Hydrogen Plant Research Articles

Alarm management approach for supervision of Green Hydrogen Plants

Amid the increasing significance of renewable energy sources, Green Hydrogen Plants (GHPs) have emerged as pivotal contributors to sustainable energy solutions. However, efficient and reliable alarm management in such complex systems remains a significant challenge. This paper presents a novel methodology called V-nets-based alarm management (VBAM), designed to improve supervision by addressing the intricacies of discrete event management in industrial applications such as GHPs. VBAM offers a powerful formalism that integrates visual modeling and temporal patterns, enabling the precise detection and handling of alarms. The proposed methodology is applied to a case study in a GHP, where critical operational parameters are continuously monitored. By analyzing discrete events and their temporal patterns, V-nets facilitate early fault detection, minimize false positives, and optimize alarm response. The theoretical application of VBAM demonstrates its efficacy in improving system safety, reducing downtime, and enhancing overall operational efficiency within GHPs. The contributions of this work to the state of the art include the development of a comprehensive VBAM methodology tailored to GHPs, as well as the theoretical and practical demonstration of its potential impact on alarm management within GHP operations. The outcomes from the experiments showcase the adaptability and effectiveness of VBAM in addressing the complexities of alarm management in GHPs, thereby contributing to enhanced safety, efficiency, and resilience in the operation of GHPs.

Process design and optimization of membrane-based CO2 capture process with experimental performance data for a steam methane reforming hydrogen plant and a coal-fired power plant

Membrane-based separation is one of the promising next-generation carbon capture technologies. High degrees of freedom in process design for multi-stage membrane networks, make it difficult to fully understand the impact of network configuration on the economics of capture and separation performance. Furthermore, the optimality in process design is heavily influenced by the levels of membrane performance and the characteristics of feed gas. Membrane model utilized for the study is validated and tuned with 183 experimental data measured at various operating conditions, having 2.45 % of overall prediction error. The superstructure-based framework for the optimization of multi-stage membrane networks is used, with which design interactions between network configurations, flue gas characteristics and membrane performance are systematically investigated. Techno-economic analysis is embedded in the optimization framework, which performs rigorous trade-off between capital and operating costs, as well as allows simultaneous determination of optimal process network configuration and operating variables. Flue gas streams emitted from a coal-fired power plant and a steam methane reforming hydrogen production plant are selected as CO2 capture sources for the analysis of flue gas characteristics. Case study shows capture cost ranged from 30.2 $/tCO2 to 79.9 $/tCO2, depending on the network configuration and design specifications, and clearly improves our techno-economic understanding on the network configuration of membrane capture process. In addition, cryogenic-hybridized membrane capture process is examined and the optimal level of enriched CO2 stream concentration between membrane capture and cryogenic distillation processes is determined. Study suggests how network configuration of membrane capture process can impact capture cost.

Flexibility assessment and aggregation of alkaline electrolyzers considering dynamic process constraints for energy management of renewable power-to-hydrogen systems

In the energy management of renewable power-to-hydrogen (ReP2H) systems, quantifying the flexibility of alkaline electrolyzers (AELs) to respond to fast load-tracking commands and maintain energy balance across various timescales is crucial. However, the flexibility of AELs is subject to electrochemical, and dynamic heat and mass transfer constraints, making them very different, both physically and mathematically, from conventional power system flexibility resources such as energy storage (ES) and electrical vehicles (EVs). Additionally, in large hydrogen plants (HPs), aggregating the flexibility of multiple AELs is necessary. Despite extensive flexibility-related research on power and integrated energy systems, work on the electrolyzers is limited. To address these gaps, this paper presents a flexibility assessment method for AELs. Considering comprehensive nonlinear dynamic process constraints, we establish a flexibility metric based on the maximal/minimal energy an AEL can provide within varying time windows. This metric is additive, facilitating the aggregation of multiple AELs within seconds. By comparing it with the energy demanded by regulatory commands, the feasibility of load-tracking control can be assessed without time-domain simulation. In cases of infeasibility, the cause and required compensation can also be interpreted. Case studies validate the proposed method, and key factors impacting the flexibility of AELs are quantitatively analyzed.

