Hydrogen station siting optimization based on multi-source hydrogen supply and life cycle cost

Hydrogen station siting plays an important role in hydrogen-energy infrastructure construction, and it's different from gas station siting. A gas station has a unitary way of fuel transport and a unitary fuel supplier, hence no consideration given to factors like fuel supplier and way of fuel transport at the time of siting it. However, hydrogen for a hydrogen fueling station can be supplied jointly from a couple of different sources nearby. Since there is a diversity of hydrogen price and productivity between different sources, hydrogen fueling station siting also entails consideration of the effect of the proportions of hydrogen supplied by the sources on hydrogen's life cycle cost. With the purpose of minimizing hydrogen's life cycle cost, this paper creates a mathematical model for station siting, largely for the case that each station can get hydrogen supply from combined multiple sources, and considers the effect of geographical information factors on station siting. The effect of geographical information factors on such siting is described herein in two cases to avoid selecting a must-not-build location and rebuilding into a gasoline-hydrogen fueling station at an existing gas station location. The latter can reduce station construction and operating costs. By creating a particle swarm optimization (PSO) example for station siting with Shanghai-Nanjing Expressway and constructing a position particle swarm in the form of 5D vector in order to optimize 5 station locations at the same time as well a weight particle swarm in the form of 2D matrix in order to optimize the multi-source hydrogen supply programs, the paper works out optimal station construction locations on condition of multi-source hydrogen supply, multi-source hydrogen supply programs, ways of storage and transport and corresponding hydrogen's optimal life cycle cost.     

Impact of hydrogen refueling configurations and market parameters on the refueling cost of hydrogen

The cost of hydrogen in early fuel cell electric vehicle (FCEV) markets is dominated by the cost of refueling stations, mainly due to the high cost of refueling equipment, small station capacities, lack of economies of scale, and low utilization of the installed refueling capacity. Using the hydrogen delivery scenario analysis model (HDSAM), this study estimates the impacts of these factors on the refueling cost for different refueling technologies and configurations, and quantifies the potential reduction in future hydrogen refueling cost compared to today's cost in the United States. The current hydrogen refueling station levelized cost, for a 200 kg/day dispensing capacity, is in the range of $6–$8/kg H₂ when supplied with gaseous hydrogen, and $8–$9/kg H₂ for stations supplied with liquid hydrogen. After adding the cost of hydrogen production, packaging, and transportation to the station's levelized cost, the current cost of hydrogen at dispensers for FCEVs in California is in the range of $13–$15/kg H₂. The refueling station capacity utilization strongly influences the hydrogen refueling cost. The underutilization of station capacity in early FCEV markets, such as in California, results in a levelized station cost that is approximately 40% higher than it would be in a scenario where the station had been fully utilized since it began operating. In future mature hydrogen FCEV markets, with a large demand for hydrogen, the refueling station's levelized cost can be reduced to $2/kg H₂ as a result of improved capacity utilization and reduced equipment cost via learning and economies of scale.     

Life cycle cost analysis: A case study of hydrogen energy application on the Orkney Islands

Hydrogen can compensate for the intermittent nature of some renewable energy sources and encompass the options of supplying renewables to offset the use of fossil fuels. The integrating of hydrogen application into the energy system will change the current energy market. Therefore, this paper deploys the life cycle cost analysis of hydrogen production by polymer electrolyte membrane (PEM) electrolysis and applications for electricity and mobility purposes. The hydrogen production process includes electricity generated from wind turbines, PEM electrolyser, hydrogen compression, storage, and distribution by H₂ truck and tube trailer. The hydrogen application process includes PEM fuel cell stacks generating electricity, a H₂ refuelling station supplying hydrogen, and range extender fuel cell electric vehicles (RE-FCEVs). The cost analysis is conducted from a demonstration project of green hydrogen on a remote archipelago. The methodology of life cycle cost is employed to conduct the cost of hydrogen production and application. Five scenarios are developed to compare the cost of hydrogen applications with the conventional energy sources considering CO₂ emission cost. The comparisons show the cost of using hydrogen for energy purposes is still higher than the cost of using fossil fuels. The largest contributor of the cost is the electricity consumption. In the sensitivity analysis, policy supports such as feed-in tariff (FITs) could bring completive of hydrogen with fossil fuels in current energy market.     

