This session is dedicated to studies investigating some of these THMC interactions by means of mathematical, experimental, numerical, data-driven and artificial intelligence methods, as well as studies focused on laboratory characterization and on gathering and interpreting in-situ geological and geophysical evidence of the multi-physical behavior of rocks. Welcomed contributions include approaches covering applications of carbon capture and storage (CCS), geothermal systems, gas storage, energy storage, mining, reservoir management, reservoir stimulation, fluid injection-induced seismicity and radioactive waste storage.
Orals: Tue, 29 Apr | Room -2.43
Underground hydrogen storage (UHS) in porous reservoirs is a promising solution for large-scale renewable energy storage. However, significant uncertainties remain regarding the impact of cyclic hydrogen injection and withdrawal cycles on reservoir geochemistry and hydraulic properties, particularly in depleted gas reservoirs, containing residual methane or CO2. Recent studies have highlighted the complex interplay of coupled thermo-hydro-mechanical-chemical and microbiological (THMCB) processes that could influence key reservoir properties such as porosity, permeability, and mechanical integrity during UHS operations.
This talk will explore some of these uncertainties by reviewing the coupled THMCB processes at play and presenting findings from recent reactive flow experiments conducted under reservoir-relevant conditions. The experiments aim to elucidate changes in reservoir properties and fluid chemistry, focusing on the impact of hydrogen-brine-rock reactions and the role of hydrogen trapping. Additionally, the presentation will discuss the significance of changes in redox potential (Eh) observed in hydrogen-saturated brine as a potential indicator of hydrogen-induced geochemical reactions.
How to cite: Edlmann, K., Thaysen, E., Kilpatrick, A., and Heinemann, N.: Exploring Coupled Processes in Underground Hydrogen Storage: Insights from Reactive Flow Experiments, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-5627, https://doi.org/10.5194/egusphere-egu25-5627, 2025.
Mafic and ultramafic rocks such as basalts and gabbro have reactive minerals such as olivine, pyroxene, and plagioclase to trap CO2 into stable carbonates. When the carbonic acid (CO2 dissolved in water) is injected to these rocks, stable carbonates such as calcite, dolomite, magnesite, and siderite are created and precipitated. However, such rocks suffer ultra-low permeability of the matrix which makes the reach of CO2 to minerals a cumbersome task. Novel stimulation techniques as well as natural fractures are required to enhance the injectivity of CO2 fluid into these rocks and create new storage opportunities. Energized fracturing with CO2 is a promising method to enhance the injectivity of low-permeable target rocks, thanks to the unique thermodynamic and transport properties of CO2. In order to ensure the safety and efficacy of storage medium, it is crucial to possess a comprehensive understanding of the movement of pressure plumes within geological features by monitoring the potential impact on the deformation of geological layers as well as the ground surface.
In this work, an extensive numerical simulation of energised fracturing with CO2 is performed utilising a robust fracturing simulator and the Span-Wagner equation of state for CO2. The simulation results show that CO2 phase (liquid, gas or super-critical) plays an important role in fracture propagation speed, injection time and stimulated volume, However, the CO2 under the supercritical state appears to be the favourable state for the purpose of stimulation. We compare opening versus shearing behaviour of fractures invaded by a fluid pressure plume. Combination of the two creates a mixed-mode deformation at the ground surface detectable via an array of tiltmeters. We present a novel inversion model that distinguishes the opening and shear modes of deformation and identifies the contribution of each mode in the observed tilt data.
How to cite: Salimzadeh, S., Xiao, F., and Kasperczyk, D.: Energised CO2 stimulation for mineral carbonation and corresponding ground deformation, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-379, https://doi.org/10.5194/egusphere-egu25-379, 2025.
After the cessation of active operations and the discontinuation of pumping, many mines are flooded with groundwater. These mines often reach depths of several hundred meters, resulting in water temperatures higher than those typically found in shallow groundwater and soil. In recent years, there has been growing interest in utilizing the geothermal energy stored in these relatively easily accessible water bodies. This energy potential is seen as a promising source of renewable geothermal energy. To evaluate the potential and assess different configurations of extraction and injection locations, detailed numerical models are required.
Such a model must account for the two distinct flow regimes present in the mine and its vicinity: porous medium flow in the soil and free flow in the mine workings. The challenge lies in capturing the relevant hydrological and thermal processes while keeping the computational costs at an acceptable level.
