An assessment of solar hydrogen production using the mark 13 hybrid process

Int. J. Hydrogen Energy, Vol 10, No. 3, pp. 143-155, 1985.

0360-3199/'85 $3.00 + 0.00 Pergamon Press Ltd. ~) 1985 International Association for Hydrogen Energy.

Printed in Great Britain.

AN ASSESSMENT OF S O L A R H Y D R O G E N P R O D U C T I O N USING T H E M A R K 13 H Y B R I D PROCESS E. BILGEN* and R. K. JOELSt " Ecole Polytechnique de Montrcal, C.P. 6079, Succursale A, Montreal, Quebec, H3C 3A7, Canada and * Commission of the European Communities, Joint Research Centre, Ispra Establishment, 1-21020 Ispra (Varese), Italy

(Received for publication 25 October 1984) Abstract--An assessment is presented of hydrogen production using a dedicated central solar receiver system concept coupled to a Mark 13-V2 hybrid thermochemical process. The system which is capable of producing about 106 GJ hydrogen per year was developed at the conceptual level. The total irradiance at normal incidence was taken as a parameter and varied from 1500 to 2500 kWh m-2 y-' at a location with 30* latitude and 0.1 km altitude. The peak noon irradiance at normal incidence was taken as 0.95 kW m -2 and the mean total sunshine hours as 2333 h y-1. A flow sheet of the solar Mark 13-V2 hybrid process was developed to operate using the intermittent heat supply from the central receiver system and the continuous electric energy supply from outside. It was then evaluated using the models for the central receiver system, the solar receiver and the chemical process. It is found that for 2000 kWh m-2 y-' total irradiance at normal incidence, the overall efficiency of the solar Mark 13-V2 process is about 21% and that the cost of the solar hydrogen is about $52 GJ-'.

INTRODUCTION The Research Centre of the European Communities has been developing its sulphur-based hybrid thermochemical cycles for several years in view of producing hydrogen from non-fossil energy sources [1, 2]. Among many, the Mark 13 and Mark 11 hybrid cycles are the most developed and both have been tested either in bench-scale circuits [3] or will be tested in a technological circuit which is under construction [4]. Although these cycles were conceived to couple them with a high-temperature nuclear reactor, there is a growing interest to determine their performance and product costs when coupled to a high-temperature solar heat source. In fact, several studies have been published recently on similar cycles coupled to a high-temperature solar heat source [5, 6, 7]. The purpose of the present system study is to evaluate the performance of Mark 13-V2 hybrid cycle coupled to a central receiver solar system. The specific objectives are: • to determine the requirements for a central receiver system for supplying heat to the thermochemical cycle; to evaluate its performance; • to design a conceptual flow sheet for the solar Mark 13-V2 cycle; to evaluate its performance; • to carry out cost and economic analyses for the determination of the solar hydrogen costs.

the remaining hours; this is the ideal case of the operation of the chemical process, however, it is the most difficult since large amounts of high temperature thermal energy must be stored successfully. (ii) the thermochemical process is run intermittently: in this case the high-temperature solar energy is directly used in the process. The hydrogen can be produced at the same time or, if desired, at a later time. In the latter case, some chemicals produced during the sunshine hours should be stored in order that the hydrogen producing electrochemical section can be operated later on. This operation may be advantageous when off-peak electricity can be used during the nighttime to produce hydrogen. (iii) the thermal section of the process is run intermittently and the electrochemical section continuously (this is similar to the case ii), however, the thermal section of the process should be able to produce the necessary chemicals in the amount required for the electrochemical section to operate 24 h a day. The first option is trivial if the high-temperature thermal energy can be stored; the second and third options are of interest since the high-temperature solar energy will be stored in chemicals. The third option may be preferable to the second since by running the electrochemical section 24 h a day, the capital recovery will be better.

Three operational possibilities may be devised:

Process design

(i) the thermochemical process is run 24 h a day: in this case, the high-temperature solar energy is directly used during the sunshine hours as well as being stored in a thermal storage system to operate the process in

The block diagram of the solar hybrid process is shown in Fig. 1. It consists of the central solar receiver system coupled to a hybrid thermochemical process, which is split into two main sections: 143

144

E. BILGEN AND R. K. JOELS

CENTRAL J RECEIVER SYSTEM

H20"--~ ELECI'ROLYSER H2 4 - - 1 2t. I-dd 0PER.

