The assessment of caprock sealing capability is a crucial component for the safety evaluation of geological carbon storage. This study imaged and modelled acid-rock interactions in a mudstone utilising time-lapse X-ray 3D imaging techniques and direct simulation at micro-scale, providing a unique perspective to comprehend the reality and predict the outcome of this topic. Different acid concentrations were used to mimic a range of possible acid concentrations during CO₂ injection and storage. Changes observed in samples subjected to acid interaction include initial closure of pre-existing fractures, followed by growth of existing-fractures and slight sample swelling. Due to the heterogeneity of mudstone, acid migration and dissolution followed preferential pathways such as along laminations or fractures. The reactive transport models demonstrate that the majority of dissolution occurs in close proximity to the inlet, while downstream of the fracture, primarily owing to the reduction of H⁺ concentration along the fluid pathways. The distribution of dissolved areas is primarily controlled by carbonate distribution within the sample. Carbonates located near fractures dissolved first and contribute to the connection of individual fractures. Both the experimental and numerical data indicate that calcite dissolution rate and dissolution front migration rate decrease with time. Numerical results demonstrate a significant decrease in shear stress after acid injection, especially with low-pH acids, resulting in slower fluid flow behaviour. Consequently, the mobile and immobile zones of fluid flow were predicted based on image and modelling results. The acid moved slowly and stayed longer in immobile zones, leading to more extensive calcite dissolution than in mobile zones. The study of fluid-rock interaction provides a valuable analogue for predicting the microstructural changes that may occur in a caprock after CO₂ injection. It is worth noting that the risk of leakage is likely exacerbated by the development of fractures induced by acidic interaction.

How to cite: Hao, J., Ma, L., Shende, T., Hollis, C., and Taylor, K.: 4D visualisation and analysis of fluid-rock interactions in a caprock for the implication of carbon sequestration and storage, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-2031, https://doi.org/10.5194/egusphere-egu24-2031, 2024.

Understanding the deformation behavior of mudstones induced by gas invasion is important to discuss the mechanical response of cap rock for geological sequestration of carbon dioxide (CO₂), especially for evaluating possible CO₂ leakage through cap rock. In this study, gas injection experiments were conducted by using a water-saturated mudstone core sample under relatively low excess gas pressure conditions, and the observed strain behaviors were compared between experiments with and without continuous gas invasion to identify characteristic deformation signals associated with gas invasion. In the experiments, the lateral surface of the sample was sealed with silicone rubber, then, the confining pressure was maintained to be 0.50 MPa and the pore water pressure to be 0.20 MPa as an initial condition. The air pressure was applied at the bottom of the sample, and was increased stepwise from 0.25 to 0.40 MPa with 0.05 MPa increments. Each condition was kept until a steady-state condition was achieved. Axial and circumferential strains at half the height of the sample were monitored using four cross gauges, and water discharge at the sample top was also observed. The measured water discharge indicated a very small amount of air invasion at the bottom air pressures of 0.25, 0.30, and 0.35 MPa, with eventual cessation of invasion. Notably, at 0.35 MPa, gas invasion persisted for a longer duration compared to the other two pressure conditions. At 0.40 MPa, the water discharge increased, and air breakthrough was observed. The measured cumulative water discharge at air breakthrough divided by the sample pore volume was 1%, indicating very limited air pathways in the sample. Under the condition that the bottom air pressure was 0.30 MPa or less, the measured strains showed initial possible poroelastic induced axial contraction and gradual extension, followed by gradual contraction, reaching to a steady-state condition. In the case where the bottom air pressure was 0.35 MPa or higher, early-stage strain behavior was similar, however, from the middle stage of the contraction phase, the strains showed a number of episodic sudden extensions and subsequent gradual contractions. Furthermore, the magnitude of the extensions differed significantly from gauge to gauge, and two of the gauges showed no extension. The observed localized episodic strain behaviors are attributed to air migration through limited pathways. When air invaded into part of the pore network filled with water, pore water pressure increased locally nearby the invaded pore, which should be close to the capillary pressure of the invaded pore. Strain gauges closer to the invaded pore then showed sudden extension and subsequent gradual contraction due to pore water pressure diffusion, while no strain was detected by other gauges located far from the invaded pore. The localized episodic sudden extensions followed by gradual contractions observed in our study strongly suggest very limited pathways for gas breakthrough in mudstones.

How to cite: Goto, H., Tokunaga, T., and Aichi, M.: Localized episodic deformation events in mudstone suggest limited pathways for gas breakthrough, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13837, https://doi.org/10.5194/egusphere-egu24-13837, 2024.

How to cite: van Noort, R. and Svenningsen, G.: Impact of CO2 with impurities on integrity of wellbore cements during CCS , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-15010, https://doi.org/10.5194/egusphere-egu24-15010, 2024.

This work describes key aspects of the methodology for subsurface characterization of Late Miocene deep marine sedimentary systems of the Gulf of Cádiz. In particular, we focus on the products of alongslope bottom currents processes, known as contourite systems, and mixed deposits developed by the interaction between contourite and downslope turbidite systems. Both these systems offer prospects for CO2 storage for their high reservoir potentials. In addition, hemipelagic sediments and fine-grained contourites present in the area could act as seals. The objective of this study consists of using seismic attributes and machine learning techniques for conducting a seismic facies analysis to distinguish between various Late Miocene deep marine deposits in a 3D seismic volume. The first step is to restrict the dataset to the deposits of interest in order to avoid irrelevant sediments or structures such as the allochthonous unit of the Gulf of Cádiz or salt domes or diapirs. This adjusts the dynamic range of the clustering to focus on our targets. The second step is the testing of the seismic attributes to improve their selection criteria, in order to maximize the differences between the distinct seismic facies. Finally, we apply an unsupervised clustering algorithm for the selected seismic attributes to perform an automatic seismic facies analysis that facilitates both reservoir and seal imaging. This study will ultimately help to assess the socio-economic impact of Late Miocene sediments developed by bottom currents on climate change mitigation and energy transition. This research and the Grant PRE2022-102745 were funded by MCIN/ AEI/10.13039/501100011033 and they are linked to the ALGEMAR project (PID2021-123825OB-I00). This work is partly supported by SEASTORAGE project (TED2021-129816B-I00), funded by MCIN/ AEI/10.13039/501100011033/PRTR-C21 and by the European Union NextGenerationEU.

