Techno-economic analysis of e-waste based chemical looping reformer as hydrogen generator with co-generation of metals,electricity and syngas

Chemical looping reforming (CLR) is an efficient technology to convert hydrocarbon fuels into CO₂ and H₂ using metal oxide based oxygen carriers. The novelty of the present study is to utilize electronic waste such as printed circuit board (PCB) to generate high quality syngas and metallic components for the CLR process. A portion of the syngas generated during e-waste pyrolysis is used with coal and polypropylene for effective combustion. A techno-economic analysis is performed for the production of hydrogen and electricity in the CLR method. The levelized costs for electricity (LCOE), hydrogen (LCOH), syngas (LCOS), and metal (LCOM) production using e-wastes are estimated as 92.28 $/MWh, 3.67 $/kg, 0.0034 $/kWh, and 24.32 $/ton, respectively. The LCOH is found to be the least of 2.90 $/kg under the co-feed conditions of PCB syngas-PP. The integration of the e-waste based CLR with a steam turbine system achieved a net efficiency of 50%.     

Design and analysis of a combined floating photovoltaic system for electricity and hydrogen production

The current study deals with a potential solution for the replacement of fossil fuel based energy resources with a sustainable solar energy resource. Electrical energy demand of a small community is investigated where a floating photovoltaic system and integrated hydrogen production unit are employed. Data are taken from Mumcular Dam located in Aegean Region of Turkey. PvSyst software is used for the simulation purposes. Furthermore, the obtained results are analyzed in the HOMER Pro Software. Photovoltaic (PV) electricity provides the required load and excess electricity to be used in the electrolyzer and to produce hydrogen. Saving lands by preventing their usage in conventional PV farms, saving the water due to reducing evaporation, and compensating the intermittent availability of solar energy are among the obtained results of the study for the considered scenario. Stored hydrogen is used to compensate the electric load through generating electricity by fuel cell. Floating PV (FPV) system decreases the water evaporation of water resources due to 3010 m² shading area. FPV and Hydrogen Systems provides %99.43 of the electricity demand without any grid connection or fossil fuel usage, where 60.30 MWh/year of 211.94 MWh/year produced electricity is consumed by electric load at $0.6124/kWh levelized cost of electricity (LCOE).     

Using renewables to hedge against future electricity industry uncertainties—An Australian case study

A generation portfolio modelling was employed to assess the expected costs, cost risk and emissions of different generation portfolios in the Australian National Electricity Market (NEM) under highly uncertain gas prices, carbon pricing policy and electricity demand. Outcomes were modelled for 396 possible generation portfolios, each with 10,000 simulations of possible fuel and carbon prices and electricity demands. In 2030, the lowest expected cost generation portfolio includes 60% renewable energy. Increasing the renewable proportion to 75% slightly increased expected cost (by $0.2/MWh), but significantly decreased the standard deviation of cost (representing the cost risk). Increasing the renewable proportion from the present 15% to 75% by 2030 is found to decrease expected wholesale electricity costs by $17/MWh. Fossil-fuel intensive portfolios have substantial cost risk associated with high uncertainty in future gas and carbon prices. Renewables can effectively mitigate cost risk associated with gas and carbon price uncertainty. This is found to be robust to a wide range of carbon pricing assumptions. This modelling suggests that policy mechanisms to promote an increase in renewable generation towards a level of 75% by 2030 would minimise costs to consumers, and mitigate the risk of extreme electricity prices due to uncertain gas and carbon prices.     

Thermoeconomic analysis of a standalone solar hydrogen system with hybrid energy storage

A comprehensive thermoeconomic analysis is presented for a novel integrated solar hydrogen energy system for standalone operation. The proposed system includes a solar PVT module (photovoltaic thermal), a FC (Fuel cell) and a battery to meet the electrical load demand and domestic hot water over a year. The PVT component works as a primary energy source converting solar energy into electricity and heat. The excess electrical energy and hot water produced by PVT are consumed for producing hydrogen, which can be stored. The generated hydrogen is fed to the fuel cell to produce electricity and water to satisfy the demand. The proposed system is convenient for different seasons of the year because in all time, produced power satisfy the demand. The first and second laws of thermodynamics are used to evaluate the performance of each component and the overall system. Economic assessment of this system is also conducted considering the net present cost, and the system performance is optimized based on this parameter. The overall electrical efficiency of the system is obtained as 9% and the levelized cost of electricity is determined as $ 0.286/kWh. For a steady operation of system, integrating a battery system is convenient when solar energy is not available for a short term. When there is a longer-term shortage of solar radiation, up to 8 days, the electricity can be supplied by utilizing the hydrogen storage system.     