I,

ELECTRICITY

Table 1. Main characteristics of Mark 13-V2 solar process

{ THERMOCHEMICAL

CYCLE DAYOPERATION

CHEMICAL I STORAGE

THERMAL ENERGY STORAGE

Fig. 1. Block diagram of the solar-thermochemical hybrid process. • a thermochemical process which runs during the sunshine hours and which produces the necessary chemicals by using the high temperature solar energy and some required chemicals. These chemicals are stored in the quantities required to run this section during the sunshine hours and to supply the hydrogen-producing section 24 h a day. • an electrolysis process which uses the chemicals stored from the day operation, water and the electricity from outside. This section is the hydrogen-producing section running 24 h a day; it also produces some chemicals which are stored for the day operation. The low-grade thermal energy required for this section may be supplied from the day operation

Plant capacity SO3 decomposition temperature SO3 decomposition pressure SO3 conversion rate H2SO4 concentration outlet tower 10 H2SO4 concentration outlet reactor 9 H2SO4 recombination temperature Fisher reactor 9 pressure Fisher reactor 9 temperature Condenser 11 temperature

0.912 x 106 GJ(H2)y -~ 1083 K 6 x 105 Pa 51.6% 98% 75% 500°C 15 x 105 Pa 165°C 30°C

The first two reactions are carried out by using solar thermal energy, during the day time. The final product of these two reactions is HBr which can be used directly or stored for later use. The third reaction is the electrolytic decomposition of HBr and is the hydrogenproducing step. The flow sheet of the Mark 13-V2 solar process is shown in Figs 2 and 3; Fig. 2 shows the thermochemical part corresponding to equations (I) and (2) and Fig. 3 to that of equation (3). The main characteristics of the solar process and those of the HBr electrolyser [8] are given in Tables 1 and 2, respectively.

Description of the solar process Process design criteria The assumptions for the solar-energy collection are based on the hydrogen production capacity and on the requirements of. the thermochemical process. These assumptions are as follows: (i) 1.4 x 106 GJ per year solar heat is collected in the central receiver system for 2333 h per year; this corresponds to about 6.4 h a day operation of the central receiver system coupled to the thermochemical process; (ii) the maximum temperature of the heat transfer fluid leaving the solar receiver is 900°C; (iii) the central receiver system supplies heat only during the day operation and no provisions are made to store the high-temperature heat and supply it later on; however, a small thermal storage system is envisaged for the smooth operation of the central receiver system. M A R K 13-V2 S O L A R CYCLE This sulphur-based hybrid cycle has the following three reactions [2]: H2504 ~ S 2 0 + 502 + 0.5 02 Br2 + SO2 + 2H20 ~ H2SO4 + 2 HBr 2 HBr --~ Br2 + H2 (electrolytic).

(1) (2) (3)

Day operation (Fig. 2). This section operates only during the sunshine hours. Bromine is fed from the chemical storage system C1 to the reactor 9 and H20 to the SO2 absorber, 26; the high-temperature solar heat is supplied to the reactors 13 to 20 and to stream 17. The major products of this process are HBr(g) which is stored in the chemical storage C2 as 48%w HBr in liquid phase and O~. Some chemical products in very small quantities are circulated from/to chemical storage systems C3-C5, however, they are not relevant to the operation of this section. As would be the case in the normal process, the heat matching technique is used to utilize to the full the Table 2. Main characteristics of the HBr electrolyser [8} Electrolyser capacity Electrolytic cell voltage Current density Electrolytic cell temperature Electrolytic cell pressure Electrolytes separation present (future) FIBr concentration, at the cell inlet HBr concentration, at the cell outlet Electrolyser efficiency Production rate

10206 Nm3(Hz)h-l 0.7V 2000 A m -2 373 K 30 x 105Pa 4.5 mm (2.5 mm) 55 w% 48 w% 98% 0.6 Nm3(HE)kWh-1

AN ASSESSMENT OF SOLAR HYDROGEN PRODUCTION FROM TO FROM C1 (~ C3

145

TO FROM C"~ CS i

rm

w~J

J

i

He

-1

" " T £ £"

He

:2:2

-- iI 'H,t ~,O~.5Oz-O~. ~ [ ~

'

,9

0

02

12 13 14 15-20

SO~.HIO

(~

I He850C

-- APPARATUS KEY --

H20 '====C>

<3===

,,

22 23 2.¢. 25

APPARATUS NUMBER

Br2 - SO2 REACTOR H2SO/. CONCENTR. H20 CONDENSER HZSO/. RECOMBIN HZSOL. BOILER HZSO4 DECOMPOSER SO3 CRACKING REACTOR SO/ COMPRESSOR SO2 CONDENSER S02 COMPRESSOR 502 CONDENSER

26 S02

ABSORBER

STREAM NUMBER

Fig. 2. Day operation flowsheet of the Mark 13-V2 solar process. ¢~=C> ~

HzO

~3

~

H20

rzTlr, r "FrZ'I Br2

"

.

I

====C>

(~PS

II

HBr

TO® FROM® TO@ -APPARATUS KEY1 Br 2 DIST. TOWER 2 CONDENS TOWER 1 3 REBOILER TOWER 1

P6~,

,f.8"/,w

HBr

i{!D

TO ( ~

APPARATUS NUMBER FROM@

I'~

STREAM NUMBER

/. 5 6 7

HBr ELECTR. CELL HBr - H2C CONDENS H2 WASHING TOWER H2 DRYING TOWER B H2 COMPRESSOR 2? H20-HBr MIXING TOWER

Fig. 3. Continuous operation flowsheet of the Mark 13-V2 solar process.

