. 7.1 The liquid fuel options for Canada for 1990 as presented in Fig. 2 of reference 47 with the electrolytic hydrogen cost estimates of this work superimposed. It was assumed that the heavy water by-product would be realized (see text for reasons) but no credit has been included for the oxygen by-product of electrolytic hydrogen production (see Fig. 6.4). Fig. 7.2: The "world oil price" of reference 47 of $38 per barrel and the natural gas price at (a) 75% and (b) 50% of the "world oil price", assuming 4% per annum real escalation for the price of cil. The electrolytic hydrogen cost estimates of Fig. 6.4 are included for comparison. Fig. 8.1: The reference estimated hydrogen demand projections for Canada for the conventional uses as a chemical and for use as a fuel in stationary or transportation applications. The chemical use projections are based on data of reference 1 while the fuel use projection is based on the assumption of substituting 48,000 barrels per day of oil with electrolytic hydrogen by the year 2025. Fig. 8.2: The higher estimated hydrogen demand projections for Canada for the conventional uses as a chemical and for use as a fuel in stationery or transportation applications. The chemical use projections are based on assumed increases in the growth rates (see text for reasons) of Fig. 8.1, while the fuel use projection is based on the assumption of substituting 200,000 barrels per day of oil with electrolytic hydrogen by the year 2025. Note the difference in the ordinate scales of Figures 8.1 and and 8.2.

Fig. 9.1: The electrolytic hydrogen demand projections for Canada for the reference (Fig. 8.1) and higher (Fig. 8.2) total hydrogen demand projections based on the assumptions that electrolytic hydrogen will compete with hydrogen derived from natural gas (a) at $7.85/G.' for chemical uses and (b) at $3.17/GJ (see Fig. 7.2) for fuel uses. An energy scale in terawatt hours per annum based on a single cell voltage of 1.9 V (78% energy efficiency) is indicated on the extreme left. The installed electrolyser plant capacity which is required '.s indicated in gigawatts for a 0.8 and a 0.2 electrolyser plant capacity factor on the right hand side. - 99 -

AMMONIA 43%

SYNFUEL 12% OIL REFINING 33%

Fig. 2.1: Industrial Uses of Hydrogen in Canada in 1978. Source: Reference 1. - 100 -

SYNTHESIS GAS (CO + 2H2)

SOLID CO + H, FUEL

GASIFIER ELECTROLYSIS PLANT

HEAVY WATER STEAM BY-PRODUCT BOILER

Fig. 2.2: Production of Synthesis gas using solid fuel in a gasifier in conjunction with electrolytic hydrogen. Source: Reference 4. - 101 -

1981 Technology 983 Technology

13 18 \ 16 \ Cos t ( c \ e m 03$/kWh 14 Hydr o j

12 lyti c h 0 c 10 u + Reference Cost- ^ - This Study ^"^^-. 8 I I I I 1 I I I I .2 .4 .6 .8 Plant Capacity Factor

Fig. 4.1: Electrolytic hydrogen costs for the 1981 and 1983 Canadian Unipolar Water Electrolysis technologies as a function of the electrolyser plant's capacity factor at electrical energy costs of 2^/kWh and 3£/kWh. The Reference Cost of this study is indicated with a cross. - 102 -

IS . 1981 Technology — . 1983 Technology —

/ /'

•> N - O o c 0 O) o i 5 • s/ -+Reference Cost - this Study

1 i i i 0 .01 .02 .03 Cost of Electricity C1980S/kWh3

HYDROGEN GAS TO STORAGE OR ENERGY FEED WATER CONVERTER ETC. (~ 140 ppm 4 ( ~ 50 ppm DEUTERIUM ) J DEUTERIUM )

DEHUMIDIFIER 4 i •

H2/H2O DEUTERIUM EXCHANGE CATALYST uXYGEN GAS TO STORAGE TOWER OR ENERGY CONVERTER ETC

I » i i i i i i • DRYER SCRUBBER i HYDROGEN FROM DEUTERIUM ENRICHED { |0, H20 I H2 SECOND STAGE 'CONDENSATE TO i H«. HEAVY WATER i i PLANT 1 (~3OOO ppm ELECTROLYSIS CELLS DEUTERIUM) ANODE | CATHODE COMPARTMENT | COMPARTMENT

Fig. 5.1: Block diagram of the Combined JElectrolysis Catalytic jixchange-Heavy Water Process (CECE-HWP) for~recovery of by-proHuct heavy water from electrolytic hydrogen. 30