Therefore, a process-based, coupled two-domain model using dimensional reduction has been developed. In the first domain, a single-phase, non-isothermal Darcy model is solved to simulate groundwater flow in the porous medium. This domain is then coupled with an embedded 1D network representing the mine workings. Beyond the coupling of the two domains, a significant challenge is the accurate representation of flow processes within the mine workings using a 1D model. Flow processes in mine workings are more complex than those in simple pipe flow. The temperature field in the subsurface, along with the intricate geometries, requires an extension of the classical 1D pipe flow description.
How to cite: Lipp, D.: Numerical modeling of groundwater flow in an abandoned mine for geothermal use - Development of a digital twin for the mine Neuhoffnung in Bad Ems using a multidomain approach, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-3070, https://doi.org/10.5194/egusphere-egu25-3070, 2025.
Modeling heat transport in porous media is a key focus in engineering and earth sciences, with applications ranging from using heat as a tracer to determine hydrogeological properties to modeling decay heat from nuclear waste repository in aquifers, and simulating geothermal systems. Most models assume local thermal equilibrium (LTE), where multi-phase media are averaged into a single phase to simplify mathematical equations. However, the validity of this assumption is often uncertain. Incorporating local thermal non-equilibrium (LTNE) effects, which describe separate thermal behaviors for fluid and solid phases with an interphase heat exchange term, provides a physically more realistic representation.
We therefore investigated LTNE effects observed in laboratory experiments involving heated water flowing through a column with glass spheres of varying sizes, using a fully coupled two-phase heat transport model developed in the Multiphysics Object-Oriented Simulation Environment (MOOSE). The study emphasizes the role of non-uniform flow effects, which complicate the interpretation of LTNE phenomena from experimental measurements. The model reveals that LTNE effects result from the interplay of transport processes, including heat transfer between fluid and solid phases, and are strongly influenced by flow velocity, grain size, and non-uniform flow conditions. Accounting for non-uniform flow in the model however accurately reproduces the observed temperature difference between fluid and solid phases.
These results highlight that grain-scale LTNE effects stem from the combined influence of phase-specific thermal properties, heat transfer, and flow field heterogeneity. The findings deepen our understanding of heat transport dynamics in porous media and offer valuable insights for improved modeling of applications in hydrogeology, geothermal energy, and nuclear water management.
How to cite: Lee, H., Blum, P., Bayer, P., and Rau, G. C.: Interpreting experimental Local Thermal Non-Equilibrium (LTNE) effects using a two-phase numerical heat transport model, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-5733, https://doi.org/10.5194/egusphere-egu25-5733, 2025.
Non-isothermal fluid injection in fractured media is vital for the analysis of aquifers and underground reservoirs in hydrogen geostorage applications. Fluid flow, rock deformation, fracture aperture, and heat transport processes are fundamental to analyzing fluid storage, stability, and tightness of underground storage structures, induced seismicity or land subsidence. Modeling all these phenomena in a coupled fashion requires high computational effort, especially if the fracture network is explicitly reproduced in the model geometry. Realistic boundary conditions are important too, since pressure, flow rates, or temperature values are usually known only at surface level. This involves taking into account the properties of the injected and host fluids as well as the hydraulic head losses during fluid flow.
In this study, we propose a fully coupled finite element scheme to simulate fluid pressure, temperature, fracture aperture, and rock deformation evolution in highly heterogeneous fractured media. We model fractures as lower-dimensional elements with inherent stiffness, permeability, and thermal properties. Fractures represent preferential flow channels within the reservoir, in contrast to the low-permeability rock matrix. We also simulate injection and production wells as pipes with a certain diameter and roughness. The non-isothermal fluid flow along pipes is coupled with the fractured reservoir, as fluid and heat exchanges are allowed between pipes and fractures.
We compare the performance of our numerical model with some multirate mass transfer models and theoretical formulations, finding excellent agreement between all approaches. For a certain surface pumping pressures, the injection/production flow rates are fundamentally determined by the head losses along wells and fractures permeability, for a certain operation pressure. Fractures permeability, in turn, depends on the thermo- and hydro-mechanical processes that modify the fractures aperture. Our results demonstrate that it is possible to replicate the expected expansion/contraction behavior of fractures through the injection/extraction of fluids with thermal contrast. We note that hydraulic head losses along pipes can be crucial to model performance, with flow rates that can vary up to an order of magnitude if they are ignored.
