An assessment of large-scale solar hydrogen production in Canada

Int. J. Hydrogen Energy, Vol. 8, No. 6, pp. 441-451, 1983.

0360-3199/83 $03.00 + .00 Pergamon Press Ltd. 1983 International Association for Hydrogen Energy.

Printed in Great Britain.

A N A S S E S S M E N T OF L A R G E - S C A L E S O L A R H Y D R O G E N P R O D U C T I O N IN C A N A D A E. BILGEN* a n d C. BILGENt * Ecole Polytechnique, Montreal, Canada; * Exergy Research Corp., Montreal, Canada

(Received for publication 5 November 1982) Abstract--This study presents an assessment on the hydrogen production using a central receiver system coupled to either an electrolyser plant or a thermochemical plant. Systems which are capable of producing 105 and 106 GJ per year thermal energy or about half of this as hydrogen were developed at four locations in Canada: Fort McMurray, London, Moncton and Victoria. For central receiver systems of 105 and 10 6 GJ per year thermal energy capacity, heliostat fields arranged to the north of the receiver and tower were developed. A code consisting of optical and thermodynamic performance models was developed to simulate the system. For chemical plants, both electrolysis and thermochemical, codes were developed to simulate their thermodynamic performances. Cost models were developed for each subsystem based on the data published in the literature. Two scenarios were used for the heliostat prices: the first with a limited time and production capacity and the second with a quasi-optimized production capacity and production time. Estimates for the costs of hydrogen were then developed. The results indicated that levelized thermal energy costs ranged from $17 to $ 55 per GJ, electricity costs ranged from $ 0.2 to $ 0.5 per kWh and hydrogen costs from $ 57 to $157 per GJ. NOMENCLATURE A

c, c,h G

Ch Ch, Ch, Ct Cn Co Co, C,

c, c,u Csu, b Csu, h

C,

c,c c,c~

c,h Ctiref Ctref

C~ Cw

Eo Fc F, fl, A H ndir Href

h In i iac i, Lp n

Area, azimuth Cost of electric power generating system Total hydrogen cost Cost of per GJ hydrogen produced Fixed cost Heliostat cost Cost of heat exchanger Levelized hydrogen cost Land cost Cost of contingencies Cost of tower pump Cost of pipe Cost of receiver Cost of storage Total investment at start-up Balance of plant capital investment at start-up Heliostat subsystem capital investment at start-up Capital cost estimate Thermochemical plant cost Cost of solar thermochemical interface Thermochemical hydrogen cost Cost of reference thermochemical interface Reference plant cost (thermochemical) Cost of tower Cost of wiring Direct irradiance at normal incidence Fixed charge rate Plant capacity factor Fraction of the cell and accessory costs Rated plant production in GJ per year Direct irradiance on horizontal surface Reference production (thermochemical) Enthalpy; rated plant production Indirect costs Operating current density Interest charges during construction Rated current density Total pipe length Day of the year

O&Mb, t O&Mh.i O&Mi O&M~ p Q q R RR

re r,s r~ Sp S1, $2,], $3, $4 .j Vi Vr W Xk xm XR

Levelized balance of plant O-M rate Levelized heliostat O-M rate Initial cost of operation and maintenance Levelized operation and maintenance rate Cost of alternating current electric power Heat input Annual energy production GJ per year or kWh per year Heliostat receiver distance in km Solar receiver reactor Yearly discount rate Escalation of prices Yearly inflation rate Cost of spare parts Storage systems Electrolyser voltage at operating current density Cell voltage at rated current density Work from the Rankine cycle Cost per kW of DC input power to the cells Cost parameter in $ per m ~ separator Rectifier cost Plant operating time

Yop Greek letters o~ Azimuth, scaling factor fl Scaling factor 6 Declination ?~att Attenuation efficiency r/R Overall efficiency r/R, Rectifier efficiency r/, Cycle efficiency Thermochemical process efficiency rl,c Latitude ~o Hour angle INTRODUCTION

T h e central receiver solar utility c o n c e p t is conceived to p r o v i d e various e n e r g y n e e d s of a c o m m u n i t y . It 441