75 % / /

13 ~/'Hz FROM /' 20 /NATURAL / 50% GAS » oo

o 10

i 1980 1990 2000 2010 2020 Year

Fig,. 6.1: The cost of hydrogen derived from natural gas assuming natural gas tracks the "world oil price" of $38 per barrel at (a) 75% and (b) 50%. The world oil price is assumed to escalate at 4% per annum in constant 1980 Canadian dollars. o

1980 1990 2000 2010 2020 Year

FROM NATURAL '

^1 SMALLER iT^ UTILITIES

ELECTROLYTIC H2

LARGE UTILITIES

I I . , 1980 1990 2000 2010 2020 Year Fig. 6.3: Electrolytic hydrogen cost estimates assuming: (a) the 1981 unipolar technology with an electricity cost of 2^/kWh, i.e., Reference Cost of $9.81/GJ; (b) a fluctuation in the Reference Cost of 20% (see text for reasons) and (c) zero escalation in the electricity cost in real 1980 Canadian dollars. For comparison, cost projections for hydrogen derived from natural gas and coal (i.e. Fig. 6.2) are also included. 30 7 7

wz FROM /MA NATURAL 20

4 o o 4 c ? ELECTROLYTIC H2 t. XI - LARGE UTILITIES HEAVY WATER CREDIT

\ WITH HEAVY WATER AND OXYGEN CREDITS

I i 1 1 1 1 1 I I 1980 1990 2000 2010 2020 Yemr

Fig. 6.4: The effect on the lower cost estimate for electrolytic hydrogen of (a) the net heavy water by-product credit (horizontal line at $6.60/GJ) and (b) the net-heavy water plus the oxygen by-product credit (horizontal line at $5.35/GJ). Each by-product credit is estimated to be $1.25/GJ of electrolytic hydrogen for a total of $2.50/GJ. The data of Fig. 6.3 are also included for comparison. 3687-H

LIQUID FUEL OPTIONS FOR 1900 $100 —

90 — ETHANOL FROM COST PER BARREL PRIME GRAINS 80- OIL EQUIVALENT (1980 DOLLARS) ETHANOL FROM / 70 — CROPS (SPECIAL - SITUATIONS) NEW HYDROCARBON FUELS FROM 60 NATURAL GAS AND COAL ELECTROLYTIC 50- METHANOL AND HYDROGEN ALCOHOL FUELS AND CNG FROM - ETHANOL FROM (This work) NATURAL GAS AND COAL WOOD WASTES 40 —

30 — NEW MARKETS FOR UNCONVENTIONAL OIL PROPANE AND 600 o RESIDUAL OIL oo 20

10 CHANGES IN FUEL SPECIFICATIONS AND REFINING PRACTICES

500 600 800 1000 1200 1400 1600 1800 2000 2200 -? LIQUID FUEL PRODUCTION RANGE OF REQUIREMENTS (THOUSANDS OF BARRELS A DAY)

Fig. 7.1: The liquid fuel options for Canada for 1990 as presented in Fig. 2 of reference 47 with the electrolytic hydrogen cost estimates of this work superimposed. It was assumed that the heavy water by-product would be realized (see text for reasons) but no credit has been included for the oxygen by-product of electrolytic hydrogen production (see Fig. 6.4). 20

SMALLER UTILITIES o ECTROLYTIC HYDROGEN LARGE UTILITIES WITH HEAVY WATER CREDIT

*—WITH HEAVY WATER AND OXYGEN CREDITS

I I i i i i I I i t 1980 1990 2000 2010 2020 Year

Fig. 7.2: The "world oil price" of reference 47 of $38 per barrel and the natural gas price at (a) 75% and (b) 50% of the "world oil price", assuming 4% per annum real escalation for the price of oil. The electrolytic hydrogen cost estimates of Fig. 6.4 are included for comparison. Hfflmon i a Methanoi OU Refining Synthetic Fuel

1980 2020 ear Fig. 8.1: The reference estimated hydrogen demand projections for Canada for the conventional uses as a chemical and for use as a fuel in stationary or transportation applications. The chemical use projections are based on data of reference 1 while the fuel use projection is based on the assumption of substituting 48,000 barrels per day of oil with electrolytic hydrogen by the year 2025. 120 CHEMICRL Rmmon f a 100 Methane 1 OH Refining Synthetic Fuel I 80 FUEL •co TOTAL 460B iI x 28

1980 1990 2000 2010 2020 Year Fig. 8.2: The higher estimated hydrogen demand projections for Canada for the conventional uses as a chemical and for use as a fuel in stationary or transportation applications. The chemical use projections are based on assumed increases in the growth rates (see text for reasons) of Fig. 8.1, while the fuel use projection is based on the assumption of substituting 200,000 barrels per day of oil with electrolytic hydrogen by the year 2025. Note the difference in the ordinate scales of Figures 8.1 and 8.2. GH GN 61.9V 60.8 60.2 100 -r250 400-

