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.

Summary: Low-salinity waterflooding is an emerging enhanced-oil-recovery (EOR) technique in which the salinity of the injected water is substantially reduced to improve oil recovery over conventional higher-salinity waterflooding. Although there are many low-salinity experimental results reported in the literature, publications on modeling this process are rare. Although there remains some debate regarding the mechanisms of low salinity waterflooding process (LoSal EOR®)*, the geochemical reactions that control the wetting of crude oil on the rock are likely to be central to a detailed description of the process. Because no comprehensive geochemical-based modeling has been applied in this area, it was decided to couple a state-of-the-art geochemical package, IPhreeqc (Charlton and Parkhurst 2011), developed by the US Geological Survey, with UTCOMP (Chang 1990), the compositional reservoir simulator developed by The University of Texas at Austin.A step-by-step algorithm is presented for integrating IPhreeqc with UTCOMP. Through this coupling, we are able to simulate homogeneous and heterogeneous (mineral dissolution/precipitation), irreversible, and ion-exchange reactions under nonisothermal, nonisobaric, and both local-equilibrium (away from the wellbore) and kinetic (near wellbore) conditions. Consistent with the literature, there are significant effects of water-soluble hydrocarbon components—e.g., carbon dioxide (CO2), methane (CH4), and acidic/basic components of the crude—on buffering the aqueous pH value and more generally, on the crude oil, brine, and rock reactions. Thermodynamic constraints are used to explicitly include the effect of these water-soluble hydrocarbon components. Hence, this combines the geochemical power of IPhreeqc with the important aspects of hydrocarbon flow and compositional effects to produce a robust, flexible, and accurate integrated tool capable of including the reactions needed to mechanistically model low-salinity waterflooding.Different geochemical-based approaches to modeling wettability change in sandstones (e.g., interpolation on the basis of total ionic strength and multicomponent ion exchange through surface complexation of the organometallic components) were implemented in UTCOMP-IPhreeqc, and the integrated tool is then used to match and interpret a low-salinity experiment published by Kozaki (2012) and the field trial performed by BP at the Endicott field.

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.

We have developed a new pore-scale method to quantify petrophysical properties of hydrocarbon (HC)-bearing shale. Recent studies indicate that slip flow, Knudsen diffusion, Langmuir desorption, and diffusion in kerogen contribute to the unconventional production properties of shale-gas formations. Conventional petrophysical interpretation methods do not account for the aforementioned phenomena and are often inconclusive when estimating petrophysical properties in shale formations. We constructed a pore-scale representation of the lower Eagle Ford Shale based on focused-ion-beam–scanning-electron-microscope (FIB-SEM) images. Permeability is calculated via previously developed finite-difference methods for the cases with and without slip flow and Knudsen diffusion. The method also calculates streamlines to describe sample pore connectivity. Weighted throat-size distributions are defined based on streamlines to represent the most resistive paths for fluid flow in the FIB-SEM image. Subsequently, permeability is estimated from the dominant throat size in the weighted throat-size distribution. We used a new fluid percolation model for HC-bearing shale that expands HC from kerogen surfaces and water from grain and clay surfaces into the pore space to vary fluid saturation. Isolated pores are randomly distributed within kerogen to increase kerogen maturity in the model. Electrical resistivity is calculated with a finite-difference solution of Kirchhoff’s voltage law applied at the pore scale. A parallel conductor model was used based on Archie’s equation for water conductivity in pores and a parallel conductive path for the Stern-diffuse layer. Calculations were compared with Waxman-Smits’ and Archie’s predictions of macroscopic electric conductivity. Using practical modeling parameters, the parallel conductor model yields the most accurate prediction of pore-scale sample conductivity for various cases of water saturation and conductivity.