442

E. BILGEN AND C. BILGEN

normally operates to produce low grade heat with sen- calculated from the direct solar irradiance on horizontal sible heat seasonal energy storage coupled to a district surface: heating system [1]. However, there are infrastructural, E, = Hdir/sin h (1) technological and economical problems relating the district heating system in Canada: where • large-scale, low-grade heat storage is not a wellestablished technology; sin h = sin 6 sin tp + cos t5cos q~cos o9 (2) • estimated costs of storage and distribution are discouragingly high; 6 = 23.45 sin[(2Jr/365)(284 + n)]. (3) • there is no experience and infrastructure for district heating system. The insolation was calculated by reading and analysAs a result, various alternatives to low-grade heat ing the direct irradiance data for a given location. production, storage and distribution were considered The data for four locations, namely Fort McMurray, and studied earlier, such as use of electricity, hydrogen London, Moncton and Victoria, were obtained from and hydrogen-rich fuels as a vector. As a further step the Atmospheric Environment Service, Toronto, to increase the energy utilization factor of a central Ontario in the form of derived hourly direct normal receiver solar utility system, various cogeneration and radiation on horizontal surface for a total of 10 years, total energy formats were studied [2-4], although in from 1967 to 1976. These data were read and analysed that case if the low grade heat is utilized for heating, and an insolation model for each location was obtained. similar problems discussed above were encountered. The model required for the simulation code included In this study, a detailed assessment of hydrogen pro- the mean monthly hourly irradiance at normal inciduction is presented using a central receiver system dence, the mean monthly daily irradiance at normal coupled to an appropriate chemical plant since hydrogen incidence, the mean yearly total irradiance a-t normal as an energy vector represents a solution to the above incidence, the peak noon irradiance at normal incidence problems in energy storage, transport and use. and mean total sunshine hours. In the following sections, the whole system which The typical year model for each site with daily irraconsists of a central receiver system and chemical plants diance at normal incidence, the yearly total irradiance will be considered; the subsystems considered are inso- at normal incidence and mean total sunshine hours for lation data analysis, optical performance of the central each site are shown in Table 1. receiver system, recewer performance, electric power For the design of the receiver and related compogenerating system, short-term high temperature thermal nents, the peak noon irradiance at normal incidence for storage system, electrolysis and thermochemical plants. each location was searched in the data. It was noticed that the data contained the following maximum peak noon irradiance at normal incidence for each site: Fort ISOLATION D A T A AND ANALYSIS McMurray: 1.018 kWm-2; London: 1.060 kWm-2; The direct solar irradiance at normal incidence was Moncton: 1.050 kW m-2; and Victoria: 1.010 kW m -2.

Table 1. Average daily irradiance at normal incidence (1967-1976), kWh m -2 day -1

Month

Fort McMurray Lat* = 56.65 Alt¢ = 0.6

London Lat = 43.03 Alt = 0.3

Moncton Lat = 46.1 Alt = 0.2

Victoria Lat = 43.65 Alt = 0

January February March April May June July August September October November December kWh m -2 y-1 Sunshine, h y-1

2.31 3.23 4.71 5.72 6.19 5.63 5.69 5.65 3.79 2.85 1.99 1.48 1500 3062

2.35 3.10 3.63 5.00 5.23 5.55 5.94 5.76 4.24 3.38 1.60 1.46 1448 2646

2,78 3.36 3.80 4.10 4.08 5.02 4.91 4.73 4.39 3.22 2.27 2.09 1323 2547

1.33 2.40 3.23 3.93 5.56 5.61 7.50 6.43 5.57 3.21 1.80 1.19 1480 2660

* Degree N. t Km from the sea level.

443

LARGE-SCALE SOLAR HYDROGEN PRODUCTION IN CANADA The cycle efficiency for a cycle with reheat is

C E N T R A L R E C E I V E R SYSTEM According to the present situation, the collection system consisting of heliostats, tower and receiver is the costliest system in a central receiver power plant. The investment of heliostats, tower and receiver including installation may represent 60-70% of the overall costs. The aim is therefore to find parameters for the heliostats and heliostat field, the tower height and the receiver configuration which can deliver the required thermal energy of the specified temperatures to the thermodynamic system at a minimum capital cost. The following parameters are of major importance and considered in this model: • Heliostat field layout • Cosine losses • Optical losses

• Shadowing effects • Field focus • Receiver losses

- - heliostat density - - slope - - heliostat reflectivity and quality of glass turbidity of the atmosphere between heliostats and receiver - - shadow - - blocking - - planeity, tracking errors flux distribution interception - - receiver aperture - - reflection, convection and re-radiation -

-

-

-

-

-

Heliostat density, slope and tower height are determined starting with initial values and searching for their optimum values with respect to shading and blocking of the worst-positioned heliostat group. Heliostat reflectivity is computed for a given thickness and quality of glass by a spectral analysis [5] or if the global heliostat reflectivity is supplied by the manufacturer, it is taken as given. The atmospheric attenuation between heliostats and receiver is computed using the following relation [6]: A = 0.6739 + 10.46 R - 1.70 R 2 + 0.2845 R 3

(4)

Watt = 1 - A / I O 0 .