How to cite: Feyzullayev, T., Lubo-Robles, D., Benjumea, B., Bedle, H., Llave, E., Javier Hernández-Molina, F., and Lin Ng, Z.: Reservoir and seal characterization of deep marine sediments using seismic facies analysis with machine learning techniques, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-17893, https://doi.org/10.5194/egusphere-egu24-17893, 2024.

Biomineralization, through microbially, thermally, or enzyme induced carbonate precipitation (MICP/TICP/EICP), is a cost-effective cementation process for changing porosity and permeability in the subsurface. This study aims to optimize compositional and injection parameters for biomineralization fluids, and to develop understanding of the interactions between geochemical reactions and fluid transport properties at the pore (micron) scale. Utilizing real-time in situ X-ray computed tomography (XCT), we compare traditional Microbially Induced Calcium Carbonate Precipitation (MICP) with novel thermally delayed (TICP) and Enzyme Induced Calcium Carbonate Precipitation (EICP) in a range of lithologies. This allows us to investigate the impact of mineralogy, grain size distribution, and temperature as well as the injection composition and strategy. We present quantitative analysis of crystal locations, the volume of carbonate and of individual crystals, and the effect of crystals on permeability and flow localisation over time. Coupled to measured changes in microstructural and macroscopic properties over repeated precipitation and dissolution cycles we present refined models of reactive transport for different injection strategies, and identify the optimal treatment strategy for different subsurface applications. This includes validation of the durability of precipitated calcite seals during dissolution phase, simulating the behaviour of CO2-enriched brines.

This work provides the underpinning understanding principles of crystal formation, growth and hydrodynamic feedback mechanisms necessary for accurate modelling of reservoir scale dynamic processes.  However, we also show how TICP and EICP strategies can improve performance of real-world Carbon Capture and Storage systems, driving more homogeneous, widely distributed and larger volumes of precipitated CaCO3 by maintaining permeability during treatment at higher degrees of cementation when compared to MICP. We also show how variable injection strategies allow improvement of other physical properties (e.g. mechanical strength) and enables the addition of highly conductive additives or phase change materials without reducing precipitation and flow. Using CaCO3 precipitation we observed a 470% increase in the thermal conductivity of unsaturated quartz sand after 9 cycles of MICP, and an 800% increase following addition of 5 wt% expanded natural graphite (ENG). Our findings also demonstrate the compatibility of integrating paraffin as a phase-change material within the porous matrix of ENG prior to MICP/EICP treatment significantly increasing specific heat capacity. These new geomaterials have widespread implications for thermal energy storage, specialized geothermal grouts/backfill, shallower wells and reduced geothermal energy costs.

The project's outcomes impact the commercialization of engineered biomineralization and its role in the subsurface energy transition.

How to cite: Salter, P., Dobson, K., Minto, J., and Warnett, J.: Exploiting induced carbonate precipitation to improve reservoir storage integrity and geothermal system efficiency, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-18106, https://doi.org/10.5194/egusphere-egu24-18106, 2024.

The North Sea plays a strategic role in the transition towards the green economy, as it hosts many offshore wind farms and carbon capture and storage (CCS) sites. The North Sea is characterized by moderate seismicity. For example, the 2023 Mw 5.1 North Sea earthquake was the largest earthquake in the region in 33 years, and led to a temporary shutdown of production of Equinor’s oil platform Snorre B.

The last comprehensive seismic hazard assessment of the North Sea was performed about twenty years ago (Bungum et al. 2000). Since then, there have been many new ground motions recorded from both onshore and offshore seismic stations in the North Sea region, as well as major advancements in probabilistic seismic hazard assessment (PSHA) methodology. As a result, this study aims to develop the first region-specific ground-motion model for the North Sea, which will be used in an updated PSHA to ensure the safe design of new offshore wind farms and CCS sites.

This research forms a part of the SHARP-Storage project, an interdisciplinary Accelerating CCS Technologies project developing improved methods for quantitative assessment of subsurface CO₂ storage containment risks. The SHARP project compiled a dataset of North Sea ground-motion records, which comprises data on natural seismicity from broadband seismometers, both onshore and offshore. Moreover, synthetic ground motions are generated to address the paucity of recordings (especially strong motions) in the North Sea region. The associated flat-file, including the metadata and intensity measures (e.g., spectral acceleration and Fourier amplitude) of manually processed waveforms is constructed for the analysis of the ground motion characteristics in the North Sea. An empirical ground-motion model is developed based on the recorded and synthetic data, which is validated and compared with the available observations and models for the North Sea.

The ground-motion model is defined for a reference rock condition. Amplification factors to estimate shaking at the soil surface are derived based on a database of one-dimensional site response analyses. The sediments encountered in the North Sea have been deposited in dynamically changing environments ranging from arctic to temperate and reworked by the movement of ice sheets. As a result, a wide range of soil types and properties are found. To capture this variability, representative profiles are developed based on site investigations from locations with different soil conditions encountered in the North Sea. One dimensional non-linear site response analyses are then performed using the recorded and synthetic ground motion database to generate a database of response spectra amplification values.

