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This dataset is composed of the files required for simulating laboratory-scale injection of CO2-saturated water and HCl solution into cm-scale limestone samples. Six files required for simulating the CO2 injection experiment are included in the folder named CO2. The names of these files are as follows: “CO2-input”: input file read by the Crunchflow code and providing the necessary physical and chemical parameters needed for the simulation -these parameters mainly include time intervals, discretization, initial and boundary conditions, geochemical conditions-; “database”: geochemical database for running the simulation; “64bit-libiomp5md”: A dynamic link library (DLL) required to run the Crunchflow code; “Perm.in.x”: permeability file in X direction for all grids; “Perm.in.y”: permeability file in Y direction for all grids; “Perm.in.z”: permeability file in Z direction for all grids. The same files for simulating the HCl injection experiment are included in the folder named HCl. This folder includes two input files “HCl-input-1” and “HCl-input-2” (instead of one) required for simulating the two stages of HCl solution injection into the limestone sample. To run the simulations, one needs to execute the Crunchflow executable file and enter the name of the input file, i.e., either “CO2-input” or “HCl-input-1” with the suffix “.in” in the command window and press enter. Note that in the HCl injection case, you only need to run the “HCl-input-1” file. The second input file will be read at the proper time by the keyword “later_inputfiles HCl-input-2.in” defined in the “HCl-input-1”.

This dataset encompasses the input files associated with diverse numerical models investigating the hydro-mechanical behavior of a fractured specimen under different mean effective stresses. The folder contains simulations for Hydro-Mechanical ("HM_") problems. The simulations are conducted for different mean effective stresses ("P03"; "P05"; "P10"; "P15"; and "P20"). Within each subfolder, files with the suffix "_gen.dat" provide input data for the model, encompassing material properties, initial and boundary conditions, and time intervals. Correspondingly, files concluding with "_gri.dat" contain information on the mesh employed. To execute a model, launching the executable "Cb_v9_1_3par4.exe" within each ".gid" folder is sufficient.

Geological Carbon Storage (GCS) is considered a promising technology to lower atmospheric emissions of CO2. Guaranteeing the sealing capacity of caprocks in this case becomes paramount as CO2 storage scales up to the gigaton scale. Many laboratory experiments have been performed with samples of intact rock, showing that low-permeability and high-entry pressure caprocks have excellent sealing capacities to contain CO2 deep underground. However, discontinuities, such as bedding planes, fractures, and faults, affect the rock properties at the field scale, being at the same time challenging to monitor in industrial-scale applications. The main objective of the thesis is to develop a methodology to characterize potential sites for low-carbon geo-energy applications at multiple scales in space and time, taking into account coupled processes. To achieve this objective, it is necessary to understand the complexity of the problem at multiple scales, starting from large-scale investigations, passing through in-situ underground rock laboratories, to laboratory investigations. This is why this thesis approaches characterizations that span a wide range of spatiotemporal scales from the order of millimeters and nanoseconds to the order of kilometers and decades. To achieve this general objective, the first part of the thesis explores four analytical solutions of pore pressure diffusion with periodic sources under relevant model geometries and boundary conditions to enable real-time interpretation of in-situ data. We compare the results with numerical solutions, assuming the same conditions as the analytical cases and incorporating reservoir deformation due to pressure waves. Encompassing three different cases to span a wide array of scenarios, we evaluate the attenuation of the signal at varying distances from the source. Numerical and analytical solutions fit when identical assumptions are upheld. Furthermore, the influence of effective mean stress variations yields errors of le

Injection-induced seismicity has become one of the most critical challenges for the widespread deployment of Enhanced Geothermal Systems (EGS). In particular, some EGS development projects have led to large, damaging earthquakes that unexpectedly occurred far off the stimulated reservoir region and, in particular, after stopping fluid injection. Yet, the causative mechanisms of these seismicity patterns remain highly elusive. Here, we identify a combination of mechanisms that could explain delayed seismicity in EGS sites by conducting fully-coupled hydromechanical simulations of the hydraulic stimulation of a naturally-fractured granitic reservoir. The model comprises a sparse network of long, variably-oriented fractures interacting with a nearby, critically-oriented fault. The results show that the presence of fractures introduces notable nonlinearities in the flow field and rock deformation and significantly expands the rock volume affected by fluid injection. First, the stimulated fracture network provides highly-permeable conduits for communicating elevated pore pressure over long distances. Second, the anisotropic expansion of fractures generates shear stress that is transmitted almost instantaneously across the reservoir. The pore pressure and stress perturbations can not only cause slip along fractures, inducing (micro)seismicity during injection, but also affect the stability of nearby faults, which may not necessarily be pressurized during injection. The transferred poroelastic stresses can increase or decrease the slip tendency along different fault segments. However, the fault may reactivate only after several months following injection when a progressive pore pressure diffusion modulated by the transient fault permeability evolution brings a critically-stressed fault segment to failure conditions. We also find that the spatiotemporal evolution of seismicity depends largely on the nearby fault orientation, hydromechanical properties, and hydraulic connect