(5)

Shadow and blocking are computed following the numerical procedure given in the literature [7]. Receiver losses are computed by considering the heat flux distribution, reflection and emission from the receiver surfaces and convection [5]. The errors due to imperfections are introduced together with the solar disk solid angle and receiver aperture is determined with respect to the interception losses.

~r=w/o

(6)

Q = ( h 2 - h6) + ( h 4 - h3)

(7)

w = (h2 - h , ) + ( h , - h , ) .

(8)

where

Points 2 and 4 indicate those at the turbine entrance; 3 and 5 are the terminii of the state point loci for the two expansions. The enthalpies h3 and hs are determined in a stage-by-stage computation, finding the terminal state of steam for any stage in terms of the initial state, pressure drop, dry stage efficiency and mean moisture content. The overall efficiency is then calculated as OR = C ~lr

(9)

where C is a correction factor to take into account the electrical and mechanical losses. The properties of steam are calculated using the relations given in refs. [9-11]. For powers greater than 10 MWe the overall efficiency of the electric power generating system is determined from the following correlations [12]: For 10 < P ~< 250 MWe ~R = 0.34146 arctan (0. 29937 P) - 0.12529 + 0.14061 × 10-4P.

(10)

For P > 250 MWe ~TR= 0.43425 + 2.9644 x 10 -s p.

(11)

COST M O D E L F O R C E N T R A L R E C E I V E R SYSTEM The individual capital cost models for wiring, tower and receiver, pump, pipe, storage, heat exchangers and electric power generating system are based on the methodology used in the chemical engineering industry [13]. The cost figures for various equipment relating central receiver system are taken based on the 100 MWe sodium design [12] and on the data from McDonald Douglas Astronautic Co. [4]. User-supplied cost parameters are for heliostat, land, fixed costs, indirect costs, contingencies and spare parts.

Thermal energy cost The total capital cost is

C,=(Ch + G + Cw + C~+ Cr+ Cp T H E R M O D Y N A M I C SYSTEM TO G E N E R A T E POWER A Rankine cycle has been assumed. Up to and including 10 MWe power generation, a detailed study on Rankine cycle efficiency including determination of an optimum reheat pressure is carried out (see, for example, [8]).

+ c,,,+ G + Che+ C,+ C~) x (1 + I, + Cn + Sp).

(12)

Based on the total capital cost estimate, a levelized busbar energy cost is estimated based on the total investment at start-up and the operation and maintenance charges.

444

E. BILGEN AND C. BILGEN

The total investment at start-up is Cs~ = (1 + iac)(1 + res)~Ct.

(13)

The interest on the borrowed investment during construction, iac, is calculated based on a 6 months drawdown schedule. The operation and maintenance charges are calculated as a levelized percentage of the capital cost which is split into heliostat and non-heliostat rates. The levelized operation and maintenance are calculated from the initial operation and maintenance charge, yearly inflation and discount rates as yop

E (1 q- re) y (1 q- rd) -y O&Ml

=

O~:~Miy=I yop

(14)

where P --- G~ is calculated from equation (15) for the case of electric energy production. T O T A L H Y D R O G E N COST A fraction (FCR) of the total installed plant cost can be applied annually to cover depreciation, operation and maintenance, insurance, taxes, etc. In this case, the cost of operation and maintenance is lumped with the other charges. If a hydrogen-producing plant operates 365 days per year with a Fp plant capacity factor, it will produce H = 365 Fph GJ hydrogen per year. Hence, the total hydrogen cost in $/GJ can be calculated from equations (16) and (17) as

E (1 + rd) -y

Che-

y=l

The levelized busbar thermal energy cost is then Cte = Fcfsu + O•Mh,lCsu,h

q- O&Mb,tCsu,b

(15)

Fp(1 - Lp)q Electric energy cost

COST M O D E L FOR E L E C T R O L Y S E R SYSTEM A detailed code is developed following the procedure given by LeRoy et al. [14]. The electrolyser chosen for this study is the 1981 unipolar electrolyser technology. The components of the cost of electrolytic hydrogen are: (i) capital component; (ii) operation and maintenance component; and (iii) electric power component. (i) Capital component of hydrogen cost

The parameters and their values for the electrolyser technologies are shown in Table 2. The values Xk and xR have been up-dated to 1981 dollars from 1977 dollars using the Marshall and Swift cost index [13].

