# Electrochemical Hydrogen Production Powered by PV/CSP Hybrid Power Plants: A Modelling Approach for Cost Optimal System Design

^{1}

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## Abstract

**:**

## 1. Introduction

_{el}and found that the concept outperforms electricity generation with gas power plants (LCOE of 86 USD/MWh

_{el}). First economic estimations showed that electrochemical hydrogen production powered by a combination of PV and CSP could also be more economical than solely using one of the technologies [16]. A techno-economic analysis (TEA) of solar hydrogen production in Chile, compared PV to CSP powered electrochemical water splitting [17]. Although the study identified lowest hydrogen production costs for a PV powered alkaline electrolyser system, the authors also found that the most economic system would be a combination of PV and CSP power generation, if subsequent process steps are considered in the TEA, like hydrogen liquefaction or ammonia production. Summing up, previous research identified that combinations of PV and CSP power generation are often economically advantageous, also for electrochemical hydrogen production. However, previous work has focused on the techno-economic evaluation of PV/CSP systems based on existing plant design. The studies did not include a detailed energy system analysis of PV/CSP and electrolyser plant combinations. Therefore, it was not possible to consider different operational strategies and to size the different process units in order to minimize the overall product costs. Furthermore, it was not possible to investigate process variants in which PV surplus electricity can be stored as heat, by considering an additional electrical heater. Thus, there is still a need for further investigation of cost-optimal design of PV/CSP hydrogen production plants.

## 2. PV/CSP Hybrid Hydrogen Plant Design Optimization Model

#### 2.1. Concept Solar Hydrogen Production Plant

^{2}a and above [12]. The study includes two cost scenarios: a standard scenario with the PV and CSP costs of today and a cost outlook scenario which considers the possible cost reductions until 2030. For CSP the cost outlook scenario considers an increased receiver efficiency and a higher working fluid temperature which leads to a higher power cycle efficiency (assumption from [18], see Figure 2).

#### 2.2. Optimization Approach

^{2}. Further design variables are: the PV peak power, the AEL system nominal power, the steam turbine nominal power, the nominal power of the electric heater and the capacity of the thermal energy storage (see also Table 2). The overall plant design optimization approach is to minimize the levelized costs of hydrogen (LCOH) depending on these six optimization variables:

^{®}Global Optimization Toolbox (Natick, MA, USA) was used, which is recommended to be used first for non-smooth optimization problems [20]. Starting values have to be provided and optimization studies should be repeated with different initial values. Through varying the optimizations variables constraints, different studies were performed, for example by setting different upper boundaries for the thermal storage, the effect of higher electrolyser full load hours could be investigated. Table 2 provides global boundaries for the constraint variables, meaning that in some studies a different boundary was set but the given boundary was never exceeded. For electrical power, the maximum was set to 1 GW.

#### 2.3. Approach Modelling

#### 2.3.1. AEL Electrolyser System and Hydrogen Production

_{H2}):

#### 2.3.2. PV System Electricity Output

^{2}. The calculation was performed for a non-tracking system, since this study focuses on the lower range of PV investment costs (see Section 3.4) and already a high module efficiency was assumed. The module efficiency ${\eta}_{PV}\left(t\right)$ for the three locations is imported to the PV/CSP plant model. From the optimization variable PV peak power ${P}_{PV,Peak}$ the total PV module area ${A}_{PV}$ can be determined:

#### 2.3.3. CSP System Thermal Power Output

- CSP system receiver concentrated power input:

_{CSP,Rec}is limited by an optimization constraint (see Table 2). Thereby, the heliostat field stays in a size, in which the assumption of a field size independent heliostat field efficiency is reasonable.

- Molten salt receiver thermal power output:

#### 2.3.4. CSP Part and Steam Cycle Auxiliary Electric Consumption

#### 2.3.5. Power Cycle Electricity Production

#### 2.3.6. Energy Balance Thermal Heat Storage

#### 2.4. Operational Strategy of the PV/CSP Hybrid Hydrogen Production Plant

#### 2.4.1. Operational Strategy for AEL System Electricity Provision

_{el}was determined assuming a battery storage with 365 annual cycles and a discharge duration of 12 h. The cost of charging was set to zero, assuming that surplus electricity during daytime can be used for charging. ${P}_{add}\left(t\right)$ is introduced here to simplify the system for the overall design optimization without considering an operational strategy of the TES. In a more detailed analysis of a predesigned PV/CSP hybrid hydrogen production plant, an operational strategy of a combination of TES and a battery storage could be also considered, but this is beyond the scope of this work. Different hydrogen production concepts were analyzed by varying the optimization variables constraints.

