In CCS wells, cyclic injection of cold CO₂ into the hot subsurface may lead to debonding between sealant and steel casing. We test how thermal cycling affects the sealing ability of five different types of sealant (S1 to S5) surrounding a simulated steel wellbore. We use cylindrical sealant samples with a stainless steel (AISI 316 L) pipe in the centre, cured at 150°C and 30 MPa for 28 days. Using 3 bar N₂ leak tests at room temperature, we test how much the sealant-steel interface leaks before and after thermal cycling under unconfined and confined (1.5 MPa) conditions. We also conduct push-off experiments using a 500 kN loading frame before and after. For the unconfined test, we place the sample on a custom-built jig, whereas for confined tests we have a similar assembly inside a conventional triaxial vessel. The samples are brought to 60°C. Subsequently, we inject 5°C water through the central pipe at 80 mL/min for 2 mins, and let the sample reheat for 12 mins. We repeat this 16 times. Afterwards, we allow the sample to cool to room temperature, and repeat the N₂ leak test in-situ. The results show that under unconfined conditions, the interface leaks more for all sealant types except S3. The key parameter controlling performance is the linear thermal expansion coefficient, where an expansion coefficient closer to that of steel indicates better performance. Under confinement, all sealant types perform better post-thermal cycling, due to the prolonged exposure to confining pressure.

Underground hydrogen storage (UHS) in underground geological reservoirs is a promising solution for large-scale energy storage. However, several challenges, particularly geomechanical ones, must be resolved before UHS can be widely and safely deployed. The interactions between hydrogen, brine, and reservoir rock, combined with the cyclic stresses resulting from hydrogen injection and withdrawal may affect the mechanical integrity of the reservoir, the caprock, as well as its surrounding formations. This is an experimental investigation into the geomechanical impact of a 6 month exposure of clay-rich sandstone (Yellow Felser) rocks to hydrogen and/or brine. Cm-scale samples were exposed to hydrogen-saturated brine at 150 bar and in an autoclave for the period of six months. Afterwards, triaxial cyclic loading experiments were conducted on the samples under confining pressures of 10, 20, and 30 MPa. The results are compared with those from the reference samples, which have been exposed to brine only, for the same time period. Each mechanical test included eight stress cycles in the linear stress regime (below the brittle yield point), followed by loading to failure. The frequency, amplitude, and stress conditions were tailored to each confining pressure. The results showed that six months of hydrogen-saturated brine exposure had no noticeable effect on the failure envelope, elastic properties, inelastic strain, and acoustic properties of the Yellow Felser sandstone compared to exposure to brine alone. Internal friction, P-wave velocity, and Young’s modulus each showed a change of around 3%, which is on the same order as the repeatability and therefore indicating minimal geomechanical alteration. Complementary qualitative and quantitative scanning electron microscopy (SEM) analyses revealed negligible microstructural changes. When eight stress cycles were applied within the linear stress regime, the majority of inelastic strain occurred during the first cycle, with no progressive accumulation thereafter. A comparison with samples tested under monotonic loading to failure confirmed that cyclic loading under these conditions does not affect the rock strength of Yellow Felser sandstone. These findings provide new insights into the combined effects of cyclic stress and hydrogen/brine/rock interactions on the geomechanical behavior of clay-rich sandstones under reservoir-relevant pressure and temperature conditions.

Geothermal energy offers a sustainable source of heat and electricity but alters reservoir pressure and temperature, affecting in-situ stress and potentially triggering fault reactivation and induced seismicity. Deep geothermal reservoirs are valuable for their high temperatures but pose challenges like low permeability and fracture-dominated flow, increasing the risk of fault instability.

This study explores two approaches to assess stress changes: a semi-analytical geomechanical proxy and a fully-coupled Thermo-Hydro-Mechanical (THM) model using open-DARTS. The THM model simulates coupled thermal, hydraulic, and mechanical processes in complex rock formations, while the proxy method approximates displacements and stress changes using reservoir simulation outputs and homogeneous geomechanical rock properties assumptions.

The proxy model has been applied to matrix- and fault-dominated systems, including the Brugge dataset. Results include pressure, temperature, displacements, stress changes predictions over 30 years. Fault stability is evaluated using Mohr-Coulomb criteria with a constant friction coefficient.

