ERE3.1 | Secure subsurface storage for future energy systems
EDI
Secure subsurface storage for future energy systems
Convener: Johannes Miocic | Co-conveners: Niklas Heinemann, Elina CeballosECSECS, Mayukh TalukdarECSECS, Wenzhuo CaoECSECS
Orals
| Tue, 16 Apr, 08:30–12:27 (CEST)
 
Room 0.96/97
Posters on site
| Attendance Tue, 16 Apr, 16:15–18:00 (CEST) | Display Tue, 16 Apr, 14:00–18:00
 
Hall X4
Orals |
Tue, 08:30
Tue, 16:15
Storage of energy (e.g., hydrogen, heat) and carbon dioxide in subsurface geological formations is of key importance in the transition to a carbon-neutral economy relying on renewables-based power and heat generation. The suitability of subsurface storage sites depends on hydromechanical properties of the reservoir and its confining units, and integrity of seals due to induced thermal, mechanical, hydraulic and chemical changes. Secure subsurface storage, as well as public acceptance of key enabling technologies, requires abundant geological knowledge, routine monitoring and sound evaluation of potential risks. This session offers a platform for interdisciplinary scientific exchanges between different branches of storage expertise, and aims to address challenges concerning the storage of fluids in geological reservoirs from core- to field-scale. This session invites submissions encompassing theoretical analyses, laboratory experiments, numerical modeling and field testing in advancing understanding of multiple physics involved in subsurface storage. Case studies and operational projects integrating different elements of the storage chain, as well as field projects focusing on geological energy/carbon storage, are particularly welcome.

Relevant topics include:
• Regional and local characterization of storage formations, caprocks, and fault structures, and their short- and long-term physical and chemical behaviour during injection and storage operations
• Evaluation of existing infrastructure and fluid injection strategies for effective subsurface storage
• Geophysical, geomechanical and geochemical monitoring and measurements for safe and cost-efficient storage
• Coupling of different energy storage types in a carbon-neutral power system
• Heat exchange systems, including aquifer thermal energy storage systems
• Techno-economics and public perception of energy storage systems


Suitable contributions can address, but are not limited to:
• Field monitoring techniques and fit-for-purpose testing technologies aimed at characterizing storage sites and behaviour of injected fluids
• Laboratory experiments investigating fluid-rock interactions
• Evaluation of caprock and fault stability and wellbore integrity, and associated leakage potential and induced seismicity
• Numerical modelling of migration, containment and geochemical reactions of injected fluids, and injectivity and pressure response of reservoirs

Session assets

Orals: Tue, 16 Apr | Room 0.96/97

Chairpersons: Johannes Miocic, Wenzhuo Cao
08:30–08:35
CO2 storage
08:35–08:45
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EGU24-2031
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ECS
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On-site presentation
Jingyue Hao, Lin Ma, Takshak Shende, Cathy Hollis, and Kevin Taylor

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.

08:45–08:55
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EGU24-13837
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On-site presentation
Hiroki Goto, Tomochika Tokunaga, and Masaatsu Aichi

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.

08:55–09:05
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EGU24-15010
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On-site presentation
Reinier van Noort and Gaute Svenningsen

CO2 injected into geological reservoirs for storage will contain a range of impurities dependent on the specifications of the transport and storage operator(s). Such impurities include inert gases such as N2 and Ar, as well as reactive components including SOx, O2, and H2S. Upon injection into a (wet) reservoir, these components will partition between the CO2-phase and the hydrous pore fluid, and some of the reactive species may introduce acidification (in addition to the acidification caused by the CO2 itself), or other chemical reactions. 

In the near-wellbore area, the partitioning impurities can potentially lead to enrichment of water-soluble impurities in the hydrous fluid and corresponding depletion of these impurities in the CO2 plume. Because of this, even low (ppm-level) concentrations of reactive impurities need to be considered with regards to their potential impact on wellbore sealant integrity. As part of the Cementegrity project, we have performed exposure experiments on five different sealant compositions; three of which are based on Ordinary Portland Cement (OPC), one is based on Calcium-Aluminate Cement (CAC) and one is a granite-based geopolymer (GP). Using a purpose-built batch-exposure system, sample cylinders were exposed to water and supercritical CO2 under simulated downhole conditions of 80°C and 8-10 MPa, for up to 16 weeks. The sealant samples were placed at two different levels in each exposure apparatus, so that samples were either exposed to wet supercritical CO2, or to CO2-saturated water. The effect of H2S in the CO2 stream was studied in a second series of experiments, where 2.2 mol% H2S was added to the CO2-phase to which the samples were exposed.

After exposure, the samples were retrieved and cross-sectioned perpendicular to the axial direction, so that the impact of exposure on sealant microstructure and composition could be studied using scanning electron microscopy (SEM) and energy dispersive X-ray spectroscopy (EDS). In this paper, we will focus on the different impacts of exposure conditions (wet sc. CO2 vs. CO2-saturated water) as well as the additional impact of H2S.

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.

09:05–09:15
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EGU24-17893
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ECS
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On-site presentation
Tural Feyzullayev, David Lubo-Robles, Beatriz Benjumea, Heather Bedle, Estefanía Llave, Francisco Javier Hernández-Molina, and Zhi Lin Ng

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.

09:15–09:25
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EGU24-18106
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ECS
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On-site presentation
Philip Salter, Katherine Dobson, James Minto, and Jay Warnett

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.

09:25–09:35
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EGU24-14723
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ECS
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On-site presentation
Chen Huang, Brian Carlton, Tom Kettlety, Tine Larsen, J. Michael Kendall, and Elin Skurveit

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.

09:35–09:45
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EGU24-10197
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ECS
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On-site presentation
Nicholas Ashmore, Ian Molnar, Stuart Gilfillan, and Magdalena Krol

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.

09:45–09:55
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EGU24-18221
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ECS
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On-site presentation
Iman R. Kivi, Silvia De Simone, and Samuel Krevor

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.

09:55–10:05
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EGU24-3599
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Highlight
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On-site presentation
Jens Birkholzer, Yves Guglielmi, Abdullah Cihan, Jonny Rutqvist, Stanislav Glubokovskikh, Matt Reagan, Preston Jordan, Utkarsh Mital, Meng Cao, and Hafssa Tounsi

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.