This dataset encompasses the input files associated with diverse analytical and numerical models investigating cyclic pressure diffusion within uniform poroelastic materials. The dataset is organized into two primary folders. The "Analytical Solutions" folder comprises three Python libraries containing the material properties and functions for calculating pressure amplitude at various distances. The "Numerical Solutions" folder contains simulations for both Hydraulic ("01_") and Hydro-Mechanical ("HM_") problems. The simulations are conducted for representative values corresponding to Berea sandstone ("BS_"), Opalinus Clay ("OPA_"), and Westerly granite ("WG_"), considering both monodimensional ("1D") and axisymmetric ("Ax") cases. Within each subfolder, files with the suffix "_gen.dat" provide input data for the model, encompassing material properties, initial and boundary conditions, and time intervals. Correspondingly, files concluding with "_gri.dat" contain information of the mesh employed. The "_bfc.dat" file documents the periodic injection pressure applied for each simulation, while the "root.dat" file specifies the model's nomenclature. To execute a model, launching the executable "Cb_v9_1_3par4.exe" within each ".gid" folder is sufficient.

Reservoir impoundment is usually accompanied by induced/triggered seismicity. The rise in the number of planned hydropower plants requires improving the understanding of the causes of this induced/triggered seismicity, which eventually could serve to propose mitigation measures to reduce the induced/triggered-seismicity risk. We investigate the case of reservoir-triggered seismicity at Nova Ponte, Brazil, where triggered seismicity started shortly after reservoir impoundment, with the maximum magnitude of M3.5 when reaching the highest water level on the dam, and followed by delayed seismicity, with the largest earthquake being a M4.0 about 4.5 years after impoundment. We have built a hydro-mechanical fully-coupled numerical model reproducing the T shape of the reservoir and including the three geological layers placed below the reservoir down to 10 km depth. Simulation results serve to identify the nodal plane, from the two nodal planes of the proposed focal mechanism, which nucleated the seismicity of the M3.5 earthquake: a vertical, E-W-oriented strike-slip fault with a reverse-displacement component. The initial seismicity was triggered by the undrained response of the subsurface to the loading of the reservoir. We also find that the delayed seismicity was triggered by pore pressure diffusion, bringing a critically oriented vertical fault to failure conditions. The vertical permeability to allow the pore pressure perturbation to reach the depth of the M4.0 earthquake, i.e., 3 km depth, in 4.5 years is 6.6·10-15 m2, two to three orders of magnitude higher than the expected permeability of the host rock, a low-permeability mica-schist. We contend that hydro-mechanical models are a useful tool to understand the triggering mechanisms of reservoir-triggered seismicity.

Nos encontramos en un estado de emergencia climática provocado por las actividades humanas. La emisión a la atmósfera de grandes cantidades de dióxido de carbono (CO₂) procedentes de la quema de combustibles fósiles (carbón, petróleo y gas) han producido un calentamiento de la superficie de la Tierra de unos 1,2 ℃ de media por encima del nivel preindustrial. Los impactos del calentamiento global ya se han manifestado en fenómenos meteorológicos extremos más intensos y frecuentes. Ante este panorama, las tecnologías de eliminación del carbono desempeñarán un papel indispensable en el camino a la descarbonización. La capacidad instalada actual de captura de CO₂ es de unas 40 megatoneladas (1 millón de toneladas) al año. Pero aún estamos peligrosamente lejos de cumplir los objetivos climáticos. La capacidad de captura y almacenamiento de CO₂ debe multiplicarse aproximadamente por 100 de aquí a 2050. Aunque las realidades económicas y políticas son determinantes, el temor a las fugas de CO₂ a la superficie ha provocado retrasos en la implementación generalizada de esta tecnología. Un miedo que, según nuestros estudios, no tiene por qué hacerse realidad.

The majority of available climate change mitigation pathways, targeting net-zero CO2 emissions by 2050, rely heavily on the permanent storage of CO2 in deep geologic formations at the gigatonne scale. The spatial and temporal scales of interest to geologic carbon storage (GCS) raise concerns about CO2 leakage to shallow sediments or back into the atmosphere. The assessment of CO2 storage performance is subject to huge computational costs of numerically simulating CO2 migration across geologic layers at the basin scale and is therefore restricted in practice to multi-century periods. Here, we present a computationally affordable and yet physically sound model to understand the likelihood of CO2 leakage over geologic time scales (millions of years) (Kivi et al., 2022). The model accounts for vertical two-phase flow and transport of CO2 and brine in a multi-layered system, comprising a sequence of aquifers and sealing rocks from the crystalline basement up to the surface (a total thickness of 1600 m), representative of a sedimentary basin. We argue that the model is capable of capturing the dynamics of CO2 leakage during basin-wide storage because the lateral advancement of CO2 plume injected from a dense grid of wellbores transforms into buoyant vertical rise within a short period after shut-in. A critical step in the proposed model is its initialization, which should reproduce the average CO2 saturation column and pressure profiles. We initialize the model by injecting CO2 at a constant overpressure into an upper lateral portion of the target aquifer while the bottom boundary is permeable to brine, resembling brine displacement by CO2 plume or leakage at basin margins. The optimum model setting can be achieved by adjusting the brine leakage parameter through calibration. We solve the governing equations using the finite element code CODE_BRIGHT. Discretizing the model with 7,100 quadrilateral elements and using an adaptive time-stepping scheme, the CPU time for the s

