The evolution of size and cost of a hydrogen delivery infrastructure in Europe in the medium and long term

The successful deployment of a hydrogen delivery (transmission and distribution) infrastructure will be critical for the widespread use of hydrogen. Estimates based on three scenarios that vary in the degree of hydrogen penetration in the European energy system indicate that between 1 and 4 million km of distribution pipelines, and up to 35 000 km of high-pressure transmission and 400 000 km of medium pressure sub-transmission pipelines may be needed by 2050. A truck fleet for the supply of liquefied hydrogen may reach the size of 3000–8000 vehicles. The cumulative capital necessary to build this infrastructure by 2050 may range between 700 and 2200 thousand million euros for the most optimistic scenario and is significantly lower for the other scenarios. Most of this will be needed for the development of the distribution network. These costs however represent a relatively small fraction (7.5–22%) of the annual gross value added of the energy sector.     

Farm-scale bio-power-to-methane: Comparative analyses of economic and environmental feasibility

Power-to-gas technologies are considered to be part of the future energy system, but their viability and applicability need to be assessed. Therefore, models for the viability of farm-scale bio-power-to-methane supply chains to produce green gas were analysed in terms of levelised cost of energy, energy efficiency and saving of greenhouse gas emission. In bio-power-to-methane, hydrogen from electrolysis driven by surplus renewable electricity and carbon dioxide from biogas are converted to methane by microbes in an ex situ trickle-bed reactor. Such bio-methanation could replace the current upgrading of biogas to green gas with membrane technology. Four scenarios were compared: a reference scenario without bio-methanation (A), bio-methanation (B), bio-methanation combined with membrane upgrading (C) and the latter with use of renewable energy only (all-green; D). The reference scenario (A) has the lowest costs for green gas production, but the bio-methanation scenarios (B-D) have higher energy efficiencies and environmental benefits. The higher costs of the bio-methanation scenarios are largely due to electrolysis, whereas the environmental benefits are due to the use of renewable electricity. Only the all-green scenario (D) meets the 2026 EU goal of 80% reduction of greenhouse gas emissions, but it would require a CO₂ price of 200 € t⁻¹ to achieve the levelised cost of energy of 65 €ct Nm⁻³ of the reference scenario. Inclusion of the intermittency of renewable energy in the scenarios substantially increases the costs. Further greening of the bio-methanation supply chain and how intermittency is best taken into account need further investigation.     

Cost assessment and evaluation of various hydrogen delivery scenarios

In this paper, performance and cost assessment studies, including the stages of hydrogen storage, transmission and distribution of three different hydrogen delivery pathways are undertaken comparatively. The produced hydrogen is stored under different temperatures and pressures and then transported to the nearby cities for distribution. In addition, three different methods for the transportation of the produced hydrogen to the distribution centers are studied, which are as transportation for hydrogen by the pressurized tanks, cryogenic liquid hydrogen tanker and the gas pipelines. Moreover, the transmission options from the distribution center to the target consumer are also examined for three different conditions. As a result, the hydrogen production capacity, the levelized cost of energy distribution (in $/kg), the infrastructure costs (truck, tanker number, gas line costs, etc.) for the selected transmission scenario are calculated. Furthermore, the environmental impact (greenhouse gas (GHG) emissions) and some application parameters of the proposed system (e.g., number of hydrogen fuel stations and the distance between the stations, length of the distribution lines, etc.) are also determined. The highest levelized cost of delivery is obtained as 8.02 $/kg H₂ for the first scenario whereas the lowest cost is obtained as 2.73 $/kg H₂ for the third scenario.     