In fracture-dominated systems, faults often control flow but. Discrete Fracture Model (DFM) has been used for flow modelling.

Combining proxy and THM models can optimize the balance between accuracy and computational cost. The study emphasizes the differing impacts of pressure and temperature on fault stability during geothermal operations.

Abstract
Solute mixing in rocks plays a central role in a wide range of reactive processes. However, how the complex 3D pore structure of rocks governs mixing rates remains largely unknown. Moreover, some mixing-driven reactions—such as dissolution and precipitation—can modify the pore space, with poorly understood consequences for mixing itself. Recent advances in X-ray imaging techniques have significantly enhanced our ability to visualize the pore-scale rock architecture of rocks and a wide range of fluid processes. However, capturing solute mixing and its impact on chemical reactions—such as mineralization—remains a major challenge. Here, we investigated the potential of coupling time-lapse 3D neutron and X-ray imaging to characterize reactive fluid mixing and subsequent calcium carbonate mineralization in porous basalt. Two flow-through experiments were performed with co-injected CaCl2 and Na2CO3, leading to precipitation. Neutron imaging tracked fluid mixing, while X-ray imaging distinguished the solid matrix from pore space for fluid analysis. The first experiment showed steady transverse mixing, while a second experiment revealed temporal fluctuations due to trapped air, causing multiphase flow. Neutron images indicated significant fluid mixing driven by these fluctuations. A synchrotron X-ray image post-experiment indicated additional mineral precipitates from long-term diffusive mixing. Despite the promising results, several challenges remain, including resolution limits, temporal synchronization between modalities, and accurate fluid phase segmentation. Overall, our findings highlight both the potential and limitations of integrated neutron and X-ray imaging for studying pore-scale reactive transport and mineralization processes.

Plain Language Summary
Understanding fluid movement inside rocks is crucial for enhancing CO2 storage and other underground applications. This study used neutron and X-ray imaging to explore how reactive fluids mix in basalt rocks and how this process forms calcium carbonate, aiding long-term carbon storage. We conducted experiments by pumping fluids through basalt samples at varying flow rates and employed advanced imaging to observe the mixing and subsequent calcite precipitation. Neutron imaging tracked fluid movement, while X-ray imaging revealed the pores filled with fluids and calcite. Our findings underscore the challenges and opportunities of using these imaging techniques to study pore-scale mixing and reactive transport, providing a framework for future research on optimizing mineral precipitation processes.

Volcanic and magmatic outgassing mechanisms can determine eruptive behavior of shallow silicic magma bodies. Most outgassing mechanisms proposed take place along conduit margins, where the highest strain rates drive ascending magma to brittle failure. However, these mechanisms do not account for outgassing large volumes of magma away from the conduit walls. Here, we present a continuum of porosity preserved in the microcrystalline rhyolitic Sandfell laccolith, Eastern Iceland. Three stages in the continuum are described: porous flow bands, pore channels, and fracture bands. These deformation features are present throughout the entire exposed volume of the Sandfell laccolith in meter-long band geometries, ranging from mm- to dm-scale thickness, and interlayered with coherent, undeformed rhyolite. Using microstructural analytical methods and drawing on the result of previous experimental studies, we show that emplacement-related deformation induced strain partitioning around a crystal content of 45 % that resulted in the segregation of melt-rich and melt-poorer flow bands. Subsequent deformation induced by continued magma emplacement caused strain partitioning in the melt-rich flow bands. Depending on strain rate, different types of deformation features developed, through dilation or porosity redistribution (porous flow bands), cavitation (pore channels), or tensile fracture (fracture bands). Porous flow bands have permeability values ∼4 orders of magnitude higher than undeformed rhyolite. Pore channels and fracture bands have much larger length scales, and so permeability increases dramatically in those systems. Hence, the abundance and interconnectivity of deformation features preserved in the Sandfell laccolith provided an efficient outgassing mechanism for the bulk of the intrusion. Outgassing due to viscous-brittle magma deformation during magma emplacement should therefore be considered for crystal-rich magmas, e.g., during effusive lava dome extrusion.