Induced seismicity is typically observed in enhanced geothermal systems (EGSs), especially during and after the operations of rock hydraulic stimulation but also during fluid circulation. Although this seismicity has generally been of low intensity, it has often reached a magnitude large enough to be felt by local inhabitants and cause damage, which has jeopardized the widespread deployment of this technology. In this chapter, we review some of the most relevant cases of induced seismicity in EGS and analyze the physical mechanisms that may lead to rock failure and, therefore, to the activation of earthquakes. Afterwards, we discuss the theories and approaches that have been used to model and forecast such seismicity.

Fluid injection into geological formations for energy resource development frequently induces (micro)seismicity. Moderate- to large-magnitude induced earthquakes may cause injuries and/or economic loss, with the consequence of jeopardizing the operation and future development of these geo-energy projects. To achieve an improved understanding of the mechanisms of induced seismicity, develop forecasting tools and manage the associated risks, it is necessary to carefully examine seismic data from reported cases of induced seismicity and the parameters controlling them. However, these data are challenging to gather together and are time-consuming to collate as they come from different disciplines and sources. Here, we present a publicly available, multi-physical database of injection-induced seismicity (Kivi et al., 2022a; 10.20350/digitalCSIC/14813), sourced from an extensive review of published documents. Currently, it contains 158 datasets of induced seismicity caused by various subsurface energy-related applications worldwide. Each dataset covers a wide range of variables, delineating general site information, host rock properties, in situ geologic and tectonic conditions, fault characteristics, conducted field operations, and recorded seismic activities. We publish the database in flat-file formats (i.e., .xls and .csv tables) to facilitate its dissemination and utilization by geoscientists while keeping it directly readable by computer codes for convenient data manipulation. The multi-disciplinary content of this database adds unique value to databases focusing only on seismicity data. In particular, the collected data aim at facilitating the understanding of the spatiotemporal occurrence of induced earthquakes, the diagnosis of potential triggering mechanisms, and the development of scaling relations of maximum possible earthquake magnitudes and operational parameters. The database will boost research in seismic hazard forecasting and mitigation, paving the way f

Geological carbon storage is one of the technologies required to arrive at the ambitious yet realistic net-zero emission target and climate change neutrality. Injected CO2 in geological formations acidifies the resident brine, inducing chemical reactions with the minerals. Reactions may alter the hydraulic and mechanical properties of the rock and have an impact on reservoir and wellbore integrity, reservoir injectivity, long-term compaction and caprock sealing capacity. We provide a comprehensive review of chemo-hydro-mechanical (CHM) effects of CO2 on the reservoir and sealing rocks, either intact or fractured, which have been studied through laboratory experiments under no-flow and open-flow conditions, i.e., batch and flow-through experiments. The hydraulic and mechanical rock properties affected by geochemical processes comprise (a) physical properties influencing the flow and transport of solutes (pore size distribution, porosity, permeability and fracture aperture and roughness), (b) multi-phase flow properties (capillary entry pressure and relative permeability), (c) mechanical characteristics, including stiffness (i.e., elastic moduli for intact rocks and normal stiffness for fractures), strength (cohesion, friction angle and fracture toughness), and poroelastic response (Biot's coefficient), and (d) time-dependent behavior of the rock (compaction creep). The experiments alone cannot capture the complex dynamics of CO2 flow underground, but they provide critical insights into short-term alteration mechanisms of rock with implications to geologic CO2 storage. Studying naturally altered rocks, extending the experiments to tens-of-meters-scale underground rock laboratories, and bringing together experimental observations and numerical simulations are valuable for the advance in the understanding of CHM processes and upscaling them across space and time.

Carbon capture and storage (CCS) in deep geological formations at the scale of gigatonnes per year is an integral component of any real-world solution to mitigate the climate change crisis. The safety and effectiveness of CCS require that the injected CO2 permanently resides underground. Concerns about CO2 leakage are linked to buoyancy-driven CO2 rise through geological formations. Appropriate geological settings for large-scale CCS deployment should include low-permeability, k, and high-gas-entry pressure, p0, caprock layers, e.g., shales, to minimize CO2 migration out of the more permeable storage formations (Kivi et al. 2022a). Assessment of the effectiveness of large-scale CCS requires basin-scale numerical simulations of subsurface CO2 flow and transport in 3D. Such simulations are computationally demanding, limiting the existing estimates of the CO2 leakage risk to multi-century periods. Herein, we develop a computationally efficient, physically-sound numerical model to constrain the CO2 leakage risk at the basin scale and over geological time scales (millions of years), considering the effect of heterogeneities and structural settings.