Our approach reduces the disadvantages associated with mesh refinement and property contrast in fractured areas. It provides an efficient way to simulate coupled heat transport, fluid flow, and rock deformation in fractured zones, also including the non-isothermal flow along the injection and production wells. This capability enables a realistic representation of subsoil fracturing to model subsurface processes such as underground hydrogen storage in deep rock formations.
Acknowledgements
This research was supported by the Spanish Agencia Estatal de Investigación and the Ministerio de Ciencia, Innovación y Universidades (10.13039/501100011033) and by “European Union NextGenerationEU/PRTR” through grant Green-HUGS (TED2021-129991B-C32 and C33).
How to cite: Andrés, S., Dentz, M., Santillán, D., and Cueto-Felgueroso, L.: Thermo-hydro-mechanical coupling and pipe flow modeling of fractured underground reservoirs for optimal operations in geostorage, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-7364, https://doi.org/10.5194/egusphere-egu25-7364, 2025.
Geological hydrogen storage provides a large-scale and long-term solution to balance the seasonal supply-demand mismatch of renewable energy [1-2]. Depleted oil reservoirs represent a secure and feasible storage option [3], but the heterogeneity and complex microstructure of the carbonate rocks, which comprise approximately 60% of the global oil reserves make the utilization of such reservoirs still challenging [4-5]. This work aims to investigate potential performance changes in porous carbonate reservoir rocks under cyclic pressure induced by hydrogen injection and extraction. Triaxial tests under various hydrostatic cyclic loading paths, with continuous permeability measurement and acoustic wave velocity measurement, are conducted on Saint-Maximin limestone (SML) samples [6] to observe the mechanical degradation and permeability evolution. In addition, changes in microstructure and percolation characteristics of the compacted samples are characterized by mercury intrusion porosimetry tests. The results show that 50 cycles within the elastic zone result in only minor of irreversible porosity reduction, while permeability and stiffness of SML remain relatively stable. However, even minimal excursions past the plastic onset P* lead to a noticeable deterioration in the properties of the SML over subsequent cycles, characterized by decreased porosity and permeability, creep and reduced stiffness. The viscoelastic constitutive model calibrated by a creep loading test is used to distinguish time-dependent and cyclic-dependent deformations. Furthermore, mesopore collapses are revealed to be the main source of damage, which leads to an increase in intrusion breakthrough capillary pressure as well as non-wetting phase trapping effects. These findings demonstrate that the historical maximum stress dictates the activation of damage processes, while the cycling intensifies existing damage accumulation without altering the intrinsic damage characteristics. Consequently, controlling the maximum stress level within the reservoir rock emerges as a pivotal parameter in the engineering design of hydrogen storage reservoirs.
References:
[1] Heinemann, N., Booth, M.G., Haszeldine, R.S., Wilkinson, M., Scafidi, J., Edlmann, K., 2018. Hydrogen storage in porous geological formations – onshore play opportunities in the midland valley (Scotland, UK). International Journal of Hydrogen Energy 43, 20861–20874.
[2] Thiyagarajan, S.R., Emadi, H., Hussain, A., Patange, P., Watson, M., 2022. A comprehensive review of the mechanisms and efficiency of underground hydrogen storage. Journal of Energy Storage 51, 104490.
[3] Dvory, N.Z., Zoback, M.D., 2021. Prior oil and gas production can limit the occurrence of injection-induced seismicity: A case study in the Delaware Basin of western Texas and southeastern New Mexico, USA. Geology 49, 1198–1203.
[4] Meng, F., Baud, P., Ge, H., & Wong, T.f., 2019. The effect of stress on limestone permeability and effective stress behavior of damaged samples. Journal of Geophysical Research: Solid Earth, 124, 376–399.
[5] Sayers, C.M., 2012. The elastic properties of carbonates. The Leading Edge, 27(8), 1020-1024.
[6] Abdallah, Y., Sulem, J., Bornert, M., Ghabezloo, S., Stefanou, I., 2021. Compaction Banding in High-Porosity Carbonate Rocks: 1. Experimental Observations. Journal of Geophysical Research: Solid Earth 126, e2020JB020538.
How to cite: Xu, Z., Braun, P., and Sulem, J.: Behaviour of carbonate reservoir rocks under hydrostatic cyclic loading for hydrogen storage application, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-12067, https://doi.org/10.5194/egusphere-egu25-12067, 2025.