In geological CO2 storage, the integrity of seals between well and caprock is crucial for ensuring permanent CO2 storage. One key mechanism that might affect this integrity is thermal cycling when cold CO2 is injected periodically into a hot reservoir. Our study aims to identify which properties of a sealant are key to its ability to withstand thermal cycling under in-situ conditions. We investigate sealants of four different compositions, namely two ordinary Portland cement-based blends (S1 and S2), and two blends designed for carbon capture and storage applications, namely a novel ordinary Portland cement-based blend with CO2-sequestering additives (S3), and a calcium aluminate cement-based blend (S4). These four sealants possess different thermomechanical properties, such as Young’s modulus, tensile strength, unconfined compressive strength, thermal diffusivity, and thermal expansion coefficient, also characterized in this study. Samples of these sealants were placed in a triaxial deformation apparatus, and subjected to either 1.5 or 10 MPa confinement at 120 °C. Then we applied eight thermal cycles by injecting 20 °C water through a central bore in these samples. To assess the effects of the thermal treatment, we used X-ray micro-computed tomography (micro-CT), helium pycnometry, and compressive strength testing on thermal-treated as well as intact samples. Micro-CT results indicate that all sealant samples maintained integrity without cracking (above 32 µm) after thermal cycling under confinement. For all four sealants, post-treatment porosity (determined by either micro-CT or pycnometer) was reduced, which is ascribed to compression during confinement. This reduction in porosity was associated with an increase in compressive strength. Compared to experiments conducted under 1.5 MPa confinement, those at 10 MPa exhibit a greater reduction in porosity, and more enhanced compressive strength. The application of confinement suppressed the potential of crack formation by increasing the effective strength including tensile strength of the sealant during thermal cycling by a reduction in porosity. Based on these findings, we conclude that to limit potential damage to seal integrity induced by thermal cycling, sealants for carbon capture and storage should ideally have high tensile strength and thermal diffusivity, but low Young’s modulus and thermal expansion coefficient.

Maintaining well integrity is a key challenge to the secure geological storage of CO2. Here, sealants based on Portland Cement form a key component, providing seals between the steel wellbore and surrounding caprock, as well as plugs for sealing wells that will no longer be used. However, exposure of sealants based on Portland Cement to CO2-bearing fluids may lead to carbonation, potentially followed by degradation of these materials during prolonged exposure or flow, which may thus negatively impact well integrity. Therefore, new sealant materials need to be developed to help ensure long-term well integrity.

This paper reports exposure of five different sealants to CO2-saturated water and wet supercritical CO2 at in-situ conditions (80 °C and 10 MPa). Three of the sealants investigated are based on Portland Cement, while the other two are based on Calcium Aluminate Cement, and a rock-based geopolymer specifically developed for Geological CO2 Storage (GCS). The five sealants were selected to represent different methods for improving wellbore seal integrity, such as restricting permeability (and porosity), or modifying how the material interacts with CO2-bearing fluids. Exposures were carried out in a purpose-built batch apparatus, enabling simultaneous exposure of up to 10 samples in total to CO2-saturated water and wet supercritical CO2.

After exposure, changes in the sealants’ microstructures and chemical and mineralogical compositions were assessed using scanning electron microscopy with energy-dispersive X-ray spectroscopy, computed tomography scanning, and fluid chemical analysis. The impact of exposure to CO2-bearing fluids was interpreted in terms of alteration and degradation of the materials, to compare how different sealant design modifications can be employed to enhance wellbore integrity.

Abstract
Effectively mitigating induced seismicity in subsurface engineering operations within highly permeable, porous geo-energy reservoirs requires a clear understanding of how fluid injection parameters influence the seismic response. In this study, we performed injection-driven fault reactivation experiments on highly permeable saw-cut Red Felser sandstone to provide new insight into the effect of injection pattern and rate on fault slip behavior and seismicity evolution. Three different pressurization rates were applied: high, medium, and low rates of 2, 1, and 0.2 MPa/min, respectively. Three injection patterns were also used: cyclic recursive, monotonic, and stepwise injections. Our results reveal that a high pressurization rate leads to increased slip velocity, more microseismic events, higher total acoustic emission (AE) energy, and a lower b-value compared to tests with low pressurization rates. We postulate that a high pressurization rate enhances the likelihood of a sudden reduction in effective normal stress, leading to fault opening and the disruption of asperity contacts. Furthermore, results from samples subjected to various injection patterns demonstrate that the cyclic recursive pattern exhibits a higher maximum slip velocity, more episodes of slow slip, and greater radiated AE energy than a monotonic pattern. In the case of the cyclic recursive pattern, increasing the number of cycles increases shear stress drop, shear slip, and maximum slip velocity. Our findings suggest that using a monotonic injection pattern and low pressurization rate may mitigate seismicity on pre-existing faults in a highly permeable, porous reservoir.

