Hydrogen (H₂) is an attractive energy carrier to move, store, and deliver energy in a form that can be easily used. Field proven technology for underground hydrogen storage (UHS) is essential for a successful hydrogen economy. Options for this are manmade caverns, salt domes/caverns, saline aquifers, and depleted oil/gas fields, where large quantities of gaseous hydrogen have been stored in caverns for many years. The key requirements intrinsic of a porous rock formation for seasonal storage of hydrogen are: adequate capacity, ability to contain H₂, capability to inject/extract high volumes of H₂, and a reliable caprock to prevent leakage. We have carefully evaluated a commercial non-isothermal compositional gas reservoir simulator and its suitability for hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs. We have successfully calibrated the gas equation of state model against published laboratory H₂ density and viscosity data as a function of pressure and temperature. Comparisons between the H₂, natural gas and CO₂ storage in real field models were also performed. Our numerical models demonstrated more lateral spread of the H₂ when compared to CO₂ and natural gas with a need for special containment in H₂ projects. It was also observed that the experience with CO₂ and natural gas storage cannot be simply replicated with H₂.

Successful deployment of geological carbon storage (GCS) requires an extensive use of reservoir simulators for screening, ranking and optimization of storage sites. However, the time scales of GCS are such that no sufficient long-term data is available yet to validate the simulators against. As a consequence, there is currently no solid basis for assessing the quality with which the dynamics of large-scale GCS operations can be forecasted. To meet this knowledge gap, we have conducted a major GCS validation benchmark study. To achieve reasonable time scales, a laboratory-size geological storage formation was constructed (the “FluidFlower”), forming the basis for both the experimental and computational work. A validation experiment consisting of repeated GCS operations was conducted in the FluidFlower, providing what we define as the true physical dynamics for this system. Nine different research groups from around the world provided forecasts, both individually and collaboratively, based on a detailed physical and petrophysical characterization of the FluidFlower sands. The major contribution of this paper is a report and discussion of the results of the validation benchmark study, complemented by a description of the benchmarking process and the participating computational models. The forecasts from the participating groups are compared to each other and to the experimental data by means of various indicative qualitative and quantitative measures. By this, we provide a detailed assessment of the capabilities of reservoir simulators and their users to capture both the injection and post-injection dynamics of the GCS operations.

Summary: Hydrogen (H2) is an attractive energy carrier, and its true potential is in decarbonizing industries, such as for providing heat for buildings and being a reliable fuel for trains, buses, and heavy trucks. Industry is already making tremendous progress in cutting costs and improving the efficiency of hydrogen infrastructure. Currently, heating is primarily provided by using natural gas and transportation by gasoline with a large carbon footprint. Hydrogen has a similarly high energy density, but there are technical challenges preventing its large-scale use as an energy carrier. Underground geologic storage of hydrogen in porous media (aquifers and hydrocarbon reservoirs) could offer substantial storage capacity at low cost as well as buffer capacity to meet changing seasonal electricity demands or possible disruptions in power supply. Underground geologic storage must have adequate capacity and ability to inject/extract high volumes with a reliable caprock. A thorough study is essential for a large number of site surveys to locate and fully characterize the subsurface geological storage sites both onshore and offshore. An isothermal compositional reservoir simulator was used to evaluate hydrogen storage and withdrawal from saline aquifers and depleted oil/gas reservoirs. The phase behavior, fluid properties, and petrophysical models were all calibrated against published laboratory data for density, viscosity, relative permeability, and capillary pressure for a given site. History-matched dynamic models of two CO2 injection field projects in saline aquifers and one natural gas storage in a depleted oil reservoir were considered as hypothetical hydrogen seasonal storage sites. A wide range of working gas volume/cushion gas volume ratios was observed, meaning that careful optimization is required for a successful storage project. For the aquifer cases, the range was 0.292 to 1.883 and a range of 1.045 to 4.4 was observed for the depleted hydrocarbon reservoir scenarios. For the saline aquifer cases, a higher injection rate, longer injection/withdrawal (I/W) cycles, and the use of pump wells to control the hydrogen plume spreading were all beneficial for improving the working gas/cushion gas ratio and the working gas volume. Plume control was important for storage in the oil reservoir in which changes in the well length location and orientation showed high sensitivity in the working and cushion gas volumes. Sensitivities to the initial gas saturation in the depleted gas reservoir scenarios suggested that both cushion and working gas volumes increased with the initial gas saturation while the ratio of working to cushion gas volumes decreased with the initial gas saturation. Finally, when comparing the ratios of working to cushion gas volumes, it was the highest for the depleted oil reservoir, followed by the depleted gas reservoir, and the aquifer.

Well integrity is paramount for the safe, environmentally responsible, and economically viable operation of wells throughout their lifecycle, encompassing conventional oil and gas production, unconventional resource extraction (e.g., shale gas and tight oil), and geological storage applications (CO₂, H₂, and natural gas). This review presents a comprehensive synthesis of well integrity challenges, failure mechanisms, monitoring technologies, and management strategies across these operational domains. Key integrity threats—including cement sheath degradation (chemical attack, debonding, cracking, microannuli), casing failures (corrosion, collapse, burst, buckling, fatigue, wear, and connection damage), sustained casing pressure (SCP), and wellhead leaks—are examined in detail. Unique challenges posed by hydraulic fracturing in unconventional wells and emerging risks in CO₂ and hydrogen storage, such as corrosion, carbonation, embrittlement, hydrogen-induced cracking (HIC), and microbial degradation, are also highlighted. The review further explores the evolution of integrity standards (NORSOK, API, ISO), the implementation of Well Integrity Management Systems (WIMS), and the integration of advanced monitoring technologies such as fiber optics, logging tools, and real-time pressure sensing. Particular emphasis is placed on the role of digital technologies—including artificial intelligence, machine learning, and digital twin systems—in enabling predictive maintenance, early failure detection, and lifecycle risk management. The novelty of this review lies in its integrated, cross-domain perspective and its emphasis on digital twin applications for continuous, adaptive well integrity surveillance. It identifies critical knowledge gaps in modeling, materials qualification, and data integration—especially in the context of long-term CO₂ and H₂ storage—and advocates for a proactive, digitally enabled approach to lifecycle well integrity.