Waste-to-hydrogen: Recycling HCl to produce H2 and Cl2

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Waste-to-hydrogen: Recycling HCl to produce H2 and Cl2 Rui Zhuanga, Xiaonan Wanga, , Miao Guob, Yingru Zhaoc, Nael H. El-Farrad, Ahmet Palazoglud ⁎

a

Department of Chemical and Biomolecular Engineering, National University of Singapore, Singapore 117585, Singapore Centre for Process Systems Engineering, Department of Chemical Engineering, Imperial College London, South Kensington Campus, London SW7 2AZ, UK College of Energy, Xiamen University, Xiamen, China d Department of Chemical Engineering, University of California Davis, One Shields Avenue, Davis, CA 95616, United States b c

HIGHLIGHTS

GRAPHICAL ABSTRACT

novel Cu-Cl cycle is designed as an • Aalternative to current hydrogen production.

process consumes waste HCl and • This produce high added-value H and Cl 2

• • •

2

products. Hot utility demand is estimated as 234.45 MJ/kg H2 from energy network integration. Hydrogen life cycle emission of the Cu-Cl cycle is 23% lower than the current process. Product cost of the Cu-Cl cycle is lower than the current hydrogen production processes.

ARTICLE INFO

ABSTRACT

Keywords: Cu-Cl cycle Waste-to-hydrogen Waste HCl Energy Environment Cost-benefit analysis

Coal-fired power plants are the most common form of power generation in many regions, which continuously produce waste heat and hydrogen chloride (HCl) flue gas. To address this issue, a novel Cu-Cl hydrogen production cycle is modeled to recycle industrial waste heat and exhaust HCl and to produce hydrogen, realizing the waste-to-hydrogen (WtH) process. To complement the process analysis, a gate-to-gate life cycle emission analysis and gate-to-grave cost-benefit analysis have been performed to evaluate the commercial feasibility and environmental impacts. The final results of the product cost and life cycle CO2 emission of this Cu-Cl cycle are 2.8 US dollars/kg H2 and 8.7 kg CO2/kg H2, respectively. Cu-Cl cycle offers an economically competitive option compared with the steam methane reforming (SMR) hydrogen production process if taking the benefit of Cl2 into account. The life cycle CO2 emission of the Cu-Cl cycle is less than other existing processes, as the process can consume a considerable amount of HCl gas, which is regarded as greenhouse gas as well. The proposed process is shown to be a promising alternative to conventional hydrogen production processes.

Abbreviations: AC, Alternating Current; CCGT, Combined Cycle Gas Turbine; CG, Coal Gasification; CHP, Combined Heat and Power; CS, Central Station; DC, Direct Current; DIST, Distributed; EDC, Ethylene Dichloride; EPA, United States Environmental Protection Agency; FCV, Fuel Cell Vehicle; GHG, Greenhouse Gas; GWP, Global Warming Potential; IPCC, Intergovernmental Panel on Climate Change; MS, Midsize Station; NREL, National Renewable Energy Laboratory; PEM, Proton Exchange Membrane Electrolysis; PV, Photovoltaic; PVC, Polyvinyl Chloride; SMR, Steam Methane Reforming; SOEC, Solid Oxide Electrolysis Cell; TI, Temperature Interval; VMT, Vehicle Miles Traveled; WtH, Waste to Hydrogen ⁎ Corresponding author. Tel.: +65 6601 6221. E-mail address: [email protected] (X. Wang). https://doi.org/10.1016/j.apenergy.2019.114184 Received 21 July 2019; Received in revised form 1 November 2019; Accepted 14 November 2019 0306-2619/ © 2019 Elsevier Ltd. All rights reserved.

Please cite this article as: Rui Zhuang, et al., Applied Energy, https://doi.org/10.1016/j.apenergy.2019.114184

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1. Introduction

Extensive research has been carried out on the production of hydrogen through Cu-Cl cycle, aiming to efficiently design the process through both simulation and experiments [25–30]. Recent researches are more oriented on the splitting of water, rather than HCl, as water is easier to obtain. However, clean water is considered as a resource as well, which is precious in some regions. In addition, the cost of thermal energy and electricity has not been sufficiently emphasized as a critical component in the product cost of Cu-Cl cycle. The potential to realize both cyclic hydrogen and chlorine economies motivates this work on the detailed study of a newly designed Cu-Cl cycle. We propose a combined thermo-electrolytic approach to realize the recovery of H and Cl, and provide a feasible solution to improve the thermodynamic efficiency. The objectives of this research are to:

Electricity, the most popular power format in the world, is being used everywhere, ranging from industrial pumps to household appliances. The total electricity energy generation of the world was 25.6 billion MWh in 2017 [1]. The main power generation methods available today include fossil fuel combustion, hydropower, nuclear, wind turbine, solar photovoltaic panel and others. Among them, coal-fired power plants accounted for near 40% [2] of global total power generation in 2016. Currently, the typical coal-fired steam power plants operate at 170 bars and 550 °C and the average heat efficiency is about 34% [3], while the latest technology can run at an efficiency of up to 47%. It is expected that the future ultra-supercritical plant can operate between 700 and 750 °C at an efficiency of 55%, but it is restricted by material limitations [4]. Seawater, as once-through cooling water, is pumped into a nuclear power plant (25,000–60,000 gallons producing per MWh power) [5] and discharged back to the ocean, which results in local high temperature in the adjacent water. The waste heat causes water to dissolve less oxygen and further induce severe marine ecological problems [6]. In addition, a considerable amount of HCl would be produced during coal combustion, which causes acidification concerns locally and globally. Emissions vary with the type of coal and technology. Generally, 0.01 kg of HCl will be produced during the combustion of 1-ton coal [7]. HCl is highly corrosive and thus represents risks to the metal structures and buildings as well as monuments made of limestone [8]. High levels of HCl gas dissolved in a water body, e.g., caused by accidental spills, can harm aquatic organisms. The high solubility of HCl gas leads to severe concerns on acid rains as a consequence of HCl atmospheric emissions; such acid rains can induce acidity of soil and aquatic environments above critical load thresholds. The waste heat can supply domestic heating if properly used, transported by insulated pipelines. A large combined heat and power plant (CHP) can run at a cycle efficiency larger than 60% [9,10], but the plant requires an extra investment on pipeline networks and equipment modifications. A CHP plant is more popular at high latitudes, but when it is summer or the power plant is located in a relatively warm region, the waste heat would be difficult to recycle. Besides, the CHP plant can only supply heat to district users, because long-distance thermal insulation pipe is not cost-efficient. For waste HCl gas, it has the potential to be recovered as valueadded products considering HCl is widely used as a cleaning agent, corrosive agent and catalyst [11]. The recovery of HCl presents a significant opportunity to enhance both environmental and economic performances of HCl-releasing systems. For liquid hydrochloric acid, the most thorough treatment is calcination [12]. High temperature forces water to react with ferrous chloride, and hydrochloride is released in a gaseous state. The common approaches to treat HCl gas are either absorbing by water to form hydrochloric acid or to use caustic soda to neutralize the acid before discharging to the environment [13–15]. However, both methods add little value and cause potential environmental impacts, such as acidic wastewater discharge and solid waste treatment. The cyclic hydrogen and chlorine economy is a potential solution to treat a large amount of HCl. A number of processes can be adopted for recovery of chlorine from HCl, such as electrolysis and catalytic oxidation [16,17]. Deacon process, based on the oxidation of hydrogen chloride [18–20], is a solution to recover HCl waste stream and produce chlorine gas, and it requires catalysts [21] to accelerate the oxidation process. The electrolysis approach [22] can turn HCl to hydrogen and chlorine directly through electrochemical reactions but requires an extensive amount of electricity [23]. Besides, the electrolyzer is sensitive to the mixture of gases in the input stream, resulting in product impurity issues. The thermochemical approach is considered as economically unfavorable mainly due to the high energy input [24]. With the improvement of metallic catalysts, the catalytic oxidation process could become thermodynamically favorable.

