PROGRAMA DE TERAPIAS INDIVIDUALES ESTRATEGIAS

The process heat required for the S–I process is provided in form of hot helium gas from the high temperature nuclear reactor and used in various steps of the process stream concentration and decomposition. The electricity is generated in-house by the same nuclear reactor and used to power the process electrolysers for stream concentration, gas circulators including the ones used in the helium gas loop to transport the heat from the nuclear reactor to the hydrogen process plant, the process fluid pumps and other utilities.

According to the energy and material balance of the S–I process, the gross thermal input is 175 MW(th), of which 5 MW(th) is input from the helium circulator gas compression heating of the heat transport loop that connects the reactor to the hydrogen plant. The net thermal input to the process is 168.9 MW(th). The net electricity consumption is 25.4 MW(e) accounting for all major usages of electricity including process electric utility (pumps and electrolyzer), and the helium gas circulation power consumption of the helium heat transport loop. Assuming a conversion efficiency of 48.8%, the hydrogen production rate is 30 655 Nm³/h (or 66.1 t/d). By-product is oxygen produced at a rate of 15 328 Nm³/h.

5.2. BOUNDARY CONDITIONS

TABLE 69. HEEP PARAMETERS FOR THE NUCLEAR PROCESS HEAT PLANTS

Cases Case A Case B Case C Case D

Canada China Germany Japan

Nuclear plant EC6 HTR-PM HTR-Modul GTHTR300C

Number of units 4 2 2 1

Thermal power (MW(th)/unit) 2084 250 170 600

Capacity factor (%) 90 90 90 90

Availability factor (%) 100 100 100 100

Thermal power for H2 plant (MW(th)/unit)

159.58 (heat pump)

250 117 170

Electrical power (MW(e)/unit) 629.88 0 21.3 204

Initial fuel loading (kg/unit) 87 552 2940 2396 7090

Annual fuel reloading (kg/unit) 126 000 1014 767 1773

Capital cost (M $/unit) 2243.77 250 599 547

Capital cost for electricity producing infrastructure (% of CC)

12.2 0 10 21

Fuel cost ($/kg) 137.2 4800 11 000 12 962

O&M cost (% of CC) 4.21 3.81 4.0 3.98

Decommissioning cost (% of CC) 14.75 4 10 0.52

Construction period (a) 6 3 3 4

Operation period (a) 30 40 40 40

Cooling before decommissioning (a) 0 2 2 2

Decommissioning period (a) 50 10 10 10

Refurbishment (a) 0 ? 1 1

Spent fuel cooling (a) 7 2 2 2

Waste cooling (a) 0 10 10 10

TABLE 70. HEEP PARAMETERS FOR THE HYDROGEN PRODUCTION PLANTS

Cases Case A Case B Case C Case D

Canada China Germany Japan

Hydrogen production plant Cu–Cl

(5-step) S–I SMR S–I

Number of units 1 2 2 1

Capacity factor (%) 90 90 90 90

Availability factor (%) 100 100 100 100

Production rate (kg-H2/s(per unit))

4.25 0.68 1.74 0.77

Thermal power consumption (MW(th)/unit)

638.36 250 117 170

Electrical power consumption (MW(e)/unit)

273.25 20 21.3 25.4

Capital cost (M $/unit) 400.23 100 203 143

Energy consumption cost (M $) 0 10.5 0 0

O&M cost (% of CC) 7.0 5.46 5.0 + 22 (CH4) 4.26

Decommissioning cost (% of CC) 10 5 10 0

TABLE 71. ECONOMIC INPUT PARAMETERS FOR HEEP SIMULATIONS

Economic parameter

HEEP default Algeria Argentina Canada China Germany India Indonesia Japan Pakistan Republic of Korea USA

Real discount

rate (%) 5 6 5 2 12 10 12 ^{No data}

provided 3 8 4 ^{No data} provided Inflation rate

(%) 1 2 9.5 2 1 1.66 5.65 0 5 2

Equity ratio

(%) 70 70 70 50 70 50 30 0 20 50

Borrowed capital ratio (%)

30 30 30 50 30 50 70 100 80 50

Capital market interest rate (%)

10 6 30 7 10 5.5 10.5 3 8 10

Tax rate (%) 10 1.5 10 30 10 28.2 30 1.4 0 10

Depreciation

period (a) 20 20 20 30 20 20 20 20 20 20

5.2.4. Explanation of input parameters A. CANADA

Four nuclear units of the Canadian EC6 type are being considered each producing a thermal power of 2084 MW(th). Assuming an electricity conversion efficiency of 32.2%, the net power generated is calculated as 629.88 MW for each unit. As the D2O coolant exit temperature is too low for use in the hydrogen production process, heat upgrading needs to be performed. Therefore, each nuclear unit is combined with a chemical heat pump which produces 159.58 MW(th) of upgraded heat at temperatures of 800 to 1000 °C, this heat being the process heat for the hydrogen plant. Capital costs for the nuclear system comprise both the cost of the EC6 (2000 M$/unit) and the cost for the heat pumps (243.77 M$/unit) totalling to 2243.77 M$/unit. Heat pump costs represent 12.2% of the total capital cost of the nuclear reactor. Nuclear fuel loading and reloading are high due to the power size, but specif ic fuel costs are low compared to the respective figures for HTGR fuel in the other cases.