Geological storage of CO2 offers a promising solution for reducing atmospheric emissions and mitigating anthropogenic climate change. The feasibility of a storage site and the efficiency of injection strategies depend on geological settings, coupled with techno-economic and socio-political considerations. A site-specific approach is crucial, as storage dynamics vary significantly across different geological structures, such as anticlines or stratigraphic traps with features like pinch-outs. This study evaluates one of two potential CO2 storage site candidates within the German North Sea, investigated as part of the GEOSTOR project, targeting the Triassic Middle Buntsandstein unit as storage formation. The study site, located approximately 130 km from onshore hub in the central German North Sea, is characterised by a 40-50 m thick basal Volpriehausen sandstone. Within the storage structure, an anticline site formed by salt tectonics, several suitable sub-traps are identified using a spill-point analysis. The site is intersected by faults with dip angles of 43°-63°, predominantly striking NE-SW.
Dynamic capacity assessment is conducted using the open-source OPM Flow simulator, with an injection target of 10 Mt/y for 30 years. A maximum allowable pressure limit derived from geomechanical modelling is applied. The model is parameterised using regional correlation models, as well as petrophysical data from legacy well logs. The reservoir model includes CO2 dissolution, hysteresis of relative permeability, as well as thermal effects associated with injecting cold supercritical CO2. The fault system geometry and displacement features are fully represented in the reservoir model but were numerically deactivated for flow and transport processes, as no parameterisation could be obtained.
Results indicate that the target injection rate is achievable using five vertical wells located down-dip of the structure, or alternatively two horizontal wells. Approximately 40% of the estimated static capacity can be utilised under technically feasible injection settings. After 100 years post-injection, about 50% of the injected CO2 remains in free-phase form above the spill point, with the remaining part trapped as residual phase or dissolved in the formation brine. Hydraulic pressure changes extend tens of kilometers from the injection points. The southern boundary of the model, defined as hydraulically closed due to formation erosion, prevents pressure changes from extending into the Dutch subsurface, located approximately 30 km from the model’s southern edge. However, fault systems in the southern model domain, which intersect both the injection reservoir and overburden formations, could potentially cause vertical pressure changes and brine displacement from the German to the Dutch sector, raising cross-border aspects of CCS. The presence of a legacy well at the formation crest point requires further considerations concerning its sealing performance, as pressure increases during injection phase may reach 50 bar.
How to cite: Gasanzade, F. and Bauer, S.: Offshore carbon dioxide storage in the German North Sea: Lessons from capacity assessment, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-13290, https://doi.org/10.5194/egusphere-egu25-13290, 2025.
Subsurface engineering applications, such as CO2 storage, face critical challenges related to safety and sustainability, including induced seismicity and potential leakage pathways, particularly in fault zones. Biomineralization, specifically induced carbonate precipitation (ICP), offers a promising solution by transforming geological formations to reduce porosity and permeability while enhancing mechanical stability. A hydraulic-geomechanical model is essential to explore these effects.
We present a conceptual modeling approach using the open-source simulator Dumux, incorporating biomineralization effects on rock mechanics and fluid flow with minimal parameterization. The model is validated against benchmark problems, focusing on flow-geomechanics coupling and biomineralization implications. A reservoir-scale showcase is conducted, adapting a fault-reactivation scenario to investigate how biomineralization of leakage pathways impacts the reservoir's hydrogeomechanical behavior. Key considerations include sealing effects on stress states and altered failure patterns from continued fluid injection.
Simulation results show that biomineralization improves geomechanical and hydraulic properties, sealing flow paths to reduce porosity and permeability, with implications for underground gas storage. Gas injection induces stress changes consistent with field observations, although geological variability affects outcomes. Sealing fault zones increases stiffness and reduces deformation but creates uneven stress distribution, potentially leading to localized failures. Biomineralization reduces seismic activity compared to unsealed cases, though pressure buildup remains a concern due to delayed response times. The study emphasizes the site-specific nature of biomineralization, necessitating parameter validation, real-world data, and further exploration of diverse operational scenarios.
How to cite: Wang, Y. and Class, H.: A hydro-geomechanical porous-media model tostudy effects of engineered carbonateprecipitation in faults, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-13876, https://doi.org/10.5194/egusphere-egu25-13876, 2025.
Subsurface energy and waste disposal in geo-reservoir environments rely on the sealing potential of clay-rich geological formations to act as physical barriers to long-term anthropogenic influences and minimise the risk of catastrophic leakage from storage facilities. Clay-rich materials are favourable sealing materials due to them characteristically consisting of small pores providing high capillary entry pressures, preventing the intrusion of non-wetting fluid (i.e., CO2, H2). The common assumption is that the gas penetrates the barrier due to capillary breakthrough, i.e., the menisci forming at the interface between the gas and pore-water reach the receding contact angle as gas pressure increases and can no longer sustain the unbalance between the gas and pore-water pressures.