• Propose a new cycle to address the problem of HCl emission and • • •

reuse the waste heat in the industries, such as power plant and waste incineration station. Conduct a comprehensive analysis to evaluate the energy demand and gate-to-gate life-cycle GHG emission during this new production process, aiming to efficiently design further experiments for the process. Conduct a gate-to-grave cost-benefit analysis for hydrogen produced by Cu-Cl cycle and evaluate the benefit potential of it. Compare the cost and emissions with traditional fossil fuel (gasoline) and hydrogen produced by other technologies, and assess its potential as an alternative fuel for transportation end use. The novelties of this research are mainly to:

• Innovatively design the Cu-Cl cycle, which uses HCl as raw material, and produce hydrogen and chlorine. • Provide a new system that combines Cu-Cl cycle with power plant or •

waste incineration station, where generates both waste heat and HCl flue gas, and meets the principle of waste-to-energy. Separate the dominant cost of thermal energy and electricity from other costs. The main cost is estimated in a more precise way, while the secondary cost is estimated using the ratio method.

In the remaining part of this paper, Section 2 first describes the methodologies for the Cu-Cl cycle design and corresponding energy, environment, and cost-benefit analysis. The life cycle emission analysis considers the feedstock and process of hydrogen production, and the cost-benefit analysis considers the whole life cycle, including production, transportation, storage etc. Section 3 shows the detailed results and discussion of the design, followed by conclusions and future work in Section 4. The analysis in this work mainly focuses on the U.S. market, which may be different from other countries, due to technical, environmental and energy structure differences. If similar analysis in other regions is conducted, the parameters such as costs of feedstock, emission factors and energy prices need to be modified correspondingly. 2. Methodology The design of Cu-Cl cycle within the context and further energy, environmental and cost-benefit analysis are initiated in this section with detailed methodologies. 2.1. Cu-Cl cycle design 2.1.1. Current hydrogen production Hydrogen fuel has already received considerable attention as a clean energy source, but the cost of using hydrogen fuel was and will be the biggest issue for large-scale implementation. After decades of effort, several pathways have been identified to produce hydrogen with a reduced production cost. Table 1 [31] summarizes the energy resources 2

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Table 1 Energy resource and scale of hydrogen production.

Central Station Midsize Station Distributed Station

Natural Gas

Coal

Nuclear Energy

Steam reforming Steam reforming Steam reforming

Gasifier

Thermal splitting of water

Biomass Gasifier or direct conversion

and main pathways to produce hydrogen. Basically, large-scale hydrogen productions use SMR, which is the mainstream approach to produce hydrogen, while electrolysis is implemented on a distributed scale. Similar to other chemical industries, hydrogen production can reduce its cost by enlarging production scales, because equipment cost is not linearly related with capacity. In electrolysis hydrogen plants, a single electrolysis cell cannot be too large, and normally it should run several electrolyzers in parallel if the capacity is large. Renewable energy to produce hydrogen offers a low-carbon pathway with significant environmental advantage over that with energy-intensive grid-connected equipment, such as voltage and current transformers [32,33]. Electrolyzers can use direct current (DC) power directly, so the energy loss from inverter (DC to AC) and converter (AC to DC) can be recovered. Besides, renewable energy such as solar and wind has the problem of intermittent power generation profile and hydrogen production can consume excess electricity to balance the fluctuations and improve the power grid performance [34,35]. On the other hand, electrolysis process can consume excess electricity during peak periods, allowing for more stability of the grid, rather than building many expensive storage facilities. Although hydrogen is clean energy, the current production processes are energy-intensive [36] and release a large amount of CO2 emission. Chen [37] showed that about 9.79 kg GHG is released from production of 1 kg hydrogen using SMR, which is significantly higher than the GHG emissions (1.5–3.0 kg CO2-eq) from per gallon of gasoline production life cycle (drilling, pumping, refining, transportation, and electric pumps at the gas station). Despite that hydrogen production offers a cost-effective option than the gasoline, based on functional equivalent vehicle miles traveled (VMT). VMT method transfers one gallon of gasoline to a certain amount of hydrogen that can drive a fuel cell vehicle to travel the same distance as the internal combustion engine can do. In this work, 1 kg of hydrogen is assumed to be equal to 1.66 gallons of gasoline [31]. The total cost of hydrogen is similar to gasoline if considering storage and transportation. Moreover, the hydrogen fuel cell is very expensive, which causes hydrogen energy to barely have a price advantage. Hence, research is ongoing to develop alternative cleaner ways to produce hydrogen, and at the same time lowering the cost through various approaches such as efficient fuel cells and transportation networks.

(1)

2CuCl2(aq) = 2CuCl2(s)

(2)

2CuCl2(s) + H2O = CuO∙CuCl2 + 2HCl

(3)

CuO∙CuCl2 = 2CuCl + 0.5O2

(4)

Wind

Grid-Based Electric Energy

Electrolysis

Electrolysis

Electrolysis

In this process, hydrochloride, cuprous chloride and copper chloride are circulating, and the system will consume water constantly. The first step operates in an electrolyzer and needs electricity input. It can operate at a voltage of 0.6–0.7 V with a current density of 0.1 A/cm2. The second step is an energy-intensive drying step using a crystallizer or spray dryer. The third step is a multi-phase hydrolysis reaction that operates at 350–400 °C to produce copper oxychloride. Then the product goes to the last decomposition step and regenerates CuCl, which is a reactant of the electrolysis step [40]. In this study, the Cu-Cl cycle is redesigned as a 6-step process where a chlorine gas production loop is introduced, so that the overall reaction becomes the splitting of hydrochloride, which will consume waste HCl gas constantly. The HCl source can come from the flue gas of coal-fired power plants or waste incineration stations, so it can relieve the environmental problems caused by HCl emission. The whole cycle is a waste-to-hydrogen (WtH) process, i.e., using waste hydrochloride to produce hydrogen gas, and at the same time, no other waste or GHG produced during the process, theoretically. The pathways and schematic of this new cycle are presented in Table 2 and Fig. 1, respectively. In fact, H2 production (step 1) can be integrated with the electrolysis (step 2), then the HCl feed will react inside the electrolyzer, and decomposition (step 5) can be integrated with hydrolysis (step 4), so the CuCl2 from the electrolyzer will enter a high-temperature fluidized bed reactor and produce O2, CuCl, and HCl directly. Here, we divide it into more steps for a better understanding of the reaction path and a higher heat efficiency performance. Industrial processes with substantial generation of waste heat and HCl flue gas, such as coal-fired power plant, metallurgy industry [12,41], and solid waste treatment station [42,43], are suitable for the proposed Cu-Cl cycle combination. As Cu-Cl cycle offers a promising approach to recover HCl waste gas as value-added hydrogen and chlorine in contrast to the cost-inefficient HCl treatment, which requires extra expenses to remove HCl to meet emission standards. 2.1.3. H2 and Cl2 market Hydrogen price is still high compared with conventional fuels, but owing to the promising prospects and strong policy support in many countries, the hydrogen production and consumption increased significantly in recent years. Hydrogen is mainly demanded by industrial concerns, including ammonia, methanol, refineries, metal manufacturing, and other chemical processing industries, while the demand in other fields also keeps growing, such as electronics and food

2.1.2. Conceptual design of Cu-Cl cycle Cu-Cl cycle, combining thermochemical steps and electrolysis steps, is one of the alternative hydrogen production methods that no fossil fuel is involved, and it uses a group of reactions to achieve the overall water splitting, and finally producing hydrogen and oxygen. Basically, Cu-Cl cycle can be divided into 3-step, 4-step, and 5-step process and more. More steps enable higher heat efficiency [38,39] due to avoidance of unnecessary cooling or heating materials, but it requires higher equipment inputs to complete these extra steps. Therefore, the process design presents a trade-off between heat efficiency and equipment costs. A 4-step typical Cu-Cl cycle can be expressed as: 2CuCl + 2HCl = H2 + 2CuCl2(aq)

Photo-voltaic

Table 2 6-step Cu-Cl cycle pathways.