This study presents the preliminary results of the North Sea ground-motion model and highlights the challenges in conducting PSHA for the North Sea region. These results improve the assessment of seismic hazard and risks to CO₂ storage security in the North Sea.

How to cite: Huang, C., Carlton, B., Kettlety, T., Larsen, T., Kendall, J. M., and Skurveit, E.: Reevaluating seismic hazard and ground motions for North Sea CO2 storage projects, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-14723, https://doi.org/10.5194/egusphere-egu24-14723, 2024.

Carbon capture and storage (CCS) has emerged as a principal emissions reduction technology for the energy transition. Its effectiveness hinges largely on the security of the storage reservoir, which may be susceptible to leakage through permeable pathways such as abandoned wells and faults. Storage failure presents risks of environmental impacts, increases in atmospheric carbon emissions, reduces both the value of carbon credits and public confidence in CCS as a viable technology for the energy transition. Given the importance of storage security, our understanding of CO₂ leakage and its fate and transport in overburden must be improved to help in the prediction, detection and assessment of leaks. Shallow groundwater monitoring for dissolved gases can be complicated by multicomponent mass transfer dynamics in the subsurface. As CO₂ migrates through the subsurface, much of the mass will partition from the gaseous to the aqueous phase, and conversely background dissolved gases present in groundwater such as N₂ and O₂ may partition to the gaseous phase, impacting both the evolution of dissolved gas concentrations and the persistence of free-phase gas in the subsurface. This process may also impact the performance of noble gas tracers in groundwater monitoring techniques. There is therefore a need for numerical models capable of accurately predicting the fate and transport of CO₂ in the subsurface. However, traditional multiphase flow models struggle to describe the buoyant unstable gas flow regime expected at leak sites, dominated by gravity and capillary forces.

Unstable gas flow is characterized by discontinuous gas clusters and sharp variations in gas saturations in space, in contrast with the smooth variation in gas saturation predicted by continuum multiphase flow models. Discrete approaches such as macroscopic invasion percolation (MIP) are better equipped to model unstable gas flow, however they are limited by assumptions of instantaneous gas movement. ET-MIP (Electro-thermal MIP) is a general purpose model which couples continuum-based electrical, thermal, groundwater and chemical species modules with a discrete MIP gas flow module. This coupled approach allows for accurate simulation of slow gas displacement characteristic of shallow subsurface gas releases while simultaneously predicting the dissolution of CO₂. ET-MIP has been validated against bench scale experiments and shown to accurately predict gas generation, multiphase transport and capillary trapping – all mechanisms which govern the fate of CO₂ in the subsurface. This talk will present comparison of ET-MIP with a bench-scale CO₂ injection and dissolution experiment and a sensitivity study showing the effects of key model parameters on CO₂ migration. Findings highlight the benefits of using a discrete-continuum coupled approach for simulating CO₂ migration in porous media, and the importance of considering background dissolved gases in the subsurface.

How to cite: Ashmore, N., Molnar, I., Gilfillan, S., and Krol, M.: A coupled discrete-continuum approach to simulating CO2 migration and dissolution in porous media , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-10197, https://doi.org/10.5194/egusphere-egu24-10197, 2024.

The majority of pathways toward net-zero CO₂ emissions propose carbon capture and storage (CCS) at rates of several gigatonnes per year by mid-century. However, there are limits on the rates at which storage resources can be used. In addition to the total storage resource, constraints are imposed by reservoir injectivity and the possibility of triggering large earthquakes by injection-induced overpressure. Such dynamic constraints are rarely considered in the assessments of available resources and possible CCS deployment rates. In this work, we have extended an open-source tool, named CO2BLOCK, from calculating reservoir pressurization during CO₂ injection to additionally estimating the probability of fault slip in the region. This provides a computationally efficient methodology for screening dynamic CO₂ storage resources. The code features a deterministic hydrogeology module that employs analytical solutions of radial, multiphase flow for a single site with time-varying injection rates and the superposition principle to calculate the spatiotemporal evolution of pore pressure in multisite, basin-scale injection scenarios. The calculated overpressure is used to analyze the slip tendency of the faults imported or randomly distributed across the basin. A probabilistic geomechanical module runs Monte-Carlo simulations to generate cumulative distribution functions of slip probability as a function of pore pressure changes for each fault from statistical ensembles of uncertain parameters including the state of stress and fault attributes and frictional strength. A combination of the two modules yields the evolution of fault slip probability as a function of time through the project life. The proposed approach allows for optimizing large-scale CCS project designs for the number and spacing of injection sites to return maximum storage rates and capacities while maintaining the risk of induced seismicity at a low level. The application of CO2BLOCK could assist in developing more realistic representations of CCS scale-up potential and the subsurface resource use in different climate change mitigation pathways. 

How to cite: Kivi, I. R., De Simone, S., and Krevor, S.: An analytical tool for estimating fault slip probability for CO2 storage resources under pressure constraints , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-18221, https://doi.org/10.5194/egusphere-egu24-18221, 2024.