From Curtailed Renewable Energy to Green Hydrogen: Infrastructure Planning for Hydrogen Fuel-Cell Vehicles

Problem definition: Hydrogen fuel-cell vehicles (HFVs) have been proposed as a promising green transportation alternative. For regions experiencing renewable energy curtailment, promoting HFVs can achieve the dual benefit of reducing curtailment and developing sustainable transportation. However, promoting HFVs faces several major hurdles, including uncertain vehicle adoption, the lack of refueling infrastructure, the spatial mismatch between hydrogen demand and renewable sources for hydrogen production, and the strained power transmission infrastructure. In this paper, we address these challenges and study how to promote HFV adoption by deploying HFV infrastructure and utilizing renewable resources. Methodology/results: We formulate a planning model that jointly determines the location and capacities of hydrogen refueling stations (HRSs) and hydrogen plants as well as electricity transmission and grid upgrade. Despite the complexity of explicitly considering drivers’ HFV adoption behavior, the bilevel optimization model can be reformulated as a tractable mixed-integer second-order cone program. We apply our model calibrated with real data to the case of Sichuan, a province in China with abundant hydro resources and a vast amount of hydropower curtailment. Managerial implications: We obtain the following findings. (i) The optimal deployment of HRSs displays vastly different spatial patterns depending on the HFV adoption target. The capital city, a transportation hub, is excluded from the plan under a low target and only emerges as the center of HFV adoption under a high target. (ii) Promoting the HFV adoption can overall help reduce hydropower curtailment, but the effectiveness depends on factors such as the adoption target and the grid upgrade cost. (iii) Being a versatile energy carrier, hydrogen can be transported to various locations, which allows for strategic placement of HRSs in locations distinct from hydrogen plant sites. This flexibility offers HFVs greater potential cost savings and curtailment reduction compared with other alternative fuel vehicles (e.g., electric vehicles) under current cost estimates. Funding: W. Qi acknowledges the support from the National Natural Science Foundation of China [Grants 72242106 and 72188101] and the Natural Sciences and Engineering Research Council of Canada [Grant RGPIN-2019-04769]. Supplemental Material: The online appendix is available at https://doi.org/10.1287/msom.2022.0381 .

Off-grid hydrogen production: Analysing hydrogen production and supply costs considering country-specifics and transport to Europe

Hydrogen plays a pivotal role in transitioning to CO2-free energy systems, yet challenges regarding costs and sourcing persist in supplying Europe with renewable hydrogen. Our paper proposes a simulation-based approach to determine cost-optimal combinations of electrolyser power and renewable peak power for off-grid hydrogen production, considering location and energy source dependencies.Key findings include easy estimation of Levelized Costs of Hydrogen (LCOH) and optimal plant sizing based on the regional energy yield and source. Regional investment risks influence the LCOH by 7.9 % per 1 % change of the Weighted Average Cost of Capital. In Central Europe (Austria), hydrogen production costs range from 7.4 €/kg to 8.6 €/kg, whereas regions like Chile exhibit cheaper costs at 5.1 €/kg to 6.8 €/kg. Despite the favourable energy yields in regions like Chile or the UAE, domestically produced hydrogen can be cost-competitive when location-specific risks and transport costs are taken into account. This underlines the critical role of domestic hydrogen production and cost-effective hydrogen transport for Europe's future hydrogen supply.