Reservoir-triggered seismicity commonly occurs as a result of reservoir impoundment. In particular, the Nova Ponte reservoir triggered a series of earthquakes, including the 1998 M4.0 earthquake, which represents the second-largest earthquake triggered by reservoir impoundment in Brazil. The earthquake occurred after prolonged seismic activity following reservoir impoundment starting in 1993. After more than two decades, the mechanisms governing these earthquakes and their relation with the spatiotemporal evolution of the seismic events are still poorly understood. Here, we explain the causal mechanisms of the two largest earthquakes: an initial response M3.5 in 1995 and the delayed M4.0 in 1998. To this end, we numerically simulate the poromechanical subsurface response to reservoir impoundment using a 3D model that includes three geological layers down to 10 km depth. From the proposed potential nodal planes of the 1995 M3.5 earthquake, we show that the earthquake has most likely occurred on a vertical, E-W-oriented strike-slip fault with a reverse-displacement component. Deviatoric stresses generated by the water column loading on the surface, superimposed by undrained pore pressure enhancement in deep low-permeability layers can explain the fault reactivation. We find that for the 1998 M4.0 earthquake to occur, conductive flow pathways with permeability as high as 6.6·10-15 m2 should exist to transmit pore pressure to a deep critically oriented fault. Our analysis raises the importance of accounting for coupled poromechanical mechanisms controlling fault stability, hydromechanical properties of different rock layers, and realistic shape of the reservoir to accurately assess the potential for reservoir-triggered seismicity. We conclude that reliable forecasting models require accurate subsurface characterization before reservoir filling to enable managing the associated reservoir-triggered seismicity.

Geo-energies, such as geothermal energy, geologic carbon storage, and subsurface energy storage, will play a relevant role in reaching carbon neutrality and allowing net-carbon removal towards the midcentury. Geo-energies imply fluid injection into and/or production from the subsurface, which alter the initial effective stress state and may destabilize fractures and faults, thereby inducing seismicity. Understanding the processes that control induced seismicity is paramount to develop reliable forecasting tools to manage induced earthquakes and keep them below undesired levels. Accurately modeling the processes that occur during fracture/fault slip leading to induced seismicity is challenging because coupled thermo-hydro-mechanical-chemical (THMC) processes interact with each other: (1) fluid injection causes pore pressure buildup that changes total stress and deforms the rock, (2) deformation leads to permeability changes that affect pore pressure diffusion, (3) fluids reach the injection formation at a colder temperature than that of the rock, which cools down the vicinity of the well, causing changes in the fluid properties (density, viscosity, enthalpy, heat capacity) and cooling-induced stress reduction, (4) the injected fluids are not in chemical equilibrium with the host rock, leading to geochemical reactions of mineral dissolution/precipitation that may alter rock properties, in particular, the shear strength. In the framework of GEoREST (www.georest.eu), a Starting Grant from the European Research Council (ERC), we aim at developing forecasting tools for injection-induced seismicity by developing methodologies to efficiently simulate the coupled THMC processes that occur as a result of fluid injection, which allows us to improve the understanding of the mechanisms that trigger induced seismicity. To this end, we use the fully coupled finite element method software CODE_BRIGHT, which includes capabilities like friction following the Mohr-Coulomb failure crit

The effectiveness of Carbon Capture and Storage (CCS) as an imperative decarbonization technology relies on the sealing capacity of a fine-grained caprock to permanently store CO2 deep underground. Uncertainties in assessing the caprock sealing capacity increase with the spatial and temporal scales and may delay CCS deployment at the gigatonne scale. We have developed a computationally efficient transport model to capture the dynamics of basin-wide upward CO2 migration in a multi-layered setting over geological time scales. We find that massive capillary breakthrough and viscous flow of CO2, even through pervasively fractured caprocks, are unlikely to occur and compromise the storage security. Potential leakage from the injection reservoir is hampered by repetitive layering of overlying caprocks. This finding agrees with geologic intuition and should be understandable by the public, contributing to the development of climate policies around this technology with increased confidence that CO2 will be indefinitely contained in the subsurface.