General Storage
10:05–10:15
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EGU24-205
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ECS
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On-site presentation
Scott Seymour, Donglai Xie, and Mary Kang

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.

Coffee break
Chairpersons: Niklas Heinemann, Elina Ceballos, Mayukh Talukdar
10:45–10:47
10:47–10:57
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EGU24-18645
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ECS
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On-site presentation
Daniel Andres von Reinicke Laredo

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.

10:57–11:07
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EGU24-18771
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ECS
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On-site presentation
Wisdom David, Juliane Kummerow, Mrityunjay Singh, Conny Schmidt-Hattenberger, and Ingo Sass

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.

11:07–11:17
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EGU24-982
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ECS
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On-site presentation
Harri Williams, Niklas Heinemann, Ian Molnar, Fernanda Veloso, Carl Boardman, Toni Gladding, and Tarek Rashwan

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.

11:17–11:27
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EGU24-2537
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On-site presentation
Elina Ceballos, Jordi Cama, and Josep M. Soler

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., SO42- + 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 (SIquartz = -2.8; SIalbite = -5.9 and SIillite = -10.6) although the solution was supersaturated with respect to chlorite (SIchlorite = 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.

11:27–11:37
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EGU24-1927
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ECS
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On-site presentation
Matt Parker, David Dempsey, Jinjiang Liu, and Andy Nicol

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.

11:37–11:47
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EGU24-10196
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ECS
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On-site presentation
Cyclic Flow Characteristics of Sandstones during Geological Hydrogen Storage in Saline Aquifers
(withdrawn)
Saeid Ataei Fath Abad and Katriona Edlmann
11:47–11:57
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EGU24-19609
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Highlight
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On-site presentation
Jan ter Heege, Anisa Corina, Vincent Soustelle, and Remco Groenenberg

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.

11:57–12:07
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EGU24-1539
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ECS
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On-site presentation
Riccardo Maria Ridolfi, Salvatore Azzaro, Stan E. Beaubien, Andrea Da Pra, Marco Pontiggia, and Sabina Bigi

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.

12:07–12:17
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EGU24-9198
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ECS
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On-site presentation
Giuseppa Anzelmo, David Iacopini, Giovanni Mario Cella, Luca Visconti, Katriona Edlmann, Martina Cascone, Giacomo Russo, Rosanna Maniscalco, Mariano Parente, Cristian Sabatino, Claudia Di Benedetto, Abner Colella, Giuseppina Balassone, Piergiulio Cappelletti, Ciro Cucciniello, Lucia Pappalardo, Enrico Di Clemente, Laura Perrotta, Donato Giovannelli, and Michele Simili

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.

General storage
12:17–12:27
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EGU24-13643
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ECS
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On-site presentation
Sandra Eriksson, James Minto, Katriona Edlmann, Gareth Johnson, Jennifer Roberts, and Zoe Shipton

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.

Posters on site: Tue, 16 Apr, 16:15–18:00 | Hall X4

Display time: Tue, 16 Apr 14:00–Tue, 16 Apr 18:00
Chairperson: Johannes Miocic
X4.124
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EGU24-178
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ECS
Ali Alsayah

The need to find sufficient capacity for geological storage of carbon dioxide (CO2) to meet demand means less-than ideal, heterogeneous reservoirs need to be considered. Many such reservoirs are apparently compartmentalised by inter-layers, which may help, or hinder, CO2migration and storage capacity, depending upon their nature. The impact of shale inter-layers of thicknesses below seismic resolutions are generally neglected in plume migration simulations, but have been shown here to be important. Only simulations of plume migration that include the full coupling of all three of mass transport, geo-chemical and geo-mechanical processes together provide proper prediction of the barrier efficiency of relatively thin shale inter-layers. A series of feedback inter-actions, between these three process types, has been studied in detail, and, for example, leads to the unexpectedly higher barrier efficiency of relatively thin inter-layers compared to slightly thicker inter-layers. The results showed that changes to the capillary breakthrough pressure, together with diffusion processes, played the vital roles in enhancing the migration of the CO2 plume via the thicker shale inter-layers towards the overburden. This presentation identifies significant research gaps regarding the effects of complicated, intricate processes affecting shale inter-layer (or seal) integrity under realistic reservoir conditions.

How to cite: Alsayah, A.: Impact of CO2 Permeation on Inter-layers and Reservoir Cap-rock Sealing Efficiency, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-178, https://doi.org/10.5194/egusphere-egu24-178, 2024.

X4.125
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EGU24-4135
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ECS
Zhenghong Li, Mads Huuse, Kevin Taylor, and Lin Ma

The Bunter Sandstone Formation (BSF) in the UK sector of the Southern North Sea is thought to have a significant potential for CO2 storage, which would help the UK achieve net-zero carbon emissions by 2050. During the assessment phase, a robust lithofacies classification scheme and accurate identification enable better control for delineating the petrophysical property distribution in 3-D space, which is vital for further estimating the storage capacity and simulating CO2 migration.   

In previous studies, several different lithofacies classification schemes were proposed for calculating the CO2 storage capacity of BSF traps. However, the establishment of these schemes was almost entirely dependent on well-logging data due to limited cores and corresponding thin sections. For example, the ‘cemented sandstone layers’ were identified only by low gamma-ray values with a sharp increase in density values and a decrease in acoustic values, which leaves significant uncertainty because of the lack of detailed lithological description and core calibration. For lithofacies identification based on well-logs, artificial neural networks are of great potential due to their strong non-linear mapping ability. Numerous researchers used the fully connected neural network (FCNN) to recognize lithofacies, but this method can only construct point-to-point mapping, which cannot take into account the previous information (data points in well-logs) of sequence data and results in not being fully competent in lithofacies identification.

This study aims to partition the BSF reservoirs into several relatively homogeneous lithofacies based on cores, thin sections, SEM (Scanning Electron Microscope) and XRD (X-ray Diffraction) analysis. We summarize each lithofacies characterization including grain size, porosity/permeability, 3D network structure of pore and cement determined by X-ray CT. Data pairs composed of logs and corresponding lithofacies types are selected for training neural networks. On this basis, we employ the algorithms designed for sequence data to achieve lithofacies identification, and make a comparison with the widely used FCNN method.