An Economic Performance Improving and Analysis for Offshore Wind Farm-Based Islanded Green Hydrogen System

When offshore wind farms are connected to a hydrogen plant with dedicated transmission lines, for example, high-voltage direct current, the fluctuation of wind speed will influence the efficiency of the alkaline electrolyzer and deteriorate the techno-economic performance. To overcome this issue, firstly, an additional heating process is adopted to achieve insulation for the alkaline solution when power generated by wind farms is below the alkaline electrolyzer minimum power threshold, while the alkaline electrolyzer overload feature is used to generate hydrogen when wind power is at its peak. Then, a simplified piecewise model-based alkaline electrolyzer techno-economic analysis model is proposed. The improved economic performance of the islanded green hydrogen system with the proposed operation strategy is verified based on the wind speed data set simulation generated by the Weibull distribution. Lastly, the sensitivity of the total return on investment to wind speed parameters was investigated, and an islanded green hydrogen system capacity allocation based on the proposed analysis model was conducted. The simulation result shows the total energy utilization increased from 62.0768% to 72.5419%, and the return on investment increased from 5.1303%/month to 5.9581%/month when the proposed control strategy is adopted.

From responsible sourcing of wastes to sustainable energy consumption in the blue hydrogen supply chain: Case of nearshoring in Nuevo Leon

Despite global uncertainties, Mexico has become the largest supplier to the United States, emphasizing its growing role in cultivating resilient supply chains. Nearshoring practices from Mexico and Canada to the U.S. present new production opportunities. Increasingly, U.S. consumers place a premium on sustainable consumption, so blue hydrogen plants must be sourced responsibly. This paper firstly goes beyond economic motivations, aiming to formulate a multi-stage methodology for assessing suppliers of municipal solid waste for blue hydrogen plants, marking a pioneering effort in catering to the environmentally conscious preferences of U.S. consumers. The purpose of this work is to examine a case study of Blue Hydrogen production in Nuevo Leon, emphasizing the importance of developing responsible sourcing criteria for waste suppliers to limited blue hydrogen plants. The developed hybrid approach integrates various methodologies, including Critical Systems Heuristics (CSH), fuzzy rough sets, hierarchical fuzzy rough analysis, Fuzzy rough WASPAS, TOPSIS, and Best-Worst Method (BWM), providing a comprehensive framework for decision-making under uncertainty. Key findings include the identification of water conservation (E2) and job creation (S2) as the top environmental and social criteria, respectively. Supplier WC2 was identified as the top-performing waste collector, achieving a final score of 4.77. This structured methodology prioritizes product categories for hydrogen consumption, considering sustainability criteria and U.S. consumer preferences, thereby offering valuable insights for businesses navigating this evolving landscape.

Grid-neutral hydrogen mobility: Dynamic modelling and techno-economic assessment of a renewable-powered hydrogen plant

The seasonally varying potential to produce electricity from renewable sources such as wind, PV and hydropower is a challenge for the continuous supply of hydrogen for transport and mobility. Seasonal storage of energy allows to avoid the use of grid electricity when it is scarce; storage systems can thus increase the resilience of the energy system. For grid-neutral and renewable hydrogen production, an electrolyser is considered together with a Power-to-Gas seasonal storage system, which consists of a methanation, the gas grid as intermediate storage and a steam reformer. As feed stream, electricity from an own photovoltaic (PV) system is considered, and for some cases additional electricity from the grid or from a wind turbine. The dynamic operation of the plant during a year is simulated. It is possible to safely supply fuel cell vehicles with hydrogen from the grid-neutral plant without using electricity when it is scarce and expensive. To supply 135 kgH2/day, unit sizes of 1 MW–2.9 MW for the PV system and 0.9 MW–2.6 MW for the electrolysis are required depending on the amount of available grid-electricity. The usage of grid-electricity increases the capacity factor of the electrolysis, which results in decreased unit sizes and in a better economic performance. Seasonal storage of energy is required, which results in an increased hydrogen production in summer of approximately 50% more than directly needed by the fuel cell vehicles. The overall efficiency from electricity to hydrogen is decreased due to the storage path by 10%-points to 56% based on the higher heating value. Assuming a cost-equivalent hydrogen price per driven kilometre in comparison to the actual diesel price and electricity costs of 10 Ct/kWhel from the grid, the revenues of the system are higher than the operating costs.