_{el}, a typical power output of a CSP tower system.

#### 2.4.2. Operational Strategy Electricity Provision of PV/CSP

#### 2.5. Model Validation

_{TES}and nominal receiver power P

_{CSP,Rec}and a given nominal turbine power P

_{Turb}. The nominal power of the electrolyser plant P

_{AEL}was set to the turbine power. The conformity of the turbine full load hours in the model and the values from greenius was in the range of 99% and also the levelized cost of electricity (LCOE), which is also calculated in the model, was similar. To validate the correctness of the levelized cost of hydrogen (LCOH), a correlation was used, which determines the LCOH as a function of electrolyser full load hours and the price of electricity (see Equation (23) in Section 4.1.2). The reference lines in Table 9 provides electrolyser full load hours and LCOE data determined with the simulation tool. The data shows good agreement with the correlation in Equation (23).

## 3. Techno-Economic Assumptions and Equipment Costs

#### 3.1. General Techno-Economic Assumptions

#### 3.2. Product Cost Calculation Method

_{eff}and the lifetime of the plant n [25]:

_{H2,annual}with the following equation:

_{P,add}and specific cost of water ${c}_{H2O/H2}$per kg

_{H2}are also considered. Similarly, levelized costs of electricity (LCOE) can be calculated. For example, for PV with the annual sum of PV electricity produced ${E}_{el,PV,annual}$:

#### 3.3. Net Present Value of Hydrogen Production Plant

_{NP}is a suitable variable to characterize the economic feasibility of a project. The W

_{NP}is the arithmetic sum of the present worth of all cash flows during the total project time [26]. Assuming a constant annual cash flow F

_{C}the net present value can be determined from the total installed costs (TIC):

#### 3.4. Investment and Operational Cost Assumptions

#### 3.4.1. AEL System

#### 3.4.2. PV System and Electric Heater

#### 3.4.3. CSP, TES and Power Block

## 4. Simulation Results and Discussion

#### 4.1. Optimal PV, CSP/AEL System Combinations

#### 4.1.1. PV-AEL Hydrogen Plant Results

#### 4.1.2. PV/CSP-Hybrid-AEL Plant and Overall LCOH Results

_{H2}). In this case using only CSP as power source leads also to lower LCOH (4.14 USD/kg

_{H2}) compared to 4.23 USD/kg

_{H2}for a PV-AEL plant. The cost outlook scenario was designed in way to investigate the influence of a strong decrease in PV and a moderate decrease in CSP investment costs. In this case a PV-AEL plant reaches almost the same LCOH than a PV/CSP hybrid-AEL plant (3.09 USD/kg

_{H2}), while the LCOH of the PV/CSP hybrid-AEL is still the global minimum. For a PV/CSP plant configuration with constant hydrogen production higher electrolyser full load hours can be reached compared to a solely CSP powered system. Table 9 summarizes the electrolyser full load hour values and the levelized cost of electricity for the most promising plant configurations. LCOE for each technology separately are listed up and also the cost of electricity provided to the electrolyser system (LCOE to AEL), and the same value including the cost of additional electricity. The table illustrates the effect of overscaling the PV system, whereby higher electrolyser full load hours can be reached, but the final electricity costs are higher than the PV LCOE. Depending on the operational strategy, the PV/CSP hybrid concept leads to 4000–6900 electrolyser full load hours. The total cost of electricity provided to the electrolyser is in the range of 35 USD/MWh

_{el}(cost outlook scenario, fluctuating H2 production) to 66 USD/MWh

_{el}(standard scenario, constant H

_{2}production).

_{H2}. This additional cost would be in a stand-alone hydrogen plant the cost for a battery system which provides the electricity for standby operation. Providing electricity with costs lower than 150 USD/MWh

_{el}could further reduce the LCOH of the PV-AEL concept and result in the lowest LCOH in the cost reduction outlook scenario. However, also the concepts which include a thermal energy storage consider additional electricity costs (0.03–0.05 USD/kg

_{H2}). This value could be reduced with an optimized operational strategy of the TES, by adjusting the turbine power and avoiding that the TES is running empty.