Plain Language Summary
Human activities involving subsurface fluid injection projects, such as geothermal energy recovery and/or gas storage (CO2, H2 or methane), are widely acknowledged to cause earthquakes occasionally. This is a cause for public concern. Although several studies demonstrate that injection patterns and rates can play an essential role, the underlying physical mechanisms responsible for induced earthquakes still need to be better understood. Therefore, we performed laboratory tests on highly permeable Red Felser sandstone containing a simulated geological fault. We pumped water from the bottom of the sample using different pressurization rates and patterns while monitoring the effects on fault movement behavior. Our results showed that faster fluid injections tend to cause more rapid fault slips and generate more laboratory micro-earthquakes compared to slow injections. Among the injection patterns, the cyclic injection pattern resulted in the highest slip velocity and higher earthquake activity, indicating that the pattern of injection can impact fault movement. Our results can help improve the design of fluid injection projects to minimize the risk of inducing small earthquakes, especially in areas with pre-existing geological faults.

This study presents a method to address the significant uncertainties in subsurface modeling that impact the efficiency of energy transition applications such as geothermal energy extraction and CO₂ geological sequetsration. The approach combines a physics-based geomechanical proxy model with an ensemble smoother with multiple data assimilation (ES-MDA), aimed at enhancing uncertainty quantification through the integration of vertical displacement measurements from fluid production and injection. The data from wells is limited in spatial coverage, while these measurements offer extensive spatial information, improving the understanding of subsurface behavior by reflecting changes in reservoir pressure and temperature. The open-DARTS simulator for fluid flow and a geomechanical proxy are used to perform data assimilation with ES-MDA. By generating an ensemble of model realizations with varied permeability, calculating vertical displacements at the surface, and applying ES-MDA, we effectively identify the probability distribution of the vertical displacement of the model conditioned to observed subsidence data. Entropy is used as a statistical measure to quantify the reduction of uncertainty of subsurface models based on observations. Our approach was tested on a 2D conceptual and 3D realistic datasets, demonstrating its capability to provide data assimilation. This workflow represents an advancement in subsurface modeling, supporting informed decision-making in geothermal energy production and CO₂ sequestration by offering an improved alternative for data assimilation and enhancing tools for uncertainty quantification.

Induced earthquakes are still highly unpredictable, and often caused by variations in pore fluid pressure. Monitoring and understanding the mechanisms of fluid-induced fault slip is essential for seismic risk mitigation and seismicity forecasting. Fluid-induced slip experiments were performed on critically stressed faulted sandstone samples, and the evolution of the actively sent ultrasonic waves throughout the experiment was measured. Two different fault types were used: smooth saw-cut fault samples at a 35° angle, and a rough fault created by in situ faulting of the samples. Variations in the seismic slip velocity and friction along the fault plane were identified by the coda of the ultrasonic waves. Additionally, ultrasonic amplitudes show precursory signals to laboratory fault reactivation. Our results show that small and local variations in stress before fault failure can be inferred using coda wave interferometry for time-lapse monitoring, as coda waves are more sensitive to small perturbations in a medium than direct waves. Hence, these signals can be used as precursors to laboratory fault slip and to give insight into reactivation mechanisms. Our results show that time-lapse monitoring of coda waves can be used to monitor local stress changes associated with fault reactivation in this laboratory setting of fluid-induced fault reactivation. This is a critical first step toward a method for continuous monitoring of natural fault zones, contributing to seismic risk mitigation of induced and natural earthquakes.

