Search Results (136)

Hydrogen (H₂) is becoming a meaningful way to store energy for long-term use and support thorough decarbonization in systems that use renewable energy. Underground hydrogen storage (UHS) has strategic benefits over above-ground systems because it can hold large volumes, is contained by geology, and is cheap to operate in cycles. This review compares four key geological formations for underground hydrogen storage (UHS): salt caverns, lined rock caverns, depleted hydrocarbon reservoirs, and saline aquifers. Each system is evaluated based on storage mechanisms, efficiency, safety, technological maturity, and economic feasibility. This review also introduces a unified cross-media evaluation framework, a TRL-risk matrix, a technology development roadmap, and novel insights into AI-based monitoring, offering prescriptive guidance for large-scale UHS implementation. Salt caverns have high injectivity, maintain their purity, and undergo 6 to 12 cycles per year at pressures of 60 to 180 bar; however, they are only found in certain places. Lined rock caverns can be built anywhere, but sealing and economic issues make them difficult to use. Depleted hydrocarbon reservoirs with TWh-scale capacity and already built infrastructure. Saline aquifers, on the other hand, have the most potential in the world but need enhanced management of microbiological responses and cushion gas optimization. A synthesis of current studies highlights key research gaps in cyclic geomechanics, hydrogen–rock–microbe interactions, and liner performance for high-pressure storage. The review concludes with techno-economic and safety considerations and identifies future directions for deploying geological UHS as a critical component of a net-zero hydrogen economy. Full article

This paper assesses the role of green hydrogen and green ammonia in the low-carbon reconstruction of Ukraine’s energy sector. The country, severely affected by war, has more than 70% of its energy infrastructure damaged or destroyed, which calls for novel solutions for not only reconstructing but also rethinking Ukraine’s energy sector shaped by the Soviet-era planning. In this context, decentralized and renewable energy solutions appear to be one of the best options to achieve this goal. This study combines four novel and mutually reinforcing methods: a Scopus-based literature review of highly cited green hydrogen publications, natural language processing (NLP) and bibliometric network analysis of Ukraine-related hydrogen research, a SWOT assessment, and a geospatial hydrogen production cost model (GEOH2). The novelty of this research lies in this integrated Ukraine-specific framework, which links research trends, wartime reconstruction constraints, hub-level policy choices, and financing risk-sensitive cost modeling. Therefore, the quantitative part of GEOH2 estimates the levelized cost of green hydrogen, while ammonia is treated as a downstream screening-level conversion and export pathway rather than as a full plant-level ammonia model. Our results show that Ukrainian green hydrogen research is concentrated on renewable-energy strategy, wind and solar electrolysis, water and desalination constraints, gas grid blending, underground storage, ammonia derivatives, and decentralized energy systems. The GEOH2 results indicate that southern Ukraine has strong physical potential for competitive green hydrogen production under de-risked financing, while war risk financing can make even resource-rich areas economically unattractive. Odesa and Dnipro emerge as important export-oriented and industrial hubs, whereas Zakarpattia remains strategically relevant as a safer western corridor linked to European markets. Our findings demonstrate that Ukraine’s hydrogen and ammonia development needs to follow a phased pathway: domestic renewable build-out and grid repair, pilot electrolysis projects and screening-level ammonia conversion pathways, targeted de-risking and insurance mechanisms, and only then broader export corridor development. This pathway can support decarbonization, energy security, industrial modernization, and Ukraine’s long-term integration into European clean energy value chains. Full article