Process optimization for large-scale hydrogen liquefaction

The investment in the hydrogen infrastructure for hydrogen mobility has lately seen a significant acceleration. The demand for energy and cost efficient hydrogen liquefaction processes has also increased steadily. A significant scale-up in liquid hydrogen (LH₂) production capacity from today's typical 5–10 metric tons per day (tpd) LH₂ is predicted for the next decade. For hydrogen liquefaction, the future target for the specific energy consumption is set to 6 kWh per kg LH₂ and requires a reduction of up to 40% compared to conventional 5 tpd LH₂ liquefiers. Efficiency improvements, however, are limited by the required plant capital costs, technological risks and process complexity. The aim of this paper is the reduction of the specific costs for hydrogen liquefaction, including plant capital and operating expenses, through process optimization. The paper outlines a novel approach to process development for large-scale hydrogen liquefaction. The presented liquefier simulation and cost estimation model is coupled to a process optimizer with specific energy consumption and specific liquefaction costs as objective functions. A design optimization is undertaken for newly developed hydrogen liquefaction concepts, for plant capacities between 25 tpd and 100 tpd LH₂ with different precooling configurations and a sensitivity in the electricity costs. Compared to a 5 tpd LH₂ plant, the optimized specific liquefaction costs for a 25 tpd LH₂ liquefier are reduced by about 50%. The high-pressure hydrogen cycle with a mixed-refrigerant precooling cycle is selected as preferred liquefaction process for a cost-optimized 100 tpd LH₂ plant design. A specific energy consumption below 6 kWh per kg LH₂ can be achieved while reducing the specific liquefaction costs by 67% compared to 5 tpd LH₂ plants. The cost targets for hydrogen refuelling and mobility can be reached with a liquid hydrogen distribution and the herewith presented cost-optimized large-scale liquefaction plant concepts.     

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.     

Design proposal for hydrogen refueling infrastructure deployment in the Northeastern United States

Fuel cell vehicles (FCVs) are expected to be commercially available on the world market in 2015, therefore, introducing hydrogen-refueling stations is an urgent issue to be addressed. This paper proposes deployment plan of hydrogen infrastructure for the success of their market penetration in the Northeastern United States. The plan consists of three-timeline stages from 2013 to 2025 and divides the designated region into urban area, suburban area and area adjacent to expressway, so that easy to access to hydrogen stations can be realized. Station is chosen from four types of stations: off-site station, urban-type on-site station, suburban-type on-site station and portable station, associated with growing demand. In addition, on-site station is used as hydrogen production factory for off-site station to save total investment. This deployment plan shows that 83% of urban residents can reach station within 10 min in 2025, and that more than 90% people especially in four major cities: Boston, New York City, Philadelphia, and Washington, D.C. can get to station within 10 min by Geographic Information System (GIS) calculation.     

Exergoeconomic and thermodynamic analyses of an externally fired combined cycle with hydrogen production and injection to the combustion chamber

A hydrogen production unit is successfully integrated with an externally fired combined cycle using biomass fuel. The hydrogen produced in an electrolyzer can be used for other purposes, but when there is temporarily no market for it is injected into the combustion chamber of an externally fired combined cycle. Injecting hydrogen into the combustion chamber was found to reduce fuel consumption by almost 27%. Moreover, hydrogen injection decreased the energy efficiency and exergy efficiency by 45%, and decreased both the exergy loss and exergy destruction rates. Meanwhile, CO₂ emissions decreased by 32%. However, there are some disadvantages to hydrogen injection, especially from the viewpoint of exergoeconomics. The total unit product cost for the externally fired combined cycle with hydrogen injection is almost 27% more than the unit without hydrogen injection, although the exergy loss and destruction costs decreased with hydrogen injection. The value of the relative cost difference with hydrogen injection rises by 40%. Also the exergoeconomic assessment demonstrates that the cost of components (purchase and maintenance) are higher than cost of components' exergy destruction for both cycles, i.e., with and without hydrogen injection. As the compressor pressure ratio increases, optimal points are identified for biomass flow rate, energy and exergy efficiencies, exergy destruction and loss rates, exergy destruction and loss exergy cost rates, total unit product cost and relative cost difference.     