Sealants that can guarantee long-term wellbore sealing integrity are of great significance to the safe and sustainable storage of CO₂ in carbon capture and storage (CCS). In this study, we investigate how abrupt cyclic thermal shocks affect the integrity of four sealants of different compositions. These sealants include two reference OPC-based blends (S1 and S2), one newly-designed OPC-based blend that contains CO₂-sequestering additives (S3), and one calcium aluminate cement (CAC)-based blend designed for CCS applications (S4). We have measured the thermal properties of these samples, followed by quenching and flow-through experiments to apply strong cyclic thermal shocks on samples of the four sealants, where we heated the samples to 120 °C, and quenched them in, or flowed through water of 20 °C. Using X-ray tomography (32 µm/voxel) before and after the experiment showed that both S1, S2 (reference OPC-based) and S4 (CAC-based) broke after thermal-shocking experiments. Cracks and new voids developed in the samples. Post-treatment strength testing shows that thermal shocks reduce the unconfined compressive strength of these three sealants. This implies that these compositions may not be optimal materials for long-term wellbore sealing during CO₂ injection and storage afterward. For all these three sealant compositions, quenching resulted in a greater reduction in strength (by 53 % on average) than flow-through experiments (by 29 % on average). On the contrary, we have not observed any cracks after either quenching or flow-through experiments in S3 sealant (OPC with CO₂-sequestering additives). We attribute the intactness of this sealant after thermal shocks to its higher thermal diffusivity than the other three sealants. Heat transfers more rapidly in this sealant and the associated thermal stresses are mild and insufficient to cause any damage to its integrity, which makes this sealant a good candidate for wellbore sealing material that can effectively withstand strong thermal shocks encountered during CCS, though further studies are required.

The development of new geological storage applications and other uses of subsurface reservoirs requires tailored wellbore sealants, able to withstand application-specific exposure conditions. For example, wellbore sealants used in reservoirs targeted for CO2-storage will be exposed to CO2-rich fluids, that may chemically attack OPC-based sealants, leading to carbonation and potential degradation. During CO2-injection, local temperature changes around the injection well may also affect the integrity of the sealant-wellbore system, for example causing the formation of annuli between sealant and steel casing due to differences in thermal expansion. The research project CEMENTEGRITY aims to identify the key sealant properties that may help to ensure the long-term integrity of the wellbore-seal system during CO2-injection and storage, as well as the best testing methods for these properties. This is done by testing five different sealant compositions, exposing them to potentially deleterious impacts under different conditions. Here, we report some of the key findings of our project. While CEMENTEGRITY is researching sealants specifically for CO2-storage, other applications, such as hydrogen storage, or geothermal energy exploitation, will require purpose-built sealants that are similarly tailored to the expected chemical and physical conditions.

While carbon capture and storage (CCS) technology has been proven effective for some time, challenges still exist in ensuring the safe and efficient storage of CO2. In this context, we highlight the results of three CCS research projects that move us closer to achieving our gigatonne targets in the North Sea and beyond: SHARP, CEMENTEGRITY, and RETURN.

In many geological systems, the porosity of rock or soil may evolve during mineral precipitation, a process that controls fluid transport properties. Here, we investigate the use of 4D neutron imaging to image flow and transport in Bentheim sandstone core samples before and after in-situ calcium carbonate precipitation. First, we demonstrate the applicability of neutron imaging to quantify the solute dispersion along the interface between heavy water and a cadmium aqueous solution. Then, we monitor the flow of heavy water within two Bentheim sandstone core samples before and after a step of in-situ mineral precipitation. The precipitation of calcium carbonate is induced by reactive mixing of two solutions containing CaCl₂ and Na₂CO₃, either by injecting these two fluids one after each other (sequential experiment) or by injecting them in parallel (co-flow experiment). We use the contrast in neutron attenuation from time-resolved tomograms to derive three-dimensional fluid velocity field by using an inversion technique based on the advection-dispersion equation. Results show mineral precipitation induces a wider distribution of local flow velocities and leads to alterations in the main flow pathways. The flow distribution appears to be independent of the initial distribution in the sequential experiment, while in the co-flow experiment, we observed that higher initial local fluid velocities tended to increase slightly following precipitation. The outcome of this study contributes to progressing the knowledge in the domain of reactive solute and contaminant transport in the subsurface using the promising technique of neutron imaging.