The widespread development of geothermal energy is deemed to accelerate the transition to a low-carbon future. Hot Sedimentary Aquifers (HSA) provide cost-effective and non-intermittent geothermal resources. However, HSA development has reportedly been associated with seismic events, harming the public perception of exploiting these resources. This work digs deeper into thermo-hydro-mechanical (THM) mechanisms raised by water circulation in a HSA and their control on fault reactivation. We numerically simulate the problem by a 2D plane-strain model. The model consists of a porous and permeable hot aquifer sandwiched between the tight seal and base rocks and laterally bounded by two normal faults, representative of extensional tectonic environments. The horizontal injection-production well pairs are spaced 500 m apart at the middle of the aquifer, and the faults are located on each side of the doublet at a distance of 1 km. We consider two scenarios: low-permeability faults, mimicking a compartmentalized reservoir, and high-permeability faults, across which fluid flow takes place with further ease. We show that the fault permeability governs the hydraulic response of the reservoir. While the pore pressure slightly increases around the injector and decreases around the producer for the case of high-permeability faults, the compartmentalized reservoir experiences a global pore pressure decline. The latter is supported by the fact that the injected cold water is denser than the extracted hot water and occupies less space in the pore system. As soon as the thermal breakthrough occurs, which is after 12 years in the current setting, a more uniform temperature distribution across the doublet is established and the pressure begins to increase in the vicinity of the injector. Provided the high permeability of the reservoir rock, pore pressure and poroelastic stress perturbations impose rapid but minor effects on the fault stability. On the contrary, the cooling front formed

Carbon capture and storage in deep geological formations is necessary to achieve a meaningful reduction of anthropogenic CO2 emissions into the atmosphere. Given the buoyancy of the injected CO2, it is essential to adequately characterize the sealing caprocks commonly comprised of clay-rich formations, including shales. If the inherent anisotropy of shales is not considered, model prediction errors will propagate with time and space. To limit errors, the accurate experimental laboratory measurements should be scaled up and the in-situ behavior of the caprock should be studied in detail. Underground rock laboratories (URLs) offer a unique opportunity to investigate the caprock sealing capacity at a few meters scale in a well-defined and well-monitored environment. This perspective applies to the CO2 Long-term Periodic Injection Experiment (CO2LPIE) at the Swiss Mont Terri URL. In the experiment, it is planned to inject gaseous CO2 into Opalinus Clay, which is considered as a representative caprock for underground storage. Opalinus Clay shows large-scale anisotropic behavior due to the presence of bedding planes and heteorogeneities. We numerically simulate the CO2LPIE experiment using a 3D hydro-mechanical model and assuming linear poroelastic transverse isotropic behavior of the rock. We find that the CO2 is unlikely to penetrate the rock in free phase, while the diffusive front of dissolved CO2 in resident brine hardly propagates half a meter after two years of injection. The overpressure and induced deformation and stress changes preferentially develop along the bedding planes, although not sufficiently to lead to shear failure.

Guaranteeing the sealing capacity of caprocks becomes paramount as CO2 storage scales up to the gigaton scale. A significant number of laboratory experiments have been performed with samples of intact rock, showing that low-permeability and high-entry pressure caprocks have excellent sealing capacities to contain CO2 deep underground. However, discontinuities, such as bedding planes, fractures and faults, affect the rock properties at the field scale, being at the same time challenging to monitor in industrial-scale applications. To bridge these two spatial scales, Underground Research Laboratories (URLs) provide a perfect setting to investigate the field-scale sealing capacity of caprocks under a well-monitored environment. In particular, the CO2 Long-term Periodic Injection Experiment (CO2LPIE) at the Mont Terri rock laboratory, Switzerland, aims at quantifying the advance of CO2 in Opalinus Clay, an anisotropic clay-rich rock with bedding planes dipping 45° at the experiment location. To assist in the design of CO2LPIE and have an initial estimate of the system response, we perform plane-strain coupled Hydro-Mechanical simulations using a linear transversely isotropic poroelastic model of periodic CO2 injection for 20 years. Simulation results show that pore pressure changes and the resulting stress variations are controlled by the anisotropic behavior of the material, producing a preferential advance along the bedding planes. CO2 cannot penetrate into Opalinus Clay due to the strong capillary effects in the nanoscale pores, but advances dissolved into the resident brine. We find that the pore pressure oscillations imposed at the injection well are attenuated within tens of cm, requiring a close location of the monitoring boreholes with respect to the injection interval to observe the periodic signal. Article highlights: Underground rock laboratory experiments permit examining the caprock sealing capacity at a representative scale for CO2 storage;We per