After decades of research on geologic carbon storage (GCS), the world seems to be moving from pilot tests and demonstration experiments to industrial-scale implementation. In the United States, the Bipartisan Infrastructure Law passed in 2021 contributes $2.5 billion for carbon storage commercialization in addition to similarly large investments in point-source carbon capture as well as direct air capture. These federal investments, combined with new tax credits provided by the 2022 Inflation Reduction Act, provide a significant push towards GCS deployment over the coming years and decades, likely creating multiple large storage projects or clusters of integrated projects across hydrogeologic basins. These projects will likely involve injection volumes that may result in large-scale pressure increases in the subsurface and may cause unwanted geomechanical effects, such as generating seismic events and seal integrity concerns per reactivation of critically stressed faults.

Here, we will focus on such large-scale deployment hurdles and discuss related regulatory challenges, using the United States permitting framework as an example. We will begin by illustrating basin-scale pressure impacts expected from geologic carbon sequestration at scale, based on regional modeling studies of future GCS scenarios. With regards to geomechanical implications, we will briefly present lessons learned from two recent field tests—one being a controlled fluid (water and CO₂) injection fault slip and leakage experiment in a clay (sealing) formation, the other a CO₂ storage demonstration site where micro-seismicity has occurred along pre-existing basement faults. We will then introduce ongoing work to transfer the knowledge derived from these experiments to larger injection volumes and scales so that ultimately geomechanical effects can be assessed and coordinated at the scale of large storage complexes. In terms of regulatory implications, we will review the regulatory framework for CO₂ storage wells in the United States and discuss how suitable it is (or not) for permitting a GCS future where sedimentary basins with interconnected reservoirs might host multiple large storage projects. Lastly, we will propose a hierarchical permitting approach for such situations, which would add a general permit for regional coordination of subsurface resources to the existing framework for permitting of individual CO₂ storage projects.

How to cite: Birkholzer, J., Guglielmi, Y., Cihan, A., Rutqvist, J., Glubokovskikh, S., Reagan, M., Jordan, P., Mital, U., Cao, M., and Tounsi, H.: Managing Large-Scale Geologic Storage of CO2 in the United States: Geomechanical Impacts, Basin-Scale Coordination, and Regulatory Implications, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-3599, https://doi.org/10.5194/egusphere-egu24-3599, 2024.

Depleted oil and gas formations and associated wells can be exploited for use as energy or carbon dioxide storage infrastructure. However, a loss of wellbore integrity can result in the uncontrolled migration of fluids out of the well, risking groundwater contamination and releasing greenhouse gases (e.g., methane, carbon dioxide, hydrogen) into the atmosphere. In Canada, emissions specifically related to wellbore integrity and subsurface-based leakage have been monitored, measured, and reported by the oil and gas industry for more than a decade, resulting in some of the largest datasets to track such wellbore emissions. While these reporting systems were not necessarily designed to track methane emissions, both the provincial and federal governments nevertheless use these data to estimate methane emissions associated with subsurface wellbore leakage.  Moreover, incomplete reporting by the industry has resulted in highly uncertain methane emission magnitudes, and attempts by federal and provincial governments to resolve these issues yield emission estimates varying by more than a factor of two. Further, poorly understood emission mechanisms are likely to yield even more uncertainty in total emissions from wellbore leakage.

In this presentation, we illustrate the highly uncertain nature of methane emissions due to subsurface wellbore leakage in Canada using industry-reported data for the provinces of Alberta and British Columbia, regions covering more than 80% of crude oil and 95% of natural gas production nationally. We illustrate the sensitivity of these methane emission estimates using a variety of assumptions employed by the different governments for incomplete data, highlighting the key knowledge gaps for this source of emission. The different assumptions result in estimates varying by a factor of 3, and more troublingly, connotate fundamentally different understandings about wellbore leakage causes, sources of fluid, and progression of emission rates over time. We make initial recommendations for wellbore leakage monitoring and measurements to improve Canada’s methane quantification but with more broad applicability for monitoring well fluid leakage more generally.

How to cite: Seymour, S., Xie, D., and Kang, M.: Oil and gas wellbore leakage in Canada: key reporting uncertainties and measurement knowledge gaps, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-205, https://doi.org/10.5194/egusphere-egu24-205, 2024.

To achieve a carbon-free economy in the medium term, hydrogen has been proposed as a viable solution. This requires large-scale subsurface storage options, especially, if green hydrogen produced from fluctuating renewable energy sources like wind and solar energy is considered. While H₂ has already been stored successfully in salt caverns for decades, H₂ storage in porous media like hydrocarbon-depleted reservoirs and saline aquifers still requires further research. We use an almost depleted gas reservoir in northwestern Germany to test various scenarios regarding withdrawal/injection cycles and different cushion gases. The case study field presents a faulted reservoir in a highly fractured rock of Upper Permian (Zechstein) age, consisting mainly of dolomite as reservoir rock and anhydrite as cap rock. A history-matched dynamic model starting in 1959 of a gas-depleted reservoir calibrated from the comprehensive information available for the reservoir site, such as density, viscosity, relative permeability, and capillary pressure, which serves as a hypothetical base case for seasonal hydrogen storage, intending to store around 300 Mio sm³. An isothermal compositional reservoir simulator with seven components is used including H₂S to monitor its concentration. Eight prediction cases were simulated, excluding: diffusion, dispersion, and microbial reaction. Between each case, changes are made to the type and amount of cushion gas injected following the same injection/withdrawal cycle, mixing the cushion gas between N₂+CH₄, H₂+N₂, H₂+CH₄, H₂+CO₂, pure CH₄, pure CO₂, pure N₂, and pure H₂. Following an initial filling from only the cushion gas of 33-months of around 730000 (sm³/d). Immediately after, withdrawal begins for 2 months from the working gas of around 3600000 (sm³/d) and withdrawal/injection cycles for 3(W)/6(I) months were the amount of working gas injected increases to 1800000 (sm³/d), and with a shut-down phase for 1 month after withdrawal and 2 months after injection, for 7 times; resulting in a total H₂ production over 8 cycles. The applied amounts were to avoid any spilling due to the highly-fracture nature of the reservoir. In a subsequent simulation from the case of using pure N₂, the prediction time was increased to observe its changes over the next 7 years. To assess the overall recovery of hydrogen and the concentration of H₂S, a volumetric and molar storage balance was analyzed. Based on the results of all the 8 simulations, at least on the first four cycles, less H₂ is recovered, except if pure H₂ is injected from the beginning as a filling phase. Despite this, all simulations show a greater H₂ recovery for the last cycle, from 96% (pure N₂ as cushion gas) to 99% (pure H₂ as cushion gas). Regarding H₂S, shows a diluted concentration while the storage cycles are increased, resulting lower than 2x10^-5 mole fraction for the last cycle. A longer time prediction reveals that H₂ recovery for the last cycle can nearly reach 100%. The next steps involve realizing a thermal simulation for the observation of the temperature effect and how can it effect the storage process, and a preliminary economic study of the storage site to determine its feasibility.