Off-grid solar powered charging station for electric and hydrogen vehicles including fuel cell and hydrogen storage

This paper designs an off-grid charging station for electric and hydrogen vehicles. Both the electric and hydrogen vehicles are charged at the same time. They appear as two electrical and hydrogen load demand on the charging station and the charging station is powered by solar panels. The output power of solar system is separated into two parts. On part of solar power is used to supply the electrical load demand (to charge the electric vehicles) and rest runs water electrolyzer and it will be converted to the hydrogen. The hydrogen is stored and it supplies the hydrogen load demand (to charge the hydrogen-burning vehicles). The uncertainty of parameters (solar energy, consumed power by electrical vehicles, and consumed power by hydrogen vehicles) is included and modeled. The fuel cell is added to the charging station to deal with such uncertainty. The fuel cell runs on hydrogen and produces electrical energy to supply electrical loading under uncertainties. The diesel generator is also added to the charging station as a supplementary generation. The problem is modeled as stochastic optimization programming and minimizes the investment and operational costs of solar and diesel systems. The introduced planning finds optimal rated powers of solar system and diesel generator, operation pattern for diesel generator and fuel cell, and the stored hydrogen. The results confirm that the cost of changing station is covered by investment cost of solar system (95%), operational cost of diesel generator (4.5%), and investment cost of diesel generator (0.5%). The fuel cell and diesel generator supply the load demand when the solar energy is zero. About 97% of solar energy will be converted to hydrogen and stored. The optimal operation of diesel generator reduces the cost approximately 15%.     

Life cycle assessment of hydrogen supply chain with special attention on hydrogen refuelling stations

The controversial and highly emotional discussion about biofuels in recent years has shown that greenhouse gas² (GHG) emissions can only be evaluated in an acceptable way by carrying out a full life cycle assessment (LCA) taking the overall life cycle including all necessary pre-chains into consideration. Against this background, the goal of this paper is it to analyse the overall life cycle of a hydrogen production and provision. A state of the art hydrogen refuelling station in Hamburg/Germany opened in February 2012 is therefore taken into consideration. Here at least 50% hydrogen from renewable sources of energy is produced on-site by water electrolysis based on surplus electricity from wind (mainly offshore wind parks) and water. The remaining other 50% of hydrogen to be sold by this station mainly to hydrogen-fuelled buses is provided by trucks from a large-scale production plant where hydrogen is produced from methane or glycerol as a by-product of the biodiesel production. These two pathways are compared within the following explanations with hydrogen production from biomass and from coal. The results show that – with the goal of reducing GHG emissions on a life cycle perspective – hydrogen production based on a water electrolysis fed by electricity from the German electricity mix should be avoided. Steam methane reforming is more promising in terms of GHG reduction but it is still based on a finite fossil fuel. For a climatic sound provision of hydrogen as a fuel electricity from renewable sources of energy like wind or biomass should be used.     

Two-tier pressure consolidation operation method for hydrogen refueling station cost reduction

An operation strategy known as two-tier “pressure consolidation” of delivered tube-trailers (or equivalent supply storage) has been developed to maximize the throughput at gaseous hydrogen refueling stations (HRSs) for fuel cell electric vehicles (FCEVs). The high capital costs of HRSs and the consequent high investment risk are deterring growth of the infrastructure needed to promote the deployment of FCEVs. Stations supplied by gaseous hydrogen will be necessary for FCEV deployment in both the near and long term. The two-tier pressure consolidation method enhances gaseous HRSs in the following ways: (1) reduces the capital cost compared with conventional stations, as well as those operating according to the original pressure consolidation approach described by Elgowainy et al. (2014) [1], (2) minimizes pressure cycling of HRS supply storage relative to the original pressure consolidation approach; and (3) increases use of the station's supply storage (or delivered tube-trailers) while maintaining higher state-of-charge vehicle fills.     

Performance and cost modelling taking into account the uncertainties and sensitivities of current and next-generation PEM water electrolysis technology

This paper presents a bottom-up approach to the assessment of model performance and costs of a proton-exchange-membrane electrolysis considering cell, stack and process levels. The cell voltage is modelled dependent on current density and detailed models for stack, investment and hydrogen costs are developed. Taking into account current research on PEM electrolysis, such as the use of thinner membranes or low precious metal loading on the electrodes, allows the prediction of next generation's efficiency and costs. By comparison of a current and next-generation PEM electrolysis, the effectiveness of individual development steps was assessed and remaining space for efficiency and cost improvement was identified. This can help to prioritize and to focus on development steps which are most effective.In the next generation, efficiency will be increased even at higher current density operation. Thus, specific stack costs will drop to less than half of present day costs which is decisive to achieve lower hydrogen production costs in the next generation. Specific installed costs and hydrogen production costs of the current and next generation are calculated for plant sizes up to 100 MW_DC and reveal significant cost decrease for plant capacities up to 25 MW_DC while only changing slightly for capacities larger than this.Costs are always subject to uncertainties due to model assumptions and boundary conditions that need to be defined. Uncertainties and the sensitivities of the model are estimated and assessed to provide an indication of the actual cost range. Main cost model uncertainties are identified to arise from membrane electrode and stack assembly costs, civil engineering and construction surcharge as well as the electrical system. Hydrogen costs are dominated by operating costs and therefore are highly sensitive to the annual operating hours and the electricity price, which have a greater impact on the hydrogen costs than the model assumptions for capital costs.     

