Transmission, Distribution & Storage

With the issue of energy shortages becoming increasingly serious the need to shift to sustainable and clean energy sources has become urgent. However due to the intermittent nature of most renewable energy sources developing underground hydrogen storage (UHS) systems as backup energy solutions offers a promising solution. The thick and regionally extensive salt deposits in Unit B of Southern Ontario Canada have demonstrated significant potential for supporting such storage systems. Based on the stratigraphy statistics of unit B this study investigates the feasibility and stability of underground hydrogen storage (UHS) in salt caverns focusing on the effects of cavern shape geometric parameters and operating pressures. Three cavern shapes—cylindrical cone-shaped and ellipsoid-shaped—were analyzed using numerical simulations. Results indicate that cylindrical caverns with a diameter-to-height ratio of 1.5 provide the best balance between storage capacity and structural stability while ellipsoid-shaped caverns offer reduced stress concentration but have less storage space posing practical challenges during leaching. The results also indicate that the optimal pressure range for maintaining stability and minimizing leakage lies between 0.4 and 0.7 times the vertical in situ stress. Higher pressures increase storage capacity but lead to greater stress displacements and potential leakage risks while lower pressure leads to internal extrusion tendency for cavern walls. Additionally hydrogen leakage rate drops with the maximum working pressure yet total leakage mass keeps a growing trend.

The subject of this study is the analysis of influence of capillary threshold pressure and injection well location on the dynamic CO2 and H2 storage capacity for the Lower Jurassic reservoir of the Sierpc structure from central Poland. The results of injection modeling allowed us to compare the amount of CO2 and H2 that the considered structure can store safely over a given time interval. The modeling was performed using a single well for 30 different locations considering that the minimum capillary pressure of the cap rock and the fracturing pressure should not be exceeded for each gas separately. Other values of capillary threshold pressure for CO2 and H2 significantly affect the amount of a given gas that can be injected into the reservoir. The structure under consideration can store approximately 1 Mt CO2 in 31 years while in the case of H2 it is slightly above 4000 tons. The determined CO2 storage capacity is limited; the structure seems to be more prospective for underground H2 storage. The CO2 and H2 dynamic storage capacity maps are an important element of the analysis of the use of gas storage structures. A much higher fingering effect was observed for H2 than for CO2 which may affect the withdrawal of hydrogen. It is recommended to determine the optimum storage depth particularly for hydrogen. The presented results important for the assessment of the capacity of geological structures also relate to the safety of use of CO2 and H2 underground storage space.

The transport of hydrogen in used natural gas pipelines is a strategic key element of a pan-European hydrogen infrastructure. At the same time accurate knowledge of the hydrogen quality is essential in order to be able to address a wide application range. Therefore an experimental investigation was carried out to find out which contaminants enter into the hydrogen from the used natural gas pipelines. Pipeline elements from the high pressure gas grid of Austria were exposed to hydrogen. Steel pipelines built between 1960 and 2018 which were operated with odorised and pure natural gas were examined. The hydrogen was analysed according to requirements of ISO14687: 2019 Grade D measurement standard. The results show that based on age odorization and sediments different contimenants are introduced. Odorants hydrocarbons but also sulphur compounds ammonia and halogenated hydrogen compounds were identified. Sediments are identified as the main source of impurities. However the concentrations of the introduced contaminants were low (6 nmol/mol to 10 μmol/mol). Quality monitoring with a wide range of detection options for different components (sulphur halogenated compounds hydrocarbons ammonia and atmospheric components) is crucial for real operation. The authors deduce that a Grade A hydrogen quality can be safely achieved in real operation.

Thanks to the advantages of cleanliness high efficiency extensive sources and renewable energy hydrogen energy has gradually become the focus of energy development in the world’s major economies. At present the natural gas transportation pipeline network is relatively complete while hydrogen transportation technology faces many challenges such as the lack of technical specifications high safety risks and high investment costs which are the key factors that hinder the development of hydrogen pipeline transportation. This paper provides a comprehensive overview and summary of the current status and development prospects of pure hydrogen and hydrogen-mixed natural gas pipeline transportation. Analysts believe that basic studies and case studies for hydrogen infrastructure transformation and system optimization have received extensive attention and related technical studies are mainly focused on pipeline transportation processes pipe evaluation and safe operation guarantees. There are still technical challenges in hydrogen-mixed natural gas pipelines in terms of the doping ratio and hydrogen separation and purification. To promote the industrial application of hydrogen energy it is necessary to develop more efficient low-cost and low-energy-consumption hydrogen storage materials.

Hydrogen threatens the structural integrity of metals and thus predicting hydrogen-material interactions is key to unlocking the role of hydrogen in the energy transition. Quantifying the interplay between material deformation and hydrogen diffusion ahead of cracks and other stress concentrators is key to the prediction and prevention of hydrogen-assisted failures. In this work a generalised theoretical and computational framework is presented that for the first time encompasses: (i) stress-assisted diffusion (ii) hydrogen trapping due to multiple trap types rigorously accounting for the rate of creation of dislocation trap sites (iii) hydrogen transport through dislocations (iv) equilibrium (Oriani) and non-equilibrium (McNabb-Foster) trapping kinetics (v) hydrogen-induced softening and (vi) hydrogen uptake considering the role of hydrostatic stresses and local electrochemistry. Particular emphasis is placed on the numerical implementation in COMSOL Multiphysics releasing the relevant models and discussing stability discretisation and solver details. Each of the elements of the framework is independently benchmarked against results from the literature and implications for the prediction of hydrogen-assisted fractures are discussed. The second part of this work (Part II) shows how these crack tip predictions can be combined with crack growth simulations.