However, capillary breakthrough is not the only possible mechanism. Developing a better understanding of the mechanisms controlling gas sealing is vital for the long-term successful deployment of subsurface energy and waste disposal in geo-reservoir environments. This study aims to investigate the contribution of different mechanisms controlling gas breakthrough in clay-rich barriers.
Previous experimental campaigns have demonstrated that gas breakthrough occurs through localised pathways (e.g., fissures) across the sealing barrier. Capillary breakthrough could be facilitated by gas penetrating the pore-water by diffusion and can ‘drain’ towards pre-existing gas cavities in the pore-space and expand them, a mechanism known as ‘cavitation’. Expanded gas cavities can merge and lead to the formation of the localised pathway. This mechanism implies that gas breakthrough is time-dependent, which is not considered in the ‘on/off’ capillary breakthrough mechanism. Additionally, there might be other time-dependent mechanisms contributing to the deformation of the menisci and/or the deformation of the clay (creep) leading to localised pathway formation. A second gap in the literature consists in the lack of information on the effect of particle shape, mineralogy, and material compressibility on gas breakthrough. This is key information to inform the selection of candidate clay-rich barriers.
Experiments that tested natural material commonly had pre-existing fissures, and therefore, tested the breakthrough pressure of these discontinuities. In this study reconstituted clayey materials are tested with the aim of distinguishing the mechanisms of gas pathway formation. An experimental apparatus was setup to allow 1D consolidation of reconstituted samples at a pre-consolidation stress of 10 MPa, representative of in-situ conditions, followed by the injection of gas (non-wetting fluid) at constant sample volume (i.e., constant effective stress). 1D mechanical consolidation ensures samples are ‘intact’ prior to gas injection, i.e., no pre-established discontinuities. The materials tested include bentonite clay, kaolinite clay, muscovite mica silt, silica (quartz) silt and mixtures of the materials with varying mass fractions. The use of different fluid electrolyte concentrations were chosen to investigate the effect of mechanical behaviour of the material compressibility and density on gas breakthrough pressure. Different pressure increase strategies showed the effect of diffusion on breakthrough mechanisms. Furthermore, that water flow (e.g., drained vs undrained conditions) is controlling the deformation and displacement of the meniscus and hence the breakthrough pressure.
How to cite: Allsop, C., Pedrotti, M., and Tarantino, A.: Gas Breakthrough Mechanisms in Reconstituted Geomaterial, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-19432, https://doi.org/10.5194/egusphere-egu25-19432, 2025.
Posters on site: Tue, 29 Apr, 10:45–12:30 | Hall X5
The inducement of earthquake has been usually thought to be a result of coupled behaviors of fluid and solid mechanics. On the other hand, recent studies have started to focus on the contribution of thermal stress. In the enhancing geothermal energy systems (EGS) popularizing today, it seems to be very necessary to study the earthquake inducements considering thermo-hydraulic-mechanical coupling behavior. Especially, EGS engineering project failure in Pohang and Basel showed that large magnitude earthquakes may be induced during hydraulic fracturing process during geothermal energy extraction from enhanced geothermal systems.
In order to ascertain the relationship between thermal stress and seismicity, a coupled thermal-hydro-mechanical (THM) scheme is formulated by using the finite element method to investigate the inducements of seismicity during geothermal heat injection. Current results with a schematic model suggested that the thermally induced strain might propagate 100 times slower than hydraulically induced strain in an injection process, and then, the possibility of later seismicity caused by the slower propagation of the thermal stress.
How to cite: Yue, L. and Aichi, M.: Thermo-Hydro-Mechanically coupled stress propagation and its possible effects on induced seismicity, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-3916, https://doi.org/10.5194/egusphere-egu25-3916, 2025.
Thermo-hydro-geochemical modelling is of great economic and scientific importance for the implementation of geothermal projects, where understanding the effects of fluid injection and extraction on reservoir properties is crucial. From an operational point of view, changing the temperature of the geothermal reservoirs can intensify both biotic and abiotic water-rock interactions. The latter, including mineral dissolution and precipitation processes, alter the rock’s structure and, consequently, its hydraulic and transport properties such as porosity and permeability. These changes in permeability - controlled by the mineral composition of reservoir’s rock, reservoir fluid composition, temperature conditions, and utilization scenarios - all affect the overall system’s performance and sustainability. The complex nature of these subsurface interactions requires to rely on numerical methods to solve systems of partial differential equations for flow, transport, and chemical reactions. The nonlinearity of such systems translates in high computational costs, mainly due to the reactive chemistry component, which has hindered the applications of those numerical methods for field-scale applications in complex reservoirs.
