Suchergebnisse

Fractures control fluid flow and the coupled geomechanical response of geological media in many geo-engineering and geo-energy applications. For instance, fluid flow and deformation mainly occur along fractures in enhanced geothermal systems (EGS), underground radioactive waste repositories and CO2 storage (Rutqvist and Stephansson, 2003). Coupled thermo-hydro-mechanical (THM) processes are induced in rock masses as a result of perturbations in the pore pressure, e.g., fluid injection and production, and/or temperature, e.g., cold fluid injection and disposal of radioactive waste. One example of these coupled processes is the fracture opening as a result of pore pressure increase, which enhances fracture permeability (Tsang, 1999). The geo-engineering and geo-energy applications of interest involve large fractured rock masses that include multiple fractures. Numerically modeling of coupled hydro-mechanical (HM) processes while considering a large number of fractures is extremely challenging (Lei et al., 2017). We propose using a continuum mechanics approach to model fractures. Before studying fractured rock masses containing many fractures, we focus on a single fracture to fully understand the hydro-mechanical behavior of a fracture to a constant injection flow rate. Here, we present some preliminary results. ; The authors acknowledge funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST (www.georest.eu) (Grant agreement No. 801809). ; Peer reviewed

Geologic carbon storage is required for achieving negative CO2 emissions to deal with the climate crisis. The classical concept of CO2 storage consists in injecting CO2 in geological formations at depths greater than 800 m, where CO2 becomes a dense fluid, minimizing storage volume. Yet CO2 has a density lower than the resident brine and tends to float, challenging the widespread deployment of geologic carbon storage. Here, we propose for the first time to store CO2 in supercritical reservoirs to reduce the buoyancy‐driven leakage risk. Supercritical reservoirs are found at drilling‐reachable depth in volcanic areas, where high pressure (p > 21.8 MPa) and temperature (T > 374°C) imply CO2 is denser than water. We estimate that a CO2 storage capacity in the range of 50–500 Mt yr−1 could be achieved for every 100 injection wells. Carbon storage in supercritical reservoirs is an appealing alternative to the traditional approach. ; The authors acknowledge funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Programme through the Starting Grant GEoREST (www.georest.eu), grant agreement No. 801809 and the support by the Spanish Ministry of Science and Innovation (Project CEX2018‐000794‐S); F. P. acknowledges funding from the Deutsche Forschungsgemeinschaft (DFG, German Research Foundation)—project number PA 3451/1‐1. ; Peer reviewed

3rd Workshop of CODE-BRIGHT Users. 2011, Barcelona. ; Anthropogenic CO2 emissions are expected to continue to increase worldwide in the next decades. This could dramatically increase CO2 concentrations in the atmosphere. One potential mitigation action is CO2 permanent storage in deep saline aquifers. CO2 is injected as a supercritical fluid (temperature and pressure higher than 31.1 ºC and 7.38 MPa, respectively) so as to obtain a relatively high density that minimizes the volume occupied by this greenhouse gas. CO2 density is highly dependent on temperature and pressure because of its high compressibility (Vilarrasa et al., 2010a), adopting a wide range of values (450-800 kg/m3). Since CO2 is lighter than brine, flow is affected by buoyancy. Buoyancy produces an upslope migration of the CO2 bubble in sloping aquifers. The post-injection fate of CO2 in sloping aquifers has been investigated (e.g. Hesse et al., 2008; Elenius et al., 2010) but without considering the actual shape of the CO2 bubble at the end of injection. However, the shape of the CO2 bubble at the end of injection affects its posterior evolution (McMinn & Juanes, 2009). Gasda et al. (2008) studied the effect of a slope up to 1º during the injection period using a 2D model, which represents injection through a horizontal well. However, CO2 injection through a vertical well, which implies a 3D geometry, has not yet been investigated.CO2 will be injected in the Hontomín CO2 pilot storage site, Burgos (Spain). Hontomín is the site for the CO2 storage Technology Demonstration Plant (TDP) of the Compostilla OXYCFB300 project, operated by Energy City Foundation (CIUDEN). CO2 will be injected through a vertical well in a flank of a dome-like structure with a slope close to 20º at a depth around 1450 m. CO2 injection tests are aimed to gain knowledge on trapping mechanisms and CO2 bubble and pressure evolution. Pressure evolution is important for assessing the caprock integrity and to avoid the open up of preferential paths for CO2 leakage (Vilarrasa et al., 2010b, 2011). These processes are relatively well known in horizontal aquifers, but a high uncertainty still exists in sloping aquifers. ; V.V. wishes to acknowledge the Spanish Ministry of Science and Innovation (MCI), through the "Formación de Profesorado Universitario", and the "Colegio de Ingenieros de Caminos, Canales y Puertos – Catalunya" for their financial support. Additionally, we would like to acknowledge the Spanish Government (Ministry of Industry, Tourism and Trade) through the CUIDEN foundation (project ALM/09/18; www.ciuden.es) and the 'MUSTANG' project (from the European Community's Seventh Framework Programme FP7/2007-2013 under grant agreement nº227286 ; www.co2mustang.eu) for their financial support. ; Peer reviewed