This study investigated the impact of cushion gas type and presence on the performance of underground hydrogen storage (UHS) in an offshore North Sea aquifer. Using numerical simulation the relationship between cushion gas type and UHS performance was comprehensively evaluated providing valuable insights for designing an efficient UHS project delivery. Results indicated that cushion gas type can significantly impact the process's recovery efficiency and hydrogen purity. CO2 was found to have the highest storage capacity while lighter gases like N2 and CH4 exhibited better recovery efficiency. Utilising CH4 as a cushion gas can lead to a higher recovery efficiency of 80%. It was also determined that utilising either of these cushion gases was always more beneficial than hydrogen storage alone leading to an incremental hydrogen recovery up to 7%. Additionally hydrogen purity degraded as each cycle progressed but improved over time. This study contributes to a better understanding of factors affecting UHS performance and can inform the selection of cushion gas type and optimal operational strategies.

In this study we evaluate the technical viability of storing hydrogen in a deep UKCS aquifer formation through a series of numerical simulations utilising the compositional simulator CMG-GEM. Effects of various operational parameters such as injection and production rates number and length of storage cycles and shut-in periods on the performance of the underground hydrogen storage (UHS) process are investigated in this study. Results indicate that higher H2 operational rates degrade both the aquifer's working capacity and H2 recovery during the withdrawal phase. This can be attributed to the dominant viscous forces at higher rates which lead to H2 viscous fingering and gas gravity override of the native aquifer water resulting in an unstable displacement of water by the H2 gas. Furthermore analysis of simulation results shows that longer and less frequent storage cycles lead to higher storage capacity and decreased H2 retrieval. We conclude that UHS in the studied aquifer is technically feasible however a thorough evaluation of the operational parameters is necessary to optimise both storage capacity and H2 recovery efficiency.

This research investigates the potential of using bedded salt formations for underground hydrogen storage. We present a novel artificial intelligence framework that employs spatial data analysis and multi-criteria decision-making to pinpoint the most appropriate sites for hydrogen storage in salt caverns. This methodology incorporates a comprehensive platform enhanced by a deep learning algorithm specifically a convolutional neural network (CNN) to generate suitability maps for rock salt deposits for hydrogen storage. The efficacy of the CNN algorithm was assessed using metrics such as Mean Absolute Error (MAE) Mean Squared Error (MSE) Root Mean Square Error (RMSE) and the Correlation Coefficient (R2 ) with comparisons made to a real-world dataset. The CNN model showed outstanding performance with an R2 of 0.96 MSE of 1.97 MAE of 1.003 and RMSE of 1.4. This novel approach leverages advanced deep learning techniques to offer a unique framework for assessing the viability of underground hydrogen storage. It presents a significant advancement in the field offering valuable insights for a wide range of stakeholders and facilitating the identification of ideal sites for hydrogen storage facilities thereby supporting informed decisionmaking and sustainable energy infrastructure development.

The addition of small amounts of certain gases such as O2 CO and SO2 may mitigate hydrogen embrittlement in high-pressure gas transmission pipelines that transport hydrogen. To practically implement such inhibition in gas transmission pipelines a comprehensive understanding and quantification of this effect are essential. This review examines the impact of various added gases to hydrogen including typical odorants on gaseous hydrogen embrittlement of steels and evaluates their inhibition effectiveness. O2 CO and SO2 were found to be effective inhibitors of hydrogen embrittlement. Yet the results in the literature have not always been consistent partly because of the diverse range of mechanical tests and their parameters. The absence of systematic studies hinders the evaluation of the feasibility of using gas phase inhibitors for controlling gaseous hydrogen embrittlement. A method to quantify the effectiveness of gas phase inhibition is proposed using gas phase permeation studies.

Hydrogen is deemed as a crucial component in the transition to a carbon-free energy system and researchers are actively working to realize the hydrogen economy. While hydrogen derived from renewable energy sources is a promising means of providing clean energy to households and industries its practical usage is currently hindered by difficulties in transportation and storage. Due to the extreme operating conditions required for liquefying hydrogen various hydrogen carriers are being considered which can be transported and stored at mild operating conditions and provide hydrogen at the site of usage. Among various candidates green hydrogen carriers obtained via carbon dioxide utilization have been proposed as an economically and environmentally feasible option. Herein the potential of using methanol and formic acid as green hydrogen carriers are evaluated regarding various production and dehydrogenation pathways within a hydrogen distribution system including the recycle of carbon dioxide. Recent progress in carbon dioxide utilization processes especially conversion of carbon dioxide captured in amine solutions have demonstrated promising results for methanol and formic acid production. This study analyzes seven scenarios that consider carbon dioxide utilization-based thermocatalytic and electrochemical methanol and formic acid production as well as different dehydrogenation pathways and compares them to the scenario of delivering liquefied hydrogen. The scenarios are thoroughly analyzed via techno-economic analysis and life cycle assessment methods. The results of the study indicate that methanol-based options are economically viable reducing the cost up to 43% compared to liquefied hydrogen delivery. As for formic acid only the electrochemical production method is profitable retaining 10% less cost compared to liquefied hydrogen delivery. In terms of environmental impact all of the scenarios show higher global warming impact values than liquefied hydrogen distribution. However results show that in an optimistic case where wind electricity is widely used electrochemical formic acid production is competitive with liquefied hydrogen distribution retaining 39% less global warming impact values. This is because high conversion can be achieved at mild operating conditions for the production and dehydrogenation reactions of formic acid reducing the input of utilities other than electricity. This study suggests that while methanol can be a shortterm solution for hydrogen distribution electrochemical formic acid production may be a viable long-term option.