3

Step

Reaction

Temperature (°C)

Step 1 H2 Production Step 2 Electrolysis Step 3 Cl2 Production Step 4 Hydrolysis Step 5 Decomposition Step 6 CuCl2 recovery

2Cu (s) + 2HCl (g) = 2CuCl (l) + H2 (g) 4CuCl (s) + 2H2O (l) = 2CuCl2 (aq) + 2Cu (s) + 2H2O (l) CuCl2 (aq) + 1/2O2 (g) = CuO (s) + Cl2 (g) 2CuCl2 (s) + H2O (g) = CuO∙CuCl2 (s) + 2HCl (g) CuO∙CuCl2 (s) = 2CuCl (l) + 0.5O2 (g)

450

CuO (s) + 2HCl (g) = CuCl2 (s) + H2O (g)

100

25 25 375 500

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water during combustion. However, hydrogen cannot be obtained directly from nature and the production processes are energy intensive, leading to substantial GHG emissions. Here, the life-cycle GHG emission is introduced to evaluate the environmental impact more precisely by considering the gate-to-gate GHG emission, which means the analysis only focus on the process of making hydrogen product. There are some existing literature focusing on the energy and environmental analysis in Cu-Cl cycle [39,48–50]. We aim to perform process simulation in Aspen plus based on these efforts and cross-validate these results. The environmental impact criterion in this work is taken as the Global Warming Potential (GWP) by converting the GHGs to the single indicator, i.e., kg CO2-eq, using characterization factors. The GWP characterization factors of CO2 (Carbon dioxide), CH4 (Methane), N2O (Nitrous oxide) and HCl (Hydrogen chloride) are 1, 25, 298 and 0.89, respectively. The total GWP is calculated by:

Total GWP = Fig. 1. Schematic of the revised Cu-Cl cycle.

[(Emission amount )i × (GWP )i]

(5)

The life cycle allocation is based on the energy contents of gasoline and other co-products. The functional unit is defined as per unit VMT. The GWP characterization impact is expressed as kg CO2-eq/kg H2. Thus for conventional fossil fuels, GWP impacts are evaluated on a comparable functional unit-basis, i.e., 1 kg-H2 functional equivalence of VMT (1.66 gallons of gasoline) [31]. With consistent unit, we can visually compare the GHG emissions of different technologies and traditional fuels. As the production of hydrogen is an energy-intensive process, the energy and feedstock dominate total GHG emissions. As defined in Fig. 2, the system boundary includes the feedstocks and energy consumption during the hydrogen production process while excluding the consumables such as the proton exchange membrane in an electrolysis process [51]. For the cost-benefit analysis, a chemical industrial plant typically has two kinds of investment [52], i.e. fixed capital and working capital. Typically, the fixed capital cost accounts for 85% of the total capital cost, and the working capital cost accounts for the remaining 15%. Fixed capital is the investment for manufacturing and plant facilities, and working capital is that for initial ongoing operations. The production process also generates costs, such as the operating cost and the expenses for administrative cost and financing (interest). The breakdown of the total cost is shown in Fig. 3. The production cost of the typical Cu-Cl cycle has been studied in the existing literature [53–55], but these models need to be modified to make them more suitable for the new Cu-Cl cycle in this work. In addition, the cost of thermal energy and electricity have not been sufficiently emphasized as a critical role of Cu-Cl cycle. Transportation cost and storage cost are important to the total cost of hydrogen plant as well but complicated to estimate, so here we exclude these from product cost and calculate them separately to enable higher accuracy, and the rest is calculated by ratio estimation, referring to proportion information of a typical chemical plant. Due to the low technology readiness level (lab-scale) of Cu-Cl cycle based hydrogen production, no publicly available information can be found on industrial or pilot-scale operation data. Therefore, this part uses a ratio estimate method [56–58] by using existing data to estimate the cost of equipment. The ratio estimate formula is expressed as Eq. (6):

processing. Hydrogen fuel cell vehicle (FCV) is also becoming more popular. In the U.S., over 6800 hydrogen FCVs are in operation, about twice as much as the total amount in 2017 [44], and the number is still growing. With the improvement of hydrogen production technology and reduction in the hydrogen price, coupled with the support of national policies, the demand across sectors is expected to increase rapidly over the next decades. It is projected that the hydrogen generation market will grow about 47% from 2018 to 2023 and expected to reach near $200 billion by 2023 [45]. Hydrogen energy is estimated to contribute 90% of the whole global energy structure by 2080 [46]. The average price of hydrogen is about $14 per kg currently, and in the future, it will be influenced by technology innovation and market demand. Chlorine gas is also important to the chemical industry and municipal sanitation facilities. One of the most significant applications of chlorine gas in the chemical industry is reacting with hydrogen gas to produce hydrogen chloride, then high purity hydrogen chloride is used to produce vinyl chloride monomer, which is the precursor of polyvinyl chloride (PVC). Chlorine reacts with water to form hypochlorous acid, which is strong oxidizing agent, so it is commonly used in sanitation, disinfection, and antisepsis. In the early 20th century, the US government required all tap water to be disinfected with chlorine, and now, there are still many waterworks using this method to treat municipal water supplies. The strong oxidizing property of hypochlorous acid can also be used for bleaching. The U.S. chlorine market revenue is predicted to be $5500 million in 2024, which is an increase of about 57%, and the major growth is driven by the increasing adoption of ethylene dichloride (EDC) and PVC in automobile, construction, packaging, and chlorine-containing solvents in the pharmaceutical industry. The price of chlorine gas is relatively stable, which is about $0.17 per kg recently [47]. 2.2. Methodology for energy, environment, and cost-benefit analysis First, the energy analysis is conducted by analyzing the heat requirements of individual steps in the Cu-Cl cycle based on the enthalpy of reactants and products. A detailed process simulation model is built to quantify the mass and energy balances. The simulation result was further used for detailed environment and cost-benefit analysis. Energy integration based on pinch analysis of the whole cycle is performed to minimize its energy consumption, balancing the utility demand and capital investment of heat exchangers at the same time. The aim of life cycle emission analysis is to compare the environmental impact of hydrogen production from the proposed Cu-Cl cycle with that of other existing hydrogen technologies. Hydrogen has been considered as one of the cleanest energy sources, as it only produces

Cost of B = Cost of A × (Size of B/Size of A) N

(6)

The process equipment size exponent (N) of 0.6 is widely adopted for a quick estimation, which is known as the six-tenths-factor rule [52]. But the value of N will be slightly different among different equipment, so a more accurate value is listed in Appendix B for further calculation.