In this contribution we demonstrate recent development of a robust simulation environment able to handle the intricate couplings of thermohydraulic, mechanical, and geochemical processes for subsurface applications. The open-source GOLEM simulator for THM modelling in fractured reservoir has been coupled with the reactive chemistry PHREEQC library. The goal is to seamlessly integrate GOLEM's capabilities in solving thermohydraulic processes within a finite element mesh, with PHREEQC's robust handling of reactive chemistry calculations. This integration allows for the simulation of 3D reactive transport processes while accounting for the spatial heterogeneities typical of natural geothermal systems, as well as the evaluation of a chemical reaction-based alteration of formation’s porosity and subsequently permeability. Our GOLEM-PHREEQC implementation exclusively relies on open-source software, enhancing the accessibility of multiphysics simulations across different sectors. Herein, we showcase details of the implementation and its validation against available benchmark tests, as well as preliminary results from a field-scale application within the framework of an Aquifer Thermal Energy Storage (ATES) project in the Berlin urban area.
How to cite: Frigo, S., Cacace, M., De Lucia, M., Blöcher, G., Petrova, E., Scheck-Wenderoth, M., and Hofmann, H.: Fully Coupled Thermo-Hydro-Chemical (THC) Modelling in Advanced Reservoir Engineering, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-6144, https://doi.org/10.5194/egusphere-egu25-6144, 2025.
Understanding heat transfer in rock fractures is crucial for optimizing geothermal energy extraction, nuclear waste storage, and other subsurface engineering applications. In geothermal systems, the understanding of thermal behaviour in fractured media is still challenging, due to the complexity of fracture geometry, heterogeneous properties of the fractures and the host rock, and varying fluid flow dynamics influenced by temperature-dependent fracture aperture. Considering that the aperture and shape of fractures can promote preferential transport of fluids and heat, several numerical and experimental studies have demonstrated that these preferential paths, or “flow channeling,” significantly impact heat transfer. However, there is no clear consensus on the effects of flow channeling on the thermal exchange between the fluid and the rock matrix, as some authors observed a decrease, due to increased flow velocity and shortened transit times in the channeled regions, while others report an increase, as radial conduction from the channel to the matrix is more efficient for heat transfer than the linear conduction assumed in a parallel plate model. This study explores the relationship between fracture roughness and heat transfer mechanisms, focusing on advective and diffusive processes under saturated conditions. Finite element numerical models are employed to simulate fluid flow and heat transfer in a set of simplified fracture geometries in which the fracture walls are represented through a sinusoidal function. These models include three scenarios: a fully-mated fracture geometry formed by two aligned sinusoidal surfaces, a fully-unmated configuration, and an intermediate geometry that transitions between the two mentioned geometries. Preliminary results indicate that surface roughness influences convective heat transfer by inducing localized flow channeling. This effect is quantified by observing the thermal attenuation and the lag time of the induced cold pulse imposed over the system. Notably, depending on the fracture geometry, distinct temperature peaks and varying heat recovery tailing profiles are observed across different scenarios. Further work is needed to define appropriate model dimensions, select suitable heat and flow parameters, and refine the time discretization. Additional numerical experimentation is required to determine the optimal approach for modelling the fracture, such as choosing between a function-based or fracture-based representation.
How to cite: González-Fuentes, S., Vilarrasa, V., and De Simone, S.: The impact of surface roughness on heat transport in fractured rocks, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-12036, https://doi.org/10.5194/egusphere-egu25-12036, 2025.
Switzerland is currently expanding renewable energies and aims to initiate carbon capture and storage (CCS), which is necessary to meet national and international climate change goals. The pilot CO2 test injection planned at the Trüllikon site in northern Switzerland (CITru project) would be the first initiative for the storage of CO2 underground in Switzerland. The Trüllikon site was investigated in detail in the context of the Swiss radioactive waste management program. Hydraulic tests carried out in the TRU1-1 well have shown that the hydraulic properties of the Upper Muschelkalk layer (Stamberg Member) and the presence of a low-permeability cap rock (Bänkerjoch Formation) are generally promising to enable the initiation, planning, and implementation of a small-scale CO2 demonstration injection.