E. BILGEN AND R. K..IOELS

146

thermal energy produced within the section. The excess heat produced in the Brz-So2 reactor, 9, and in the H:O condenser, 11, are stored in the sensible heat storage system, Fig. 4; it is used, in part, in the electrolyser section and in part, for mechanical power production. The day operation section normally functions during 1/3 of the day (24 h) and it is maintained to operating condition during the remaining 2/3 of the day by supplying the necessary power which represents a loss. The power loss from this section can be estimated by using two different methods: (i) the empirical method - - the power loss is 0.5% of the total power exchanged which is estimated for this plant at about 280 MW; hence, the power loss will be about 1.40 MW; (ii) the detailed evaluation--the power loss is estimated from the detailed designs for the H~SO4 concentrator, the H2SO4 boiler and SO3 cracker. It is about 1.36 MW. In addition, the power loss from other parts is estimated to be 0.12 MW. Hence, the total power loss will be about 1.50 MW. Both estimates have the same order of magnitude; hence, 1.50 MW will be taken as a base to supply the necessary energy. Electrolyser section (Fig. 3). This section operates 24 h a day. 48% by weight HBr from the chemical storage C2 and 1-I20 are consumed to produce H: and Br2, the latter is being stored in the chemical storage C1. Some chemicals in very small quantities are either produced and stored in C3 and C5 or used from the chemical storage C4. TO

HEATING STREAM',5

The heat-matching technique is again used in this section; the thermal energy generated in the electroylser and that of the cooling stream 1 are converted to mechanical power. The heat required in the Br2 distillation tower, 1, and for the stream 15 is obtained from the heat storage H1, which is supplied from the day operation section. The electrolyser is basically run by the electric energy supplied from outside.

Thermal energy storage system After the heat matching, the excess heat available is 5.60 MW at 165°C from the reactor 9 and 58.65 MW at 171°C from the condenser 11, both in the day operation section (Fig. 2 and Table 3). Part of this heat is used in the continuous operation section: 1.85 MW to heat the stream 15 from 126 to 130°C and 5.53 MW in the reboiler 1 at 126°C (Fig. 3 and Table 4). The remaining power is converted to mechanical energy. Since this is the only cross-utilization between the day and the continuous operation sections, a thermal energy storage system consisting of a pair of hot and cold tanks is devised as shown in Fig. 4. A thermofluid such as "Gilotherme" is circulated at atmospheric pressure and each tank is about 8000m 3 to provide a 24 h a day operation either for supplying heat or generating mechanical power.

Surplus heat utilization The surplus heat is converted to electricity to be TO

FROM

FROM

P3

170.5 C

H2

~

® 171

® i{

C[

30C

165C COOLINGFLUID 30 C

Fig. 4. Thermal storage system (TES).

T

TO POWER CYCLE

147

AN ASSESSMENT OF SOLAR HYDROGEN PRODUCTION Table 3. Mark 13-V2 solar cycle energy balance 1 Apparatus No.

Power (MW) 24 h operation day operation

Apparatus

Required power for isothermal apparatus 13 H2SO4 boiler 3 Reboiler tower

89.32 5.54

Total group power Available power from isothermal apparatus 2 Condenser tower 1 5 HBr-H20 condenser 7 H2 drying tower 23 SO2 condenser 25 SO2 condenser 26 SO2 absorber 4 HBr electrolyser cell 9 Brz-SOz reactor 11 H20 condenser Total group power

Total group power

utilized in the electrolyser. The heat to electricity conversion efficiency is taken as 50% of a Carnot value with a sink temperature of 303 K: (4)

where rls is the conversion efficiency, Tn is the maximum temperature of the surplus heat and Tc is the sink temperature.

Electric energy consumption For 7000 h per year operation, the electric energy consumption by the electrolyser is 125.37 × 106 kWh; in order to maintain the necessary operating conditions in the day operating section, the electric energy required will be 7 x 106 kWh; the electric energy required for the various mechanical drives is 8.68 x 106kWh. The electrical energy generated from the power recovered amounts to 27.19 × 106 kWh. The net electric energy required will therefore be 105.18× 106kWh; if a 5.26 x 106 kWh loss is assumed, the total electric energy from outside will be about 110 x 106kWh per year.

423 126

89.32

5.59 0.32 0.01 6.64 0.63 0.00 13.24 5.60 58.65 19.16

Electrical power requirements 4 Hbr electrolytic cell 8 H2 compressor 22 SO2 compressor 24 SO2 compressor P1 P2 Circulation pump P3 P4 HBr + H20 feed pump P5

rls = 0.5 (Tnm Tc)/Tc,

5.54

Temp. (°C)

30 30 30 30 30 30 100 165 171

12.87

17.91 0.00 0.82 0.39 0.02 0.18 0.14 0.43 0.20 18.68

1.41

C E N T R A L R E C E I V E R SYSTEM (CRS) The CRS model developed earlier was used to evaluate the system performance and costs [6]. The design parameters, the optical performance of the system and the costs as evaluated for three irradiance values at normal incidence are shown in Table 5. The thermal and optical performance of the receiver was evaluated by using the model developed earlier [9]. The receiver has the following characteristics: • the ratio of diaphragm diameter to that of the cavity is 0.5, • the cavity length to diameter ratio is 1, • the overall heat transfer coefficient for the He receiver was estimated to be about 1000 W m - : K -1, • the receiver has an overall efficiency of 0.90 [10]. The coupling of the central receiver system with the thermochemical process is carried out as shown in Fig. 5. The thermovector He leaves the receiver at 900°C and circulated through the apparatus in the day operation section and returns to the receiver at 800°C. It