This study developed and validated a new simple and improved two-parameter high-quality equation of state (EOS) for hydrogen that can be used with less computational burden for the accurate description of various processes regarding underground hydrogen storage. Variation in hydrogen gas density with pressure was described by the modified power-law equation by relating density variation to deviations of density from the low-end and high-end limit values of density. The high-end limit density dependence on temperature was described by an Arrhenius-type asymptotic exponential function. The parameters of this EOS were determined by requiring thermodynamic consistency. This simple two-parameter EOS is thermodynamically consistent because the molar density is equal to zero, and its derivative with respect to pressure is equal to 1/(RT), like an ideal gas EOS when pressure approaches zero (T is absolute temperature, and R is the universal gas constant). This new simple EOS correlates hydrogen density efficiently using experimental data over 0–100 MPa and 220–473 K and molecular simulation data over the 14.03–116.064 MPa and 310.9–470 K ranges of pressures and temperatures. The new EOS is very accurate, as indicated by the coefficients of correlation being almost equal to unity (R² = 0.9999), the relative difference between the correlation and measured density values being very close to zero (RMSE = 0.0032), and the percentage average absolute value of the relative deviation of the EOS correlation density values ρ_EOS from the experimental density values ρ_Data being (ρ_Data/ρ_EOS − 1)100 = 0.15% average uncertainty. Full article

Large-scale hydrogen storage is expected to play a critical role in balancing the variability of renewable energy systems, particularly those driven by wind power. However, the combined influence of storage capacity and deliverability on supply reliability remains insufficiently characterized. This study investigates the reliability limits of hydrogen storage systems operating under variable hydrogen production and time-varying demand. A dimensionless modeling framework is developed to map system performance across a wide range of storage capacities and deliverability levels. The results reveal a clear transition between reliable and unreliable operating regimes. Reliable operation requires a minimum deliverability level approximately equal to the mean hydrogen production rate, corresponding to a value of about 1.05–1.10 times the average production across the range of intermittency conditions considered in this study (from moderate to highly variable production). Below this threshold, increasing storage capacity alone cannot prevent supply shortfalls. Once this threshold is exceeded, further increases in deliverability provide diminishing returns and storage capacity becomes the dominant factor governing reliability. In this regime, the required storage capacity approaches a plateau on the order of 10–30 days of average hydrogen throughput, depending on the level of production variability. The proposed regime-based framework provides a practical tool for evaluating storage feasibility and guiding preliminary capacity design in renewable hydrogen systems. Full article

The continuous increase in Renewable Energy Sources (RES) in Greece’s electricity system has led to growing energy curtailment due to limited grid capacity, especially in high-production regions. According to recent data, more than 200 GWh of clean energy was curtailed in a single quarter in 2024, highlighting the urgent need for effective storage solutions. Curtailment represents a growing system level challenge, but it also creates an opportunity to convert surplus renewable electricity into green hydrogen through electrolysis. This study quantifies the hydrogen production potential of curtailed RES electricity in four Greek regions, Peloponnese, Crete, Thrace, and Western Macedonia, and evaluates alternative storage pathways under harmonized techno-economic assumptions. A scenario-based framework is developed using regional RES capacity, curtailment estimates, electrolyzer efficiency, hydrogen conversion factors, and indicative storage cost ranges. The analysis compares pressurized tank storage, underground storage, and hybrid configurations, while also estimating avoided CO₂ emissions from the substitution of grey hydrogen. The results indicate substantial regional variation. The Peloponnese exhibits the highest annual hydrogen potential, followed by Crete, Thrace, and Western Macedonia, while each region presents different infrastructure constraints and deployment roles. Mainland regions with access to geological storage show lower indicative hydrogen costs than island systems, where storage and export constraints increase costs. The findings show that curtailed renewable electricity can function as a low-carbon feedstock for hydrogen production in Greece, supporting grid flexibility, regional decarbonization, and the gradual development of hydrogen hubs under differentiated regional strategies. Full article