How to cite: von Reinicke Laredo, D. A.: Reservoir simulation studies in underground hydrogen storage in a depleted gas reservoir - northwestern Germany, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-18645, https://doi.org/10.5194/egusphere-egu24-18645, 2024.

Hydrogen (H₂) is a clean source of energy and a promising solution in the energy transition due to its vast energy content and potential of zero greenhouse gas emissions. Storing hydrogen to meet present and future energy demands requires a large storage volume which is only available in subsurface reservoirs such as salt caverns, depleted oil and gas fields, and deep saline aquifers. Despite the high demand for Underground Hydrogen Storage (UHS) technology as part of a full H₂-value chain, there is especially limited knowledge of the transport behavior of hydrogen in porous media [1]. With its charging and discharging operations, the storage of hydrogen in a porous reservoir formation undergoes a transient flow process, influenced by coupled thermo-hydro-mechanical processes between hydrogen, the formation fluid, the solid components of the rock, and the prevailing temperature and pressure regime, which repetitively changes under geotechnical utilization [2]. In consequence of cyclic storage operations, variations in effective mechanical stresses can affect the pore space geometry and may lead to irreversible deformation and weakening of reservoir and cap rocks.
Here, we present first results of an experimental laboratory study focussing on fluid substitution experiments (gas replacing brine) on various sandstone core samples sourced from Bad Bentheim and the Stuttgart formation. The study was specifically designed to replicate the unique reservoir conditions of the Stuttgart formation at the Ketzin site in Germany (confining pressure = 150 bar, pore pressure = 25 to 75 bar, temperature = 37 °C). In the frame of the national-funded GEOZeit project, long-term flow experiments are carried out to determine  the evolution of relative permeability of H₂-brine and CH₄-brine systems in dependence of the number of load cycles. Alongside, measurements of electrical resistivity and ultrasonic wave velocities at each brine/gas saturation state are performed. This enable us to derive the saturation level and to understand the spatial distribution of liquid and gaseous phases in the pore space of our sample material. The experiments are complemented by a range of additional tests, including chemical analyses and microstructural investigations using XRD, SEM, and optical microscopy. Our results are expected to improve the understanding of coupled hydromechanical processes and their impact on reservoir properties during geotechnical operations, and to also provide the necessary parameters for large-scale modelling and up-scaling, required to assess the feasibility of storage, production, and monitoring of hydrogen gas in porous geological formations.

[1] Heinemann, N., Alcalde, J., Miocic, J. M., Hangx, S. J. T., Kallmeyer, J., Ostertag-Henning, C., Strobel, G. J., Hassanpouryouzbanda, A., Schmidt-Hattenberger, C., Edlmann, K., Wilkinson, M., Thaysen, E. M., Bentham, M., Haszeldine, R. S., Carbonell, R., Rudloff, A. (2021). Enabling large-scale hydrogen storage in porous media – The scientific challenges. Energy & Environmental Science, 14(2), 853–864. https://doi.org/10.1039/D0EE03536J


[2] Ershadnia, R., Singh, M., Mahmoodpour, S., Meyal, A., Moeini, F., Hosseini, S. A., Sturmer, D. M., Rasoulzadeh, M., Dai, Z., Soltanian, M. R. (2023). Impact of geological and operational conditions on underground hydrogen storage. International Journal of Hydrogen Energy, 48 (4), 1450-1471. https://doi.org/10.1016/j.ijhydene.2022.09.208.

How to cite: David, W., Kummerow, J., Singh, M., Schmidt-Hattenberger, C., and Sass, I.: Experimental investigation of hydrogen flow behavior in porous media at reservoir conditions., EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-18771, https://doi.org/10.5194/egusphere-egu24-18771, 2024.

Large-scale H₂ storage within porous geological formations – such as depleted hydrocarbon reservoirs – presents a practical opportunity leveraging existing energy industry infrastructure to address renewable energy intermittency (e.g., from wind and solar). H₂ can be generated from excess renewable energy, stored in these reservoirs, and drawn when needed. Depleted gas reservoirs have proven to trap gases (e.g., natural CH₄) over geological timescales, and have been used for large-scale CH₄ storage. The working gas (i.e., H₂) is the fraction that is injected, stored temporarily, and produced from the reservoir. The cushion gas, the share of the injected gas that remains in the reservoir to maintain operational pressures and drive the production, represents an initial investment in the storage operation. Therefore, because H₂ is relatively expensive, the use of a cheaper alternative cushion gas – such as CO₂ and / or in-situ CH₄ – can reduce the investments needed. Furthermore, the use of CO₂ storage can simultaneously contribute to Net-Zero goals (as the CO₂ will remain fixed in the reservoir).