The process chosen for this study is the General Atomic sulfuric acid-hydrogen iodine cycle. The overriding reason for selecting this cycle was that this is the only high efficiency, purely thermochemical cycle at the present. This process is being developed to produce hydrogen in a large-scale plant coupled with a helium-cooled high temperature nuclear reactor. The reactor is rated at a thermal energy output of 3345 MW, with a helium outlet temperature of 1283K. The plant produces about 11.2 × 106 normal m 3 per day hydrogen or about 39.5 x 106 GJ per year hydrogen at an overall process efficiency of 47%.

Solar-thermochemical process description

In terms of the rated plant production, the total cost is given as

Ceh = 777 H{[f~/i + (1 --fl)/ir] X,, + 0.5fz[1/i + 1/ir]X,, (16)

(ii) Operation and maintenance component

A process configuration at the conceptual level that utilizes solar energy to drive the sulfur-iodine cycle as a continuous process was carried out by General Atomic Company [15]. The difficulty in coupling a solar heat source to a thermochemical cycle is in devising the system in such a way as to eliminate the problems relating to the Table 2. Parameters used in the electrolyser technology

A per cent of the total capital charge is usually assumed in calculating the cost of operation excluding power and maintenance of the plant. This is estimated to be between 10 and 12% of the capital charges. (iii) Electric power component The cost per GJ hydrogen produced is given by Cep = 186 V,P/~R,

(18)

T H E R M O C H E M I C A L PROCESS

The levelized electric energy cost is calculated in a similar manner from equation (15). In this case, the total capital cost includes the costs of equipment relating electric energy generation.

+ V, xR/IO0 r/R,}.

FcCeh H +Gp.

(17)

Parameter fl f2

xk ($/kW DC) xR ($/kW AC) ir (mA cm-2) Vr(V) r/R,

Unipolar 1981 0.9 0.45 150.6 83.7 134 1.82 0.96

LARGE-SCALE SOLAR HYDROGEN PRODUCTION IN CANADA time-varying solar heat input as it requires a 24 h a day chemical plant operation. A thermochemical process may be best to suit the solar input variation since usually many intermediate products can be readily stored in the required amount for use later. The simplified process flow-sheet for a possible system arrangement with the General Atomic sulfur-iodine cycle is shown in Fig. 1. With reference to Fig. 1, the low temperature solution reaction in the main reaction R is carried out 24 h a day producing H2SO4 and HI. The H2504 is stored in S1 and during solar system operation is pumped from the storage, preheated in E l , and is then decomposed in a high temperature solar receiver-reactor, RR. The decomposition products SO2, H20 and 02 are then cooled with the incoming H2SO4 in E l , the oxygen and water are removed, and the SO2 is stored in $2 for use in the low temperature solution reaction. A heat carrier fluid, such as a eutectic salt, is heated at intermediate temperature in the receiver-reactor RR and the heat storage system $3 is charged during the solar system operation. The thermal energy collected is used in the steam generator E2 to provide work and for concentration and cracking of the HI in the reactor E3. This section is designed to operate 24 h a day either directly or using thermal storage, $3. Preliminary studies indicate no technical uncertainties and there is some industrial experience with the molten salt storage technology. For example, the draw salt, which is a 50% molar mixture of sodium nitrate and potassium nitrate, may be the heat carrier fluid and the storage medium. This material has good stability up to about 867 K with low vapour pressure. Hence, the storage temperature may be up to about 700 K. The solar-thermochemical process is divided in two main sections: (i) thermochemical process section and (ii) solar-thermochemical interface section. The solar-thermochemical interface section includes the solar receiver-reactor RR, the storage systems S1, $2, $3 and $4, the heat exchanger E1 and related equip-