Underground Gas Storage (UGS) is transitioning from traditional fossil fuel peak-shaving facilities into comprehensive hubs for Terawatt-hour-scale Terawatt-hour (TWh) scale renewable energy storage. The unique physicochemical properties of diverse fluids, such as the negative Joule–Thomson coefficient of hydrogen (−0.03 K/bar), present complex engineering adaptability challenges. Since existing studies primarily focus on single mechanisms or specific geological types, this review integrates a unified engineering framework to evaluate the repurposing potential and retrofitting requirements of existing oil and gas assets. By compiling a property benchmarking matrix for methane, carbon dioxide, and hydrogen, the storage adaptability of various geological formations is summarized. Salt caverns exhibit strong adaptability to highly diffusive and reactive fluids due to their high salinity (exceeding 150 g/L) and mechanical stability, whereas porous media offer massive capacity (more than 10 times) but require overcoming severe biogeochemical obstacles. Based on thermo–hydro–mechanical–chemical–biological (THMCB) coupling mechanisms, an integrity evaluation system for artificial wellbore and natural geological barriers is systematically reviewed. Critical risks, including fatigue failure under high-frequency cyclic loading, material degradation, gas leakage, and indirect Global Warming Potential (GWP), are elucidated. A future evolution route integrating physical, digital, and policy dimensions is outlined. This roadmap emphasizes Hydrogen-Enriched Compressed Natural Gas (HCNG)synergistic storage, dynamic risk control utilizing digital twins and Artificial Intelligence (AI), and standardized Life Cycle Assessment mechanisms (LCA), providing a scientific basis for the sustainable transition of UGS facilities. Full article

Pressure swing adsorption (PSA) is a viable method for separating hydrogen from gas mixtures, an important aspect of long-term hydrogen storage in depleted gas fields. This study explores optimizing a 12-step PSA process for recovering high-purity hydrogen from varying compositions of hydrogen–methane mixtures, simulating the conditions likely encountered during hydrogen storage and recovery. Step-time optimization was performed on four different hydrogen–methane mixtures using the toPSAil simulation package—an open-source dynamic PSA simulator developed by researchers at the Georgia Institute of Technology—integrated with a particle swarm optimization (PSO) algorithm. The goal was to develop an optimization framework that can reliably identify PSA step times for different operating scenarios and satisfy specified purity and recovery constraints under fluctuating wellhead feed conditions. The optimization converged within 25–30 iterations, even in high-contaminant, low-pressure scenarios, where PSA performance is traditionally weak. The product purity in the optimized cycles was above 99.1% with more than 80% recovery for all cases, while fuel cell quality (99.7%) hydrogen was achieved in two out of the four scenarios. The purge-to-feed ratio of the best-performing cycles was between 0.07 and 0.32. These findings show the potential of the proposed approach in overcoming the difficulty of designing PSA cycles for non-constant gas compositions and achieving a hydrogen purification process suitable for variable feed conditions. The workflow generates a large synthetic dataset that can support surrogate or hybrid modeling. The results can help advance research in other gas separation areas with non-constant conditions, like flue gas or biogas purification. Full article