One of the main challenges associated with the use of alternative cushion gases in these storage systems is the mixing with the working gas. Increased mixing will increase the cost of separation after production. In this study, we explore how the mixing of cushion and working gas can be minimised by using the reservoir geometry of laterally extensive reservoirs such as the Southern North Sea gas fields. Ultimately, the reservoir architecture and the infrastructure will dictate the extend of the contact area between the cushion and working gases, and by reducing this, the risk of mixing will be reduced. This work proposes an alternative operational strategy that investigates the storage of H₂ working gas and CO₂ cushion gas in a depleted system, where both gases are kept separated by injecting them at opposing ends of a reservoir to reduce the surface area of the mixing gas interface.

How to cite: Williams, H., Heinemann, N., Molnar, I., Veloso, F., Boardman, C., Gladding, T., and Rashwan, T.: Exploring Hydrogen Storage Strategies in Geological Formations to Minimise Gas Mixing, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-982, https://doi.org/10.5194/egusphere-egu24-982, 2024.

Underground hydrogen storage (UHS) is proposed as a carbon-free energy source derived from renewable solar and wind energies. Deep saline aquifers are proposed for UHS since can potentially contribute to large-scale renewable energy storage, providing high storage capacities required to buffer seasonal energy demands. The caprock plays an important role in the sealing capacity for safe and effective UHS. The geochemical reactions involved in H₂-saline groundwater-rock interaction are significant for the integrity of the caprock as these processes directly determine the sealing capacity during UHS.

Aqueous H₂ could react with minerals and trigger redox and dissolution/precipitation reactions, which may affect the permeability and porosity of the caprock. The resulting changes reactivate or propagate microfractures and, consequently, affect the integrity of the caprock and the long-term storage stability. UHS in formations with sulfate-rich groundwater can induce an increase in pH due to sulfate reduction (i.e., SO₄^2- + 4H₂ = HS^- + 3H₂O + OH^-). The main goal of this work is to study the effect of the increase in pH (HS^--rich water) on a marly limestone caprock.

The PHREEQC code and the phreeqc.dat database were used to simulate equilibrium of H₂ (at any pressure in a range between 1 and 100 bar) with a saline solution in equilibrium with calcite and gypsum at 60 °C. The thermodynamic calculations show that H₂ reduces sulfate and that the pH increases from 8.2 to 11.1. This high alkaline water could, therefore, affect the integrity of the caprock. We tried to prove the model results (sulfate reduction and pH increase) in a batch experiment. A saline water rich in sulfate was put in equilibrium with H₂ at 3 bars. After a week, however, the pH did not increase, suggesting that the short-term sulfate reduction does not occur in the absence of sulfate-reducing microorganisms.

A column experiment was carried out to observe potential changes in the marly limestone in contact with an alkaline (pH ≈ 12), HS^--rich solution at 60 °C. Circulation of the solution led to a release of Si and Al, i.e., dissolution of quartz and aluminosilicates. After 380 h, an increase in the flow rate (from 0.01 to 0.03 mL min^-1) resulted in a decrease in the concentrations of Si and Al, suggesting a far-from-equilibrium dissolution of the silicates (SI_quartz = -2.8; SI_albite = -5.9 and SI_illite = -10.6) although the solution was supersaturated with respect to chlorite (SI_chlorite = 5-12). The dissolution of silicates at highly alkaline (pH ≈ 12) may result in a variation of the initial properties of the UHS caprock (e.g. porosity, permeability). Numerical and experimental results of ongoing column experiments will help reveal the extent of the rock alteration.

How to cite: Ceballos, E., Cama, J., and Soler, J. M.: Reactivity of a marly-limestone caprock in contact with an alkaline HS--rich solution: application to hydrogen storage in a saline aquifer, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-2537, https://doi.org/10.5194/egusphere-egu24-2537, 2024.

Underground storage of green hydrogen in depleted gas fields could provide Aotearoa New Zealand (ANZ) with a storage option critical for meeting peak energy demands and realising green hydrogen ambitions. During early de-risking of specific sites, it is important to develop an accurate geological model to test whether the reservoir has the desired containment, volume and hydrogen deliverability. However, where seismic reflection lines and well data are limited and/or the storage system is structurally complex, the resulting geological models may be non-unique. Therefore, injection and withdrawal simulations using different structural end members is critical to constrain how a hydrogen plume may flow within (and out of) the container and interact with existing reservoir fluids.

Here we present workflows for modelling a multi-year injection and withdrawal cycle of hydrogen into a depleted gas field. We use data from the Tariki Sandstone Member of the Ahuroa field in the Taranaki Basin, currently used to store natural gas in ANZ. This reservoir is located 2 km deep at the crest of an anticline above a major thrust fault, with marine mudstones forming the top seal and low-permeability fault rock the lateral seal. With only mixed quality 2D seismic reflection lines and a tight well cluster, the precise geometry of the thrust fault and its relations to smaller secondary faults is poorly constrained.

To capture this uncertainty in our simulations, we have developed two 3D geological models of the Ahuroa field in Leapfrog Energy software. We use these geological models to conduct dynamic simulation of hydrogen injection and withdrawal using the massively-parallel simulator PFLOTRAN-OGS. We develop simulations that allow us to, over a 10-year cycle, test for closure or spill into adjacent fields, and predict the amount of mixing with remnant natural gas and formation water. During the simulations, we see major differences between the two geological models related to cushion injection and working H₂ volumes, rates of water production and impurities due to natural gas. Additionally, one model has high risks of unrecoverable H₂ gas loss when over-pressurised. Finally, we reimport the results back into Leapfrog for visualisation of the behaviour of the two hydrogen plumes over time.