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. ; Open Access funding provided thanks to the CRUE-CSIC agreement with Springer Nature. The research presented in this article was funded by the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST (www.georest.eu) (Grant agreement No. 801809). This work was partly supported by the Spanish Ministry of Science and Innovation through the grant CEX2018-000794-S, funded by MCIN/AEI/10.13039/501100011033. Additional support was provided by the grant IJC2020-043809-I funded by MCIN/AEI/10.13039/501100011033 and the European Union NextGenerationEU/PRTR. This study also received the support from US DOE through CarbonSAFE Macon County Project DE-FE0029381. Open access funding provided by the Spanish National Research Council (CSIC). ; Peer reviewed

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. ; I.R.K. and V.V. acknowledge funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST (www.georest.eu) (Grant agreement No. 801809). IDAEA-CSIC is a Centre of Excellence Severo Ochoa (Spanish Ministry of Science and Innovation, Project CEX2018-000794-S). R.M. is thankful for the support from US DOE through CarbonSAFE Macon County Project DE-FE0029381. ; Peer reviewed

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. ; I.R.K. and V.V. acknowledge funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST (www.georest.eu) (Grant agreement No. 801809). IDAEA-CSIC is a Centre of Excellence Severo Ochoa (Spanish Ministry of Science and Innovation, Project CEX2018-000794-S). R.M. is thankful for the support from US DOE through CarbonSAFE Macon County Project DE-FE0029381. ; Peer reviewed

This Special Issue originates from selected contributions at the International Conference on Coupled Processes in Fractured Geological Media: Observation, Modeling, and Application (CouFrac2018). CouFrac2018 has been the first CouFrac conference focusing on coupled processes in fractured media, providing a platform for international discussion, communication and networking on this emerging topic. The conference was held in Wuhan, China, between 12 and 14th of November, 2018. ; K.-B.M. acknowledges support from the Institute of Engineering Research, Seoul National University. J.R. acknowledges support from the U.S. Department of Energy to the Lawrence Berkeley National Laboratory under contract No. DE-AC02-05CH11231. V.V. acknowledges funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Programme through the Starting Grant GEoREST, grant agreement No. 801809 (www.georest.eu). ; Peer reviewed

The emission of huge amounts of anthropogenic CO2 into the atmosphere have given rise to global warming and therefore climate change. Currently, it is widely accepted that geologic storage of CO2 in deep underground formations has to be part of the solution to mitigate these harmful consequences (IPCC, 2018). The injected CO2 is a non-wetting fluid in the reservoir rock and it is also lighter than the in-situ brine, leading to upward buoyant transport of CO2 across the storage reservoir. The migration of CO2 out of the reservoir is supposed to be principally restricted by a low-permeability and high-entry pressure caprock lying immediately above it. Therefore, the successful and safe retainment of CO2 in place over geologic time scales is strongly controlled by the sealing capacity of the caprock. As CO2 gets in contact with the caprock, the concentration gradient of the dissolved CO2 into brine drives molecular diffusion of the non-wetting fluid out of the storage repository through the fluid-filled interconnected pore network of the caprock (Busch et al., 2008). On the contrary, the bulk penetration of CO2 as a free phase into the caprock encounters capillary resistance imposed by fluid-fluid and fluid-rock interfacial forces operating at tight pore throats. The injection-induced excess pressure and buoyancy forces may increase the differential pressure between CO2 and brine at the reservoir-caprock interface. If the overpressure of the non-wetting fluid exceeds the entry capillary pressure P0 acting at the largest pore throats, it starts invading the caprock. Further increase in the differential pressure overcoming another capillary threshold, termed breakthrough pressure Pbrth initiates a continuous filament of CO2 across the pore system. From this point on, the two-phase flow dominates the volumetric displacement of CO2. It is generally believed that the pressure-driven bulk flow of the non-wetting fluid mainly governs the potential leakage through the intact caprock and that molecular diffusive loss toward the surface is negligible (Song and Zhang, 2013). However, to arrive at a fundamental understanding of the CO2 transport behavior and distinguish between the prevailing leakage mechanisms, further experimental investigations under representative reservoir conditions are required. These experimental studies should be accompanied by appropriate interpretation techniques to accurately deal with the CO2-brine-rock system complexities. The main objective of this study is to combine methods from two complementary disciplines of experimental observations and numerical simulations to get a better insight into the dominant leakage mechanisms of CO2 through the caprock. Our focus is on the potential leakage through the rock matrix. Laboratory tests on an analogous caprock sample are first carried out under the in-situ conditions with the primary goal of evaluating CO2 penetration and flow properties across the caprock. Experimental results are then used to parameterize a two-phase flow model for the numerical simulation and interpretation of the core-scale CO2 breakthrough and flow behavior. ; I.R.K. and V.V. acknowledge funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST (www.georest.eu) (Grant agreement No. 801809). R.M. is thankful for the support from US DOE through CarbonSAFE Macon County Project DE-FE0029381. ; Peer reviewed