This study develops a conceptual framework for characterizing reservoir architecture in multi-component, discrete systems using pressure transient analysis (PTA), aimed at calibrating inflow geometry prior to full-field dynamic simulation for subsurface gas storage applications such as CO₂ and hydrogen. A secondary objective is to identify variations in permeability over time by analyzing flow capacity trends and evaluating the dynamic influence of faults and fractures. The analysis is based on a gas-condensate field comprising seven wells and four zones (A, B, C, D), using integrated dynamic datasets including extended well tests (EWTs), mud loss, production logs, and production data. Detailed interpretation of PX-1’s EWT indicated delayed re-pressurization and persistent under-pressure, suggesting a compartmentalized or transient system with limited gas-in-place connectivity. Four reservoir architecture concepts were developed: (1) lithology-dominated inflow, (2) structurally controlled inflow, (3) discrete, weakly connected compartments, and (4) transient-dominated systems with tight matrix GIIP. These concepts informed four reservoir models: matrix-only (M), areal heterogeneity (A), sparse bodies (B), and sparse networks (S). Application of these models across other wells revealed consistent localized KH (permeability–thickness product) behavior, with all models fitting short-duration data comparably. However, only sparse drainage models (B/S) adequately matched PX-1’s EWT response. PTA results confirm that well tests constrain KH locally but provide limited insight into large-scale reservoir architecture. EWTs may reach ~1 km, while shorter tests are confined to ~200–400 m, typically within one to two simulation grid blocks. This study demonstrates how integrating PTA with multi-scale data improves characterization of naturally fractured, tight carbonate reservoirs and supports reservoir simulation and history matching for hydrogen storage evaluation. Based on reservoir simulations, this study concluded that naturally fractured carbonate gas reservoirs can provide significant storage and injection capacities for underground hydrogen storage. This study exemplifies how to characterize the naturally fractured tight carbonate reservoirs by integrating multi-scale and multi-dimensional data such as PTA. Furthermore, this study assists in gridding for full-field reservoir models, for history matching and quantifying the potential of hydrogen storage in these complex reservoirs. The proposed workflow provides an uncertainty-bounded reservoir characterization framework and should not be interpreted as a complete field-design methodology for hydrogen storage. The modeling does not explicitly couple geomechanical fracture growth, hydrogen diffusion, long-term geochemical reactions, or caprock integrity degradation. Therefore, the presented storage scenarios represent technically feasible cases under defined assumptions. Comprehensive site-specific geomechanical and containment assessments are required prior to field-scale implementation. Full article

Impure rock salt is increasingly used as a host medium for underground hydrogen and compressed air energy storage in China; however, its permeability evolution under stress remains insufficiently constrained. This study presents a systematic experimental and modeling investigation of the permeability behavior of impure rock salt from the Pingdingshan (Henan) and Yunying (Hubei) salt mines. Nineteen cylindrical specimens were subjected to full-process triaxial permeability testing, including initial measurements, hydrostatic damage recovery, and staged deviatoric loading. A hydrostatic recovery stage (15 h at 40 MPa) was applied to reduce coring- and machining-induced micro-damage, resulting in a permeability reduction in one to three orders of magnitude. After recovery, the initial permeability decreases nonlinearly with increasing effective stress and converges to approximately 10⁻²¹ m² at stress levels corresponding to in situ burial depths. During deviatoric loading, permeability exhibits a two-stage response: a rapid increase associated with early damage and microcrack initiation, followed by saturation once the dilatant volumetric strain exceeds approximately 1–2%. Impurity content influences both the magnitude and evolution of permeability by modifying the initial pore structure and damage development; however, the response is non-monotonic and region-dependent due to differences in dominant impurity mineralogy. Based on the experimental results, a semi-theoretical permeability model incorporating effective stress, dilatant strain, and impurity content was developed. The model reproduces the observed permeability evolution under different confining pressures with good agreement, providing a practical framework for evaluating the hydraulic integrity of impure rock salt in underground energy storage applications. Full article

In the context of the energy transition and the increasing deployment of low-carbon gases (hydrogen, biomethane), reliable analytical monitoring is required to support integrity assessment and traceability of gas infrastructures under diverse on-site conditions while limiting analytical costs through standardized sampling and a single analytical system. We developed and validated integrated workflows combining sampling and laboratory analysis for chemical and compound-specific isotope analysis (CSIA) of natural gas and associated gaseous effluents in underground storage. An original quantification approach was implemented, linking sampling pressure to the amount of each compound collected in vials, and coupled with δ¹³C and δ²H measurements of alkanes (C₁–C₃), CO₂ and H₂. Two complementary sampling modes were optimized and compared: conventional high-pressure cylinders and direct collection into vacuum-sealed vials suitable for a broad range of pressures and field conditions. Using reference gas mixtures and operational samples, both approaches showed good reproducibility and isotopic accuracy during laboratory validation and over two years of monitoring. In particular, δ²H determinations for alkanes and H₂ remained robust under low-pressure sampling typical of annular spaces (~1–2 bar), despite gas-composition fluctuations. These validated methodologies provide a flexible basis for routine, standardized monitoring of stored and circulating gases, including emerging low-carbon components. Full article