ment, piping, pump, etc. The thermochemical process section constitutes the rest. COST M O D E L FOR T H E R M O C H E M I C A L SYSTEM (i) Thermochemical process section The detailed cost estimates for this cycle are not yet completed as the development and improvement of the process flow-sheet and engineering evaluation are being actively pursued [16]. An order of magnitude capital cost estimate was carried out by Lummus based on process flow diagrams and energy and material balances in 1976 [17]. The overall process thermal efficiency was then 41.1%. The capital cost estimated was $500559 × 106 for the plant size described earlier. The total investment cost of the thermochemical process based on 1981 prices and improved process efficiency would be ($ 500-559 x 106) (628/472) (0.414/0.47) = $ 586--655 × 106

where 628 and 472 are the Marshall and Swift cost indices for 1981 and 1976, respectively. A recent estimate of the installed cost of the process equipment was based on the new process flow diagrams and developed for each process area using equipment costs for similar conventional chemical plants [18]. The total direct capital cost was $ 900 x 106 in mid-1979 prices. The cost based on 1981 prices would be ($ 900 x 106) (628/577) ~ $ 980 × 106. A detailed cost estimate is highly desirable, however it is not the scope of this study. Therefore, the most recent estimate of $ 980 x 106 for a 40 x 106 GJ per year plant will be taken as a base in the development of cost of the thermochemical process. The thermochemical plant cost is then calculated based on the reference plant as

Ctc = Ctref( n / Hre,) a.

RR

445

(19)

(ii) Solar-thermochemical interface

HI

r

j 1-12

Fig. 1. Simplified process flow-sheet of the solar sulfur-iodine cycle.

The additional equipment required to couple the thermochemical process described earlier and shown schematically in Fig. 1 consists of the following: (1) high and low temperature receivers, receiverreactors; (2) heat exchangers; (3) power cycles; (4) pumps; (5) storage tanks (molten salt, sulfuric acid, H2S, SO2 solution, water). Installed equipment costs for a 1.35 × 106 GJ per year solar-thermochemical plant were estimated by General Atomic [19]. The total installed cost estimated was $ 44.1 million in August 1979 dollar or $ 47.3 million in 1981 dollars.

446

E. BILGEN AND C. BILGEN

The cost of solar-thermochemical interface can be calculated based on this estimate as

Ctci -~ Ctiref( H/Href) fl,

(20)

The total capital requirements are calculated from equation (13). The operation and maintenance costs are calculated using equation (14). The levelized hydrogen cost is then calculated as Ch, --

Fc Cth + Ot~M Cth H

Cte

(21)

+ --. ~7,c

COST, ECONOMIC AND FINANCIAL ASSUMPTIONS Two different scenarios were adapted for heliostat production and cost. Following [4], the first scenario assumes a 1983 time frame with a limited heliostat production facility. This facility would be capable of producing up to 5000 heliostats per year with a heliostat cost of $ 260 m -2. The second scenario is based on a 1990 time frame and assumes a 25000 heliostats per year production facility. In this case, the installed heliostat cost will be $126 m -2. These prices include installation and a nominal 8% fee, however they exclude

site-specific design work, and overall contingency allowances. The economical and financial assumptions for the cost and price calculations are shown in Table 3. RESULTS AND DISCUSSION The order of magnitude of various efficiencies for the systems considered is: Solar energy collection 0.60 Receiver 0.90 Electricity generation 0.40 Electrolysis 0.80 Thermochemical process 0.47 Overall solar-electrolysis 0.17 Overall solar-thermochemical 0.25 Cost estimates of the central receiver systems and chemical plants developed are presented in Tables 4 and 5 for 105 and 106 G J/year plants, respectively. These tables show two different scenarios for heliostat production and two different hydrogen-producing processes. Levelized unit energy costs from the central receiver-electrolyser plants and central receiver-ther-

Table 3. Economic and financial assumptions Item

Value

Land cost Capital discount rate Inflation rate Interest rate during construction Inflation rate during construction Escalation rate of cost of operation and maintenance Plant construction time Plant system operating life time Accounting life time

$ 2 m -2 12% 10% 14% 10% 10% 3 years 30 years 30 years

Table 4. System costs for 105 GJ per year system. Costs are in million 1981 dollars

CRS-electrolyser plants CRS (heliostat at $126 m -2) CRS (heliostat at $260 m-2) Electrolyser plant CRS-thermochemical plants CRS (heliostat at $126 m -2) CRS (heliostat at $260 m -2) Thermochemical plant Total costs CRS-electrolyser plants Heliostat $126 m -2 Heliostat $260 m-2 CRS-thermochemical plants Hefiostat $126 m -2 Heliostat $260 m -~

