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.

Quick estimates of fluid-induced subsurface deformation are helpful to assess the land uplift/subsidence and to reveal precursors of induced seismicity. Here, we adopt the inclusion theory and Green's function to develop a closed-form solution in a half space for the poroelastic response of a reservoir compartmentalized by an intersecting fault that can be offset and either permeable or impermeable. Simulated results reveal that (1) fault permeability mainly impacts the spatial distribution of displacement while its effect on displacement magnitude is small; (2) ground displacement slightly increases with fault dip while slightly decreases with increasing fault offset; in contrast, reservoir geometry shows a stronger effect than fault geometry: the ground displacement is proportional to the vertical and lateral depth ratios, defined as the ratios of reservoir thickness (h) and width (w) to reservoir depth (D), respectively; (3) the maximum vertical displacement is the double of the horizontal one regardless of fault permeability, fault and reservoir geometries, and mechanical parameters. Comparing the solution in a half space with that in a full space shows that neglecting the free surface underestimates the poroelastic displacement in the overburden. The validity of full-space solutions can be assessed with the product of the lateral and vertical depth ratios, i.e., wh/D2. The full-space solutions become valid when wh/D2 decreases to an intrinsic threshold. This threshold may range from 0.01 to 0.02 for displacement, and its specific value depends on the field background and demands of projects, but can be estimated based on our solution. It is larger for stress than for displacement, and wh/D2 ≤ 0.1 is recommended as a general condition for neglecting the free-surface effects on induced stress. The analytical solution represents a useful tool for estimating ground deformation and for gaining insights of reservoir and fault geometries by analyzing surface deformation patterns.

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.

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.

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.

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.

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'.

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.