#### 4.1.3. PV/CSP-Hybrid-AEL Plants Suggested Plant Design

#### 4.2. Economic Interpretation of the Results

_{NP}) was introduced. Figure 11 depicts the W

_{NP}depending on the revenue of the produced hydrogen for the three most promising concepts in the cost outlook scenario. For each plant design the W

_{NP}turns positive for hydrogen prices greater than the before determined LCOH. The PV/CSP hybrid plant with fluctuating H

_{2}production has the steepest slope and is therefore the mot economic design concept for hydrogen revenue prices greater than 3.09 USD/kg

_{H2}. The earnings from the PV/CSP hybrid concept with constant hydrogen production also exceed the value of the PV-AEL plant for hydrogen revenue prices greater than 3.50 USD/kg

_{H2}. Electrochemical hydrogen production will typically be coupled to other processes, except if a direct feeding to a pipeline system is foreseen. For example, for long-distance transport as liquid hydrogen (LH

_{2}) the electrochemical process will be coupled to a hydrogen liquefaction plant. Another option is to couple the hydrogen production to a fuel synthesis process like the Fischer-Tropsch process. In all these cases a more constant H

_{2}production is more convenient to reduce costs for hydrogen storage and other process equipment. Therefore, a process design evaluation including coupling to other processes will probably favour the concepts with constant H

_{2}production.

## 5. Conclusions and Outlook

_{H2}). Considering the mentioned minimum of PV costs in the cost outlook scenario results in almost equal LCOH for a PV powered AEL plant and a PV/CSP-AEL plant with fluctuating hydrogen production (3.09 USD/kg

_{H2}). However, the PV/CSP hybrid variant leads to a significantly higher project profitability, what we showed with an investigation of the net present worth of the investment.

## Author Contributions

## Funding

## Acknowledgments

## Conflicts of Interest

## Nomenclature

Abbreviations | Greek Letters | ||

AoI | annuity of investment | $\eta $ | energetic efficiency |

AEL | alkaline electrolyser | Technical Nomenclature | |

CAPEX | capital expenditure | $A$ | area (m^{2}) |

CSP | concentrated solar power | ${c}_{H2O/H2}$ | specific cost of water (USD/kg_{H2}) |

CRF | capital recovery factor | ${C}_{P,add}$ | cost of additional electricity |

DNI | direct normal irradiance | ${i}_{eff}$ | internal interest rate |

EPC | total major equipment costs | $P$ | power (J/s) |

FLH | full load hours | $Q$ | thermal energy (J) |

GHI | global horizontal irradiance | $\dot{Q}$ | rate of heat transfer (J/s) |

LCOE | levelized cost of electricity | Subscripts | |

LCOH | levelized cost of hydrogen | add | additional |

LCOS | Levelized cost of storage | aux | auxiliary |

LHV | lower heating value | av | available |

OMC | operating and maintenance costs | el | electric |

PV | photovoltaics | H2 | hydrogen |

TEA | techno-economic analysis | in | input stream |

TES | thermal energy storage | Sys | system |

TIC | total installed cost | ||

TRR | total revenue requirement | ||

USD | US Dollar | ||

WNP | net present worth |

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**Figure 2.**Scheme of the PV/CSP hybrid power plant powering an alkaline electrolyser (AEL) system for stand-alone solar hydrogen production. The six plant design optimization variables are highlighted in green.

**Figure 3.**Modelled CSP receiver efficiency depending on the load of the receiver. Values for standard and cost outlook scenario.

**Figure 4.**Modelled load dependent turbine efficiency. Values for standard and cost outlook scenario.

**Figure 5.**Comparison of different solar hydrogen plant operational concepts for a day with good solar irradiation. Results from the standard cost scenario for the location Ouarzazate, Morocco. (

**a**) PV powered H2 production; (

**b**) PV/CSP powered fluctuating H2 production; (

**c**) PV/CSP powered constant H2 production.

**Figure 6.**Operational strategy for time step calculation of PV/CSP hybrid hydrogen production plant.

**Figure 7.**Levelized cost of hydrogen (LCOH) depending on the PV peak power to AEL nominal power ratio for the location Ouarzazate in Morocco. The study was performed for the standard cost scenario and the cost reduction outlook scenario.

