Point-to-point transportation: The economics of hydrogen export

Hydrogen transport over long distances is a critical cost component, and it can involve many complex pathways. We have developed a model and an associated framework that can be used to determine the cost of transport methods for both land and land-and-sea scenarios. The model assesses the transportation of liquid and gaseous hydrogen by truck, rail, and barge; as well as gaseous hydrogen pipelines. Our results show that for large scale and long-distance hydrogen transport, the only feasible gaseous hydrogen transport option are pipelines. For example, a well-planned pipeline can keep hydrogen transportation costs below $3 per kg for distances up to 7000 km so long as the demand is greater than 150 tonnes per day. Liquid hydrogen transport is feasible and efficient for long distance transport, especially when used alongside rail travel providing less than 50 tonnes per day.     

Estimating global production and supply costs for green hydrogen and hydrogen-based green energy commodities

Green energy commodities are expected to be central in decarbonising the global energy system. Such green energy commodities could be hydrogen or other hydrogen-based energy commodities produced from renewable energy sources (RES) such as solar or wind energy. We quantify the production cost and potentials of hydrogen and hydrogen-based energy commodities ammonia, methane, methanol, gasoline, diesel and kerosene in 113 countries. Moreover, we evaluate total supply costs to Germany, considering both pipeline-based and maritime transport. We determine production costs by optimising the investment and operation of commodity production from dedicated RES based on country-level RES potentials and country-specific weighted average costs of capital. Analysing the geographic distribution of production and supply costs, we find that production costs dominate the supply cost composition for liquid or easily liquefiable commodities, while transport costs dominate for gaseous commodities. In the case of Germany, importing green ammonia could be more cost-efficient than domestic production from locally produced or imported hydrogen. Green ammonia could be supplied to Germany from many regions worldwide at below the cost of domestic production, with costs ranging from 624 to 874 $/t NH₃ and Norway being the cheapest supplier. Ammonia production using imported hydrogen from Spain could be cost-effective if a pan-European hydrogen pipeline grid based on repurposed natural gas pipelines exists.     

Feasibility analysis of blending hydrogen into natural gas networks

Hydrogen fuel has the potential to mitigate the negative effects of greenhouse gases and climate change by neutralizing carbon emissions. Transporting large volume of hydrogen through pipelines needs hydrogen-specific infrastructure such as hydrogen pipelines and compressors, which can become an economic barrier. Thus, the idea of blending hydrogen into existing natural gas pipelines arises as a potential alternative for transporting hydrogen economically by using existing natural gas grids. However, there are several potential issues that must be considered when blending hydrogen into natural gas pipelines. Hydrogen has different physical and chemical properties from natural gas, including a smaller size and lighter weight, which require higher operating pressures to deliver the same amount of energy as natural gas. Additionally, hydrogen's small molecular size and lower ignition energy make it more likely to permeate through pipeline materials and seals, leading to degradation, and its wider flammability limits make it a safety hazard when leaks occur. In this study, we investigate these potential issues through simulation and technical surveys. We develop a gas hydraulic model to simulate the physical characteristics of a transmission and a distribution pipeline. This model is used throughout the study to visualize the potential impacts of switching from natural gas to hydrogen, and to investigate potential problems and solutions. Furthermore, we develop a Real-Time Transient Model (RTTM) to address the compatibility of current computational pipeline monitoring (CPM) based leak detection methods with blended hydrogen. Finally, we suggest the optimal hydrogen concentration for this model, and investigate the amount of carbon reduction that could be achieved, while considering the energy needs of the system.     

Large-scale long-distance land-based hydrogen transportation systems: A comparative techno-economic and greenhouse gas emission assessment

