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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.

Geologic carbon storage, as well as other geo-energy applications, such as geothermal energy, seasonal natural gas storage and subsurface energy storage imply fluid injection and/or extraction that causes changes in rock stress field and may induce (micro)seismicity. If felt, seismicity has a negative effect on public perception and may jeopardize wellbore stability and damage infrastructure. Thus, induced earthquakes should be minimized to successfully deploy geo-energies. However, numerous processes may trigger induced seismicity, which contribute to making it complex and translates into a limited forecast ability of current predictive models. We review the triggering mechanisms of induced seismicity. Specifically, we analyze (1) the impact of pore pressure evolution and the effect that properties of the injected fluid have on fracture and/or fault stability; (2) non-isothermal effects caused by the fact that the injected fluid usually reaches the injection formation at a lower temperature than that of the rock, inducing rock contraction, thermal stress reduction and stress redistribution around the cooled region; (3) local stress changes induced when low-permeability faults cross the injection formation, which may reduce their stability and eventually cause fault reactivation; (4) stress transfer caused by seismic or aseismic slip; and (5) geochemical effects, which may be especially relevant in carbonate-containing formations. We also review characterization techniques developed by the authors to reduce the uncertainty in rock properties and subsurface heterogeneity both for the screening of injection sites and for the operation of projects. Based on the review, we propose a methodology based on proper site characterization, monitoring and pressure management to minimize induced seismicity.

One of the most promising ways to significantly reduce greenhouse gases emissions, while carbon-free energy sources are developed, is Carbon Capture and Storage (CCS). Non-isothermal effects play a major role in all stages of CCS. In this paper, we review the literature on thermal effects related to CCS, which is receiving an increasing interest as a result of the awareness that the comprehension of non-isothermal processes is crucial for a successful deployment of CCS projects. We start by reviewing CO2 transport, which connects the regions where CO2 is captured with suitable geostorage sites. The optimal conditions for CO2 transport, both onshore (through pipelines) and offshore (through pipelines or ships), are such that CO2 stays in liquid state. To minimize costs, CO2 should ideally be injected at the wellhead in similar pressure and temperature conditions as it is delivered by transport. To optimize the injection conditions, coupled wellbore and reservoir simulators that solve the strongly non-linear problem of CO2 pressure, temperature and density within the wellbore and non-isothermal two-phase flow within the storage formation have been developed. CO2 in its way down the injection well heats up due to compression and friction at a lower rate than the geothermal gradient, and thus, reaches the storage formation at a lower temperature than that of the rock. Inside the storage formation, CO2 injection induces temperature changes due to the advection of the cool injected CO2, the Joule-Thomson cooling effect, endothermic water vaporization and exothermic CO2 dissolution. These thermal effects lead to thermo-hydro-mechanical-chemical coupled processes with non-trivial interpretations. These coupled processes also play a relevant role in “Utilization” options that may provide an added value to the injected CO2, such as Enhanced Oil Recovery (EOR), Enhanced Coal Bed Methane (ECBM) and geothermal energy extraction combined with CO2 storage. If the injected CO2 leaks through faults, the caprock or wellbores, strong cooling will occur due to the expansion of CO2 as pressure decreases with depth. Finally, we conclude by identifying research gaps and challenges of thermal effects related to CCS.

Carbon dioxide (CO2) is likely to reach the bottom of injection wells at a colder temperature than that of the storage formation, causing cooling of the rock. This cooling, together with overpressure, tends to open up fractures, which may enhance injectivity. We investigate cooling effects on injectivity enhancement by modeling the In Salah CO2 storage site and a theoretical, long-term injection case. We use stress-dependent permeability functions that predict an increase in permeability as the effective stress acting normal to fractures decreases. Normal effective stress can decrease either due to overpressure or cooling. We calibrate our In Salah model, which includes a fracture zone perpendicular to the well, obtaining a good fitting with the injection pressure measured at KB-502 and the rapid CO2 breakthrough that occurred at the observation well KB-5 located 2 km away from the injection well. CO2 preferentially advances through the fracture zone, which becomes two orders of magnitude more permeable than the rest of the reservoir. Nevertheless, the effect of cooling on the long-term injectivity enhancement is limited in pressure dominated storage sites, like at In Salah, because most of the permeability enhancement is due to overpressure. However, thermal effects enhance injectivity in cooling dominated storage sites, which may decrease the injection pressure by 20%, saving a significant amount of compression energy all over the duration of storage projects. Overall, our simulation results show that cooling has the potential to enhance injectivity in fractured reservoirs.