**Figure 8.**Levelized cost of hydrogen (LCOH) depending on electrolyser full load hours and levelized costs of electricity provided to the electrolyser (LCOE). Each simulation value for three locations and two costs scenarios was obtained by cost minimization for different stand-alone hydrogen production plants.

**Figure 9.**Share of process equipment costs (TIC and OMC) in the levelized hydrogen production costs for the most promising PV/CSP-AEL plant configurations in the standard and in the cost reduction outlook scenario. Plant location is Ouarzazate in Morocco.

**Figure 10.**Optimized plant design of PV/CSP-hybrid alkaline electrolyser plants (fluctuating or constant hydrogen production) for the two cost scenarios and the location Ouarzazate, Morocco. Nominal power of process equipment is provided.

**Figure 11.**Net present worth (WNP) of the best solar hydrogen production plants depending on the revenue of the produced hydrogen (cost reduction outlook scenario).

Location | Price Index (OECD) [18,19] | Considered Technology | Solar Resource: DNI/GHI (kWh/m ^{2}a) | Source Meteo Data |
---|---|---|---|---|

Freiburg, Germany | 100 | PV | 971/1137 | greenius |

Almeria, Spain | 84 | PV, CSP | 1918/1812 | greenius |

Ouarzazate, Morocco | 42 | PV, CSP | 2518/2123 | Meteonorm 6.1 |

Nr. | Optimization Variable | Description | Global Optimization Variable Constraints |
---|---|---|---|

1 | P_{CSP,Rec} | CSP molten salt receiver nominal input power (at DNI 900 W/m^{2}) | 0 or: 800 $\le {P}_{CSP,Rec}\le $ 1200 MW |

2 | P_{PV,Peak} | PV peak power (at GHI 1000 W/m^{2}) | $\le $1000 MW |

3 | P_{AEL} | Nominal power of alkaline electrolyser system | $\le $1000 MW |

4 | P_{Turb} | Nominal power of steam cycle turbine | 0 or: $\ge $50 MW |

5 | C_{TES} | Capacity of molten salt thermal energy storage | $\le $8000 MWh |

6 | P_{Heater,el} | Nominal power of electric molten salt heater | $\le $1000 MW |

Parameter | Value Source [6,10] |
---|---|

AEL System efficiency ${\eta}_{AEL,Sys}$ in % | 64.2 |

LHV_{H2} (kWh/kg) | 33.326 |

AEL operational range in % | 20–100 |

AEL standby consumption in % of nominal power | 1 |

Hydrogen outlet pressure (bar) | 20 |

Case | Condition | Correlation |
---|---|---|

CSP standby mode aux. consumption (no solar input) | ${P}_{CSP,Rec}\left(t\right)=0$ | ${P}_{CSP,aux}\left(t\right)=0.0005\cdot {P}_{CSP,Rec}$ |

CSP operating aux. consumption | ${P}_{CSP,Rec}\left(t\right)0$ | ${P}_{CSP,aux}\left(t\right)=0.0091\cdot {P}_{CSP,Rec}\left(t\right)$ |

Steam cycle auxiliary consumption | ${P}_{Turb}\left(t\right)>0$ | ${P}_{Turb,aux}\left(t\right)=0.05\cdot {P}_{Turb}\left(t\right)$ |

Reference year | 2018 |

USD/Euro exchange rate | 1.1815 |

Internal interest rate ${i}_{eff}$ | 5% |

Plant lifetime n (years) | 25 |

**Table 6.**Techno-economic data (TIC and OMC) for the AEL system, the PV plant and the electric heater for the standard cost scenario and the cost reduction outlook scenario.

Equipment | Parameter | Standard Scenario | Outlook Scenario | Cost Reduction |
---|---|---|---|---|

AEL plant | TIC (USD/kW) | 827 | 827 | 0% |

OMC, including stack replacement (USD/a) | 0.035 of TIC | |||

PV plant | TIC (USD/kW) | 760 | 340 | 55.3% |

OMC, including replacement and insurance (USD/kW a) | 14.08 | |||

Elec. heater | TIC (USD/kW) | 180 | 180 | 0% |

OMC elec. heater (USD/kWh_{th}) | 11.83 |

**Table 7.**CSP equipment costs for the standard and the cost reduction outlook scenario for the location Almeria in Spain and Ouarzazate in Morocco.