4

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Fig. 2. System boundary of Cu-Cl hydrogen production life-cycle emission analysis.

3. Results and discussion

the fluidized bed reactor and CuCl2 from the CuCl2 recovery step. The oxidation reaction of CuCl2 is an endothermic reaction and needs 50.0 kJ/mol heat input. CuCl2 reacts with water and produces copper oxychloride (Cu2OCl2) and HCl at 375 °C in a fluidized bed reactor (step 4), and HCl further feeds to CuCl2 recovery reaction (step 6) as a reactant after cooling. The copper oxychloride (Cu2OCl2) then heats up to 500 °C and decomposes to O2 and molten CuCl (step 5). CuCl goes back to the electrolyzer, and oxygen is consumed as the reactant of Cl2 production (step 3). The last step (CuCl2 recovery) uses CuO from Cl2 production (step 3) and HCl gas from hydrolysis reaction (step 4) to produce CuCl2 to form a closed loop and recover a substantial amount of chemical energy at the same time. The by-product, water vapor, is fed to a boiler and recycled in the fluidized bed reactor after heating up and pressurizing. A rough estimate of energy consumption is shown in Table 3. If all the heat output can be recovered, the minimal energy demand would be 62.6 kJ electricity and 160 kJ thermal energy producing 1 mol of hydrogen, which equals to 8.7 kWh and 80 MJ per kg hydrogen. However, it is difficult to recover all energy, because heat can only transfer from high temperature to low temperature according to thermodynamic law, and as a result, low-grade energy is hard to be

3.1. Energy analysis of Cu-Cl cycle Considering the limited data of the industrial Cu-Cl hydrogen cycle, we firstly estimate the energy demand based on a thermodynamic analysis. Generally, the energy efficiency of the original Cu-Cl cycle is about 43% [38], depending on the number of steps. 3.1.1. Heat and energy analysis of processes In H2 production (step 1), the main energy usage is heating up reactants, including solid copper, hydrochloride gas and vaporizing moisture on the solid surface. The system can recover part of this energy, as the process is an exothermic reaction, and after the reaction, the products need to cool down so that the next step can proceed. The energy consumption in the electrolysis cell (step 2) will be affected by many factors, such as temperature, applied potential, concentration, membrane property, electrode material etc. The electrical energy of 62.6 kJ/mol H2 in existing literature is adopted here [49]. Chlorine production (step 3) operates at room temperature, with O2 coming from

Fixed capital cost (85%)

Total capital cost

Total Cost

Working capital cost (15%)

Total product cost Transportation cost

Indirect cost Electricity

Manufacturing cost

Utility

General expenses

Other

Storage cost Fig. 3. Total cost of a Cu-Cl hydrogen production process. 5

Direct cost

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Table 3 Heat requirement of individual step in Cu-Cl cycle. Step

Process

Temperature (°C)

Step 1

Vaporizing Heating Cu Heating HCl Heat of reaction 2Cu + 2HCl = 2CuCl + H2 Cooling and solidification of CuCl Cooling hydrogen product

35 → 70 25 → 450 25 → 450 450

Step 2

Electrolysis (electricity) [49] 4CuCl + 2H2O = 2CuCl2 + 2Cu + 2H2O

25

Step 3

Heat of reaction CuCl2 + 1/2O2 = CuO + Cl2

25

50

Step 4

Heating CuCl2 Heat of hydrolysis reaction [49]2CuCl2 + H2O = CuO∙CuCl2 + 2HCl Steam production [49] Cooling HCl

70 → 375 375 25 → 375 375 → 100

46.5 116.6 57.1

Step 5

Heating CuOCuCl2 Heat of decompose reaction [49] CuO∙CuCl2 = 2CuCl + 0.5O2 Cooling oxygen Cooling and solidification of CuCl

375 → 500 500

16.2 129.2

Heating CuO Heat of reaction CuO + 2HCl = CuCl2 + H2O Cooling CuCl2 Cooling water

25 → 100 100

Step 6

16.1

7.5 54.1 3.3

100 → 25 100 → 25

107.2 5.5 2.5

62.6

494.3

334.3

Cu2OCl2 converts to CuCl [60]. We use “SOLID” as the property method in the simulation, as solids are involved in every steps of reaction. Due to the assumption of the complete separation, the block of “separator” is adopted to separate process flow by setting component ratios in the outlet of the separators. Reactions and temperatures are specified in the stoichiometric reactor models, and conversion rates are set according to existing data. Heaters are used to heat up or cool down flows to fulfill requirements of the next steps, so the outlet temperatures are constrained in the heater model. The simulation result can be referred to Appendix A. The maximum heat exchange area in a single heat exchanger is 283 m2, which is an acceptable size, as the area of an industrial heat exchanger can reach several thousands of m2. The simulation result shows that streams needing frequent temperature changes between operating units, ranging from 25 °C to 500 °C, so numerous but overlapping heat exchanges appear inside the cycle. If all reactors and heat exchangers are connected to the utilities directly, the hot utility and cold utility requirements would be 460.7 MJ/kg H2 and 368.4 MJ/kg H2, respectively. Hence, thermal energy is the main cost and energy consumption in the Cu-Cl cycle, and the reduction of utility usage is extremely important to the process design. A rough utility demand can be estimated by the composite curve [61], as shown in Fig. 5, where the minimum hot and cold utility demands and pinch point are illustrated. With the available stream data, such as flow rate and effective heat capacity, the temperature interval (TI) method [62] can be used to analyze the relationship between hot and cold process streams more precisely and then find out the minimum utility demands though pinch point analysis [63].

• Due to the limited kinetics data, all the reactors are simulated using

•

60.8 68.2 12.4

500 → 25 500 → 25

3.1.2. Process simulation A case study based on the above discussion has been conducted using Aspen Plus simulation (Fig. 4). Some assumptions are made as followed:

•

29.9 20.7 24.8

Heat Output (kJ/mol H2)

62.6

reused. The whole process is actually an HCl splitting reaction, while the difference of Cu-Cl hybrid cycle and direct electrolysis of HCl is that CuCl cycle removes a part of electrical energy, which is a high grade of energy, to thermal energy. Hence, if a power plant is co-located with the Cu-Cl cycle, it can produce a considerable amount of hydrogen when generating electricity. In addition, the heat exchange at a relatively low temperature can use low-grade waste heat in a plant so that the energy consumption of the whole process can be further reduced.

• •

Heat Demand (kJ/mol H2)

450 → 25 450 → 25

Total

• • •

Electricity (kJ/mol H2)

a stoichiometric model, as the conversion information under certain reaction conditions can be obtained from existing reports. Since most of the separation processes are multi-phase, it is assumed that the complete separation can be achieved. The Cu-Cl cycle operates at atmospheric pressure, so pumps and compressors are excluded. Assuming that the HCl input is 20 kmol/hr and conversion in the electrolysis reactor 50% [59], a large amount of recycled CuCl is needed to feed into the electrolyzer to maintain the reaction rate. If the current density of electrolysis cell is 0.1 A/cm2, the applied potential would then be about 0.65 V [59]. The current efficiency, estimated by the ratio of actual hydrogen amount produced over the Faraday’s theoretical hydrogen amount, is assumed to be 90% [59]. The amount of recycling water from CuCl2 recycle step to fluidized bed reactor is 340 kmol/hr, which is 17 times of the molar amount of CuCl2 so that the hydrolysis conversion rate inside fluidized bed reactor can be close to 100% [40]. No side reactions occur in the decomposition reactor and 75.5% of