Geothermal systems, including hydrothermal systems [1], enhanced geothermal systems (EGS) [2], and superhot or supercritical systems [3–5], are receiving an increasing interest because they provide carbon-free energy that is necessary to shift the current dependency on fossil fuels and thus significantly reduce CO2 emissions to the atmosphere [6]. Geothermal energy can potentially provide continuous energy output without daily or seasonal fluctuations—a strong advantage when compared to other renewable sources—and negative emissions if CO2 is used as the working fluid [7–9]. However, the deployment of geothermal systems is being hindered by insufficient permeability of the reservoir rock [10], excessive induced seismicity during reservoir stimulation [11], and geochemical reactions accelerated by high temperature that lead to corrosion and scaling [12]. To overcome these challenges, interdisciplinary approaches that investigate relevant processes occurring during geothermal energy exploitation are necessary. The focus of this special issue is on geomechanical aspects of geothermal systems, including coupled processes occurring in multiphase systems, experimental characterization of rock and inelastic deformation that may induce seismicity, and geochemistry of geothermal systems. This special issue compiles the most recent advances in geothermal energy and combines the complex interactions between geomechanics, fluid flow, and geochemical reactions. ; The guest editors thank all the authors of this special issue and their perseverance during the publication process. We also thank the many anonymous reviewers who helped to evaluate and contributed to these papers. The guest editors would also like to acknowledge their sources of funding. V.V. acknowledges funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Programme through the Starting Grant GEoREST, grant agreement No. 801809 (http://www.georest.eu). R.M. is thankful for the support provided by the UIUC-ZJU Research Collaboration program (grant # 083650). The contribution of F.P. is funded by the Deutsche Forschungsgemeinschaft (DFG, German Research Foundation)—project number PA 3451/1-1. ; Peer reviewed

Clear understanding of coupled hydromechanical effects, such as ground deformation, induced microseismicity and fault reactivation, will be crucial to convince the public that geologic carbon storage is secure. These effects depend on hydromechanical properties, which are usually determined at metric scale. However, their value at the field scale may differ in orders of magnitude. To address this shortcoming, we propose a hydromechanical characterization test to estimate the hydromechanical properties of the aquifer and caprock at the field scale. We propose injecting water at high pressure and, possibly, low temperature while monitoring fluid pressure and rock deformation. Here, we analyze the problem and perform numerical simulations and a dimensional analysis of the hydromechanical equations to obtain curves for overpressure and vertical displacement as a function of the volumetric strain term. We find that these curves do not depend much on the Poisson ratio, except for the dimensionless vertical displacement at the top of the caprock, which does. We can then estimate the values of the Young's modulus and the Poisson ratio of the aquifer and the caprock by introducing field measurements in these plots. Hydraulic parameters can be determined from the interpretation of fluid pressure evolution in the aquifer. Reverse-water level fluctuations are observed, i.e. fluid pressure drops in the caprock as a result of the induced deformation that undergoes the aquifer-caprock system when injecting in the aquifer. We find that induced microseismicity is more likely to occur in the aquifer than in the caprock and depends little on their stiffness. Monitoring microseismicity is a useful tool to track the opening of fractures. The propagation pattern depends on the stress regime, i.e. normal, strike slip or reverse faulting. The onset of microseismicity in the caprock can be used to define the maximum sustainable injection pressure to ensure a permanent CO2 storage. ; This work has been funded by Fundación Ciudad de la Energía (Spanish Government) (www.ciuden.es) through the project ALM/09/018 and by the European Union through the "European Energy Programme for Recovery" and the Compostilla OXYCFB300 project. We also want to acknowledge the financial support received from the 'MUSTANG' (www.co2mustang.eu) and 'PANACEA' (www.panacea-co2.org) projects (from the European Community's Seventh Framework Programme FP7/2007-2013 under grant agreements n° 227286 and n° 282900, respectively). ; Peer reviewed