148

E. BILGEN AND R. K. JOELS Table 4. Mark 13-V2 solar cycle energy balance 2 Stream No. 28 ] 27 t 26 25 24 23 30 14 17} 15

lit 3 11 ~1 18 J 21 12 29

Stream or Apparatus

Power (MW) 24 h operation day operation 3.39 5.09 6.23 7.36 7.92 8.48 32.81 62.17 10.78

heating stream

H2SO4 decomposer heating stream

1.85

Total group power

1.85

Temp. (°C) inlet outlet

0.82 0.39 1.26 58.65 5.40 11,45 23.83 31.06

HzSO4 recombinator cooling stream Total group power

810.0 810.0 810.0 810.0 810.0 810.0 810.0 500,0 253.7 130.0

71.0 75.1 100.0 171.8 253.7 494.0 500.0 799.4

30.0 30.0 30.0 30.0 171.8 423.2 494.0 500.0

144.23

cooling stream condenser cooling stream

778.3 762.4 752.0 741.6 736.6 731.6 500.0 423.2 165.0 126.0

59.91

72.95

is circulated using a blower with an electric drive, which is a part of the central receiver system, As can be seen in Fig. 5, the dimensions of the solar hydrogen producing plant for 2000 kWh m -2 y-~ would be about 1.5 × 1.5 km.

1500m

!

|

= 2000 kWh.re'2 y "1

Table 5. Design parameters and costs of the central receiver systems

Parameter

¼

Direct irradiance at normal incidence 1500 2000 2500

Plant capacity (106GJ) Plant operation (h y-') CRS operating temp. (°C) Number of heliostats (7 x 7 m) Heliostat density Total land area (km2) Tower height (m) Receiver size (m2) Global optical performance Site facilities (MS) Collector system (MS) Tower and receiver (MS) Thermal storage, transport (MS) Master control, buildings Indirect costs (MS) Contingencies (MS) Spare parts (MS)

1.4 1.4 1.4 2333 2333 2333 950 950 950 10993 7679 5955 0.165 0 . 1 7 4 0.174 2.93 1.93 1.50 259 221 196 830 830 830 0.537 0 . 5 7 6 0,594 2.93 1.93 1.50 49.91 3 4 . 7 2 26,95 15.14 11.39 9,56 I 2.81 1.62 1.08 7.08 4.97 3,09 I 12.46 8.74 6,91 I 9.34 6.56 5.18 0.78 0.55 0,43

Total cost in current $ (MS) Total cost in start-up $ (MS)

100.45 185.80

7 0 . 4 8 55.70 130.30 102.60

/

,,,,

TOWER

T HERMOCHEMICAL PLANT

SOLAR R'ECEIVER

©

.

I I

H2SO& BOILER 8. SO3 DECOMPOSER

L

OT.ER

,

POINTS

} }

HzO ~ HZ mO~

THERMOCHEMEAL PLANT

Fig. 5. Coupling of the centrai receiver system with the Mark 13-V2 hybrid process.

Thermal energy storage/Reboiler tower 1

Thermal energy storage/heating stream 15

Cooling stream 21/heating stream 17

Cooling stream 18/heating stream 17

HzO condenser ll/heating stream 17

Cooling stream 29/I-I2SO4 boiler 13

H2SO4 recomb. 12/t-I2SO4 boiler 13

Cooling stream 21,/H2SO4 boiler 13

Cooling stream 29/I-I2SO4 decomposer 14

Cooling stream 21/H2SO4 decomposer 14

I 660.0 636.6 434.9 423.2 188.1 799.4 500.0 494.0 423.2 660.0 425.4 483.2 423.2 500.0 423.2 585.4 423.2 171.8 165.0 253.7 166.8 428.2 181.4 170.5 126.0 170.5 126.0

heating str. 28-23 30 Thermovector/ H2SO4 dec. 14 /H2SO4 boiler 13 [.heating str. 17 Cooling stream 29/heating stream 30

810.0 810.0 500.0 423.2 253.7 660.0 636.0 483.2 425.4 585.4 434.9 428.2 423.2 494.0 423.2 500.0 423.2 171.3 166.8 226.8 181.4 423.2 188.1 140.0 130.0 140.0 126.0

Temp. (°C) inlet outlet

Process step (primary/secondary)

26.4

23.1

241.0

65.9

5.6

114.1

73.6

22.1

196.6

6.41

161.3

A T (°C) (av.)