This review examines the emerging concepts of hydrogen production and storage directly within hydrocarbon reservoirs (in situ), evaluating their technical feasibility, infrastructure requirements, challenges, and potential role in net-zero strategies. The in situ hydrogen production involves injecting substances, like water or gases, into the reservoir where they react with the natural materials underground. Heat and catalysts can also help speed up chemical reactions. Techniques such as methane reforming, steam gasification, and aquathermolysis show promise for producing hydrogen efficiently while keeping carbon emissions low. There are several benefits when producing and storing hydrogen underground, including lower costs, less need for surface equipment, and reduced gas emissions. However, there are still certain challenges to this process, such as finding the optimal reaction conditions and keeping the reservoir stable over time. This review outlines key technological breakthroughs, real-world applications, and future research directions for in situ hydrogen generation and storage initiatives to help meet net-zero emission goals by 2050. Full article

Serbia’s energy sector is undergoing structural transformation driven by European climate policies, market volatility, and the need for long-term energy security. In this context, geological storage of energy carriers represents a strategically important option. Depleted gas reservoirs, particularly within the Pannonian Basin, constitute a technically validated subsurface infrastructure suitable for repurposing as multifunctional storage systems for natural gas, CO₂, and green hydrogen. This study analyzes trends in European and Serbian natural gas markets, EU decarbonization targets, and Serbia’s energy balance to assess the feasibility of carbon capture and storage (CCS) and underground hydrogen storage. Key geological parameters governing long-term containment—lithology, effective porosity, permeability, caprock integrity, and structural stability—are evaluated, with emphasis on reservoirs combining favorable properties and proximity to existing infrastructure. Quantitative screening based on reservoir depth (approximately 1000–2500 m), effective porosity (15–25%), permeability (typically >50 mD), verified caprock integrity, and estimated geological storage capacities ranging from 0.17 to 1.25 billion m³ demonstrates that several depleted gas reservoirs in Serbia meet explicit fit-for-purpose criteria for underground storage applications. A comparative analysis of the physical and molecular behavior of H₂, CH₄, and CO₂ in porous media indicates that hydrogen storage is the most sensitive to reservoir integrity. The reported results provide quantitative and qualitative evidence that selected depleted gas reservoirs in Serbia satisfy essential requirements for project-level screening, including reservoir capacity, petrophysical suitability, caprock integrity, and infrastructure accessibility. These findings support the technical readiness of such reservoirs for staged deployment of natural gas storage, CO₂ sequestration, and underground hydrogen storage in the post-2035 energy system. Overall, combined subsurface storage of natural gas, CO₂, and hydrogen in Serbia is technically feasible, economically justified, and strategically relevant within the national energy transition framework. Full article

Depleted oil and gas reservoirs, owing to their large storage capacity and well-established infrastructure, are attractive sites for storing green energy carriers such as natural gas, hydrogen, and compressed air. During injection–production cycling in underground gas storage (UGS), variations in effective stress can cause repeated stress disturbances in the reservoir and surrounding rock, which may trigger borehole sand production. In this study, laboratory sand-production simulation tests were conducted to evaluate the effects of cyclic-loading stage, upper stress limit, and cycling frequency on borehole damage and sand-production behavior. The results show that sand production is stage-dependent. During the rapid-hardening and stable stages, the borehole remains largely intact and sand production is negligible. Once the failure and collapse stages are reached, borehole integrity deteriorates and sand production increases sharply, with fine particles becoming dominant. Cumulative sand production increases with the upper stress limit. Increasing the upper limit from 80% to 95% leads to a 2.53-fold increase in produced sand mass, together with a higher fine-sand fraction and a shift in the particle-size distribution (PSD) toward smaller sizes. The cycling frequency also plays an important role. When the frequency decreases, cumulative sand production increases and becomes 53.1% higher than the baseline at 0.001 Hz. Meanwhile, the median particle size (D50) decreases, indicating stronger particle breakage under low-frequency cycling. These findings provide guidance for designing injection–production schemes for UGS and for selecting appropriate sand-control completion strategies. Full article