Interest in hydrogen as an energy carrier is growing as countries look to reduce greenhouse gas (GHG) emissions in hard-to-abate sectors. Previous works have focused on hydrogen production, well-to-wheel analysis of fuel cell vehicles, and vehicle refuelling costs and emissions. These studies use high-level estimates for the hydrogen transportation systems that lack sufficient granularity for techno-economic and GHG emissions analysis. In this work, we assess and compare the unit costs and emission footprints (direct and indirect) of 32 systems for hydrogen transportation. Process-based models were used to examine the transportation of pure hydrogen (hydrogen pipeline and truck transport of gaseous and liquified hydrogen), hydrogen-natural gas blends (pipeline), ammonia (pipeline), and liquid organic hydrogen carriers (pipeline and rail). We used sensitivity and uncertainty analyses to determine the parameters impacting the cost and emission estimates. At 1000 km, the pure hydrogen pipelines have a levelized cost of $0.66/kg H₂ and a GHG footprint of 595 gCO₂eq/kg H₂. At 1000 km, ammonia, liquid organic hydrogen carrier, and truck transport scenarios are more than twice as expensive as pure hydrogen pipeline and hythane, and more than 1.5 times as expensive at 3000 km. The GHG emission footprints of pure hydrogen pipeline transport and ammonia transport are comparable, whereas all other transport systems are more than twice as high. These results may be informative for government agencies developing policies around clean hydrogen internationally.     

交流输电线路对埋地金属管道稳态干扰的影响规律

随着电力和石油能源需求不断发展,电力线路和埋地金属油气管道建设在全国各地迅速展开。土地资源紧张的地区,高压输电线路和油气管道往往面临同走廊并行走线的状况。高压交流线路正常运行时,线路上的电流周期性变化产生交变磁场会在管道上产生纵向感应电动势从而引起交流稳态干扰。探讨并获得了管道外径/壁厚、管道埋深、防腐层厚度、管道防腐层绝缘电阻率等参数对交流稳态干扰的影响规律,可供电力和管道设计单位参考之用。     

Energy crop production costs in the EU

The objective of this study was to calculate indicative ranges of production costs and assess the main sources of cost for a number of energy crops, both annual and perennial, on a regional level in Europe. The production costs were calculated in terms of the economic compensation required by the farmer in order to grow the crop, and therefore include not only the cost of cultivation, but also the costs of land and risk, which are often omitted in production cost calculations. The cost of land was calculated as the opportunity cost based on the production of cereals. Thus, higher food prices lead to higher land costs, which in turn lead to higher energy crop production costs. The analysis was performed for three cases with different assumptions concerning yields and production cost reductions resulting from scale (total cultivation area in the region), and learning effects. The calculated energy crop production costs were found to be consistently lowest for short-rotation coppice (SRC) crops and highest for annual straw crops. The production costs of SRC crops were calculated to be about 4–5 € GJ⁻¹ under present conditions and 3–4 € GJ⁻¹ under improved future conditions. The production costs for perennial grasses were calculated to be about 6–7 € GJ⁻¹ and 5–6 € GJ⁻¹ under present and improved future conditions, respectively. The production costs for annual straw crops were estimated to be 6–8 € GJ⁻¹ under present conditions with small potential for cost reductions in the future.     

Determining the lowest-cost hydrogen delivery mode

Hydrogen delivery is a critical contributor to the cost, energy use and emissions associated with hydrogen pathways involving central plant production. The choice of the lowest-cost delivery mode (compressed gas trucks, cryogenic liquid trucks or gas pipelines) will depend upon specific geographic and market characteristics (e.g. city population and radius, population density, size and number of refueling stations and market penetration of fuel cell vehicles). We developed models to characterize delivery distances and to estimate costs, emissions and energy use from various parts of the delivery chain (e.g. compression or liquefaction, delivery and refueling stations). Results show that compressed gas truck delivery is ideal for small stations and very low demand, liquid delivery is ideal for long distance delivery and moderate demand and pipeline delivery is ideal for dense areas with large hydrogen demand.     

Analysis of hazard area associated with hydrogen gas transmission pipelines

Hydrogen is considered to be the most important future energy carrier in many applications reducing significantly greenhouse gas emissions, but the safety issues associated with hydrogen applications need to be investigated and fully understood to be applicable as the carrier. Generally, the locations of hydrogen production and consumption are different. Hydrogen must be transported from the point of production to the point of use. Pipeline delivery is cheaper than all other methods for large quantities of hydrogen. The rupture of a hydrogen pipeline can lead to outcomes that can pose a significant threat to people and property in the immediate vicinity of the failure point. In this work, a simplified equation of hazard analysis is proposed for the pipeline transporting hydrogen, which relates the diameter, the operating pressure and the length of the pipeline to the size of the affected area in the event of a failure of the pipeline. The dominant hazards are thermal radiation from sustained fire and shock pressure from gas cloud explosion. For a transmission pipeline of hydrogen gas, the hazard area from the fire is slightly larger than by the other event. The hazard area is directly proportional to the operating pressure raised to the power one-half, and to the pipeline diameter. This simplified equation to estimate the hazard area will be a useful tool for safety management of hydrogen gas transmission pipelines.     