Shear sonic wave velocity (Vs) has a wide variety of implications, from reservoir management and development to geomechanical and geophysical studies. In the current study, two approaches were adopted to predict shear sonic wave velocities (Vs) from several petrophysical well logs, including gamma ray (GR), density (RHOB), neutron (NPHI), and compressional sonic wave velocity (Vp). For this purpose, five intelligent models of random forest (RF), extra tree (ET), Gaussian process regression (GPR), and the integration of adaptive neuro fuzzy inference system (ANFIS) with differential evolution (DE) and imperialist competitive algorithm (ICA) optimizers were implemented. In the first approach, the target was estimated based only on Vp, and the second scenario predicted Vs from the integration of Vp, GR, RHOB, and NPHI inputs. In each scenario, 8061 data points belonging to an oilfield located in the southwest of Iran were investigated. The ET model showed a lower average absolute percent relative error (AAPRE) compared to other models for both approaches. Considering the first approach in which the Vp was the only input, the obtained AAPRE values for RF, ET, GPR, ANFIS + DE, and ANFIS + ICA models are 1.54%, 1.34%, 1.54%, 1.56%, and 1.57%, respectively. In the second scenario, the achieved AAPRE values for RF, ET, GPR, ANFIS + DE, and ANFIS + ICA models are 1.25%, 1.03%, 1.16%, 1.63%, and 1.49%, respectively. The Williams plot proved the validity of both one-input and four-inputs ET model. Regarding the ET model constructed based on only one variable,Williams plot interestingly showed that all 8061 data points are valid data. Also, the outcome of the Leverage approach for the ET model designed with four inputs highlighted that there are only 240 "out of leverage" data sets. In addition, only 169 data are suspected. Also, the sensitivity analysis results typified that the Vp has a higher effect on the target parameter (Vs) than other implemented inputs. Overall, the sec

Geologic carbon storage in deep saline aquifers has emerged as a promising technique to mitigate climate change. CO2 is buoyant at the storage conditions and tends to float over the resident brine jeopardizing long-term containment goals. Therefore, the caprock sealing capacity is of great importance and requires detailed assessment. We perform supercritical CO2 injection experiments on shaly caprock samples (intact caprock and fault zone) under representative subsurface conditions. We numerically simulate the experiments, satisfactorily reproducing the observed evolution trends. Simulation results highlight the dynamics of CO2 flow through the specimens with implications to CO2 leakage risk assessment in field practices. The large injection-induced overpressure drives CO2 in free phase into the caprock specimens. However, the relative permeability increase following the drainage path is insufficient to provoke an effective advancement of the free-phase CO2. As a result, the bulk CO2 front becomes almost immobile. This implies that the caprock sealing capacity is unlikely to be compromised by a rapid capillary breakthrough and the injected CO2 does not penetrate deep into the caprock. In the long term, the intrinsically slow molecular diffusion appears to dominate the migration of CO2 dissolved into brine. Nonetheless, the inherently tortuous nature of shaly caprock further holds back the diffusive flow, favoring safe underground storage of CO2 over geological time scales.

We present a comprehensive, publicly accessible database of injection-induced seismicity. The database is sourced from a comprehensive review of more than 500 published documents and contains information for 158 cases of induced earthquakes from around the world. The collected earthquakes are associated with a variety of geoenergy applications, which can be broadly categorized into geologic gas storage, geothermal energy development, shale gas fracturing, research projects and wastewater disposal. The compilation comprises more than 70 variables, including general project information, host rock properties, ‎in situ site characteristics, fault attributes, operational parameters, and recorded seismicity data (both overall seismic activities and the largest event sequence). The developed database opens up opportunities for improved understanding of the causative mechanisms of injection-induced seismicity and advancing on seismic hazard forecasting and mitigation.

Deep geothermal energy (DGE) represents an opportunity for a sustainable and carbon-free energy supply. One of the main concerns of DGE is induced seismicity that may produce damaging earthquakes, challenging its widespread exploitation. It is widely believed that the seismicity risk can be controlled by using doublet systems circulating water to minimize the injection-induced pressure changes. However, cold water reinjection may also give rise to thermal stresses within and beyond the cooled region, whose potential impacts on fault reactivation are less well understood. Here, we investigate by coupled thermo-hydro-mechanical modeling the processes that may lead to fault reactivation in a hot sedimentary aquifer (HSA) in which water is circulated through a doublet. We show that thermal stresses are transmitted much ahead of the cooled region and are likely to destabilize faults located far away from the doublet. Meanwhile, the fault permeability mainly controls the fault reactivation timing, which entails the importance of employing appropriate characterization methods. This investigation is crucial for understanding the mechanisms controlling induced seismicity associated with DGE in a HSA and allows the success of future DGE projects.

Carbon capture and storage in deep geological formations suggests a promising large-scale CO2 mitigation option. Currently available pathways to meet the Paris climate goal of limiting global warming to well below 2 ºC involve significant contributions of geologic carbon storage. Nonetheless, this mitigation technology is not exempt from challenges. In particular, the potential CO2 leakage through the caprock is a major concern. CO2 is less dense than the in-situ brine in deep saline formations and tends to float. The upward migration of the buoyant CO2, if causing leakage through the caprock, can put at stake the large-scale implementation of geologic carbon storage. Therefore, the assessment of the caprock sealing capacity is of paramount importance. This study provides an improved understanding of CO2 flow mechanisms across the caprock based on insights gained from numerical simulations of core-scale CO2 injections. We inject supercritical CO2 into a caprock sample under representative subsurface conditions. We parameterize a two-phase flow model using laboratory data and reproduce the CO2 injection experiments. Overall, we conclude that advective CO2 flow is unlikely to take place through a caprock with sufficiently high capillary entry pressure and low intrinsic permeability. The ubiquitous molecular diffusion principally dominates CO2 leakage. These findings favor long-term storage of CO2 underground. Nevertheless, diffusive leakage over geological time scales has yet to be assessed through field-scale numerical simulations.