3.1.3. Energy integration of Cu-Cl cycle First of all, the minimum heat transfer temperature difference, which ensures heat transfer in the correct direction, should be decided, as it directly influences the matching streams and utility demand. A 6

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Fig. 4. Flowsheet of the Cu-Cl cycle.

smaller minimum heat transfer temperature difference means more energy can be recycled, but it needs more heat exchangers, which increases capital investment remarkably as shown in Fig. 6. In this case, as the hydrogen production capacity is small, the operating cost is not as obvious as capital cost changes, so we use 25 °C as the smaller

minimum heat transfer temperature difference. If the capacity or any other condition varies, the result may be different. The calculation stops at 25 °C due to coolant selection. We choose ice brine as the cooling medium which operates at 0 °C, so if a higher temperature difference is needed, the coolant inside the system should be changed to a

Fig. 5. Composite curve (at 25 °C) of Cu-Cl hydrogen production system. 7

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Fig. 6. Total cost index variation due to minimum heat transfer temperature difference (red line indicates the capital cost; blue line indicates the operating cost).

refrigerant with lower temperature, and the operation cost would be higher. After that, the minimum hot and cold utility requirements of the whole system can be calculated by temperature interval method. Pinch point is a plane that the temperature of streams of both sides has a difference that equals to the minimum heat transfer temperature difference. In other words, there is no heat flow going through this plane. Pinch point can separate the heat exchanger network into two parts – one is that the temperature of hot and cold streams is higher than pinch point temperature (hot side), and the other is lower than pinch point temperature (cold side). The theoretical optimal situation is that all process stream heaters are located above the pinch and all process stream coolers are located below the pinch. Fig. A1 in Appendix A shows the divisions of temperature intervals of the studied cycle and the minimum hot and cold utility demands are 95.02 MJ/kg H2 and 2.77 MJ/kg H2, respectively. But normally, a perfect heat exchanger network is not economically optimal, because the capital cost could be much higher than the benefits from recycling heat, so some unnecessary and low heat duty exchangers are normally removed and a small amount of heat is allowed to pass through the pinch point. One of the feasible network designs is shown in Fig. 7 in Appendix A, with 234.45 MJ/kg H2 of hot utility and 178.95 MJ/kg H2 of cold utility. The result is numerically reasonable, as the energy demand is about twice the minimum energy requirement according to the previous calculation. It has been reported that the energy consumption of a 5-step Cu-Cl is 300 MJ/kg H2 in an existing study [39], which is close to the result above. In the case of coal-fired power plants, the furnace temperature can be higher than 1100 °C and the high-pressure steam generated from boiler can reach 550 °C in a supercritical pressure thermal power plant and higher than 600 °C in an ultra-supercritical pressure thermal power plant. The stream with the lowest temperature is condensed water, which is about 42 °C [64]. The main waste heat sources are flue gas (150 °C), condensed water (42 °C) and equipment cooling water. If combined with a solid waste incineration process, Cu-Cl hydrogen production cycle can receive energy from incineration furnace (850 °C) or thermal decomposition process (1650–1800 °C). Generally, these processes can satisfy the hot utility temperature demand of a Cu-Cl cycle, but cold utility should be operated at lower than 0 °C to ensure the minimum heat transfer temperature difference. It can use

refrigerant or appropriately improve reaction temperature of step 2 (electrolysis) and step 3 (Cl2 production) in the Cu-Cl cycle. 3.2. Life-Cycle emission of hydrogen production 3.2.1. Data for life-cycle GHG emission Several hydrogen production processes have been evaluated to compare with the Cu-Cl cycle, including SMR, coal gasification (CG), proton exchange membrane electrolysis (PEM) and solid oxide electrolysis cell (SOEC). The inventory for feedstock and energy consumption inventory is given in Table 4. The adopted data are based on the U.S. in order to make the source consistent. The inventory and emission data can be revised correspondingly when evaluating other regions. The life-cycle GHG emission data of natural gas was derived from the Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990–2017 [69], which collects the emission data of natural gas exploration, production, processing, transmission, storage and distribution. Exploration includes well drilling, testing, and completion. The major emission of the natural gas life cycle (excluding combustion) comes from the production process, while most of emission in the production processes comes from offshore platforms, compressors, and pneumatic controllers [69]. The total emission amount changes every year, and here uses the data in 2017 as 0.85 g CO2/MJ natural gas and 0.21 g CH4/MJ natural gas, which is 6.1 g CO2-eq/MJ natural gas in total. The GHG emission in the coal life cycle is mainly attributable to the coal mining, including underground mining, liberated, recovered & used, surface mining, and post-mining [69]. For underground mines, continuously release of CH4 from ventilation systems and degasification systems is accounted for, which is used to keep the air inside the mines fresh and low-toxicity. For surface coal mines, methane normally releases when the rock layer overlying the coal mineral is removed. The emission amount increases with the mines going deeper, so underground mining produces higher GHG emissions, mainly CH4, than surface mining. And the approximate quantity ratio of these two sorts of mining is 69% of surface mining to 31% of underground mining [70]. The coal production and total emission of coal mining system in the U.S. are 702,082 kt and 2227 kt CH4 in 2017, respectively. In addition, abandoned underground coal mines also contribute a large amount of GHG emission, because the CH4 will continue leaking from the mines

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for various energy sources. The Intergovernmental Panel on Climate Change (IPCC) in 2014 provided a set of life-cycle emission data [72]: 0.82 kg CO2-eq/kWh for a coal burner power plant; 0.041 kg CO2-eq/ kWh for a rooftop solar PV panel; 0.012 kg CO2-eq/kWh for nuclear energy; and 0.011 kg CO2-eq/kWh for wind turbines. If considering Combined Cycle Gas Turbine (CCGT) technology in a natural gas power plant, the emission will be 0.419 kg CO2-eq/kWh. The electricity from the same sources also varies greatly among nations. For example, European countries can retain a relatively low emission level, while African countries have much higher levels of emissions. This study adopts 0.707 kg CO2-eq/kWh as an average value from the United States Environmental Protection Agency (EPA) [73]. For a better comparison, Cu-Cl cycle uses the same electricity emission factor as the other processes. However, if it uses renewable energy, such as solar or wind power, the final life-cycle GHG emissions could be lower [74]. The emission factor of thermal energy is obtained from the result of Aspen Plus, calculated by the data source of US-EPARule-E9-5711, and energy is generated by coal as normally used in electric power plants. The GHG emissions of cold utilities are excluded, as heat can be recovered by water preheating in a power plant. As a large amount of water is circulated in a power plant, there is a potential to recover most of the heat. Cu-Cl cycle also consumes HCl flue gas, which contributes a negative emission factor – producing 1 kg of hydrogen needs 32.5 kg CO2-eq of HCl gas. The final emission of Cu-Cl cycle is therefore calculated to be 8.68 kg CO2-eq/kg H2. The life-cycle emission of gasoline can be calculated in two parts production and combustion. The emission during the gasoline production process mainly comes from oil extraction, refinery, and transportation, but it is difficult to define the exact emissions, as the petroleum industry is a multi-product process. In this study, an energy-allocation approach is followed to assign the proportions of total GHG emissions of the refinery process based on energy contents of gasoline and other co-products. Here emission from the production part is estimated as 0.022 kg CO2-eq/MJ gasoline [70]. The combustion emission per gallon of gasoline is 8.887 kg CO2-eq/gallon [75]. Assuming the energy density of gasoline is 119.4 MJ/gallon [76], the combustion emission is estimated as 0.0744 kg CO2-eq/MJ. Overall, the emission of the whole gasoline life cycle is 0.0964 kg CO2-eq/MJ gasoline, which is functional equivalence of 21.08 kg CO2-eq/kg H2. 3.2.2. Results of life-cycle GHG emission The results of GHG emissions are shown in Fig. 8. Hydrogen production using the proposed Cu-Cl cycle delivers the lowest GHG profile compared with alternative routes. Although the conventional SMR hydrogen plant reaches a low level of GHG emission as well, it is 23% higher than the clean Cu-Cl cycle. Moreover, it is worth noting that the emission result of Cu-Cl cycle can be over-estimated based on primary hot utility, which means the fired heat or high-pressure steam is sent to Cu-Cl process. In fact, it can use most secondary heat sources, which have been used once already. Since the GHG emission factors of such kind of heat sources are difficult to calculate, here the emission data of primary hot utility are used which lead to over-estimated GHG profiles than the real scenario. The GWP scores could be further optimized by improving the heat exchanger network. The green bars represent the potential of CO2 sequestration in SMR and CG, and yellow bars represent the potential of CO2 reduction if CCGT has been used in the power generation process in PEM SOEC and Cu-Cl. The lower part of orange bar indicates the GHG emission during gasoline production, and upper part represent the combustion process in the internal combustion engines, showing the large emission of the subsequent process. For hydrogen, it would not produce emission at the stage of end use.