+ 50 + 200

300 -• 40 -• 150

30 200- - -- 100 20 100- -50 10

1980 1990 2000 2610 2020 Year Fig. 9.1: The electrolytic hydrogen demand projections for Canada for the reference (Fig. 8.1) and higher (Fig. 0.2) total hydrogen demand projections based on the assumptions that electrolytic hydrogen will compete with hydrogen derived from natural s^ (a) at $7.85/GJ for chemical uses and (b) at $3.17/GJ (see Fiy. "\2) for fuel uses. An energy bC=»le in terrawatt hours per annum based on a single cell voltage of 1.9 V (78% energy efficiency) is indicated on the extreme left. The installed electrolyser plant capacity which is required is indicated in gigawatts for a 0.8 and a 0.2 electrolyser plant capacity factor on the right hand side. - 113 -

APPENDIX A

AN EQUATION FOR CALCULATING THE COST OF ELECTROLYTIC HYDROGEN

A.I Introduction LeRoy and Stuar; presented an equation which deals separately with the various cost cerms which make up the total cost of electrolytic hydrogen. Their equation wai based on 1.49 V as the voltage corresponding to the higher heating value of hydrogen at 70°C. The value chosen here is 1.481 V which is based on a higher heating value of 63.317 kcal/mol* (A2) at 25°C. Also, a fifth and sixth term have been added to the LeRoy-Stuart aquation to account for the cost of compression from atmospheric pressure (0.1 MPa) to 3.45 MPa (500 psi), following the method of Darrow (A3) et al. The parametric equation is derived in terms of the total cost of hydrogen per gigajoule (GJ = 10^ J) of equivalent hydrogen energy based on the above higher heating value of hydrogen. The equation in general terms is given by the expression: [Al] C = Ci + C2 + C3 + C4 + C5 + Cs where C = total cosf of electrolytic hydrogen in $/GJ Ci = the capital cost component for cells and accessories C2 = installation-related costs C3 = rectifier costs C4 = electricity cost for electrolysis C5 = capital cost component for gas compression Cs = electricity cost for gas compression Each term is derived below. A.' Cells and Accessories Costs of an electrolyser are often expressed in terms of dollars par kilowatt of input power. This measure causes confusion, however, as the cost per kilowatt would be higher for the more energy efficient of two plants which have the same total capital cost and gas production. Furthermore, this way of expressing costs produces values which depend on the rated current density of operation. For example, two plants operating at the same voltage and at the same production rate (same power) but at current densities differ- ing by a factor of two, would seem to yield the s.?me capital cost per unit of hydrogen produced whereas, in fact, the plant op ...-ing at the higher current density would be half as large and therefore cost roughly half as much,

* 1 cal = 4.1868J - 114 -

assuming similar materials of construction. This latter argument applies equally to the other common practice of expressing costs in dollars per kilowatt-equivalent of hydrogen. Not surprisingly, this practice has led to conflicting cost estimates in the literature (A4-A6). The cost parameter first used by LeRoy and Stuart and more recently by Escher (A7) is xm defined as dollars per square metre of separator area. This factor, then, is directly related to the physical size of the plant; it is also related to x^, the cost per kilowatt of DC input power to the cells by equation [A2].

[A2] xm = Vrir/100xk

where ir and Vr are the rated current density (mA/cm^) and the unit cell voltage (volts) at the rated current density, respectively. Thus, if A is the total separator area expressed in square metres of a plant operating at ir, the total cost of electrolyser equipment would be equal to the product, A

Both X|( and xm are considered to include the costs of the complete electrolyser with accessories but excluding the rectifier and power conditioning systems. These accessories include all gas sub-systems (except compressors) and electrolyte conditioning sub-systems external to the electrolyser module as well as the necessary pumps, instrument and control facilities, maintenance equipment, valves and piping. The cost of a fraction, fj, of these accessories is independent of the current density at which the plant is to be operated. For example, the electrolyser modules may operate at a different current density, within reason, from the rated current density with only a change in the operating voltage. On the other hand, a fraction, (1-fl), of this equipment must be sized to the maximum gas flow which is planned. These items would include the piping and valves, the electrolyte circulation and cooling systems as well as the gas handling systems. If i is the operating current density (mA/cm^), then the equipment cost becomes:

[A3] Cost of Cells and Accessories = fixmA + (1-fi)xmAi/1r

= xmA A.3 Installation and Start-Up

Capital cost items of an electrolytic hydrogen plant in addition to "cells and accessories" include land costs, site preparation, suitable foun- dations, building and support structures, packing and freight, installation and contractor's fees, as well as start-up costs.