How to cite: Li, Z., Huuse, M., Taylor, K., and Ma, L.: Novel application of artificial neural networks to derive lithofacies in the Bunter Sandstone Formation of the UK Southern North Sea, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-4135, https://doi.org/10.5194/egusphere-egu24-4135, 2024.

X4.126
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EGU24-4703
Piyaphong Chenrai

The main source of carbon dioxide (CO2) emissions in Thailand is the energy sector, particularly coal-fired power plants. The Mae Moh lignite-fired power plant, owned by the Electricity Generating Authority of Thailand (EGAT), stands out as the primary point source of CO2 emissions in the energy sector. Situated in Northern Thailand, this power plant relies on lignite supplied from the Mae Moh lignite open-pit mine in the same vicinity. Consequently, this study conducts a preliminary assessment of the geological CO2 storage potential of the Mae Moh mine, evaluating its suitability as a CO2 storage site. The concept of CO2 sequestration in unmineable coal seams is considered as a potential approach to mitigate CO2 emissions by injecting CO2 into these seams. While a substantial portion of the remaining coal at the Mae Moh mine may still be extractable through traditional methods, the feasibility of opening new mines is uncertain. This study aims to evaluate the suitability of coal seams for CO2 storage, taking into account geological, technical, economic, and safety criteria. The findings of this study are anticipated to contribute to an enhanced understanding of carbon sequestration in coal seams in Thailand.

How to cite: Chenrai, P.: Carbon sequestration potential of the Mae Moh mine, Northern Thailand, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-4703, https://doi.org/10.5194/egusphere-egu24-4703, 2024.

X4.127
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EGU24-4735
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ECS
Alejandro Fernandez Visentini, Luis Cueto-Felgueroso, Juan Jose Hidalgo, and Marco Dentz

The efficiency of hydrogen storage and recovery cycles largely depends on how the fluid spreads as it is injected in the reservoir, and how well it mixes with the in-situ fluids. Spreading leads to the stretching of the fluid front and to the creation of chemical concentration gradients, whereas mixing is driven by the existence of such gradients and it tends to erase them by molecular diffusion. Spreading is caused by spatial heterogeneity in the gas flow velocity, which in turn depends on the spatial distribution of the host rock permeability, the latter exhibiting orders of magnitude variation over a wide range of spatial scales. Quantification of the impact of permeability heterogeneity on the spreading and mixing behaviour of gases can help to better predict the outcome of hydrogen production cycles, but it has not been systematically studied to date in the context of underground hydrogen storage. Further, the dependence on pressure and chemical composition of the hydrodynamic properties of gases, namely, viscosity, density and compressibility, leads to a non-linear relationship between spreading and mixing of hydrogen and permeability that requires detailed numerical modelling. Here, we investigate the dependence of standard spreading and mixing measures on the hydrodynamic parameters of evolving mixtures of hydrogen and other fluids (e.g., cushion gases, water) for different permeability models. We simulate isothermal hydrogen injection and extraction for different permeability models, imposed pressure gradients and regimes of flow stability (e.g., viscous and gravitational). We consider different test cases where invading and residing fluids go from mildly- to highly-contrasting hydrodynamic properties. The considered spectrum of spreading and mixing behaviours for given permeability models helps to develop uncertainty measures and analytical models. We perform the modelling using open-source Matlab Reservoir Simulation Toolbox (MRST).

 

How to cite: Fernandez Visentini, A., Cueto-Felgueroso, L., Hidalgo, J. J., and Dentz, M.: Spreading and mixing of hydrogen in heterogeneous porous media, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-4735, https://doi.org/10.5194/egusphere-egu24-4735, 2024.

X4.128
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EGU24-8870
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ECS
James Johnson, Daniel Kiss, Reinier van Noort, and Viktoriya Yarushina

Storage of compressed gases in lined rock caverns (LRC) has been proposed in order to buffer the peaks of energy intake/output for industrial/renewable systems. LRCs consist of a thin (1-2 cm) steel liner to ensure gas tightness, surrounded by a concrete layer (0.5-2 m) to transmit stresses to the host rock which acts as a pressure vessel. Advantages of storage in such underground LRCs when compared to storage in tanks on the surface or on the seabed include (1) increased safety, and potentially (2) increased storage capacity.

Pilot studies exploring the feasibility for LRC storage have been carried out showing the potential for the technology (e.g. Grängesberg, Sweden​; Skallen, Sweden; ANGAS, Japan). All three test facilities demonstrated that it is possible to reach a gas pressure that is at least 20 times larger than the lithostatic pressure without compromising the integrity of the LRC. While these pilot tests are valuable for demonstrating the potential of the LRC technology, it is not possible to extrapolate safe operating conditions for future scenarios (e.g. shallower depths, different rock types). As a result, widespread adoption of LRC storage is hindered by uncertainty. Our focus is operating pressure, which scales roughly with storage capacity, and thus has a direct impact on LRC profitability.

In this study we will present results of analogue and numerical models. We focus on brittle deformation in the host rock due to the load exerted by a pressurized cavity. Our specific goal is to determine the extent of safely acceptable brittle deformation, and to identify useful indicators of storage integrity to be monitored during initial pressurization tests and continuous operation. Our analogue modelling of this system identifies key parameters that influence the potential success of these projects including (1) proximity to surface, (2) strength of the host rock, (3) mechanical anisotropy, (4) injection rate and amount, and (5) type of liner(s) applied. For the analogue modelling we use gelatin to represent a shallow competent host rock (e.g. granite, gneiss). A hole placed centrally on one side of the cell allows for the injection of compressed air. Utilizing a balloon placed within the hole, the compressed air acts on the liner until the stress applied by the forced air results in visible strain (i.e. fracturing). For the numerical modelling we use a 2D, visco-elasto-plastic, finite difference, hydro-mechanical code utilizing a pseudo-transient solver running on GPUs. The main goal is to cross-validate the results of the two independent methods, and to provide a straightforward way to extrapolate from laboratory simulation to real world conditions.

How to cite: Johnson, J., Kiss, D., van Noort, R., and Yarushina, V.: Analogue and numerical modelling of rock deformation due to subsurface compressed gas storage , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-8870, https://doi.org/10.5194/egusphere-egu24-8870, 2024.