Realistic generation cost of solar photovoltaic electricity

Solar photovoltaic (SPV) power plants have long working life with zero fuel cost and negligible maintenance cost but requires huge initial investment. The generation cost of the solar electricity is mainly the cost of financing the initial investment. Therefore, the generation cost of solar electricity in different years depends on the method of returning the loan. Currently levelized cost based on equated payment loan is being used. The static levelized generation cost of solar electricity is compared with the current value of variable generation cost of grid electricity. This improper cost comparison is inhibiting the growth of SPV electricity by creating wrong perception that solar electricity is very expensive. In this paper a new method of loan repayment has been developed resulting in generation cost of SPV electricity that increases with time like that of grid electricity. A generalized capital recovery factor has been developed for graduated payment loan in which capital and interest payment in each installment are calculated by treating each loan installment as an independent loan for the relevant years. Generalized results have been calculated which can be used to determine the cost of SPV electricity for a given system at different places. Results show that for SPV system with specific initial investment of 5.00 $/kWh/year, loan period of 30 years and loan interest rate of 4% the levelized generation cost of SPV electricity with equated payment loan turns out to be 28.92 ¢/kWh, while the corresponding generation cost with graduated payment loan with escalation in annual installment of 8% varies from 9.51 ¢/kWh in base year to 88.63 ¢/kWh in 30th year. So, in this case, the realistic current generation cost of SPV electricity is 9.51 ¢/kWh and not 28.92 ¢/kWh. Further, with graduated payment loan, extension in loan period results in sharp decline in cost of SPV electricity in base year. Hence, a policy change is required regarding the loan repayment method. It is proposed that to arrive at realistic cost of SPV electricity long-term graduated payment loans may be given for installing SPV power plants such that the escalation in annual loan installments be equal to the estimated inflation in the price of grid electricity with loan period close to working life of SPV system.     

An economic investigation of the wind-hydrogen projects: A case study

Hydrogen as an energy carrier can play a significant role in reducing environmental emissions if it is produced from renewable energy resources. This research aims to assess hydrogen production from wind energy considering environmental, economic, and technical aspect for the East Azerbaijan province of Iran. The economic assessment is performed by calculation of payback period, levelized cost of hydrogen, and levelized cost of electricity. Since uncertainty in the power output of wind turbines may affect the payback period, all calculations are performed for four different turbine degradation rates. While it is common in the literature to choose the wind turbine based on a single criterion, this study implements Multi-Criteria Decision-Making (MCDM) techniques for this purpose. The results of Step-wise Weight Assessment Ratio Analysis illustrates that economic issue is the most important criterion for this research. The results of Weighted Aggregated Sum Product Assessment shows that Vestas V52 is the most suitable wind turbine for Ahar and Sarab cities, while Eovent EVA120 H-Darrieus is a better choice for other stations. The most suitable location for wind power generation is found to be Ahar, where it is estimated to annually generate 2914.8 kWh of electricity at the price of 0.045 $/kWh, and 47.2 tons of hydrogen at the price of 1.38 $/kg, which result in 583 tons of CO₂ emission reduction.     

Thermodynamic and economic assessment of a PEMFC-based micro-CCHP system integrated with geothermal-assisted methanol reforming

A micro-combined cooling heating and power (CCHP) system integrated with geothermal-assisted methanol reforming and incorporating a proton exchange membrane fuel cell (PEMFC) stack is presented. The novel CCHP system consists of a geothermal-based methanol steam reforming subsystem, PEMFC, micro gas turbine and lithium bromide (LiBr) absorption chiller. Geothermal energy is used as a heat source to drive methanol steam reforming to produce hydrogen. The unreacted methanol and hydrogen are efficiently utilized via the gas turbine and PEMFC to generate electricity, respectively. For thermodynamic and economic analysis, the effects of the thermodynamic parameters (geothermal temperature and molar ratio of water to methanol) and economic factors (such as methanol price, hydrogen price and service life) on the proposed system performance are investigated. The results indicate that the ExUF (exergy utilization factor the exergy utilization factor), TPES (trigeneration primary energy saving) and energy efficiency of the novel system can be reached at 8.8%, 47.24% and 66.3%, respectively; the levelized cost of energy is 0.0422 $/kWh, and the annual total cost saving ratio can be reached at 20.9%, compared with the conventional system. The novel system achieves thermodynamic and economic potential, and provides an alternative and promising way for efficiently utilizing abundant geothermal energy and methanol resources.     