Maritime Security and the Wind: Threats and Risks to Offshore Renewable Energy Infrastructure

Abstract Offshore wind energy production has seen a significant expansion in recent years. With technologies rapidly improving and prices dropping, it is now one of the key instruments in the green energy transition. The implications of offshore wind farm expansion for maritime security and ocean governance have, so far, received sparse attention in the literature. This article offers one of the first thorough analyses of the security of offshore wind farms and related installations, such as underwater electricity cables, energy islands, and hydrogen plants. The technical vulnerabilities of wind farm systems is reviewed and threats from terrorism, crime and State hostilities, including physical and cyber risk scenarios, are discussed. The expansion of green offshore energy production must keep pace with the changing threat landscape that follows from it. Prospective solutions for the protection of wind farms systems, including surveillance, patrols and self-protection are discussed. The current repertoire of maritime security solutions is in many ways capable of dealing with the threats and risks effectively if adjusted accordingly. The analysis builds important new bridges between debates in energy security and maritime security, as well as the implications of climate change adaption and mitigation for security at sea.

A novel framework for quantitative resilience assessment in complex engineering systems during early and late design stages

Recently, resilience assessment has evolved and grown in prominence, yet most studies are carried out on operational stage when sufficient knowledge on the processes is available, overlooking the design stage, a time frame that is more suitable for making a resilient system. To this end, this work aims at developing a novel quantitative resilience assessment framework for engineering systems with two different approaches that practically analyse resilience at the early and late design stages when detailed information on the system’s safety and resilience capabilities may be deficient. In the early design stage, system resilience attributes are identified, and expert judgment is used to assess their quality. In the late design stage, attributes are derived from revealed information such as detailed emergency response and safety barrier data. In both stages, dynamic Bayesian Network (DBN) is used to quantify resilience based on the acquired information. Since the green hydrogen technology is relatively novice, the application of the proposed framework is demonstrated in a resilience assessment of a green hydrogen plant undergoing hydrogen release scenarios. The proposed framework can be used as an effective tool for early design improvements as well as enhancing process safety in the late design stage of hydrogen plants or any other complex engineering system.

Ukraine hopes new €400m hydrogen plant will secure its energy supply

Ukraine hopes new €400m hydrogen plant will secure its energy supply

Feasibility analysis of virtual clean hydrogen plant platform: A case study on energy policy in S. Korea using stochastic programming

In S. Korea, high-density renewable and high-density load areas are separate. This separation has led to increased transmission constraints. As both Renewable Energy Source (RES) penetration and power demand simultaneously increase, RES saturation occurs. This phenomenon reduces both the benefits of power transactions and the acceptance of RES. Addressing this issue requires actions from Independent Power Producers (IPP) and policymakers. This paper suggests a Virtual Clean Hydrogen Plant (VCHP) platform design that consolidates the Photovoltaic (PV) energy from high-density renewable areas into a single power plant. The platform converts excess energy, generated by PV due to transmission constraints, into hydrogen and supplies it to the high-density load areas. The South Korean government plans to introduce a Clean Hydrogen Portfolio Standard (CHPS), which offers a fixed premium (FP) to private power generators that provide power through clean hydrogen. Consequently, the proposed benefit structure of the VCHP platform includes an FP, settled through CHPS. This paper's design and operation algorithm for the VCHP platform incorporates stochastic programming to analyze PV operation and deterministic optimization for the optimal scheduling of Fuel Cells (FC) that provide power and heat to high-density load areas. The simulation results demonstrate that the minimum subsidy required for CHPS benefits varies depending on how PV-coupled P2G technology is utilized. Specifically, engaging in net metering with VCHP over the course of one month can establish a cost-effective benefit structure, verified to require a subsidy ranging from a minimum of 0.2036 $/kWh to a maximum of 0.2416 $/kWh.