X4.129
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EGU24-9061
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ECS
Jonas Simon Junker, Anne Obermann, Alba Zappone, Hansruedi Maurer, and Stefan Wiemer

In a pilot project (DemoUpStorage) in Helguvik, Iceland, CO2 is injected into basaltic strata using seawater instead of freshwater for CO2 dissolution. The aim is to obtain permanent storage of the CO2 by mineral carbonation. We aim to observe the precipitation of Mg and Fe carbonates in the porosity of the reservoir at depth. Additional to geochemical observations, we use geophysical methods (ERT, seismics) to monitor the mineralization process.

Here, we present the overall project, the geophysical characterization of the site and the first time-lapse monitoring results. We performed a cross-hole seismic traveltime tomography and single-hole electrical resistivity (ERT) measurements to characterize the study site in the target depth of 150m to 400m and to record a geophysical baseline for the time-lapse measurements. The seismic and geoelectric data are in good agreement, highlighting multiple basaltic layers of tens of meters in thickness with sedimentary interlayers. With the CO2 injection starting in early 2024, we will also show the first results from the (daily) time-lapse ERT surveys.

How to cite: Junker, J. S., Obermann, A., Zappone, A., Maurer, H., and Wiemer, S.: Geophysical Site Characterization and monitoring of CO2 mineralization in Basaltic Complexes, Helguvik, Iceland, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-9061, https://doi.org/10.5194/egusphere-egu24-9061, 2024.

X4.130
|
EGU24-12575
|
ECS
Dóra Cseresznyés, Nereo Preto, Katalin Báldi, Péter Kónya, Csilla Király, Orsolya Gelencsér, Ágnes Szamosfalvi, Csaba Szabó, György Czuppon, and György Falus

A promising method that could drastically reduce the effects of anthropogenic carbon-dioxide emissions is the capture of CO2 and its storage in geological formations (CCS technology). The processes that can take place in saline aquifers got under the spotlight in the last decades and the most promising options are sandstone reservoirs. However, natural CO2 trapped in carbonate (limestone) reservoirs are not well studied. The general assumption is that CO2 aggressively dissolves the limestone (matrix, grains, and cement), which would cause drastic changes in the reservoir properties (e.g., porosity, permeability).
To better understand the processes that CO2 injection can cause in a carbonate reservoir, a natural CO2 subsurface occurrence in Ölbő (Hungary) was investigated, where CO2 has been trapped safely in the limestone on a geological timescale. Core samples of the reservoir from 1700-1900 m depth were studied with various methods like petrography (carbonate facies analysis, nannoplankton determination), scanning electron microscopy, cathodoluminescence microscopy, X-ray diffraction and infrared spectroscopy. Microdrilling of the carbonates was also carried out to determine the C and O isotope composition of different constituents in order to reveal possible dissolution/recrystallization processes which may occur in the CO2 reservoir.
Two types of cement were found in the samples, a blocky, drusy cement and a syntaxial cement on the echinoderms (early cement). Contrary to the assumption, dissolution features, may be related to the CO2 inflow, were not observed in the rocks.
The average mineral composition of the samples is the following: 79 m/m% calcite; 6 m/m% dolomite; 3 m/m% ankerite, mica and quartz; 1 m/m% kaolinite, minor feldspar and pyrite. Dawsonite, the indicator mineral of CO2 flooding in siliciclastic sandstones, was not identified in the samples.
Carbonate components of the rock are Red algae, Foraminifera, Bryozoa, Bivalves, Echinoderms and Brachiopods. Nearly all were originally calcitic. Based on nannoplankton biostratigraphy and literature, the age of the host rock is Upper Badenian (Serrevallian), Middle Miocene.
The stable C and O isotope data of microfossils shows a narrow range, δ13C is ranging from -1.55‰ to 2.05‰ (average: -0.23‰), δ18O is between -7.98‰ to -0.25‰ (average: -4.54‰), expressed on the V-PDB scale. These data do not indicate the effect of magmatic CO2, which may reside in the Ölbő reservoir (Cseresznyés et al., 2021), in agreement with the petrography. According to our preliminary results, CO2 inflow did not affect the Ölbő limestone reservoir, i.e., did not imply significant dissolution, neither was involved in cement precipitation. Limestone thus could be an excellent physical trap for CO2. However, due to limited mineral reactions, our results indicate that limestone reservoirs may not be the best for mineral trapping which is the safest storage mechanism of CO2 on geological timescale. Further analyses will be carried out with geochemical modeling, to study the water-CO2-limestone reactions based on the Ölbő CO2 field.

Reference:
Cseresznyés et al 2021. ChemGeol.  https://doi.org/10.1016/j.chemgeo.2021.120536

How to cite: Cseresznyés, D., Preto, N., Báldi, K., Kónya, P., Király, C., Gelencsér, O., Szamosfalvi, Á., Szabó, C., Czuppon, G., and Falus, G.: Limestone reservoirs: are they good for CO2 geological storage?, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-12575, https://doi.org/10.5194/egusphere-egu24-12575, 2024.

X4.131
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EGU24-13687
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ECS
|
Edward Yates, Andy Nicol, Matthew Parker, and David Dempsey

Hydrogen is projected to account for at least 10% of the global energy system in 20 years and is a critical component of the future zero-emissions energy system. Underground storage of green hydrogen in Aotearoa New Zealand (ANZ) will take advantage of intermittent surplus of renewable electricity at low cost, balance seasonal fluctuations in energy supply and demand, and provide a strategic reserve of energy. This poster is part of a larger research programme primarily focused on investigating the potential for underground hydrogen storage (UHS) in Taranaki, ANZ. Here, we explore the potential for UHS in porous rock formations of depleted gas reservoirs with particular focus on the role of seal integrity for storage. 

In this project the overarching goal is to improve understanding of whether mudstone seal strata have the potential to prevent leakage of hydrogen from Taranaki reservoirs. The primary focus is to characterise the geometries of fault and fracture systems in seal strata, their impact on its bulk permeability and to identify the pressure conditions required to promote the loss of seal integrity. In this poster we use Formation Micro Imagery (FMI) together with stratigraphic and fault/fracture mapping of core from petroleum wells to identify fracture densities, orientations and properties in both seal and reservoir rocks. Interpretations of seismic reflection lines in Taranaki and analogous outcrop observations are used to understand the geometries and permeability properties of fault zones. 