Fort McMurray

London

Moncton

Victoria

14.32 22.83 0.75

14.32 22.73 0.75

19.26 31.65 0.75

14.40 22.93 0.75

12.84 21.18 3.28

12.89 21.17 3.15

17.91 30.30 3.66

13.13 21.64 3.15

15.07 23.58

14.37 23.48

20.01 32.40

13.21 23.68

16.12 24.46

16.04 24.32

21.57 33.96

16.28 24.79

447

LARGE-SCALE SOLAR HYDROGEN PRODUCTION IN CANADA Table 5. System costs for 106 GJ per year system. Costs are in million 1981 dollars Fort McMurray CRS-electrolyser plants CRS (heliostat at $126 m -2) CRS (heliostat at $260 m -2) Electrolyser plant CRS-thermochemical plants CRS (heliostat at $126 m -E) CRS (heliostat at $260 m -2) Thermochemical plant Total costs CRS-electrolyser plants Heliostat $126 m-2 Heliostat $260 m-2 CRS-thermochemical plants Heliostat $126 m -2 Heliostat $260 m-2

London

Moncton

Victoria

120.0 209.5 6.8

107.06 185.8 6.8

100.2 170.6 6.8

114.8 199.5 6.8

113.9 203.5 21.2

87.7 153.7 21.2

93.6 163.9 21.2

107.6 191.3 21.2

126.8 216.3

114.4 192.6

107.0 177.4

121.6 206.3

135.1 224.7

108.9 174.9

114.8 185.1

128.8 212.5

mochemical plants are shown in Tables 6-9. The fixed charge rate for the levelized unit energy cost calculations has been taken as 10%. De-levelized costs for each site, for both chemical processes and two different scenarios are presented in Figs. 2-9. These figures show the cost of manufactured chemical fuel at the plant in the next 30 years in terms of inflated as well as real dollar. Relative costs of manufactured fuel with respect to thermal energy cost from fossil fuel are computed for both 105 and 106 GJ per year plants and are presented in Figs. 10 and 11, respectively. The cost of fuel oil in 1981 dollars has been assumed to escalate from the present day price of $ 20 per bbl. to the 1985 price of about $ 50 per bbl. at a constant rate, thereafter, the fuel escalation rate is taken as 13% in inflated terms or 3% in real dollar terms. The initial investment for the boiler and related equipment is taken as $ 225000 and $ 750000 for 105 and 106 GJ per year systems, respectively. The operation and maintenance are assumed as 1% of the installed cost. The overall efficiency of combustion is assumed to be about 70%. Study and analysis of irradiance data indicated that the sites in order of preference are London, Fort McMurray, Victoria and Moncton. Moncton has sig-

nificantly less irradiance and requires more heliostats to supply the required capacity. Due to high latitudes, heliostat fields are arranged at the north of the receiver tower. The field sizes range from about 1000 to 1500 heliostats for 105 GJ per year plant and from about 8500 to 10 000 heliostats for 106 GJ per year plant. The receivers are all high efficiency cavity-type receivers. In the case of the central receiver system coupled to the electrolyser plant the heat carrier fluid is steam. In the case of the central receiver system coupled to the thermochemical plant, the heat carrier fluid is the chemical elements used in the cycle. In all cases, the high temperature thermal storage system is reduced to a minimum and required only for a very short period of time. The results of this study for the sites considered indicate that the minimum levelized cost of hydrogen from central receiver solar systems will be in the order of $ 57 per GJ. The relative costs of hydrogen calculated as the ratio of costs of hydrogen and of fuel oil indicate that the cross-over points for solar hydrogen/fuel oil are from 10 to 26 years for 105 GJ plant and from 7 to 18 years for 106 GJ plant. At the lower limits, the cost of hydrogen and crossover points should be considered encouraging with

Table 6. Levelized cost of thermal energy in 1981 dollars per GJ Site Fort McMurray London Moncton Victoria

105 GJ per year 1983TF* 1990TF 38.71 38.68 55.36 39.54

* 1983TF = 1983 Time Frame.