In the first phase of the project, additional site investigations are planned, such as a seismic survey, a review of the previously conducted hydrotests, and a detailed risk analysis. An important contribution to the initial planning of the project are numerical simulations to show the theoretical feasibility of a CO2 test injection, i.e., the estimation of subsurface pressures, temperatures, and flow parameters during a potential small-scale CO2 injection. Here, we show an outline of the project focusing on preliminary numerical modeling results using advanced multiphase flow simulation tools. The simulations are intended to show, for instance, the pressure and temperature changes near the borehole, effects on nearby faults and the expected expansion of dissolved and undissolved CO2 in the reservoir. The results of the numerical simulations will help to constrain the expected reservoir and well behavior during the envisioned injection test and could be used to optimize injection strategies and monitoring techniques.
How to cite: Zbinden, D., Rinaldi, A. P., Schultz, R., Alt-Epping, P., Diamond, L. W., and Wiemer, S.: The pilot CO2 test injection project in Trüllikon, Switzerland: project outline and first simulation results, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-16614, https://doi.org/10.5194/egusphere-egu25-16614, 2025.
Reactive transport processes are fundamental in various geological settings, driving ore deposit formation, rock alteration, and deep geothermal energy systems. These processes fundamentally depend on interactions between fluids and the surrounding rock, resulting in dynamic changes in permeability structures and mineral composition over time. In low-porosity systems, creating interconnected porosity is essential for efficient fluid transport. This is particularly critical for deep geothermal energy systems, where mechanically induced permeability enhancements are often viewed as societally sensitive.
To investigate the coupling of fluid-driven mineral replacement reactions and porosity formation, we conducted hydrothermal batch experiments across different reaction durations, analyzing fluid-rock interactions in granitoid systems with varying lithologies and concentrations of F-bearing aqueous fluids under acidic conditions. Using X-ray powder diffraction (XRPD), scanning electron microscopy (SEM), and fluid chemical analyses, we characterized and quantified mineralogical and chemical changes while assessing the microstructural evolution of rock samples exposed to reactive fluids.
Our results show that fluid-rock interactions significantly enhance porosity, driven by mineral dissolution and the formation of denser phases that pseudomorphically replace the original mineral assemblages. In some cases, pores were partially filled with newly precipitated amorphous silica and F-bearing minerals, preferentially replacing feldspar and mica within the granitoid. Key findings underscore the potential of reactive transport processes to enhance permeability in granitoid rocks, emphasizing the critical influence of initial fluid composition on both permeability formation and the overall chemical evolution of the rock system.
How to cite: Rüdiger, G., Kummerow, J., and John, T.: Permeability enhancement through reactive transport, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-17738, https://doi.org/10.5194/egusphere-egu25-17738, 2025.
Forecasting induced seismicity is a challenging task. Most forecasting tools are phased on statistical approaches, incorporating little physics at most. As a result, these tools fail to forecast the complex subsurface response to fluid injection/extraction, like maximum-magnitude earthquakes occurring after the stop of injection. To overcome this issue, we have developed a physics-based forecasting tool that also takes into account the statistics of induced seismicity to forecast the frequency and magnitude of future events (Boyet et al., 2014a). The physics-based model solves the hydro-mechanical coupling and could also solve the thermo-hydro-mechanical coupling. This coupled model permits accounting for triggering mechanisms of induced seismicity other than just pore pressure diffusion. In particular, it considers poroelastic stresses, poromechanical stress relaxation after the stop of injection, and shear-slip stress transfer. We have applied this forecasting tool to the case of the enhanced geothermal system at Basel (Switzerland), where the maximum-magnitude earthquake was induced a few hours after the stop of injection. Our tool successfully forecasts the post-injection maximum-magnitude earthquake when reproducing the step-rate stimulation scheme that was used at Basel. Interestingly, a constant-rate or a cyclic stimulation would have not induced large-magnitude post-injection seismicity, according to the forecasting tool. We have also explored the effect of how injection is stopped has on induced seismicity (Boyet et al., 2024b). Simulation results reveal that, for the case of Basel, shutting-in the well would have led to lower magnitude earthquakes than bleeding-off the well, as performed at Basel. Additionally, a progressive decrease in the injection rate would have stabilize faults even further in the post-injection stage.