An analysis of hydrogen production from renewable electricity sources

Three aspects of producing hydrogen via renewable electricity sources are analyzed to determine the potential for solar and wind hydrogen production pathways: a renewable hydrogen resource assessment, a cost analysis of hydrogen production via electrolysis, and the annual energy requirements of producing hydrogen for refueling. The results indicate that ample resources exist to produce transportation fuel from wind and solar power. However, hydrogen prices are highly dependent on electricity prices. For renewables to produce hydrogen at $2 kg⁻¹, using electrolyzers available in 2004, electricity prices would have to be less than $0.01 kWh⁻¹. Additionally, energy requirements for hydrogen refueling stations are in excess of 20 GWh/year. It may be challenging for dedicated renewable systems at the filling station to meet such requirements. Therefore, while plentiful resources exist to provide clean electricity for the production of hydrogen for transportation fuel, challenges remain to identify optimum economic and technical configurations to provide renewable energy to distributed hydrogen refueling stations.     

Hydrogen perspectives in Italy: Analysis of possible deployment scenarios

The paper analyses Italian hydrogen scenarios to meet climate change, environmental and energy security issues. An Italy-Markal model was used to analyse the national energy–environment up to 2050. About 40 specific hydrogen technologies were considered, reproducing the main chains of production, transport and consumption, with a focus on transport applications. The analysis is based on the Baseline and Alternative scenario results, where hydrogen reaches a significant share. The two scenarios constitute the starting points to analyse the hydrogen potential among the possible energy policy options. The energy demand in the Baseline scenario reaches values around 240 Mtoe at 2030, with an average annual growth of 0.9%. The Alternative scenario reduces consumption down to 220 Mtoe and stabilizes the _CO2${\mathrm{CO}}_2$ emissions. The Alternative scenario expects a rapid increase of hydrogen vehicles in 2030, up to 2.5 million, corresponding to 1 Mtoe of hydrogen consumption. A sensitivity analysis shows that the results are rather robust.     

Economics of hydrogen production and liquefaction by geothermal energy

Seven models are considered for the production and liquefaction of hydrogen by geothermal energy. In these models, we use electrolysis and high-temperature steam electrolysis processes for hydrogen production, a binary power plant for geothermal power production, and a pre-cooled Linde–Hampson cycle for hydrogen liquefaction. Also, an absorption cooling system is used for the pre-cooling of hydrogen before the liquefaction process. A methodology is developed for the economic analysis of the models. It is estimated that the cost of hydrogen production and liquefaction ranges between 0.979 $/kg H₂ and 2.615 $/kg H₂ depending on the model. The effect of geothermal water temperature on the cost of hydrogen production and liquefaction is investigated. The results show that the cost of hydrogen production and liquefaction decreases as the geothermal water temperature increases. Also, capital costs for the models involving hydrogen liquefaction are greater than those for the models involving hydrogen production only.     

On optimal investment strategies for a hydrogen refueling station

The uncertainty and cost of changing from a fossil-fuel-based society to a hydrogen-based society are considered to be extensive obstacles to the introduction of fuel cell vehicles (FCVs). The absence of existing profitable refueling stations has been shown to be one of the major barriers. This paper investigates methods for calculating an optimal transition from a gasoline refueling station to future methane and hydrogen combined use with an on site small-scale reformer for methane. In particular, we look into the problem of matching the hydrogen capacity of a single refueling station to an increasing demand. Based on an assumed future development scenario, optimal investment strategies are calculated. First, a constant utilization of the hydrogen reformer is assumed in order to find the minimum hydrogen production cost. Second, when considerations such as periodic maintenance are taken into account, optimal control is used to concurrently find both a short term equipment variable utilization for one week and a long term strategy. The result is a minimum hydrogen production cost of $4–6/kg, depending on the number of reinvestments during a 20 year period. The solution is shown to yield minimum hydrogen production cost for the individual refueling station, but the solution is sensitive to variations in the scenario parameters.     