5.53

1.85

0.80

1.77

0.22

8.86

23.82

8.90

7.73

1.73

14.46

38.44 18.35 52.70 47.72 7.97

Power (MW)

St. Steel

St. Steel

Incol 800

St. Steel

St. Steel

Hastel C

lncol 800

lncol 800

Hastedl C

Incol 800

Hastel C

Material class

45

14

1

46

11

130

544

117

127

47

280

htex. surface (m z)

Table 6. Mark 13-V6 solar cycle process heat recovery, and cost information

124

124

686

37

19

67

43

75

60

36

51

Heat flux (kWm -2)

1222

1507

1954

755

1171

1500

680

1054

1577

1689

1173

Specific cost ($m -z)

0.059

0.024

0.002

0.038

0.014

0.214

0.407

0.136

0.210

0.084

0.339

Invest. cost (MS)

X ~D

z

0

0 0 m "x

,.~ t~

o > 7:

,.] owl

K

OO

> :Z >

150

E. BILGEN AND R. K. JOELS Table 7. Mark 13-V6 solar cycle process power disposable and cost information

Process step (primary/secondary) Condens. Tower 1/ cooling water HBr-H20 Condens./ cooling water H~ drying tower/ cooling water SO2 condenser/ cooling water SO2 condenser/ cooling water Cooling stream 19/ cooling water Cooling stream 32,/ cooling water Cooling stream 1/ cooling water H20 condenser 11/ cooling water Helium/ heating stream 17

Temp. (°C) inlet outlet

A T (°C) (av.)

Power (MW)

Material class

htex. surface (m:)

Heat flux (kW m -2)

10

5.58

St. Steel

163

34

326

0.053

10

0.32

C. Steel

9

34

236

0.002

10

0.02

Incol 800

0

28

734

0.000

10

6.64

C. Steel

194

34

236

0.045

10

0.63

C. Steel

18

34

236

0.004

25

0.82

St. Steel

83

9

326

0.027

26

0.39

C. Steel

13

28

236

0.003

27

0.62

St. Steel

21

9

326

0.006

27

20.67

St. Steel

2085

9

326

0.681

Hastel. C

44

179

4089

0.162

30 20 30 20 30 20 30 20 30 20 30 20 30 20 30 20 30 20

71.0 75.1 80 80 674.8 188.1

535.2 253.7

152.4

7.97

PROCESS E V A L U A T I O N Mark 13-V2 Solar Process shown in Figs 2 and 3 was then evaluated using the Optimo code [13]. Selected results are presented in Tables 3, 4 and 6 to 8. In both Tables 3 and 4, the results of the energy balance are grouped for the day and continuous operation sections, so that required power, available power, power requirements and heating/cooling possibilities can be identified easily for each section. Tables 6 and 7 present the results of heat matching for process heat recovery and power disposable within and between the two sections. They also present heat transfer, material and cost information on the heat exchangers. The mechanical work produced using the excess thermal power in various parts of the process is shown in Table 8. The conversion efficiency is calculated using equation (4). Except the power conversion system from

S p e c i f i c Invest. cost cost ($ m-'-) (MS)

the stream 18 which operates only day time, all conversion systems operate continuously to produce electricity for internal usage.

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 chemical engineering and industry [11]. The cost figures for various equipment relating to the central receiver system are based on the 100 MWe sodium design [12] and on the data from McDonald Douglas Astronautic [13]. User-supplied cost parameters are for heliostat, land, fixed cost, indirect costs, contingencies and spare parts.

Table 8. Power recovered by mechanical work production Apparatus or stream HBr El. Cell 4 Cooling str. 1 TES * Cooling str. 18" Total

Power (MWt) 13.24 0.20 18.96 3.62

* Day operation. ~-Thermal energy storage.

Temp. (°C) from to 100.0 129.8 140.0 253.0

30 30 30 171.0

Conv. eft. (%)

Power (MWe)

Prod. y-I 10° kWh

Cost (MS)

9.4 12.4 13.3 7.8

1.24 0.02 2.52 0.28 4.06

8.70 0.17 17.67 0.65 27.19

0.734 0.024 1.494 0.166 2.418

151

AN ASSESSMENT OF SOLAR HYDROGEN PRODUCTION

Thermal energy cost

Table 9. Cost elements and economic assumptions

The total capital cost is C, = ( Ch + G +

Element

Cw + C~ + C. + C. + C.i + C.

+ Che + Ce + Cr) (1 + In + Cn + Sp),

(5)

where C is cost with h = heliostat, l = land, w = wiring, tw = tower, r = receiver, p = p u m p , p i = pipe, s = storage, he = heat exchangers, e = electric power generating system, f = fixed charges and In = indirect cost, Cn = contingencies, Sp = spare parts. 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. The total investment at start-up is Csu = (1 + idc) (1 + res)rC,,

(6)

where idc is the interest rate during construction, re~ is the rate of price escalation, y is the construction time in years. The interest on the borrowed capital during construction, ioc is calculated based on a 6-month draw-down schedule, as idc = rdc (n + 1)/4,

(7)

where rd~ is the rate of interest during construction and n=2y. 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 is calculated from the initial operation and maintenance charge, yearly inflation and discount rates as

Heliostat cost Land cost Fixed costs (master control, buildings, roads, etc.) Indirect cost Contingencies Spare pans 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

Value $97 m-2 $1 m -2 0.10 IEC* 0.16 IEC 0.12 IEC 0.01 IEC 12% 10% 14% 10% 10% 3y 30 y

* IEC = installed equipment cost. COST M O D E L F O R T H E R M O C H E M I C A L PROCESS Various cost models are used to estimate the installed costs of various elements of the thermochemical process.