REFERENCES
Boyet, A. Vilarrasa, V, Rutqvist, J. and De Simone, S., 2024a. Forecasting fluid-injection induced seismicity to choose the best injection strategy for safety and efficiency. Philosophical Transactions Royal Society A, 382: 20230179
Boyet, A., De Simone, S. and Vilarrasa, V., 2024b. To bleed-off or not to bleed-off? Geophysical Research Letters, 51, e2023GL107926
How to cite: Vilarrasa, V., Boyet, A., and De Simone, S.: Reliable induced-seismicity forecasting based on a coupled-processes model, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-19631, https://doi.org/10.5194/egusphere-egu25-19631, 2025.
Underground green hydrogen storage is a key technology for achieving net-zero carbon goals. However, injecting gas into the subsurface introduces anthropogenic stresses that may destabilize faults, leading to sliding and safety risks. Traditional risk assessments rely on deterministic models that often overlook critical stress zones caused by variability in mechanical properties. To address this, we developed a 2D numerical model to evaluate the effects of heterogeneity on fault stability using stochastic analysis. Two stress regimes—normal faulting and strike-slip—were studied. Random Gaussian fields of Young’s modulus introduced variability, allowing us to examine the influence of standard deviation, correlation length, and stratification angle. Our results show that heterogeneity reduces the safe pressure threshold, increasing fault reactivation risk. Variability in mechanical properties, particularly standard deviation, plays a greater role in stability than geometric arrangements. This study advocates for replacing deterministic approaches with statistical analyses that quantify sliding probabilities, offering a more reliable framework for assessing subsurface risks.
How to cite: Bastias, J., Santillán, D., and Cueto-Felgueroso, L.: Impact of Geomechanical Heterogeneity on the Mobilized Friction Coeffcient, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-10290, https://doi.org/10.5194/egusphere-egu25-10290, 2025.
Posters virtual: Mon, 28 Apr, 14:00–15:45 | vPoster spot 4
EGU25-1746 | ECS | Posters virtual | VPS16
Multi-layer Hydrocarbon Accumulation Model in Yuqi area, Tarim Basin, ChinaMon, 28 Apr, 14:00–15:45 (CEST) | vP4.14
The superimposed basins in western China have undergone multiple periods of tectonic changes and cycles of oil and gas accumulation, and the distribution patterns of oil and gas are very complex, which limits the accurate understanding of the mechanisms of oil and gas accumulation. In this paper, Yuqi area in Tarim Basin is taken as the research area, and based on the geological background, fluid inclusion-homogenization temperature, hydrocarbon inclusion abundance analysis, reservoir quantitative fluorescence technology, infrared spectrum, crude oil geochemical analysis, reservoir asphalt identification and other technologies, the Ordovician-Triassic oil and gas accumulation, migration and adjustment process in Yuqi area is studied. The results indicate that the Ordovician system in the study area developed oil injection during the Late Caledonian, Yanshanian, and Himalayan periods. The Triassic system only had oil injection during the Himalayan period, slightly later than the Ordovician system during the same period. The crude oil injected by the Ordovician in the late Caledonian period was biodegraded into heavy oil and carbonaceous bitumen due to tectonic uplift. Light oil from the Yuertus Formation source rock during the Yanshan-Himalayan period was vertically injected into the Ordovician reservoir along activated faults, and then mixed and transformed early heavy oil reservoirs through lateral adjustment along karst. A certain range of light oil reservoirs were formed in the heavy oil reservoir area. In the late Himalayan period, the light/heavy oil reservoirs mixed and filled by the Ordovician system were locally adjusted upwards along faults to the Triassic system, making the crude oil of the Triassic system, which had stable structures and no degradation conditions, similar to the crude oil of the Ordovician system in terms of crude oil density, maturity, inclusion abundance, biodegradation characteristics, and partially mix with late mature oil and gas that migrated along the Luntai fault-sand body, forming the sporadic distribution characteristics of light and heavy oil reservoirs in the Triassic system today. Therefore, a reservoir formation model of "vertical transport along faults, lateral adjustment along karst, strong degradation, and differential superposition" was established for the Ordovician, and " T-shaped transport along fault-sand and late stage reservoir formation " was established for the Triassic in the Yuqi area.The research have important guiding and reference significance for shallow-deep oil and gas exploration in the Yuqi area.
How to cite: Su, Y., Liu, H., Wang, S., Wang, J., and Zhao, Z.: Multi-layer Hydrocarbon Accumulation Model in Yuqi area, Tarim Basin, China, EGU General Assembly 2025, Vienna, Austria, 27 Apr–2 May 2025, EGU25-1746, https://doi.org/10.5194/egusphere-egu25-1746, 2025.