Fig. 7. A feasible heat exchanger network design of the Cu-Cl cycle. Table 4 Feedstock and energy consumption inventory of hydrogen production process. Natural gas (MJ/kg H2) SMR [65] CG [66] PEM [67] SOEC [68] Cu-Cl

164.6 0 0 59.09 0

Coal (MJ/kg H2) 0 261 0 0 0

Electricity (kWh/kg H2) 0.569 1.36 54.3 36.8 19.4

HCl (kg/kg H2) 0 0 0 0 36.5

Thermal energy (MJ/kg H2) 0 0 0 0 95.02

after closure, and the total released amount reaches 257 kt CH4 in the U.S. in 2017. Assuming the energy density of coal is 27 MJ/kg [71], the final result is calculated as 3.28 g CO2-eq/MJ. The GHG emissions per kWh of electricity generation are different

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Fig. 8. GHG emissions of several hydrogen production technologies and gasoline production and combustion.

3.3. Cost-Benefit analysis

3.3.2. Product cost The calculation basis of product cost is also shown in Appendix B, with the result of $493,533 per year. Fig. 9 shows the competitive production cost of hydrogen and gasoline. Without considering transportation and storage cost, SMR is the most cost-effective way to produce hydrogen, and the cost is even lower than gasoline which has been adjusted by VMT method. Hydrogen produced by Cu-Cl cycle is relatively expensive than SMR, CG and gasoline, but has a lower cost than PEM and SOEC. To a certain extent, it illustrates that electricity as a high-grade energy should be more expensive, while thermal energy

3.3.1. Capital cost Using the simulation result of Aspen Plus, the capital cost of heat exchangers can be estimated by the heat transfer area. Capital cost of reactors refers to Wu et al.’s work [53]. The percentages of elements in fixed capital are estimated in Appendix B [54]. As a result, the final equipment cost and total capital cost are estimated as $767,206 and $2,256,488, respectively.

Fig. 9. Product cost of several hydrogen production technologies and gasoline production. 10

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in the whole system. The result shows that the GHG emissions will increase by 12.7%, from 8.69 kg CO2-eq/kg H2 to 9.79 kg CO2-eq/kg H2, if increasing the temperature of the entire system by 20 °C, while the cost of thermal energy will reduce from $215,138 per year to $190,330 per year, which accounts for 11.5%. It is reasonable because a higher operating temperature requires more energy input, but it also allows a higher minimum temperature difference of heat exchange, leading lower operating cost according to Fig. 6. However, the case of lower temperature is not considered, as it will cause the reaction difficult to carry out.

Table 5 The proportions of total product cost. Component

Cost ($)

Proportion (%)

Operating labor Direct supervisory and clerical labor Maintenance and repairs Operating supplies Laboratory charges Depreciation Local taxes Insurance Rent Plant overhead costs Administrative costs Research and development costs Financing (interest) Thermal energy Electricity Total Product Cost

21,042 2,104 57,540 13,426 2,104 40,278 19,180 7,672 7,672 10,521 4,208 2,104 22,565 215,138 67,978 493,532

4.26 0.43 11.66 2.72 0.43 8.16 3.89 1.56 1.55 2.13 0.85 0.43 4.57 43.59 13.77 100.00

3.3.3. Transportation cost The transportation cost of hydrogen, which depends on the distance, hydrogen demand, transport modes, supply-demand network and many other factors, mainly consists of capital cost and operating cost. Currently, hydrogen is mainly transported in two modes – tank transportation and pipeline transportation, which depends on the quantity and distance. Tank transportation can be divided into compressed gas cylinder transportation and cryogenic liquid tanker transportation according to the state of hydrogen product. More information about the transportation modes can be found in Appendix B. In general, the pipeline is more cost-effective only when the transport quantity is large; compressed gas cylinders are suitable for a short distance and small quantity delivery; cryogenic liquid tanker is the best choice in the case of small quantity but relatively long distance. Estimation of a point-topoint hydrogen pipeline transportation cost has been reported as around $0.25 per kg hydrogen in the case of high flow rate (100 ton/ day) and 50 km of distance. For gasoline, the average transportation cost is $0.16 per gallon by pipeline and $0.40 per gallon by rail [78].

from fossil fuel combustion, as a low-grade energy, would be cheaper. If considering the value of chlorine by-product, the product cost will be much lower than all the other technologies. According to the result, utility cost, electricity fee, maintenance cost and depreciation account for about 80% of the total product cost, as shown in Table 5. Maintenance cost and depreciation are mainly driven by equipment, which is difficult to reduce. Thereby, the key to reduce the product cost of Cu-Cl hydrogen production is to minimize the energy consumption and reduce unit energy costs. For electric energy reduction, the primary goal is to improve the reaction efficiency of the electrolyzer; for thermal energy, the heat exchanger network should be further improved, but it also needs to consider the incremental capital cost. Using electricity and waste heat generated by the power plant, combined with Cu-Cl cycle, can reduce the unit cost compared to a primary heat source [77]. In addition, enlarging the capacity of Cu-Cl cycle may be a more effective way to lower the product cost. As shown in Eq. (6), the growth rate of equipment price is slower than producing capacity due to the economy of scale. More heat should be transferred with the stream flowrates increasing, so the relationship between capital cost and operating cost may change. And a smaller minimum heat transfer temperature difference can be set, which means more heat can be recovered and as a result, the total product cost should be lower. The purple bars in SMR and CG indicate the extra cost if CO2 sequestration is operated. The yellow bars in PEM, SOEC, and Cu-Cl cycle represent the electricity tariffs during producing hydrogen, which can be reduced in a certain extent, if renewable energy or on-site power generation has been used. The green bar under Cu-Cl cycle shows the benefit of the chlorine by-product, which has a negative contribution to the product cost of hydrogen. Gasoline is used as a control group for comparing the economic potential of hydrogen in the case of transportation as end use. In order to maintain unit consistency, the cost of gasoline has been modified by the VMT method. It should be noted that the data in the cost-benefit analysis, including electricity fee and global energy mix, are based on the recent situation. With further development of the global energy structure, more and more renewable energy will be integrated into the grid or used directly, which means the electricity tariff will be further reduced. If so, the product cost of hydrogen through PEM, SOEC, and Cu-Cl cycle will be reduced as well. The integration of more renewable energy will cause a certain level of unpredictability and fluctuation, so electrolysis process will play an important role in the future energy structure, as it can better adapt to such conditions and consume the excess electricity. A sensitivity analysis is conducted based on the temperature change