Integrated planning method of green hydrogen supply chain for hydrogen fuel cell vehicles

To satisfy the growing refueling demand of hydrogen fuel cell vehicles (HFCVs) with carbon-free hydrogen supply, this paper proposes an integrated planning method of green hydrogen supply chain. First, the k-shorted path method is introduced to analyze HFCV refueling load considering vehicle travel habits and routing diversity. Second, based on it, a two-stage integrated planning model is established to minimize the total investment and operation cost. The construction of hydrogen refueling stations, electrolysis-based hydrogen generation stations and hydrogen pipelines are coordinated with their operating constraints, constituting the green hydrogen supply chain, in which hydrogen storage is also an important part for consideration to address variable renewable power. Then, the proposed model is reformulated as a mixed integer linear programing (MILP) problem solved efficiently. Finally, the case studies are carried out on an urban area in Xi'an China to verify the validity and correctness of the proposed method. The results show that the integrated planning can realize synergy benefits. The influence of electricity prices and k values is also discussed.     

Hydrogen station location optimization based on multiple data sources

A hydrogen station is one that fills or stores the hydrogen, which is critical to the commercial development of hydrogen energy and fuel cell vehicle industry. Therefore, its location planning becomes an important issue. Similar to the electric vehicle (EV) charging station's planning, several factors are considered including the location, the demand of the fuel, the driving distance, etc. In this paper, multiple data sources are applied to the site selection model, including the existing petrol-refueling station network data, geographic information system (GIS) data, population data and regional economic data. Based on the operation of the genetic algorithm, combined with the idea of the greedy algorithm and the annealing algorithm, we propose a multi-algorithm hybrid solution, which not only can avoid local optimal, but also can converge quickly. On the basis of the site selection scheme of the hydrogen station in California, we have optimized the location scheme in Beijing. Finally, we present the feasibility proposals for hydrogen station location in Beijing, including the appropriate number of hydrogen stations in different regions, the reasonable coverage distance of hydrogen stations, etc. Due to the huge development prospects for hydrogen energy and the urgent need to reduce the construction cost of hydrogen stations in China, this research can quickly optimize the location of the hydrogen station and further explore potential mathematical relationships, which has certain social significance and economic benefits.     

Polysilanes: The grail for a highly-neglected hydrogen storage source

The hydrogen economy is a proposed system of delivering energy using hydrogen for engines and fuel cells. Otherwise, hydrogen, in comparison to hydrocarbons, is quite difficult to store or transport with current technology since it possesses a good energy density by weight, but a poor energy density by volume requiring a large tank to store at high pressure and low temperature. In this context, polysilanes constitute a neglected hydrogen storage source. We present a general catalyzed environmentally friendly, rapid and safe hydrogen production from organosilane hydrogen carriers' derivatives by reacting with water. The reaction is successful with a wide range of silane derivatives in quantitative yield of H₂ gas and could be used for daily life applications due to its modest cost, easy approach for implementing and limitation of greenhouse gas liberation.     

Review and comparison of various hydrogen production methods based on costs and life cycle impact assessment indicators

Hydrogen is a clean, renewable secondary energy source. The development of hydrogen energy is a common goal pursued by many countries to combat the current global warming trend. This paper provides an overview of various technologies for hydrogen production from renewable and non-renewable resources, including fossil fuel or biomass-based hydrogen production, microbial hydrogen production, electrolysis and thermolysis of water and thermochemical cycles. The current status of development, recent advances and challenges of different hydrogen production technologies are also reviewed. Finally, we compared different hydrogen production methods in terms of cost and life cycle environmental impact assessment. The current mainstream approach is to obtain hydrogen from natural gas and coal, although their environmental impact is significant. Electrolysis and thermochemical cycle methods coupled with new energy sources show considerable potential for development in terms of economics and environmental friendliness.     

Economic and environmental competitiveness of high temperature electrolysis for hydrogen production

Alternative hydrogen production technologies are sought in part to reduce the greenhouse gas (GHG) emissions intensity compared with Steam Methane Reforming (SMR), currently the most commonly employed hydrogen production technology globally. This study investigates hydrogen production via High Temperature Steam Electrolysis (HTSE) in terms of GHG emissions and cost of hydrogen production using a combination of Aspen HYSYS® modelling and life cycle assessment. Results show that HTSE yields life cycle GHG emissions from 3 to 20 kg CO_2e/kg H₂ and costs from $2.5 to 5/kg H₂, depending on the system parameters (e.g., energy source). A carbon price of $360/tonne CO_2e is estimated to be required to make HTSE economically competitive with SMR. This is estimated to potentially decrease to $50/tonne CO_2e with future technology advancements (e.g., fuel cell lifetime). The study offers insights for technology developers seeking to improve HTSE, and policy makers for decisions such as considering support for development of hydrogen production technologies.