Recommendations on X80 steel for the design of hydrogen gas transmission pipelines

By limiting the pipes thickness necessary to sustain high pressure, high-strength steels could prove economically relevant for transmitting large gas quantities in pipelines on long distance. Up to now, the existing hydrogen pipelines have used lower-strength steels to avoid any hydrogen embrittlement. The CATHY-GDF project, funded by the French National Agency for Research, explored the ability of an industrial X80 grade for the transmission of pressurized hydrogen gas in large diameter pipelines. This project has developed experimental facilities to test the material under hydrogen gas pressure. Indeed, tensile, toughness, crack propagation and disc rupture tests have been performed. From these results, the effect of hydrogen pressure on the size of some critical defects has been analyzed allowing proposing some recommendations on the design of X80 pipe for hydrogen transport. Cost of Hydrogen transport could be several times higher than natural gas one for a given energy amount. Moreover, building hydrogen pipeline using high grade steels could induce a 10 to 40% cost benefit instead of using low grade steels, despite their lower hydrogen susceptibility.     

Failure analysis of corroded high-strength pipeline subject to hydrogen damage based on FEM and GA-BP neural network

The pipeline is a major approach to achieving large-scale hydrogen transportation. Hydrogen damage can deteriorate the material performance of the pipe steel, like ductility and plasticity reduction. Corrosion is dominating damage that impairs a pipeline's bearing capacity and structural reliability. However, previous research barely investigated the effect of hydrogen damage on failure behaviors, residual strength and interacting effect between adjacent corrosions of corroded high-strength pipelines transporting hydrogen. Besides, hardly any burst pressure model considers hydrogen damage. In this paper, several approaches, including the finite element method (FEM), regression analysis, the orthogonal test method, and the artificial neural network method, are applied to fill the gap. First, a series of finite element models with different geometric features and hydrogen damage is established to investigate the effects of hydrogen damage and corrosion on failure behaviors and residual strength. The results show that hydrogen damage can change the corroded pipeline's failure behaviors and reduce the residual strength. Second, based on the simulation results and regression analysis, a new burst model is developed to consider the hydrogen damage and improve the estimation accuracy. Third, based on the genetic algorithm (GA), a GA-BP neural network is established and trained for accurate and efficient residual strength estimation considering hydrogen damage. Furthermore, an orthogonal test is designed and performed to investigate the effects of critical parameters on the burst pressure of the corroded pipeline after hydrogen damage. The results indicate that hydrogen damage and corrosion length have similar contributions to the residual strength. Finally, the simulation results of pipelines with multiple corrosions show that hydrogen damage has a significant impact on the interacting effect between adjacent corrosions. The results obtained are valuable for further integrity management of steel pipelines carrying hydrogen.     

A multi-objective model for optimizing hydrogen injected-high pressure natural gas pipeline networks

The paper develops a statistical model for optimizing the Hydrogen-injected Natural gas (H-NG) high-pressure pipeline network. Gas hydrodynamic principles are utilized to construct the pipeline and compressor station model. The model developed is implemented on a pipeline grid that is supposed to carry Hydrogen as an energy carrier in a natural gas-carrying pipeline. The paper aims to optimize different objectives using ant colony optimization (ACO). The first objective includes a single objective optimization problem that evaluates the maximum permissible hydrogen amounts blended with natural gas (NG) for a set of pipeline constraints. We also evaluated the variations in operational variables on injecting Hydrogen into the natural gas pipeline networks at varying fractions. The study further develops a multi-objective optimization model that includes bi-objective and tri-objective problems and is optimized using ACO. Traditional studies have focused on single-objective optimization with minimal bi-objective issues. In addition, none of the earlier research has shown the effect of introducing Hydrogen to the NG network using tri-objective function evaluations. The bi-objective and tri-objective functions help evaluate the effect of injecting Hydrogen on different operational parameters. The study further attempts to fill the gap by detailing the modelling equations implemented through a bi-objective and tri-objective function for the H-NG pipeline network and optimized through ACO. Pareto fronts that show the tradeoff between the different objectives for the multi-objective problem have been generated. The primary objective of the bi-objective and tri-objective optimization problems is maximizing hydrogen mole percent in natural gas. The other objective chosen is minimizing compressor fuel consumption and maximizing delivery pressure, throughput, and power delivered at the delivery station. The findings will serve as a roadmap for pipeline operators interested in repurposing natural gas pipeline networks to transport hydrogen and natural gas blend (H-NG) and seeking to reduce carbon intensity per unit of energy-delivered fuel.     