These installation related costs were treated by LeRoy and Stuart (Al) by assuming that they are a fraction, f2, of the cell and accessories cost, xmA. - 115 -

One-half of these installation related costs are assumed to be independent of i while the remaining half increases linearly with i, the operating current density. Thus, the contribution to plant cost is:

[A4] Installation Related Costs = 0.5 f2xmA + 0.5 f2xmA i/ir

= 0.5 f2xmA (1 + i/ir) A.4 Rectifier If XR and HR are the rectifier cost in dollars per kilowatt of AC input power and electrical energy efficiency (expressed as a fraction, not as a percentage), respectively, the cost of rectification is:

[A5] Rectifier Cost = i Vi AxR/100riR The operating current density, i, is used with its corresponding operating cell voltage, Vi (volts), since the rectifier must be sized for the maximum power load. Equation [A5] ignores the relatively small variations in n R as the power load varies. A.5 Capital Component of Hydrogen Cost A gas generating plant is usually not characterized by the total separator area, A, but rather to the rated production of the plant. From an energy point of view it is convenient to relate A in square metres to the production rate expressed as H gigajoules (GJ) energy equivalent of hydrogen per day: [A6] H(GJ/day) = 1.28 x 10~3 Ai Therefore, in terms of this production rate, the plant cost from equations [A3] - [A6] becomes: [A7] Total Installed Cost = (1.28xlO~3 ) -1 H {fiVi+( 1-fl)/ir3 xm

+ 0.5 f2[/ /r] loon

A certain fraction, K, of this cost must be applied annually to cover depreciation, operation (excluding electricity for hydrogen generation), maintenance, insurance and ad-valorem taxes. These components may be grouped together as a first approximation since capital recovery constitutes the major contribution. The factor K is thus a broadly defined capital recovery factor. If P is the plant capacity or plant utilization factor, then an electrolytic hydrogen plant producing H(GJ/day) of hydrogen will produce (365 PH)GJ per year. Thus a fraction K/(365 PH) of the total capital cost of the plant must be charged against each GJ of hydrogen produced. Note that since - 116 -

K is broadly defined here, this fractional charge will account for all capital and operating costs with the exception of electricity. Thus, equation [A7] may be rewritten:

[A8] Total Capital Cost ($/GJ) = 2.14 K ( [fi/1+(l-fi)/1r]xra

+ 0.5 f2 [l/1+l/1r]Xni + ViXR/100nR A.6 Electricity Costs The electricity cost of electrolytic hydrogen production is directly proportional to the cost of electricity, p ($/kWh),and the operating cell voltage, V-j. This cost is:

[A9] Electricity Cost = 187.5 V, p/nR The rectifier efficiency appears in this equation because electricity costs are expressed per unit of AC power by the supplier. Note that V-j and Vr are unit-cell voltages,!.e.,1^ 1.6-2.0 V, and not the total voltage applied across the terminals of a series of cells, since we have defined plant production in terms of total separator area, A.

A.7 Compression If the electrolyser plant being considered produces the gases at about atmospheric pressure, such as the Canadian unipolar system (A9) and the Norsk Hydro bipolar system (A8), we must include the cost of external compression.

Darrow et al. (A3) give a convenient expression for the horsepower rating of the piston compressor as a function of the hydrogen throughput. This information has credibility because the source is a compressor manufacturer. For compression from 0.1 MPa to 3.45 MPa (14.7 to 500 psi) this expression is: [A10] Horsepower of Compressor = 2.124 x 10'4 % where VD is the hydrogen production in standard cubic feet per day. Con- verting to GJ of hydrogen per day and to kW for compressor power, equation [A10] becomes: fAll] Compressor Power (kW) = 0.4711 V5 where V(j is expressed in gigajoules of hydrogen per day. Thus the fractional charge which must be applied to each GJ of hydrogen produced is: [A12] Capital Cost for Compression ($/GJ)

3 = (0.4771/365 P)KCxc = 1.29 x 10~ KCxc/P - 117 -

where KQ is the capital recovery factor including operating (excluding electricity) and maintenance for the compressors and xc is the cost in dollars per kilowatt of the compressors required.