Cost of a potential hydrogen-refueling network for heavy-duty vehicles with long-haul application in Germany 2050

Long-distance road-freight transport emits a large share of Germany's greenhouse gas (GHG) emissions. A potential solution for reducing GHG emissions in this sector is to use green hydrogen in fuel cell electric vehicles (FC-HDV) and establish an accompanying hydrogen refueling station (HRS) network. In this paper, we apply an existing refueling network design model to a HDV-HRS network for Germany until 2050 based on German traffic data for heavy-duty trucks and estimate its costs. Comparing different fuel supply scenarios (pipeline vs. on-site), The on-site scenario results show a network consisting of 137 stations at a cost of 8.38 billion € per year in 2050 (0.40 € per vehicle km), while the centralized scenario with the same amount of stations shows a cheaper cost with 7.25 billion euros per year (0.35 € per vehicle km). The hydrogen cost (LCOH) varies from 5.59 €/kg (pipeline) to 6.47 €/kg (on-site) in 2050.     

Integrated MAED–MARKAL-based analysis of future energy scenarios of Nepal

This paper employs an integrated model for analysis of energy demand and MARKet ALlocation modelling framework for assessing different pathways for the development of energy systems of Nepal. Four energy scenarios are analysed with the time horizon from 2010 to 2030. With high electrification and energy efficiency and demand-side management, the analysis reveals that all three major goals of sustainable energy for all can be achieved by 2030, but that the total discounted systems costs required account for three times the costs of the reference scenario. In the policy scenario, net fuel import costs and greenhouse gas emissions will decline by 20% and 35%, respectively and the share of renewable energy will increase from 3% in 2010 to 22% in 2030. The analysis provides insights for selecting a better pathway for the sustainable energy development and energy security of the country.     

A quantitative risk assessment of a domestic property connected to a hydrogen distribution network

The increased reliance on natural gas for heating worldwide makes the search for carbon-free alternatives imperative, especially if international decarbonisation targets are to be met. Hydrogen does not release carbon dioxide (CO₂) at the point of use which makes it an appealing candidate to decarbonise domestic heating. Hydrogen can be produced from either 1) the electrolysis of water with no associated carbon emissions, or 2) from methane reformation (using steam) which produces CO₂, but which is easily captured and storable during production. Hydrogen could be transported to the end-user via gas distribution networks similar to, and adapted from, those in use today. This would reduce both installation costs and end-user disruption. However, before hydrogen can provide domestic heat, it is necessary to assess the ‘risk’ associated with its distribution in direct comparison to natural gas. Here we develop a comprehensive and multi-faceted quantitative risk assessment tool to assess the difference in ‘risk’ between current natural gas distribution networks, and the potential conversion to a hydrogen based system. The approach uses novel experimental and modelling work, scientific literature, and findings from historic large scale testing programmes. As a case study, the risk assessment tool is applied to the newly proposed H100 demonstration (100% hydrogen network) project. The assessment includes the comparative risk of gas releases both upstream and downstream of the domestic gas meter. This research finds that the risk associated with the proposed H100 network (based on its current design) is lower than that of the existing natural gas network by a factor 0.88.     

How to decarbonize the transport sector?

This article investigates possible evolution pathways for the transport sector during the 21st century, globally and in Europe, under a climate change control scenario. We attempt to shed light on the question how the transport sector should best be decarbonized. We perform our study with the global bottom-up energy systems model TIAM-ECN, a version of the TIAM model that is broadly used for the purpose of developing energy technology and climate policy scenarios, which we adapted for analyzing in particular the transport sector. Given the global aggregated perspective of TIAM-ECN, that in its current version yields at every point in time a single CO₂ price for different forms of energy use across geographic regions and economic sectors, it generates a decarbonization process that for the transport sector occurs later in time than for the power sector. This merely reflects that emission reductions are generally cheaper for electricity production than for transportation, and that it is thus cost-minimizing to spend limited financial resources available for CO₂ emissions abatement in the power sector first. In our scenarios the use of hydrogen in internal combustion engines and fuel cells, rather than electricity as energy carrier and batteries to store it, gradually becomes the dominant transport technology. This outcome is in agreement with some recent publications but is at loggerheads with the current popularity of the electric car. Based on sensitivity analysis we conclude that even if the establishment of a hydrogen infrastructure proves about an order of magnitude more costly than modeled in our base case, electricity based transportation only broadly emerges if simultaneously also the costs of electric cars go down by at least 40% with respect to our reference costs. One of the explanations for why the electric car is today, by e.g. entrepreneurs, often considered the supposed winner amongst multiple future transportation options is that the decision horizon of many analysts is no more than a few decades, instead of a full century. Electric cars fit better the current infrastructure than hydrogen fueled vehicles, so that from a short time perspective (covering the next decade or two) investments are not optimally spent by establishing an extensive hydrogen distribution network. Hence the path-dependency created by the present existence of a vast power transmission and distribution network can make electricity the most efficient choice for transportation, but only if the time frame considered is short. Electric transportation generally proves the more expensive alternative in our long-term perspective, except when electric car costs are assumed to drop substantially.     