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.     

Options of natural gas pipeline reassignment for hydrogen: Cost assessment for a Germany case study

The uncertain role of the natural gas infrastructure in the decarbonized energy system and the limitations of hydrogen blending raise the question of whether natural gas pipelines can be economically utilized for the transport of hydrogen. To investigate this question, this study derives cost functions for the selected pipeline reassignment methods. By applying geospatial hydrogen supply chain modeling, the technical and economic potential of natural gas pipeline reassignment during a hydrogen market introduction is assessed.The results of this study show a technically viable potential of more than 80% of the analyzed representative German pipeline network. By comparing the derived pipeline cost functions, it could be derived that pipeline reassignment can reduce the hydrogen transmission costs by more than 60%. Finally, a countrywide analysis of pipeline availability constraints for the year 2030 shows a cost reduction of the transmission system by 30% in comparison to a newly built hydrogen pipeline system.     

中国规模化氢能供应链的经济性分析

目的 文章研究规模化氢能供应链的经济性,未来十年,氢能作为战略能源将会重构社会的能源结构,并影响未来社会能源总成本。预测大规模氢能时代的制氢、储氢、输氢、分销、应用的成本,和市场化的趋势有着重要的意义。氢气由于高储运成本,用途、品质的多样性,氢气市场存在分层结构。分析氢能与常规能源的可比价格,提出原油当量价格(POE)的概念,预测未来氢能价格的合理区间。解决供应链问题是获得低成本氢能的关键,由此提出干线门站模式,解决绿氢的资源分布与长距离输送氢能的问题。 方法 利用平准化氢气成本(LCOH)分析模型,测算大型光伏制氢管道输氢LCOH,分析大规模可再生能源制氢输氢的经济性。利用氢能供应链的储、输、卸六个象限成本公式,分析气氢、液氢、固氢、有机氢、管道氢等不同储运技术,短距离氢储运成本,分析门站后输氢的场景和成本,预测短距离输氢的成本趋势。 结果 研究表明：我国有丰富的绿氢资源,随着投资下降,预计大规模绿氢管道输送的城市门站LCOH将低于2.0 RMB/Nm³,将成为未来主要的氢源。当前,氢储运技术气氢、液氢、甲醇、合成氨、有机氢、固氢、管道氢,随着规模的增加实现远距离输送。在现有的技术下,城市门站到终端的输送,氢短距输送（<100 km）测算成本都在1.2 RMB/Nm³以下,由此评估的氢能供应链的总成本,干线门站模式下氢能最终到达终端的价格约为3.2 RMB/Nm³,当量价格POE与汽油价格接近,考虑燃料电池的能效因素,氢能汽车在4.0 RMB/Nm³的氢价下,具有比汽油车更低的百公里燃料费用。 结论 因此,氢能作为战略能源,在无补贴的情况下实现中国氢能源的绿氢替代,在技术经济上是可行的。     

An MILP model for the reformation of natural gas pipeline networks with hydrogen injection

A mixed integer linear programming (MILP) model is proposed for the reformation of natural gas pipelines. The model is based on the topology of existing pipelines, the load and pressure at each node and the design factors of the region and minimizes the annual substitution depreciation cost of pipelines, the annual construction depreciation cost of compressor stations and the operating cost of existing compressor stations. Considering the nonlinear pressure drop equations, the model is linearized by a piecewise method and solved by the Gurobi optimizer. Two cases of natural gas pipeline networks with hydrogen injection are presented. Several adjustments are applied to the original natural gas pipeline network to ensure that our design scheme can satisfy the safety and economic requirements of gas transportation. Thus, this work is likely to serve as a decision-support tool for the reformation of pipeline networks with hydrogen injection.     