Expansive soils are suitable as backfill and buffer materials in engineered barrier systems to isolate heat-generating nuclear waste in deep geological formations. The canisters containing nuclear waste would be placed in tunnels excavated at a depth of several hundred meters. The expansive soil should provide enough swelling capacity to support the tunnel walls, thereby reducing the impact of the excavation-damaged zone on the long-term mechanical and flow-barrier performance. In addition to their swelling capacity, expansive soils are characterized by accumulating irreversible strain on suction cycles and by effects of microstructural swelling on water permeability that for backfill or buffer materials can significantly delay the time it takes to reach full saturation. To simulate these characteristics of expansive soils, a dual-structure constitutive model that includes two porosity levels is necessary. The authors present the formulation of a dual-structure model and describe its implementation into a coupled fluid flow and geomechanical numerical simulator. The authors use the Barcelona Basic Model (BBM), which is an elastoplastic constitutive model for unsaturated soils, to model the macrostructure, and it is assumed that the strains of the microstructure, which are volumetric and elastic, induce plastic strain to the macrostructure. The authors tested and demonstrated the capabilities of the implemented dual-structure model by modeling and reproducing observed behavior in two laboratory tests of expansive clay. As observed in the experiments, the simulations yielded nonreversible strain accumulation with suction cycles and a decreasing swelling capacity with increasing confining stress. Finally, the authors modeled, for the first time using a dual-structure model, the long-term (100,000 years) performance of a generic heat-generating nuclear waste repository with waste emplacement in horizontal tunnels backfilled with expansive clay and hosted in a clay rock formation. The thermo-hydro-mechanical results of the dual-structure model were compared with those of the standard single-structure BBM. The main difference between the simulation results from the two models is that the dual-structure model predicted a time to fully saturate the expansive clay barrier on the order of thousands of years, whereas the standard single-structure BBM yielded a time on the order of tens of years. These examples show that a dual-structure model, such as the one presented here, is necessary to properly model the thermo-hydro-mechanical behavior of expansive soils.

In the light of current concerns related to induced seismicity associated with geological carbon sequestration (GCS), this paper summarizes lessons learned from recent modeling studies on fault activation, induced seismicity, and potential for leakage associated with deep underground carbon dioxide (CO2) injection. Model simulations demonstrate that seismic events large enough to be felt by humans require brittle fault properties and continuous fault permeability allowing pressure to be distributed over a large fault patch to be ruptured at once. Heterogeneous fault properties, which are commonly encountered in faults intersecting multilayered shale/sandstone sequences, effectively reduce the likelihood of inducing felt seismicity and also effectively impede upward CO2 leakage. A number of simulations show that even a sizable seismic event that could be felt may not be capable of opening a new flow path across the entire thickness of an overlying caprock and it is very unlikely to cross a system of multiple overlying caprock units. Site-specific model simulations of the In Salah CO2 storage demonstration site showed that deep fractured zone responses and associated microseismicity occurred in the brittle fractured sandstone reservoir, but at a very substantial reservoir overpressure close to the magnitude of the least principal stress. We conclude by emphasizing the importance of site investigation to characterize rock properties and if at all possible to avoid brittle rock such as proximity of crystalline basement or sites in hard and brittle sedimentary sequences that are more prone to injection-induced seismicity and permanent damage.

Thermo-mechanical effects are important in geologic carbon storage because CO2 will generally reach the storage formation colder than the rock, inducing thermal stresses. Capillary functions, i.e., retention and relative permeability curves, control the CO2 plume shape, which may affect overpressure and thus, caprock stability. To analyze these thermal and capillary effects, we numerically solve non-isothermal injection of CO2 in deformable porous media considering the In Salah, Algeria, CO2 storage site. We find that changes in the capillary functions have a negligible effect on overpressure and thus, caprock stability is not affected by capillary effects. However, we show that for the strike slip stress regime prevalent at In Salah, stability decreases in the lowest parts of the caprock during injection due to cooling-induced thermal stresses. Simulations show that shear slip along pre-existing fractures may take place in the cooled region, whereas tensile failure is less likely to occur. Indeed, only the injection zone and the lowest tens of meters of the 900-m-thick caprock at In Salah might be affected by cooling effects, which would thus not jeopardize the overall sealing capacity of the caprock. Furthermore, faults are likely to remain stable far away from the injection well because outside the cooled region the injection-induced stress changes are not sufficient to exceed the anticipated shear strength of minor faults. Nevertheless, we recommend that thermal effects should be considered in the site characterization and injection design of future CO2 injection sites to assess caprock stability and guarantee a permanent CO2 storage.