How to cite: Parker, M., Dempsey, D., Liu, J., and Nicol, A.: Geological modelling and reservoir simulation workflows for hydrogen geostorage in depleted gas fields, Aotearoa New Zealand, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-1927, https://doi.org/10.5194/egusphere-egu24-1927, 2024.

Large scale storage of hydrogen in porous reservoirs can buffer intermittent energy supply and demand in energy systems with large contributions of wind and solar energy. The efficiency of long term injection and withdrawal of hydrogen streams with large concentrations of hydrogen can be particularly affected by the long term interaction between hydrogen and rock or well materials in combination with cyclic pressure, temperature and stress changes during injection and withdrawal. Critical elements of hydrogen storage systems that may be affected are (1) the hydrogen gas stream, (2) the storage reservoir, (3) the caprock, (4) faults, (5) the well system, and (6) the surface environment. In particular, effects on the durability and integrity of well systems and on the mechanical and flow properties of porous sandstone reservoirs may impact the efficiency of storage operations. In this study, we show how results of laboratory experiments on rock and well materials at high pressure and temperature conditions can be used to assess effects of hydrogen exposure and cyclic pressure, temperature and stress changes on well systems and porous sandstone storage reservoirs. Key results of experiments on well cement (Portland type G), sandstone reservoirs, caprock and a scaled-down well system consisting of a casing, well cement and reservoir rock are reported. Samples were placed under relevant high pressure, temperature and stress conditions (100-200 bar, 50-100°C), both in an autoclave for reaction with H­₂ and N₂ and in a triaxial cell for testing injection/withdrawal scenarios. The results show (1) no major effects of H₂ exposure or cyclic loading on mechanical properties of well cement and reservoir sandstone under investigated conditions, (2) different behavior for sandstones exposed to N₂ (stiffer) and H₂ (less stiff) during cyclic loading, (3) some cumulative plastic deformation during cyclic loading of sandstone that may affect flow and mechanical properties, even in the elastic regime, (4) indications of increasing stiffness in caprock due to cyclic loading, (5) importance of casing-cement-reservoir interfaces as potential leakage pathways for hydrogen along wells, and (6) large effects of sample variations that complicate disentangling effects of N₂/H₂ exposure and cyclic loading. These results suggest that effects of interaction between hydrogen and rock or well materials in combination with cyclic pressure, temperature and stress changes during injection and withdrawal are limited for the investigated materials and conditions. However, they also emphasize the need for further research to understand the long-term effects of H₂ exposure and cyclic loading in different geological settings and under extended exposure durations.

How to cite: ter Heege, J., Corina, A., Soustelle, V., and Groenenberg, R.: Durability and integrity of well and rock materials for large scale underground hydrogen storage projects in porous reservoir: Insights from laboratory experiments, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-19609, https://doi.org/10.5194/egusphere-egu24-19609, 2024.

The use of hydrogen as an energy carrier will require effective storage solutions, and depleted hydrocarbon reservoirs offer a safer and cheaper large-scale option compared to other possibilities. The selection of a site for underground hydrogen storage (UHS) entails considerable responsibilities and expenses, and specific tools should be employed to facilitate and optimize the decision process. Thus, a site-screening method was developed to rank depleted and almost depleted hydrocarbon reservoirs for UHS, with subsequent testing on a confidential dataset of 48 production sites from Italy provided by Eni. A set of 27 screening parameters was selected from a wider dataset and a weight for each one was defined by reproducing the Analytic Hierarchy Process (AHP) in Microsoft Excel and gathering expert judgements from both academic and industry following the Delphi technique. This was performed from the points of view of HSE (health, safety, and environment), geotechnical performance (GP) and economic performance (EP), dividing the individual parameters among these three supergroups and normalizing the diverse kinds of dataset records to be used in the calculation procedure. The method resulted in three preliminary rankings based on the sites’ HSE, GP and EP scores and a comprehensive ranking obtained through the aggregation of these three scores for each site, with penalties applied if specific, adverse features exist for UHS purposes. For sites with incomplete data, an estimation of the potential score was derived based on average values calculated from the dataset and attached as additional information to the screening scores without affecting the ranking. The AHP results highlighted a major role for Faulting Description, Mineralization Type, Onshore/Offshore, Wells Number, Reservoir Architecture, Datum Depth and Initial Pressure at Datum, even though other factors made significant contributions. The result consists of a set of scores ranging from 29 to 72 out of 100. To assess the reliability of the method, two blind tests were conducted on a minor proprietary dataset containing well-known sites from North Africa, the first involving a subset of the sites and the second using all sites. The results yielded a good match with the existing ranking performed by Eni. The developed method can be adjusted for a variety of decision-making scenarios, to accommodate changes in the screening purposes or advancements in research. In this configuration, it consists of a highly effective tool for an objective and transparent screening of sites for UHS purposes.

How to cite: Ridolfi, R. M., Azzaro, S., Beaubien, S. E., Da Pra, A., Pontiggia, M., and Bigi, S.: Development of a site-screening method for hydrogen storage purposes and its application to an industrial dataset of Italian reservoirs, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-1539, https://doi.org/10.5194/egusphere-egu24-1539, 2024.