Systematic planning to optimize investments in hydrogen infrastructure deployment

The introduction of hydrogen infrastructure and fuel cell vehicles (FCVs) to gradually replace gasoline internal combustion engine vehicles can provide environment and energy security benefits. The deployment of hydrogen fueling infrastructure to support the demonstration and commercialization of FCVs remains a critical barrier to transitioning to hydrogen as a transportation fuel. This study utilizes an engineering methodology referred to as the Spatially and Temporally Resolved Energy and Environment Tool (STREET) to demonstrate how systematic planning can optimize early investments in hydrogen infrastructure in a way that supports and encourages growth in the deployment of FCVs while ensuring that the associated environment and energy security benefits are fully realized. Specifically, a case study is performed for the City of Irvine, California – a target area for FCV deployment – to determine the optimized number and location of hydrogen fueling stations required to provide a bridge to FCV commercialization, the preferred rollout strategy for those stations, and the environmental impact associated with three near-term scenarios for hydrogen production and distribution associated with local and regional sources of hydrogen available to the City. Furthermore, because the State of California has adopted legislation imposing environmental standards for hydrogen production, results of the environmental impact assessment for hydrogen production and distribution scenarios are measured against the California standards. The results show that significantly fewer hydrogen fueling stations are required to provide comparable service to the existing gasoline infrastructure, and that key community statistics are needed to inform the preferred rollout strategy for the stations. Well-to-wheel (WTW) greenhouse gas (GHG) emissions, urban criteria pollutants, energy use, and water use associated with hydrogen and FCVs can be significantly reduced in comparison to the average parc of gasoline vehicles regardless of whether hydrogen is produced and distributed with an emphasis on conventional resources (e.g., natural gas), or on local, renewable resources. An emphasis on local renewable resources to produce hydrogen further reduces emissions, energy use, and water use associated with hydrogen and FCVs compared to an emphasis on conventional resources. All three hydrogen production and distribution scenarios considered in the study meet California's standards for well-to-wheel GHG emissions, and well-to-tank emissions of urban ROG and NO_X. Two of the three scenarios also meet California's standard that 33% of hydrogen must be produced from renewable feedstocks. Overall, systematic planning optimizes both the economic and environmental impact associated with the deployment of hydrogen infrastructure and FCVs.     

A comparative techno-economic and quantitative risk analysis of hydrogen delivery infrastructure options

The comparative techno-economic analysis and quantitative risk analysis (QRA) of the hydrogen delivery infrastructure covering the national hydrogen demands are presented to obtain a comprehensive understanding of the infrastructure of commercial hydrogen delivery. The cost calculation model, which was based on the hydrogen delivery scenario analysis model (HDSAM), was employed to estimate the costs of hydrogen fuel delivery in Seoul, Korea, whose area is small enough to not require intermediate delivery stations. The QRA methodology was modified to be suitable for the comparative analysis of the whole hydrogen infrastructure. The capacities of a hydrogen refueling station and the hydrogen market penetration were employed as the main variables and the two scenarios, viz. the gaseous and liquid hydrogen delivery options, were considered. The analysis results indicate that the delivery system of gaseous hydrogen was superior in terms of cost and that of liquid hydrogen was superior in terms of safety. Both delivery options were affected by the capacity of the station and the market penetration, and the cost and risk drastically changed, especially when the two variables were small. Thus, according to the results, the economic and safety issues of the hydrogen delivery infrastructure are critical to achieving a hydrogen energy society.     