From equation [All] the electrical energy cost for compression can be obtained as:

[A13] Electricity for Compression ($/GJ)

= 0.4711 x 1 x 24 p/nc = 11.31 where Hr, is the compression cycle efficiency. The conversion efficiency from electricity to shaft power has already been taken into account in equation [All] by Darrow et al. (A3). Combining equations [A12] and [A13] gives: [A14] Total Compression Cost ($/GJ)

3 = 1.29 x 10- KcxC/P + 11.31 p/nc A.8 Total Hydrogen Cost The total hydrogen cost in dollars per gigajoules equivalent of hydrogen is given by adding equations [A8], [A9] and [A14]: [A15] Total Hydrogen Cost ($/GJ)

= 2.14 K { [fi/i + (l-fi)/ir]xm 7 <

+ 0.5 f2 (1/i + l/ir)xm + Vi

3 + 187.5 V-jp/DR + 1.29 x 10" Kr,xc/P + 11.31 p/n c In terms of equation [1] in the text and [Al] here, this expression may be written as:

C ($/GJ) = Cj + C2 + C3 + C4 + C5 + CQ

where Cx = 2.14 K [f2/i + (1-fi)/ir)xm P

C2 = 2.14 K [0.5 f2 (1/i + l/ir)xm] P

C3 = 2.14 J< [ P - 118 -

C4 = 187.5 Vip/n R 3 C5 = 1.29xlO- Kcxc/P and Cg = 11.31 p/n Q The terms C\, C?, C3 and C4 are the respective contributions to total hydrogen cost of (a) the cells plus accessories, (b) installation and start- up costs including a building for the cells, (c) the installed rectifier and (d) electricity for electrolysis. The terms C5 and Cs, developed in this work, are the contributions to the total hydrogen cost of the gas compressors and the electricity for operating them, respectively, for compression from 0.1 MPa to 3.45 MPa. For electrolysers which are capable of operating at elevated pressures, terms C5 and C5 should be neglected. In equation [A15] no allowance has been made for the electricity required for electrolyte pumps in some bipolar designs, or for electricity losses due to internal shunt currents of the electrolyser [A9]. Electrolyte pumps are not required in the Canadian unipolar electrolysers and their shunt currents are negligible because the applied voltage is low (about 2 V per tank). - 119 -

REFERENCES IN APPENDIX A

Al. R.L. LeRoy and A.K. Stuart, in "Industrial Water Electrolysis", eds. S. Srinivasan, F.J. Salzano and A.R. Landgrebe, The Electrochemical Society, N.J. Vol. 78-4, 1978, p.117. A2. J.H. Kelley and E.A. Laumann, "Hydrogen Tomorrow: Demands and Technology Requirements", Report of the NASA Hydrogen Energy Systems Technology Study, JET Propulsion Laboratory Report No. JPL-5O4O-1, December 1975. A3. K. Darrow, N.Biederman and A. Konopka, Introduction to Hydrogen Energy, 2, 175 (1977). A4. J.B. Laskin and R.D. Feldwick, Recent Development of Large Electro- lytic Hydrogen Generators, First World Hydrogen Energy Conference, Proceedings Vol. 2, p. 6B-3, March 1976. A5. F.J. Salzano, C. Braun, A. Beaufrere, S. Srinivasan, G. Strickland and J.J. Reilly, Hydrogen for Energy Storage, Brookhaven National Laboratories Report No. BNL-2O931, January 1976. A6. W.J.D. Eschar and T.D. Donakowski, Int. J. Hydrogen Energy, 1, 389 (1976). A7. W.J.D. Escher, R.W. Foster, R.R. Tison and J.A. Hanson, Solar/Hydrogen Systems Assessment, Vol. II, part 2, Report No. 00E/JPL-955492, June 1980. A8. K. Christiansen and T. Grundt, in "Industrial Water Electrolysis", eds. S. Srinivasan, F.J. Salzano and A.R. Landgrebe, The Electro- chemical Society, N.J., Vol. 78-4, 1978, p.24. A9. R.L. LeRoy and A.K. Stuart, in "Hydrogen Energy Progress", eds. T.N. Veziroglu, K. Fueki and T. Ohta, Perganon Press, N.Y., Vol. 4, 1981, p. 1817. ISSN 0067 - 0367 ISSN 0067 - 0367

To identify individual documents in the series Pour identifier les rapports individuels faisant we have assigned *n AECL- dumber to each. partis de cette se>ie nous avons assign^ un numero AECL- a chacun.

Please refer to the AECL- number when re- Veuillez faire mention du numiro AECL- si questing additional copies of this document vous demandez d'autres exemplaires de ce , rapport

from au

Scientific Document Distribution Office Service de Distribution des Documents Officials Atomic Energy of Canada Limited L'Energie Atomique du Canada Limite'e Chalk River, Ontario, Canada Chalk River, Ontario, Canada KOJtJO K0J1J0

Price $7.00 per copy Prix $7.00 par exemplaire

10M-42