This dataset comprises the input files for numerical simulation of 30-years cold water reinjection through a doublet for geothermal exploitation of a hot sedimentary aquifer (HSA) and the associated risk for reactivating distant faults. Numerical models explore the effect of fault permeability on the governing thermo-hydro-mechanical (THM) processes and the geomechanical response of the system. The models are 2D plane strain including a homogeneous and isotropic HSA laterally bounded by two opposite dipping normal faults. Following this brief explanation, the dataset has two folders, each containing data for a distinct model: - “THM_k=1e-19.gid” for simulating the geothermal system with the embedded faults having low permeability k=1·10-19 m2 - and - “THM_k=1e-16.gid” for simulating the geothermal system featured with high fault permeability k=1·10-16 m2. In each folder, there is a file with the name of the folder ended as “_gen.dat” which contains the input data of the model, including material properties, initial and boundary conditions and the time intervals. There is also a file ended as “_gri.dat” that includes the information on the mesh. The file “root.dat” includes the name of the model. To run the simulation, execute the Code_Bright executable “Cb_v9_3.exe” in a folder that contains the three input files and the executable.

Geologic storage of carbon dioxide (CO2), mainly in deep saline aquifers, has emerged as a key solution to reach the Paris Agreement goal of limiting the global temperature increase below 2ºC and effectively mitigate climate change. The injected CO2 is less dense at the storage condictions than the resident brine and tends to flow upward by buoyancy. Therefore, to achieve the primary objective of permanently storing CO2 underground during geological time scales, the host reservoir should be overlain by a low-permeability and high-entry pressure caprock that prevents CO2 escaping from the storage formation. Meanwhile, the caprock sealing capacity is of particular significance and yet to be assessed in more detail. In this presentation, we aim at shedding light on the flow processes governing potential CO2 leakage through shaly caprocks by combining experimental observations and numerical simulations. We present breakthrough experiments on Opalinus Clay, which is a representative caprock for CO2 storage. These experiments reproduce supercritical CO2 intrusion and flow through the caprock sample under representative reservoir conditions. Next, we address numerical simulation of the breakthrough experiments using a twophase flow model in deformable porous media to provide a mechanistic interpretation of experimental observations. Overall, we conclude that CO2 leakage through the caprock is dominated by molecular diffusion rather than by rapid bulk volumetric advection.

Carbon capture and geologic storage, mainly in deep saline aquifers, is extensively considered as an essential component of any strategy to achieve carbon neutrality and effectively mitigate climate change. At pressure and temperature conditions relevant to CO2 storage in sedimentary formations, CO2 is less dense than the resident brine and tends to float, threatening the long-term storage of CO2 underground [1]. Therefore, successful deployment of geologic CO2 storage and its public acceptance is primarily a matter of ensuring the sealing capacity of caprock overlying the storage reservoir and yet to be investigated. Bringing together experimental methods and a numerical interpretation scheme, we aim at shedding light on the processes governing CO2 intrusion and flow through low-permeability shaly caprock. We perform CO2 injection experiments on Opalinus Clay samples retrieved from the Mont Terri underground rock laboratory in Switzerland. Two types of Opalinus Clay are examined: intact specimen, representing an ideal caprock for CO2 storage, and remolded shale, representing the potential shear zone in the caprock [2]. The latter is found to possess relatively higher intrinsic permeability and lower capillary entry pressure. We parameterize a two-phase flow model in deformable porous media using appropriate hydromechanical properties and replicate experimental observations. Simulation results highlight three concomitant flow mechanisms: molecular diffusion of CO2, bulk volumetric advection of CO2, and brine advection transporting dissolved CO2. The bulk CO2 intrusion is confined to the lowermost portion of the specimen and remains unable to trigger an effective increase in the relative permeability to CO2. Therefore, advective CO2 migration is minor. We conclude that rapid capillary breakthrough of CO2 is unlikely to take place and compromise the sealing capacity of nonfractured caprock. The relatively slow diffusive flow appears to purely dominate leakage in the l