Optimum energy evaluation and life cycle cost assessment of a hydrogen liquefaction system assisted by geothermal energy

In this study, analyses of the thermodynamic performance and life cycle cost of a geothermal energy-assisted hydrogen liquefaction system were performed in a computer environment. Geothermal water at a temperature of 200 °C and a flow rate of 100 kg/s was used to produce electricity. The produced electricity was used as a work input to liquefy the hydrogen in the advanced liquefaction cycle. The net work requirement for the liquefaction cycle was calculated as 8.6 kWh/kg LH₂. The geothermal power plant was considered as the work input in the liquefaction cycle. The hydrogen could be liquefied at a mass flow rate of 0.2334 kg/s as the produced electricity was used directly to produce liquid hydrogen in the liquefaction cycle. The unit costs of electricity and liquefied hydrogen were calculated as 0.012 $/kWh and 1.44 $/kg LH₂. As a result of the life cycle cost analysis of the system, the net present value (NPV) and levelized annual cost (LAC) were calculated as 123,100,000 and 14,450,000 $/yr. The simple payback period (N_spp) and discount payback period (N_dpp) of the system were calculated as 2.9 and 3.6 years, respectively.     

A 3E,hydrogen production,irrigation, and employment potential assessment of a hybrid energy system for tropical weather conditions – Combination of HOMER software,shannon entropy,and TOPSIS

The increasing threat to environmental sustainability as a result of greenhouse gas (GHG) emissions from fossil fuel base power plants has necessitated the need to find sustainable energy sources to meet the world's energy demands. This study focuses on assessing the potential of a hybrid power plant for the production of electricity, hydrogen for the production of fertilizer for agricultural activities, farmland irrigation, environmental impact as well as its employment potential in northern Ghana. The Shannon entropy weight and TOPSIS multi-criteria decision-making approach were adopted to rank and identify the optimal configuration out of five possible options for the study area. Results from the simulation show that the winning system, i.e., Hydro + Battery system would generate a total electricity of 1,095,679 kWh/year. A cost of electricity of 0.06 $/kWh with an operating cost (OC) of $18,318 was recorded for the winning system. The total produced hydrogen by the optimum configuration is 8816 kg/year at a levelized cost of hydrogen (LCOH) of 4.47 $/kg. The quantity of low-carbon fertilizer that can be produced from the produced hydrogen is also assessed. The optimum configuration also recorded an employment potential of 4 persons in 25 years. A total GHG equivalence of 383.49 metric tons of CO₂ equivalent indicating the level of emissions that will be avoided should the optimum system be used to meet the demands specified in this study was obtained.     

Transient simulation and techno-economic assessment of a near-zero energy building using a hydrogen storage system and different backup fuels

Proposing a cost-effective off-grid Hybrid Renewable Energy System (HRES) with hydrogen energy storage with a minimum CO2 emission is the main objective of the current study. The electricity demand of an office building is considered to be supplied by Photovoltaic Panels and wind turbines. The office building, modeled in Energy Plus and Open studio, has annual electricity consumption of 500 MWh electricity. 48.9% of the required electricity can be generated via renewable resources. Considering a system without energy storage, the remaining amount of electricity is generated from diesel generators. Hence, for reducing CO2 emission and fuel costs, a hydrogen energy storage system (ESS) is integrated into the system. Hydrogen ESS is responsible for supplying 38.6% of the demand electricity, which means that it can increase the energy supplying ability of the system from 48.9% to 87.5%. In addition to analyzing the application of the hydrogen storage system, the effect of four different kinds of fuel is considered as well. effects of Natural gas, Diesel, Propane, and LPG on the system's application are investigated in this study. Results indicate that natural gas emits less amount of CO2 compared to other fuels and also has a fuel cost of 3054 $/year, while hydrogen ESS is available. For the renewable system without ESS, the fuel cost rises to 10,266 $/year. However, liquid gas, Propane, and LPG have better performance in terms of CO2 emission and fuel cost, respectively.     