Optical measurements of solid nitrogen solubility in hydrogen at cryogenic temperatures

The solubility of impurities in hydrogen at cryogenic temperatures is essential information for the design of liquid hydrogen plants. However, large data scatter and inconsistent predictions of impurity solubility by thermodynamic models mean that expensive engineering design margins are required to avoid blockages in cryogenic equipment. Here we report the combination of a stereomicroscope, commercial cryocooler and pressure cell to directly visualise solid impurity freeze-out and melting in stirred hydrogen at low temperatures and elevated pressures. Scattered literature data for nitrogen's solubility in hydrogen are compared to new solid-fluid equilibrium (SFE) measurements for a 1000 ppm N2 in H2 mixture at (1.8–5) MPa, and (42–52) K. These results were used to improve solubility models implemented in the ThermoFAST software package, achieving a three-fold decrease in the root-mean-square deviations between the SFE predictions and the data, helping lower the risk of impurity freeze-out in hydrogen liquefaction.

Hydrogen 4.0: A Cyber-Physical System for Renewable Hydrogen Energy Plants.

The demand for green hydrogen as an energy carrier is projected to exceed 350 million tons per year by 2050, driven by the need for sustainable distribution and storage of energy generated from sources. Despite its potential, hydrogen production currently faces challenges related to cost efficiency, compliance, monitoring, and safety. This work proposes Hydrogen 4.0, a cyber-physical approach that leverages Industry 4.0 technologies-including smart sensing, analytics, and the Internet of Things (IoT)-to address these issues in hydrogen energy plants. Such an approach has the potential to enhance efficiency, safety, and compliance through real-time data analysis, predictive maintenance, and optimised resource allocation, ultimately facilitating the adoption of renewable green hydrogen. The following sections break down conventional hydrogen plants into functional blocks and discusses how Industry 4.0 technologies can be applied to each segment. The components, benefits, and application scenarios of Hydrogen 4.0 are discussed while how digitalisation technologies can contribute to the successful integration of sustainable energy solutions in the global energy sector is also addressed.

RWE plans Scotland hydrogen plant

RWE plans Scotland hydrogen plant

Waste CO2 capture and utilization for methanol production via a novel membrane contactor reactor process: Techno-economic analysis (TEA), and comparison with other existing and emerging technologies

We introduced recently a CO2 capture and utilization (CCU) technology that produces methanol (MeOH), from waste CO2 employing a novel configuration combining a reverse water gas shift reactor (RWGSR) with a membrane contactor reactor for MeOH synthesis (MeS-MCR). The integrated RWGSR/MeS-MCR process overcomes the challenges direct CO2 conversion into MeOH faces and achieves carbon conversions exceeding 80 %, significantly surpassing the equilibrium conversion of ∼ 20–30 % for the MeS reaction. In this study, a techno-economic analysis (TEA) was conducted on the RWGSR/MeS-MCR process along with four other CO2-to-MeOH CCU processes. Key economic parameters, as well as the energy efficiency, were analyzed with respect to CO2 and renewable hydrogen (H2) costs and plant capacity. The study revealed that the RWGSR/MeS-MCR technology has the highest energy efficiency and the best economic performance among all the technologies investigated. All technologies offer the significant societal benefit of capturing and utilizing waste CO2, but under present CO2 and renewable H2 costs, they cannot currently compete cost-wise with conventional MeOH production methods. However, under a future scenario whereby government incentives lower the CO2 cost and technological advances decrease the price of renewable H2, the proposed RWGSR/MeS-MCR process and another catalytic technology (CAMERE) become price competitive.