Geothermal energy production often involves use of corrosion inhibitors. We performed rock mechanical experiments (room temperature; confining pressure of 10/20/30 MPa) on typical reservoir rocks (Bentheim sandstone and Treuchtlinger limestone) in contact with two different inhibitor solutions or with demineralized water. The sandstone experiments show no discernible difference in rock strength between inhibitors or water, attributed to low quartz reactivity. The limestone experiments show a significant difference in rock strength (and Mohr–Coulomb envelope), dependent on inhibitor type, attributed to high carbonate reactivity. This implies that, depending on the reactivity of the rocks and local stress conditions, inhibitor leakage may lead to unpredicted reservoir failure.

Many rocks contain planar heterogeneities, in the form of open fractures, veins and/or stylolites, but scarce data exist on how strength and fracture pattern formation is affected by the presence of a singular planar heterogeneity in an otherwise uniform matrix. The mechanics of stylolite-bearing and/or fractured limestone is of interest to several engineering applications, from quarries to subsurface gas or geothermal reservoirs. We have performed Brazilian Disc tests on pre-fractured Indiana limestone samples and Treuchtlinger Marmor discs which contain cohesive stylolites, investigating Brazilian test Strength and the resulting fracture pattern. All experiments were filmed, and where possible analyzed with particle image velocimetry. When viewed in 2D, the planar discontinuity was set at different rotation angles compared to the principal loading direction, where perpendicular to the loading direction is defined as 0⁰. The results show that all samples are weaker than their intact counterparts. For the pre-fractured Indiana limestone, there is 10–75% angle-dependent weakening. However, in the samples with a stylolite, strength is weakened by 35–75%, independent of direction. Several new cracks appeared when fracturing a stylolite-sample, where the orientation is heavily influenced by the stylolite orientation. The fracture pattern and associated stress drops are more complex for high angles. In these samples always more than one fracture formed, whereas in pre-fractured samples usually only one new fracture formed. This suggests a potential for more permeability increase when hydrofracturing a stylolite-rich interval. Comparison with Finite Element Models indicates that this difference in fracture pattern is caused by the strength contrast between the anastomosing stylolite zone and the matrix material, leading to stress concentrations effects. This causes (micro-) fracture nucleation to occur locally, promotes fracture coalescence and fracture growth at lower overall sample-load conditions compared to intact samples.

This report describes the activities performed within Task 1.2 “Report on gas solubility and degassing kinetic (type C)” until the end of month 40 of the REFLECT project. Two series of experiments have been carried out that assess the degassing process of type C geothermal fluids respectively in bulk and porous media. This has resulted in an improved understanding of the process and the associated physical phenomena by utilizing experimental equipment and data analysis tools specifically created for this task.

The long-term performance of the reservoir is essential in order to ensure competitive life-cycle cost of the geothermal installations. Geothermal fluids are often saturated with gasses such as CO2 and N2. With their extraction from the reservoir, pressure and temperature decrease towards the extraction well. This disturbs the state of equilibrium the geothermal water is in with its dissolved components, which for gas can lead to exsolution. The exsolved gas bubbles can block the pores of the reservoir rock and therefore reduce the apparent permeability. As permeability reduction occurs mainly near the extraction well it can reduce production of geothermal waters substantially. This paper is aimed at experimentally investigating the conditions at which the onset of degassing starts and quantitively assess any associated permeability decrease. Knowledge on these parameters will enable operators to adapt their operation procedures in order to ensure long-time reservoir permeability. This paper reports core-flood experiments where tap water containing dissolved carbon dioxide was injected into either a Bentheimer (2.3 Darcy) or Berea (140millidarcy) sandstone core at different conditions. The first sets of core-flood experiments showed that at a temperature of 30 °C and pressure up to 50 bars the onset of the degassing process correlates closely to CO2solubility values obtained by the Henry’s law. At these conditions CO2 degassing near the core outlet will cause the apparent permeability to decrease by a factor2 to 5 in the high permeability Bentheimer sandstone core. At the same conditions the apparent permeability will decrease by a factor of nearly 10 in the low permeability Berea sandstone core. The decrease ineffective permeability is gradual in the Bentheimer sandstone while in the Berea sandstone the change is steeper. For rocks with small pore sizes and low absolute permeability, the reduction in effective permeability is larger and the rate of permeability decrease is faster. However, the onset of degassing is not influenced by the pore size and initial permeability. Experiments at temperatures between 30 and 90 °C show that with increasing temperature, the Van ‘t Hoff equation becomes less to accurate to find the degassing pressure