Preliminary results indicate that fractures are present in both reservoir and seal rocks. The densities of fractures increase with proximity to regional fold hinges and faults, and with increasing carbonate content. Questions remain about under what conditions fractures are open and capable of transmitting hydrogen. The poster outlines preliminary results, proposed research pathways and invites discussion.

How to cite: Yates, E., Nicol, A., Parker, M., and Dempsey, D.: Impact of faults and fractures in mudstone seal rocks of porous-media underground hydrogen storage reservoirs – Case study in Taranaki, New Zealand, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-13687, https://doi.org/10.5194/egusphere-egu24-13687, 2024.

X4.132
|
EGU24-14418
Martin Krueger and Anja Dohrmann

In the subsurface, biotic and abiotic processes can generate and consume hydrogen. Hydrogen has a low reduction potential and is thus a highly energetic electron donor when involved in sulfate, carbon dioxide or ferric iron reduction. Although known as important drivers for the deep biosphere, the contributions of different processes to hydrogen turnover in different geosystems still are not well understood. In context with the ongoing transformation to renewable energy resources, underground H2 storage (UHS) in deep porous or salt cavern systems came into focus. In situ microbial and geochemical reactions that consume H2 are highly relevant topics in deep biosphere research, and also are still a major uncertainty during UHS.

Consequently, we studied the potential microbial hydrogen oxidation rates – combined with the possible production of metabolic products like H2S, acetic acid or CH4 - in formation fluids from natural gas fields and salt caverns, thereby considering the importance of in situ pressure and temperature conditions, fluid chemistry and mineral composition. In addition, more defined experiments were conducted with selected pure cultures representing important metabolic groups of deep biosphere microorganisms.

Several original formation fluids showed immediate H2 consumption. Microorganisms oxidized hydrogen at relevant in situ pressure conditions (up to 100 bar) and tolerated dynamically changing pressure and temperature conditions. The microbial hydrogen oxidation rate was strongly dependent on H2 partial pressures and the availability of e.g. sulfate as a terminal electron acceptor. High-throughput sequencing of 16S rRNA gene amplicons indicated hydrogen oxidation by sulfate reducing bacteria to be the presumed process in the studied porous rock reservoir fluids. In addition, hydrogen turnover by methanogenic and acetogenic as well as iron-reducing microorganisms was investigated. Also, the importance of biotic reactions in relation to abiotic hydrogen turnover processes at mineral surfaces will be discussed.

 

How to cite: Krueger, M. and Dohrmann, A.: Hydrogen-driven microbial redox reactions in deep geosystems relevant for H2 storage, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-14418, https://doi.org/10.5194/egusphere-egu24-14418, 2024.

X4.133
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EGU24-14800
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ECS
Joseph Regur, Jiaqi Liu, and Tomochika Tokunaga

Subsurface petroleum storage in excavated caverns sealed using a hydraulic containment system offers many advantages over traditional surface storage tanks. The challenge of accurately simulating a complex subsurface system includes accounting for the viscous shear forces within free-flow regions such as the boreholes, fractures, voids, and storage tanks. The Brinkman extended Darcy’s equation is one solution which accounts for viscous shear forces along the free-flow boundaries and momentum transfer across the porous media interface.

This study aims to demonstrate the significance of fluid viscosity forces in the subsurface flow regime, and show the suitability of the Brinkman equation by using numerical modeling in COMSOL to create lab-scale simulations of a borehole coupled with porous media. It analyzes and compares the simulated velocity gradients and head gradients, calculated using the Brinkman equation and the classic Darcy equation. This study shows simulation cases at various inlet pressures, inlet velocities, porosities, and permeabilities, such as those used for subsurface storage to evaluate the influence of these parameters.

The preliminary results show that the Brinkman equation predicts a non-uniform velocity profile within the borehole due to friction along the borehole interface. The two equations also predict  different velocity distributions across the borehole interface and in the porous media near the borehole. These differences are more significant at higher inlet velocities/pressures. These models could be validated by laboratory experiments, enhanced to include fractures, and enlarged to field scales. This study will have implications for numerous injection and well production activities, such as subsurface energy storage, hydraulic fracturing, and contaminant transport studies.

How to cite: Regur, J., Liu, J., and Tokunaga, T.: Numerical Modeling of Fluid Flow through a Borehole-Porous Medium System: Comparison between Brinkman and Darcy Equations, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-14800, https://doi.org/10.5194/egusphere-egu24-14800, 2024.

X4.134
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EGU24-15218
Ching-En Kung, Chia-Wei Kuo, and Yun-Chen Yang

Large-scale carbon capture and storage (CCS) stands a crucial role in achieving net-zero emissions by 2050. To successfully deploy the geological CO2 storage, it is essential to consider heterogeneities of storage reservoirs and surrounding strata. The variation of porosity, permeability, relative permeability, and capillary pressure have a significant influence on storage capacity, potential leakage, CO2 plume migration, and risk assessment. Besides, underground aqueous CO2 can convert to minerals or form insoluble ionic species if reacting with specific ions or solid minerals. These processes, known as geochemical trapping, is considered as the most permanent form of storage.

In this work, we utilize the well-known multiphase flow software TOUGH3 as well as reactive-transport software TOUGHREACT with module ECO2N, to simulate the behavior of CO2 injected into the 2D large-scale models comprising aquifer, seal, and reservoir layers with homogeneous distributions.  A series of sensitivity studies on porosity-permeability relations, different pairs of relative permeabilities and different heterogeneous distributions generated from a geostatistical software SGeMS will be conducted in this work to investigate their impacts on CO2 plume migration and pressure evolutions.  In addition, capillary trapping mechanisms are also simulated based on sensitivity studies on different capillary pressure curves. Finally, brine with different concentration species is considered to simulate the geochemical trapping.

This research aims to achieve the following objectives: 1. Examine the impact of uncertainties of petrophysical properties and heterogeneities. 2. Analyze preliminary results of predicted pressure buildup and saturation distribution in the heterogeneous models. 3. Evaluate the possible storage capacity of both physical and geochemical trapping.

How to cite: Kung, C.-E., Kuo, C.-W., and Yang, Y.-C.: Numerical Simulation of CO2 Storage Behavior: Investigation of Physical and Geochemical Trapping in Heterogeneous Underground Structures, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-15218, https://doi.org/10.5194/egusphere-egu24-15218, 2024.