Underground hydrogen storage (UHS) in depleted oil and gas reservoirs is regarded as a highly promising subsurface option due to its large storage capacity. In such reservoirs, the pore structure provides the primary space for hydrogen storage and governs matrix flow and diffusion. Tree-shaped fracture networks generated by hydraulic fracturing or cycling injection–production typically exhibit much higher transmissivity and serve as the dominant pathways. In this study, the geometry of multilevel branching fractures was parameterized, and two classes of tree-shaped fracture configurations were constructed, including point–line-type (PLTSF) and disc-shaped (DSTSF) networks. Analytical models were developed to evaluate the equivalent permeability of tree-shaped fracture networks with either elliptical or rectangular cross-sections. The Klinkenberg slip correction and a gas-type factor associated with molecular kinetic diameter were incorporated. The apparent equivalent permeability of hydrogen (k_app,H2) was quantified and compared with those of nitrogen and methane under identical conditions. The main findings were as follows: (1) the fracture width ratio (β) was identified as the primary factor controlling network conductivity, while the height ratio (α) amplified or attenuated this effect at a given β; (2) as the main-fracture aspect ratio, the branching order (n) or branching angle (θ) increased, the rectangular cross-sections were more favorable for maintaining higher permeability compared to the elliptical cross-section; (3) under typical operating pressures of 5–30 MPa, the apparent permeability of hydrogen was approximately 2–9% higher than that of methane and nitrogen; and (4) by introducing the fracture volume fraction, the REV-scale equivalent-permeability expression was derived for fractured rock masses containing tree-shaped fracture networks. The proposed framework provides a theoretical basis and parametric support for quantifying fracture flow capacity for UHS in depleted reservoirs. Full article

Although technologies used in non-fossil methane and fossil resources to produce blue hydrogen are relatively mature, a system-integrated approach to reference system (RS)-based purification of H₂, CO₂ capture and storage, and UHS is relatively unexplored and requires research to fill gaps in the literature regarding balanced permutations and geological viability for net-zero requirements. This research proposes a system-integrated process for H₂ production through a PSA-based purification technique coupled with amine-based CO₂ capture and underground hydrogen storage (UHS). The intellectual novelty of the research is its first quantitative treatment of synergistic effects such as heat recovery and pressure-matching across units. Additionally, a site separation technique is applied, where H₂ and CO₂ reservoirs are selected based on the permeability of rock formations and fluids. On a research methodology front, a base case of a steam methane reforming process with the production of 99.99% pure H₂ at a production rate of 5932 kg/h is modeled and simulated using Aspen Plus™ to create a balanced permutation of mass and energy across units. As per the CO₂ capture requirements of this research, a capture of 90% of CO₂ is accomplished from the production of 755 t/d CO₂ within the model. The compressed CO₂ is permanently stored at specifically identified rock strata separated from storage reservoirs of H₂ to avoid empirically identified hazards of rock–fluid interaction at high temperatures and pressures. The lean amine cooling of CO₂ to 60 °C and elimination of tail-gas recompression simultaneously provides 5.4 MW_th of recovered heat. The integrated design achieves a net primary energy penalty of 18% of hydrogen’s LHV, down from ~25% in a standalone configuration. This corresponds to an energy saving of 8–12 MW, or approximately 15–18% of the primary energy demand. The research computes a production cost of H₂ of 0.98 USD per kg of H₂ within a production atmosphere of a commercialized WGS and non-fossil methane-based production of H₂. Additionally, a sensitivity analysis of ±23% of the energy requirements of the reference system shows no marked sensitivity within a production atmosphere of a commercially available WGS process. Full article