Techno-Economic Analysis of Heat-Assisted Hydrogen Production from Nuclear Power

To play a full role in decarbonisation, hydrogen must be produced economically at scale; the role of nuclear power is interesting to national governments as it is capable of supplying both low-carbon electricity and high-quality heat. Depending on the hydrogen production technology choice, a plant may require electricity and/or heat input. This techno-economic evaluation considers not only the costs of the hydrogen plant itself but also the costs of the power supply it requires. This paper calculates cost estimates for HTSE (High Temperature Steam Electrolysis) coupled with nuclear heat and electricity, and a thermochemical SI (Sulphur Iodine) cycle coupled with nuclear heat, based on the predictions of technical process models. These estimates are then compared to estimates made elsewhere for the costs of using wind with low temperature liquid water electrolysis, and steam methane reformation with carbon capture. This analysis led to the identification of the conditions under which nuclear-heat-coupled hydrogen production would be competitively priced. Estimates for nuclear-coupled LCOH2 (levelised cost of hydrogen) in 2050 range from 2.14 to 1.24 £/kg for HTSE, and from 2.88 to 0.89 £/kg for the SI cycle. There is still a great deal of uncertainty around the efficiency of SI and how it may improve over time, and this limits the accuracy to which the LCOH2 can be predicted.

Оптимизация перевозок термочувствительных грузов в рефрижераторных контейнерах с применением альтернативных источников энергии

Purpose: to consider the main problems of transportation of temperature-sensitive cargoes in refrigerated containers (refcontainers). To show the possibilities of transportation optimization through the introduction of alternative energy sources. Methods: comparison of technical and economic indicators of diesel, hydrogen and hydrogen plants is carried out. The exergetic method of estimating the effect of replacing diesel fuel with LNG was applied. Results: the article defines the peculiarities of cargo transportation in containers with built-in refrigeration units — autonomous refcontainers. Classification of existing energy units for power supply of refcontainers is given. The design of an autonomous installation for power supply of refcontainers is described. Environmentally safe alternatives for providing autonomous power supply of refrigerating units of refrigeration containers are proposed. The advantages of autonomous power supply based on high-temperature fuel cells are presented. An autonomous power unit with liquefied natural gas (LNG) as fuel is described. The feasibility of utilization of cold from LNG regasification is analyzed in order to ensure the stability of refcontainer operation. The estimation of the expected effect from the use of alternative fuels for autonomous power supply is made. Practical significance: the obtained results can be used for modernization of low-capacity power plants used in refrigerated and other types of transport.

Multi-objective optimization hydrogen network in refinery expansion with improved transport constraint

In developing countries like Indonesia, adding a new unit for hydroprocessing facilities is more efficient than modifying the existing equipment. When the addition occurs, refiners should analyze if the existing hydrogen network can supply enough hydrogen to the new unit before constructing a costly hydrogen plant. Current studies on the hydrogen network have yet to consider pressure drop adequately. Therefore, this paper integrates pressure drop estimation and density prediction into the multi-objective MINLP-based hydrogen network. The multi-objective problem is solved sequentially by adding a minor unit to obtain each configuration's maximum flowrate and total annual cost. The optimal configuration based on the combined objective function is to add 1 PSA and compressor for a hydrogen purity of 0.84 and specified pressure requirements. The pressure drop integration shows an insignificant impact averaging 0.004 m3/s of maximum flowrate difference compared to optimization without pressure drop.

Using electrolytic hydrogen production and energy storage for balancing a low carbon electricity grid: Scenario assessments for India

Nuclear reactors and variable renewables will play a significant role in the global energy transition as providers of low carbon electricity to various end use sectors. Real time balancing of power demand and supply without modulation or curtailment is possible using electrolytic hydrogen plants and energy storage systems. The generation mix adopted and load profiles are unique to a country and this study considers the specific case of India. This work analyses the use of grid connected water electrolysers, grid scale battery storage, hydrogen storage and fuel cells as flexible loads and dispatch schemes for grid balancing. Based on postulated long term power generation scenarios for India, the minimum required system sizes for grid balancing are estimated and techno-economic uncertainties are assessed. The use of water electrolysers is prioritized to make use of excess power, while minimizing battery storage requirement. This scheme can potentially produce a substantial share of low carbon hydrogen in India for use in industrial decarbonization, thus reducing the need for additional generation infrastructure.