CSP Equipment | Location: Almeria, Spain Cost Index: 84 [18,19] | Location: Ouarzazate, Morocco Cost Index: 42 [18,19] | ||||
---|---|---|---|---|---|---|

Standard Scenario | Outlook Scenario | Cost Reduction | Standard Scenario | Outlook Scenario | Cost Reduction | |

Heliostat field (USD/m^{2}) | 114.76 | 83.11 | 27.6% | 87.88 | 65.27 | 25.7% |

Tower (10^{3} USD/m) | 78.48 | 62.78 | 20.0% | 48.24 | 38.59 | 20.0% |

Receiver (USD/kW_{th}) | 146.57 | 102.60 | 30.0% | 124.43 | 87.10 | 30.0% |

Thermal storage (USD/kWh) | 24.93 | 20.68 | 17.0% | 21.09 | 17.75 | 15.8% |

Power Block (USD/kW_{el}) | 785.12 | 708.45 | 9.8% | 693.56 | 25.62 | 9.8% |

CSP Equipment | Annual OMC |
---|---|

Heliostat field (USD/m^{2}) | 3.00 |

Tower (USD/m) | 1063 |

Receiver (USD/kW_{th}) | 2.95 |

Thermal storage (USD/kWh_{th}) | 0.24 |

Power Block (USD/kW_{el}) | 0.95 |

**Table 9.**Results of AEL-system full load hours and levelized cost of electricity (LCOE) for the most promising PV/CSP-AEL plant configurations in the standard and in the cost reduction outlook scenario. Plant location is Ouarzazate in Morocco.

Scenario/Configuration | FLH AEL (h/a) | LCOE PV (USD/MWh) | LCOE CSP (USD/MWh) | LCOE to AEL (USD/MWh) | LCOE to AEL + Cost P_{add} (USD/MWh) |
---|---|---|---|---|---|

Standard cost scenario | |||||

Only PV | 2751 | 37.92 | - | 43.85 | 46.26 |

Only CSP | 6163 | - | 62.87 | 62.87 | 63.90 |

PV/CSP hybrid fluctuating | 4463 | 37.92 | 69.03 | 55.07 | 55.67 |

PV/CSP hybrid constant | 6633 | 37.92 | 77.69 | 65.84 | 66.26 |

Outlook scenario | |||||

Only PV | 2973 | 19.83 | - | 24.87 | 27.09 |

Only CSP | 6337 | - | 51.02 | 51.02 | 51.94 |

PV/CSP hybrid fluctuating | 4039 | 19.83 | 58.69 | 34.48 | 35.07 |

PV/CSP hybrid constant | 6884 | 19.83 | 65.02 | 48.75 | 49.10 |

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## Share and Cite

**MDPI and ACS Style**

Rosenstiel, A.; Monnerie, N.; Dersch, J.; Roeb, M.; Pitz-Paal, R.; Sattler, C. Electrochemical Hydrogen Production Powered by PV/CSP Hybrid Power Plants: A Modelling Approach for Cost Optimal System Design. *Energies* **2021**, *14*, 3437.
https://doi.org/10.3390/en14123437

**AMA Style**

Rosenstiel A, Monnerie N, Dersch J, Roeb M, Pitz-Paal R, Sattler C. Electrochemical Hydrogen Production Powered by PV/CSP Hybrid Power Plants: A Modelling Approach for Cost Optimal System Design. *Energies*. 2021; 14(12):3437.
https://doi.org/10.3390/en14123437

**Chicago/Turabian Style**

Rosenstiel, Andreas, Nathalie Monnerie, Jürgen Dersch, Martin Roeb, Robert Pitz-Paal, and Christian Sattler. 2021. "Electrochemical Hydrogen Production Powered by PV/CSP Hybrid Power Plants: A Modelling Approach for Cost Optimal System Design" *Energies* 14, no. 12: 3437.
https://doi.org/10.3390/en14123437