Robust optimization of hydrogen network

Process integration is an effective way to reduce hydrogen utility consumption in refineries. A number of graphical and mathematical programming approaches have been proposed to synthesis the optimal network. However, as the operation of refineries encounters uncertainty with the rapidly changing market and deteriorating crude oil, existing approaches are inadequate to achieve robust hydrogen network distribution due to the uncertain factors. In this paper, robust optimization is introduced as a framework to optimize hydrogen network of refineries under uncertainty. In this framework, a number of scenarios representing possible future environments are considered. Both model robust and solution robust are explicitly incorporated into the objective function. A possible optimal network distribution which is less sensitive to the change of scenarios and has the minimum total annual cost is achieved by the tradeoff between the total annual cost and the expected error. Case studies indicate that this method is effective in dealing with hydrogen network design and planning under uncertainty in comparison to the deterministic approach and the stochastic programming method.     

A review of technical and regulatory limits for hydrogen blending in natural gas pipelines

There is rising interest globally in the use of hydrogen for the provision of electricity or heat to industry, transport, and other applications in low-carbon energy systems. While there is attention to build out dedicated hydrogen infrastructure in the long-term, blending hydrogen into the existing natural gas pipeline network is also thought to be a promising strategy for incorporating hydrogen in the near-term. However, hydrogen injection into the existing gas grid poses additional challenges and considerations related to the ability of current gas infrastructure to operate with blended hydrogen levels. This review paper focuses on analyzing the current understanding of how much hydrogen can be integrated into the gas grid from an operational perspective and identifies areas where more research is needed. The review discusses the technical limits in hydrogen blending for both transmission and distribution networks; facilities in both systems are analyzed with respect to critical operational parameters, such as decrease in energy density, increased flow speed and pressure losses. Safety related challenges such as, embrittlement, leakage and combustion are also discussed. The review also summarizes current regulatory limits to hydrogen blending in different countries, including ongoing or proposed pilot hydrogen blending projects.     

The importance of economies of scale,transport costs and demand patterns in optimising hydrogen fuelling infrastructure: An exploration with SHIPMod (Spatial hydrogen infrastructure planning model)

Hydrogen is widely recognised as an important option for future road transportation, but a widespread infrastructure must be developed if the potential for hydrogen is to be achieved. This paper and related appendices which can be downloaded as Supplementary material present a mixed-integer linear programming model (called SHIPMod) that optimises a hydrogen supply chains for scenarios of hydrogen fuel demand in the UK, including the spatial arrangement of carbon capture and storage infrastructure. In addition to presenting a number of improvements on past practice in the literature, the paper focuses attention on the importance of assumptions regarding hydrogen demand. The paper draws on socio-economic data to develop a spatially detailed scenario of possible hydrogen demand. The paper then shows that assumptions about the level and spatial dispersion of hydrogen demand have a significant impact on costs and on the choice of hydrogen production technologies and distribution mechanisms.     

Economic analysis of near-term California hydrogen infrastructure

A detailed economics model of hydrogen infrastructure in California has been developed and applied to assess several potential fuel cell vehicle deployment rate and hydrogen station technology scenarios. The model accounts for all of the costs in the hydrogen supply chain and specifically examines a network of 68 planned and existing hydrogen stations in terms of economic viability and dispensed hydrogen cost. Results show that (1) current high-pressure gaseous delivery and liquid delivery station technologies can eventually be profitable with relatively low vehicle deployment rates, and (2) the cost per mile for operating fuel cell vehicles can be lower than equivalent gasoline vehicles in both the near and long term.     