Optimal siting and sizing of hydrogen refueling stations considering distributed hydrogen production and cost reduction for regional consumers

Hydrogen fuel cell vehicles are currently facing two difficulties in achieving their general use: the lack of hydrogen refueling stations and high hydrogen prices. Hydrogen refueling stations are the middle stage for delivering hydrogen from its sources to consumers, and their location could be affected by the distributed locations of hydrogen sources and consumers. The reasonable siting and sizing of hydrogen refueling stations could both improve the hydrogen infrastructure and reduce regional consumers' cost of using hydrogen. By considering the hydrogen life cycle cost and using a commercial volume forecasting model, this paper creates a relatively thorough and comprehensive model for hydrogen station siting and sizing with the objective of achieving the optimal costs for consumers using hydrogen. The cost‐based model includes the selection of the hydrogen sources, transportation methods, and storage methods, and thus, the hydrogen supply chain can also be optimized. A numerical example is established in Section 4 with the solution algorithm and results.     

Large-scale hydrogen production from biogas

In this study, various steps involving hydrogen production from biogas, its storage and transportation, and its marketing as a commodity have been reviewed. Various scenarios have been studied, and design and cost relationships have been developed for feasible alternatives. A case study has been carried out for India, and an economic assessment has been presented. It is found that the hydrogen production cost in industrial centers is 310 Yen GJ⁻¹ and the FOB export cost of liquefied hydrogen to 10 000 km away, to Japan for example, is 1523 Yen GJ⁻¹.     

Multidimensional risk analysis of hydrogen pipelines

Hydrogen has the highest mass specific energy content of all conventional fuels and is the most abundant element in the universe. It is considered as a renewable resource and sustainable solution for reducing global fossil fuel consumption and combating global warming. In general, it must be transported from production plants to demand points. Thus, the delivery process of its supply chain leads to the possibility of there being new forms of hazard. Pipelines have proven to be one of the cheapest ways to transport hydrogen. However, failures in pipelines can pose major risks. In this context, this paper proposes a multicriteria decision model for assessing the risk in hydrogen pipelines. By incorporating the decision maker's preferences structure into the decision process, the model enables sections of the pipeline to be ranked in terms of risk. The model proposed in this work is considered as an evolution of previous studies in the area, due to new features incorporated in the process. Finally, a numerical application is conducted in order to test the model.     

The cost of hydrogen from coal

Isolation of the hydrogen and oxygen plants from the rest of the liquefaction complex, combined with appropriate transfer costs for all utilities and raw materials has been used to estimate the value of hydrogen. For the five alternatives, minimum cost hydrogen is produced by gasification of coal at 1000 psia. 500 psia gasification of coal yielded slightly more expensive hydrogen; however, on an equivalent mole basis of hydrogen, they were virtually the same. As would be expected, the cost of coal, discount cash flow rate and method of costing supplemental fuel needs were the primary variables affecting the cost of hydrogen. Hydrogen cost ranged from $0·847/1000 standard cubic feet to $2·986/1000 standard cubic feet.     

A spatially-explicit optimization model for long-term hydrogen pipeline planning

One of the major barriers to the deployment of hydrogen as a transportation fuel is the lack of an infrastructure for supplying the fuel to consumers. Consequently, models are needed to evaluate the cost and design of various infrastructure deployment strategies. The best strategy will likely differ between regions based on the spatial distribution of H₂ demand and variations in regional feedstock costs. Although several spatially-explicit infrastructure models have been developed, none of the published models are capable of optimizing interconnected regional pipeline networks for linking multiple production facilities and demand locations. This paper describes the Hydrogen Production and Transmission (HyPAT) model, which is a network optimization tool for identifying the lowest cost centralized production and pipeline transmission infrastructure within real geographic regions. A case study in the southwestern United States demonstrates the capabilities and outputs of the model.