3.3.4. Storage cost Similar to transportation, storage cost is a function of many factors, including storage mode, duration, and production rate. Hydrogen can be stored as compressed gas, liquid or metal hydride, and the container could be cylinders, tanks or underground caverns. For long-term storage, underground storage and liquid hydrogen storage are more costeffective, and operating cost is much lower than capital cost in this case. For short-term storage, underground storage and compressed gas hydrogen storage are more favorable. With the production rate increases, the storage preference is compressed gas, liquid hydrogen, and finally underground storage. Metal hydrides are suitable for a case that a high pressure but a small quantity of hydrogen is needed, while the production pressure is low. A short-term (one-day) small production rate (1 kg/hr) compressed gas hydrogen storage cost is estimated to be $0.36 per kg; a 7-day, 4536 kg/hr liquid hydrogen storage is estimated to be $0.64 per kg, and a long-term (30-day) large amount (45,359 kg/ hr) of underground storage is estimated as $0.15 per kg [78]. 3.3.5. Benefits The price of hydrogen fuel ranges from $12.85 to more than $16 per kg, and the average price is about $14 per kg, while chlorine gas is priced about $0.17 per kg. Today's hydrogen prices are still higher than gasoline, and hydrogen production technology is still evolving, therefore the price of hydrogen should continue decreasing over a period of time. The price of hydrogen will vary with the relationship between supply and demand, after the hydrogen production technology is mature and the hydrogen price is lower than the price of gasoline. Chlorine is often a by-product of other processes, so it will also be affected by the market economy. Currently in 2019, the gasoline price in the U.S. is $2.9 per gallon. Assuming the transportation, storage, and dispensing costs of hydrogen are $0.25 per kg and $0.15 per kg, and $0.39 per kg, respectively [31,79], the profit of hydrogen produced by SMR and CG would be $12.1 per kg and $11.8 per kg. Although the product cost of

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hydrogen produced by Cu-Cl cycle is higher than by SMR and CG, Cu-Cl cycle produces 35.5 kg chlorine gas when producing 1 kg hydrogen. As a result, the profit of hydrogen produced by Cu-Cl cycle would be $18.1 per kg, which is 50% higher than the profit of hydrogen produced by SMR, if the benefit of chlorine is deducted from the total cost. Assuming the total dispensing and distribution cost of gasoline is $0.19 per gallon, the profit of gasoline is $1.81 per gallon. Taking FCV as an example, from the perspective of the consumer, the hydrogen retail price should be lower than about $4.8 per kg so that the extra investment of FCV can be paid back in 10 years. This estimation was based on the assumption that the price of a hydrogen fuel cell car is $24,363, conventional combustion engine car is $15,805 [80], an automobile is driven 10,000 km per year. In this case, the hydrogen profit of Cu-Cl cycle would be $7.2 per kg, which is 252% higher than $2.86 per kg of SMR.

challenges. Moreover, larger production scale, higher heat efficiency, and better waste heat recovery can be helpful to reduce the product cost and negative environmental impact of the Cu-Cl process. However, the scale of Cu-Cl production cannot increase infinitely, as Cu-Cl production process is combined with coal-fired power plant or waste incineration station, which will be constrained by the amount of waste HCl, so a larger scale of production should wait for a larger power plant in the future. With the development of hydrogen transportation and storage technologies, the hydrogen price will be reduced continuously. There are still some limitations in this article that need further improvement. For example, the analysis does not consider the HCl separation process before the Cu-Cl cycle due to the limited data of cost. The pressure loss and heat loss are not considered in the simulation. In addition, the separation process is considered to be fully performed. The optimization of the process and even the whole supply chain can be a future direction after this initial study. Cu-Cl cycle is one of the promising approaches to produce hydrogen in a cleaner way, while further research in various fields is needed to improve the accuracy of the analysis and fully realize its potential.

4. Conclusions This paper presented a novel Cu-Cl cycle design, that can not only consume waste HCl and waste heat from several industries but also produce high added-value H2 and Cl2 products. Hydrogen will have a promising market in the future as it is one of the most likely alternatives to fossil fuels. Energy analysis shows that producing one kg of hydrogen through Cu-Cl cycle needs 19.4 kWh electricity energy and 234.45 MJ thermal energy. Our life-cycle GHG emission analysis highlights that Cu-Cl hydrogen production cycle has the lowest emission potential, 8.7 kg CO2-eq/kg H2, compared to conventional gasoline producing process and mainstream hydrogen production processes. A cost-benefit analysis indicates that the product cost of one kg hydrogen is $2.82 using the Cu-Cl cycle, which is higher than hydrogen product cost of SMR, but the profits of by-product (e.g., Cl2) increase the profit margin of hydrogen, making Cu-Cl cycle more capable of meeting market

Acknowledgements This work has been supported by the National University of Singapore Flagship Green Energy Program (#R-279-000-553-646 and R-279-000-553-731) and the National Research Foundation, Prime Minister’s Office, Singapore under its Campus for Research Excellence and Technological Enterprise (CREATE) programme (Grant Number R706-000-103-281 and R-706-001-102-281). The authors acknowledge the helpful discussion and support from Ms. Lokasenna Liu, Mr. Ewan Jun Xian Chee, Mr. Tongfei Xu, Mr. Xikun Zhang, Mr. Angra Lee, and Mr. Shirui Hu.

Appendix A (See Figs. A1 and A2). (See Table A1).

Stream Name From To Temperature Mass Enthalpy Mass Entropy Mass Density Enthalpy Flow Mass Flows CU CUCL CUCL2 CUO HCL CL2 H2 H2O O2 CU2OCL2

Units

CU2OCL2 HEATX3 D EC OMP C 500 kcal/kg -321.487 cal/gm-K -0.574785 kg/cum 5167.59 Gcal/hr -2.18429 kg/hr 6794.34 kg/hr 0 kg/hr 3959.95 kg/hr 0 kg/hr 0 kg/hr 0 kg/hr 0 kg/hr 0 kg/hr 0 kg/hr 0 kg/hr 2834.39

CUCL2 HEATX7 C L 2P D C 25 -365.682 -0.263056 3439.94 -0.491664 1344.51 0 0 1344.51 0 0 0 0 0 0 0

CUCLRE SEP 4 E LE 25 -333.11 -0.138939 4137.95 -1.97865 5939.92 0 5939.92 0 0 0 0 0 0 0 0

CUO DECOMOUT ELEOUT FBRIN FBROUT HEATX5 HEATX4 ELE HEATX2 HYDROLY CUC L2RE SEP 4 SEP 2 HYDROLY SEP 3 100 25 25 375 375 -462.302 -334.226 -296.392 -299.585 -1603.49 -0.248049 -0.265691 -0.154712 -0.0866535 -0.32387 6509.44 54.1516 79.829 3824.13 0.677226 -0.36774 -2.27085 -2.39062 -1.99193 -20.4833 795.454 6794.34 8065.74 6648.98 12774.2 0 0 1270.92 0 0 0 5939.92 3959.95 3959.95 3959.95 0 0 2689.03 2689.03 0 795.454 0 0 0 0 0 0 145.843 0 729.213 0 0 0 0 0 0 0 0 0 0 0 0 0 0 5945.04 0 159.994 0 0 0 0 694.427 0 0 2139.97

H2O HEATX6 HYDROLY 375 -3043.44 -0.229083 0.334301 -18.6416 6125.2 0 0 0 0 0 0 0 6125.2 0 0

Fig. A1. Screenshot of the result of the main streams.