Hydrogen integration in power-to-gas networks

The share of renewable energy resources is consistently rising in the global energy supply, and power-to-gas technique is being seen as the feasible storage of surplus renewable electricity. In this regard the sensitivity of hydrogen towards various elements of the P2G network needs to be assessed. The study provides an overview of a number of P2G projects mainly concentrated in Europe, and summarizes the results of investigations carried out on the effects of hydrogen injection on the existing natural gas pipeline infrastructure. It has been found that each element of the natural gas infrastructure has a varying degree of acceptability to hydrogen concentration; however the determinant element affects the overall allowable hydrogen concentration. In the transmission network, compressors are the determinant element and have a limiting value of 10% hydrogen admixture. Distribution network and storage elements allow a 50% concentration of hydrogen. End use appliances have a tolerant range of 20–50%. The second portion of the study demonstrates the effect of hydrogen injection on gas quality, which reveals that an introduction of 2% hydrogen in the distribution network has negligible effect however a 10% hydrogen mixture affects the calorific value of the supplied fuel gas below the desired level.     

Experimental study of hydrogen explosion in repeated pipe congestion – Part 2: Effects of increase in hydrogen concentration in hydrogen-methane-air mixture

Hydrogen is seen as an important energy carrier for the future which offers carbon free emissions. At present it is mainly used in refueling hydrogen fuel cell cars. However, it can also be used together with natural gas in existing gas fired equipment with the benefit of lower carbon emissions. This can be achieved by introducing hydrogen into existing natural gas pipelines. These pipelines are designed, constructed and operated to safely transport natural gas, which is mostly methane. Because hydrogen has significantly different physical and chemical properties than natural gas, any addition of hydrogen my adversely affect the integrity of the pipeline network, increasing the likelihood and consequences of an accidental leak. Since it increases the likelihood and consequences of an accidental leak, it increases the risk of explosion. In order to address various safety issues related to addition of hydrogen in to a natural gas pipeline a EU project NATURALHY was introduced. A major objective of the NATURALHY project was to identify how much hydrogen could be introduced into the natural gas pipeline network. Such that it does not adversely impact the safety of the pipeline network and significantly increase the risk to the public. This paper reports experimental work conducted to measure the explosion overpressure generated by ignition of hydrogen-methane-air mixture in a highly congested region consisting of interconnected pipes. The composition of the methane/hydrogen mixture used was varied from 0% hydrogen (100% methane) to 100% hydrogen (0% methane) to understand its effect on generated explosion overpressure. It was observed that the maximum overpressures generated by methane-hydrogen mixtures with 25% (by volume) or less hydrogen content are not likely to be significantly greater than those generated by methane alone. Therefore, it can be concluded that the addition of less than 25% by volume of hydrogen into pipeline networks would not significantly increase the risk of explosion.     

Life-cycle analysis of greenhouse gas emissions from hydrogen delivery: A cost-guided analysis

The cost of hydrogen delivery for transportation accounts for most of the current H₂ selling price; delivery also requires substantial amounts of energy. We developed harmonized techno-economic and life-cycle emissions models of current and future H₂ production and delivery pathways. Our techno-economic analysis of dispensed H₂ costs guided our selection of pathways for the life-cycle analysis. In this paper, we present the results of market expansion scenarios using existing capabilities (for example, those that use H₂ from steam methane reforming, chlor-alkali, and natural gas liquid cracker plants), as well as results for future electrolysis plants that use nuclear, solar, and hydroelectric power. Reductions in greenhouse gas emissions for fuel cell electric vehicles compared to conventional gasoline pathways vary from 40% reduction for fossil-derived H₂ to 20-fold for clean H₂. Supplemental tables with greenhouse gas emissions data for each step in the H₂ pathways enable readers to evaluate additional scenarios.     