Heat exchanger cost The heat exchange network synthesis and the capital cost estimates are carried out by using the Optimo code [14]. The cost estimating procedure is based on a modified method which was originally developed by TPL/ ADES for the JRC [15].

yop

Process equipment costs

(1 + r,)Y (1 + rd)-~ O&MI = O(~¢..Miy= ~ yop

,

(8)

Z (1 + r~ y)

y=l

where r, is the inflation rate, rd is the discount rate and Yop is the total number of years of operation. The levelized busbar thermal energy cost is then

Ct, = F~C,~ + O&Mh,l Csu.h + O&Mb.t F,(1 - Lp)q

C,~,b,

(9)

where F~ is the fixed capital charge rate, Fp is the load factor, Lp is the parasitic load, q is the yearly production in GJ or in kWh.

Electric energy cost The levelized electric energy cost is calculated in a similar manner from equation (9). In this case the total capital cost includes the costs of equipment relating to electric energy generation. The cost elements and economic assumptions are shown in Table 9.

For the process equipment, excluding the H2SO4 boiler and the SOs cracker, the module estimating procedure developed by TPI./ADES is used [15]. A module is defined as the equipment used to perform a unit operation. In the TPL/ADES program 18 such units are identified. Each unit contains components and materials other than those normally seen explicitly on a conceptual process flow sheet. Such necessary elements are therefore included in the cost estimates. They may be internals, drives, thermal insulation, painting, piping and fittings, measuring and control instruments, civil and structural works, electrical works, etc. The preliminary design and cost estimates for the H2SO4 boiler, 14, and the SO3 cracker, 15-20, were carried out by the C E A for a full-size hydrogen producing plant [16]. This information was used to make the necessary conceptual flow-sheet in Fig. 2 and estimate the thermal performance and costs for the solar process which is about 1/3 of the full-size plant. The estimated costs for the chemical installation, the process solar adaptation, the process heat exchangers and the electric power generating systems (EPGS) are presented in Table 10.

152

E. BILGEN AND R. K. JOELS Table 10. Installed and grass-roots costs for chemical installation, and process adaptation

Chemical installation Apparatus 1, 6, 7, 9, 10, 26 Reactors 14, 15-20 H2SO4 boiler 13 Hot ducts Pump P6 Compressor, 22 Compressor, 24 Total

Battery limit (MS 1977)

Battery limit (MS 1981)

2.15 15.00 3.00 1.00 0.03 1.33 0.81 23.32

Grass-roots factor

Grass-roots (MS)

2.72 18.95 3.79 1.26 0.04 1.68 1.02 29.46

1.33 1.33 1.33 1.33 1.33 1.33 1.33

3.61 25.20 5.04 1.68 0.05 2.23 1.36 39.17

Process solar adaptation He heat exchanger adaptation Chemical storage tanks C1 C2 C3-C5 H20--HBr mixing tower, 27 Heat storage tanks, H1, I-t2 Pumps P1-P4 Pump P5 Total

0.23

0.29

1.11

0.32

0.41 0.61 0.03 0.26 0.68 0.88 0.18 3.28

0.52 0.77 0.04 0.33 0.86 1.11 0.23 4.15

1.33 1.33 1.33 1.33 1.33 1.33 1.33

0,69 1,03 0.05 0,44 1.14 1.47 0.30 5.44

Process heat exchangers EPGS

2.51 2.42

3.17 3.05

1.11 1.33

3.52 4.06

Electrical equipment cost The cost estimates for the HBr electrolyser, the transformer and the rectifier were based on those of a recent feasibility study [17]. The costs for an electrolyser system of about 6.7 MWe power were estimated in 1981 $ as" transformer/rectifier installation of transformer/rectifier electrolyser unit of 305 kWe installation of a unit

72.20 $ kW-1 54.87 $ kW -t 0.120 M$ 0.072 M$

56 units of 305 kWe were required for the solar Mark 13-V2 process and the unit cost estimates above were taken as a base without any modification. The estimated costs are shown in Table 11. Total cost calculations The total cost of chemical and electrical equipment is then calculated as C, = C,c (1 + In + Cn + Sp),

(10)

where C,c is the total installed cost. The total investment at start-up is then calculated by using equation (6). The levelized operation and maintenance costs are calculated using equation (8). The levelized cost of

hydrogen due to the investment, operation and maintenance of the thermochemical plant is then calculated as Ch,- CA (Fc + O&M) H '

(11)

levelized cost of hydrogen: CH = Ch, + C,e. q, + Ce" q__.__~ . H H '

(12)

where q, = 1.4 × 106 GJ, q, = 110 x 106 kWh and H = 0.912 × 106 GJ.