X4.135
|
EGU24-15536
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ECS
Orsolya Gelencsér, Csaba Árvai, László Mika, Ákos Kővágó, Dóra Cseresznyés, Csaba Szabó, Péter Tóth, Dániel Breitner, Zsuzsanna Szabó-Krausz, and György Falus

The concept of subsurface hydrogen storage was born in the middle of the 1970’s in the shadow of the global oil crisis, however the high prices of commercial hydrogen limited the interest in it as an energy source. Today, hydrogen is considered to be a major energy carrier as well as potential alternative fuel in transportation.

Porous rocks receive a high attention for the future hydrogen storage as geologic structures can achieve greater void volume compared to surface storage options. Understanding the potential reactions of injected hydrogen with pre-existing minerals, gases, ions, and other substances (e.g., microorganisms) is critical as it is required for safety and keeping the quality of the withdrawn hydrogen. Abiotic processes are inorganic reactions between the reservoir rock, in-situ brine, and injected H2 that could alter the petrophysical reservoir performance (porosity, permeability, pore structure, and composition) and the geo-mechanical stability of the rock.

The subject of this research is the Late Miocene sandstone of the Alföld Formation Group located in the Pannonian basin, Carpathian-Pannonian region. This succession can potentially play a significant role in hydrogen storage in the future, due to its favorable reservoir geological and petrophysical characteristics.

We studied the abiotic reactions that can occur in the reservoir by a combined experimental and geochemical modeling work. Among the rock forming minerals, two constituents are highlighted in this study. K-feldspar (KAlSi3O8) is one of the most pH sensitive silicate minerals and pyrite (FeS2) is a redox sensitive accessory mineral of sedimentary rocks.

Static batch reactor experiments were conducted in the pressure and temperature range of subsurface hydrogen storage to track the effect of hydrogen on K-feldspar and pyrite in a similar way as described in Gelencsér et al. (2023). Geochemical modeling was performed in PHREEQC modeling environment.

Results show that K-feldspar behaves similarly both under hydrogen and nitrogen “atmosphere”. Pyrite can react with hydrogen resulting in partial alteration of pyrite surface (thorough the precipitation of pyrrhotite [FeS]) and hydrogen sulfide (H2S) production, whereas the reference experiments (with nitrogen) did not show any H2S release or the appearance of pyrrhotite.

 

Project no. 971238 has been implemented with the support provided by the Ministry of Culture and Innovation of Hungary from the National Research, Development and Innovation Fund, financed under the KDP-2020 funding scheme.

 

Reference:

Gelencsér O., Árvai C., Mika L. T., Breitner D., LeClair D., Szabó C., Falus G. and Szabó-Krausz Z. (2023) Effect of hydrogen on calcite reactivity in sandstone reservoirs: Experimental results compared to geochemical modeling predictions. J. Energy Storage 61, 1–6.

How to cite: Gelencsér, O., Árvai, C., Mika, L., Kővágó, Á., Cseresznyés, D., Szabó, C., Tóth, P., Breitner, D., Szabó-Krausz, Z., and Falus, G.: Mineral reactivity under subsurface hydrogen storage conditions from the Carpathian-Pannonian region: an experimental and geochemical modeling study, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-15536, https://doi.org/10.5194/egusphere-egu24-15536, 2024.

X4.136
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EGU24-18572
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ECS
Solmaz Abedi, Niklas Heinemann, Arthur Satterley, Carolina Coll, and Philippa Park

Transitioning to renewable energy is crucial for combating climate change, but solar and wind power face supply-demand gaps due to seasonal dependencies. To bridge this gap, converting excess renewable energy into hydrogen for storage in depleted onshore and offshore gas fields offers a promising solution, enabling stored energy for use during high-demand periods without carbon emissions. These sites offer an attractive option for underground hydrogen storage, facilitating global distribution and using existing infrastructure.

However, selecting the type and required optimum volume of cushion gas is crucial to ensure the effective reproduction of working gas and economic feasibility. To address this, an analogue model was built based on the geology of the Kinsale field, a depleted gas field potential future hydrogen store in the Celtic Sea. This model uses reservoir and flow properties derived from wireline data of existing wells and the geological system in the area.

For fluid flow, a compositional simulator was used to model changes in fluid composition. Actual field operational control parameters such as maximum and minimum pressure ranges were considered. A uniform depletion procedure was initiated reflecting current field production data. The study investigated the impact of various aspects of the hydrogen storage operation, including reservoir heterogenity, number of wells, cushion gas types, and optimal scenarios for working gas production.

The findings reveal that after the first storage cycle, injecting hydrogen as a cushion gas yields the highest purity (93.5%) of produced hydrogen working gas, while methane as a cushion gas exhibits the lowest purity (85.2%). The hydrogen purity increases with increasing cycles, but 100% purity cannot be achieved because of the in-situ natural gas. Moreover, across production phases, the hydrogen purity in the produced gas within each cycle declines over time. This decline is attributed to decreasing pressure during production leading to the migration of methane from the surrounding flanks toward the wellbore area.  Additionally, an increase in the number of wells decreases the required volume of cushion gas because multiple wells require lower production pressures to produce the same volume of stored gas.

Based on the findings derived from the simulations, we conclude that depleted natural gas reservoirs offer a viable option for hydrogen storage in terms of both dynamic storage capacity and hydrogen purity.

How to cite: Abedi, S., Heinemann, N., Satterley, A., Coll, C., and Park, P.: Cushion Gas Type and Optimal Volume for Underground Hydrocarbon Storage in a Depleted Gas Reservoir in the Celtic Sea, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-18572, https://doi.org/10.5194/egusphere-egu24-18572, 2024.