Rail transportation by hydrogen vs. electrification – Case study for Ontario Canada,I: Propulsion and storage

Cities around the world are expanding their passenger train operations to address concerns with GHG pollution, noise and high costs of commuter transportation. Locomotives offer an attractive mode of transportation in terms of energy consumption per passenger kilometre of travel. This paper compares hydrogen against electrification as cleaner alternatives to power diesel locomotives. Disadvantages of electrification include the capital investment to install electrical substations and catenaries, together with a lack of flexibility for locomotives to move into other service areas not covered by electrification. This paper specifically analyzes the implementation and operation of hydrogen passenger locomotives in the GO Transit Lakeshore corridor, through Toronto, between Oshawa and Hamilton, Ontario. A sensitivity analysis is performed over a range of operational costs for a hydrogen train, with variability of feedstock prices, fuel cell power density and expected return on capital investment. Various methods of propulsion and storage are compared against electrification. The installation and operational costs in dollars per train-km are analyzed for various train scenarios and results are presented.     

Levelized and environmental costs of power-to-gas generation in Germany

The transformation to a greener energy system leads to new challenges, as wind and solar power are not always available. A solution for this challenge is the generation of synthetic natural gas (SNG) and hydrogen from (surplus) wind and solar power, so that the green gases can be stored in the natural gas grid long-term and be used for electricity generation when wind and solar power are not accessible. This solution is especially of interest if the storage infrastructure is already in place, as in Germany, since investment costs can be avoided. Because of that, the study investigates the levelized cost of SNG and hydrogen generation in Germany applying the cost estimation method by Rubin et al. For the investigation, different water electrolysis technologies (alkaline electrolysis, polymer exchange membrane, and solid oxide electrolyzer cell with a size of 1 and 100 MW) and energy scenarios (8,000 h grid, 2,000 h grid, wind, and solar) are contemplated. Besides that, the environmental costs of SNG and hydrogen generation in Germany are investigated due to the increasing importance of these costs for society and companies. The author concludes that the levelized costs of SNG and hydrogen are far too high compared to peer studies, as more cost factors have been considered after applying the method by Rubin et al. In terms of the environmental costs, the use of Germany's grid electricity is not recommended for SNG and hydrogen generation since the generation from wind and solar power is more environmentally friendly, whereby wind power is preferable over solar power.     

Cost effective integration of hydrogen in energy systems with CO2 constraints

The integration of hydrogen in national energy systems is illustrated in four extreme scenarios, reflecting four technological mainstreams (energy conservation, renewables, nuclear and CO₂ removal) to reduce C emissions. Hydrogen is cost-effective in all scenarios with higher CO₂ reduction targets. Hydrogen would be produced from fossil fuels, or from water and electricity or heat, depending upon the scenario. Hydrogen would be used in the residential and commercial sectors and for transport vehicles, industry, and electricity generation in fuel cells. At severe (50–70%) CO₂ reduction targets, hydrogen would cost-effectively supply more than half of the total useful energy demands in three out of four scenarios. The marginal emission reduction costs in the CO₂ removal scenario at severe CO₂ reduction targets are DFL 200/tCO₂ (ca $ 100/t). In the nuclear, renewable and energy conservation scenarios these costs are much higher. Whilst the fossil fuel scenario would be less expensive than the other scenarios, the possibility of CO₂ storage in depleted gas reservoirs is a conditio sine qua non.     

On the feasibility of direct hydrogen utilisation in a fossil-free Europe

Hydrogen is often suggested as a universal fuel that can replace fossil fuels. This paper analyses the feasibility of direct hydrogen utilisation in all energy sectors in a 100% renewable energy system for Europe in 2050 using hour-by-hour energy system analysis. Our results show that using hydrogen for heating purposes has high costs and low energy efficiency. Hydrogen for electricity production is beneficial only in limited quantities to restrict biomass consumption, but increases the system costs due to losses. The transport sector results show that hydrogen is an expensive alternative to liquid e-fuels and electrified transport due to high infrastructure costs and respectively low energy efficiency. The industry sector may benefit from hydrogen to reduce biomass at a lower cost than in the other energy sectors, but electrification and e-methane may be more feasible. Seen from a systems perspective, hydrogen will play a key role in future renewable energy systems, but primarily as e-fuel feedstock rather than direct end-fuel in the hard-to-abate sectors.