23.45 23.55 32.73 23.98

10 6

1983TF 37.18 28.08 29.95 34.95

GJ per year 1990TF 20.82 16.03 17.11 21.14

448

E. BILGEN AND C. BILGEN

Table 7. Levelized cost of electric energy in 1981 dollars per kWh 105 GJ per year 1983TF 199OTF

Site Fort McMurray London Moncton Victoria

0.408 0.406 0.565 0.409

0.256 0.256 0.344 0.257

FORT McMURRAY IO‘ GJ YEAR SYSTEM

lo6 GJ per year 1990TF 1983TF 0.410 0.364 0.333 0.395

---

ELECTROLYSIS THERMOCHEMICAL

0.235 0.211 0.196 0.227

Table 8. Levelized cost of hydrogen from the CRS-electrolyser plants in 1981 dollars per GJ

Site

10’ GJ per year 1983TF 1990TF

lo6 GJ per year 1990TF 1983TF

Fort McMurray London Moncton Victoria

133.23 132.58 182.00 133.66

133.93 119.72 109.94 129.14

86.07 86.06 113.40 86.41

79.65 72.18 67.37 77.17

Table 9. Levehzed cost of hydrogen from the CRS-thermochemical plants in 1981 dollars per GJ

Site

lo5 GJ per year 1983TF 1990TF

lo6 GJ per year 1983TF 199oTF

Fort McMurray London Moncton Victoria

117.82 116.30 157.34 118.12

102.68 82.68 86.66 97.30

85.37 84.11 109.18 85.03

I@ GJ/YEAR ---

94

67.87 57.04 59.33 67.91

1990

respect to fossil fuel use and more favourable sites should be studied further to make the solar-hydrogen more competitive. CONCLUSIONS An assessment on the hydrogen production using central receiver system coupled to either an electrolyser plant or a thermochemical plant is presented. The hydrogen is to be used as a vector in the resulting central

SYSTEM

I 2cca

TIME,

YEiy

Fig. 3. De-levelized costs of hydrogen in terms of inflated and real dollars for Fort McMurray and lo6 GJ per year plant.

ELECTROLYSIS THERMOCHEMICAL

I i990

2010

TIME,

ELECTROLYSIS ---THERMOCHEMICAL

I 2010

YEAR

Fig. 2. De-levehzed costs of hydrogen in terms of inflated and real dollars for Fort McMurray and 10s GJ per year plant.

1984

1990

2000

TIME,

2c

YEAR

Fig. 4. De-levelized costs of hydrogen in terms of inflated and real dollars for London and lo5 GJ per year plant.

LARGE-SCALE SOLAR HYDROGEN

50(

300

I LONDON,ON"~'I

: TLECT#OS'cAL

_J 0(Z)

/

1983TF ~

n,, i.iJ ,,"1 .Y

//

-

I

/

/

/

J J 0..'m

I/ /

/

-- ELECTROLYSIS -- THERMOCHEMICAL

/

/

/

/"

2OO /

INFLATED I~

1983TF ~ 1990TF ~ , ~ / "

_m

.,/I

449

I i MONCTON, N.B. I06 GO/YEAR SYSTEM

/

106 GO/YEAR SYSTEM ff ILl n ¢r"

P R O D U C T I O N IN C A N A D A

/

/

/ / /

/////

,

if)

0 I00 U g ILl h

100 J I..iJ h Z >(.r}

-- ~

~

......~~

REAL I~ ,

Z

o 1984

I 1990

0

2000

1984

2010

TIME, YEAR

I

o'

I

MONCTON, N.B

--" ELECTROLYSIS

i'r" hi

/

------THERMOCHEMICAL /

a.

INFLATED 8

1990TF ~

/

/

/

/ /

/

/

/ /

/ /

2010

I VICT~IA,B.~.

I

/

/

~

/

2000

Fig. 7. Deilevelized costs of hydrogen in terms of inflated and real dollars for Moncton and 10 6 GJ per year plant.

!'~ 300

, ' I f

/

/

/

I~TF ~

~200 J J

/

/

1990

TIME, YEAR

Fig. 5. De-levelized costs of hydrogen in terms of inflated and real dollars for London and 10 6 GJ per year plant.

300

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TIME, YEAR Fig. 6. De-levelized costs of hydrogen in terms of inflated and real dollars for Moncton and 10 5 GJ per year plant,

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1990

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TIME , YEAR Fig. 8. De-levelized costs of hydrogen in terms of inflated and real dollars for Victoria and 10 5 GJ per year plant.