P A R A M E T R I C STUDY Two cost parameters, namely the capital charge rage, Fc, and the cost of electricity, Ce, and one physical parameter, the direct irradiance at normal incidence are taken as variable and a parametric study is carried out. The cost of solar energy in $ GJ -1, with respect to the capital charging rage, is shown in Fig. 6 for three irradiance levels. It can be seen that for a typical 20% capital charge rate, the cost of high temperature thermal energy varies from about $16 to $30 GJ -~. The cost of solar hydrogen in $ GJ -t, with respect to the direct irradiance level, is shown in Fig. 7 for various

AN ASSESSMENT OF SOLAR HYDROGEN PRODUCTION

153

Table 11. Mark 13-V2 solar cycle hydrogen production cost Battery limit (MS) Chemical installation Process heat exchangers Process adaptation Interest during const.

13%

EPGS (MWe) Transf. + rectif. (MWe) Electrolysers (MWe) Interest during const.

4.06 17.58 17.01 8%

Grassroots (MS)

Fixed cost (%)

29.46 3.17 4.15

39.17 3.52 5.44 6.26

25 25 25 11

9.79 0.88 1.36 0.69

3.05

4.06 1.65 10.75 1.15

15 15 15 11

0.61 0.25 1.61 0.13

Hydrogen plant investment Solar heat cost ($ GJ -1) Process heat required (GJ y-1 × 106) Electricity cost (mills kWh -1) Electr. required (kWh y-1 × 106)

72.00 21.2" 1.4 20.0 110.0

15.32

29.68 2.20

Total annual charges Annual prod. (GJ y-i x 106) Thermal efficiency?, % Overall thermal eff.:~, %

Ann. Char. (MS)

47.20 0.912 37.34 21.51

Hydrogen production cost ($ GJ -1)

51.75

* Typical value; see Fig. 6. 5"Excluding the solar energy collection efficiency. ~: Including the solar energy collection efficiency.

capital charge rates and various electric energy costs. It can be seen that for a typical 20% charge rate and 20 mills kWh -1 cost for electric energy the cost of solar hydrogen varies from about $63 to $84 GJ -1. It can be seen in Fig. 6 that the cost of high-temperature solar heat is almost a linear function of the other two parameters, namely capital charge rate and direct normal irradiance. Figure 7 indicates a similar functional relationship between the cost of solar hydrogen and the capital charge rate or between the cost of solar hydrogen and the cost of electricity. The relation between the cost of of solar energy and direct normal irradiance is however non-linear; this non-linearity is more pronounced with increasing capital charge rate. COST C A L C U L A T I O N U S I N G JRC M E T H O D AND COMPARISON Following the cost calculation method used at the Joint Research Centre, Ispra, the grass-roots of various sections, namely chemical installation, process heat exchangers, process adaptation, EPGS are calculated as shown in Table 10 [1, 18, 19]. A n interest rate during construction is then added at 13% for the non-electrical installation and at 8% for the electrical equipment sec-

tion. The annual costs are calculated by applying various fixed cost rates as shown in Table 11. For the case under consideration, the total investment for the grass-roots thermochemical plant is 72 MS and the annual charge is 15.32 MS. The cost of process heat and that of electric energy are added to find the total annual charge. For the solar heat cost, a typical value corresponding to 20% capital charge and 2000 kWh m -2 y-1 direct irradiance is taken from Fig. 6. F o r the electric energy cost, the typical value is 20mills kWh -1. Hence, the total annual charge is 47.20 MS for 0.912 x 106 GJ hydrogen production. This results in a hydrogen cost of $51.75 GJ -1. The thermal efficiency is calculated using the values in Table 11 and assuming a 38% conversion efficiency for the production of electric energy. It can be seen that the process thermal efficiency is about 37.34% excluding the solar-energy collection efficiency and 21.51% including it. These findings can be compared to those obtained earlier [6]. Using the same JRC method discussed above, the costs of solar hydrogen from the G A solar thermochemical process and the solar electrolysis unipolar 1983 technology are recalculated and shown in Table 12.

E. BILGEN AND R. K. JOELS

154

Table 12. Solar hydrogen cost comparison GA Thermochemical cycle

Chemical installation Process adaptation Interest during const.

Electrolysis unipolar (1983 tech.)

Grassroots (MS)

Fixed cost (%)

Ann. char, (MS)

101.4 44.6 18.9

25 25 11

25.35 11.15 2.09

13%

Electrolysers (MWe) Transformer + rectifier (MWe) Interest during const. Plant investment

164.9

Solar heat cost ($ GJ -1) Process heat req. (GJ y-1 x 106) Solar elect, cost (mills kWh-t) Elect. req. (kWh y-1 x 106)

Grassroots (MS)

Fixed cost (%)

92.3

53.73

0.15

8.06

8%

4.30

0.11

0.47

38.59

21.2" 2.5

58.03

8.53

53.00 189t 288.4

Total annual charges

54.51

91.59

63.04

Annual prod. (GJ y-1 x 106) Overall thermal eft. (%):]:

1.175 25.6

0.853 18.9

Hydrogen production cost ($ GJ -~)

77.95

73.90

* Typical value; see Fig. 6. t Typical value; see ref. (6). $ Including the solar energy collection. t.O LAT. ALT,

30 N 0.1 km

50 I

?,

LAT 30N ALT 0.1 km

DIRECT IRRADIANCE AT NORMAL INCIDENCE kWh. rn'2 y-I

30

1500

==

40

LAJ Z W n-

30

-

>. t.9 n~

CAPITAL

20

7~ 8

20 %

2500

10

0

0

5

10

15

CHARGE RATE

TYPICAL

8

VALUE

20

25

10 I .

30

CAPITAL CHARGE RATE . %

Fig. 6. Cost of high-temperature solar energy from central receiver system.