Economic analysis of hydrogen production from wastewater and wood for municipal bus system

The levelized cost of hydrogen for municipal fuel cell buses has been determined using the DOE H2A model for steam methane reforming (SMR), molten carbonate fuel cell reforming (MCFC), and wood gasification using wastewater biogas and willow wood chips as energy feedstocks. 300 kg H₂/day was chosen as the design capacity. Greenhouse gas emissions were calculated for each for the three processes and compared to diesel bus emissions in order to assess environmental impact. The levelized cost per kilogram for SMR, MCFC, and gasification is $5.12, $8.59, and $10.62, respectively. SMR provided the lowest sensitivity to feedstock price, and lowest levelized cost at various scales, with competitive cost to diesel on a cost/km basis. All three technologies provide a reduction in total greenhouse gases compared to diesel bus emissions, with MCFC providing the largest reduction. These results provide preliminary evidence that small scale distributed hydrogen production for public transportation can be relatively cost-effective and have minimal environmental impact.     

Evaluation of small wind turbines in distributed arrangement as sustainable wind energy option for Barbados

The island of Barbados is 99% dependent on fossil fuel imports to satisfy its energy needs, which is unsustainable. This study proposes a 10 MW distributed wind energy scheme using micro wind turbines (WT) of horizontal (HAWT) and vertical axis (VAWT) configurations. These units are rated less than 500 W, and the scheme is hereafter referred to as mWT10. mWT10 is compared to the proposed 10 MW medium WT farm by the Barbados Light & Power Company (BL&P). The economic bottom line is the levelized cost of electricity (LCOE). The results highlight the BL&P proposal as the best economic option at BDS$0.19 per kWh, while that of both mWT10 configurations exceeds the conventional cost of BDS$0.25 by two to nine times. This is attributed to significantly higher relative installation and operational costs. However, the financial gap between mWT10 LCOE and the retail price of electricity is much smaller due to a large fuel surcharge passed on to each customer. Annual additional benefits of using wind energy include: greenhouse gas emissions savings of 6–23 kt of carbon dioxide; and anavoided fuel costs of BDS$1.5–5.3 million.

The distributed mWT10 using HAWTs competes directly with the BL&P farm, however, it provides these benefits without the visual or ecological impacts of the larger machines. Conversely, VAWTs have features that favour a visually discrete and widely repeatable scheme but suffer relatively high costs. Therefore, this study illustrates the great potential of small wind turbines to be competitive with conventional wind farms, thus challenging the small wind industry to meet its potential by producing reliable and robust machines at lower cost.     

Comprehensive assessment on a hybrid PEMFC multi-generation system integrated with solar-assisted methane cracking

A hybrid proton exchange membrane fuel cell (PEMFC) multi-generation system model integrated with solar-assisted methane cracking is established. The whole system mainly consists of a disc type solar Collector, PEMFC, Organic Rankine cycle (ORC). Methane cracking by solar energy to generate hydrogen, which provides both power and heat. The waste heat and hydrogen generated during the reaction are efficiently utilized to generate electricity power through ORC and PEMFC. The mapping relationships between thermodynamic parameters (collector temperature and separation ratio) and economic factors (methane and carbon price) on the hybrid system performance are investigated. The greenhouse gas (GHG) emission reductions and levelized cost of energy (LCOE) are applied to environmental and economic performance evaluation. The results indicate that the exergy utilization factor (EXUF) and energy efficiency of the novel system can reach 21.9% and 34.6%, respectively. The solar-chemical energy conversion efficiency reaches 40.3%. The LCOE is 0.0733 $/kWh when the carbon price is 0.725 $/kg. After operation period, the GHG emission reduction and recovered carbon can reach 4 × 10⁷ g and 14,556 kg, respectively. This novel hybrid system provides a new pathway for the efficient utilization of solar and methane resources and promotes the popularization of PEMFC in zero energy building.     

Technico-economic analysis of off grid solar PV/Fuel cell energy system for residential community in desert region