The four EC6 units are connected to one hydrogen production plant that is expected to generate hydrogen at a rate of 4.25 kg/s, if the 5-step Copper–Chlorine cycle is applied.

Thermal power input to the H2 plant is from the four chemical heat pumps, a total of 638.36 MW(th). Of the total nuclear power output of 2519.52 MW(e), only a small fraction, 273.25 MW(e), is consumed in the hydrogen production process, while the remaining ~90%

of the electricity is directed to the grid. The capital costs for the hydrogen plant based on the given thermochemical cycle and production rate are estimated to be 400.23 M$.

B. CHINA

In the China case, the nuclear plant of choice is the HTR-PM. As the electricity generating reference variant is currently under construction in China, respective input data for the HEEP calculation could be derived from the report. Capital costs for the nuclear twin plant are estimated to be 500 M$ or 250 M$ per unit. The nuclear system here does not produce any electricity, all of the thermal power produced is directed to the H2 production system.

The hydrogen production system considered here is composed of two units based on the S–I cycle. Capital costs per unit are 100 M$. While the nuclear thermal power generated is completely consumed in the H2 plants. For the given hydrogen production rate, it includes already the fraction needed to generate the required electric power of 20 MW(e) per unit.

C. GERMANY

In the process heat HTR-Modul, the helium coolant is heated up to an average maximum temperature of 950°C and then passed through the steam reformer component where the high temperature heat is utilized to exchange heat with the process gas (methane plus steam).

While the process gas mixture is heated up to reaction temperature, the primary helium is cooled to ~680°C. This heat exchange thus consumes about 65 MW(th). The helium is then routed to the steam generator where part of the steam is diverted to the steam reformer as feedstock for the reforming process, while the remainder is used for generating 21.3 MW(e) of electricity. Assuming an electric efficiency of 40%, a total of 117 MW(th) is consumed in

the SMR hydrogen production system. In the 2-module plant, each nuclear unit has its own integrated steam reformer for hydrogen generation.

Capacity and availability factors of both nuclear and hydrogen plant are fixed at 90% and 100%, respectively. Nuclear fuel needed is 2396 kg as initial loading as well as 767 kg as annual reloadings. Specific fuel costs are assumed to be 11 000 $/kg. This value was derived from a specific fuel price of 6.37 $/MWh considering an annual heat production in the HTR-Modul of 170 MW × 8760 h/a × 0.9 = 1 340 280 MWh/a and an annual fuel demand of 767 kg/a.

Based on the assumption of 1.3 billion Euro for the two-module plant including two steam reforming plants, the per-unit price is 802 M US $ based on an exchange rate between Euro and US $ (1.23 US $ = 1 Euro). A partition of the total capital costs between nuclear heat production system and hydrogen production system was made as 75:25. This yields capital costs of 599 US $ per nuclear unit and 203 US $ per hydrogen unit. An estimated 10% of the nuclear capital costs are spent for the electricity generating infrastructure. Operation and maintenance of the nuclear plant are assumed to cost annually 4% of the capital cost. After the final shutdown, 10% of the capital costs are assumed to be spent on decommissioning.

Costs for the methane feed will be again attributed to the O&M costs of the steam reforming plant. A hydrogen production rate of 1.74 kg/s per steam reforming unit translates into a net annual production of 4.94×10⁷ kg of hydrogen of the unit. Doubling this mass, 9.88×10⁷ kg, is needed as annual methane feedstock to each steam reforming unit according to the following reaction of steam–methane reforming:

CH4 + 2H2O = 4H2 + CO2

With a net heat value of combustion of methane to be 50.0 MJ/kg, the above methane mass corresponds to an equivalent energy demand of 4.94×10⁹ MJ per year or 1.37×10⁶ MWh per year per steam reforming unit. Assuming a natural gas / methane price of 26.50 Euro/MWh or 32.60 US $/MWh, the total annual methane feedstock costs amount to 44.7 M US $ or about 22% of the capital costs of per unit of the hydrogen plant. Together with 5% of the capital costs for other (overhead) O&M, the overall O&M costs are 27% of the capital costs. The cost of CO2 certificates has been neglected here.

D. JAPAN

In the Japan case, the nuclear reference plant for cogeneration of heat and electricity is the GTHTR300C to be connected to a hydrogen production plant based on the S–I cycle. The GTHTR300C is designed for a thermal power of 600 MW(th), of which 170 MW(th) are decoupled via the IHX to the H2 production system, while the remaining thermal power is used to run a gas turbine for the generation of 204 MW(e) of electricity. Estimated capital costs for the nuclear plant are 547 M$.

The GTHTR300C is connected to one hydrogen plant with estimated capital costs of 547 M$.

Besides the 170 MW(th) of thermal power, the H2 plant also receives from the nuclear plant an electric power of 25.4 MW(e) to run the system. The remaining power of 178.6 MW(e) is given to the grid.

5.3. COUNTRY SPECIFIC CALCULATION RESULTS