It is widely accepted that massive deployment of Carbon Capture and Storage (CCS) in geologic media at the gigatonne scale should be part of the mitigating pathways toward net-zero CO2 emissions. For a successful geologic CO2 storage, the caprock sealing capacity and the associated governing processes have to be assessed in detail. In this contribution, we aim at improving our understanding of hydromechanical processes induced by dynamics of CO2 leakage through intact shaly caprocks. To this end, we perform laboratory experiments on supercritical CO2 injection into a caprock sample under representative subsurface conditions. We numerically simulate the process to provide a mechanistic interpretation of experimental observations. Overall, we find that CO2 intrusion into the pore network increases pore pressure and triggers hydromechanical coupling effects, mainly causing the specimen to expand after an initial transient compaction. The pressureinduced rock expansion slightly enhances the porosity and permeability, promoting CO2 flow close to the upstream. However, the high entry pressure and ultra-low effective permeability of the non-wetting phase limit the bulk volumetric penetration of CO2 deep into the caprock. Therefore, advective flow of CO2 is restricted to the lowermost portion of intact caprock, whereas diffusion extends along the whole caprock sample.

We are performing a series of coupled hydro-mechanical (HM) simulations to model CO2 flow through Opalinus Clay at the Mont Terri rock laboratory in the CO2 Long-term Periodic Injection Experiment (CO2LPIE). CO2LPIE aims at inter-disciplinary investigations of the caprock sealing capacity in geologic CO2 storage in a highly monitored environment at the underground laboratory scale. Numerical modeling allows us to gain knowledge on the dynamic processes resulting from CO2 periodic injection and to assist the experimental design. The cyclic injection parameters (i.e., the period and the amplitude) have to be optimized for the field experiment and therefore different values are taken into account. Opalinus Clay is a claystone with nanoDarcy permeability that contains well developed bedding planes responsible for its anisotropic HM behavior. The hydraulic anisotropy is defined by a permeability parallel to the bedding planes being three times the one perpendicular to it. Additionally, the drained Young’s modulus is measured to be 1.7 GPa parallel and 2.1 GPa perpendicular to bedding. Excavation reports by swisstopo document a SSEdip of 45° for the bedding planes at the experiment location. CO2 injection generates a mean overpressure of 1 MPa into the brine that propagates into the formation. The differential pressure between CO2 and formation water, i.e., capillary pressure, is lower than the entry pressure and thus, CO2 diffuses through the pores but does not advect in free phase. The liquid overpressure distribution is distorted by the hydraulic anisotropy, preferentially advancing along the bedding planes, as the associated permeability is higher than the one perpendicular to the bedding. The pore pressure buildup induces a poromechanical stress increase and an expansion of the rock that leads to a permeability enhancement of up to two orders of magnitude. The cyclic stimulation propagates trough the domain faster and with a lag time and an attenuation, both of which

Global warming brought upon by anthropogenic CO2 emissions into the atmosphere is causing significant impacts on the Earth and represents one of the major concerns of the current century. To be controlled, it is widely accepted that huge amounts of CO2 at the gigatonne scale have to be captured and injected back into the underground in a process known as Carbon Capture and Storage (CCS). As CO2 is less dense than the in-situ brine, it tends to flow upward out of the storage reservoir by buoyancy and the injection overpressure. A laterally-extensive and thick nonfractured caprock possessing low permeability and high entry capillary pressure is commonly expected to keep CO2 within the host reservoir. However, the potential risks of CO2 leakage through the intact caprock need thorough assessment. This contribution brings together experimental observations and numerical simulations to inspect the sealing capacity of an intact shaly caprock and render an in-depth understanding of the governing flow mechanisms. Reproducing the subsurface conditions of CO2 intrusion and flow through the caprock, breakthrough experiments are conducted on Opalinus Clay as a representative caprock for CO2 storage. The adopted approach consists of injecting supercritical CO2 into the caprock sample lying between two permeable porous disks, all initially saturated with brine. Supplementary experiments are also performed to characterize the pore structure and hydromechanical properties of the specimen. The extracted properties are used to parameterize a two-phase flow model in deformable porous media and simulate the breakthrough experiment carried out on Opalinus Clay to make a mechanistic interpretation of the experimental observations. Simulation results reveal three concomitant CO2 flow mechanisms into and through the caprock: molecular diffusion, bulk volumetric advection, and transported CO2 dissolved in the advected brine. It is inferred that the high entry pressure and low effective perm

Geologic carbon storage is needed to meet the climate goal of limiting global warming to 1.5 ºC. Injecting in deep sedimentary formations brings CO2 to a supercritical state, yet less dense than the resident brine making it buoyant. Therefore, the assessment of the sealing capacity of the caprock lying above the storage reservoir is of paramount importance for the widespread deployment of geologic carbon storage. We perform laboratory-scale supercritical CO2 injection into a representative caprock sample and employ numerical simulations to provide an in-depth understanding of CO2 leakage mechanisms. We explore the effect of relative permeability curves on the potential CO2 leakage through the caprock. We show that capillary breakthrough is unlikely to take place across a non-fractured caprock with low intrinsic permeability and high entry pressure. Rather, CO2 leakage is dominated by the intrinsically slow molecular diffusion, favoring safe storage of CO2 over geological time scales.