A technico-economic analysis based on integrated modeling, simulation, and optimization approach is used in this study to design an off grid hybrid solar PV/Fuel Cell power system. The main objective is to optimize the design and develop dispatch control strategies of the standalone hybrid renewable power system to meet the desired electric load of a residential community located in a desert region. The effects of temperature and dust accumulation on the solar PV panels on the design and performance of the hybrid power system in a desert region is investigated. The goal of the proposed off-grid hybrid renewable energy system is to increase the penetration of renewable energy in the energy mix, reduce the greenhouse gas emissions from fossil fuel combustion, and lower the cost of energy from the power systems. Simulation, modeling, optimization and dispatch control strategies were used in this study to determine the performance and the cost of the proposed hybrid renewable power system. The simulation results show that the distributed power generation using solar PV and Fuel Cell energy systems integrated with an electrolyzer for hydrogen production and using cycle charging dispatch control strategy (the fuel cell will operate to meet the AC primary load and the surplus of electrical power is used to run the electrolyzer) offers the best performance. The hybrid power system was designed to meet the energy demand of 4500 kWh/day of the residential community (150 houses). The total power production from the distributed hybrid energy system was 52% from the solar PV, and 48% from the fuel cell. From the total electricity generated from the photovoltaic hydrogen fuel cell hybrid system, 80.70% is used to meet all the AC load of the residential community with negligible unmet AC primary load (0.08%), 14.08% is the input DC power for the electrolyzer for hydrogen production, 3.30% are the losses in the DC/AC inverter, and 1.84% is the excess power (dumped energy). The proposed off-grid hybrid renewable power system has 40.2% renewable fraction, is economically viable with a levelized cost of energy of 145 $/MWh and is environmentally friendly (zero carbon dioxide emissions during the electricity generation from the solar PV and Fuel Cell hybrid power system).     

Levelized cost of storage — Introducing novel metrics

The increasing share of variable renewable generation capacity leads to a growing interest in electricity storage technologies and a summarizing cost metric to analyze the economic viability of such electricity storage units. For conventional generation technologies, the levelized cost of electricity (LCOE) is a well-known metric. In the context of electricity storage however, such LCOE-like metrics are only limitedly applicable as the finite energy storage capacity can limit the charge and discharge scheduling decisions of the storage operator. In addition, the “fuel”, i.e., charged electricity, and “generated electricity”, i.e., discharged electricity, is one and the same commodity which provides the opportunity to use an adapted levelized cost metric. This work analyzes three different levelized cost metrics and their application to electricity storage units used for electric energy arbitrage. The strengths and shortcomings of these storage cost metrics are analyzed in order to determine how they can be applied correctly. This analysis results in the following recommendations. First, it is recommended to use a levelized cost metric in combination with an analysis of a representative price profile upon which the storage operator will act. This allows a more accurate estimation of the number of charging and discharging hours and the associated charging cost and discharging revenue, given the energy storage capacity constraints of the storage unit. Second, when a number of different representative price profiles, hence with different charging costs, is available, it is recommended to use a cost metric which is independent of the charging cost as this single metric can be compared to each price profile, thereby facilitating the interpretation of the results. The results and conclusions from this work provide a framework on how to use levelized cost metrics in the context of electricity storage. Such metrics may help policy makers and investors in prioritizing energy storage investment decisions.     

Economic analysis of the seasonal storage of electricity with liquid organic hydrides

A future alternative for generating winter electricity is the seasonal storage of surplus summer electricity in the form of chemically bound hydrogen in liquid organic hydrocarbons using the MTH-system (Methylcyclohexane–Toluene–Hydrogen). This paper compares the economics of the MTH-system with the conventional production of electricity from fossil fuel sources.

Based on numerical modelling of the individual plants, simulations of several design alternatives of the MTH-system were performed for 1000 GWh of stored summer electricity and 80 MW output. The overall efficiencies η_tot and the economic results of these simulations are η_tot=0.40 and 0.26 $/kWh for the MTH-SOFC system alternative, η_tot=0.33 and 0.30 $/kWh for the MTH-MCFC and η_tot=0.25 and 0.36 $/kWh for the MTH-system with gas and steam turbines.

Compared with the cost of electricity production using fossil fuels (0.05–0.1 $/kWh), the electricity produced by the MTH-system is expensive. Therefore an economic comparison including an assumed carbon tax was made to account for a possible scarcity of energy or the environmental impact due to the use of fossil energy resources. It concludes that the MTH-system is not competitive for the levels of carbon tax under discussion, but compares with options for providing electricity from new renewables.

Due to the disparities in economics and carbon taxes, a best case study of the MTH-system was made to reduce its economic disadvantages. This results in a maximum efficiency of the MTH-system of 0.48 with corresponding winter electricity costs of 0.17 $/kWh.     