450

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Fig. 9. De-levelized costs of hydrogen in terms of inflated and real dollars for Victoria and 106 GJ per year plant.

1984

1990

2000 T I M E , YEAR

2010

Fig. 11. Relative costs of hydrogen energy with respect to thermal energy cost from fuel oil for 106GJ per year plants. receiver solar utility concept to provide the energy needs of a community. The results for four different sites in Canada indicate that the levelized costs of hydrogen will be in the order of $ 57--68 per GJ for a plant which has a 106 GJ per year capacity and which is built in 1990s using massproduced heliostats. The costs are in the order of $ 80-100 per GJ for the same plant built in the mid1980s using heliostats produced in a limited production facility. 8.0

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Acknowledgement--This study was sponsored by The Central Mortgage and Housing Corporation, Canada. REFERENCES

8 "~o

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The four sites chosen in this study are typical urban centres in Canada located in various climatic zones. By considering the inherent advantages of using hydrogen as an energy carrier, more favourable sites, however far from urban centres, can be studied further to make the solar hydrogen more competitive.

I 2010

TIME , YEAR

Fig. 10. Relative costs of hydrogen energy with respect to thermal energy cost from fuel oil for 105GJ per year plants.

1. J. Wadsworth, Security and a price ceiling for home heating. Tech. Rep., Central Mortgage and Housing Corp. (1 August 1979). 2. E. Bilgen, A feasibility study on solar utility total energy systems (SUTES). ASME, 80-WA/Sol-22,pp. 1-8 (1980). 3. E. Bilgen and C. Bilgen, Hydrogen as a vector for central receiver solar utilities. Int. J. Hydrogen Energy 7, 977 (1982). 4. B. E. Tilton et al., Central receivers for cogeneration applications in Canada. MDC G9418 (December 1980). 5. J. Galindo and E. Bilgen, Sur l'interaction rayonnement solaire concentr6--r6acteur thermochimique. Tech. Rep. No. EP-81-R6, Ecole Polytechnique (February 1981). 6. C. N. Vittitoe and F. Biggs, Terrestrial propagation loss. Proc. ISES-American Section Meeting, Denver (August 1978). 7. R. H. McFee, Power collection reduction by mirror surface non-flatness and tracking error for a central receiver solar power system. Appl. Optics 14, 1493 (1975). 8. W. J. Kearton, Steam Turbine Theory and Practice, 7th edn. Sir Isaac Pitman, London (1958). 9. H. C. Schnackel, Formulation for the thermodynamic properties of steam and water. ASME Trans. 80, 959 (1958).

LARGE-SCALE SOLAR HYDROGEN PRODUCTION IN CANADA 10. W. G. Steltz and G. J. Silvestri, The formulation of steam properties for digital computer. ASME Trans. g0, 967 (1958). 11. J. H. Keenan and F. G. Keyes, Thermodynamic Properties of Steam. John Wiley, New York (1936). 12. T. A. DeUin and M. J. Fish, A user's manual for delsol. SAND79-8215 (June 1979). 13. M. S. Peters et al., Plant Design and Economics for Chemical Engineers. McGraw-Hill, New York (1980). 14. R. L. LeRoy et al., Unipolar water electrolyzers. A competitive technology Proc. 2nd WHEC, Zurich (1978). 15. J. R. Schuster et al., Solar hydrogen production via the sulfur/iodine thermochemical water splitting cycle. Proc. DOE Chemical Energy Storage and Hydrogen Energy Systems, Washington, D.C., pp. 101-107 (November 1979). 16. G. E. Besenbruch et al., Progress report on the development of the General Atomic thermochemical water split-

451

ting process. Proc. DOE Meeting on Thermal and Chemical Energy Storage, Washington, D.C., pp. 279-282 (October 1980). 17. J. E. Funk, A technoeconomic analysis of large scale thermoehemical production of hydrogen. Tech. Rep. EPRI EM-287 (December 1976). 18. K. E. Ekman, Production cost comparison of hydrogen from fossil and nuclear fuels and water decomposition. Proc. DOE Meeting on Thermal and Chemical Energy Storage, Washington, D.C., pp. 266--270 (October 1980). See also Chemical/hydrogen energy systems, Annual Rep. BNL 51512, Brookhaven National Laboratory (April 1982). 19. G. E. Besenbruch and K. H. McCorkle, Thermochemical water splitting with solar thermal energy. Final Rep., General Atomic Co. (February 1981).