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. Plain Language Summary: Massive and timely deployment of Carbon Capture and Storage (CCS) at the gigatonne scale is a critical component of the majority of pathways toward reaching the Paris Agreement emissions abatement targets to mitigate climate change. Although CCS has been successfully deployed at multiple sites around the world, concerns about long‐term containment, especially for gigatonne‐scale storage, are causing uncertainty about the ability of geological layers to permanently store CO2 underground. This uncertainty is delaying the widespread deployment of CCS. This paper focuses on assessing the possibility of basin‐wide CO2 leakage through a typical multi‐layered geological setting with a sequence of aquifers and fine‐grained caprocks (e.g., shales). Numerical transport models, constrained by hydraulic properties of intact and pervasively fractured caprocks (as the best‐ and worst‐case scenarios, respectively), enable us to draw unambiguous limits on the CO2 leakage rates over previously unexplored temporal and spatial scales. We show that CO2 leakage to shallow sediments in both extreme scenarios is quite unlikely and the injected CO2 will be contained in the subsurface over millions of years. These findings should offer confidence to industrial developers, policy‐makers, investors, and most importantly, the public that CCS provides a secure and environmentally sound carbon removal option. Key Points: We develop a numerical transport model to understand the long‐term fate of CO2 in gigatonne‐scale geologic carbon storageCO2 leakage is dominated by molecular diffusion at inherently slow rates, hardly approaching a meter per several thousands of yearsThe long‐term potential for CO2 leakage from a multi‐layered system is low, making geologic storage a secure decarbonization technology [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Induced seismicity poses a challenge to the development of Enhanced Geothermal Systems (EGS). Improving monitoring and forecasting techniques is essential to mitigate induced seismicity and thereby fostering a positive perception of EGS projects among local authorities and population. Induced seismicity is the result of complex and coupled thermo-hydro-mechanical-chemical mechanisms. Injection flux and pressure are crucial controlling parameters for both hydraulic stimulation and circulation protocols. We develop a methodology combining a hydro-mechanical model with a seismicity rate model to estimate the magnitude and frequency of mainshocks and aftershocks induced by fluid injection. We apply the methodology to the case of the Basel EGS (2006, Switzerland) to compare the effects of progressive, cyclic and constant injections on the mechanical response of discrete faults. Results from the coupled hydro-mechanical models show that the pore pressure diffusion and consequent enhancement of fault permeability are limited to the vicinity of the injection well during cyclic injection. Additionally, constant injection induces seismicity from the start of the injection but enhances the permeability of most of the faults within a shorter duration, inducing less post-injection seismicity. The methodology can be adapted to any numerical model and allows new projects to be developed by anticipating the safest injection protocol.This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'.

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 m 2 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., (© 2023. The Author(s).)

Low-enthalpy geothermal energy (LEGE) is a carbon-free and renewable source to provide cooling and heating to infrastructures (e.g. buildings) by exchanging their temperature with that of the ground. The exchange of temperature modifies the groundwater temperature around LEGE installations, which may contribute to enhancing the capacity of aquifers to degrade organic contaminants of emerging concern (OCECs), whose presence is significantly increasing in urban aquifers. Here, we investigate the impact of LEGE on OCECs and their bioremediation potential through numerical modelling of synthetic and real-based cases. Simulation results demonstrate that: (i) LEGE facilities have the potential to noticeably modify the concentrations of OCECs; and (ii) the final impact depends on the design of the facility. This study suggests that optimized LEGE facility designs could contribute to the degradation of OCECs present in urban aquifers, thus improving groundwater quality and increasing its availability in urban areas., (© 2023. The Author(s).)

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., (© 2022. The Author(s).)