The crucial role of hydrogen in future energy systems, particularly in balancing fluctuations in electricity generation, underscores the need for effective storage solutions. For the underground storage of chemical energy carriers such as hydrogen, the underground salt cavern is the sole underground space that has been successfully used as storage facilities. This study explores the potential of underground salt caverns for storing hydrogen. Salt caverns offer advantages such as low investment costs, high sealing potential, and minimal cushion gas requirements. Geological considerations, including a salt top depth of 400-600 m, >95% pure halite, a deposit thickness of 200-300 m, and a diapiric salt bank or internally homogeneous lenses, are necessary for successful cavern exploitation. From a microbial point of view, during the water evaporation process leading to the underground salt cavern formation, small parts of the in-situ brine become trapped in the salt and end up as fluid inclusions, potentially including halophilic microorganisms subsequently freed during the process of solution mining. Autotrophic microbial life is feasible under salt cavern circumstances, especially if a suitable electron donor like H₂ is introduced.

The study focuses on a salt mine in Realmonte, Sicily and explores the geology, geochemistry, geomechanics and microbiology properties of the halite section. The mine, extracting 97% pure rock salt, serves as a natural laboratory for geochemical and geo-mechanical studies. It is characterized by four depositional units. Unit A comprises laminated gray halite (50 m); Unit B (100 m) features massive gray halite with kainite laminae up to 18m thick; Unit C (70-80m), consists of white halite layers separated by dark mud laminae and Unit D (60m) which includes anhydritic mudstone transitioning to an anhydrite laminite sequence. Utilizing well log data and a 3D geological subsurface model, the study reveals a salt bank with an average thickness of 500 m (of which only the upper 220 m b.s.l. is exploited) and defines the top and bottom of the halite subunits. Pore-perm analysis on 28 rock salt and kainite cores, including XRF analysis and Mercury Intrusion Porosity, provides insights into geochemical and porosity characteristics. Pore network model was obtained from the processing and interpretation of the micro-tomographic images collected on 10 rock salt and 1 kainite sample. A hydrogen injection test under varying conditions simulates cyclic storage under both static and dynamic conditions and a geochemical model of the internal conditions of a cavern has been produced using PHREEQC model.

Results indicate limited diffusion under relatively high pressure. Microbiology and the linked geochemistry of two salt cores, both from the Realmonte mine but of different composition, is being investigated. The integrated geochemical, geomechanical, microbiological and experimental data support the feasibility of storing hydrogen in a stratified salt geological context, particularly where pure rock salt and kainite interlayers are present. Finally, we explore the potential for a large-scale project, envisioning coexistence of traditional mining activities up to 200 m b.s.l. and hydrogen storage activities at greater depths (Units B and A) between 300 and 600 m.

How to cite: Anzelmo, G., Iacopini, D., Cella, G. M., Visconti, L., Edlmann, K., Cascone, M., Russo, G., Maniscalco, R., Parente, M., Sabatino, C., Di Benedetto, C., Colella, A., Balassone, G., Cappelletti, P., Cucciniello, C., Pappalardo, L., Di Clemente, E., Perrotta, L., Giovannelli, D., and Simili, M.: Integrated approach for hydrogen storage in a salt mine: the case of Realmonte, Sicily (Italy). , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-9198, https://doi.org/10.5194/egusphere-egu24-9198, 2024.

In order to reach carbon neutrality, a drastic increase in subsurface carbon storage is essential. During the storge site selection process, sites are assessed based on overall security for long-term storage, and any remaining risks require a risk assessment with leakage mitigation plan. With an increase in large scale carbon storage, there is an increased chance of leakage and the potential for contamination of drinking water aquifers above the storage reservoir. In such a scenario, subsurface sweeping via the pumped injection of large volumes of water would be the most suitable method for remediation, yet this comes with issues of tailing and rebound occurring after the treatment has stopped, necessitating the injection of large volumes of water, over long time-scales, which significantly increases both the cost and carbon footprint of the remediation operation. With this study we look at how modified pumping techniques may improve sweeping to minimise rebound, but also how to minimise use of water.

The pumping techniques used in this study were continuous flow and pulsed flow. The pulsed flow was divided into two types, cyclic flow and rapid pulses. Cyclic flow has long breaks and relies on diffusion, whereas rapid pulses rely on vortices created in the pore spaces to increase mixing. The rock types used for the experiments were Clashach sandstone which represented a homogeneous rock, and Wattscliffe Lilac sandstone, representing a heterogeneous rock. The Clashach sandstone is quartz dominated and has a porosity of ca. 24 % with an overall uniform grain size and pore size, as well as well-connected pores. The Wattscliffe Lilac sandstone has a more heterogeneous mineralogy with a porosity of ca. 21 % and varied grain size, pore sizes, and pore connectivity. The different rock types were chosen based on their distinctly different pore structure to aid in understanding how heterogeneity impacts the different flow mechanisms. The cores were prepared at 4 cm long and just under 5 mm wide, covered in heat shrink tubing then cast in resin in order to prevent bypass flow, and optimised for pore-scale XCT imaging at injection pressures of up to 2 MPa. To study the recovery behaviour of the different flow types through the rock cores, fluorescein was used as a tracer and measured in a flow-through fluorometer. The resulting breakthrough curve, tailing, and total recovery was then used to determine which pumped flow method was the most efficient in terms of: 1) remediation of fluorescein, 2) water usage during remediation, and 3) speed of remediation. These different factors of efficiency can be crucial in determining which pumping method is used to remediate a contamination site.

How to cite: Eriksson, S., Minto, J., Edlmann, K., Johnson, G., Roberts, J., and Shipton, Z.: Comparing fluid flow mechanisms in reservoir rocks to improve subsurface pollutant remediation, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13643, https://doi.org/10.5194/egusphere-egu24-13643, 2024.