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H2ORE H2OSEP HEATX6 100 -3172.42 -0.487093 0.580671 -19.4317 6125.2 0 0 0 0 0 0 0 6125.2 0 0

HCL HCLIN HPDCOUT HEATX8 HEATX1 CUCL2RE HCLHEAT SEP 1 100 25 25 -2890.32 -604.703 -348.439 -0.399128 0.0664116 -0.115805 0.614645 1.47083 6.17499 -19.2907 -0.440957 -0.747741 6674.26 729.213 2145.98 0 0 0 0 0 1979.97 0 0 0 0 0 0 729.213 729.213 145.843 0 0 0 0 0 20.1588 5945.04 0 0 0 0 0 0 0 0

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Fig. A2. Temperature intervals of Cu-Cl hydrogen production system (the short arrows indicate the heat demands of reactors, which should stay at certain temperature). Table A1 Simulation result of the heat exchanger. Heat Exchanger

Area (m2)

Shells

E-114 E-115 E-116 E-117 E-118 E-119 E-120 E-121 E-122 E-123 E-124 E-125 E-126 E-127 E-128 E-129 E-130 E-131 E-132 E-133 E-134 E-135 E-136

70.81 3.793 172 51.33 64.06 283.8 8.032 12.88 10.01 21.22 2.076 11.12 18.14 97.39 23.12 16.03 3.875 1.622 15.28 3.152 85.77 218.4 23.13

3 1 1 3 1 1 2 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

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Appendix B The proportion is different from a typical chemical plant, because the Cu-Cl hydrogen cycle in this work needs to be attached to an existing power plant or solid waste treatment station, so the equipment cost would account for a larger proportion of the whole capital investment, compared to other plants due to the elimination of land cost and infrastructure. While the contingency cost, equipment installation, piping, instrumentation and controls maintain as the average levels. We assume that equipment purchases account for 40% of the fixed capital cost (See Tables B1–B4). Electricity power and thermal power are massively consumed in the Cu-Cl cycle. According to the research of National Renewable Energy Laboratory (NREL), electricity tariff accounts for about 80% [81] of total product cost of hydrogen from electrolysis using the current production process, so the ratio estimations of the electricity tariff and utility cost in a typical chemical plant are not accurate any more. Some elements of product cost are estimated by its ratio to total product cost, and it will produce a relatively large deviation. Thereafter we calculate these two parts of cost directly and add them to the product cost after calculating other elements in the product cost list, which means electricity fee and utility cost are not included in the product cost when using the ratio to calculate other product cost component. Assuming the overall Cu-Cl cycle only consumes HCl, the cost of purchasing raw materials is nearly 0 as it uses the waste resources. The electricity fee is assumed to be $60 per MWh here [55], and the cost of thermal energy is generated from Aspen simulation. Tank transportation refers storing hydrogen in a temporary container, and transport by lorry, ship, rail or any other feasible way. For a short distance and small quantity of hydrogen delivery, it uses a compressed gas cylinders, where hydrogen is compressed to 20–60 MPa but still remains in the gas phase. It can also bundle a group of containers in a protective frame to enlarge the one-time transport volume, which can hold 63–460 kg of hydrogen. Hydrogen is very light-weighted gas so that the containers need to be pressurized to several hundred bars to maximize the hydrogen amount in a limited volume. But even so, the density of hydrogen under 500 bars of pressure (33 kg/m3) is still much lower than conventional fuels Table B1 Process equipment size exponent (N) [56]. Equipment Type

Size Unit

Size exponent (N)

Heat exchanger, fixed tube Heat exchanger, U-tube Tanks and vessels, pressure, carbon steel Tanks and vessels, stainless steel

Sq. ft. Sq. ft. gallons gallons

0.62 0.53 0.50 0.68

Table B2 Equipment cost result. Equipment

Cost ($)

Heat exchanger E-114 E-115 E-116 E-117 E-118 E-119 E-120 E-121 E-122 E-123 E-124 E-125 E-126 E-127 E-128 E-129 E-130 E-131 E-132 E-133 E-134 E-135 E-136

40,100 12,320 59,160 33,270 32,300 83,360 14,870 16,180 15,050 19,210 11,430 15,500 18,130 41,180 19,870 17,360 12,360 11,180 17,080 12,000 38,170 69,490 19,870

Separator Separator1 Separator2 Separator3 Separator4 H2OSEP CL2SEP

16,100 16,100 24,500 16,100 19,900 16,100

Reactor ELE H2PDC CL2PDC CUCL2RE FBR TOTAL

6,468 5,976 5,976 5,976 4,570 767,206

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Table B3 Typical percentages of cost elements in fixed capital [54]. Component

Percentage (%)

Value ($)

Direct Cost Purchased equipment Equipment installation Instrumentation and controls Piping Electrical system Building Yard improvements Service facilities Land

40 9 3 7 3 5 2 6 0

767,206 172,621 57,540 134,261 57,540 95,901 38,360 115,081 0

Indirect Cost Engineering and supervision Construction expenses Contractor’s fee Contingency

6 8 2 9

115,081 153,441 38,360 172,621

Table B4 Typical Basis of the components in product cost [54]. Component

Basis

Raw materials Operating labor Direct supervisory and clerical labor Utilities Maintenance and repairs Operating supplies Laboratory charges Depreciation Local taxes Insurance Rent Plant overhead costs Administrative costs Research and development costs Financing (interest)

Calculation 10% of total product cost 10% of operating labor Calculation 3% of fixed capital investment 0.7% of fixed capital investment 10% of operating labor 2% of fixed capital investment + 2% of building 1% of fixed capital investment 0.4% of fixed capital investment 8% of value of rented land and buildings 5% of total product cost 2% of total product cost 2% of total product cost 1% of total capital investment

(usually 800 kg/m3). Normally, a single tube trailer can deliver 500 kg of hydrogen one time, and a gasoline tank transportation can carry about 2–40 tons of fuel one time [78]. Hydrogen can be further compressed to liquid and transported by cryogenic liquid tankers [82]. The hydrogen density can increase to a higher level (about 70.8 kg/m3) [83] and the tanks use double insulated wall structure or liquid nitrogen coolant to prevent hydrogen boil-off. But the super high pressure would always be a security risk during transportation. Another issue of tank transportation is the low transportation efficiency, that is, most of the energy consumption during the transportation is used to carry the container material, rather than hydrogen, as the container are commonly made of steel or other heavy materials. Pipeline transportation requires a high-level capital investment, so it is more suitable for a large quantity of long-term hydrogen delivery. Pipeline materials need to solve the security issues such as hydrogen embrittlement. There have been many successful cases already – the U.S. has more than 2,600 km of hydrogen pipeline in 2017 and new pipelines are constantly being built around the world. The typical operating conditions of existing hydrogen pipelines are 1–3 MPa and flowrates range from 310 to 8900 kg/h [78], so the hydrogen inside the pipeline is also in the format of compressed gas. Another alternative solution is to blend hydrogen with natural gas and then deliver the mixture using natural gas pipeline network. Hydrogen is separated from natural gas at the demand side of the pipeline or directly used in the format of hybrid gas as fuel. In this way, it can reduce the capital investment of the hydrogen pipeline.

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