Geoenergy and geoengineering applications usually involve fluid injection into and production from fractured media. Accounting for fractures is important because of the strong poromechanical coupling that ties pore pressure changes and deformation. A possible approach to the problem uses equivalent porous media to reduce the computational cost and model complexity instead of explicitly including fractures in the models. We investigate the validity of this simplification by comparing these two approaches. Simulation results show that pore pressure distribution significantly differs between the two approaches even when both are calibrated to predict identical values at the injection and production wells. Additionally, changes in fracture stability are not well captured with the equivalent porous medium. We conclude that explicitly accounting for fractures in numerical models may be necessary under some circumstances to perform reliable coupled thermohydromechanical simulations, which could be used in conjunction with other tools for induced seismicity forecasting., (© 2021. The Authors.)

Displaced faults crossing the reservoir could significantly increase the induced earthquake frequency in geo-energy projects. Understanding and predicting the stress variation in such cases is essential to minimize the risk of induced seismicity. Here, we adopt the inclusion theory to develop an analytical solution for the stress response to pore pressure variations within the reservoir for both permeable and impermeable faults with offset ranging from zero to the reservoir thickness. By analyzing fault stability changes due to reservoir pressurization/depletion under different scenarios, we find that (1) the induced seismicity potential of impermeable faults is always larger than that of permeable faults under any initial and injection conditions-the maximum size of the fault undergoing failure is 3-5 times larger for impermeable than for permeable faults; (2) stress concentration at the corners results in the occurrence of reversed slip in normal faults with a normal faulting stress regime; (3) while fault offset has no impact on the slip potential for impermeable faults, the slip potential increases with the offset for permeable faults, which indicates that non-displaced permeable faults constitute a safer choice for site selection; (4) an impermeable fault would rupture at a lower deviatoric stress, and at a smaller pressure buildup than a permeable one; and (5) the induced seismicity potential is overestimated and the injectivity underestimated if the stress arching (i.e., the poromechanical coupling) is neglected. This analytical solution is a useful tool for site selection and for supporting decision making during the lifetime of geo-energy projects., (© 2020. The Authors.)

Geologic carbon storage is required for achieving negative CO 2 emissions to deal with the climate crisis. The classical concept of CO 2 storage consists in injecting CO 2 in geological formations at depths greater than 800 m, where CO 2 becomes a dense fluid, minimizing storage volume. Yet CO 2 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 CO 2 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 CO 2 is denser than water. We estimate that a CO 2 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., Competing Interests: There are no conflicts to declare., (©2020. The Authors.)

Supercritical geothermal systems are appealing sources of sustainable and carbon-free energy located in volcanic areas. Recent successes in drilling and exploration have opened new possibilities and spiked interest in this technology. Experimental and numerical studies have also confirmed the feasibility of creating fluid conducting fractures in sedimentary and crystalline rocks at high temperature, paving the road towards Enhanced Supercritical Geothermal Systems. Despite their attractiveness, several important questions regarding safe exploitation remain open. We dedicate this manuscript to the first thermo-hydro-mechanical numerical study of a doublet geothermal system in supercritical conditions. Here we show that thermally-induced stress and strain effects dominate the geomechanical response of supercritical systems compared to pore pressure-related instabilities, and greatly enhance seismicity during cold water re-injection. This finding has important consequences in the design of Supercritical Geothermal Systems.

Zoback and Gorelick [(2012) Proc Natl Acad Sci USA 109(26):10164-10168] have claimed that geologic carbon storage in deep saline formations is very likely to trigger large induced seismicity, which may damage the caprock and ruin the objective of keeping CO2 stored deep underground. We argue that felt induced earthquakes due to geologic CO2 storage are unlikely because (i) sedimentary formations, which are softer than the crystalline basement, are rarely critically stressed; (ii) the least stable situation occurs at the beginning of injection, which makes it easy to control; (iii) CO2 dissolution into brine may help in reducing overpressure; and (iv) CO2 will not flow across the caprock because of capillarity, but brine will, which will reduce overpressure further. The latter two mechanisms ensure that overpressures caused by CO2 injection will dissipate in a moderate time after injection stops, hindering the occurrence of postinjection induced seismicity. Furthermore, even if microseismicity were induced, CO2 leakage through fault reactivation would be unlikely because the high clay content of caprocks ensures a reduced permeability and increased entry pressure along the localized deformation zone. For these reasons, we contend that properly sited and managed geologic carbon storage in deep saline formations remains a safe option to mitigate anthropogenic climate change.