X4.137
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EGU24-20803
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ECS
Sepideh Goodarzi, Branko Bijeljic, and Martin Blunt

We performed three cycles of hydrogen injection (drainage) followed by brine
injection (imbibition) combined with high-resolution three-dimensional X-ray imaging on a
sample of Bentheimer sandstone. After each injection, the sample was imaged initially and
after waiting 16 hours. Capillary pressure was measured from the differential pressure across
the rock once the injection has stopped and from estimating the meniscus curvatures from the
images. In addition, the gas saturation, pore occupancy, Euler characteristic and interfacial areas
were measured. There was a significant rearrangement of the gas in the pore space after injection stopped,
which we hypothesise is caused by Ostwald ripening, namely the transport of dissolved hy-
drogen in the aqueous phase to equilibriate local capillary pressure. This rearrangement led to
the formation of larger, more connected gas ganglia. The capillary pressure displayed char-
acteristics that cannot be explained by traditional hysteresis models. While the direct and
curvature-based measurements agreed to within experimental uncertainty, and corresponded to
independent measurements in the literature on initial displacement, Ostwald ripening allowed
less trapping and less hysteresis (a smaller difference between drainage and imbibiton capillary
pressure) than measured previously on mercury and oil/water systems where Ostwald ripening
did not occur. The results imply that for gas storage applications it is not appropriate to use hysteresis
measurements based on mercury or hydrocarbon systems. Instead, in local capillary equi-
librium, there is less trapping and less difference between drainage and imbibition capillary
pressure.

How to cite: Goodarzi, S., Bijeljic, B., and Blunt, M.: Ostwald Ripening Leads to Less Hysteresis during Hydrogen Injection and Withdrawal: A Pore-Scale Imaging Study, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-20803, https://doi.org/10.5194/egusphere-egu24-20803, 2024.

X4.138
|
EGU24-5455
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ECS
Alice Macente, Sandra Piazolo, and Frederick Oritseweneye Pessu

Carbon capture and storage (CCS) holds the potential to mitigate carbon dioxide (CO2) emissions into the atmosphere. However, there is a likely accumulation of impurities generated from the corrosion reaction taking place within the pipelines during the injection process as well as during the transportation phase. Reactions can change the chemistry of injected fluids for storage, which can then react with the adjacent rock formations reservoir, affecting the reservoir porosity, permeability and caprock integrity. These are important parameters that determine the injectivity and storage capacities of deep geological sites for long term CO2 storage. The study is aimed at evaluating the upstream corrosion of the metallic pipeline materials, correlating their kinetics with changes in the injection fluid chemistry and evaluating the effect of these combined phenomena on the storage capacities of the geological reservoir rocks. The study involves the investigation and characterisation of corrosion and bulk scaling upstream to the deep geological formations of various rock types. Reservoir rock samples are characterised before corrosion and after carbonation reactions using X-ray Computed Tomography and other micro-analytical techniques, to assess the changes in the rock storage capacity properties such as porosity, pore connectivity and permeability. Our preliminary results indicate an increase in porosity, pore size and pore connectivity in pure sandstones compared to impure sandstones, indicating that local rock chemistry in an important factor in controlling dissolution/carbonation kinetics.

How to cite: Macente, A., Piazolo, S., and Pessu, F. O.: Understanding corrosion and carbonation effects on pore scale properties of geological reservoir rocks during CO2 injection and storage: Insights from X-ray Computed Tomography , EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-5455, https://doi.org/10.5194/egusphere-egu24-5455, 2024.

X4.139
|
EGU24-6123
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ECS
Lorenzo Borghini, Amerigo Corradetti, Marco Franceschi, Anna Del Ben, and Lorenzo Bonini

Net-zero emission targets for 2050 are pushing governments, energy industries, and the scientific community to explore the use of alternative energetic vectors. Among them, hydrogen has risen as a potentially extremely relevant technology, as testified by the establishment of several “hydrogen valleys” in the EU. One of the key aspects in the use of hydrogen as energy vector is its underground storage. The majority of studies focus on physical experiments and numerical simulations, whereas little attention has been so far directed on potential sites selection. This study presents a site selection and feasibility study considering the Cavanella Formation (lower Miocene, Northeast Italy) as potential reservoir for hydrogen storage. This unit comprises medium to fine glauconitic sandstones. The presence of the Cavanella Formation in the subsurface of the Friuli Plain is widely documented and the unit is easily identified in seismic lines. A preliminary petrophysical characterization of the Cavanella Formation was carried out on sampling collected from outcrops. The site selection study was based on interpretation of publicly accessible seismic lines, well logs, thin sections, and literature data. Each potential site was evaluated, attributing a storage feasibility index through a designed scoring matrix developed by us and based on literature reservoir characteristics needed for hydrogen storage. Results suggest that the Cavanella Formation could have good petrophysical characteristics for hydrogen storage and that potential storage sites could exist. The scoring matrix has already been tested on underground hydrogen storage sites currently in use worldwide and has proven reliable. The identification of possible sites for hydrogen storage and their petrophysical characterization can have significant impact on the deployment of this new technology, therefore helping the energy transition to renewable sources.

How to cite: Borghini, L., Corradetti, A., Franceschi, M., Del Ben, A., and Bonini, L.: An Underground Hydrogen Storage Site Selection Ranking Matrix: Insight into the Friulian Plain, Italy, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-6123, https://doi.org/10.5194/egusphere-egu24-6123, 2024.

X4.140
|
EGU24-8284
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ECS
Elisa Colas, Stefan Back, and Peter Kukla

The end of coal mining activities in Germany has resulted in vast underground spaces becoming potentially available for alternative purposes. The reuse of underground space may therefore provide answers to a growing interest in terms of economic and environmental considerations. Underground spaces can play an important role in future renewable energy scenarios (e.g. electricity and heat storage) and they can be considered as sites for waste disposal and other goods.

One example in these scenarios is the use of abandoned coal mines as sites for future subsurface hydropower plants (UPSP). However, risks associated with underground cavity projects and hydropower plants are well known (Colas et al., 2023), and these may be the reason that there are only a few examples of reusing abandoned coal mines as UPSP. In any repurposing process for former coal mines, geological criteria necessary for a quantitative assessment of the usability of abandoned coal mines need to be established. We use in this study the former coal mine Prosper-Haniel, Ruhr Area, Germany, as a lab test case. The Prosper-Haniel mine covers an area of approx. 165 km², has a maximum depth of 1,159 m at 7 different levels of coal production and can be accessed by a total of five sinking shafts and one inclined shaft. Although the mine has been closed since 2018, feasibility studies have been carried out to investigate the potential reuse of the mine as a heat storage reservoir (Geo-MTES, 2018) and as a lower reservoir for a UPSP (Niemann et al., 2018).