Economic implications of thermal energy storage for concentrated solar thermal power

Solar energy is an attractive renewable energy source because the sun's energy is plentiful and carbon-free. However, solar energy is intermittent and not suitable for base load electricity generation without an energy backup system. Concentrated solar power (CSP) is unique among other renewable energy options because it can approach base load generation with molten salt thermal energy storage (TES). This paper describes the development of an engineering economic model that directly compares the performance, cost, and profit of a 110-MW parabolic trough CSP plant operating with a TES system, natural gas-fired backup system, and no backup system. Model results are presented for 0–12 h backup capacities with and without current U.S. subsidies. TES increased the annual capacity factor from around 30% with no backup to up to 55% with 12 h of storage when the solar field area was selected to provide the lowest levelized cost of energy (LCOE). Using TES instead of a natural gas-fired heat transfer fluid heater (NG) increased total plant capital costs but decreased annual operation and maintenance costs. These three effects led to an increase in the LCOE for PT plants with TES and NG backup compared with no backup. LCOE increased with increasing backup capacity for plants with TES and NG backup. For small backup capacities (1–4 h), plants with TES had slightly lower LCOE values than plants with NG backup. For larger backup capacities (5–12 h), plants with TES had slightly higher LCOE values than plants with NG backup. At these costs, current U.S. federal tax incentives were not sufficient to make PT profitable in a market with variable electricity pricing. Current U.S. incentives combined with a fixed electricity price of $200/MWh made PT plants with larger backup capacities more profitable than PT plants with no backup or with smaller backup capacities. In the absence of incentives, a carbon price of $100–$160/tonne CO_2eq would be required for these PT plants to compete with new coal-fired power plants in the U.S. If the long-term goal is to increase renewable base load electricity generation, additional incentives are needed to encourage new CSP plants to use thermal energy storage in the U.S.     

Fuel cell electric vehicle as a power plant: Fully renewable integrated transport and energy system design and analysis for smart city areas

Reliable and affordable future zero emission power, heat and transport systems require efficient and versatile energy storage and distribution systems. This paper answers the question whether for city areas, solar and wind electricity together with fuel cell electric vehicles as energy generators and distributors and hydrogen as energy carrier, can provide a 100% renewable, reliable and cost effective energy system, for power, heat, and transport. A smart city area is designed and dimensioned based on European statistics. Technological and cost data is collected of all system components, using existing technologies and well-documented projections, for a Near Future and Mid Century scenario. An energy balance and cost analysis is performed. The smart city area can be balanced requiring 20% of the car fleet to be fuel cell vehicles in a Mid Century scenario. The system levelized cost in the Mid Century scenario is 0.09 €/kWh for electricity, 2.4 €/kg for hydrogen and specific energy cost for passenger cars is 0.02 €/km. These results compare favorably with other studies describing fully renewable power, heat and transport systems.     

Economic evaluation of a stand-alone residential photovoltaic power system in Bangladesh

The economics of stand-alone photovoltaic power system is studied to test its feasibility in remote and rural areas of Bangladesh and to compare renewable generators with non-renewable generators. The life cycle cost of these generators are determined using the method of net present value analysis. It is found that the life cycle cost of this experimental PV system is Tk. 43.40/kWh for one family (US $1.00 = Bangladeshi taka Tk.50.00). The life cycle cost for grid electricity is Tk. 20.00/kWh and Tk. 7.75/kWh for generation of fuel costs of Tk. 6.80/kWh and Tk. 0.47/kWh respectively. For a village 1 km away from the distribution line, this cost becomes Tk. 125.00/kWh for a family. For petrol generator life cycle cost is Tk. 50.00/kWh at fuel price of Tk. 22.00 per litre. For diesel generator life cycle cost is found to be Tk. 46.10/kWh at fuel cost of Tk. 15.00 per litre. It is observed that the life cycle cost of one unit of energy from grids that are 1 km away from a village is much higher than the cost of energy from a PV system. Thus, the use of PV system is economically feasible in rural villages and remote areas of Bangladesh, where grid electricity is not available.     

Techno-economic analysis of hydrogen transportation infrastructure using ammonia and methanol

The transformation from a fossil fuels economy to a low carbon economy reshapes how energy is transmitted. Since most renewable energy is harvested in the form of electricity, hydrogen obtained from water electrolysis using green electricity is considered a promising energy vector. However, the storage and transportation of hydrogen at large scales pose challenges to the existing energy infrastructures, both regarding technological and economic aspects. To facilitate the distribution of renewable energy, a set of candidate hydrogen transportation infrastructures using methanol and ammonia as hydrogen carriers were proposed. A systematical analysis reveals that the levelized costs of transporting hydrogen using methanol and ammonia in the best cases are $1879/t-H₂ and $1479/t-H₂, respectively. The levelized cost of energy transportation using proposed infrastructures in the best case is $10.09/GJ. A benchmark for hydrogen transportation infrastructure design is provided in this study.