Deep geological media will be intensively utilized for achieving carbon neutrality within the next few decades (Friedmann et al., 2020). Widespread deployment of geothermal energy production, geologic carbon storage, and subsurface energy storage will require massive injection and production of fluids in porous reservoir rock and fractured low permeable formations. Fluid injection and production causes pore pressure and temperature perturbations that induce deformation and stress changes (Tsang, 1991). These pressure, temperature, and stress changes affect fracture and fault stability, leading to aseismic and/or seismic slip if failure conditions are reached (Cornet et al., 1997). Understanding how coupled processes control fluid flow and fracture stability is crucial for the success of geo-energy projects. While small shear slip, in the order of mm to cm, can be beneficial to enhance the permeability of the rock mass (Rutqvist and Stephansson, 2003), larger slip, in the order of tens of cm over rupture areas on the scale of hundred meters in diameter, may induce earthquakes that could be felt on the surface, causing nuisance to the local populations and eventually damaging structures and infrastructures (Kanamori and Brodsky, 2004). Numerical simulations of coupled processes are a useful tool to understand the interactions between pore pressure, temperatures, and stress in fractured rock as a result of fluid injection and/or extraction. In this study, we aim at identifying the long-term thermo-hydro-mechanical (THM) response of a fractured reservoir to water injection and production. ; V.V. acknowledges funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST (www.georest.eu) (Grant agreement No. 801809). R.M. is thankful for the support from US DOE through CarbonSAFE Macon County Project DE-FE0029381. F.P. acknowledges funding from the Deutsche Forschungsgemeinschaft (DFG, German Research Foundation) – project number PA 3451/1-1. ; Peer reviewed

The injection of supercritical carbon dioxide (CO2) in deep saline aquifers leads to the formation of a CO2 rich phase plume that tends to float over the resident brine. As pressure builds up, CO2 density will increase because of its high compressibility. Current analytical solutions do not account for CO2 compressibility and consider a volumetric injection rate that is uniformly distributed along the whole thickness of the aquifer, which is unrealistic. Furthermore, the slope of the CO2 pressure with respect to the logarithm of distance obtained from these solutions differs from that of numerical solutions. We develop a semianalytical solution for the CO2 plume geometry and fluid pressure evolution, accounting for CO2 compressibility and buoyancy effects in the injection well, so CO2 is not uniformly injected along the aquifer thickness. We formulate the problem in terms of a CO2 potential that facilitates solution in horizontal layers, with which we discretize the aquifer. Capillary pressure is considered at the interface between the CO2 rich phase and the aqueous phase. When a prescribed CO2 mass flow rate is injected, CO2 advances initially through the top portion of the aquifer. As CO2 is being injected, the CO2 plume advances not only laterally, but also vertically downwards. However, the CO2 plume does not necessarily occupy the whole thickness of the aquifer. We found that even in the cases in which the CO2 plume reaches the bottom of the aquifer, most of the injected CO2 enters the aquifer through the layers at the top. Both CO2 plume position and fluid pressure compare well with numerical simulations. This solution permits quick evaluations of the CO2 plume position and fluid pressure distribution when injecting supercritical CO2 in a deep saline aquifer. © 2013 Springer Science+Business Media Dordrecht. ; This work has been funded by Fundación Ciudad de la Energía (Spanish Government) (www.ciuden.es) and 35 by the European Union through the "European Energy Programme for Recovery" and the Compostilla OXYCFB300 project. We also want to acknowledge the financial support received from the 'MUSTANG' (www.co2mustang.eu) and 'PANACEA' (www.panacea-co2.org) projects (from the European Community's Seventh Framework Programme FP7/2007-2013 under grant agreements nº 227286 and nº 282900, respectively). ; Peer Reviewed