10%

I

1500

2000

2500

DIRECT IRRADIANCE AT NORMAL INCIDENCE kWh. m"Z.y 4

Fig. 7. Cost of hydrogen from the Mark 13-V2 solar process.

AN ASSESSMENT OF SOLAR HYDROGEN PRODUCTION

155

CONCLUSIONS

5. J. R. Schuster, et al., Solar hydrogen production via the sulfur/iodine thermochemical water splitting cycle, Proc.

In view of the results obtained, three conclusions appear.

D O E Chemical Energy Storage and Hydrogen Energy Systems, pp. 101-107. Washington, D.C. (1979). 6. C. Bilgen, et al., An assessment of hydrogen production using central receiver solar systems, Proc. 4th WHEC, pp.

(i) The solar hydrogen production using the central receiver system concept coupled to the Mark 13-V2 hybrid process, is feasible; the intermittent operation of the thermochemical part with chemical storage system can be coupled to the continuous operation of the electrochemical part of the process without too big a penalty either in process performance or in capital investment. (ii) The process efficiency is about 37% which results in an overall solar hydrogen production efficiency of about 21%. (iii) The typical cost of solar hydrogen is about $52 per GJ. When this is compared to those from two other processes, namely, solar-purely thermochemical process and solar-electrolytic process, it is seen that it is lower than those by 34 and 30%, respectively. Acknowledgements--Many fruitful discussions with G. Beghi,

A. Broggi, H. Dworschak, G. De Beni, P. Fiebelmann and J. Gretz in the course of this study are gratefully acknowledged. REFERENCES 1. E. Cazzaniga, (ed.), Hydrogen production from water using nuclear heat--Progress Report No. 8. Joint Research Centre, Ispra Establishment, Italy (1979). 2. R. K. Joels, Thermodynamic and engineering assessment of hybrid processes for the production of hydrogen with specific application to the Mark 13 process, Technical Report, EUR 7010 EN, Commission of the European Communities (1979). 3. D. Van Velzen, et al., Development, design and operation of a continuous laboratory scale plant for hydrogen production by the Mark 13 Cycle, Proc. 2nd WHEC, Ziirich, pp. 649-668 (21-24 August 1978). 4. Anon., Hydrogen production energy storage and transport, Programme Progress Report, No. 3906, Joint Research Centre, Ispra Establishment, Italy (JanuaryJune 1981).

1437-1452. Pasadena, California (13-17 June 1982). 7. L. E. Van Bibber, et al., Economic potential for hydrogen production using a solar powered thermochemical process, Proc. 4th WHEC, pp. 1583-1593. Pasadena, California (13-17 June 1982). 8. G. H. Schuetz, et al., Electrolysis of hydrobromic acid, Proc. 2nd WHEC, Ziirich, pp. 709-730 (21-24 August 1978). 9. J. Galindo, et al., Sur l'Interaction Rayonnement Solaire Concentr6--R6acteur Thermochimique, Rapport Technique, No. EP 81 R6, Ecole Polytechnique de Montr6al (F6vrier 1981). 10. J. Galindo, et al., Interface problems in solar-thermochemical hydrogen production, Proc. 4th WHEC, Pasadena, California, pp. 651-658 (13-17 June 1982). 11. M. S. Peters, et al., Plant Design and Economics for Chemical Engineers, McGraw-Hill, New York (1980) 12. T. A. Dellin, et al., A User's Manual for Delsol, SAND 79-8215 (1979). 13. B. E. Tilton, et al., Central receivers for cogeneration applications in Canada, MDC G9418 (1980). 14. A. Broggi, et al., A method for the techno-economic evaluation of chemical processes--improvements to the Optimo code, Int. J Hydrogen Energy 6, 25-44 (1981). 15. Anon., Process plant cost estimation, Tech. Report TPL TechniPetrol--ADES, prepared for the JRC (May 1977). 16. Anon., Contrat Euratom--Production Hydrog6ne, Rapport Final, Commissariat ~i l'l~nergie Atomique, Centre d'Etudes Nucl6aires de Grenoble (1979). 17. W. Gestrich, Durchf0hrbarkeits--Studie Mark 13A Prozess, Contract Report for the Joint Research Centre (1982). 18. Anon., Hydrogen, Programme Progress Report, January-June 1978, No. 3532, Joint Research Centre, Ispra Establishment, Italy (1978). 19. R. K. Joels, Comparison of methods for estimating hydrogen production costs, Technical Note No. 1.06.06.81.156 PER 521/81, Joint Research Centre, Ispra Establishment, Italy (December 1981).