We present an outline of geological and hydrogeological considerations essential for the repurposing of the abandoned coal mine Prosper-Haniel. The approach integrates stratigraphy data, fault sets, mine geometry, geological properties, and three-dimensional geological modelling. The envisaged repurposing applications encompass the utilization of Prosper-Haniel as a lower reservoir for UPSPs, a reservoir for heat storage, a geothermal production site, and as an underground space for storage purposes including waste disposal. The multi-disciplinary and integrated approach presented aims to contribute to a nuanced understanding of the potential repurposing opportunities associated with underground coal mines.

References

Colas, E., Klopries, E.-M., Tian, D., Kroll, M., Selzner, M., Bruecker, C., Khaledi, K., Kukla, P., Preuße, A., Sabarny, C., Schüttrumpf, H., and Amann, F., ‘Overview of converting abandoned coal mines to underground pumped storage systems: Focus on the underground reservoir’, JOURNAL OF ENERGY STORAGE, Vol. 73, 2023.

Geo-MTES, Studie zur thermischen Nachnutzung von Steinkohlebergwerken am Beispiel des Bergwerks Prosper-Haniel am Standort der Innovation City Bottrop. Teilvorhaben: Numerische Modellierung (FKZ 03ET1193B), 2018.

Niemann, A., Balmes, J. P., Schreiber, U., Wagner, H.-J., and Friedrich, T., ‘Proposed underground pumped hydro storage power plant at Prosper-Haniel colliery in Bottrop—state of play and prospects’, Mining Report Glückauf, Vol. 154, No. 3, 2018.

How to cite: Colas, E., Back, S., and Kukla, P.: Future underground spatial utilization – The role of geological criteria in the repurposing process of former coal mines, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-8284, https://doi.org/10.5194/egusphere-egu24-8284, 2024.

X4.141
|
EGU24-19156
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ECS
Sayan Sen and Scott K. Hansen

Capturing large quantities of CO2 from the atmosphere and sequestering voluminous amounts into deep saline aquifers form one of the key aspects of modern-day climate change mitigation strategies. However, the technical challenge lies in understanding the non-linear dynamics which govern the flow and transport of CO2 in the subsurface. Diffusion of CO2 into brine causes the development and growth of a diffusive layer having a density greater than the ambient brine. This layer yields to small scale perturbations in the flow field thereby producing fingers which propagate with time, facilitating dissolution and trapping. In natural systems, the solubility of CO2 and the mixing behavior is influenced largely by the simultaneous impact of ambient pressure, temperature, brine salinity, heterogeneity and background flow. Although, previous studies have mainly investigated fingering dynamics for homogeneous and heterogeneous cases, employing little or no background flow, a full-scale study collectively considering the different parameters remains to be done.  

For our research we developed a 2D particle tracking reservoir simulator to model the transport dynamics of single-phase CO2-brine mixture for a system with spatially varying density, viscosity and local diffusion coefficient, governed primarily by variations in salinity and mixture concentration. Using this simulator, we perform a large-scale Monte Carlo parametric study to establish a thorough understanding regarding the influence of heterogeneous permeability-porosity fields, variable background flow, multicomponent electrolyte brine systems and dispersion anisotropy on the fingering dynamics and transport behavior of CO2-brine mixtures in the subsurface. We will demonstrate how salinity gradients in typical aquifers influence the viscosity and density variations of the mixture at wide ranges of reservoir heterogeneities and investigate its effect on the convective mechanism and mixing behavior. Additionally, in this regard, we will also examine how transverse shearing disrupts fingering thereby influencing the dissolution rate of CO2 into the aquifer. We will also present results highlighting fingering dynamics in preferential permeability pathways of aquifers having very high heterogeneities at different salinities and background flow. Finally, we will investigate how the interplay of these above physical parameters at different degrees affect the standard transition regime stages that are developed previously for homogeneous and heterogeneous cases. The novelty of study lies in considering a much wider range of attributes deemed important to influence large scale fingering dynamics and mixing behavior, where currently to our knowledge, no studies have been performed.

How to cite: Sen, S. and Hansen, S. K.: Understanding the effects of heterogeneity, salinity and background flow on convective dynamics of CO2-brine mixture in fully saturated porous media at geologic carbon storage conditions, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-19156, https://doi.org/10.5194/egusphere-egu24-19156, 2024.

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EGU24-5579
Tine B. Larsen, Elin Skurtveit, Steve Pearson, Tom Kettlety, Jung Chan Choi, Chen Huang, Brian Carlton, J. Michael Kendall, Michael Kupoluyi, Daniela Kühn, Daniel Roberts, Kees K. Hindriks, Anne-Kari Furre, Auke Barnhoorn, and Devendra N. Singh and the SHARP Team

SHARP is an interdisciplinary project with the overall aim to develop improved methods for quantitative assessment of subsurface CO2 storage containment risks. The project combines subsurface stress models, rock mechanical failure experiments, and seismicity observations with probabilistic modelling of fault stability, seismic hazard, and containment risk. This presentation will summarise and give a status update on risk quantification work of the SHARP project. Uncertainties and parameter ranges are included for the failure data, and independent and dependent failures of geological barriers are treated probabilistically. A new catalogue of natural seismicity in the North Sea form the basis for constructing offshore ground motion prediction equations (GMPEs) and an updated regional probabilistic seismic hazard analysis (PSHA). Natural seismicity, pressure, and pressure induced seismicity are identified as potential root causes of leakage (triggers) and a catalogue of generic release diagrams are built for realistic geological settings. The generic release diagrams are mapped onto test cases from the North Sea. The geological containment risk with uncertainties will be evaluated though event tree analysis and Monte Carlo runs, where the inputs are the quantified contributions from release diagrams, probabilistic fault stability analysis and the seismic hazard curve.

How to cite: Larsen, T. B., Skurtveit, E., Pearson, S., Kettlety, T., Choi, J. C., Huang, C., Carlton, B., Kendall, J. M., Kupoluyi, M., Kühn, D., Roberts, D., Hindriks, K. K., Furre, A.-K., Barnhoorn, A., and Singh, D. N. and the SHARP Team: SHARP project – an integrated approach for assessing CO2 storage containment risks, EGU General Assembly 2024, Vienna, Austria, 14–19 Apr 2024, EGU24-5579, https://doi.org/10.5194/egusphere-egu24-5579, 2024.