CO2 will remain in supercritical (SC) state (i.e. p>7.382MPa and T>31.04°C) under the pressure (p) and temperature (T) conditions appropriate for geological storage. Thus, it is usually assumed that CO2 will reach the aquifer in SC conditions. However, inflowing CO2 does not need to be in thermal equilibrium with the aquifer. In fact, surface operations are simpler for liquid than for SC CO2, because CO2 is transported in liquid state. Yet, problems might arise because of thermal stresses induced by cold CO2 injection and because of phase changes in the injection tubing or in the formation. Here, we propose liquid CO2 injection and analyze its evolution and the thermo-hydro-mechanical response of the formation and the caprock. We find that injecting CO2 in liquid state is energetically more efficient than in SC state because liquid CO2 is denser than SC CO2, leading to a lower overpressure not only at the wellhead, but also in the reservoir because a smaller fluid volume is displaced. Cold CO2 injection cools down the formation around the injection well. Further away, CO2 equilibrates thermally with the medium in an abrupt front. The liquid CO2 region close to the injection well advances far behind the SC CO2 interface. While the SC CO2 region is dominated by gravity override, the liquid CO2 region displays a steeper front because viscous forces dominate (liquid CO2 is not only denser, but also more viscous than SC CO2). The temperature decrease close to the injection well induces a stress reduction due to thermal contraction of the media. This can lead to shear slip of pre-existing fractures in the aquifer for large temperature contrasts in stiff rocks, which could enhance injectivity. In contrast, the mechanical stability of the caprock is improved in stress regimes where the maximum principal stress is the vertical. © 2013 Elsevier Ltd. ; V.V. wishes to acknowledge the Spanish Ministry of Science and Innovation (MCI), through the "Formación de Profesorado Universitario" Program, and the "Colegio de Ingenieros de Caminos, Canales y Puertos – Catalunya" for their financial support. This work has been funded by Fundación Ciudad de la Energía (Spanish Government) (www.ciuden.es) through the project ALM/09/018 and by the European Union through the "European Energy Programme for Recovery" and the Compostilla OXYCFB300 project. We also want to acknowledge the financial support received from the 'MUSTANG' (www.co2mustang.eu) and 'PANACEA' (www.panacea-co2.org) projects (from the European Community's Seventh Framework Programme FP7/2007–2013 under grant agreements nos. 227286 and 282900, respectively). ; Peer Reviewed

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. ; I.R.K. and V.V. acknowledge funding from the European Research Council (ERC) under the ‎European Union's Horizon 2020 Research and Innovation Program through the Starting Grant ‎GEoREST (http://www.georest.eu) under Grant agreement No. 801809. I.R.K. also acknowledges support by the grant IJC2020-043809-I funded by MCIN/AEI/ 10.13039/501100011033 and the European Union NextGenerationEU/PRTR. IDAEA-CSIC is a Centre of Excellence Severo Ochoa (Spanish ‎Ministry of Science and Innovation, Grant CEX2018-000794-S funded by MCIN/AEI/ 10.13039/501100011033). Additional funding was provided to J.R. by the U.S. Department of Energy under contract No. DE-AC0205CH11231 to the Lawrence Berkeley National Laboratory and to E.P. through the grant RYC2020-029225-I funded by MCIN/AEI/ 10.13039/501100011033. ; Peer reviewed

The offshore Castor Underground Gas Storage (UGS) project had to be halted after gas injection triggered three M4 earthquakes, each larger than any ever induced by UGS. The mechanisms that induced seismicity in the crystalline basement at 5–10 km depth after gas injection at 1.7 km depth remain unknown. Here, we propose a combination of mechanisms to explain the observed seismicity. First, the critically stressed Amposta fault, bounding the storage formation, crept by the superposition of well‐known overpressure effects and buoyancy of the relatively light injected gas. This aseismic slip brought an unmapped critically stressed fault in the hydraulically disconnected crystalline basement to failure. We attribute the delay between induced earthquakes to the pressure drop associated to expansion of areas where earthquakes slips cause further instabilities. Earthquakes occur only after these pressure drops have dissipated. Understanding triggering mechanisms is key to forecast induced seismicity and successfully design deep underground operations. ; The authors would like to acknowledge Álvaro González for sharing the catalogs that were used in Cesca et al. (2014). Funding: Víctor Vilarrasa acknowledges funding from the European Research Council (ERC) under the European Union's Horizon 2020 Research and Innovation Program through the Starting Grant GEoREST (www.georest.eu) (grant agreement No. 801809). Antonio Villaseñor acknowledges funding from Spanish Ministry of Science and Innovation grant CGL2017‐88864‐R. IDAEA‐CSIC is a Center of Excellence Severo Ochoa (Spanish Ministry of Science and Innovation, Project CEX2018‐000794‐S). ICM‐CSIC is a Center of Excellence Severo Ochoa (Spanish Ministry of Science and Innovation, Project CEX2019‐000928‐S). ; Peer reviewed